lea coal research - sustainable-carbon.org
TRANSCRIPT
I
lEA COAL RESEARCH (
Coal specifications - impact on power station performance
Nina M Skorupska
IEACRl52 January 1993 lEA Coal Research London
Copyright copy lEA Coal Research 1993
ISBN 92-9029-210-5
This report produced by lEA Coal Research has been reviewed in draft fonn by nominated experts in member countries and their comments have been taken into consideration It has been approved for distribution by the Executive Committee of lEA Coal Research
Whilst every effort has been made to ensure the accuracy of information contained in this report neither lEA Coal Research nor any of its employees nor any supporting country or organisation nor any contractor of lEA Coal Research makes any warranty expressed or implied or assumes any liability or responsibility for the accuracy completeness or usefulness of any information apparatus product or process disclosed or represents that its use would not infringe privately-owned rights
lEA Coal Research
lEA Coal Research was established in 1975 under the auspices of the International Energy Agency (lEA) and is currently supported by fourteen countries (Australia Austria Belgium Canada Denmark Finland Germany Italy Japan the Netherlands Spain Sweden the UK and the USA) and the Commission of the European Communities
lEA Coal Research provides information and analysis of all aspects of coal production and use including
supply transport and markets coal science coal utilisation coal and the environment
lEA Coal Research produces
periodicals including Coal abstracts a monthly current awareness journal giving details of the most recent and relevant items from the worlds literature on coal and Coal calendar a comprehensive descriptive calendar of recently-held and forthcoming meetings of interest to the coal industry technical assessments and economic reports on specific topics throughout the coal chain bibliographic databases on coal technology coal research projects and forthcoming events and numerical databanks on reserves and resources coal ports and coal-fired power stations
General enquiries about lEA Coal Research should be addressed to
Mr John Trubshaw Head of Service lEA Coal Research Gemini House 10-18 Putney Hill London SW 15 6AA United Kingdom
Telephone (0)81-780 2111 Fax (0)81-7801746
3
Abstract
This report examines the impacts of coal properties on power station perfonnance As most of the coal used to generate electricity is consumed as pulverised fuel the focus of the report is on performance in pulverised fuel (PF) power station units The properties that are currently employed as specifications for coal selection are reviewed together with their influence on power station performance Major coal-related items in a power station are considered in relation to those properties which affect their performance There is a review of tools being used for coal selection and prediction of station performance which includes an overview of the types of computer models that are available and those that are being developed
The principal coal properties that were found to cause greatest concern to operators included the ash sulphur moisture and volatile matter contents heating value and grindability Little has changed over the years in the way that coal is assessed and selected for combustion Operators continue to use tests as specifications that were mostly developed for coal uses other than combustion Because the procurement specifications are based on tests which do not relate well to actual practice there is still a need for expensive large scale test burns to confIrm suitability With the advances that have been made in computer technology there is a growing number of utilities that are adopting expert unit or integrated models that aid in the planning and operation of generating units Others have shown scepticism over the capability of devising a truly representative model of a coal combustion plant using the coal data produced from current testing procedures
Specific requirements that have been identified include the need to develop internationally acceptable methods of defining coal characteristics so that combustion plant perfonnance can be predicted more effectively There is also a need to establish economic parameters which can serve to measure the effects of coals on plant performance and hence on the cost of electricity
4
Contents
List of figures 7
List of tables 9
Acronyms and abbreviations 11
1 Introduction 13 11 Background 13
2 Coal specifications 15 21 Proximate analysis 17 22 Ultimate analysis of coal 20 23 Ash analysis and minerals 21 24 Forms of sulphur chlorine and trace elements 23 25 Coal mechanical and physical properties 23 26 Calculated indices 28 27 Comments 28
3 Pre-combustion performance 29 31 Coal handling and storage 29
311 Plugging and flowability 32 312 Freezing 34 313 Dusting 35 314 Oxidationspontaneous combustion 36
32 Mills 37 321 Drying 37 322 Grinding 38 323 Size classification and transport 42
33 Fans 42 34 Comments 45
4 Combustion performance 46 41 Burners 46 42 Steam generator 47
421 Combustion characteristics 47 422 Ash deposition 49
43 Comments 56
5
5 Post-combustion performance 57 51 Ash transport 57 52 Environmental control 58
521 Coal cleaning 59 522 Fly ash collection 60 523 Technologies for controlling gaseous emissions 63 524 Solid residue disposal 65
53 Comments 67
6 Coal-related effects on overall power station performance and costs 68 61 Capital costs 68 62 Cost of coal 68 63 Power station perfonnance and costs 69
631 Capacity 69 632 Heat rate 69 633 Maintenance 74 634 Availability 76
64 Comments 77
7 Computer models 79 71 Least cost coalcoal blend models 80 72 Component evaluation models 81 73 Unit models 82
731 Statistically-derived regression models 82 732 Systems engineering analysis 88 733 Integrated site models 97
74 Comments 99
8 Conclusions 101
9 References 104
Appendix List of standards referred to in the report 117
6
Figures
Schematic diagram of the coal-to-electricity chain 14
8 Three-day consolidation critical arching diameter (CAD)
18 Influence of ash characteristics of US coals on
23 Resistivity results for both power station fly ash and
2 Comparison of different coal classification systems 18
3 Mill throughput as a function of Hardgrove grindability index 24
4 Critical temperature points of the ash fusion test 25
5 Typical power station components 29
6 Typical flow patterns in bunkers 32
7 Surface moisture versus critical arching diameter (CAD) determined from shear tests 33
versus per cent fines in coal as a function of moisture content 33
9 Dewatering efficiency versus temperature 34
10 Size distributions of Australian export coal 35
11 Coal lift-off from a stockpile as a function of total moisture content 35
12 Influence of storage time on swelling index 37
13 Primary air temperature requirements depending on moisture content and coal type 39
14 Variation in capacity factor with HGI for different fineness grinds 40
15 HGI for several coals as a function of rank 41
16 Typical utility boiler fan arrangement 43
17 Fuel ratio as an indicator of coal reactivity 48
furnace size of 600 MW pulverised coal fired boilers 49
19 Mechanisms for fly ash formation 50
20 Heat flux recovery for different coals and soot blowing cycles 52
21 Effect of CaO and MgO on corrosivity deposit 53
22 Typical ash distribution 58
laboratory ash from Tallawarra power station feed coal 62
7
24 Laboratory resistivity curves of ash from a South African coal and from a blend of South African and Polish coals against temperature 62
25 Effects of grindability on vertical spindle pulveriser performance 72
26 Example of cost impact of a coal change on heat rate for a 1000 MW boiler 74
27 Adjusted maintenance cost accounts for TVAs Cumberland plant 75
28 Causes of coal-related outages 76
29 Boiler and boiler tubes equivalent availability factor (EAF) record 77
30 Mill engineering model analysis approach 82
31 Comparison of TVA and EPRI availability correlations to a 1000 MW boiler 85
32 Comparison of ash and H20 effects on boiler efficiency and gross heat rate 86
33 Outline of CIVEC model operation 87
34 CQEA evaluation of the impact of different coals on overall production costs of one unit 92
35 Equipment types modelled by CQIM 92
36 Major components of the CQE system 94
37 Correlations of forced outage hours against ash throughput using the CQI model 95
38 Schematic showing the structure of the C-QUEL system 97
39 Comparison of the operations with and without the use of the C-QUEL 98
8
5
10
15
20
25
Tables
1 Summary of coal quality requirements for power generation 16
2 Coal composition parameters standard measurements 17
3 Analysis of a given coal calculated to different bases 18
4 Rank and coal properties 19
Minerals in coal 22
6 Coal mechanical and physical parameters standard measurements 24
7 A summary of the major characteristics of the three maceral groups in hard coals 25
8 Summary of coal ash indices 26
9 lllustrative example of USA coal storage requirements 30
Conveyor Equipment Manufacturers Association (CEMA) material classification chart 31
11 CEMA codes for various coals 32
12 Analysis of ash and clay distribution in a coal by mesh size 33
13 Effect of coal properties on critical lift-off moisture content 35
14 Preferred range of coal properties 37
Maximum mill outlet temperatures for vertical spindle mills 38
16 Comparison of fineness recommendations 38
17 Summary of the effects of coal properties on power station component performance - I 44
18 Enrichment of iron in boiler wall deposits shycomparison of composition of ash deposits and as-fired coal ashes 52
19 Hardness of fly ash constituents 54
Properties of some coal ash components 54
21 Summary of the effects of coal properties on power station component performance - II 56
22 Summary of coal cleaning effects on boiler operation 59
23 Effect of coal type on total concentrations of selected elements from fly ash samples 65
24 Summary of the effects of coal properties on power station component performance - III 66
The effect of coal quality on the costs of a new power station 68
9
26 Ash contents of traded coals 69
31 Examples of boiler frreside variables station and cost
33 Comparison of coal energy costs based on gross heating
27 Calculation of boiler heat losses 70
28 Typical boiler losses for four Australian Queensland steaming coals 71
29 Total fuel costs for power stations of the Southern Company USA 75
30 Comparison of reduced boiler availability on the basis of hours in operation and type of fuel 76
components which may be affected by those variables when coal quality is changed 78
32 Model input output data - International Coal Value Model (ICVM) 80
value (at power station pulverisers) - in order of increasing cost 80
34 Boiler groupings in TVA study 83
35 TVA study - maintenance costs plant correlations for all coal-related equipment 84
36 NERA study - gross heat rate correlation 85
37 ClVEC coal specifications input 88
38 ClVEC power station operational parameters 89
39 ClVEC factors contribution to utilisation value 89
40 Model input output data - COALBUY 90
41 Model input output data - Coal Quality Advisor (CQA) 90
42 Model input output data - Coal Quality Engineering Analysis (CQEA) 91
43 Model input output data - Coal Quality Impact Model (CQIM) 93
44 Ranges of selected coal-ash combustibility parameter that predict approximate classification of CF values 94
45 Model input output data - IMPACT 95
46 Assessment of four coals for Fusina unit 3 using the CQI model 96
47 Summary of model types and capabilities 99
48 Summary of the impacts of coal quality on power station performance 102
10
Acronyms and abbreviations
ad AP ARA ASTM BSl Btu CAD CCSEM CEMA CGI cif CPampL CQA CQEA CQE CQIM CSIRO daf DIN dmmf DTF EEl EFR EPRl ESP FD FEGT FFV FGD FGET FGR fob FTIR GADS GHR GP HGI HLampP HR
air-dried auxiliary power Acid Rain Advisor American Society for Testing and Materials British Standards Institution British thermal unit critical arching diameter computer controlled scanning electron microscopy Conveyor Equipment Manufacturers Association continuous grindability index cost insurance freight Carolina Power and Light Company Coal Quality Advisor Coal Quality Engineering Analysis Coal Quality Expert Coal Quality Impact Model Commonwealth Scientific and Industrial Research Organisation (Australia) dry ash-free Deutsches Institut rur Normung (Germany) dry mineral matter-free drop tube furnace Edison Electric Institute (USA) entrained flow reactor Electric Power Research Institute (USA) electrostatic precipitator forced draft furnace exit gas temperature flow factor value flue gas desulphurisation flue gas exit temperature flue gas recirculation free on board Fourier transform infrared Generating Availability Data System (USA) gross heat rate gross power Hardgrove grindability index Houston Lighting amp Power Company (USA) heat rate
11
ICVM ill IEEE IFRF ISO LCFS kWh MCR MJlkg MWe MWh NERA NERC NHR nm NOx
NYSEG OGampE OampM PA PF PGNAA PN PP ppm ROM SCR SNCR TGA THR TVA UDI UK USA US DOE
International Coal Value Model induced draft Institute of Electronic and Electrical Engineers (UK) International Flame Research Foundation (The Netherlands) International Organization for Standardization Least cost fuel system kilowatt hour maximum continuous rating megajoule per kilogram megawatt (electrical) megawatt hours National Economic Research Associate (USA) North American Electric Reliability Council (USA) net heat rate nanometres nitrogen oxides New York State Electric amp Gas Company (USA) Oklahoma Gas amp Electric Company (USA) operation and maintenance primary air pulverised fuel Prompt Gamma Neutron Activation Analysis Polish Standards Committee Pacific Power parts per million run-of-mine selective catalytic reduction selective non-catalytic reduction thermal gravimetric analysis turbine heat rate Tennessee Valley Authority (USA) Utility Data Institute (USA) United Kingdom United States of America United States Department of Energy
12
1 Introduction
This report examines the impacts of coal properties on power stations buming pulverised fuels (PF) The properties that are currently examined when defining specifications for coal selection are reviewed together with their influence on power station performance The main power station components are considered in relation to those coal properties which affect their performance There is a review of tools being used for coal selection and prediction of station performance which includes an overview of the types of computer models that are both available and under development
In support of the study lEA Coal Research conducted a survey by questionnaire of power stations in 12 countries to obtain additional information about utility practice and experience of the effects of coal quality on power station performance The responses of station operators and research specialists to the questionnaire were of considerable value and much appreciated
11 Background Utilities are continually striving to produce power at the lowest possible cost This means that power stations must operate at optimal availability and rated output while maintaining efficient operation and maintenance schedules At the same time they must also meet relevant emission requirements
Operators of coal-frred stations have long known that coal composition and characteristics signifIcantly affect operation on a broad front Because a power station is a complex interrelated system a change in one area such as coal quality can reverberate throughout the whole system Figure 1 shows a schematic diagram of the coal-to-electricity chain To generate electricity to the busbar at minimum cost it is necessary to evaluate the total cost associated with each coal This includes the cost of any coal-related effects on the performance and availability of
power station components as indicated by Sections 4-7 in Figure 1 in addition to the delivered cost of the coal It is estimated that coal quality factors can contribute up to 60 of all unscheduled outages of coal-fired stations (Mancini and others 1988)
In some cases utilities have the opportunity to fire a range of coals in their power stations In general power stations have a design coal analysis with which initial performance guarantees are met It is also usual to have an allowable range for the most important coal properties within which it is expected that full load may be produced although possibly at reduced efficiencies Substantial deviations in one or more of the properties may result in impaired plant performance or even serious operating and maintenance problems
The quality of coal supplied to a power station may vary for many reasons including
typical day-to-day seam variations in individual coals longer term variations in coal quality due to seam depletion andor change of mining method inconsistencies due to inadequate preparation or poor quality control at the mine site variation in proportions of coals supplied from several traditional supply sources replacement of traditional supplies with sources with different properties due to changing availability or price switchinglblending requirements to meet changing emissions regulations intentional change of fuel quality to solve existing performance problems heavy reliance on recoveries from old stockpiles effects of weather
In order to select a coal supply utilities must try to predict the impacts of alternative coals on power station performance and overall power generation costs Since the type and design of boiler and auxiliary equipment are fixed the coal is
13
6
Introduction
PREPARATION PLANT TRANSPORTMINE
2 3
Figure 1 Schematic diagram of the coal-ta-electricity chain
usually selected to match these rather than the reverse There are numerous methods employed to help select an appropriate coal These can range from selecting coals on the basis of a limited number of design specifications based on proximate analysis through use of sophisticated computer models describing overall performance to expensive full
4 5
HANDLING AND MILLING
STORAGE
PARTICULATES REMOVAL - COMBUSTION~ bull
6B FGD
6C
WASTE DISPOSAL
9
ADDITIONAL UNIT
GENERATION CAPACITY
STEAM 7TURBINE
ELECTRICITY TO 8BUSBAR
scale test firing of sample loads over a limited time period It is recognised that a wide range of complex physical and chemical processes occur during preparation and combustion and so it is not surprising that these methods may still prove to be inadequate in providing a quantitative understanding of the impacts of coal quality
14
2 Coal specifications
The criteria for including particular properties of a coal in a specification used for a particular power station are varied Basic coal contracts can include as few as three or four base quality guarantees - stipulating a range of values for heating value ash content moisture and more recently sulphur More typical purchasing specifications incorporate additional properties such as volatile matter fixed carbon ash fusion temperatures grindability along with the base level specifications of heating value ash moisture and sulphur (Schaeffer 1988) More recently these have been expanded by some utilities to include trace element details and the petrographic composition of the coal Table 1 summarises the typical coal quality requirements for power generation The specification values indicated are derived from both the literature and analysis of the results obtained from the survey of boiler operators
Most of the properties described in Table 1 are measured using relatively simple standard tests More recently some coal specifications have emerged which appear even more complex and restrictive In addition to the standard characterisation tests they may include non-standard characterisation and combustion tests such as the use of thermal gravimetric analysers drop-tube furnaces and pilot-plant tests (see Section 42) It has been argued that such detailed specifications are not necessary (OKeefe and others 1987) may be excessively restrictive and could lead to increasing fuel cost as specific sources are no longer available (Mahr 1988 Harrison and Zera 1990) The advocates for detailed specifications argue that to use only a basic fuel specification for selection will leave the market open for many coals which may not perform as well as the design-specification coal (Vaninetti 1987 Myllynen 1987) They will most likely be attractively priced (Corder 1983 OKeefe and others 1987) but there is no assurance that the saving will necessarily minimise the overall cost of power generation In many cases buying the coal of lowest price can be false economy (see Chapter 6) for example if the coal adversely affects heat rate additional coal will be
needed If the selected coal cannot sustain full unit capacity or causes additional outages (availability loss) alternative units must be operated to make up the lost power possibly at considerable additional cost Also increased maintenance costs add directly to the total cost of power generation (Folsom and others 1986a Sotter and others 1986 Yarkin and Novikova 1988 Ziesmer and others 1991 Bretz 1991a)
Blending to meet quality specifications is gaining acceptance In most cases power stations do not fire only coal from a single seam in their boilers As coal occurs in heterogeneous deposits the supply from any mine is already a blend of material from different seams to meet the required specification This principle may be extended such that coals supplied to power stations can be blends from several different sources prepared at handling centres such as at Rotterdam The Netherlands (Rademacher 1990) Power stations themselves may have facilities for blending two or more coals on site Separately the coals may not meet specification but a homogeneous mix does (Ratt 1991) Most countries which depend solely on imported coals have commercial strategies stipulating that no single source should account for more than 40 of supply (Klitgaard 1988) Blending which extends the range of acceptable coals increases the number of supply opportunities It should be noted that the non-additive nature of some of the standard tests such as ash fusion tests and use of HGI values (see Section 25) makes blend evaluation for power station use inherently complex (Riley and others 1989)
The following sections examine the coal properties used in coal specifications and evaluate their significance in power station operation
Table 2 lists eighteen standard methods of measuring coal composition together with an indication of the relevance of the results to the utility industry As illustrated in Table 2 the key measurement methods are proximate analysis
15
Coal specifications
Table 1 Summary of coal quality requirements for power generation
Parameter Desired Typicallimits
Heating value (ar) MJkg high min 24-25 (23) Proximate analysis - Total moisture (ar) 4-8 max 12
- Ash (mt) low max 15-20 (max 30) - Volatile matter (rot) 20-35 min 20 (23) - side-fIred furnaces
15-20 max 20 - down-fIred pf furnaces Total sulphur (mt) low max 05-10 - dependent on local pollution regulations
Hardgrove grindability index (HGI) high
Maximum size mm 130-40 Fines less than 05 mm (15 max)
Proximate analysis Ultimate analysis
Chlorine (rot)
Ash analysis weight of ash
Ash fusion temperatures degC
Swelling index Ash resistivity Handleability
Trace elements
Vitrinite reflectogram
Maceral analysis
- Fixed carbon (rot) - Carbon (daf)
- Hydrogen (daf)
- Nitrogen (dat) low - Sulphur (dat)
- Oxygen (by diff daf) low
Silicon dioxide (Si02) Aluminium oxide (Ah03) Titanium oxide (Ti02) Ferric oxide (Fe203) Calcium oxide (CaO) Magnesium oxide (MgO) Sodium oxide (Na20) Potassium oxide (K20) Sulphite (SOn Phosphorus pentoxide (P20 S)
- initial deformation high - softening (H = W) high - hemispherical (H =lizW) high - fluid high
low ohmem at 120degC
As Cd Co Cr Cu
Hg Ni Pb Sb Se Tl Zn
Vitrinite Exinite Inertinite Mineral
min 50-55 (min 39) 50 limited by size accepted by pulveriser
limited for handling characteristics
(08-11)
max 01--03 (max 05)
(45-75) (15-35) (04-22) (1-12) (01-23) (02-14) (01--09) (08-26) (01-16) (01-15)
(gt1075) in reducing conditions (gt1150) for dry bottom furnaces (gt1180) Values are much lower for wet bottom (gt1225) furnaces
(max 5) if available if available
Declaration of presence
if available
55-80 5-15 10-25 to declare
Typical limits refer to those commonly quoted those in brackets indicate outer limits acceptable in some cases
Measurement basis ar shy as received mf - moisture free daf - dry ash-free
16
Coal specifications
Table 2 Coal composition parameters standard measurements (after Folsom and others 1986c)
Measurement Method Standards procedure
ASTM AS BS DIN ISO
Parameters measured
Relationship to power station performance
Proximate analysis 03172-89 Moisture D3173-87 Volatile matter D3175-89 Ash D3174-89 Fixed carbon
Ultimate analysis 03176-89 Oxygen Carbon 03178-89 Hydrogen 03178-89 Nitrogen 03179-89 Total sulphur 03177-83
10383-89 10383-89 10383-89 10383-89 10388-89
10386-86
103861-86 103861-86 103862-86 103863-86
10163-73 10163-73 10163-73 10163-73 10163-73
10166-77 10166-77 10166-77 10166-77 10166-77 10166-77
51700-67 51718-78 51720-78 51719-78
51700-67
51721-50 51721-50 51722 517241-75
331-83 562-81 1171-81
1994-76 625-75 625-75 332-81 334-75
H20 Ash VM FC
Part of proximate analysis
C H 0 N S Ash H2O
) Pm of 1_ analysis
These parameters affect all power station systems since they are the principal constituents of coal
Ash analysis D2795-89 AA-Elemental ash analysis Major 03682-87 AA-Elemental ash
1038141-81
1038141-81
101614-79
101614-79
51729-80
analysis Trace 03683-78 Mineral matter C02 in coal D1756-89 Forms of sulphur D2492-90 Chlorine D2361-91 Total moisture D3302-89 Equil moisture D1412-89
1038104-86 103822-83 103823-84 103811-82 10388-80 10381-80 103817-89
10166-77 101611-87 10168-84 10161-89 101621-87
51726 517242 51727-76 51718
602-83 925-80 157-75 352-81 589-81 1018-75 Surface moisture
Corrosion slagging fouling
Handling amp pulverisation
Proximate analysis by instrumental procedures D5142-90
AA Atomic Adsorption ASTM American Society for Testing and Materials AS Australian Standards
BS British Standards Institution DIN Deutsches Institut fur Normung ISO International Organization for Standardization
ultimate analysis and ash analysis Additionally other early 1800s at a time when carbonisation was the most chemical analyses are often carried out on coal samples important use of coal It was a means of broadly assessing Some of these tests are used to enable correction of the bulk distribution of products obtainable from a coal by proximate and ultimate analysis data to allow for mineral destructive distillation (Elliott 1981) It is widely accepted matter constituents while others are used to evaluate the by the utility industry and forms the basis of many coal coals suitability for specific purposes In most coal qualitypower station performance correlations The great producing and consuming countries national or international advantage of the tests required for proximate analysis is that standard techniques are used The titles of the standards they are all quite simple and can be performed with basic reported in this chapter and the addresses of the standards laboratory equipment So much so that they have been fully organisations are given in the Appendix automated in recent years The results of proximate analysis
although endorsed with long history and extensive Common causes of confusion in the comparison of coal and experience are empirical and only applicable if the tests are interpretation of analytical data as reviewed by Carpenter carried out under strict standardised conditions The five (1988) are characteristics obtainable from the procedure are
the different domestic and international coal total moisture classification schemes used (see Figure 2) air-dried moisture the wide range of analytical bases on which the coal data volatile matter may be reported and the failure of many workers to ash identify clearly the basis for their results Table 3 fixed carbon illustrates how results will vary for a single coal depending on the base used Proximate analysis reports moisture in only two categories
as total and air-dried although it actually occurs in coals in different forms Air-dried moisture is also referred to as21 Proximate analysis inherent moisture The total moisture of coal consists of
The proximate analysis of coal is the simplest and most surface and inherent moisture Surface moisture is the common form of coal evaluation It was introduced in the extraneous water held as films on the surface of the coal and
17
----- ---
---
01
Coal specifications
Volatile Australia
301a
302
303
301b 302 303
401-901 high volatile A bituminous
402-702 coal402 class 7 Ihigh volatile B bituminous
coal 902 high volatile
class ~inouscoal
I subbituminousclass subbituminous
B coal 11 A coal subbituminous
class ~
approximate C coal 12 volatile matter
f-- shy dmmf lignite A class class 6 32-40
13 class 7 32-43 class 8 34-49
class ~
class 9 41-49
-14 lignite B
class
-15
matter dmmf
2 6 8 9
10 115 135
14 15 17
195 20 22 24
275 28 31 32 33
36
44J
47J
Great Britain NCB
101 anthracite
102
201a dry Ol ~~ 201b I~~~I~ COcgt
202 ~EgE- co co ~co203 -OlO 02 -en8en t)204
FRG
meta-anthracite
anthracite
lean (non-caking)
coal
forge coal
fat (coking) coal
hard coals
gas coal
tgas flame coal
flame coal
shiny hard
brown coal
matt
soft brown coal
MJkg class 6 326
class 7
302 class 8
class 9 -256
- 221 soft
193 brown coals
147
Heating value MJkg
N S
173 131
179 136
198 151
gross net
3168 3067
3279 3175
3635 3520
-
medium volatile coals
30shy
40shy
50shy
60shy
70shy
International hard coals
class 0
class 1A
class 1B
class 2
class 3
class 4
hardclass 5 coals
class 6 moi sture
high ~ f 0Yo
brown coals
volatile I coals
and I
I~ class 8
-1Q class 9- - 20shy
North America ASTM
Imeta-anthraciteI
anthracite
semi-anthracite
low volatile bituminous
coal
medium volatile
bituminous coal
Calorific value mmmf
hard coals
class 1
class 2
class 3
class 4A
class 4B
hardclass 5 coals
Figure 2 Comparison of different coal classification systems (Couch 1988)
Table 3 Analysis of a given coal calculated to different bases
Condition or basis
Proximate analysis
H2O VM FC Ash
Ultimate analysis
C H 0
As received 339 2061 6653 947 7729 459 561
Dry 2133 6887 980 8000 436 269
Dry ash-free 2365 7635 8869 483 299
Analysis of US Pennsylvania Somerset County Upper Kittaning Bed No 3 Mine
In the ultimate analysis moisture on an as received basis is included in the hydrogen and oxygen Net heating value is calculated from the gross value using the relationship in ISO 1928
its content can vary in a coal over time The moisture present water is difficult to control separate assessment of inherent in other forms is regarded as the inherent moisture it is or air-dried moisture is also necessary as most other more or less constant for coals of a given rank (Ward 1984) analyses are carried out on air-dried material
A coal that is sold commercially usually contains a certain Surface moisture is important to the handleability of coal amount of surface moisture which forms part of the total (see also Section 31) With a content greater than 12 of weight of coal delivered Knowledge of the total moisture the coal weight problems such as bridging in bunkers and content of the coal is therefore essential to assess the value of blocking of feeders can be expected in the transport system any consignment However because the amount of surface (Cortsen 1983) In cold climates the excess surface moisture
I
18
Coal specifications
may freeze and act as a binder so incurring coal handling problems (Raask 1985)
Extremely low surface moisture content can cause environmental problems due to dust and enhanced risks of fire due to coal oxidation which causes heating and may lead to spontaneous combustion especially in low rank coals (see
also Sections 313 and 314)
Surface moisture and part of the inherent moisture of a coal can be released in the mills during grinding This means that the mill inlet or primary air temperature prior to milling must be increased for coals with a high total moisture content The surface moisture of the coal is converted to vapour during milling and forms part of the coal-air mixture in direct feed systems The vapour enters the furnace where it can cause a delay in coal ignition and increase flame length The effect however is small for coals with moisture contents not exceeding 10
The inherent moisture has a more direct influence on coal ignition and combustion Significant gasification of the coal particle to release combustible gases cannot start prior to the evaporation of the moisture from within the particle When firing a coal with a high inherent moisture content conditions can also be improved by increasing mill air inlet temperature
Total moisture in the coal contributes to the overall gas flow in the form of vapour (Cortsen 1983) This can influence the operation of fans that move the air flue gas and pulverised coal through the unit An increase in coal moisture will increase the flue gas volume flow rate thus necessitating an increased power requirement for the fans (see Section 33)
During the combustion process coal releases volatiles which include various amounts of hydrogen carbon oxides methane other low mOlecular weight hydrocarbons and water vapour Volatile yield of a coal is an important property providing a rough indication of the reactivity or combustibility of a coal and ease of ignition and hence flame stability The amount of volatiles actually released in practice is a function of both the coal and its combustion conditions including sample size particle size time rate of heating and maximum temperature reached In order to obtain a method for comparing coals a simple test was devised to obtain a value for the volatile matter content of a coal The volatile matter content as determined by proximate analysis represents the loss of weight corrected for moisture when the coal sample is heated to 900degC in specified apparatus under standardised conditions
Typical values of volatile matter content associated with different ranks of coal as determined by proximate analysis are given in Table 4 (Cunliffe 1990) It should be noted that some of the volatile matter may originate from the mineral matter present
The volatile matter content of a coal is used to assess the stability of the flame after ignition Under the same combustion conditions that is same burner configuration and amount of excess air a coal with a high volatile matter content will usually give stable ignition and a more intensive
Table 4 Rank and coal properties (Cunliffe 1990)
Type C H 0 Volatile Heating
(composition ) matter value daf MJkg
Wood 500 60 430 800 146
Peat 575 55 350 684 159
Lignite 700 50 230 526 216
Bituminous High volatile 770 55 150 421 258
Medium volatile 860 50 45 263 335
Low volatile 905 45 30 188 348
Semi-anthracite 905 45 30 188 348
Anthracite 940 30 15 41 346
daf dry ash-free basis
flame compared with a coal with a low volatile matter content Maintaining stable ignition is one of the most crucial aspects of pulverised coal firing since instability necessitates the use of pilot fuel and in extreme cases may incur the risk of furnace explosion (Cortsen 1983) Low laquo20) volatile matter coals can produce high-carbon residue ash In order to combat this adverse effect the coal would require extra-fine milling and combustion in boilers with a long flame path (Raask 1985) A high volatile matter content (gt30) can cause mill safety problems This is due to the increased possibility of mill fires resulting from spontaneous combustion of the coal (see Section 32) Volatile matter content values are often used to calculate combustibility indices which are used as an indication of the reactivity of a coal They are also included in formulae for the prediction of NOli release during coal combustion (Kok 1988)
Ash is the residue remaining following the complete combustion of all coal organic material and oxidation of the mineral matter present in the coal Ash is commonly used as an indication of the grade or quality of a coal since it provides a measure of the incombustible material present in the coal A higher ash content means a lower heating value of the coal as ash does not contribute any energy to the system It represents a dead weight during coal transport to and through a power station (Lowe 1988a) In order to maintain boiler output when switching from a low ash coal to another with similar specification but a higher ash content an increased throughput of material would be required to achieve the same loading Alternatively power station output may be constrained by the lack of capacity in the ash handling system
Ash content and its distribution within the coal influences ignition stability The transformation of mineral matter to ash is an endothermic reaction - requiring energy Thus some coal particles containing a high proportion of mineral matter may not ignite satisfactorily In some cases stack and unburnt carbon losses have been shown to increase as the heating value of the coal decreases with increased ash content A high-ash content may lower the accessibility of the carbon to combustion within the particle (Kapteijn and others 1990) In contrast to these situations Australian power stations have been known to combust coals with a
19
Coal specifications
high ash (gt25) content without support fuel satisfactorily (Sligar 1992)
High ash coals (gt20) can cause abrasion and particle impaction erosion wear of fuel handling plant mills burners boiler tubes and ash pipes if the plant is not designed for this (Raask 1985) Utilisation of a high ash coal may impair the performance of particulate control devices by ash overloading There may also be problems of accommodating higher ash levels for disposal (Bretz 1991b)
Possibly the most serious effects that ash constituents have upon the boiler performance are those connected with fouling slagging and corrosion of the heating surfaces These problems are discussed in Section 422
The fixed carbon content of coal is not measured directly but represents the difference in an air-dried coal between 100 and the sum of the moisture volatile matter and ash contents It still contains appreciable amounts of nitrogen sulphur hydrogen and possibly oxygen as absorbed or chemically combined material (Rees 1966)
The fixed carbon content of coal is used by the ASTM to classify coal according to rank (Carpenter 1988) It is also used as an estimate of the quantity of char (intermediate combustion product) that can be produced and to indicate the amount of unburnt carbon that might be found in the fly ash
In any assessment of data it should be noted that the final temperatures heating rates and residence times utilised in proximate analysis tests differ significantly from conditions experienced in power station boilers In proximate analysis depending upon the set of country standards used
moisture content is determined in a nitrogen atmosphere at around 100degC for 10 minutes volatile matter of a coal is determined under restricted conditions at 900degC after a residence time of up to seven minutes ash content is determined by combusting the organic component of the coal in air up to around 800dege
Conditions in a power station boiler have been reported to produce temperatures greater than 1700degC (3120degF) heating rates of 1O000-100OOOdegCs and particle residence times within the system of seconds rather than minutes Ideally the suitability of a coal for combustion use should take into account the operational conditions and aim to identify relationships between critical process requirements and specific properties of the coal on a more rational basis However proximate analysis is still widely used in the utility industry
There are also problems with interpreting the results from a proximate analysis Ideally the moisture fraction should contain only water the volatiles fraction should consist only of volatile hydrocarbons released during the initial stages of heating the fixed carbon would be the char after complete devolatilisation and ash only the oxidised remains of the mineral matter after combustion This is not always the case Many coals contain light hydrocarbons which are driven off from the coal at temperatures low enough to cause them to
appear in the moisture determination Consequently the moisture measurement is too high and corresponding volatiles measurement too low This can be a significant problem with lower rank coals (Folsom and others 1986c)
A similar problem occurs between volatiles and fixed carbon The mechanisms involved in thermal decomposition of coal are complex and variations in the particle size treatment times temperatures and heating rates may affect the results Volatile matter content usually includes a loss in weight due also to the decomposition of inorganic material especially carbonates which are known to decompose at temperatures in excess of 250degC (see Section 23) Since fIxed carbon is not a direct measurement but obtained by difference it will include any errors bias and scatter involved in the related determinations of moisture volatile matter and ash Thus the concept of well defmed quantities of fixed carbon and volatile matter for specific coals is subject to qualification
Ash as produced during proximate analysis is often used as the material for conducting chemical analysis and other tests for assessing ash behaviour in a power station The problems associated with this approach are discussed in Section 23
22 Ultimate analysis of coal Ultimate analysis involves the determination of the elemental composition ofthe organic fraction of coal (Ward 1984 Gluskoter and others 1981) Table 2 describes the standard measurement methods for ultimate analysis techniques for ASTM AS BS DIN and ISO In addition to ash and moisture element weight per cents of carbon hydrogen nitrogen sulphur and oxygen (which is determined by difference) are reported Ash and moisture are determined by the same method as in the proximate analysis and suffer from the same shortcomings The detection of the above elements are usually performed with classic oxidation decomposition andor reduction methods (Berkowitz 1985)
Carbon and hydrogen occur mainly as complex hydrocarbon compounds Carbon may also be present in inorganic carbonates The nitrogen found in coals appears to be confmed mainly to the organic compounds present (Ward 1984) The nitrogen content of coal has become an important issue with the increased awareness of air pollution by nitrogen oxides (NOx) Unfortunately there is no simple correlation between coal nitrogen content and nitrogen oxide emissions as unlike sulphur dioxide not all nitrogen oxide produced during combustion comes from the coal itself In combustion theory there are three different formation mechanisms for NOx thermal prompt and formation ofNOx from fuel-bound nitrogen although the reactions are not fully understood (Juniper and Pohl 1991) Only the third mechanism relates to oxidation of the nitrogen contained in coal (Hjalmarsson 1990) The nitrogen content in coal varies between 05 and 25 and is contained mostly in aromatic structures (Burchill 1987 Zehner 1989) Some of the fuel nitrogen is released during devolatilisation and in highly turbulent unstaged burners is rapidly oxidised The remainder of the fuel nitrogen remains in the char and is released at a similar rate to that of char combustion The effIciency of coal-bound nitrogen conversion to NOx has
20
Coal specifications
been estimated at 20-25 for the char and up to 60 for the volatile matter (Morgan 1990) NOx formation from fuel-bound nitrogen can be minimised by promoting devolatilisation in zones of high temperature under reducing conditions for example air staging This principle is exploited in low NOx burners However less can be done to mitigate NOx formation due to the combustion of post-devolatilisation char-bound nitrogen (Kremer and others 1990 Hjalmarsson 1990)
Sulphur is present in nearly all coals from trace amounts up to about 6 although higher levels are not unknown The presence of sulphur compounds in the coal and ash can have many deleterious effects on the operation of boilers for example
during combustion the sulphur is oxidised to S02 A small percentage generally not more than 2 is converted into S03 of which a substantial percentage may then be reabsorbed to form sulphates with the alkali metals in the ash Alkaline sulphates are undesirable in that they increase the tendency of fouling and corrosion of heat transfer surfaces (see Section 422) if the dew point of the combustion gases is reached the S03 present combines with condensing water vapour to produce sulphuric acid which can then cause severe corrosion in cool sections of the power station particularly flue gas ducts and treatment systems (see Section 422)
The main problem however is S02 which is emitted through the stack and constitutes an environmental problem due to the resulting formation of acid rain
The oxygen content of coal is traditionally determined by difference subtracting the sum of the measured elements (C + H + N + S) from 100 although there are procedures available for the direct determination of oxygen (Gluskoter and others 1981 Ward 1984) It is an important property as it can be used as an indicator of rank and the basic nature of the coal Coals tend to oxidise in air to form what is commonly known as weathered coal The oxygen content of a coal has also been used as a measure of the extent of oxidation
Whilst the procedures for elemental analysis described by national standards often differ in minutiae they generally yield closely similar results This can only be achieved by the rigorous adherence to test specifications as laid down by the standards careful sampling and sample preparation
Similar to proximate analysis corrections to the analysis data are necessary For example
contributions to the hydrogen content from residual coal moisture and dehydration of mineral matter because the hydrogen content in coal is determined by the conversion of all the hydrogen present to H20 contributions to the carbon and sulphur contents which are determined by conversion to C02 and S02 respectively because both C02 and S02 are released from any carbonates and sulphides or sulphates that may be contained in the mineral matter
The major limitation of ultimate analysis is the labour cost
and time required to conduct the analyses Several techniques and instruments have been developed to reduce these limitations Some utilise automated gas chromatographic or spectroscopic equipment attached to high temperature combustion furnaces to reduce the time and labour required for the analysis Others utilise a range of measurement techniques including nucleonic methods to provide a quasi-continuous analysis for example on-line analysers (Folsom and others 1986a Kirchner 1991)
23 Ash analysis and minerals Coal ash consists almost entirely of the decomposed residues of silicates carbonates sulphides and other minerals Originating for the most part from clays it consists mainly of alumino silicates so that its chemical composition can usually be expressed in terms of similar oxides to those found in clay minerals The composition of the ash may be used as a guide to the types of minerals originally present in the coal (Given and Yarzab 1978 Ward 1984)
Certain generalisations can be made on the influence of the ash composition on the fusion characteristics as determined by the ash fusion test
the nearer the composition approaches that of alumina silicate Al2032Si02 (Al203 =458 Si02 =542) the more refractory (infusible) it will be CaO MgO and Fe203 act as mild fluxes lowering the fusion temperatures especially in the presence of excess Si02 FeO and Na20 act as strong fluxes in lowering the fusion temperatures high sulphur contents lower the initial deformation temperature and widen the range of fusion temperatures
In practice power station operators are primarily interested in knowing how closely the laboratory-prepared ash content of coal represents the quantity and behaviour of ash produced in large boilers Therefore when interpreting the results of the ash analysis it is important to recognise that the analysis is conducted on a sample of ash produced by the procedures specified in the proximate analysis (for example ASTM D3172 - see Appendix) It does not therefore correspond to the mineral matter present in the parent coal or necessarily to the individual ash particles formed when fired in a utility boiler For example it would be incorrect to assume that the iron measured in the ash sample is necessarily present in the coal as Fe203 or that the aluminium is present as Ah03 (Folsom and others 1986c) The principal chemical reactions that affect the ash yield at different temperatures are
High temperature Low temperature combustion oxidation
(Na K Ca)0Si02xAL203 + S03~ (Na K Ca)S04 + Si02xA1203 2 FeO + 1z 02 ~ Fe203
The boiler ash cools rapidly at a rate of about 200degCs through the temperature range from 900degC to 250degC and
21
Coal specifications
during this short time interval there is only a limited degree of sulphation and oxidation taking place Thus the ash prepared in a laboratory furnace at 815degC has higher weight than that formed in the boiler furnace due to the absorption of S03 in sulphate and additional oxygen in the ferric oxide (Raask 1985) For many years ash analysis in this form has been the only method available for assessing fly ash and deposit composition These in turn would be used to assess a coals slagging fouling and corrosive propensities which are of concern for the efficient operation of the power station More recently investigators have recognised the importance of actual mineral matter composition and
Table 5 Minerals in coal (Mackowsky 1982)
Mineral group First stage of coalification
distribution within the parent coal particles as a better indicator of a coals slagging and fouling behaviour (Nayak and others 1987 Heble and others 1991 Zygarlicke and others 1990) (see also Section 422)
Mineral matter determination is carried out far less frequently than the relatively fast and inexpensive ash determination (Brown 1985) Table 5 describes the minerals found in coal and their method of deposition
Although the ash as measured by proximate analysis is often equated with the coal mineral matter there are significant
Second stage of coalification Occurrence
Syngenetic fonnation synsedimentary-early diagenetic Epigenetic formation (intimately intergrown)
Transported Newly fonned Deposited in Transfonnation by water or fissures cleats of syngenetic wind and cavaties minerals
(coarsely (intimately intergrown) intergrown)
Clay minerals Kaolinite common-very common Illite-Sericite Illite dominant-abundant Minerals with a layered structure Chlorite rare Montmorillonite rare-common Tonstein
Carbonates Siderite Ankerite Ankerite common-very common Dolomite Dolomite rare-common Calcite Calcite common-very common
Sulphides Pyrite Pyrite Pyrite rare-common Melnikovite rare Marcasite Marcasite rare
Galena rare Chalcopyrite rare
Oxides
Quartz
Phosphates
Heavy minerals and accessory
Hematite Goethite
Quartz grains Quartz Quartz
Apatite Apatite Phosphorite
Zircon Tounnaline Orthoclase Biotite
Chlorides Sulphates Nitrates
rare rare
rare-common
rare rare
rare very rare very rare very rare rare rare rare
dominant gt60 abundant 30-60 very common 10-30 of the total mineral matter common 5-10 content in the coal rare 5-1 very rare lt1
22
Coal specifications
differences For example dehydration decomposition and oxidation of mineral matter which may occur during the laboratory process can affect the composition of the ash as follows
FeS04nHzO FeS04 + nHZO dehydration reduces the weight of CaC03 CaO + COZ decomposition ash and adds to
volatile matter
FeS + 20z FeS04 oxidation adds to weight of ash
Similarly partial loss of volatile constituents in particular mercury (Hg) potassium (K) sodium (Na) chlorine (CI) phosphorus (P) and sulphur (S) means that the ash is qualitatively and quantitatively quite different from the mineral matter that gave rise to it Its behaviour which is ultimately determined by its composition is also different If the ash sample is used for subsequent composition analysis the concentration of sodium and other volatile inorganic elements may be significantly lower than in the original mineral matter
Carbonate minerals are common constituents of many coals (see Table 5) These minerals liberate carbon dioxide (C02) on heating and therefore can contribute to the total carbon content of the coal as determined by ultimate analysis Whilst the COz content of the mineral matter is important for the correction of other specifications it is not normally included on coal specification sheets for combustion
24 Forms of SUlphur chlorine and trace elements
Procedures for determining these properties are described in various national and international standards (see Table 2)
Sulphur in coal is generally recognised as existing in three forms inorganic sulphates iron pyrites (FeS2) and organic sulphur compounds known respectively as sulphate sulphur pyritic sulphur and organic sulphur Although the total sulphur content provides sufficient data for most commercial applications a knowledge of the relative amounts of the forms of sulphur present is useful for assessing the level to which the total sulphur content of a particular coal might be reduced by preparation processes Commercial preparation plants can generally remove much of the pyritic sulphur but have little effect on the organic sulphur content
Pyrite is one of the substances which enhance the risk of spontaneous combustion by promoting oxidation and consequent heating of the coal (Bretz 1991a) Pyrite is also a hard and heavy substance which adds to the abrasion of coal mills (Cortsen 1983) (see Section 322)
It appears that in many cases some of the sulphur in the coal is retained in the ash as sulphate Thus the sulphate in the ash is invariably greater than the sulphate in the original coal when both parameters are expressed as fractions of the weight of original coal This effect is so large with the lower rank lignites that the ash yield may actually be greater than
the mineral matter content Kiss and King (1979) showed that between 0 and 99 of the organic sulphur in Australian brown coals may be retained in the ash as sulphate The thermal decomposition of carboxylate salts is particularly efficient in trapping organic sulphur as sulphate in ash With higher rank coals that do not contain carboxyl groups it is carbonates or the oxides formed from pyrolysis that tend to fix sulphur as sulphate It is evident that the amount of sulphate in ash depends on both the sulphur content of the coal and the concentration and nature of the materials capable of fixing it during ashing Various national and international standards specify procedures for determining sulphate in ash
Although not strictly part of the usual ultimate analysis procedure determination of chlorine which may be present in the organic fraction of the coal as distinct from the mineral analysis of the ash is often included Chlorine can enter the coal in the form of mineral chlorides in saline strata waters but this accounts for less than 50 of the total amount The bulk of the chlorine is present as CIshyassociated with organic matter probably as hydrochlorides of pyridine bases (Gibb 1983) In general chlorine content in most coals is quite low though there are exceptions For example some British coals can contain up to 1 chlorine (Given 1984)
In combustion chlorine from both alkali chlorides and the organic fraction of coal can combine with other mineral elements and contribute to deposition and corrosion Chlorine content is also used as an indication of potential fouling tendencies as the majority of the alkali metals responsible for fouling problems are present in the original coal associated with chlorine Chlorine can also affect the control of the pH (aciditylbasicity) in FGD plants (Jacobs 1992)
Apart from the major impurities in coal which are measured in the normal analysis there are a wide variety of trace elements which can also occur Clarke and Sloss (1992) have reviewed the typical concentrations of trace elements in coals There is a growing interest in the emission of trace elements from stacks as atmospheric pollutants and one can expect more attention to be given to this over the coming years (Swaine 1990) There has also been increased anxiety over the possible leaching of trace elements from ash or flue gas desulphurisation waste which may be deposited on the ground as means of disposal or use (Clarke and Sloss 1992) (see also Section 524)
25 Coal mechanical and physical properties
The commercial evaluation of a coal also involves assessments of physical properties A variety of tests have been developed to quantify physical properties of coal but each one is usually related to a particular end use requirement Table 6 lists standard measurements for coal physical tests which are considered relevant for handling and combustion
23
ASTM American Society for Testing and Materials AS Australian Standards BS British Standards Institution DIN Deutsches Institut fUr Norrnung ISO International Organization for Standardization
Bulk density flow properties fineness friability and dustiness all affect the handleability of coal
bulk density measurements are designed to evaluate the density of the coal as it might lie in a pile or on a conveyor belt (Folsom and others 1986c) the size distribution test is used to evaluate the size distribution of coal prior to pulverisation This measurement is important as it can be used to determine the suitability of a coal for a particular mill type and is used to assess the efficiency of the mill system Particle size distribution is also determined for the coal sample after air drying and pulverisation Pulverised coal fineness and size distribution is particularly important for burner performance (see Section 41) there are several tests to evaluate coal friability They are designed to determine the extent of coal size degradation and dusting caused by handling stockpiling and grinding
Most modem coal-burning equipment requires the coal to be ground to a fine powder (pulverised) before it is fed into the boiler The Hardgrove grindability index (HGI) is designed to provide a measure of the relative grindability or ease of pulverisation of a coal The test has changed little over the years Traditionally the HGI is used to predict the capacity performance and energy requirement of milling equipment as well as determining the particle size of the grind produced (Wall 1985a) Coals with high HGI are relatively soft and easy to grind Those with a low value (less than 50) are hard and more difficult to make into pulverised fuel (Wall and others 1985 Ward 1984) The grindability of coals is important in the design and operation of milling equipment A fall in HGI of 15 units can cause up to 25 reduction in the mill capacity for a given PF product as shown by the
10--1-----shyOJ sect 5 Cl r
eOl
09 pound
middotE 0 OJ ~
~ 08
lt5 z
constant PF size distribution
50 48 46 44 42
Hardgrove grindability index (HGI)
Figure 3 Mill throughput as a function of Hardgrove grindabaility index (Fortune 1990)
graph in Figure 3 Coals with high HGI values in general cause few milling problems
The abrasion index is a measure of the abrasiveness of a particular coal and is used in the estimation of mill wear during grinding (Yancey and others 1951) The abrasion index is expressed in milligrams of metal as lost from the blades of the test mill per kilogram of coal
The free swelling index (FSI) also called the crucible swelling number is used to indicate the agglomerating characteristics of a coal when heated Although primarily intended as a quick guide to carbonisation characteristics it can be used as an indicator of char behaviour during combustion A high swelling number suggests that the coal
24
Coal specifications
particle may expand to fonn lightweight porous particles that ash residue at high temperatures can be a critical factor in fly in the air stream and could contribute to a high carbon selection of coals for combustion applications Ash fusion content in the fly ash The extent of swelling is a function of temperatures are often used to predict the relative slagging the rate of heating final temperature and ambient gas and fouling propensities of coal temperature (Essenhigh 1981) so that the actual effects in practice are greatly dependent on combustion conditions The The test involves observing the profiles of specifically swelling number is also significantly affected by the particle size distribution of the sample (Ward 1984) Knowledge of the swelling properties of a coal can be used to avoid agglomeration problems in fuel feed systems (Hainley and others 1986 Tarns 1990) The size of the char particle after devolatilisation and swelling has been found to have an important influence on the kinetics of the combustion process 2 3 4 (Morrison 1986 Jiintgen 1987b) IT 5T HT
1 Cone before heating
The FSI can also provide a broad indication of the degree of 2 IT (or ID) Initial deformation temperature 3 ST Softening temperature (H=W) oxidation of a given coal when compared with a fresh 4 HT Hemispherical temperature (H=12W)
unoxidised sample or against a background history of 5FT Fluid temperature
measurement for a particular coal (ASTM DnO Shimada and others 1991)
Figure 4 Critical temperature points of the ash fusion The ash fusion test (AFT) measures the softening and test (Singer 1991 ASTM D1857) melting behaviour of coal ash The behaviour ofthe coals
Table 7 A summary of the major characteristics of the three maceral groups in hard coals (Falcon and Snyman 1986)
Maceral group Reflectance Chemical properties Combustion properties plant origin
Description Rank Reflected Characteristic Typical products on Ignition Burnout light element heating
Vitrinite woody trunks Dark to Low rank to 05-11 intermediate light intermediate ill ill branches stems medium grey medium rank hydrogen hydrocarbons volatiles jj jj stalks bark leaf bituminous 11-16 content decreasing j j tissue shoots and rank j j detrital organic Pale grey High rank 16--20 j j matter gelified bituminous vitrinised in White anthracite 20-100 acquatic reducing conditions
Exinite cuticles spores Black- Low rank -00-05 early methane volatile- jjjj jjjj resin bodies algae brown gas rich accumulating in sub- Dark grey Bituminous -05--09 hydrogen- oil decreasing jjj jjj acquatic conditions -09-11 rich with rank
Pale grey Medium rank -11-16 condensates bituminous wet gases (j) (j)
Pale grey High rank (decreasing) (=vitrinite) bituminous to white to shadows anthracite -16--100
Inertinite as for vitrinite but Medium Low rank 07-16 hydrogen- low fusinitised in aerobic grey bituminous poor volatiles oxiding conditions Pale grey Medium rank -16--18 in all ranks
to white bituminous and yellow to anthracite -18-100 (j) (j) - white
Capacity or rate j = slow Capacity or rate shown in parenthesis refers to vitrinite jj = medium jjj = fast jjjj = very fast
5 FT
25
Coal specifications
Table 8 Summary of coal ash indices (Anson 1988 Folsom and others 1986c Wibberley and Wall 1986 Wigley and others
Index Factors
Ash descriptor Base-acid ratio (BfA)
Ash viscosity T250 of ash degC (OF) Silica ratio
Siagging propensity Base-acid ratio (BfA) (for Iignitic ash CaO + MgO gtFe203) Siagging factor (for bituminous ash CaO + MgO lt Fe203) Iron-calcium ratio Silica-alumina ratio
Slagging factor degC (OF)
Viscosity slagging factor
Fouling propensity Sodium content
Fouling factor
Total alkaline metal content in ash (expressed in equivalent Na203)
chlorine in dry coal
Strength of sintered fly ash Psi
Temperature ash viscosity = 250 poise SiOl(Si02 +Fe203 + CaO + MgO)
(BfA)(S dry)
Fe20 3fCaO SiOlAh03 Maximum hemispherical temperature + 4(minimum initial deformation temperature)
5 T25o(oxid-TlOooO(red)
975 Fs
(Fs ranges from 10-110 for temperature range 1037-1593degC (1900-2900degFraquo
Na203 (for Iignitic ash CaO + MgO gtFe203) (for bituminous ash CaO + MgO ltFe203)
BfA(Na20 in ash) (for bituminous ash CaO + MgO ltFe203) BfA(Na20 water solublellow temperature ash) Na20 + K20 (for bituminous ash CaO + MgO ltFe203)
oxid oxidising conditions red reducing conditions
shaped cones made from ash prepared by the proximate analysis method with a suitable binder The cones are gradually heated in a furnace under either an oxidising or reducing atmosphere until the ash softens and melts Temperatures corresponding to four characteristic cone profile conditions are noted These conditions are shown in Figure 4 The four cone shapes are defined as follows
initial deformation - the initial rounding of the cone tip softening temperature - height equal to width hemispherical temperature - height equal to one-half width fluid temperature - height equal to one-sixteenth width
Under reducing conditions AFTs are lower due to the greater fluxing action (basicity) of the ferrous ion (FeO) compared with the ferric ion which is present under oxidising conditions
The heating value or calorific value is the single most important coal index or quality value for use in steam power stations since it provides a direct measure of the heat released during combustion The energy liberated by a coal on combustion is due to the exothermic reactions of its
hydrocarbon content with oxygen Other materials in the coal such as nitrogen sulphur and the mineral matter also undergo chemical changes in the combustion process but many of these reactions are endothermic and act to reduce the total energy otherwise available
The standard laboratory test measures the gross heating value that is the total amount of energy given off by the coal including latent heat of condensation of vapour formed in the process Under practical conditions water vapour and other compounds (acid forming gases) can escape directly to the atmosphere without condensation and the recoverable heat given off under these conditions is known as the net heating value It can differ most significantly from the gross heating value in coals that have a high moisture content such as brown coals or lignites as the main difference between the two values is the latent heat of evaporation of water The net heating value can be calculated from the standard laboratory-determined gross value based on factors such as the moisture sulphur and chlorine contents of the coal concerned An example of a conversion formula which relates gross and net heating value reads (ISO 1928)
Qn = Qg - 0212 H - 00008 0 - 00245 M MJkg
26
Coal specifications
1989)
Tendenciesvalues
Low Medium Iligh Severe
gt1302 (2375) 1399-1149 (2550-2100) 1246-1121 (2275-2050) lt1204 (2200)
Viscosity proportional to silica ratio
lt05 05-10 10-175
lt06 06-20 20-26 gt26
lt031 or gt300 031-30 Low ~ High
gt1343 (2450) 1232-1343 (2250-2450) 1149-1232 (2100-2250) lt1149 (2100)
05-099 10-199 gt200
lt20 20-60 60-80 gt80 lt05 05-10 10-25 gt25 lt02 02-05 05-10 gt10 lt01 01-024 025-07 gt07
lt03 03-04 04-05 gt05
lt03 03-05 gt05
lt1000 1000-5000 5000-16000 gt16000
where Qn = net heating value Qg = gross heating value H = hydrogen (percentage fuel weight) 0 = oxygen content (percentage fuel weight) M = moisture content (percentage fuel weight)
In North America boiler thennal efficiency is usually quoted on the basis of the gross heating value whereas most European countries use net heating value
Various fonnulae for predicting the heating value of coal from ultimate analysis have been developed On a dry mineral matter-free basis the heating value relates directly to the composition of the coal substance Some of these fonnulae are reviewed by Mason and Gandhi (1980) and Raask (1985)
Petrographic analysis of coals is increasingly being used to add to the information necessary to assess the suitability of coal for combustion in a particular power station Coal petrology describes coal in tenns of its maceral and mineral matter composition (see Table 7) These components can be recognised and measured quantitatively with the aid of a microscope A comprehensive review of the features that
characterise the various members of the maceral groups and rules for their microscopic identification can be found in the Intemational Handbook of Coal Petrography (ICCP 1963 1975 1985) Stach and others (1982) gives an overview of the macerals and their physical and chemical properties and Teichmiiller (1982) Given (1984) Davis (1984) Falcon and Snyman (1986) and Carpenter (1988) provide a good description of the origin of macerals
Maceral composition can be linked to properties of significance for describing combustion perfonnance Relatively little attention has been given to assessing maceral effects on grindability The literature that is available provides a confusing and somewhat contradictory picture This could be a consequence of the relative grindabilities of vitrinite and inertinite reversing as the rank of coal increases (Unsworth and others 1991) The preferential population of macerals within particular size ranges has been reported by several investigators (Falcon and Snyman 1986 Skorupska and Marsh 1989) For example an investigation involving a medium rank bituminous coal revealed a difference between the grindability of vitrinite and inertinite of approximately 15 units with inertinite displaying a HGI value averaging
27
Coal specifications
55 Such differences can significantly influence mill throughput (Unsworth and others 1991)
In certain circumstances it has been reported that a petrographic assessment of coal rank has advantages over the other techniques used as standards (Neavel 1981 Unsworth and others 1991) Parameters such as volatile matter content fixed carbon heating value swelling indices are average properties of a coal sample As such they reflect coal rank but they are also affected by variations in maceral composition Measurement of vitrinite reflectance is widely used as an index of coal rank
Earlier investigators recognised that the carbonaceous materials present in fly ash were predominantly forms of inertinite (Yavorskii and others 1968 Nandi and others 1977 Kautz 1982) Since that time the influence of maceral composition on coal reactivity during combustion has been the subject of considerable study (Jones and others 1985 Falcon and Falcon 1987 Oka and others 1987 Shibaoka and others 1987 Bend 1989 Diessel and Bailey 1989 Skorupska and Marsh 1989 Sanyal and others 1991) It has now been applied in many cases to explain problems that occur during combustion when other traditional tests such as proximate analysis have failed (Sanyal and others 1991)
The application of petrographic assessment as a predictive tool is still believed to be some way off Two reasons for this are
the subjective identification and different criteria being applied by the different countries to distinguish macerals has led to unsatisfactory reproducibility in results This has been illustrated in international exchange exercises conducted by the ICCP in the past It has been clear for some time that there is a need to reduce subjectivity to a minimum This may be achieved by using automated assessment techniques limited validation on a power station boiler scale of the influence of macerals on boiler performance Present operational procedure at boiler scale does not lend itself well to simultaneously monitor performance and allow for full petrographic assessment of the feedstock coal
26 Calculated indices In an effort to extend the use of laboratory results a number of empirical indices have been developed based on the
measurements discussed in the previous subsections These indices have been used to relate coal composition to the performance of power station components While the indices are not measurements as such in many cases they are utilised in the same manner as coal properties The accuracy reproducibility and applicability of these indices depend directly on the specific measurement procedures employed Indices have been developed for
rank reactivity ash descriptor ash viscosity slagging propensity fouling propensity
Rank relationships with coal properties as used nationally and internationally are summarised earlier in Figure 2
Some combustion reactivity indices use a relationship of the proximate volatile matter and fixed carbon of a coal known as the fuel ratio lllustrations of the relationship are given in Section 421
The indices used to describe ash behaviour are summarised in Table 8 The indices can be included in coal specification sheets to help assess the suitability of a coal for combustion How they are used and their relationship to performance are discussed in Section 422 of this report
27 Comments Most coal evaluation testing for combustion relies on empirical procedures which were developed primarily for the carbonisation industry town gas and blast furnace coke manufacture using simple laboratory equipment under conditions which were intended to represent those found in that type of process Despite the shortcomings the techniques required to perform the tests such as for proximate analysis are so simple that they lend themselves to automation This removes much of the risk of operator error and produces repeatable results
As operating requirements become more stringent the weaknesses of some of these techniques are becoming increasingly apparent There is a growing need to develop tests and specifications which reflect more closely the conditions found in power station boilers
28
3
steam generator
burners
mills
environmental control
I
Pre-combustion performance
environmental controlcoal handling
and storage
ash transport fans
The following three chapters describe the effect of coal quality parameters on the performance of various component parts of coal-frred steam generator systems Figure 5 illustrates the components of a typical power station The main power station components include
coal handling and storage mills fans burners boiler ash transport technologies for controlling emissions
This chapter focuses on effects of coal quality on the pre-combustion components of a power station
31 Coal handling and storage The coal handling equipment includes all components which process coal from its delivery on site to the mills This includes a large amount of equipment which (depending on power station design) may include unloading facilities hoppers screens conveyors outside storage bulldozers reclaimers bunkers etc and of course the coal feeders to the mills (Folsom and others 1986b) A high level of automation and remote control is often incorporated in
Figure 5 Typical power station components
29
Pre-combustion performance
Table 9 Illustrative example of USA coal storage requirements (Folsom amp others 1986b)
Coal
Lignite Subbituminous Bituminous
midwest eastern
Heat to turbine 106 kJh 4591 4591 4591 4591 Boiler efficiency 835 862 885 905 Coal heat input 106 kJh 5499 5326 5185 5073 Coal HHV MJkg 14135 19771 26284 33285 Coal flowrate th 429 297 217 168
Design storage requirements t Bunkers 12 hours 5148 3564 2604 2016 Live 10 days 102960 71280 52080 40320 Dead 90 days 926640 641520 468720 362880
Storage time for eastern bituminous plant design t Bunkers hours 47 68 93 120 Live days 39 57 77 100 Dead days 35 51 69 902
equivalent storage time for a plant designed for eastern bituminous coal but fired with the coals listed
modern coal handling facilities including sophisticated stacking-out and reclaim facilities to achieve some degree of coal blending capability Slot bunker systems with bulldozer operated stacking and reclaimers are still preferred by many utilities because of capital cost savings and greater flexibility of stockpile management
Coal storage can be divided into two categories according to the purpose live (active) storage with short residence time which supplies fIring equipment directly and dead or reserve storage which may remain undisturbed for many months to guard against delays in shipments etc Live storage is usually under cover and reserve storage outdoors
When outdoor storage serves only as a reserve the normal practice is to take part of an incoming shipment and transfer it directly to live storage within the station while diverting the remainder to the outdoor pile
The coal storage components are generally sized to provide capacity equivalent to a fIxed time period of fIring at full load (McCartney and others 1990) Typical values are 12 hours for inplant storage in bunkers ten days for live storage and more than 90 days for reserve storage Capacity of the reserve pile can be for example a minimum 60-day supply at 75 of the maximum burn rate These time periods are specifIed by the architectengineer based on the utilitys desired operating procedures and other constraints such as political legislation for strategic stocking The key parameters for assessing the quantity of coal required are
power station capacity heat rate coal heating value
Steam generators of a given capacity operating at steady load
require a fIxed heat input per unit of time regardless of coal heating value (Carmichael 1987) Therefore if the actual heating value of the coal is reduced then the storage capacity and quantities that must be delivered to the utility via the transport system must be increased For example Folsom and others (l986b) compared the storage requirements for four coals of differing rank supplying a 500 MW steam-electric unit (see Table 9) For all performance parameters to remain constant over a wide range of coal heating values substantial variations in coal flow rate at full load are required with factors of as much as 21 in some cases The coal storage requirements for specifIc time periods reflect this same range of variation Also shown are the storage times required for fIring alternate coals in a unit designed to fIre a high heating value fuel an Eastern USA bituminous coal These changes may not affect the ability to operate the unit at high capacity for short time periods However the equipment which transports the coal may need to operate more frequently and this could limit the ability to fIre at full station capacity over an extended period Also normal power station operating procedures may need to be modifIed to permit fIlling the bunkers more than once per day etc
Most of the equipment which transports the coal operates intermittently Thus coal quality changes which result in coal flow rate changes will vary the duty cycle for the transport equipment An increase in flow rate requirements caused by a decrease in coal heating value or an increase in boiler heat rate will increase the duty cycle and may affect unit capacity Provided that these changes in flow rate are small or of limited duration most power stations will be able to tolerate them with no equipment modifIcations Large increases in flow rate for example those that may occur due to a shift from a bituminous coal to a lignite as described in Table 9 may require such long duty cycles that the normal operating procedures of the power stations and maintenance intervals
30
Pre-combustion performance
Table 10 Conveyor Equipment Manufacturers Association (CEMA) material classification chart (Colijn 1988a)
Major class Material characteristics included Code designation
Density
Size
Flowability
Abrasiveness
Miscellaneous properties or hazards
Bulk density loose
Very fine 200 mesh sieve (0075 mm) and under 100 mesh sieve (0150 mm) and under 40 mesh sieve (0406 mm) and under
Fine 6 mesh sieve (335 mm) and under
Granular 127 mm and under
Lumpy 76 mm and under 178 mm and under 406 mm and under
Irregular stringy fibrous cylindrical slabs etc
Very free flowing - flow functiongt 10 Free flowing - flow function gt4 but lt10 Average flowability - flow function gt2 but lt4 Sluggish - flow function lt2
Mildly abrasive - Index 1 - 17 Moderately abrasive - Index 18 - 67 Extremely abrasive - Index 68 - 416
Builds up and hardens Generates static electricity Decomposes - deteriorates in storage Flammability Becomes plastic or tends to soften Very dusty Aerates and becomes fluid Explosiveness Stickiness - adhesion Contaminable affecting use Degradable affecting use Gives off harmful or toxic gas or fumes Highly corrosive Mildly corrosive Hygroscopic Interlocks mats of agglomerates Oils present Packs under pressure Very light and fluffy - may be windswept Elevated temperature
Actual kgcoal flow
Azoo AIOO
~
C~
E
1 2 3 4
5 6 7
F G H J K L M N o P Q R S T U V W X Y Z
may be inadequate In such extreme cases the capacity of the transfer equipment may be insufficient even with continuous operation such that modifications will be required In some power stations it may be possible to increase the capacity of the transport equipment For example conveyor belt speeds may be increased However this can also lead to dust problems and increased spillage especially with friable coal
Unlike the other coal transport equipment the coal feeders operate continuously Thus any change in coal flow rate requirements must be met with an immediate change in feeder speed Coal feeders are usually designed with excess capacity so that minor changes in coal flow rate requirements can be tolerated easily The major changes required by significant changes in coal heating value such as switching
from a bituminous coal to a lignite would be beyond the capacity of most coal feed systems Another factor to consider is the feeder turndown Many feeders have a minimum operating speed beneath which problems such as uneven flow can occur
In addition to changes in the required coal flow rates coal characteristics can produce other detrimental effects on handling and storage systems
In a survey carried out at a coal handleability workshop (Arnold 1988) attendees from utilities and the mining community were asked to rank the problems from one (1 - worst) to ten (10 -least) The ratings are indicated next to each problem
31
Pre-combustion performance
plugging in bins (1) feeders (2) arching and caving in storage (10) flowability hang-up in bins (3) sticky coal on belts (4) freezing in transport (5) storage (8) dusting on conveyors (6) in stockpiles (7) oxidationspontaneous combustion (9)
Other concerns mentioned included abrasiveness of coal causing chute wear wet fuel hang-up in transfer towers sticky fuel in downcomers spillage and sliding from belts due to wetness hang-up in breakers excessive surface moisture and coal sticking in bottom-dumped rail cars Whilst relationships between coal properties and handleability have been established these are not the same as those needed for combustion purposes In fact some coal specifications do not usually include parameters which reflect the handling and storage properties of coal Colijn (1988a) reported that the Conveyor Equipment Manufacturers Association (CEMA) have made an effort to establish a listing of material properties and characteristics which influence the handling and storage of granular bulk materials including coal as shown in Table 10 The coding system has been developed to describe particular material properties such as density size flowability and abrasiveness Where material handling characteristics are in general not easily quantifiable they are listed as hazards - watch out Table II shows typical CEMA codes for various coal
Table 11 CEMA codes for various coals (Calijn 1988a)
Material description CEMA material code
Coal anthracite (River amp Culm) 6OB635TY Coal anthracite sized - 127 mm 58C-225 Coal bituminous mined 50 m amp under 52A4035 Coal bituminous mined 50D335LNXY Coal bituminous mined sized 50D335QV Coal bituminous mined run-of-mine 50Dx35 Coal bituminous mined slack 47C-245T Coal bituminous stripping not cleaned 55Dx46 Coal lignite 43D335T Coal char 24Cl35Q
x refers to a range of particle sizes
311 Plugging and flowability
The economic impact of plugging of coal transport facilities can be significant resulting in added manpower costs for clearance partial unit deratings or in some cases total shutdowns For example at 15 $MWh a typical 575 MW unit could lose over 1000 $h income as a result of partial deratings for each plugged silo (Bennett and others 1988)
No flow or limited flow problems are often due to the formation of stable arches andor increases in wall friction (Arnold 1990) Binsilo blockages occur when the coal has become sufficiently adhesive to form a stable arch which supports the weight of the coal above it Increases in wall friction which is a measure of the sliding resistance of the coal against the bin wall will result in coal adjacent to the wall moving slower than that in the centre zone This gives
mass flow funnel flow expanded flow
Figure 6 Typical flow patterns in bunkers (Colijn 1988a)
rise to different flow patterns in various parts of the bin (see Figure 6) For most coals three to four days outdoor storage increases the chances of one or both of the above problems occurring Coal flowability is directly related to various coal characteristics depending on the coal rank Some of the major contributing properties are (Llewellyn 1991)
surface moisture particle size distribution clay content changes in bulk density
Surface moisture is considered the most critical factor There is a level below which regardless of other factors coal flow problems do not occur There is also a critical surface moisture at which maximum adhesion and bulk coal strength will occur Above this level additional water flows away rises to the surface or in the extreme decreases strength due to slurry formation Adding moisture to dry coal first creates a lubricating effect and allows particles to slide against each other more easily and pack into a denser stronger material Surface tension develops as a form of physico-chemical bonding (known as hydrogen bonding) increases between water and coal particles
Particle size distribution contributes to flowability problems because it determines the available surface area and hence adhesion characteristics The proportion and size of the smallest particles in bulk coal have a great effect on its handleability In some coals the ash and clay content which is inherent in the coal concentrates in the fines fraction (see Table 12) This also influences coal flowability characteristics Average particle size can be affected by coal handling procedures and equipment or by natural causes A major factor influencing the size composition of a coal product is its friability Friability is a combination of the impact strength and fracture cleavage characteristics of the coal and its susceptibility to degradation due to a rubbing action during handling A high fines content if combined with a critical moisture level can result in a coal with very poor handling properties (Llewellyn 1991) In low rank coals large pieces may fall apart and produce excess fines in dry air If the coal is subsequently rewetted the combination
32
Pre-combustion performance
Table 12 Analysis of ash and clay distribution in a coal by mesh size (Bennett and others 1988)
Property Base fuel +6 Mesh (+335 mm)
6-50 Mesh (036-030 mm)
50-100 Mesh (030-015 mm)
-100 Mesh (-015 mm)
Weight Ash (Dry) Silica
10000 2277 6740
4514 1702 5850
4512 2320 6490
765 3596 7790
209 4153 8380
of increased surface area and moisture can have a substantial impact on flow characteristics
The clay content of coal affects its cohesive characteristics Increased clay content in strip mined subbituminous coal and lignites has been shown significantly to increase wall friction and shear strength at a given moisture content (Bennett and others 1988)
If all of the above factors increase simultaneously that is high surface moisture high clay high fmes percentage and coal is stored in a bin for several days drastic increases in coal bulk shear strength lead to significant adhesion bridging and consequent coal flowability problems
There are no coal specifications which relate to coal bulk shear strength although tests have been developed which provide bulk shear strength values for coals They are used as a measure of the cohesive strength or stickiness and have been used as a quantifying factor for problem coals Shear strength can be measured using either a rotational or a linear translational instrument Results from the rotational shear test can be obtained within an hour and may be used on-site to provide real time analyses (Bennett and others 1988 Colijn 1988a) The principle of the rotational shear tester is to provide an equally distributed shearing force across a horizontal plane in the coal sample This is done while the sample is placed under varied loads The bulk shear strength determined for a particular fuel handling situation can be represented as a value in applied pressure or as an arbitrary relative flow factor value (FFV) The FFV can be plotted relative to moisture and clay values A critical arching diameter (CAD) can be extracted by combining results from a shear tester with the bulk density of the coal Calculations can then be made for the geometric configuration of each type of coal container for particular types of coal thus negating possible problems of archingplugging in a binsilo Figure 7 shows the data derived from shear tests for more than twenty coals conducted by Colijn (1988b) The CAD was plotted against the surface moisture content for the coals and while a clear relationship between increasing moisture content and increasing CAD exists there is significant data scatter As discussed earlier other investigators (Blondin and others 1988 Arnold 1991) have shown that the amount of clay and fines also influence the CAD
As many coals have a tendency to increase their strength after a few days of consolidation it is often necessary to test the coals under these conditions For these cases a coal sample would be kept inside the shear cell under pressure for a number of days to simulate the time period during which the coal may be contained within a bin or silo Arnold (1991) reported a study conducted to define further the relationship
mass flow - instantaneous
2 E ~
til Q) E til 0 0) c
c ()
ro (ij ()
8
0
0
Figure 7
3 E
~ Q) E til 2 0 0)
~ c ()
ro (ij ()
8
0
0 0 0
o
0
6 o 00 oo0
o D cPo DO
0 CI o~ 0_o
--tJ 0 0 0 _ - shy
9 - Data for a variety of coal samples
2 4 6 8 10 12 14 16
Surface moisture
Surface moisture versus critical arching diameter (CAD) determined from shear tests (Coljjn 1988b)
3-day consolidation
10 moisture
+ 8 moisture
6 moisture
+ +
0
0 2 4 6 8 10 12 14
Fines -44 ~m (-325 mesh)
Figure 8 Three-day consolidation critical arching diameter (CAD) versus per cent fines in coal as a function of moisture content (Arnold 1991)
of coals and their handling behaviour Six coals that were combusted at an Eastern USA power station were selected The coals had very similar chemical analyses and all met the power station coal specification but exhibited a range of handling characteristics As an illustration of some of the preliminary results of the study Figure 8 shows the influence of the percentage fines (particles less than 44 lm in diameter) moisture content and consolidation time on the CAD calculated from shear tests conducted on one of the coals The instantaneous CAD values are not shown in Figure 8 but were in fact 30 lower in value than the three-day consolidation values Generally for all the coals studied the maximum value occurred at the highest moisture
33
Pre-combustion performance
contents and there was a tendency to increase with increasing fines content and increases in consolidation time
More recently Rittenhouse (1992) reported the development of a series of simplified empirical tests that can be run by power station staff members that make it possible to identify potential problem coals The results of the tests are indices that characterise the flowability of coal The individual indices are
arching index ratholing index hopper index chute index flow rate index density index
These can also be used to indicate when hopper modifications may extend the operating range of the system so that coals that are less than free flowing can be handled The tests are reviewed in greater detail by Johanson (1989 1991) Arnold and OConnor (1992) have recently reported the development of another simplified test that can be used more easily on-site and has been validated against the tri-axial shear tester
Coal flowability can be modified by the use of chemicals which specifically enhance the flow of wet coal Additive selection and performance depend greatly on fuel quality (Bennett and others 1988) The effectiveness of particular additives on problem coals is assessed by measurement of shear strength values produced
312 Freezing
Although it is difficult to assess the cost related specifically to coal moisture freezing during cold weather some of the potential problems are as follows
production losses at the mine beneficiation plant and the utilities increased labour costs associated with frozen coal removal less safe working conditions costs related to operation of thawing and mechanical removal equipment transport equipment damage due to mechanical or thermal means of removing frozen coal from ships rail cars or trucks demurrage costs on rail cars accelerated rail wear andor derailment
Work done in the mid-1970s showed that surface moisture of a coal caused the problems For freezing to occur the coal being handled must be exposed to sub-freezing temperatures for a sufficient period of time It is generally accepted however that no problems with handling should be expected unless the surface moisture exceeds approximately five per cent Total moisture content of the coal is inadequate as a sole indicator since coal that has a high inherent moisture may not freeze at 20 or more total moisture while coal with a low inherent moisture
may freeze and cause severe problems at seven per cent or below
Each coal type has a characteristic inherent moisture content defined here as the moisture contained in the fine pore structure itself Depending upon rank porosity and hydrophilicity of the coal inherent moisture ranges from less than one per cent to greater than 20 of the coal mass While surface moisture is undoubtedly the primary cause of coal freezing and the consequent handling problems other factors also influence the situation For example Connelly (1988) reported that at lower temperatures the increased viscosity of water renders the dewatering of coal processes less efficient Total moisture content of dewatered coals can be expected to increase at lower temperatures as shown in Figure 9
90
86 bull
t-O)
s 82 bull
iiimiddot0 E 78
Cii l 0V 0)
cr 74
72 bull
66
4 10 20 30 40 50 Temperature degC
Figure 9 Dewatering efficiency versus temperature (Connelly 1988)
Particle size is also important If the coal particle size were consistently large that is 127 cm (h inch) or larger it would be unlikely that the particles would pack together sufficiently to freeze and cause a serious problem Current mining methods use continuous longwall techniques to extract coal with consequent breakage and fines production For this reason it is impractical for beneficiation plants to furnish a product with a minimum particle size of 127 cm or greater for all shipments unless some form of agglomeration process is used Typically coal being shipped contains a wide range particle size distribution and a substantial amount of material less than 016 cm in diameter Because of this particle size distribution the fine particles of coal can pack between the larger ones and form a more continuous solid mass The finer particle size coal also tends to hold a larger percentage of surface moisture With the finer particle size and increased surface water more particle-to-particle contact occurs accentuating the freezing problems
The freezing process can be offset by the use of additives such as urea calcium chloride solution or polyhydroxy alcohols (Hewing and Harvey 1981 Boley 1984 Connelly 1988)
34
Pre-combustion performance
313 Dusting
Most bulk solid materials have the potential to generate dust during handling Dust can be generated while the coal is in motion such as during transfer from transport to storage and even as wind borne dust from stockpiles This creates safety as well as environmental problems The extent of dust problems may be related empirically to particle size distribution (the amount of fines) moisture content moisture holding capacity and the wind speed (Mikula and Parsons 1991) Nicol and Smitham (1990) reported that in the case of Australian export coals they are sold with a nominal top size of 5 cm but as was discussed earlier there is a wide range of size distributions covered by this specification Figure 10 shows the broad range of coal sizes that are exported This implies that the potential dustiness of coal is a variable with coal source Sherman and Pilcher (1938) have done considerable work in the area of dust control and have tested the size of dust particles in the ASTM D547 dust cabinet test and found that the diameters of particles range from 11 to 55 11m Devised in the 1930s the test is perceived to be somewhat dated as it was originally designed to simulate coal delivery into a bin
Nicol and Smitham (1990) investigated the effects of moisture on the lift-off potential of different coals over a range of wind velocities using a laboratory wind tunnel facility They found that depending on the coal size fraction the velocity to remove wet particles was between 25 and 75 greater than the dry particle removal velocity Alternatively the amount of coal removed at a given velocity is reduced as the moisture content increases Figure 11
99
80
E 60 -E 7 40
if ro 0
20 0
N middotw 10 m 0 c 5J
shaded area encompasses 90 of export coals with coarsest (lower) and finest (upper) size disributions also shown
0125 025 05 2 4 8 16 315 63 Particle Size mm
Figure 10 Size distributions of Australian export coal (Nicol and Smitham 1990)
illustrates the effect and shows that a critical moisture content of about 9 in the coal can be reached at which coal removal can be largely prevented The effects of different coals show up most clearly in the moisture content to prevent any dust emission that is the intercept on the moisture axis in Figure 10 Table 13 summarises the results for the three coals of different properties Rank and chemical properties such as volatile matter content are poor indicators of the propensity for different coals to dust Porosity as reflected in the moisture holding capacity does provide a useful indicator of the potential dustiness of coal Coals with a low moisture holding capacity that is a low equilibrium moisture have little internal porosity so that once this internal volume is filled the excess water remains at the particle surface where it is available to form bridges of water between adjacent particles preventing their removal in an air stream High moisture capacity coals require a greater amount of water to fill the internal volume before water is available at the surface to be an effective dust control agent Jensen (1992)
2000
o
N
E Oi ui Cf)
g Cii 0 ()
Q) gt ~ S E J u
1500
1000
500
0
0
0 0
0 0
amp0
0 ~ 0
0 0
0
0
o 2 4 6 8 10 12
Total moisture
Figure 11 Coal lift-off from a stockpile as a function of total moisture content (Nicol and Smitham 1990)
Table 13 Effect of coal properties on critical lift-off moisture content (Nicol amp Smitham 1990)
Coal Critical moisture Reflectance Australian coal Moisture holding content Ro max rank nomenclature capacity
1 100 094 high volatile bituminous A 25 2 115 120 medium volatile bituminous 40 3 210 073 high volatile bituminous A 120
66
35
Pre-combustion performance
reported that work carried out by ELSAM Denmark has shown that coals with a sUlface nwisture content of 2-3 was sufficient to prevent dusting of some coals
314 Oxidationspontaneous combustion
All coals when stored tend to combine to some extent with oxygen from the air in a process known as weathering (Davidson 1990) This causes some loss of heating value generally less than 1 in the first year of storage for most coals but may be up to 3 for low rank coals - and can change firing characteristics (Singer 1989a) Weathering also tends to promote reduction in size or crumbling (Llewellyn 1991)
Llewellyn (1991) also reported that grindability tests carried out on both fresh coal supplies and the coal stored on the surface of a stockpile indicated a clear separation in behaviour Surface samples were reported as being significantly harder (average 43 HGI) to grind than the fresh coal supply samples (average 52 HGI) The hardness increased with the age of the stockpiled coal A similar clear separation was found between the surface and the interior of the stockpile
Oxidation releases heat and if conditions in the stockpile are such that it occurs at a sufficiently rapid rate enough heat can be generated to cause spontaneous combustion (Sebesta and Vodickova 1989)
In brief the coal properties that have been found to influence oxidation and spontaneous combustion are
rank (heating value or volatile matter) moisture content ash content particle size
Malhotra and Crelling (1987) reported that as the rank of coals decreases the susceptibility for spontaneous combustion increases Cacka and others (1989) suggested that this phenomenon may be related to the increasing content of aliphatic structures which have a higher propensity to react with oxygen than aromatic structures present in coal However there are many anomalies to this straight rank order susceptibility Chamberlain and Hall (1973) have in fact pointed out that some higher rank coals may be more susceptible to spontaneous combustion
The mechanism of water adsorption into the pores of coal also releases heat so that heating in a stockpile will be dependent to some extent upon the inherent moisture (Matsuura and Uchida 1988 Iskhakov 1990) In most cases excess moisture can suppress the heating process (Taraba 1989) although cases have been reported where addition of water to an overheating stockpile can exacerbate the problem and these have been discussed in greater detail in a review by Chen (1991)
The mineral matter composition of coals can influence their susceptibility to oxidation Dusak (1986) reported incidents where mineral matter can play the role of oxidation
promoters by increasing oxidation rate and heat emission due possibly to exothermic reactions of the mineral matter itself with oxygen Work by Cacka and others (1989) determined that iron and titanium were particularly active in the coals under investigation Nemec and Dobal (1988) reported the influence of pyritic sulphur The magnitude of the influence on the oxidation process depends upon mineral matter size and its dissemination within the coal along with the rank moisture content and size of the coal
Particle size influences the surface area available for oxidation Several workers have reported that the smaller the particle size the greater the heat build up within coal stockpiles (Brooks and Glasser 1986 Nemec and Dobal 1988 Llewellyn 1991)
A number of tests have been devised to assess the extent of oxidation of a coal and its susceptibility to spontaneous combustion These include
crossing point test This measures the ignition temperature of a coal sample when it is heated at a constant temperature rate in a small cylindrical furnace The ignition temperature is measured as that at which the coal temperature crosses or becomes greater than the furnace temperature (Brown 1985) This can also be known as the runaway temperature (Gibb 1992) Differential thermal gravimetric analysers and calorimeters are also used to carry out a similar form of test (Clemens and others 1990 Shonhardt 1990) free swelling index test (see also Section 25) Shimada and others (1991) used free swelling index to monitor the extent of weathering of coals in a stockpile The swelling index of a Polish coal (K11) was seen to decrease significantly after a short storage time of three months (see Figure 12) It could also be used to distinguish between coal samples taken from the body (K11) of the coal stockpile and those from the slope (K11 slope) The test can only be applied to coals that exhibit a high initial swelling index as some coals with low initial swelling index (such as Kl in Figure 12) do not give any perceptible change after storage spectroscopic techniques Berkowitz (1989) has reviewed the spectroscopic methods utilised to detect oxidation of coal These can include Fourier transform shyinfra red (FTIR) spectroscopy electron spin resonance (ESR) nuclear magnetic resonance (NMR) and fluorescence microscopy (pavlikova and others 1989 Bend 1989)
Most of the above tests are not standardised With the exception of FSI which is generally used as an indicator of the caking nature of coals they usually are not included in a typical coal specification
At present none of the above effects can be quantified accurately The overall impact on operation and any required modifications must be based primarily on experience The influence of coal quality on the spontaneous combustion of the coal can be minimised by careful layout and construction of the stockpiles
36
Pre-combustion performance
bull 6
--- K1
0 K11
x L K11 slope 5 0
(]) 0 4 0 ~
0OJ sect 3CD ~ 0
(f)
2
L ~ - - - - - - - - - - - - 1f - - - - - - - - - - -- - - - - - shy II I
o 3 5 7 9 11 13 15 17 30 40 50 60 70
Storage time months
Figure 12 Influence of storage time on swelling index (Shimada and others 1991)
The special requirements for low rank coal storage are reviewed in an lEA Coal Research report entitled Power generation from lignite (Couch 1989)
32 Mills Most large steam-electric units are direct fIred that is the coal is supplied to the mills and is pulverised continuously with direct pneumatic transport of the pulverised coaVair mixture to the burners Thus the performance of the mills has a direct effect on the performance of the unit In modern practice a single mill can supply several burners In tangentially fIred systems all four bumers on a single elevation are typically supplied by a single mill In wall fIred systems a single mill may supply a complete row or another symmetrical array of burners A common design practice is to size systems to achieve full load with one or more mills out of service This allows time for maintenance and allows the spare mill to be brought on-line in the event that a failure occurs in one of the other mills
Because of their heterogeneous nature coals used for combustion can exhibit a wide range of grindabilities and require different milling actions to produce a suitably sized product Fine grinding of coal - generally 70 or more passing 75 11m (200 mesh) - is the standard commonly adopted to assure complete combustion of coal particles and to minimise deposits of ash and carbon on heat absorbing surfaces (Carmichael 1987) The different mill designs can be classified according to speed
low-speed mills are of the balVtube design with a large rotating steel cylinder and a charge of hardened balls Coal grinding occurs as the coal is crushed and abraded between the balls medium-speed mills are typically vertical spindle designs and grind the coal between rollers or balls and a bowl or face There are a number of designs in service differing in the specific design of the equipment which rotates size and shape of the grinding elements etc high-speed mills have a high-speed rotor which impacts and breaks the coal
Table 14 Preferred range of coal properties (Sligar 1985)
Mill type Low speed
Maximum capacity tJh 100 Turndown 41 Coalfeed top size mm 25 Coal moisture 0-10 Coal mineral matter 1-50 Coal quartz content 0-10 Coal fibre content 0-1 Hardgrove grindability
Medium High speed speed
100 30 41 51 35 32 0-20 0-15 1-30 1-15 0-3 0-1 0-10 (0-15)
index 30-5080 40-60 60-100 Coal reactivity low medium medium
The range of properties listed above is a preferred range and operation outside these limits is possible
Numerical values for the preferred range of coal properties appropriate for each mill type are given in Table 14 Most large steam-electric units use balVtube or vertical spindle mills
Coal mills integrate four separate processes all of which can be influenced by coal characteristics
drying grinding classifIcation transport
321 Drying
Earlier mills used external dryers before the coal was fed to the mills placing an economic disadvantage on the system Internal drying was developed to overcome this The surface moisture of the coal must be evaporated in the mill to avoid agglomeration of the particles (Sadowski and Hunt 1978) As the primary air is used for conveying the coal the only variable for drying is the temperature of this air The primary air temperature is adjusted to achieve a mill discharge temperature high enough to ensure complete drying in the
37
Pre-combustion performance
Table 15 Maximum mill outlet temperatures for vertical spindle mills (Babcock amp Wilcox 1978 Singer 1991)
Maximum temperature degC (OF)
Coal Babcock amp Wilcox Combustion Engineering
High volatile 66 (150) 71-77 (160-170) bituminous
Low volatile 66-79 (150-175) 82 (180) bituminous
Lignite 49-60 (120-140) 43-60 (110-140)
grinding zone For example Table 15 lists the maximum mill discharge temperatures recommended by Babcock amp Wilcox and Combustion Engineering The discharge temperatures are fixed for safety reasons and are dependent on coal type For bituminous coals the value is usually between 65degC and 90degC with the lower value for fuels of high volatility to reduce the potential for mill fires Higher temperatures of over 100degC have been reported to be used in some cases (Jones and others 1992) Standard proximate analysis volatile matter tests have been used to provide some indication of the likelihood of spontaneous combustion High volatile matter coals are more reactive and more susceptible to spontaneous combustion under these conditions
The primary air temperature required to dry the coal depends on several factors including its moisture (or ice) content temperature and specific heat together with airfuel ratio and mill design The required air temperature may be calculated via a simple energy balance (Folsom and others 1986b)
Figure 13 shows the effect of coal moisture on primary air temperature requirements for vertical spindle mills manufactured by Babcock amp Wilcox and Combustion Engineering As the moisture content of the coal increases so the inlet air temperature must increase to compensate Increases in the coal moisture content can impact unit capacity if the primary air supply system cannot provide air at a high enough temperature It should be noted that to
provide more heat to the drying process the aircoal ratio can be increased However the aircoal ratio affects classifier performance and other downstream operations such as burner performance pulverised coal transport and wear in the coal supply system These effects must be considered Increasing the air temperature increases the potential for mill fires since dry coal particles especially those recycled from the classifier may come into contact with the high temperature air entering the mill
Low-speed mills are most sensitive to coal surface moisture content The capacity of these mills falls in an approximately linear manner with increase in moisture content The decrease in mill capacity is of the order of 3 for each 1 increase in coal surface moisture This effect is present because of the use of a lower airfuel ratio with these mills lower primary air temperature and less efficient mixing within the mill body Medium- and high-speed mills are not nearly as sensitive to high moisture coal
322 Grinding
The size consistency of the coal feed has a direct effect on the power requirements of the mill (see Section 632) All three types of mill are affected by coal feed top size Table 14 gives the critical feed top size for all three types of mill Low-speed mills are particularly sensitive to coal top size Mill capacity falls in a regular manner with increase in coal feed top size In addition to the top size the overall particle size distribution is also of significance In all cases the presence of excessive proportions of fines in the feed to the mill acts to the detriment of the full output
The fineness required is usually related to the rank of a coal the higher the rank of the coal the fmer the particle size distribution needed to achieve satisfactory combustion that is an increase in fmeness with decreasing volatile matter content The approximate size ranges which are acceptable for coals of different rank to ensure complete combustion are shown in Table 16 Analysis of the combustion process shows that burnout is a function of the proportion of particles over 100 1JlIl rather than the amount less than 75 -Lm It is to be expected that increasing the 200 IJlIl oversize from 1 to
Table 16 Comparison of fineness recommendations ( passing 200 mesh -75 11m) (Babcock amp Wilcox 1978 Cortsen 1983)
Babcock amp Wilcox specification ASTM classification of coals by rank
Fixed carbon Fixed carbon below 69
Type of furnace 979-86 (petroleum coke)
859-78 779-69 BtuI1b gt13000 (gt303 MJkg)
BtuI1b 12900-11 000 (300-256 MJkg)
BtuI1b lt11 000 (lt256 MJkg)
Water-cooled 80 75 70 70 65 60
ELSAM Denmark specification
Volatile matter content dry ash-free () lt10 10-20 20-25 gt25
Water-cooled 85 80 75 70
38
Pre-combustion performance
Eastern USA coals (Combustion Engineering)
80a C leaving mixture temperature
H 2 0 entering-leaving
300 14-20
o 12-20 a
10-20
8-20
6-15
4-15
2-10
Babcock amp Wilcox
3000 a
(i100 CIl ~
gt 3
3 4 5 Cl
9 (1)kg of air leaving millkg of coal a 200 lt1l Cii Cl E
Midwestern USA coals (Combustion Engineering) 2 ill
nac leaving mixture temperature ~
laquo 100
JI 24-70 entering-leaving
22-65
26-75 H 0
~ 2
20-60
18-60300 shy16-55
o 2 4 6 8 1014-50 12-50 kg of coalkg of air
10-45 8-40
6-40
100
2
~
OJshysect
pound 0 ~
ES
2 3 4 5
kg of air leaving millkg of coal
Figure 13 Primary air temperature requirements depending on moisture content and coal type (Babcock amp Wilcox 1978 Singer 1991)
39
ie curve is unreliable in this area
60 lt75 ~m
lt75~m
lt75~m
90 lt75 ~m----shy
25 50 75 100
Pre-combustion performance
2 would have a much more significant increase on bumout than decreasing the under 75 lm from 70 to 65 Oversize particles are believed to contribute to slagging problems in boilers although there are no adequate correlations to relate particle size distribution to the incidence of slagging (Babcock amp Wilcox 1978 Singer 1991) The use of low NOx combustion strategies has required a policy of finer grinding for some coals in order to offset the increased unbumt carbon found in the fly ash (Heitmiiller and Schuster 1991)
The ease by which a coal can be ground within a particular type of apparatus is termed its grindability The most common measurement is the Hardgrove grindability index (HGI) (see Section 25) The HGI is widely accepted as the industry standard for evaluating the effects of coal quality on mill performance for high rank coals (Babcock amp Wilcox 1978 Singer 1991) The rated capacity of a mill is defined as the amount of coal (tlh) that can be ground to a fineness of 70 through a 75 lm sieve using a coal with HGI of 50 or 55 Mill manufacturers tend to be divided on how mill capacity is determined for a particular coal Some provide correlations relating the HGI of the coal to mill output for each standard mill size Other manufacturers depend on assessments made in proprietary small test mills or full size mill tests with large samples to give more confidence to anticipated performance of mills with the specification coal(s) With the multitude of mill designs available there is no reason to expect that the capacity of each type should be related to HGI according to any universal relationship
The Hardgrove test is limited in its application as it is a batch operation which is then related to a continuous process Mills
are air swept so that as comminution proceeds fine particles are quickly removed from the grinding elements whereas they remain in the grinding zone in the Hardgrove machine (Hardgrove 1938)
Values of HGI for coal lie in the range 25-11 O Within the range of 42-65 HGI is probably a good indicator of grindability providing the other properties (moisture specific energy etc) are considered Outside this range confidence in HGI is not so good (see Figure 14) Many attempts have been made to correlate HGI with coal composition (Singer 1991) but whilst there is a general trend with coal rank as seen in Figure 15 the scatter is enormous For example the HGI for high volatile bituminous A coals range from 30 to 75 a factor of 25 The scatter could be accounted for by the distribution of macerals in the coal (Fortune 1990) The milling properties of the different maceral types can give rise to segregation of macerals within particular size ranges For example vitrinite tends to be more brittle than exinite or inertinite and is usually concentrated in the finer fraction of the milled coal (Falcon and Falcon 1987 Conroy 1991) In addition vitrinite and exinite are more reactive than inertinite so that a greater concentration of inertinite will generally be found in the unbumt fuel than in the parent coal Inertinite also tends to concentrate in the larger particle size ranges where its lower reactivity has a noticeable effect on bumout It should be noted that this will depend on the different forms of inertinite as some types are more reactive than others (Bailey and others 1990) These observations are dependent greatly on maceral distribution within the coal Macerals in some coals occur in discrete layers whereas in others (for example South African coals) they can occur as intimate associations (Falcon and Ham 1988) The distribution as
20
16
ist5 12 2 2shy0 ro g- 08 ()
04
o
curves extrapolated to zero capacity usefull range for
(HGI =13) curves
range in which bituminous coals are found
Hardgrove grindability index (HGI)
Figure 14 Variation in capacity factor with HGI for different fineness grinds (Fortune 1990)
40
Pre-combustion performance
o
o o
bull Ball mill indexes
Hardgrove tests converted to equivalent Ball mill indexes
bull bull 0
ltlOl 0
etgtz l 2 2
100 - o o o
90
o80
a 70S xOl U ~ 60 pound 0 ro 50 U sect 01 Ol 40 gt e -e01 bull ro 30 I U 0 m
en enJ J Jroen middot0 middot020 Olen Olen ~ 0 0 degoJ _J _J ro ro c c 0 oen len~ gt 0 0 J c cmiddotE middotE EJ~ roc roc gtJ
C middot02 CEo
3 omiddotE omiddotE o~ ro10 3 0 _
Eg cp ro eO2 ~~~ gtJ gtJ middot~middotE gtEmiddotc 0 0 J c~ middotE c
0 0 uJ 3J Q)ouo 010 010 Ol- C01 J J Jc 0middot Ol =i Cf) Cf) Cf)roU Im Iltl ~o -10 Cf) ltl ~
0 9 10 11 12 13 14 15 16 70 80 90 100
Moist mineral-matter-free MJ Dry mineral-maller-free fixed carbon
Figure 15 HGI for several coals as a function of rank (Elliott 1981)
described will effect the particle composition and other coal to 77 and mainly in the 60 to 70 range In general such coals physical properties These effects cannot be predicted from would not be expected to cause difficulty with grinding proximate analysis and so could account for discrepancies in the anticipated performance of coals having similar The abrasive properties of a coal and especially its associated proximate analysis values but with different petrographic minerals cause wear of the grinding elements and other compositions surfaces in the mill The extent of this wear determines the
intervals between planned maintenance periods and the Grinding of coal blends in which the components have possibility of shutdowns It is therefore of great importance widely different HGI values have shown that care is required for an operator to have an idea of how long these periods are in the interpretation of the results Byrne and Juniper (1987) likely to be and how unplanned outages caused by excessive observed that in such cases the harder material tended to mill wear can be avoided concentrate in the coarser fractions of the pulverised fuel and the softer coal in the finer fractions It was believed that this Wear is caused by one of four mechanisms (Fortune 1990) was a consequence of the softer coal blanketing the harder coal and so preventing full grinding of all the fuel adhesion
surface fatigue One difficulty with HGI is reproducibility BS ISO and AS1M abrasion standards all state that a spread of three units is acceptable This corrosion is equivalent to a 4 change in mill capacity Comparisons from different laboratories have given a reproducibility of Adhesion and surface fatigue effects in milling are negligible around eight to nine (Fortune 1990) This is equivalent to a mill compared with abrasion and corrosion capacity variation spread of 12 which is clearly unacceptable as an indication of grinding performance The rate of abrasive wear in mills will depend in general on
the following factors Attempts have been made to develop alternative grindability indices but so far none of these has attained widespread use the type of coal used especially the amount and Typical of these is the continuous grindability index (CGI) composition of the incombustible minerals associated which relates mill performance to power input It was with the coal developed for low rank coal applications A new method has the material used for the mill rolls and bowls also been proposed for determining coal grindability and the design of the mill abrasivity properties using a single machine by Scieszka (1985) although it should be noted that this work was based The most widely used abrasion test is the Yancey Geer and on a limited range of coals with HGI values ranging from 39 Price (YGP) test (Yancey and others 1951) although its
41
Pre-combustion performance
repeatability varies with coal characteristics For abrasive coals the repeatability is about 3 However for coals with low abrasiveness repeatability may be as low as 18 Babcock Energy Scotland use a similar test but with a smaller coal sample (Cortsen 1983) Babcock amp Wilcox in the USA has developed an abrasion test using a radioactive tracer technique (Goddard and Duzy 1967) This test produces a measurement of mill wear albeit at a laboratory scale
Literature data indicate that coal itself is not very abrasive (Parish 1970) Of the associated minerals usually present in coal only quartz (SiOz) and pyrite (FeSz) are considered to be hard enough to cause significant wear Other minerals mainly clays are generally quite soft and friable and do not contribute much to mill wear The earlier studies have shown some correlation between wear and quartz or pyrite content of the coal but the correlations obtained were generally not widely applicable (Parish 1970) In investigations carried out by Donais and others (1988) it was found that as well as the total amount the size of the quartz and pyrite grains significantly affected the wear rate The study was carried out on eight different US coals using NIHARD rolls in both Babcock amp Wilcox and Combustion Engineering mills In general the data indicated that the coarser fractions of quartz and pyrite contribute more to mill wear than the finer size fractions The best correlation between the data was as described in the following expression
Abrasion (radial wear per tons of throughput) =F (3 Q+ P)
where F = constant
Q = ( Quartzgt100 Ilm) P = ( Pyrite gt300 Ilm)
Donais and others (1988) found that the intercept of the curve from the above relationship on the Y axis (mill wear) was well above zero indicating that the effect of the finer fractions of the quartz and pyrite are not negligible and that the coal itself or other minerals may also contribute to wear It should be noted that the size distribution of pyrite and quartz are not normally measured and are not usually included in coal specifications
Other experimental techniques for abrasion testing are summarised in an early report by Parish (1970)
Erosion by mineral particles picked up in the air stream carrying pulverised coal through the mill classifier and ducting is a recognised problem The following parameters affect erosion rates
stream velocity - erosion rate increases exponentially with velocity For ductile materials the exponent is about 23 for brittle materials the exponent ranges between 14 and 5 impingement angle on mill surfaces - maximum erosion rates occur at 30deg for ductile materials and at 90deg for brittle materials particle size - erosion rates increase with particle size up to a critical size above which no increase is observed
323 Size classification and transport
Reduction in oversize particles after initial milling is achieved by separation and recycling of particles through the mill to be reground until they are sufficiently small to pass through a classifier The classifIer can be adjusted to vary the final fineness of the coal Coal fineness affects essentially all processes occurring downstream of the mill including ignition flame stability flame shape ash deposition char burnout etc However if the classifier is adjusted for greater fineness to accommodate for example the firing of a lower volatile coal (see Section 41) the amount of material recycled back to the grinding zone increases This alters the grinding process and if the coal mass in the grinding zone increases too much the grinding elements may begin to skid or excessive spillage can occur The initial coal particle size and grindability can affect the fine tuning of the classifier
The primary air flow rate to the mill is based on the requirements of the burner mill and pulverised coal transport At full load the air flow rate usually corresponds to an aircoal mass ratio of about 20 For a given size of pipes the air flow rate can be adjusted over a narrow range only without causing de-entrainment of PF or increasing pipeline wear for lower or higher rates respectively For a given mill for example ring ball type roller mills supplied with design coal and having 20 of total air as primary air at full load the calculated coalair ratio changes from about 05 kgkg to about 036 kgkg by reducing load from 100 to 50
The relationship between primary air flow rate and coal flow rate is established by the mill manufacturer Moisture content of the coal determines the necessary primary air temperatures as discussed earlier in Section 321 Moisture content of the coal may therefore influence effective and accurate transport of the coal through the mill
33 Fans Coal fired steam-electric units use a number of fans to move air flue gas and pulverised coal The major type of fans include
forced draft (FD) fans - supply air to the wind box under positive pressure induced draft (ID) fans - withdraw flue gas from the furnace and balance furnace pressure primary air (PA) fans - supply air to the mills flue gas recirculation (FGR) fans - recirculate flue gas from the economiser outlet to the burners or the wind box
The performance of the fans can be impacted by changes in coal quality
A typical arrangement of the major fans at a steam-electric unit is illustrated in Figure 16 The major path flow involves the FD and ID fans It should be noted that the fan arrangement shown in Figure 16 is not fully representative of all coal fired steam-electric units The number and arrangement of the fans and other components can vary substantially Also the pressures and temperatures of the air
42
Pre-combustion performance
air FD forced draft exhaust to FGR flue gas recirculation stack - - - - - - flue gas 10 induced draft
-----_ _-- coalair PA primary air I
1_1I __ Tempertures are approximate and may vary with plant design and operating parameters ambient air I EMISSION I
PA HEATER (air side)
PULVERISERS
-
I PA 1 FAN
-
I CONTROL I I EQUIPMENT
--T-shyt 150degC
AIR HEATER (air side)
( V
I
EMISSION CONTROL
EQUIPMENT
air heater leakage
--------+--------shy
AIR HEATER (gas side)
I
r------ -----jI
I 3700C 1 I
CONVECTIVE COLLECTOR
FGR OUST
_PA__S_ __ 2DC
1 370degC
FGR FAN FUR~ACE
g
__roaka 0I 3700C
- - - - - -+ - - - - ~ - - - -~ - - shy
wind box
burners~bullbullbullbull ------------- bullbullbull ----------- ---- bullbull ------ bullbullbull -------------- bullbull - --- bullbull --shy
Figure 16 Typical utility boiler fan arrangement (Folsom and others 1986c Sligar 1992)
43
Pre-combustion performance
entering the fans depend on the overall plant design Thus to change in flow rate required evaluate the impact of coal quality on fan capacity it is change in system resistance necessary to specify the details of the fan design and change in fan inlet conditions operating characteristics as well as the power station change in rate of fan erosion arrangement To evaluate fan capacity only the characteristics at maximum performance settings need be The flow rate through the fan could be changed in a number considered of ways by changes in coal quality For example an increase
in coal moisture will increase the flue gas volume flow rate Changes in coal characteristics can impact fan performance Changes in heating value of the coal would require a change in four ways to the airfuel ratio and hence the firing rate The excess air
Table 17 Summary of the effects of coal properties on power station component performance - I (after Lowe 1987)
Property Contributing properties Effect
Coal handling and storage Heating value
Coal flow properties
Freezing
Dustiness
Combustibility (spontaneous combustion)
Mills
Drying
Mill throughput
Wear
Fans Flow rate
moisture ash ultimate analysis
moisture coal size distribution mineral matter analysis bulk density
types of moisture
moisture size analysis mineral matter analysis porosity
coal rank moisture size distribution sulphur
moisture
volatile matter
total moisture
Hardgrove grindability index (HGI)
raw coal top size
pulverised fuel size
distribution
mineral matter analysis (quartz amp pyrite) mineral matter size distribution
moisture slagging propensity fixed carbon
A 1 decrease in heating value increases required mass throughput of coal by 1
As flow properties degrade coal throughput remains relatively constant until catastrophic blockages occur at a critical flow property value This value is highly site specific
Surface moisture at low temperatures is the primary cause of freezing
Increased operating and maintenance costs with dusty coals Potential for increased loss of availability
Heating value of stockpiled coal decreases due to spontaneous combustion Plant layout and procedures are dictated by spontaneous combustion
MiD type
Low speed Medium speed Influences primary air requirements and power consumption for both types of mill Mfects the susceptibility of both mill types to mill fires
-3 throughput for 1 moisture -15 throughput for 1 increase moisture increase above
approx 12 moisture -1 throughput for 1 unit -1 throughput for 1 reduction in HGI unit reduction in HGI Caution when using HGI for interpreting coal blend behaviour -3 throughput for 5 mm increase No loss in throughput below in top size 60 mm top size Reduction in fraction passing Reduction in fraction passing
lt75 JlII1 mesh screen by 035 for lt75 Ilm screen by 09 for 1 increase in throughput 1 increase in throughput Influences the component operation and maintenance rate for both types of mill
An increase in moisture increases the flue gas volume flow rate Influences the excess air requirements
44
Pre-combustion performance
required for a specific coal depends on the slagging propensity of the coal carbon burnout and boiler steam temperature considerations These effects are difficult to predict and the actual value of excess air used is determined by the operators to achieve the best balance
The system resistance can also be affected in a number of ways For example fouling of the convective pass increases ID fan resistance on units with induced or balanced draft (Folsom and others 1986b) Fly ash loading in the flue gas can influence the performance for example increased fan blade erosion can occur with increased quantities of fly ash (Sligar 1992)
34 Comments Table 17 summarises the effects of coal properties on the performance of the power station components discussed in this chapter It has been shown that whilst many empirical
relationships have been developed and used to describe the problems that are encountered in the power station there are some signifIcant uncertainties related to many assumptions made These can include for the components described in Chapter 3 the following
coal handling and storage - oxidation dusting flowability and freezing cannot be predicted from coal composition measurements mills - there is no way to evaluate the fineness requirements accurately Mill capacity for blends of coals and for lower rank coals are difficult to evaluate using existing HGI correlations fans - air and gas flow rates depend on excess air Excess air depends on flame stability carbon burnout and slaggingfouling considerations There is no satisfactory method of predicting the effect of these relationships for specific coals Twenty per cent excess is often assumed
45
4 Combustion performance
41 Burners For ignition to take place four elements must be present
fuel air sufficiently high temperature ignition energy availability
A pulverised fuel burner solves this task by blowing a mixture of pulverised coal and air into a part of the furnace where there is a high temperature When lighting up the burner this high temperature is secured locally with an ignition system The burner itself however must be designed in such a way that a stable flame is achieved after the ignition flame is extinguished and it must be able to keep the flame stable and provide optimum combustion The loss of a flame on tum-down even within normal control ranges constitutes a serious dust explosion hazard (Cortsen 1983) Sustained combustion without support fuel also requires consistent coal quality Pockets of high ash can cause momentary extinction and subsequent risk of explosion when fuel returns
A number of physical and chemical processes occur extremely rapidly within the flame It is difficult to describe the number of interactions and complexity of the reactions occurring In spite of many years of theoretical flame research burner design is still based on practical experience though in more recent years this has been supplemented with pilot- and full-scale experiments (Knill 1987 Noskievic and others 1987 Harrington and others 1988 Kosvic and others 1988 Repic and others 1988 Penninger 1989)
Ignition stability is strongly influenced by the characteristics of the coal The conventional method of evaluating the impact of coal characteristics has been to consider the volatile content of the coal and the presence of inert material (moisture and ash) However even if two
coals have the same proximate analysis their ignition characteristics may still be very different due to differences in chemical structure
There are three distinct groups of coal with respect to ignition according to Truelove (1985)
lignites and subbituminous coals with high inherent moisture and high volatile matter content greater than 50 bituminous coals with proximate volatile matter content between 20 and 50 anthracite and semi-anthracite with volatile matter content less than 20
Notwithstanding the high volatile matter content low rank coals can still be difficult to ignite because the high moisture lowers the flame temperature and dilutes the volatilesair mixture The energy required to evaporate 15 moisture and superheat it is equal to the energy required to heat the coal material to 500degC When the moisture content exceeds 40 the coal can be dried using hot flue gas with the result that the primary coaVair stream is heavily loaded with inert water vapour and products of combustion In contrast to the difficulties associated with the ignition of low rank coals the char resulting from high-moisture high volatile matter coals is generally highly reactive
Low volatile coals are much more difficult to ignite In these cases the heat released during the combustion of volatiles is usually insufficient to raise the temperature of the char to ignition and hence sustain combustion It may be necessary to provide continuous support fuel to maintain combustion Ignition stability with low volatile coals can be enhanced by grinding the coal finer and using high preheat for the combustion air Table 16 shows recommendations for pulverised coal fineness based on the volatile matter content (Cortsen 1983) Bituminous coals with volatile contents above 25 should present few problems with ignition
46
Combustion performance
Modem independent burners all use strongly swirling air flows to achieve flame stability and control flame length and width and combustion intensity The application of swirl produces short and intense flames Although excess swirl especially in the primary stream may delay ignition due to rapid mixing of the primary coaVair stream with the relatively cool combustion secondary air
The effect of ash on flame stability has been studied at the International Flame Research Foundation (IFRF) in the Netherlands No significant differences in ignition and flame stability were found when firing 6 ash and 30 ash high volatile coals provided that the fuel was well mixed and delivered to the burner at consistent quality
In the efforts to cut NOx emissions virtually all the combustion-equipment manufacturers are involved in the development of low NOx coal burners Many utilities already utilise the technology Intensive research has focused on the formation of NOx which is influenced greatly by combustion conditions This is discussed further in Section 523
42 Steam generator The ability of the steam turbine to generate power at full capacity depends on an adequate supply of steam at the correct temperature and pressure The steam supply and quality is dependent on the heat release occurring in the furnace and the heat transfer from the resulting gases to the various boiler surfaces located in radiant and convective banks
The effects of coal characteristics on boiler heat transfer and ultimately steam conditions are complex and closely related to the arrangement of large steam generators Factors such as the layout of radiative and convective heat transfer surfaces in the gas side and location of boiling and non-boiling regions on the steam side are critical This section considers how coal characteristics can affect both heat release and heat transfer processes via the mechanisms of fuel combustion and ash deposition
421 Combustion characteristics
Insight into the influence of coal properties on pulverised coal combustion can be gained by examining the factors affecting combustion There is an extensive amount of literature which reviews the work carried out in the field of pulverised coal combustion An lEA Coal Research report Understanding pulverised coal combustion by Morrison (1986) reviews the literature mainly post 1980 on the fundamental processes and mechanisms of pulverised coal combustion Others include reviews by Laurendeau (1978) Essenhigh (1981) Smoot (1984) Smoot and Smith (1985) Heap and others (1986) and Singer (1991) Only a brief description will be given here
The combustion of individual coal particles comprises the following sequence of processes which are partly overlapping and are all dependent on both physical conditions and coal properties
heating of the particle
release of volatile matter combustion of volatile matter combustion of the char
Heating of the particles occurs very quickly The temperature gradient is 105_106degCs depending on the size of the particle Thus a 60 lm particle may achieve furnace temperature within 005-01 s
Release of volatiles occurs within the similar time span but varies with coal quality and particle size The initial gases released ignite and bum momentarily consuming the oxygen present in the air surrounding the particle At this stage the volatiles bum independently of the char particle The devolatilisation of coal at high heating rates is an important stage because it may control
the rate at which combustion proceeds the rate at which oxygen is consumed the rate and form of evolution of nitrogen sulphur and other species together with the mechanisms governing the fate of these species
Depending on temperature and coal quality char combustion may be initiated before combustion of all volatile constituents is completed For successful combustion the heat release associated with the gas-phase reaction must raise the bulk gas temperature sufficiently to ignite the char The rate of char combustion is dependent upon several factors
initial coal structure variations diffusion of reactants reaction by various species (02 H20 C02 H2) particle size effects developed pore diffusion char mineral content (catalysis) changes in surface area as the reaction proceeds char fracturing variations with temperature and pressure
The time required for consumption of a char particle represent a significant portion of the overall time required in the coal reaction process and can range from 03 s to over 1 s (Smoot 1984)
The watersteam temperature balance in a boiler is influenced greatly by the burning profile of the coal that is the rate at which coal passes through the different stages of combustion the heat release associated with them and take-up by watersteam (Singer 1991) During combustion gas temperatures are near 1800degC but the gases must cool to the design point temperatures (usually around 1200degC) of the convective sections of the boiler so that they may be maintained in a satisfactory condition of cleanliness (see Section 422) If the coal bums too quickly
too much heat may be absorbed in the radiant section of the boiler When the gases subsequently reach the superheater tubes they may be too cool to raise steam temperature to the levels necessary for efficient turbine operation and full capacity utilisation temperatures at the radiant section can rise too high and
47
Combustion performance
cause circulation problems or increased boiler slagging (see Section 422) thus raising the incidence of forced outages
If the coal bums too slowly temperatures in the radiant section do not reach design levels and gases reaching the superheater tubes may be hotter than l200dege Thus there can be a decrease in boiler efficiency through
decreased steam production fouling of superheater tubes (see Section 422) increased carbon loss loss of superheater temperature control increased risk of fires in the economiser hopper air heater and particulate control system higher than desired exit temperature of exhaust gases
Many attempts have been made to establish empirical correlations between combustion behaviour and coal properties The volatile matter content is most commonly used as an indicator for ignition behaviour of a particular fuel Similarly heating value and ash content provide a guide to flame stability
The heating value of the coal is important as it constitutes the amount of energy that can be imparted to the system Moisture and total ash content act as negative influences to the energy supply by affecting the adiabatic flame temperature and firing density
The combustibility or reactivity of a coal can be characterised by two factors (Wall 1985a)
volatile matter yield and composition (Jiintgen 1987a Morrison 1986 Saxena 1990) reactivity of char - char reactivity generally increases with decreasing rank in PF combustion (Smith 1982 Morgan and others 1987) so that the rate of combustion is similarly dependent on rank (Shibaoka and others 1987 Jiintgen 1987b Oka and others 1987) However Cumming and others (1987) and Bend (1989) found that rank was not an accurate guide for high volatile bituminous coals from different origins The amount of char produced has been shown to be related to the proximate analysis fixed carbon content petrographic composition and initial coal particle size
An index that relates both of the parameters above is the fuel ratio that is fixed carbon divided by volatile matter as determined by proximate analysis can be used as a measure of coal reactivity The fuel ratio provides an indication of the relative proportion of char to volatiles Although correlations between the fuel ratio and carbon burnout have been found (for example Baker and others 1987) there are exceptions (Oka and others 1987) A higher fuel ratio does not necessarily indicate a coal of lower reactivity and high carbon burnout (Figure 17) This is not surprising since both volatile matter and fixed carbon determinations relate to laboratory test conditions which do not represent the conditions encountered in PF boiler As was discussed in Section 21 proximate volatile yield is generally lower than the true volatile yield as it is sensitive to test conditions
20
C----------) indicates trend reversal
These comparisons 10 contradict the rule that a higher fuel ratio necessarily means higher unburnt carbon and lower reactivity
Coal sized to +125-150 Ilm 5
Peak temperature 1300degC
2
10
c o 0 CB U
c 05s
0 c J
02
01 -t----------+-------------
05
Fuel ratio fixed carbonvolatile matter
Figure 17 Fuel ratio as an indicator of coal reactivity (Smith 1985)
(Morgan 1987) Similarly proximate fixed carbon makes no allowance for the differing reactivity of chars formed from different coals (Oka and others 1987 Smith 1982) Fuel ratio has also been found to be unsuitable for assessing low rank coals
Many utilities have found that volatile matter content information alone is a poor indicator of coal furnace performance they are tuming to the use of advanced test methods Further test procedures have been developed by boiler manufacturers and utilities which give a better insight into the influence of coal properties on combustion characteristics For example thermal gravimetric analysis (TGA) may be used to evaluate the characteristics of coal with respect to particle coal heating and volatiles ignition It should be noted however that TGA test conditions can also differ largely from the conditions present in a PF boiler An example of a TGA test requires a coal sample to be heated at
10 20 40
48
Combustion performance
a controlled rate in a controlled environment The weight loss of the sample is recorded continuously as a function of time (or temperature) The burning profiles determined in TGA are often used as a characteristic fingerprint for a coal These will be compared to a standard coal with an established boiler performance (Cumming and others 1987 Morgan and others 1987) The TGA can also be used to determine the reactivity of coal chars prepared in situ or in other test apparatus such as drop tube furnaces (DTF) or entrained flow reactors (EFR) (Jones and others 1985 Morgan and others 1987 Crelling and others 1988 Hampartsoumian and others 1991)
The DTF or EFR apparatus can also be used to determine the reactivity of coalschars under a range of conditions The apparatus can be utilised under conditions similar to those experienced in a boiler In these tests a consistently higher extent of volatile release is measured than in the volatile matter test of the proximate analysis (Morrison 1986 Knill 1987 Gibbs and others 1989) Carbon burnout can be determined along with the reaction rates for the different stages of combustion (Wall 1985b Skorupska and others 1987 Tsai and Scaroni 1987 Diessel and Bailey 1989 Smith and others 1991a Chen and others 1991) This topic has also been reviewed by Unsworth and others (1991)
Other apparatus used for volatile matter release rates and coalchar reactivity determinations include the heated wire grid apparatus flat flame burners pyroprobe and pilot scale furnaces
All these tests provide data on the devolatilisation and combustion characteristics of coal in considerably more detail than the data provided by standard proximate analysis The boiler manufacturers have developed methods of utilising the test data to predict boiler performance However it should be recognised that these tests are used subject to individual choice and interpretation They are not widely accepted in the utility industry as standards Currently the tests results are meaningful only in the context of a background database for a particular installation which includes accumulated measurements on fuels in the specific test facilities as well as field operating systems The most direct method of utilising the tests would be to compare the performance of specific coals to a base coal whose performance in the subject boiler is well documented In cases where such an approach is not practical it is necessary to rely on laboratory data and modelling to extrapolate the results to full scale However the test procedures particularly in the case of DTF apparatus are complex and since the test facilities have been used primarily as research tools there are no accepted standards
422 Ash deposition
Ash deposition is one of the most important operational problems associated with the efficient utilisation of coal (lEA Coal Industry Advisory Board 1985 Jones and Benson 1988) Since deep cleaning of coal is expensive (Couch 1991) ash is present in all coal-fired furnaces and must be carefully controlled
Equipment manufacturers have used several approaches for
108wx 106d 126 w x 124 d
D D D L wxd 116wx108d
r130 h
U Eastern Western Lignite
bituminous subbituminous coal coal
Siagging propensity low-medium high severe high Fouling propensity low-medium high high high
Midwest (Illinois)
bituminous coal
Furnace size is also affected by coal heating value - moisture - volatile matter
Figure 18 Influence of ash characteristics of US coals on furnace size of 600 MW pulverised coal fired boilers (Babcock amp Wilcox 1978)
ash management to accommodate effective collection and disposal of the deposit Dry and wet bottom furnaces utilise very different operational conditions to achieve this goal (Hatt 1990) Most pulverised coal units that are offered today are of the dry bottom type although wet bottom or slagging bottom furnaces may still be offered for special applications
Since the presence of ash is unavoidable coal-fired power stations are designed to tolerate some deposit on tube surfaces without undue interference of unit operation Knowledge of ash deposition tendencies of coals is important for boiler manufacturers as boiler design features can be varied to accommodate difficult coals Figure 18 describes how one manufacturer accommodates various ash characteristics by adjustment of furnace dimensions and the number of deposition removal systems such as wall blowers The criteria of several utility boiler manufacturers for designing boilers to avoid deposition have been reported by Barrett and Tuckfield (1988) It was observed that each manufacturer applied a different set of criteria and placed different emphasis on the coal analyses details used for prediction of ash depositional behaviour
The occurrence of extensive ash deposits can create the following problems in a boiler
reduced heat transfer - due to a reduction in boiler surface absorptivity and thermal resistance of the deposit impedance ofgas flow - due to partial blockage of the gas path in the convective section of the boiler
49
Combustion performance
physical damage to pressure parts - due to excessive loading of the structures andor impact damage when pieces of the deposit break off and fall down through the furnace corrosion ofpressure parts - due to chemical attack of metal surfaces by constituents of ash erosion ofpressure parts - resulting from abrasive components of fly ash
If the deposits cannot be removed by wall blower or soot blower operation the load on the boiler may have to be reduced to lower furnace temperatures to the point where ash softening is controlled and wall andor soot blowers become effective It is not unusual to observe power stations that must drop loads to about one-third of capacity at night to shed slag accumulated during high-load day time operation (Barrett and Tuckfield 1988) In extreme cases the boiler
Extraneous minerals
must be shutdown and the deposit removed by hand Frequent maintenance and unscheduled shutdowns for removing these deposits and the repair of the effects of corrosion and erosion add substantially to the cost of power generation These problems can result in reduced generating capacities and in some cases costly modifications (Bull 1992)
Deposit problems within a boiler are classified as either slagging or fouling Different definitions of slagging or fouling are used by different people Some people refer to the nature of the deposit - defining molten deposits as slagging and dry deposits as fouling Others define slagging and fouling by the section of the boiler on which the deposit occurs (Borio and Levasseur 1986) For the purposes of this report slagging refers to deposits within the furnace and on widely spaced pendant superheaters in those areas of the unit
bull pyrite 1100degC --------- fusion clays 1300degC
quartz 1550degC
~ expansion
~
Inherent minerals
bull M cenospheres
Y
Na K Heterogeneous 8 ~ condensation Mg ~
80 Homogeneous I __ nucleation
MgO coalescence
surface enrichment
coalesce~--------------I~~ euroY-----~ bull 30~m
p~QD~--- quench ---1~~ ~Qi) 10-90 ~m
disintegration
~
Figure 19 Mechanisms for fly ash formation (Wibberley 1985b Jones and Benson 1988)
50
Combustion performance
which are directly exposed to flame radiation Fouling refers to deposits on the more closely spaced convection tubes in those areas of the unit not directly exposed to flame radiation
Ash slagging and fouling give rise to the first four problems listed above The fifth problem erosion is the result of the impingement of abrasive ash on pressure parts Often coal ash deposit effects are inter-related For example the build up of ash deposit layers on tube walls and superheaters does not only reduce furnace and overall boiler efficiency but can also increase the temperature level in furnace and convective passages and aggravate existing deposit problems The characteristics of the deposit layer change so as to reduce the heat transfer to the surface locally the gas temperature in the furnace will rise partially ameliorating the impact However the net effect is that furnace deposits (slagging) decrease the heat transfer in the radiant furnace and increase the furnace exit gas temperature This can lead to enhanced fouling problems in the convective pass if the ash particles enter the convective tube bundles in a sticky state Ash deposits accumulated on convection tubes can reduce the cross-sectional flow area increasing fan requirements and also creating higher local gas velocities which accelerate fly ash erosion In situ deposit reactions can produce liquid phase components which are instrumental in tube corrosion
The coal ash deposition process involves numerous aspects of coal combustion and mineral matter transformations reactions The importance of the furnace operating conditions on the combined results of the above areas must also be stressed For a given coal composition furnace temperatures combustion kinetics heat transfer to and from the deposit and residence times generally dictate the physical and chemical transformations which occur (Barrett 1990) The ash formation process is therefore dependent on the timetemperature history of the coal particle and the heterogeneous nature of the mineral matter in coal Each pulverised fuel particle may behave uniquely as a result of its composition Figure 19 summarises the mechanisms for fly ash formation
The ash transported through the combustion system only becomes a problem if it is first transported to the heat transfer surface and subsequently sticks to that surface Particle size particle density and shape affect transport behaviour (Borio and Levasseur 1986)
In addition to transport phenomena the three requirements for the formation of deposits from a gas stream containing inorganic vapour and fly ash are (Wibberley 1985b)
the vapours and fly ash penetrate the boundary layer of the tube and contact the metal surface the material adheres to the tube surface sufficient cohesion occurs in the deposit to allow continued growth without periodic shedding under the influence of its own weight vibration soot blowing temperature cycling in the furnace etc
The initial deposit layer is significant as it represents the boundary between the tube metal or rather oxide and the remainder of the deposit Adhesion between the tube and the
first deposit forming material from the fumace gases may involve several factors
surface attraction between the fine ashcharged ash and the tube inherent roughness of the tube which is increased by oxide whisker growth or growths of desublimed alkalis liquid phases on the tube surface formed by supercooling of condensing alkalis reactions involving desublimed alkalis or alkalis pyrrhotite fly ash sulphur compounds and the tube metal to form low melting point complex salts such as Na3Fe(S04)3 Tm = 627degC sticky fly ash particles with either supercooled sodium silicates or condensed alkalis on the surface of the ash and species migration through the deposit
As the deposit thickens the temperature at its outer surface increases at the rate of 30-100degCmm depending on the thermal conductivity of the deposit and the local heat flux to the deposit (Wibberley 1985a) The increasing temperature decreases the viscosity of any liquid phases present which in tum increases the retention of larger fly ash particles impinging on the tube and also the rate of deposit consolidation by sintering and sUlphation
As the size of the fly ash retained at the deposit surface increases its surface becomes increasingly irregular (secondary deposit layer) The rate of deposition is highest where the deposit extends furthest into the oncoming gas stream This causes projections to form Continued growth of the deposit depends on simultaneous growth and consolidation Consolidation involves sintering and sulphation which are enhanced by the increasing temperature in the outer regions of the growing deposit
Siagging Slagging deposits typically form on the water wall section of boilers near the burner region In this region the water wall tubes surfaces are typically in the region of 200degC to 425degC (400degF to 800degF) a temperature too low for mineral matter to form molten deposits The fireside layer of a slagging deposit may consist of a running fluid in which all the fly ash has dissolved or it may consist of a glassy phase impregnated with particles of fly ash (Bryers 1992) Formation of slagging deposits is a time dependent phenomenon Situations are commonly encountered within a boiler where initiation of slag deposits in one region of the boiler will propagate to other regions of the boiler as the heat transfer through the water wall tubes is continually reduced and the temperature of the flame and the deposit increases This influence on heat absorption has been demonstrated using pilot combustor facilities to monitor the effect and rate of deposit build up on heat flux on panels designed to simulate boiler water wall surfaces (Abbott and Bilonick 1992) Figure 20 shows the average per cent heat flux recovery for soot blowing cycles at two different coal firing rates for a range of US coals The work demonstrated that the ash deposits from different coals prove to have a range of tenacities as demonstrated by the different values of heat flux recovery
Determination of the elemental composition of slagging deposits in comparison with equivalent compositions of fly ash have
51
Combustion performance
1 washed Pittsburgh seam - medium sulphur 2 run-at-mine Pittsburgh seam - medium sulphur 3 Pittsburgh seam - low sulphur 4 Pittsburgh seam - high sulphur 5 Illinois No 6 seam - low sulphur 6 Roland seam 7 60 Roland40 Illinois No 6 - low sulphur blend
Figure 20 Heat flux recovery for different coals and soot blowing cycles (Abbott and Bilonick 1992)
shown that there is enrichment of some elements in the deposit (Borio and Levasseur 1986) The results of such an analysis are shown in Table 18 This analysis shows some depletion of silica (Si02) alumina (Ah03) and lime (CaO) in the deposit and an increase in hematite (Fe203) In some cases direct impaction of unspent pyrite on hanger tubes and the leading edge of the first row of convection bank tubes can cause an iron-rich deposit to form that is 75-90 Fe203 in the deposited ash The deposit is semi-fused as pyrrhotite and is further oxidised to hematite or magnetite While bulk analysis of deposits on water wall tubes can give an insight into the formation of the deposits still more information can be gained from chemical analysis of different layers within the deposits which are seldom homogeneous and vary with time
Wain and others (1992) have also illustrated that slag
deposits from different UK coals can exhibit a range of chemical and physical properties At one extreme the slag may be highly porous and friable having little mechanical strength while at the other extreme the slag deposit may be dense and fused with great strength Susceptibility to removal processes was shown to be related to the porosity of the slag formed which in tum is dependent upon ash composition and operating conditions Earlier work indicated that the physical state of the deposit can have a significant effect on the radiative properties In particular molten deposits show higher emissivitiesabsorptivities than sintered or powdery deposits (Goetz and others 1978) Thin molten deposits are less troublesome from a heat transfer aspect than thick sintered deposits However molten deposits are usually more difficult to remove and cause frozen deposits to collect in the lower reaches of the furnace where physical removal can no longer be carried out with wall blowers
Fouling In all coal-fired units ash deposits build up on the convective pass tube bundles due to the flow of the particulate laden flue gas over the tubes The boiler manufacturers attempt to design their units to avoid the uncontrollable build up of deposits in this region Fouling problems occur when the strength of the deposits is high and the action of soot blowers is unable to remove the deposits It should be noted that with fouling there is no analogue to the wet bottom approach to slagging that is units cannot be designed to accommodate fouling problems by ensuring that the ash deposits are removed from the convective pass tubes as liquids
As with slagging the bonding of ash particles to the tube surface depends on the physical state of the particles approaching the tubes and wetting action of the ash on the tube surface However in the convective pass the temperature difference between the particles (and gas) and the tube surface is much less than in the radiant furnace so that the quenching action of the particles impacting the tube surface is greatly reduced
Organically-bound sodium and sodium chloride are most frequently the cause of convective bank fouling in low rank coals and bituminous coals respectively (Osborn 1992) As discussed earlier many of the alkali metal compounds in coal
Table 18 Enrichment of iron in boiler wall deposits - comparison of composition of ash deposits and as-fired coal ashes (Borio and Levasseur 1986)
Unit sample Power station 1 Power station 2 Power station 3
As-fired Waterwal1 As-fued Waterwal1 As-fired Waterwal1 coal ash deposit coal ash deposit coal ash deposit
Ash composition Si02 470 333 502 551 497 418 Ah03 267 180 169 146 165 158 Fe203 146 435 59 183 120 285 CaO 22 12 128 72 65 90 MgO 07 05 35 20 09 09 Na20 04 02 06 05 11 06 K20 23 16 08 06 15 09 Ti02 13 08 09 08 11 07 S03 11 05 120 01 20 02
52
Combustion performance
vaporise readily at typical furnace temperatures They form hydroxides or oxides that react with S03 in the gas phase at the tube surface to form sodium sulphate They can react with ash particles to form low melting point eutectics or can nucleate on the surface of ash particles or tubes Thus alkali metal compounds can lead to sticky deposits on the tube surfaces Generally sodium and calcium sulphate dominate the initial layer of deposits As the deposits build up in thickness they can sinter into a strong fused mass They may include other ash particles completely encapsulated with calcium and sodium sulphate crystals The sintering process may be related to diffusion of materials through the deposits and solid phase reactions
As in the case of slagging fouling deposits also are not uniform but are built in layers of material which can differ in particle size and chemical composition
Corrosion Corrosion of the furnace wall tubes has resulted in metal depletion rates of 600 nmh or more compared to normal oxidation rates of about 8 nmh (Brooks and others 1983) Such severe corrosion drastically reduces the lifetime of the tubes and may lead to unexpected failure Fumace wall corrosion of steel tubes has been observed in virtually all types of pulverised coal boilers In extreme cases the result is tube failure and large scale requirements for replacement (Clarke and Morris 1983 Blough and others 1988) Currently corrosion is no longer the primary cause of forced boiler shutdowns owing to control strategies and regular maintenance However remedial measures are quite costly and current efforts seek to reduce this cost by substantially extending maintenance intervals (Flatley and others 1981)
The mechanisms which govern the corrosion of the furnace wall tubes are not well understood (Harb and Smith 1990) Corrosion behaviour is closely linked to conditions in the furnace Fireside corrosion can occur on both water walls and superheater tube surfaces Water wall corrosion results essentially from regions of persistent local substoichiometric combustion near the walls which may be due to coal devolatilisation andor inadequate coalair mixing The resulting low partial pressure of oxygen and a high partial pressure of sulphur (as H2S and S02) cause the formation of scales containing iron sulphides Sulphide scales grow more rapidly than the corresponding oxides They are less protective and can lead to increased stress when formed in an existing oxide scale This promotes rapid spalling of the tube surface (Wright and others 1988) Other species believed to participate in corrosion reactions include HCI This is formed on volatilisation in the flame Flatley and others (1981) postulated that HCl reacts with the outer scales of the previously formed protective oxide to create gaseous microchannels through which HCl gains access to the metal surface Once at the surface the HCI reacts with the iron to form a volatile iron chloride which is then transported back toward the bulk furnace gases The reducing environment is also known to lower ash fusion temperatures and increase mineral deposition which in turn can affect corrosion behaviour
Corrosion often occurs in definite patterns associated with the direction of the flame and has been linked to flame impingement (Borio and others 1978) Flame impingement
again creates severely reducing conditions high heat fluxes and leads to the generation of corrosive species Evidence exists that severe furnace wall corrosion of carbon steel is a consequence of poor local combustion associated with flame impingement and the delivery of unburnt coal particles to the tube surface (Flatley and others 1981) Strategies to limit NOx formation in some boilers can increase the likelihood of corrosion owing to the presence of reducing environments and enlargement of the flame zone (Chou and others 1986)
On higher temperature metal surfaces such as superheaters and reheaters two main causes of corrosion are
overheating which leads to accelerated oxidation of both fireside and steam side deposit related molten-salt attack
The latter form of corrosion can be related directly to the chemistry of the coal being burned and the steam (wall) temperature Molten salt attack concerns the development of conditions beneath a surface deposit which are conducive to the formation of a low melting salt ofthe type (NaK)3Fe(S04)3 These alkali-iron trisulphates form by reaction of alkali sulphates deposited from the flue gas with iron oxide on the tubes or from the fly ash in the presence of S03 (Shigeta and others 1987) The minimum melting point for these salts occurs at 552degC (1026degF) This type of corrosion has been associated with the presence of alkali metals sulphur and iron in coal
Chlorine can also be a contributing factor towards superheater metal corrosion if sulphate content is low While exact mechanisms can be argued there have been both liquid phase and gas phase corrosion when chlorides have been present (Latham and others 1991b Daniel 1991)
Calcium and magnesium which may also be found in coal mineral matter are known to be anticorrosive elements which inhibit the formation of alkali-iron trisulphates This is particularly true for acid-soluble calcium and magnesium contents which have an inhibiting ability for liquid-phase corrosion by forming a solid sulphate in the deposit for example calcium sulphate (Blough and others 1988) Work by Shigeta and others (1987) showed from corrosion tests that the corrosion rates were influenced by anti-corrosive elements (see Figure 21)
c 4 co E 0
-0 3E ( ()
Q 2 1 OJ
Qj
5
o 4 8 12 16
Contents of CaO and MgO
Figure 21 Effect of CaO and MgO on corrosivity deposit (Shigeta and others 1987)
20
53
Combustion performance
Erosion Erosion due to fly ash is recognised as the second most important cause of boiler tube failure (Dooley 1992) Considerable effort is being spent to understand the mechanism of fly ash erosion and to acquire the capability to predict erosion rates due to fly ash in boilers Fly ash is more erosive compared to the coal from which it originates one reason being the absence of the soft organic fraction
Table 19 Hardness of fly ash constituents (Nayak and others 1987)
Constituent Mohs Vickers Hardness kgmrnz
Mullite Vitreous material Free silica (quartz) Hematite Magnetite Coke particles with inherent and surface ash
Fume sulphate particles Anhydrite (CaS04)
5 550-600 7 1200-1500 5-6 500-1100 5-6 500-1100
3-5 100-500 (non-abrasive)
Erosion occurs at the outlet of the furnace section where the flue gas is made to tum over the top of the boiler while traversing pendant tube banks and in the rear pass especially on the sections of horizontal tube banks adjacent to the back wall of the rear pass (Wright and others 1988) Fly ash size and shape ash particle composition hardness and concentration and local gas velocities play important roles concerning the erosion phenomenon Table 19 lists the available data on hardness values of fly ash particles (Nayak and others 1987) The hardness characteristics of the major mineral contents in fly ash have not been studied extensively Work by Raask (1985) and Bauver and others (1984) has shown that quartz particles above a certain particle size are very influential in the erosion process and that furnace temperature history plays an important role in determining erosive characteristics of the particles
Many of the above phenomena discussed under the headings of Slagging Fouling Corrosion and Erosion have standard tests such as ash fusibility (see Section 25) as the basis for predicting their occurrence These bench-scale tests provide relative information on a coal which is used in a comparative
fashion with similar data on fuels of known behaviour Unfortunately although commonly used they do not always provide sufficient information to permit accurate comparison
The fusibility temperature measurement technique attempts to recognise the fact that mineral matter is made up of a mixture of compounds each having their own melting point (see Table 20) As a cone of ash is heated some of the compounds melt before the others and a mixture of melted and unmelted material results The structural integrity or deformation of the traditional ash cone changes with increasing temperature as more of the minerals melt However use of ash fusion data can be misleading Ash fusion tests typically are run in both a reducing and oxidising environment This means there is either sufficient oxygen in the atmosphere surrounding the ash particles to oxidise various minerals or there is not Generally an oxidising environment pertains throughout the combustion chamber of the boiler For a number of reasons there may be moments when as the coal and mineral particles pass through the combustion chamber there is not enough oxygen for oxidation to occur This is known as a reducing environment It is important to be aware of these conditions since if a reducing environment develops the ash fusion temperatures are lower than those occurring in oxidising conditions and can become low enough to cause slagging and fouling
The problems with ash fusion measurement is that recent results indicate that significant meltingsintering can occur before initial deformation is observed The fact that the timetemperature history of the laboratory ash is quite different from the conditions experienced in the boiler can result in differences in melting behaviour In addition the ash used in this technique may not represent the composition of the ash deposits that actually stick to the tube surfaces Often there is a major discrepancy between the composition of as-fired ash and that which is found in the deposits The discrepancies between fusion temperature results and actual slagging performance are usually greater on ashes that may look reasonably good in the laboratory One can usually assume with reasonable confidence that the melting temperature of the water wall deposits will be no higher than measured fusion temperatures although they can be and often are lower This is because deposition of lower melting constituents can and does occur with a resulting enrichment of lower melting material in the deposit Bearing all of these points in mind it is difficult to show confidence in this test as a predictor of performance
Table 20 Properties of some coal ash components (Singer 1991)
Element Oxide Melting temperature degC
Si SiOz 1716 Al Ah0 3 2043 Ti TiOz 1838 Fe Fez03 1566 Ca CaO 2521 Mg MgO 2799 Na NazO sublimes at 1276 K KzO decomposes at 348
54
Chemical Compound Melting property temperature degC
acidic NazSi03 877 acidic KzSi03 977 acidic Ah03NazO6SiOz 1099 basic Alz03KzO6SiOz 1149 basic FeSi03 1143 basic CaOFez03 1249 basic CaOMgO2SiOz 1391 basic CaSi03 1540
Other tests such as ash viscosity measurements suffer from shortcomings These tests are conducted on laboratory ash and on a composite ash sample Viscosity measurements are less subjective and more definitive than fluid temperature determination for the assessment of ash flow characteristics The usual procedure for assessing slag viscosity for wet bottom furnaces is to correlate the temperature at which the viscosity of coal ash slag is 250 poise This is defined as T250 Viscosities for dry bottom furnaces are usually conducted at higher temperatures These values can also be calculated from ash analysis Thompson and Gibb (1988) reported that in a study of nine UK coal ashes with a high iron content the slagging propensities as determined by ash viscosity tests was broadly in keeping with expectations though four of the samples showed contradictory behaviour During pulverised coal firing a severe problem may already exist before slag deposits reach the fluidrunning state Generally only a small quantity of liquid phase material exists in deposits and it is the particle-to-particle surface bonding which is most important
Tests utilising the electrical resistance properties of ash have also been developed and these are perceived as being superior to the standard ash fusibility test for providing an indicator of the onset of ash sintering (Cumming 1980 Lee and others 1991)
Much use is also made of the ash composition which is normally a compilation of the major elements in coal ash expressed as the oxide form Coal ash can be classified as one oftwo types viz
bituminous-type Fe203 in ash is greater than the sum of CaO + MgO in ash lignitic-type Fe203 in ash is less than the sum of CaO + MgO in ash
From the compilation of elements expressed as oxides from the ash analyses judgements are often made based on the quantity of key constituents like iron silicon aluminium and sodium
Using the results obtained from a standard ash analysis the measured oxides can be separated into basic and acidic components (see Table 8 and Table 20) The acidic components are those materials which will react with basic oxides They include Si02 Ab03 and Ti02 The basic ash constituents are those materials which will react with acidic oxides They include Fe203 CaO MgO Na20 and K20 The base to acid ratio is the ratio of the sum of the basic components to the sum of the acidic components Baseacid ratios are used as indicators of ash behaviour normally lower melting ashes fall in the 04 to 06 range It has been shown that baseacid ratios generally correlate well with ash softening temperatures so although baseacid ratios have helped explain why ash softening temperatures varied it has not improved the predictive capabilities (Borio and Levasseur 1986) Other ratios such as FeCa and SiAI have been used as indicators of ash deposit behaviour Ratios like these have helped to explain deposit characteristics but their
Combustion performance
use as a prime predictive tool is questionable especially since these ratios do not take into account selective deposition nor do they consider the total quantities of the constituents present An FeCa ratio of two could result from weight per cent ratios of 63 or 3015 the latter numbers would generally indicate a far worse situation than the former but the ratio does not show this
Many of the slagging and fouling indices described earlier in Table 8 are based upon certain ash constituent ratios and corrected using such factors as geographical area sulphur content sodium content etc One commonly used slagging index uses both BaseAcid ratio and sulphur content Factoring in sulphur content is likely to improve the sensitivity of this index to the influence of pyrite on slagging (As previously discussed iron-rich minerals often play an important role in slagging) However the use of such correction factors is often a crude substitute for more detailed knowledge of the fundamental ash properties Another example of this is the use of chlorine content in a coal as a fouling index This can be valid as a general rule if the chlorine is present as NaCI (thereby indicating the concentration of sodium which is an active form) and that the sodium will in fact cause the fouling Chlorine present in other forms mayor may not adversely affect fouling
Sintering strength tests have been used as an indication of fouling potential Assuming that correct ash compositions have been represented (which is less of a problem in the convection section than in the radiant section) worthwhile information may be obtained relative to a timetemperature versus bonding strength relationship Again in order for sintering tests to accurately predict actual behaviour it is necessary that tests be conducted with ash produced under representative furnace conditions (timetemperature history) (Kalmanovitch 1991)
The conventional analyses and developed indices may provide indications for limited parts of the coal spectrum but they share a flaw in that they take their point of departure in the end composition of the ash without taking account of the original minerals and intermediate products formed and transformed in the combustion zone (Cortsen 1983)
Information concerning the mineral forms present in the coals and the distribution of inorganic species within the coal matrix can be extremely important in extrapolating previous experience since the nature of the inorganic constituents contained in the coal can be the determining factor in their behaviour during the ash deposition process (Borio and Levasseur 1986) Generally speaking newer bench-scale techniques can be more sensitive to the conditions that exist in commercial furnaces than the older predictive methods Selective deposition for example has been recognised as a phenomenon which cannot be ignored More attention is being paid to fundamentals of the ash formation and deposition processes The use of new analytical techniques could give results that allow mineral matter to be identified according to composition mineral form distribution within the coal matrix and grain size Techniques such as computer-controlled scanning electron microscopy (CCSEM) scanning transmission electron microscopy
55
Combustion performance
Table 21 Summary of the effects of coal properties on power station component performance - II (after Lowe 1987)
Property Contributing properties Effect
Burners and steam generator Volatile matter
Ultimate analysis
Fuel ratio
Moisture
Slagging propensity
Furnace wall emissivity
Fouling propensity
carbon hydrogen nitrogen
fixed carbon volatile matter
ash elemental analysis ash fusion temperatures coal particle mineral analysis
ash elemental analysis wall deposit physical state
ash elemental analysis active alkalis (sodium amp potassium) ash fusion temperatures
Special burner design for flame stabilisation required below a dry ash-free volatile content of 25
Air requirements are affected by ultimate analysis unit increase of CIH ratio increases air requirements per unit heat release by 08
A 006 increase in efficiency loss due to unburnt carbon for 10 increase in fuel ratio at ratio of 16
A 1 increase in moisture decreases boiler efficiency by 025 requiring a proportional increase in firing rate
Slagging propensity generally ranked as low intermediate high or severe Response to slagging propensity is a function of unit thermal rating
Furnace wall emissivity is typically 08 a decrease of 1 will increase furnace outlet gas temperature by 16degC
Fouling propensity ranked low to severe Response to slagging propensity and is highly unit specific
(STEM) and X-ray diffraction can be used to characterise these properties on an individual particle basis New spectroscopies such as extended X-ray absorption fine structure spectroscopy (EXAFS) and electron energy loss spectroscopy (EELS) are capable of determining the electronic bonding structure and local atomic environment for organically associated forms of calcium sodium and sulphur Other new techniques such as Fourier transform infrared spectroscopy (FTIR) electron microprobe electron spectroscopy for chemical analysis (ESCA) all provide methods of improving present capabilities Thermal gravimetric analyses (TGA) and drop tube furnaces (DTF) have been used to characterise mineral matter decomposition and prepare ash samplesdeposits under near-boiler conditions respectively For example Benson and others (1988) have used a laminar flow DTF to study the formation of alkali and alkaline earth alumino silicates during coal combustion
A cautionary note though should be added here as many of the new techniques are still primarily focused on small fragments of the overall deposition process in order to permit manageable controlled studies in the laboratory Unfortunately the results are all too often not re-integrated in order to understand the total process But it cannot be doubted that a knowledge of the effects of the
aforementioned coal qualities is essential to avoid expensive delay in any changes to operational conditions in order to rectify deposition problems once they arise Information of performance in test reactors could also help to implement counter strategies to prevent the occurrence of deleterious incidents forewarned is forearmed
43 Comments Table 21 summarises the effects of coal properties on the performance of the power station components discussed in this chapter Whilst many empirical relationships have been developed and used to describe the problems that are encountered in the burner and boiler region of the power station it has been shown that significant uncertainties relate to many of the assumptions involved Flame shape and stability and char burnout cannot be predicted with certainty on the basis of coal composition data Correlations for slagging fouling erosion and corrosion have been shown to be inadequate
Power station operators still consider the problems of slagging fouling corrosion and erosion to be of greatest concern In view of this these subjects are the attention of a number of studies and have been reviewed extensively It is recognised that this topic merits a more extensive review than could be incorporated in this study
56
5 Post-combustion performance
51 Ash transport
The mineral matter entering with the coal exits the power station in the following five streams
mill rejects bottom ash economiser ash particulate collection system flue gas
The distribution between these streams depends on the power station design and operation as well as the coal composition Figure 22 shows a typical distribution However as described below this distribution may vary substantially
Most direct-fired mills have provision to reject pyrite extraneous material and excess coal introduced into the mill Under normal operating conditions the mass of the material rejected is a negligibly small fraction of the total coal flow rate However as the flow rate of coal into the mill is increased toward maximum capacity the amount of rejects increases Thus there is no effective way of estimating the effect of coal composition on mill rejects The mill reject system is typically oversized and would not be expected to limit mill operation except under unusual circumstances or where mill capacity is exceeded
The amount of ash removed at the bottom of the furnace is typically about 20 of the total ash content of the coal However the mass of bottom ash is difficult to measure accurately It may be estimated by measuring the mass of ash exiting with the flue gas and subtracting this from the ash entering the boiler with the coal However the errors of such an analysis procedure are considerable and the calculated mass of bottom ash may even be negative The factors which are probably the most important for determining the fraction of ash in the bottom ash are the design of the firing system the coal fineness bulk
velocities in the furnace and slagging Coal qualities that would directly influence these factors are
ash in the coal grindability of the coal slagging propensity of the fly ash
Due to the uncertainty in the mass of the bottom ash the handling system for the material is typically designed with considerable excess capacity Most systems operate intermittently so that an increase in bottom ash may be accommodated by an increase in duty cycle
The composition of the coal ash has an impact on the characteristics of the material captured as bottom ash Dry bottom furnaces are designed to maintain the ash in the hopper in a powdery non-sticky state The powdery ash slides down the hopper walls into the collection tank at the bottom of the furnace IT the ash has a low fusion temperature it may stick to the hopper or build up to running slag This material can accumulate at the bottom of the hopper and plug the hopper exit Solid slag deposits may fall from water walls higher in the fumace causing similar problems Wet bottom furnaces are designed to operate with running slag The slag must have a viscosity low enough to flow into the collection tank where it is quenched in water and shatters into small particles Typically the slag viscosity should be in the range of 250 poise at 1426degC (2600degF) for adequate fluidity (Babcock amp Wilcox 1978) If the viscosity increases plugging of the hopper bottom can occur similar to dry bottom furnaces
The strength of the ash can affect bottom ash system operation Many bottom ash systems are equipped with clinker grinders to reduce the size of the slag particles IT the slag particles are sufficiently large or strong they can disable the clinker grinder All the problems described above are related to the coal ash chemistry that is whether a fluid slag is formed and operating conditions
57
1-----++---------shy--
Post-combustion performance
Based on coal 10 ash 2791 MJkg
Unit 500 MW 1055 MJkWh
Mass kgkJ
Mass
Flow rate th
Coal ash
Mill rejects
Bottom ash
Economiser ash
Cyclone ESP
baghouse
Stack emissions
358
1000
1905
003
10
019
072
200
381
018
50
095
261
734
1398
002
06
012
Figure 22 Typical ash distribution (Folsom and others 1986c)
Occurrences of ash hopper explosions have been reported (Stanmore 1990) The exact mechanism for the explosions has not been elucidated Hypotheses of the cause include
chemical explosions involving iron-rich ash thermal explosions resulting from rapid quenching of falling hot deposits inducing a pressure wave within the water thermal explosion within the ash hopper causing entrainment of unburnt coal which then ignites to produce a secondary blast
Stanmore (1990) reports that work so far in this field has failed to uncover any boiler feature hopper type or coal composition which was common to all explosions investigated Corner-fired and wall-fired units experience the problem with both bituminous and subbituminous coals Both low and high ash content coals were involved with both high and low ash fusion temperatures
Ash-related explosions involving residual carbon in the ash can result from unfavourable furnace conditions which can occur during a cold start of a boiler Moreover variation in initial coal size can lead to poor grinding efficiencies giving rise to a wide pulverised coal size distribution and hence incomplete coal combustion (Stanmore 1990 Wol1mann 1990)
Most of the ash particles captured in the economiser hopper
are large because they are shed from the convective pass tube bundle deposits by the action of gravity flue gas flow rate or soot blowing The amount of ash varies with the fouling characteristics of the coal and cannot be predicted easily Economiser ash disposal systems are typically designed to handle about five per cent of the coal ash The presence of unburnt carbon in economiser ash can impact the operation of the collection system Poor coal reactivity can lead to high carbon content in the ash The carbon can continue to burn in the hopper and fuse the powdery material into a large mass which cannot flow from the hopper easily
Most of the ash exits the boiler as fly ash and is captured in particulate control equipment which may include cyclones ESPs fabric filters (baghouses) or scrubbers
52 Environmental control Since the early 1970s mandatory control of power station emissions has significantly increased the cost of generating electricity (CoalTrans International 1991) Initial concerns were focused on particulate emissions and have led to the development of efficient particulate removal systems Environmental concern about the use of coal is particularly tuned to the problem of emissions of SOx NOx and C02 to the atmosphere Trace elements are receiving increasing attention from the scientific and electric power communities who are attempting to evaluate the potential impact of trace
58
elements on the environment (Clarke and Sloss 1992) There is also the problem of disposal of the solid residues which are obtained from power stations
The capital and operating costs of emission control hardware can account for up to 40 of a power stations operating expenses (Cichanowicz and Harrison 1989) Increasingly coal-fired utilities are realising that in order to comply with ever tightening emission regulations their environmental control strategies must include adequate control of coal quality Emission control strategies related to coal quality can include
coal switching coal blending coal cleaning control of emissions during combustion post-combustion emission control
The impact of coal quality on emission control hardware has not been studied extensively Additional constraints in some cases are applied to coal quality during coal selection as a result of the implementation of emission controls
The following sections briefly review the emission control technologies available and attempts to highlight the coal characteristics and other considerations that affect the selection or efficient use of emission control systems
521 Coal cleaning
Historically coal has been cleaned to maintain specifications for delivered fuel quality and to reduce transport costs Coal cleaning benefits are usually greatest for coals which have to be transported over long distances to the point of use Conventional coal preparation plant mainly uses methods developed at least forty years ago Nevertheless in recent years there have been major advances in instrumentation and control which have resulted in reduced costs and greater consistency in the cleaned product
Utilities also have the option to incorporate coal cleaning strategies on site High mineral matter high sulphur coals could be purchased at lower prices and cleaned on site to boiler-related specifications The decision to implement this type of strategy is dependent essentially upon three factors
cost savings achieved by coal cleaning feasibility of residue disposal
Coal cleaning costs depend upon the initial cleaning plant capital costs cleaning plant operations and maintenance and the value of lesser-quality coal discarded in the cleaning process In general coal cleaning capital costs average about five per cent of the cost of the power station using the coal Direct operating costs are determined by labour consumables and power Discarded coal can account for as much as 50 of total cleaning costs (Cichanowicz and Harrison 1989)
Savings achieved by coal cleaning depend upon the depth of
Post-combustion performance
cleaning instigated (Elliott 1992) A review by Couch (1991) entitled Advanced coal cleaning technology provides a technical overview of recent developments in coal cleaning methods The fuel characteristics most significantly changed by cleaning are
mineral matter content and distribution sulphur content and form heating value
Reducing the mineral matter impurities and sulphur in the coal can have a signifIcant affect on a coals abrasiveness reduce ash loadings by up to 93 and potential S02 emissions by as much as 70 (Hervol and others 1988) Moreover coal cleaning can reduce environmental control costs by lowering the quantity of fly ash and S02 that must be removed after combustion Coal cleaning permits smaller and therefore less expensive flue gas processing equipment reduces reagent quantity and decreases the amount of solid waste requiring disposal Cleaned coal can improve station heat rate by reducing auxiliary power for flue gas handling systems and allowing lower air heater exit temperature thus increasing boiler efficiency Pilot scale combustion tests conducted by Cichanowicz and Harrison (1989) showed that boiler efficiency was greatly improved by coal cleaning as shown in Table 22
Table 22 Summary of coal cleaning effects on boiler operation (Cichanowicz and Harrison 1989)
Characteristics Run-of-mine Medium Deep coal cleaned cleaned
coal coal
Moisture 17 17 16 Sulphur 38 37 20 Ash 235 71 35 Heating value MJkg 2338 3103 3266 Flue gas S03 7 4 3
concentration ppm Air heater exit 136 120
temperature degC Boiler efficiency 884 901 Flue gas volume 6
reductionsect
dried sect includes flue gas temperature reduction and efficiency
improvement
Although the total ash content is reduced it must be noted that all ash constituents may not be removed equally Unfortunately those constituents which are primarily responsible for slagging and fouling are least affected so that problems in this area can be induced as a result of cleaning
As overall S02 emissions will be lowered by coal cleaning the benefits of this form of pollution reduction must be considered in the light of the ESP problems that might result from the use of low sulphur coal (see Section 522) and with regard to its adverse effects on collection efficiency (Strein
59
Post-combustion performance
1989) Coal cleaning has only peripheral implications for NOx and C02 emissions
An additional benefit of cleaning coals is the substantial removal of many trace elements especially heavy metals with the mineral components (Swaine 1990) Efficiencies for trace element extraction have been reported for various physical cleaning processes including density separation oil agglomeration float-sink separation and combinations of heavy-media cyclones froth flotation and hydraulic classifiers (Gluskoter and others 1981 Couch 1991)
The adoption of coal cleaning strategies on a power station site would require a knowledge of quality characteristics that affect cleaning These include
the amount nature and the size of the mineral matter If they are finely divided and dispersed they are difficult to liberate and to separate the size distribution of the coal affected by inherent friability and by mining and handling procedures All of the properties which affect coal handling have an influence here the relative proportions of pyritic and organic sulphur coal oxidation affecting surface properties the porosity of the particles
A number of tests have been developed specifically to assess the cleanability of a coal These have been reviewed in an lEA Coal Research report by Couch (1991) and will not be discussed here
522 Fly ash collection
Fly ash collection systems are required on virtually all coal-fired power stations to meet particulate emissions or opacity regulations The acceptable dust loading from collection equipment is usually about 01 gm3 A coal containing 20 ash typically provides an uncontrolled dust loading of about 30 gm2 so that a collection efficiency of 997 is required to meet acceptable emission standards For very fine particles such as fly ash such a high collection efficiency can only be achieved using electrostatic precipitators (ESP) or fabric filters
Electrostatic precipitators (ESP) ESPs have been studied extensively and a number of comprehensive texts are available that describe the process (Babcock amp Wilcox 1978 Singer 1991 Klingspor and Vernon 1988) The ESP process involves fly ash particle charging collection and removal
The perfonnance or collection efficiency of an ESP is defined as the mass of particulate matter collected divided by the mass of such material entering the ESP over a period of time One of the earliest and simplest equations for predicting the particulate collection efficiency of an ESP was that proposed by Anderson in 1919 and subsequently developed by Deutsch in 1922 The Deutsch-Anderson equation enables the collection efficiency to be predicted from the gas flow the precipitator size and the precipitation rate (or migration
velocity) ofthe particles It may be presented as follows (Deutsch1922)
where e = fractional precipitator collection efficiency (dimensionless)
a = total collecting electrode surface area (m2) v = gas flow rate (m3s) w = migration velocity of the particles (ms)
The ratio av is often referred to as the specific collecting area (SCA) and has dimensions slm When determined empirically the migration velocity w accounts for ash properties such as ash particle size distributions as well as for rapping losses and gas flow distribution The Deutsch-Anderson equation was recognised as having several limitations and so gives only approximate results for some operating regimes For this reason alternative equations have been developed often as modifications of the original Deutsch-Anderson equation For example Matts and Ohnfeldt (1973) introduced a semi-empirical factor and a constant based on particle size distribution and other ash properties which gives a more realistic approximation of actual precipitator behaviour
The equations discussed above describe how perfonnance is a function of ESP design flue gas flow conditions and the characteristics of the fly ash The impact of coal quality on ESP perfonnance is primarily via the influence of the chemical and physical properties of the fly ash on the migration velocity of the particles These include
ash resistivity ash quantity ash particle size and size distribution
Ash resistivity influences ESP power input Resistivity is critical for fly ash ESPs because it directly influences operational voltages and currents As the ash resistivity increases the flow of corona current decreases Generally speaking as the corona current decreases so does the precipitator efficiency Low resistivity ash (l08 ohm-cm and below) is also a problem because the ash easily loses its charge after being collected on the plates The uncharged particles are recharged and redeposited several times and some are eventually re-entrained into the flue gas and escape from the precipitator A limit on maximum gas velocity and special collector profiles are needed to overcome this problem
High resistivity ash (above 1011 ohm-cm) is considerably more difficult to precipitate with a risk of back corona discharge An explanation for this phenomenon is that the ash particles do not readily lose their charge when they reach the electrodes This results in difficulties when trying to remove the agglomerated ash When a deep enough deposit collects on the plate back corona may develop on the ash surface and the precipitator no longer operates efficiently Back corona is extremely detrimental to precipitator performance and occurs when particles migrate to the collecting surface but fail to dissipate their charge This
60
Post-combustion performance
causes a high potential gradient in the dust layer on the surface of the electrode and results in current conduction of opposed polarity to that of the discharge electrode
The range of dust resistivity is primarily affected by
chemistry of fly ash levels of sulphur trioxide and moisture content of the flue gas flue gas temperature
Key ash constituents which affect resistivity are ferric oxide Fez03 potassium oxide (KzO) and sodium oxide NazOshywhere a substantial reduction in either or both of these will cause an increase in fly ash resistivity Conversely a substantial increase in calcium oxide (CaO) magnesium oxide (MgO) aluminium oxide (Alz03) and silicon dioxide (SiOz) will cause ash resistivity to increase (Singer 1991) Strein (1989) describes the impact of coal cleaning in particular the removal of sulphur from coals and switching to low sulphur coals on ESP performance It was determined that coal cleaning was not always beneficial to good precipitator operation Although precipitators can be designed for low sulphur coals the use of low sulphur coals in other cases can lead to a reduction in precipitator collection efficiency and possible non compliance with stack opacity limits Precipitators constructed many years ago were likely to encounter problems if any change to a lower sulphur coal was encountered It was concluded that before a change in fuel was made a careful review should be made of the precipitator design data predicted precipitator performance and the coal and ash chemistry of the new fuel If the problem of high fly ash resistivity was encountered after a fuel switch of this nature flue gas conditioning must be considered in particular a S03 injection system The purpose of this is to supplement the naturally occurring S03 in the boiler flue gas stream to the extent necessary to reduce fly ash resistivity to an acceptable level
A number of electrostatic precipitator manufacturers have developed regression equations which make first order predictions of fly ash precipitation performance based on the elemental analysis of the ash in coal These equations are generally regarded as proprietary and are not published
CSIRO Australia have published details of correlations of ash chemistry with pilot-scale electrostatic precipitators Whilst many correlations used in the past have proved inadequate for precise prediction the most promising correlation was obtained when consideration was given to the elements that would contribute to the refractoriness of fly ash The best precision was obtained from the sum of the elemental analyses for silicon aluminium and iron calculated assuming (on an ash basis) Si+Al+Fe+Ti+Mn+Ca+Mg+Na+K+P+S = 100
The formula given for a precipitator outlet concentration of 01 gm3 and for coal at 15 ash content is in two parts (Potter 1988)
for Si+Al+Fe = a lt82 am = 1886 + 0565a for 82 lta lt90 am = -2864 + 428a
where am = required specific collecting area in mass units mZ(kgs) This value can also be represented as a percentage of the ash content (A) by multiplying by the factor f given by f = 1364 - 048810glO[(100A)-I]
Cortsen (1983) reports of the use of alkaline sulphate index (ASI) by utility operators to assess the ease of fly ash precipitation The ASI is calculated from a series of equations which relate S03 content of the flue gas and the corresponding chemical equivalent of the oxides of silicon aluminium calcium magnesium phosphorus sodium and potassium Coal ashes with ASI values between two and three are perceived difficult to collect while an ASI of six or above indicates easy precipitation The index was not considered as accurate in ESP evaluation as measurement of ash resistivity nor measurement of actual precipitator efficiency (Cortsen 1983)
Sulphur content of the coal can also influence ash resistivity Sulphur trioxide (S03) formed from the combustion of the sulphur reacts with water vapour to produce sulphuric acid (HZS04) at temperatures of approximately 500degC (950degF) In the cool part of the flue gas system there may be some deposition of HZS04 which depends on flue gas temperature and vapour pressure The HzS04 can be absorbed onto the fly ash particles and reduce their resistivity It has been shown that H2S04 can alter the fly ash resistivity either by completely absorbing on the dust particles or by chemically reacting to form sulphates Others have suggested that the formation of binary acid water aerosol is the primary mechanism by which HzS04 can affect fly ash resistivity Although the mechanism which accounts for the presence of absorbed H2S04 on fly ash particles is not clearly understood the net effect is reduction in fly ash resistivity
Increases in moisture content can adversely affect precipitator performance through impacts upstream of the ESPs The moisture content of the coal in conjunction with coal particle size and volatility can affect flame stability and combustion within the boiler furnace area If this causes excessive carbon content in the fly ash at the ESP inlet ESP performance will suffer because of the decreased resistivity of the fly ash
Flue gas temperature can also influence ash resistivity Peak resistivities occur between about 120degC and 230degC depending upon coal ash characteristics Above 230degC to 288degC the ash resistivity is inversely proportional to the absolute temperature while below 120degC to 149degC the resistivity is directly proportional to the absolute temperature (Singer 1991)
The quantity of fly ash produced from a particular coal can vary as discussed in Section 51 It is important to ensure that the total electrode collection surface area and rapping frequency is adequate to handle the quantity of fly ash produced so as to prevent re-entrainment of the material back into the gas stream after initial entrapment at the collecting plates (Strein 1989)
Migration velocity and therefore particle collection rates
61
Post-combustion performance
decrease in proportion to the size of the particle (Darby 1983 Wibberley 1985b) lithe coal is pulverised too finely before entering the boiler ESP perfonnance can be adversely affected due to reduction in particle size distribution of the fly ash at the precipitator inlet The fonnation of fine fly ash may be increased also by higher combustion temperatures and from coals that have a high Free swelling index Disintegration of swollen char particles precludes agglomeration of the mineral inclusions thus ensuring the production of finer ash particles (Wibberley 1985b)
Bench-scale tests that are nonnally perfonned on new coal samples include
preparation of ash samples in a test furnace fly ash resistivity measurement of drift velocity in an electric field
Ideally the ash analysed for the purpose of investigating ESP perfonnance should be taken from the boiler to which the ESP system under assessment is attached Baker and Holcombe (I988b) have demonstrated that the fly ash produced in a specially developed laboratory furnace could show similarities to fly ash resulting from combustion of the coal in approximately eight different power stations It was possible to reproduce the properties of the power station fly ash in tenns of electrical properties and elemental analysis
14 shyelectric stress 400 kVm
bull
13
10 - - ltgt power station fly ash
- simulated fly ash
Mass H2 0r fIgures Indicated = d fl r mass ry ue gas
015 9
80 100 150 200
TemperatureOC
Figure 23 Resistivity results for both power station fly ash and laboratory ash from Tallawarra power station feed coal (Baker and Holcombe 1988b)
and general shape although the material was coarser than nonnal power station fly ashes A comparison of the resistivities of boiler and laboratory ashes is illustrated in Figure 23
Measurement of ash resistivity must ideally be measured under the same gas and temperature conditions as those at which the precipitator will operate The packing density should also be the same as that of the dust layer deposited on the precipitator collectors Dust resistivity measurements do not correlate very well with experience in ash precipitation efficiency
Laboratory resistivity tests are not standardised by ASTM BS AS nor ISO The Institute of Electronic and Electrical Engineers in the UK standard IEEE 548-1984 describe a resistivity test designed for testing compressed fly ash at 96 water vapour by volume (IEEE 1984) Measurements of resistivity are usually taken during both heating and cooling of the sample (Young and others 1989) Figure 24 illustrates the resistivity curves against temperature for ashes from a South African coal and Polish and South African coal blend respectively It can be seen that there is a degree of hysteresis as a result of the effect of moisture in the ash
5
3
2
103
E Eo 5 c 0 4
2 323shy
s ~
200 Q)
a
102
5 4 South African coal 3 50 Polish50 South African coal
2
100 120 140 160 180 200
Temperature degC
Figure 24 Laboratory resistivity curves of ash from a South African coal and from a blend of South African and Polish coals against temperature (Cortsen 1983)
62
Post-combustion performance
which gives a lower resistivity and which disappears after the heating process (Cortsen 1983)
The drift or migration velocity in a particular electric field can be estimated by examining the dielectric constant and particle size distribution as well as the aerodynamic factors for the fly ash A technique has been developed for determining particle dielectric constant from resistivity cell tests and other measurements (Baker and Holcombe 1988a) Particle size analysis of simulated ash is not reliable because of the difference in severity of the combustion process between full scale and test combustor Optical and scanning electron microscopes can be used to assess the shape characteristics of the fly ash
Prediction of fly ash precipitation characteristics remains an inexact science so that both pilot plant testing and electrical simulation studies remain extremely important in determining the precipitability of fly ash in practice
Fabric filters Although the use of fabric filters has become more widespread in recent years with the continued preference for low sulphur coals and to reduce stack emissions further there are no coal quality tests which relate to their performance directly
As described in Section 523 in cases where sorbent injection into the flue gas is used to control sulphur emissions collection of the fine sorbent in the bag can confer a high surface area to the gas and enhance the sulphur collection performance
While the efficiency of fabric filters is very high it is important to note that problems may occur with the presence of fine ash and acid condensation derived from coal causing
retention of filter cake on the filter fabric after the cleaning cycle due to agglomeration of the cake improving its mechanical strength blinding of the apertures of the fabric by very fine particles clogging of the filter by condensation promoting filter cake agglomeration bag rotting due to acid condensation
523 Technologies for controlling gaseous emissions
A range of methods is available for control of gaseous emissions in particular for SOx and NOx Options include
emissions control in the combustor post-combustion control technologies
lEA Coal Research have produced several reports that review these technologies SOx control technologies are reported in Flue gas desulphurisation - system performance (Dacey and Cope 1986) FGD installations on coal-fired plants (Vernon and Soud 1990) Market impacts of sulphur control the consequences for coal (Vernon 1989) Technologies for
controlling NOx emissions are described in detail in the reports NOx control technologies for coal combustion (Hjalmarsson 1990) and Systems for controlling NOxfrom coal combustion (Hjalmarsson and Soud 1990)
Emissions control in the combustor In-furnace desulphurisation by injection of calcium-based sorbents is not a widely-used sulphur control technology at present mainly because of its inability to achieve as high sulphur removal rates in commercial use as wet or spray-dry scrubbers Promising results are being obtained with sorbent injection followed by enhanced collection in a fabric filter in New South Wales Australia (Boyd and Lowe 1992)
There are several potential problems that may arise from the injection of calcium-based sorbents such as limestone (CaC03) into pulverised coal flames
the additional calcium may interact with the coal ash to reduce the ash melting point with consequent risk of increased slagging and fouling it is necessary to handle increased quantities of solid residue the possible adverse effects of calcium addition on downstream equipment such as electrostatic precipitators and solid residue disposal (see Sections 522 and 524 respectively) the possible influence of sorbent injection on the radiative properties of the flame (Morrison 1982)
To date sorbent injection into the furnace has only been utilised in smaller power stations with low sulphur coal where its low capital costs are particularly favoured Sorbent utilisation rates are generally low although it still results in a significant volume of mixed fly ash and calcium sulphitesulphate residue requiring disposal (Vernon 1989)
The formation of NOx depends mainly on oxygen partial pressure temperature and coal properties such as the content of nitrogen and volatile matter Measures can also be taken to modify the combustion conditions so that they are less favourable for NOx formation (Hjalmarsson 1990) This is usually achieved by some form of air staging Combustion air is admitted in stages in such a way as to limit flame temperature
The implementation of low NOx combustion techniques is much easier and more effective in a new installation compared with a retrofIt Low NOx measures on existing boilers can affect the combustion the boiler and other parts of the power station Combustion measures especially on existing boilers are specific to each boiler Consequently it is difficult to transfer experience of the impact of coal qualities directly
Most NOx abatement investigations have concentrated on determining the coal properties that influence NOx formation such as total nitrogen content volatile matter content and particle size distribution and developing technologies for reducing NOx emissions (Nakata and others 1988) There is limited information available concerning the impact of coal properties on power station performance under low NOx
63
Post-combustion performance
combustion conditions Discussions with power station operators have revealed that coals which previously produced a satisfactory performance prior to low NOx modifications have caused increased carbon in fly ash andor fouling slagging and corrosion along with other problems under low NOx combustion conditions Some possible explanations for this behaviour are presented briefly below
combustion efficiency can be reduced combustion conditions that reduce NOx formation such as low combustion temperature and low excess air are not favourable for accomplishing complete combustion As a result of this the level of unburnt carbon in the fly ash tends to increase If this is not counteracted the high content of unburnt carbon can cause changed conditions in an electrostatic precipitator (Klingspor and Vernon 1988) and make the fly ash unsaleable (see
Section 524) changes may also occur in the characteristics of the fly ash due to the reduced combustion temperature This will make the fly ash less glassy changing its properties and making the fly ash less attractive for use in cement and concrete production the thermal conditions in both the water and the steam parts of the boiler may change through low NOx combustion leading to changes in the temperature profile of heat exchangers Combustion modifications can also lead to an increased furnace exit gas temperature (FEGT) Deposits on heat exchange surfaces can affect heat absorption The reducing atmospheres reduce the ash melting point and can aggravate the problem of causing heat surface slagging Low excess air and staged combustion can produce areas with a reducing atmosphere which cause corrosion to boiler tubes (Coal Research Establishment 1991) the higher pressure drop over burners requires a higher fan capacity This in addition to other measures such as increased mill energy to obtain the required fineness and flue gas recirculation leads to higher power consumption low NOx burners may give longer flames that can cause deposits by impingement Flame stability may also be influenced Decrease in flame stability is usually found at reduced load causing limitations to boiler load turn down
Low NOx combustion was in many cases expected to give a higher degree of slagging and fouling in the boiler The opposite however has also been found Either result causes changes in soot blowing operations (Hjalrnarsson 1990)
Post-combustion control technologies SOx emission is minimised mainly with low sulphur coal Beyond this control is carried out with flue gas desulphurisation (FGD) systems The vast majority of FGD systems use an alkaline sorbent to absorb the flue gas sulphur dioxide chemically There are a number of different types of FGD and the effects of coal changes on their performance depends on the specific design details - no generalisation can be made For example flue gas temperature and SOz level impact the performance of wet limelimestone scrubbers These same variables affect spray dry FGD systems differently (Hjalmarsson 1990)
In wet FGD systems the effects of chloride from coal are generally all negative Chloride concentrations can build to high levels in the wet scrubbing loop causing corrosion problems and greatly reducing scrubber liquid-phase alkalinity (Rittenhouse 1991) However the removal of HCl in spray-dry scrubbers can have both positive and negative effects The HCl in the system can improve SOz removal capabilities resulting in lower reagent costs This effect was noted during a full-scale test conducted by Northern States Power Company in 1983 The addition of an amount of calcium chloride equivalent to a 02-03 increase in chlorine content reduced lime consumption by 25 Pilot tests carried out by EPRI confmn this effect (Collins 1990) The savings in lime consumption usually outweigh the cost of any negative effects including
incomplete droplet drying corrosion of stainless steel components in the system increased pressure drop downstream of fabric filters degraded ESP performance
Reference manuals have been published at IEA Coal Research that evaluate the wide range of FGD systems (Vernon and Soud 1990 Dacey and Cope 1986)
Where power station limits for NOx emissions cannot be met by combustion control flue gas treatment has to be installed The dominant method in use is selective catalytic reduction (SCR) In the SCR method the NOx concentration in the flue gas is reduced through injection of ammonia in the presence of a catalyst The role of the catalyst catalyst types and the reaction mechanism are described extensively by Hjalmarsson (1990) The efficiency of NOx reduction is primarily dependent upon condition of the catalyst which in tum is dependent upon the type of catalyst its susceptibility to poisoning and its location in the flue gas flow
The positions that are used for catalyst location are high dust low dust and tail end In the high dust location between the economiser and the air preheater the flue gases passing through the catalyst contain all the fly ash gaseous contaminants and sulphur oxides from combustion This can cause degradation of the catalyst leading to a decrease in NOx reduction efficiency The main types of degradation that are coal quality related are
deposition of fly ash causing clogging of the pores of the catalyst (Balling and Hein 1989) poisoning of the active sites of the catalyst by compounds such as alkali ions (sodium potassium calcium and magnesium) especially in sulphated form and some trace elements such as arsenic (Gutbertlet 1988 Balling and Hein 1989) erosion of the catalyst A high fly ash content in addition to an uneven particulate concentration and size distribution are most likely to cause erosion problems
The lifetime of a catalyst in this position is considerably shorter than in other positions Nakabayashi (1988) reported from a comparison of the impact of position on catalyst characteristics that catalyst life can range from 2-3 years in
64
Post-combustion performance
Table 23 Effect of coal type on total concentrations of selected elements from fly ash samples (Ainsworth and Rai 1987)
Mean and range of concentrations in fly ashes (Ilglg solid) from
Element Bituminous Subbituminous Lignite
Arsenic 219 (11-1385) 191 (8-34) 544 (21-96)
Cadmium 117 laquo5-169) lt5 lt5
Chromium 245 (37-609) 73 (41-108) 284 laquo40-651)
Molybdenum 56 (7-236) 165 laquo4--55) 141 (8-197)
Selenium 123 laquo5-435) 142 laquo5-281) 184 laquo5-469)
Vanadium 290 (99-652) 133 laquo25-292) 209 (lt25-268)
Zinc 607 (65-2880) 148 (27-658) 647 (25-127)
mean value is followed by range in parenthesis for 26 8 and 5 fly ashes from bituminous subbituminous and lignite coals respectively
a high dust location compared to 3-5 years in the tail end position
A low dust location means that the catalyst is situated after a hot gas electrostatic precipitator and before the preheater The flue gas reaching the catalyst is almost dust free but still contains sulphur dioxide which may result in poisoning of the catalyst
Tail end systems have the catalyst situated in the end of the chain of flue gas purification equipment after the desulphurisation plant The flue gases reaching the catalyst therefore contain only small amounts of sulphur oxides and particulates
NOx can also be controlled through thermal reactions by using appropriate reducing chemicals The process is called selective non catalytic reduction (SNCR) It has been found that different conditions in the flue gases influence the reactions and the temperature window (Mittelbach 1989 Gebel and others 1989) High CO content (gt1000 ppm) reduces the removal efficiency High S02 content increases the reaction temperature (Hjarlmarsson 1990)
Numerous processes have been developed for combined desulphurisation and denitrification of gases Most processes are still at the laboratory scale and there are a few stations operating at full commercial scale Coal quality effects on combined removal processes have not been studied extensively The problems encountered during the implementation of the individual abatement technologies may also be exacerbated for the dual systems An lEA Coal Research report Interactions in emissions control for coal-fired plants (Hjarlmarsson 1992) examines the interactions between control of S02 NOx and particulate emissions with different combustion methods and also the production of solid and liquid residues An understanding of the impact of coal quality on emission control technologies must be achieved for future efficient implementation of control systems
Trace elements emissions during combustion can also become associated with fly ash andor bottom ash Because of vaporisation-condensation mechanisms most of the trace elements in fly ash are often higher in total concentrations than those found in the corresponding bottom ash (WU and Chen 1987) In addition the levels of many trace elements including Cr Mn Pb n and Zn are often concentrated on the surfaces of the fly ash particles Typical median concentrations of selected trace elements in fly ash from different coal types are shown in Table 23 In power stations equipped with wet FGD systems the sludge from the scrubbers is a combination of spent solvent calcium sulphate and sulphite precipitates and fly ash The quantity and distribution of trace elements occurring in sludge are essentially determined by the coal ash composition and may influence the disposal cost of the material (Akers and others 1989)
524 Solid residue disposal
A typical pulverised coal fired power station employing ESPs or baghouses for particulate control and FGD for SOx control can produce three types of residue bottom ash (including slag) fly ash and FGD sludge Although under favourable conditions increasingly large amounts of these residues are utilised for various purposes at a net profit to the utility (Murtha 1982 Taubert 1991) it is anticipated that utilisation will not eliminate the need for disposal at a net cost in the foreseeable future
Changing coal characteristics can impact both the quantity and characteristics of the residue Power stations with limited resources for residue disposal have to transport the ash to alternative locations Ash for disposal may be conveyed to the disposal site as a dilute slurry Cerkanowicz and others (1991) reported that physical and rheological properties of fly ashes vary from different power stations This can impact the flow properties of fly ashwater mixtures significantly
The major factors that affect the amount of residue produced
65
Post-combustion performance
Table 24 Summary of the effects of coal properties on power station component performance - III (after Lowe 1987)
Property Contributing properties
Ash and dust plant
Ash quantity per unit heat release
Slagging propensity
Ash solubility
Erosiveness
Clinker reactivity
Environmental control
Coal cleaning
Particulate control ESP Dust burden (Ash per unit gas volume) Gas flow per unit heat
Ash resistivity
Sulphur
Fabric filters Dust burden
Gas flow per unit heat
Combustion measures
Post combustion
Residue disposal
ash level heating value grindability
ash elemental analysis ash fusion temperature coal particle mineral matter
ash elemental analysis ash mineral composition
mineral matter elemental analysis coal size distribution trace element
ash heating value ultimate analysis CIH ratio moisture level
ash heating value ultimate analysis CIH ratio moisture level
sulphur nitrogen volatile matter
cWorine fly ash size trace elemental analysis
ash ash elemental analysis sulphur heating value trace elemental analysis chlorine content
Effect
A I increase in ash quantity per unit heat release increases the ash and dust plant duty by 1
High slagging propensity increases the duty on ash extraction plant Formation of large clinkers may cause blockages in hopper doors and contribute to ash crusher problems
For wet hopper systems with recirculated water formation of scale pipelines may cause problems
Increased erosiveness will increase wear in pipelines and sluiceways
Some coals produce clinker in the furnace which is prone to explosive release of energy on quenching in the ash hopper
Different techniques are required depending upon the type and size distribution of the mineral matter Coal particle size influences the efficiency of the cleaning process and overall organic coal recovery
A 1 increase in dust burden will increase emissions by 1
A 1 increase in gas flow per unit heat release will increase emissions by 15 A resistivity change of 1 order of magnitude would suggest an increase in emissions by a factor of 2 General trend for reducing resistivity as sulphur increases possibly one order of magnitude per 1 sulphur change Below 1 sulphur resistivity is dominated by other factors
Differential pressure will increase with dust burden
A 1 increase in gas flow per unit heat release will increase unit heat differential pressure over the filter bags by 1
Influences the amount of sorbent used and dust collecting efficiencies Use of low NO burners can influence the combustion conditions and promote slaggingfouling due to reducing conditions present
Can have a positive and negative influence on SO removal efficiencies Can cause a reduction in catalyst efficiency in the removal of NObull
Quantity and quality influenced by the properties Saleable byshyproducts can be contaminated by carbon carry-over and trace elements
Quality of FGD waste can be influenced by cWorine and trace elements content
66
Post-combustion performance
annually by a pulverised coal fIred power station are the following
coal consumption ash content of the coal sulphur content bottom ashfly ash ratio fly ash collection efficiency SOx removal efficiency
These in turn influence the land requirement for residue disposal Ugursal and Al Taweel (1990) use the parameters listed above for calculating the area requirement for power station ash and FGD sludge disposal
The characteristics of the solid residue are particularly important where the residue materials must meet specifIcations to be sold (Cerkanowicz and others 1991 Bretz 1991b) For example the key requirement for the use of fly ash in cement production is the carbon content (Tisch and others 1990) A typical specifIcation is less than 5 carbon A coal change which degrades mill performance affects flame stability or reduces the rate of char oxidation such as in the case of low NOx combustion measures may increase the carbon content enough to exceed this carbon specifIcation (Zelkowski and Riepe 1987) Such a change would result in a considerable net cost to the utility since the fly ash would need to be disposed in a landfill at some cost instead of being sold for cement production at a profIt (Folsom and others 1986b) Similar problems can occur with FGD solid residue use for gypsum production The chlorine content of the coal is becoming an increasingly important consideration for power stations that have an established market for the gypsum produced from FGD residue as the chlorine impacts the quality of the gypsum for sale
The trace element content of combustion residues is an important consideration for both disposal and utilisation purposes (Clarke and Sloss 1992) The concentrations in power station residues may vary signifIcantly depending primarily on the coal used and on the cleaning techniques and combustion methods employed Therefore if the residue disposal strategy of the power station includes residue utilisation then a detailed knowledge of trace element content of the coal being fired is essential An lEA Coal Research report Trace elements emissions from coal combustion and gasification examines the behaviour of trace elements within these systems in more detail than can be discussed here (Clarke and Sloss 1992)
53 Comments The properties of coal affect the performance of the post combustion components of the power station These impacts are summarised in Table 24 As has also been highlighted in Chapters 3 and 4 many empirical relationships have been developed and used to describe the problems that are encountered in these systems but there are some signifIcant uncertainties related to many assumptions made For the post-combustion components these can include
fly ash collection - there is considerable disagreement as to the best method of measuring fly ash resistivity There is no correlation between coal composition and fly ash fIneness technologies for controlling gaseous emissions - there is no adequate means to predict NOx emissions
Whenever a change in coal supply is considered it is important to pay attention to the downstream effects
67
6 Coal-related effects on overall power station performance and costs
The production of electricity at the lowest busbar cost at a coal-fired power station depends on
the capital costs of the power station the delivered cost of the coal consumed overall power station performance the way in which the capital costs are financed during the construction and operating life of the station (interest depreciation profits taxes etc) the cost of decommissioning the power station at the end of its life
Coal quality can affect each of the above factors except for the last two components The main aim of this chapter is to look at coal-related effects on overall power station performance and costs
61 Capital costs The capital costs in most cases are affected by the range of coal qualities envisaged at the design stage (Mellanby-Lee 1986) In a study done by Ebasco Services Inc (Cagnetta and Zelensky 1983) the capital costs of a new power station are estimated for a wide range coal and a dedicated coal specification The wide range coal characteristics encompass about 90 of the recoverable reserves east of the Mississippi in the USA while the dedicated coal characteristics vary over a much narrower range Table 25 gives details of coal quality values for both types of coal and the costs with respect to the design for the wide range coal type It can be seen that the cost of a power station to bum a wide range of coals is $54 million more expensive than the design for a dedicated coal supply
A decision to bum high sulphur coal in a power station may necessitate the installation of an FGD or other emission control technologies FGD the best established technology to control emissions can be costly typically adding up to 20 or more to the total capital cost for new capacity and around
Table 25 The effect of coal quality on the costs of a new power station (Cagnetta and Zelensky 1983)
Coal Wide range Dedicated
Heating value GIlt 2442-3315 2949-3282 Moisture 10-150 10-65 Ash 60-180 64-146 Sulphur 05-40 17-32 HGI 40-64 45-60
Power station capital costs $ million coal handling +03 base steam generators +66 base ash handling +10 base ESP +417 base FGD +46 base total 1086 1032
Figures are for a 2 x 600 MW net power station they exclude coal costs
30 to power station capital costs when retrofitted to existing power stations (Vernon 1989) Control costs for NOx an additional environmental consideration are lower adding some 6-10 to the total capital costs of large new plants but as with FGD costing more when retrofitted (Hjalmarsson 1990 Daniel 1991)
62 Cost of coal The cost of internationally traded coal varies considerably For the third quarter of 1991 the lEA reported that the average cif coal import prices in Europe Japan and the USA were 4927 4998 and 3425 US$lMt respectively The range of prices to the two major importing areas that is the EC and Japan were 4320-5068 US$lMt and 4451-5180 US$lMt respectively The variation in prices is influenced by geographic location transport costs and coal quality The lEA reported that countries describe thermal coal using different average coal quality values for example the lower
68
Coal-related effects on overall power station performance and costs
heating value of a steam coal as detennined by the EC is 2617 MJkg (6251 kcalkg) compared with Japan at 2466 MJkg (5890 kcalkg) (International Energy Agency 1992)
Ash contents of traded coal vary substantially from under 5 for Colombias Cerrej6n coal for example to over 20 for typical South African thermal coals (see Table 26) Most of the traded coals have an ash content below 15 with the average being around 12-13 Given the associated costs of ash handling and disposal (see Section 63) coals with high ash contents will attract a lower price than those with lower ash even when corrected for heat content because of the application of penalties Many utilities and traders have a formula for calculating price penalties in relation to ash content Estimates of penalties vary depending upon the equipment in place It is probable given the increasing concern about the disposal of combustion residues that these ash penalties may increase during the next decade and a half
Table 26 Ash contents of traded coals (Doyle 1989)
Low Medium High lt8 8-15 gt15
Colombia Canada South Africa Venezuela China Indonesia Australia
Poland USA South Africa
While ash characteristics have traditionally most worried boiler managers sulphur content has become more significant in recent years because it is the primary determinant of the cleanliness of a coal in relation to S02 emission standards Most traded coal is low sulphur Only a small volume has a sulphur content above 15 However as S02 emission standards have tightened there has been a noticeable downward shift in what is considered low sulphur coal The defmition of low sulphur is now perceived to be below 09-10 and an increasing amount of traded materials now below 06 Various studies have deduced that low sulphur coal could command a premium price of up to one third greater than high sulphur coal (Doyle 1989 Calarco and Bennett 1989) Doyle (1989) also reported that at the most general level the low sulphur premium must be less than or equal to the smaller of either FGD costs or coal cleaning costs Otherwise buyers would take higher sulphur coals In practice the situation is more complicated For some users regulations may make the use of low sulphur coal or FGD equipment compulsory An excessive premium on low sulphur coal may also bring gas frring inter-fuel competition into consideration
63 Power station performance and costs
Several investigations of coal qualitypower station performance relationships have been conducted by utilities and other organisations These have been reviewed by
Folsom and others (1986a) In general the manner in which station performance evaluation of the impacts of coal quality have been assessed was by considering the following four performance categories
capacity - the capability of the unit to produce design load
heat rate - a measure of the net energy conversion efficiency
maintenance - the cost of maintaining all components in suitable working order
availability - a measure of the degree to which the unit can be operated when required
A summary of coal quality effects on these categories is presented under these headings
631 Capacity
The utility industry uses a number of definitions for station capacity In this discussion the term capacity will refer to the maximum rate of power generation for a specific unit under given operating conditions It should be noted that changes in this definition of capacity mayor may not be of economic consequence to a utility The need to operate a specific unit depends on
utilitys power demand available capacity system-wide relative costs of operating the specific unit compared to other available units
Fuel quality can affect unit capacity in a number of ways An analysis of the way fuel quality affects the capacity of each component of a generating station can reveal the total impact This analysis must start with the component most critical in detennining power station capacity The next step is to estimate the effects on less critical components The effects of successively less critical components may be interactive with the impacts on more critical components In some cases a change in fuel quality may affect one component to such an extent that it becomes the most critical item
Since a coal-fired steam-electric unit has a large number of components detailed analysis can be quite complex In Chapters 3-5 the effects of coal characteristics on the seven major components of a power station were described The capacity of the component was often influenced by these effects In many cases these effects could be evaluated with reasonable accuracy using existing straight forward engineering procedures In other cases assumptions on coal behaviour had to be made to facilitate the calculations As was summarised in Sections 34 43 and 53 there are some significant uncertainties related to many assumptions made
632 Heat rate
Heat rate (HR) is an index of the overall efficiency of a power station expressed as the heat input in the form of coal (Qin (MJIhr or BtuIhr)) required to produce one unit of electrical energy It may be expressed on a gross or net basis Gross heat rate (GHR) is based on the total or gross power
69
Coal-related effects on overall power station performance and costs
(GP) produced by the turbine generator while the net heat rate (NHR) is based on the GP reduced by the auxiliary power (AP) NHR depends on the turbine heat rate (THR) boiler efficiency (BE) GP and AP and it may be calculated as follows
NHR= THR x GP BE (GP-AP)
The coal changes which affect heat rate are associated primarily with boiler thermal efficiency auxiliary power consumption and turbine cycle efficiency (via changes in steam conditions) The following three sections describe how coal characteristics can affect boiler efficiency auxiliary power consumption and turbine heat rate respectively
Boiler efficiency The most widely used method of evaluating the impacts of coal characteristics on boiler efficiency is to assess the heat losses from the boiler and to assume that the remainder of the heat is absorbed to produce superheated or reheated steam This approach has the advantage of eliminating direct measurement or calculation of heat transfer rates in each section of the boiler which are quite complex but can only be carried out with suitable probes on fully instrumented boilers
The procedure involves the calculation of around six types of heat losses (Corson 1988) These can be
dry flue gas loss heat losses due to fuel moisture heat loss due to moisture produced from the combustion of hydrogen in the fuel heat loss due to combustibles and sensible heat in the ash
heat loss due to radiation unaccounted heat losses
Dry flue gas loss which is usually the largest factor affecting boiler efficiency increases with higher exit gas temperatures or excess air values Every 35degC to 40degC increment in exit gas temperature is reported to reduce boiler efficiency by 1 A 1 increase in excess air by itself decreases boiler efficiency by 005 ill most boilers however increased excess air leads to higher flue gas exit temperatures (FGET) Consequently increases in excess air can have a twofold effect on unit efficiency (Singer 1991) Calculations of excess air requirements depend on
flame stability carbon burnout slagging and furnaceconvective pass heat transfer considerations
These are difficult to predict with existing correlations
Losses due to moisture and fuel hydrogen are calculated easily from the coal analysis data using straight forward chemical and physical relationships
illcomplete combustion is manifest primarily by carbon in the bottom and fly ash The carbon content of the ash is difficult to predict and is affected by the slagging and fouling characteristics of the coal If the furnace is large enough to avoid slagging and fouling problems the carbon content of the ash is often less than about 5 For any furnace the carbon content of the ash tends to increase as the excess air decreases Also carbon loss may vary with char reactivity which depends on coal characteristics such as particle size
Table 27 Calculation of boiler heat losses (Folsom and others 1986a)
Loss
Dry gas
Fuel moisture
Fuel hydrogen
Combustibles
Radiation
Data required
Coal ultimate analysis Excess air Exhaust temperature Product specific heat
Coal moisture content Exhaust temperature H20 latent and specific heat
Coal hydrogen content Exhaust temperature H20 latent and specific heat
Carbon content of ash Coal carbon and ash content Heating value of carbon
Total heat output Maximum continuous rating
Assumption Comments
Complete combustion based Carbon corrected for on ultimate analysis carbon lost to ash shy
usually the largest loss
Complete combustion of fuel hydrogen to H20
Neglects CO and HxCy emissions which are usually negligible
External surface temperature Usually less than 05 Ambient air velocity over surfaces Independent of coal characteristics Calculated using ABMA chart
Unaccounted None Allowance for Usually estimated as about 05 bottom ash quenching Independent of coal characteristics CO and HxCy emissions Miscellaneous
70
Coal-related effects on overall power station performance and costs
rank and petrographic composition and combustion as the heat absorption pattern in the boiler changes Also if conditions At present there is no satisfactory method of the acid dew point of the flue gases changes the operators predicting the carbon content of the fly ash andor may need to adjust furnace exit gas temperature (FEGT) so combustibles loss based on standard coal analysis alone as to maintain the minimum air heater metal temperature Most coal quality analyses merely assume that the carbon above the acid dew point to avoid air heater corrosion loss guarantee provided by a boiler manufacturer will not be Whilst largely empirical procedures are used the actual exceeded This is usually in the range of 5 since fly ash amount of available data are insufficient to determine the with higher carbon content has less value for subsequent use accuracy of this approach Thus improved procedures need such as feed stock for cement manufacture (see to be developed and evaluated for assessing excess air flue Section 524) For coals with 10 ash and 60 carbon as gas exhaust temperature and combustible loss as a function fired 5 in the fly ash corresponds to a carbon utilisation of coal characteristics for a given furnace efficiency of 9912 (Folsom and others 1986a)
A summary of the data required for calculating heat losses is Procedures have been developed to predict combustibles loss given in Table 27 Combustion handbooks published by the based on furnace models An example of this is a boiler manufacturers include detailed descriptions of 3-dimensional model developed by the Energy and procedures for evaluating these losses (Babcock amp Wilcox Environmental Research Corporation USA (EER) This 1978 Singer 1991) These calculations are complex but includes a char combustion sub-model which evaluates the nevertheless straightforward and can be automated via a combustion process as a function of the micro-environment computer program easily An illustration of typical boiler surrounding individual char particles (WU and others 1990) losses for four Australian Queensland steaming coals is given Several more simplified approaches to carbon loss prediction in Table 28 have been developed All involve burning the coal under controlled laboratory conditions measuring the carbon loss Auxiliary power consumption and then scaling these data to full-scale units (see Power station auxiliaries consume power for Section 421)
coal handling In the calculation of boiler efficiency the flue gas exit mills temperature (FGET) is usually assumed constant However a feedwater pumps detailed evaluation should consider that the FGET may vary soot blowing
Table 28 Typical boiler losses for four Australian Queensland steaming coals (St Baker 1983)
Coal type A B C D
As-burnt - Total moisture 70 160 100 110 -Ash 214 143 100 280 -Carbon 581 535 676 487 - Nitrogen 11 09 15 09 - Hydrogen 39 34 38 32 - Sulphur 04 03 02 02 -Oxygen 76 111 64 75 Unburnt carbon 05 05 05 05
Gross heating value GJt 2412 2120 2738 1998 Latent heat of evaporation 102 112 106 096 of H20 from coal OJt Net heat value GJt 2310 2008 2632 1902 Unburnt carbon loss GJt 017 017 017 017 Radiation amp other losses OJt 013 012 015 011 Total dry air per tonne of coal tit 9130 8180 10433 7556 Sensible heat in combustion air OJt 221 196 252 183 Total heat available OJt 2501 2175 2852 2057 Overall total combustion products t 10130 9108 11433 8556 Exit flue gases (at 130degC) OJt 0108 0110 0108 0110 Flue gas exit loss GJt 110 100 123 094
Heat balance Heat input in coal 1000 1000 1000 1000 - Flue gas exit loss 46 47 45 47 - Heat loss due to H20 42 52 39 48 - Loss to unburnt carbon 07 08 06 09 - Loss to radiation etc 05 05 05 05
Net heat to watersteam 900 888 905 891
71
----
-----------
Coal-related effects on overall power station performance and costs
fans 200 shyparticulate control
flue gas desulphurisation shy-~ 0
Auxiliary power is typically in the range of 50 to 100 of gross power and is highly dependent on the specific power station design However coal characteristics also affect power consumption for most of these components although the impacts in many cases are not large and can be evaluated by considering trends
The primary factors impacting the power requirements for coal handling are the design of the systems and the desired coal flow rate The design of coal handling systems varies substantially and power requirements can be determined accurately by considering the details of the specific designs Since coal handling equipment normally operates intermittently any change in coal flow rate will change the duty cycle of the equipment and the power consumption will be approximately proportional to the coal flow rate This assumes that no modifications to the coal handling equipment are made to increase capacity In some analyses the coal flow rate is assumed to be inversely proportional to the coal heating rate on the assumption that the total heat input remains constant However as discussed earlier any change in heating value may change the performance of several other power station components and impact overall heat rate This compounding effect means that changes in coal flow rate are often greater than would be expected based on heating value alone
The power required for coal grinding depends on mill design characteristics of the coal feed including its grindability and size distribution and the mill operating conditions including the coal flow rate and pulverised coal size distribution The manufacturers have developed power consumption correlations based primarily on Hardgrove grindability index (HGI) Cortsen (1983) reported that the power consumption of the mills at a Danish utility was mainly dependent on the grindability of coal In evaluating mill performance it must be recognised that for a given design the operating parameters are linked It is not possible to vary the coal flow rate HGI and pulverised coal size distribution independently This is illustrated in Figure 25 which shows the effects of an independent change of coal grindability on the performance of a pilot vertical spindle mill (Luckie and others 1980) However Folsom and others (1986a) put forward the theory that reasonably accurate evaluation of coal changes have been made by assuming that the power consumption varies linearly with the coal flow rate independent of coal grindability in cases where variations in HGI are small St Baker (1983) reported that the power consumption of mills increases with increases in moisture content
There are few data that can be used to determine the number of soot blowers and frequency of operation for a specific coal The usual procedure is to select the wall blower array based on experience with similar coals and to set the wall blower operating schedule during normal boiler operation to minimise slagging and fouling problems The actual frequency of soot blowing will depend on the severity of
a5 sect 5 0
Cii 0 ()
100 ---shy--constant coal flow rate ---
0
40 50 60 70
Hardgrove grindability index (HGI)
80
100 -
o 40 50 60 70 80
Hardgrove grindability index (HGI)
10 shy
5
o 40 50 60 70 80
Hardgrove grindability index (HGI)
Figure 25 Effects of grindability on vertical spindle pulveriser performance (Luckie and others 1980)
slagging and fouling In some cases certain boiler stages may be blown unnecessarily and incur a heat rate penalty Excessive blowing can result in erosion of the tube surfaces which leads to premature tube failure and subsequent forced outages Proper blowing schemes are critical in achieving target steam and flue gas exit temperatures Wall blowers can utilise steam or air as the blowing medium The steam consumption can be treated as auxiliary steam use and can be evaluated in terms of its impact on heat rate Compressed air is generated in motor driven air compressors and the compressor power consumption can be evaluated as part of the auxiliary power load which has a greater impact on overall heat rate
The power consumption of fans in a power station is based
72
Coal-related effects on overall power station performance and costs
on the required flow rate and pressure rise fan design and the method of fan control Given these parameters the power requirements may be calculated easily based on standard fan analysis procedures In general a coal change that causes an increase in flow rate or pressure rise for example as a result of a reduction of cross-sectional flow area due to ash deposit bridges will increase fan power requirements (Borio and Levasseur 1986)
Essentially all the power consumed by an electrostatic precipitator for particulate control is used to generate the corona The power consumed to charge and deposit particulates is negligible while collection efficiency increases with corona power (Folsom and others 1986b)
The auxiliary power requirements of the flue gas desulphurisation (FGD) systems depend on the equipment designs which vary substantially among operational systems employed internationally A number of reference manuals have been published which provide procedures for evaluating the impacts of coal quality on flue gas desulphurisation systems These manuals should be consulted to conduct a detailed evaluation of the impact of coal characteristics on flue gas desulphurisation system auxiliary power (Dacey and Cope 1986) Generally the FGD facility will require more auxiliary power when operating with a high sulphur coal
Turbine heat rate Turbine heat rate is an index of the efficiency of the steam cycle and generator set in converting heat supplied to the turbine in the form of superheated or reheated steam to electrical power The turbine heat rate depends on the specific design of the turbine cycle as well as the operating conditions principally the steam supply and the discharge conditions
Since the coal does not come into contact with the steam coal quality impacts on turbine heat rate are neglected in many analyses However coal quality can impact the steam supply characteristics by changing the distribution of heat absorption among the various heat transfer surfaces in the boiler as discussed earlier in this section It should be noted that this is distinct from the total quantity of heat absorbed which is related to the boiler efficiency Changes in the heat distribution may result in an inability to achieve the required superheat or reheat temperatures or necessitate excessive attemperation to moderate steam temperature Both effects can degrade turbine cycle efficiency significantly
Evaluation of the effects of coal characteristics on steam temperature and hence turbine heat rate requires analysis of the radiative and convective heat transfer occurring in the various boiler sections and consideration of the options available to boiler operators to vary steam conditions (see also Section 42) A wide range of heat transfer models of varying complexity for the furnace and convective surfaces have been created (Shida and others 1984 Robinson 1985 Boyd and Kent 1986 Fiveland and Wessel 1988 Pronobis 1989) (see also Section 72)
The effects of coal characteristics on heat transfer evaluated by these methods can be grouped into three categories
gas flow rate changes through the furnace and the tube bank due to the volume of combustion products which mainly affects convective heat transfer radiative heat transfer changes due to varying coal composition combustion conditions and particle deposition heat transfer change due to deposits resulting from slagging and fouling
The volume of combustion products from a coal of arbitrary composition can be evaluated easily by simple combustion principles given the firing rate and excess air The impact of volumetric air flow rate on radiant and convective pass heat transfer can be evaluated using the models The effects of coal composition on radiative heat transfer are more difficult to evaluate As coal composition changes the radiative characteristics of the reacting gases and particles change along with the characteristics of the wall deposits The emissivity and thermal resistance of the ash deposits have the greatest impacts Similarly the effects of fouling deposits on convective pass heat transfer are difficult to evaluate However tests of slagging in pilot-scale furnaces indicate that potassium sodium sulphur ash fusion temperature ash particle size and total ash might be important (Wagoner 1988 Pohl 1990) In contrast Wain and others (1992) have shown in a study of slags from UK power stations that the thermal conductivity of wall deposits is primarily influenced by the physical properties of the slag such as its porosity rather than by its chemical composition
Deposits are formed over the perimeter of the tube quite irregularly so that the effective shapes of the tubes immersed in the flow of flue gases are completely changed This not only impairs the efficiency of the heat exchanger because of the necessity to overcome the thermal resistance layer but leads also to changes of the heat transfer coefficient brought about by the changed flow pattern and the effective shape of the tube cross-sections In the course of time the properties of the deposits also change resulting in further changes of thermal resistance (Pronobis 1989) The ability to remove the deposit by soot blowing and recovery of lost heat transfer is also important and is determined by the thickness strength and phase of the deposit and the available soot blowing power (Wagoner 1988)
If the effects of these changes on heat transfer can be determined or assumed the turbine heat rate can be evaluated via thermodynamic analysis Several computer programs have been developed to analyse complex thermodynamic cycles The limiting factor of the models is the specification of the input parameters
In general the heat rate correlations are perceived to be adequate providing that certain key parameters such as excess air carbon loss and mineral matter impacts can be specified In many analyses these are assumed since coal quality impact data are usually not available An example of the cost implications of a coal change on heat rate for a 1000 MW boiler was compiled by Folsom and others (1986a) Figure 26 illustrates this effect based on various assumptions conceming the unit characteristics The relatively large change in coal quality is shown to result in a
73
Coal-related effects on overall power station performance and costs
Change in coal characteristics
Coal ash increase 10
Coal moisture increase 5
Coal heating value decrease 15
Char reactivity decrease
- carbon in ash increase 2
- excess air increase 0
Ash deposition
- superheat decrease 50degC
- reheat at temperature increase 5
- exhaust temperature increase 10
Loss component Cost impact
ESP
Coal handling
Carbon loss
Dry flue gas
Moisture loss
Fans
Turbine efficiency
070
010
055
079
048
066
118
65 capacity factor base line heat rate 10000 Btu kWh thermal efficiency 89 coal heating value 279 MJkg (12000 Btulb) coal ash 10 coal moisture 5 coal carbon 77 and coal cost 35 Sit
Figure 26 Example of cost impact of a coal change on heat rate for a 1000 MW boiler (Folsom and others 1986a)
cost impact in heat rate of $446 millioniy (1986 prices) which is equivalent to an availability loss of about 5
As an alternative to these fairly complex calculations some attempts have been made to correlate coal quality with heat rate and boiler efficiency statistically (Barrett and others 1983 Kemeny 1988)
Several organisations have developed methods to facilitate the calculation of coal quality impacts on heat rate Some of these methods use computer programs to calculate economic effects directly from coal quality data power station design information and economic assumptions Others make use of manual calculations and rely more on engineering judgement and experience with similar coals
The use of both statistical techniques and computer models is discussed in greater detail in Chapter 7
633 Maintenance
While it is widely accepted in the utility industry that coal characteristics can affect maintenance costs primarily via wear by abrasion and erosion and by corrosion of power station components there is at present no effective method for predicting the effects of a coal change on maintenance Utilities use a range of procedures to account for maintenance costs in coal-fired units Whilst these procedures generally meet utility needs they often make it difficult to evaluate actual coal quality impacts For example while the maintenance cost due to a tube failure may be identifiable it may not be possible to determine whether tube failures relate to coal quality water quality structural problems or other effects (Heap and others 1984) Another significant problem is that maintenance costs are due in part to phenomena which should be predictable and form part of scheduled
maintenance routine for example replacement of expendable components (such as worn mill rollers and balls) Unfortunately they are also due to unscheduled failures which may cause partial or full outages It has been demonstrated that both routine maintenance requirements and unscheduled outages can be affected by coal characteristics
The mechanisms involved in wear of components are discussed in more detail in Sections 32 and 422 For many components the major factor affecting wear rates and hence maintenance costs is the mass of material processed This will be directly related to the heating value of the coal and the heat rate of the power station However as discussed in Sections 32 and 422 certain coal minerals are identified as strongly influencing the rate of wear by abrasion in handling equipment and mills In some instances erosion rate depend on power station design and aerodynamic considerations (Walsh and others 1988 Platfoot 1990)
Increases in unscheduled maintenance costs and consequent reduced availability (see Section 634) even involving reduced boiler life which result from excessive boiler flue gas erosion and corrosion can be considerable In a review of the state-of-the-art methods of reducing fireside corrosion and fly ash erosion as factors responsible for tube failures in boilers Wright and others (1988) reported that both of the effects are considered to be major problems only on units burning coal that is rated as very aggressive (high sulphur alkalis and chlorine) or that contains a high percentage of erosive materials such as quartz and ash Fly ash erosion of primary superheater reheater and economiser tubes were considered to be more serious problems than fireside corrosion An interesting observation from the study was that although there were proven permanent solutions for most of the problems encountered such as coal and hardware modifications these were not widely accepted Evidently the
74
Coal-related effects on overall power station performance and costs
costs of these solutions were perceived to compare unfavourably with continued maintenance activities in spite of the inconvenience of several unscheduled outages annually for emergency maintenance
St Baker (1983) reported that a typical 20-day unscheduled outage on a single 350 MW generating unit to repair boiler erosion damage could cost more than A$2 million in 1983 in replacement power costs alone This would amount to more than A$33 million (US$25 million) at 1991 prices
In a study of the use of declining fuel quality in 110 and 200 MW Czechoslovak power stations Teyssler (1988) showed increased maintenance costs due to higher equipment wear Examples of costs were given as Czech crowns 15-25t ash output in 1988 (US$04-07 (1991raquo for the cost of repair and replacement of heating surfaces damaged by erosion a 1 increase in ash content was found to result in at least a 10 higher cost in mill component replacement
Smith (1988) in a paper describing Tennessee Valley Authority s (TVA) experience with switching to improved quality coal presents a comparison of performance variations at the Cumberland power station (2 x 1300 MW) and Paradise power station (2 x 704 MW 1 x 1150 MW) with coal quality over the period 1977-86 The results show that maintenance costs for the boilers burning equipment and ash handling equipment were reduced with improved quality coal Costs dropped by about US$15 millionyon average between 1980 and 1984 at the Cumberland power station In this case the improvement in quality was achieved by cleaning the coal supply Prior to coal washing the units exhibited extensive slagging fouling corrosion and tube leakages Figure 27 shows the effect of a coal quality change that occurred at Cumberland in 1982 The largest change after washing was a reduction in ash content from about 152 to 92 Sulphur was reduced from 35 to 28 and which heating value went up from 249 MJkg (10712 Btulb) to 271 MJkg (11635 Btulb) In contrast
10 o boilers
A burning equipment 9
LD ash handling equipment co en 8~
c Q 7E $ (j) 6 =gt t5 50 u (l) u 4c ro c 2 3c iii ~ 2
I 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986
Figure 27 Adjusted maintenance cost accounts for TVAs Cumberland plant (Smith 1988)
operation and maintenance costs for the Paradise power station do not show dramatic cost improvements on utilisation of washed coals because major modifications and maintenance improvements necessitating significant investment were also made to the station over the same time period TVA believe that damage done to the Cumberland boiler by years of operating with poor quality coal was still causing problems long after the change to washed coal (Smith 1988) This example illustrates the difficulty of obtaining valid information of coal quality effects on maintenance and other power station performance factors independently from the influence of other modifications and changes in operating procedure
Hodde (1988) in an investigation of work conducted by Blake and Robin (1982) which considered the contribution of coal quality effects to total fuel-related operating costs of the Southern Company USA (see Table 29) concluded that whilst the dominant portion of the total fuel-related bill is the delivered cost of fuel comprising about 80 the remaining costs are associated with problems due to coal quality It was shown that approximately three quarters of the quality-related costs are in maintenance and residue disposal From this assessment Hodde (1988) suggested that maintenance costs relate linearly with coal quality in particular ash and could be calculated in advance This figure together with the price of the coal would account for almost 90 of the total costs associated with the coal This simplified approach is adopted in a number of computer models (see Section 72) However the approach has been challenged by a number of other sources (Folsom and others 1986b Mancini and others 1987 Galluzzo and others 1987 Lowe 1988b) who report that maintenance costs are not linearly related to the mass of ash processed by a power station Additionally there is usually a substantial lag between the initial variation in ash content of the fuel and the first experience of its effect on maintenance costs Consequently care should be taken in the use of linearised maintenance cost assessments to allow for the effects of lead times and incubation
In general the relationships between maintenance costs and coal quality are difficult to assess due to four factors the inadequacies of records maintained by utilities the impact of non-coal-related factors power station design variations and delayed effects of coal quality impacts
Table 29 Total fuel costs for power stations of the Southern Company USA (Hodde 1988)
Costs of total For coals with ash content of
15 20
Delivered fuel cost 83 77
Waste disposal cost 5 6 Maintenance cost 7 9 Ash related unavailability 3 4 Other operating costs 2 4 Slagging and fouling -0 -0
Total 100 100
75
r ~ 250 lt9 c o t3 200 J 0 2 a 0 150 3 o a
Ui3 100
50
o 2 (ij 3
~
0 ro Q)r 0 a J
(fJ
0 ~ 0 gt
5 0
(ij 0 c Q)
3 ~ is
CD
~ 2 ro Q)r Q)
a
0 ltJ)
E 0 c 0 U w
c ~
-0 0 Q) u J 0
Ol c 6l Ol ro iii
Coal-related effects on overall power station performance and costs
Table 30 Comparison of reduced boiler availability on the basis of hours in operation and type of fuel (Pasini and Trebbi 1989)
Mean annual All boilers Hours in operation Type of fuel reduced availability lt105 gt105 oil-gas coal
Furnace wall 220 203 270 184 309 Secondary SH 054 032 113 045 075 Reheater 032 032 032 015 075 Primary SH 019 008 051 005 054 Economiser 013 005 036 012 014
Unheated 020 017 029 025 008 Casing 030 025 043 039 009 Others 045 075 048 045 045
Total 433 365 622 370 588
634 Availability
The availability of a power station is important to both system reliability and generating-company profit Improving availability only slightly can save considerably on reserve generating capacity and the cost of replacement power Availability can be defined as the percentage of time that a unit is available for operating regardless of whether electricity is actually generated The total electricity sent out from a power station is affected by the planned shutdowns for maintenance forced down-ratings forced outages and other reductions in its availability (Mellanby-Lee 1986)
While it is clear that availability can be affected by coal quality the nature of the relationship is not well understood Statistical data-gathering studies such as the programme conducted by the North American Electric Reliability Council (NERC) utilising the Generating Availability Data System (GADS) supplied data relating to the component cause of outages and load reduction but were not able to provide information as to why particular components failed (Electrical World 1987) A study conducted by Combustion Engineering USA has gathered information from coal-fired units of 390 MW and larger on the causes of outages and load reductions in nine major equipment categories related to steam generators Included were
water walls superheaters and reheaters economisers furnace soot blowingbottom ash removal equipment convection-section soot blowing and fly ash removal equipment boiler controls fans mills boiler circulating pumps
The study indicated that water wall superheater reheater and economiser tube leaks account for 80-90 of all forced outages whereas coal milling systems accounted for 50 of equivalent down-time hours in load reductions (Llinares and others 1982 Llinares and Lutz 1985) Pasini and Trebbi (1989) reported similar trends of reduced power station availability for ENEL Italy (see Table 30) Mancini and
others (1988) reported that in a study of the top eighteen causes of full and partial outages at coal-fired stations in the USA for the decade from 1971 through 1980 60 of these causes were related to coal-quality (see Figure 28)
A record of boiler tube erosion at two Australian power stations Munmorah (4 x 350 MW) and Liddell (4 x 500 MW) illustrates the considerable costs that can result from excessive flue gas dust burdens in boilers supplied with off-specification coals particularly ash content above the design level They have experience of
up to 7 per annum additional reduced availability due to outages for the repair of boiler tube leaks reduced boiler life before major refurbishment affecting the economic life and gross power station output over
350
300 Coal related outages represent 60 of total power station outages
E
Figure 28 Causes of coal-related outages (Mancini and others 1988)
76
Coal-related effects on overall power station performance and costs
Southern Electric System USA 10 ] D US Industry average
8
7
6
J lLshy 5 ltt w
4 9339
3
2
90
Early units Early units Later units 1975-77 1985-87
Figure 29 Boiler and boiler tubes equivalent availability factor (EAF) record (Richwine and others 1989)
which the power stations initial capital costs could be recovered the necessity to be complemented by a greater level of standby generating capacity in order to ensure adequate reliability of electricity supply to consumers (St Baker 1983)
Richwine and others (1989) reported the results of an availability improvement programme in the Southern Electric System (SES) USA coal-fired units Due to a decline in availability between 1970-76 increased attention was given to this factor such that from 1977 to 1988 an improvement of over 22 percentage points was achieved This turnaround was accomplished by recognising the problems implementing appropriate solutions and adopting new power station practices The problems included coal-related cases such as boiler tube superheater reheater and economiser tube failures arising from fly ash erosion and slagging Figure 29 shows the increase in equivalent availability factor (EAF) achieved when coal quality upgrades were adopted along with tube maintenance during planned outages and the design improvements of later units to incorporate a wider range of coals while maintaining high reliability Problems encountered with mill operation were recognised as being a result of coal characteristics Many units experienced outages due to fires and flow problems due to high moisture coal
It has been suggested that a 5 increased outage rate for a power station designed for a 30 ash coal compared for one designed for 15 ash is a reasonable allowance for possible loss of availability (ERM Consultants 1983)
Due to the undefinable relationship between availability loss and coal characteristics engineering correlations cannot be used directly to evaluate the impacts of coal quality on availability At present the only way to calculate availability loss due to particular coal parameters seems to be to correlate
performance observations in the operating boiler with coal quality data Illustrations of these type of observations have been given above On a larger scale than single power station observations the statistical studies conducted by TVA (Barrett and others 1982) EPRI (Heap and others 1984) and the National Economic Research Associates (NERA) (Corio 1982) (see also Section 731) provided correlations for availability parameters of boilers with
ash sulphur and the age of the boiler (TVA study) actual ash sulphur and moisture content utilised and differences between actual and design values a complex relationship involving 13 independent variables
Most of the methodologies above resulted in equivalent availability values increasing with ash and sulphur contents which is contrary to expectation The correlation utilising the difference between actual and design coal quality values with availability agreed with expectation in that the availability of a power station should be degraded by deviation from the design coal specification A more detailed account of statistical studies is given in Section 731
64 Comments In any final analysis the economic trade offs which take into account system availability cost of coal (at various quality levels) maintenance costs substitute fuel and capacity costs station replacement costs etc must be analysed for each operating situation Only then can any meaningful and specific conclusions about the cost impact of coal quality on the cost of electricity be made Final judgements are often required to compare these costs with other factors such as diversity of supply reliability control of emissions for environmental reasons balance of trade and currency availabilities in order to make final coal selection decisions
Whichever judgement is made it is widely accepted that the capacity availability and cost of operation of each individual boiler are materially affected by the quality of coal fed to it It is generally believed that availability does not depend on the quality of the design coal and will only be affected if the actual coal burnt is outside the design range (Cagnetta and Zelensky 1983) However experience at some stations have shown that substantial losses in availability or down ratings can occur when the quality of the coal used is not outside the design range A summary of these effects is shown in Table 31 The missing links though in coal quality evaluations are the lack of information concerning power station performance and the ability to attach a price to a change in performance as a result of a change in coal quality
There is also the problem that some affects of a change in coal quality require time to show themselves Proper allowance must also be made for this incubation period
Hitherto the accounting systems of many utilities have not been designed to identify easily the costs associated with coal quality impacts (Skinner 1988) These systems need to
77
Coal-related effects on overall power station performance and costs
Table 31 Examples of boiler fireside variables station and cost components which may be affected by those variables when coal quality is changed (Sotter and others 1986)
Variable type Boiler design Operating conditions cost component
affected Coal quality
Capacity Ash size distribution - organic associations - separate species Moisture content Hardgrove grindability index Sulphur content
Heat rate illtimate analysis Moisture content Slow burning macerals Slagging fouling indices (Steam temperature control)
Maintenance Ash content Ash composition (abrasiveness slagging tendency)
Availability Ash Na 0 CaO Fez03 SiOz etc
be updated and improved if utilities wish to take full advantage of new tools that are becoming available In particular improved data are required to support the
Number of mills Precipitator collecting area
Burner type Furnace size
Number and placement of soot blowers
Heat releasefurnace area Convective tube spacing
Excess air
Excess air Coal particle sizes Burner settings
Load history
Load history Soot blowing interval
increasingly sophisticated computer models which can be used to predict the effect of fuel quality on station performance
78
7 Computer models
The decision to buy particular quality coals from either local interstate or from international sources must include a quantitative evaluation of the impact of coal quality on performance of the power station and ultimately the cost of electric power generation As has been demonstrated in Chapter 6 and illustrated further in this chapter the cheapest coal to buy does not necessarily produce the cheapest electricity Because of the large number of processes involved in the coal-to-electricity chain and the complicated nature of coal-power station interactions engineering and economic evaluation studies are usually both time consuming and costly The methodologies adopted can range from manual calculations and a reliance on practical experience with similar coals through to elaborate computer models which calculate performance and resulting economic impacts directly from coal quality data power station design information and economic factors Use of a computer based model to quantify the impact of coal and system parameters on the cost of electrical generation could substantially reduce the time and cost of these studies In theory such a model would be used to evaluate various approaches and the most economic action could be selected with relative ease (Ugursal and others 1990) However it should be noted that the results from the models are only as good as the data used in particular the coal properties measured to predict combustion performance
For the purpose of this report the types of models available for the evaluation of part or all of the coal-to-electricity chain (see Figure 1) have been identified as belonging to one of four categories described below
least cost coalcoal blend models that assess the cost of coals and their associated transport costs They can calculate suitable coal blends according to power station design specifications to provide the lowest cost purchasing plan They may also include allowances for some maintenance and disposal factors
component evaluation models that predict the performanceefficiency of the subsystems of the power station such as mills boiler ESPs unit models that offer coal quality impact evaluation of an entire power station and in some cases attempt to supply costs of the impacts on generation Two methods most commonly put forward as evaluation techniques include
statistically-derived regression analyses leading to overall power station inputoutput models developed for specifying general utility power station requirements These models however do not usually contain detailed predictions of system operation or design requirements
systems engineering analysis for defining relative impacts of fuel properties on each systems performance These types of models are being developed by both equipment manufacturers and research contractors and utilise in addition to fuel property data (that is proximate and ultimate analyses and slagging and fouling indices) special bench-scale measurements of key parameters and pilot-scale data These data combined with the proprietary models can allow for the determination of operating limits for specific units
integrated site models that bring together the information from unit models systems performance and other models and are integrated directly into the control room data system
In this chapter brief examples of the above methodologies are described with particular emphasis given to unit models which are known to include coal quality impact assessments Although particular attention is given to coal specification details used by the models the overall intention is to provide a cross-section of the procedures and the capabilities of the various methodologies
79
Computer models
71 Least cost coalcoal blend models
Least cost models in most cases use linear relationships for the evaluation and purchasing of fuels for power stations The technique is used to find the lowest cost purchasing plan for a utility fuel buyer from among a large number of fuel supplies available and will meet the constraints imposed by the fuel supplies and by the utilityS system The programs are usually designed to run on personal computers and to be user-friendly (Allman 1987 Bek 1987 Hodde 1988 Maher and Smith 1990)
Examples of this type of model include the International Coal Value Model (ICVM) (Maher and Smith 1990) Least Cost Fuel System (LCFS) (Hodde 1988) and Perfectblend (Bck 1987) and Steam coal blending plan (Allman 1987 1991) for blending coals
Least cost coalcoal blend models are reported to have the ability to conduct an economic evaluation of thermal coals as traded on the world market The main users of the models are identified as power companies buying coals of various properties and costs from a number of sources In many cases
blending of coals would also be employed The coals would be selected by the model in accordance with the coal specification requirements of the power stations based on their design and operating experience They are designed as a tool to determine the real cost of coal and energy at the inlet of the power station being considered (see Figure 1 Sections 1-4 of the coal-to-electricity chain) They permit comparison of all coal properties within allowable power station coal specifications including other coals and blends It allows for the blending of a large number of coals in any desired proportions (Maher and Smith 1990) Examples of the types of input data required and the items included in the results for a Least cost model are given in Tables 32 and 33
This type of model does not apply merits or demerits in value for particular properties for example sulphur The reason given by the developers is that the effect of such properties is very site-specific being dependent on the design of the power station and accessories for example flue-gas desulphurisation environmental regulations applying residue disposal costs etc
Hodde (1988) illustrated the use of the Least Cost Fuel System model by considering a utility system with three
Table 32 Model input output data -International Coal Value Model (ICVM) (Maher amp Smith 1990)
Developer Coal input Generating unit input Key output
Joint Coal Board CSIRO Australia
Gross specific energy Total moisture Proximate analysis Elemental analysis Chlorine Phosphorus Free swelling index Hardgrove index Ash fusion temperatures degC Top size mm Fines ltlmm Sulphur form Ash analysis Cost fob cif Currencies amp
exchange rates Ocean freight costs Insurance costs Handling costs
Power station power output MW Generated thermal efficiency Capacity factor
Gross and net specific energy and other properties calculated to different bases and units
Slagging and fouling tendencies Average blend properties with non-linearity warnings CoalconsumptionUy Ash production Uy Cost of coal at pulverisers in various currencies on a
tonne per consignment and per energy unit basis Thermal coal database
Table 33 Comparison of coal energy costs based on gross heating value (at power station pulverisers) - in order of increasing cost (Maher and Smith 1990)
Coal Cost US$GJ Total Specifications moisture
ash VM gross specific energy MJlkg
BBB 206 90 1193 330 2953 AAA 212 95 1238 316 2909 Blend 2 220 84 1434 288 2903 Blend 1 222 86 1406 291 2901 CCC 229 80 1596 260 2869
80
Computer models
coal-fired power stations evaluating the purchase of coal from eleven coal sources supplying contract and spot deliveries Like the ICVM model the objective function to be minimised includes the sum of the fob mine coal cost transport cost and coal quality costs for all three stations on the system But unlike the ICVM the LCFS includes additional costs related to coal quality that are net of the following
maintenance costs assumed to be linearly proportional to the tons of ash processed by each power station ash disposal costs also assumed to be linearly proportional to the tons of coal burned at each station fuel handling costs assumed to be linearly proportional to the tons of coal burned at each station FGD operation and maintenance cost and FGD residue disposal costs assumed to be linearly proportional to the tons of sulphur removed from the flue gas revenue from the sale of ash for construction material assumed to be linearly proportional to the ash content of the fuel
These factors are calculated separately and fed into the LCFS model Additional constraints can be added for utility application For example some utilities are located in regions which have legislated that a certain fraction of the coal burned for power production must be sourced from the region
These programs make only limited provision for coal quality because most of the effects on costs are non-linear so that they cannot be accommodated by these models Warnings are issued by some models of the non-linear behaviour of coal blend properties for example Hardgrove grindability index ash fusion temperatures and ash analysis
Coal quality impacts that are not assessed by the simple models include
slagging and fouling costs cost of reduced boiler availability impacts of coal quality on gross power station heat rate and boiler efficiency impacts of coal quality on the capacity of various station systems including mills fans and ash handling systems
72 Component evaluation models Since the mid-1970s boiler manufacturers utilities and other research centres have been developing advanced numerical system models that can be used to optimise performance of power station components and hence improve overall system performance Most of the development effort has been directed to modelling the boiler With the increasing availability of substantial computing power numerical simulation of combustion systems is now feasible and provides a new engineering tool for evaluating designs and the complex interactions in the flow and combustion processes More recently the techniques have been applied to improve understanding of NOx formation and control in increasingly complex combustion systems For boilers the intricacy of the models range from single zoned one-dimensional (I-D) models
that predict combustion and thermal efficiency for boilers with staged or unstaged combustion systems (Smith and Smoot 1987 Hobbs and Smith 1990 Misra and Essenhigh 1990) to models attempting to solve the fully elliptic multi-zoned three-dimensional systems with finite difference approximations of the conservation equations for mass momentum turbulence combustion and heat transfer (Thielen and others 1987 Boyd and Lowe 1988 Gomer 1988 Jarnaluddin and Fiveland 1990 Luo and others 1991) A widely used boiler computer code known as FLUENT has also been applied to model PF boilers (Tominaga and Sato 1989 Swithenbank and others 1988 Vissar and others 1987 Lockwood and Mahmud 1989) Other examples are documented in literature and a review of the application of these types of models to addressing both NOx formation and unburned carbon has been presented recently by Latham and others (1991a)
The output from these models includes coal particle trajectories within the boiler predictions of unburned carbon involving coal devolatilisation and char burnout models furnace exit gas temperatures (FEGT) species concentrations heat release and heat absorption (Latham and others 1991a)
The coal characteristics that have been found to have the greatest influence in these boiler models are
ultimate analysis carbon hydrogen nitrogen sulphur oxygen
moisture content volatile matter content ash content heating value particle size distribution
Most of the models do not include provision for the effects of fouling and slagging propensity of a particular coal on heat transfer Work on developing computer models that describes the transformation of mineral matter during combustion the mechanism of ash deposition on surfaces as well as the physical properties of the ash deposit after deposition has been initiated (Hobbs and Smith 1990 Smith and others 1991b Beer and others 1992) Baxter (1992) has recently reported the development of a model that considers ash deposit local viscosity index of refraction and ash composition (ADLVIC) in coal-fIred power stations In contrast to other ash deposition predictor models which are based on the elemental composition of ash ADLVIC is based on the mineralogical description of a coals inorganic matter and can be used to predict changes in these mineral properties with time and their effect on ash deposition as the particles flow through the boiler It has received some validation during a three week test burn in a 600 MW boiler operated by Centrallllinois Public Services The approach of using mineralogical descriptions of a coals inorganic matter has also been utilised in a model called the Slagging Advisor developed by PSI Technologies (Heble and others 1991)
81
Computer models
I
Performance factors
MAXIMUM MILL CAPACITY
INLET AIR TEMPERATURE
GRIND CHARACTERISTICS
POWER ~
I
I
I I
Indicescorrelations
Fineness bull passing 200 mesh bull gt50 mesh
Grindability bull
bull HGI Wear
bull abrasion index bull ash burden bull wear index bull equal life
moisture
Pulverised coal distribution bull Rosin - Rammler distribution
function perameter
Mass throughputMMBtu
HGI
moisture
i
Engineering analysis model
COMPOSITE MILL MODEL
- Maximum capacity bull base capacity (as new - of MCR) bull 10ssMMBtu throughput
- Inlet air temperature bull minimum inlet temperature
- Mill power
I
U)0 ttl
~ 0 Q5
~ 0 0 E
Q Level 1 predictions
Q Level 2 predictions
Figure 3D Mill engineering model analysis approach (Nurick 1988)
Nurick (1988) describes an engineering model for the detennination of performance factors for each major system component as impacted by coal quality The modelling approach for each component is described For example Figure 30 illustrates the analysis approach for the mill engineering model The figure also highlights two levels of prediction capability The first level is based on the manual assessment of indicescorrelations of the coal properties and the second level refers to predictions from correlations obtained from application of the mill model The latter predictions can be included into an overall power station model In this particular case the overall performance model does not include any cost evaluations These models can form part of larger more comprehensive systems engineering unit models as described in Section 73
73 Unit models The development of models to assess the impact of coal quality on overall power station performance was initiated in the 1970s when statistical methods were used to compare historical power station performance and cost data (such as forced outage hours or maintenance costs) with coal use and coal quality data in order to fmd working relationships
More recently engineering-based methods have been employed to predict power station performance directly from coal characteristics by using individual component models as modules in an overall power station model In some of the unit models both statistical assessments and operating experience are employed to produce an overall assessment
731 Statistically-derived regression models
Most statistical studies of coal quality impacts on power station performance have been conducted by utilities and research organisations in the US A notable and extensively publicised statistical study has been performed by Battelle Columbus Laboratories and Hoffman-Hold Incorporated on Tennessee Valley Authoritys (TVA) coal-fired power stations (Barrett and others 1982)
The TVA study was aimed at evaluation of how coal quality impacts on boiler operation and costs Information was collected from nine TVA power stations for the period 1962 to 1980 based on monthly proximate analyses of the coal used power station outages maintenance costs boiler
82
Computer models
Table 34 Boiler groupings in TVA study (Barrett and others 1982)
Plant and unit Size Manufac- Firing Stearn Year put Capacity Coal Firing configuration MWlUnit turer methodsect temperature into
degC COF) commercial gt500 MW lt500 MW Midshy
operation Large Small Eastern Western Wall Tangential
Bull Run 1 950 CE PF-DB 538538degC 1967 j j
(10001OOOdegF) Colbert 1-4 200 BampW PF-DB 566566degC 1955 j j
(l0501050degF) Colbert 5 550 BampW PF-DB 566538degC 1965 j j
(10501OOOdegF) Gallatin 1-2 300 CE PF-DB 566566degC 1956 j j j
(l0501050degF) Gallatin 3-4 328 CE PF-DB 566566degC 1959 j j j
(l0501050degF) John Sevier 1-4 200 CE PF-DB 566566degC 1955-6 j j
(l0501050degF) Johnsonville 1-6 125 CE PF-DB 538538degC 1951-3 j j j
(l 0001 OOOdegF) Johnsonville 7-10 173 FW PF-DB 566538degC 1958-9 j j j
(l 0501OOOdegF) Kingston 1-4 175 CE PF-DB 538538degC 1954 j j j
(l0001OOOdegF) Kingston 5-9 200 CE PF-DB 566566degC 1955 j j j
(l0501050degF) Paradise 1-2 704 BampW Cyc 566538degC 1963 j j
(l 0501OOOdegF) Paradise 3 1150 BampW Cyc 538538degC 1970 j j
(l 0001 OOOdegF) Shawnee 1-10 175 BampW PF-DB 538538degC 1953-6 j j j
(l0001 OOOdegF) Widows Creek 1-6 141 BampW PF-DB 538538degCj[ 1952-4 j j
(l 0001ooodegF) Widows Creek 7-8 550 CE PF-DB 566538degC 1961-5
(l 0501 OOOdegF)
BampW = Babcock amp Wilcox CE = Combustion Engineering FW = Foster Wheeler PF = pulverised fuel Cyc= cyclone fired DB = dry bottom
II Units 1-4 do not have reheat
efficiency and where available griruklbility data The data were organised into 15 groups of similar boilers (see Table 34) In addition six aggregates of these 15 groups were assembled based on the capacity of the boilers (greater or less than 500 MW) coal characteristics (Eastern or Western US coal) and firing configuration (wall or tangential)
A variety of statistical techniques including linear and non-linear multiple regression techniques were used to look for meaningful relationships Power station boiler capacity was considered for inclusion in the analysis but dropped due to lack of precise historical data Operating costs other than maintenance costs as determined by TVA were not deemed dependent on coal quality so that analysis in this area was also discontinued (Barrett and others 1983)
In spite of the fact that considerable quantities of data were available within the TVA system it was recognised at the time that the data were not designed to support this study Hence the preferred data such as data on boiler capacity and detailed coal analyses were not always available The investigators sometimes found themselves under severe
limitations They persisted because they believed that the results from what was originally conceived as a limited study might provide utilities with additional useful information for making decisions conceming coal purchase and use
The study identified some quantitative relationships between certain coal quality properties and power station performance and cost However the statistical analyses suffered from the difficulty of co-linearity (or correlated variables) as it was found that the impact of ash and sulphur also generally increased with boiler age due to unavoidable changes in the quality of the coal supplies over time Analysis of data from most TVA units showed that the ash and moisture contents of the coal together with boiler age had the greatest effect on boiler efficiency (see later Figure 32 on page 86)
Availability on the other hand was found to be influenced mainly by ash and sulphur content of the coal although boiler age was still relevant Only outages attributed to equipment that were exposed to coal flue gas or ash were considered in the analysis Over the range of ash fired at TVA power stations (generally 12 to 14) the statistical relationship indicated that for a typical power station the outage hours
83
Computer models
may vary by 360 hy because of changes in ash content alone Likewise over the range of sulphur values for TVA power stations (generally 10 to 50) outage hours at a typical power station may vary by as much as 870 hy due to sulphur alone
Only maintenance costs for coal-related equipment were considered relevant for evaluating the operating cost variations when fIring different coals It was found that ash sulphur content of the coal and power station boiler age were the independent variables although it was determined eventually that age was not a signifIcant factor affecting maintenance costs so that was dropped from further consideration This is somewhat surprising since it is commonly accepted that maintenance costs for most types of equipment increase with equipment age However the effects of age may have been overshadowed by the effects of changes in coal quality with time especially increasing ash
It was reasoned that maintenance costs were not an instantaneous effect of coal quality but rather a result of firing the coal over a period of time To account for delayed or integrated effects over time (for example erosion) the ash and sulphur mass variables were allocated a lag coefficient of several months in the correlations It was reasoned that correlations which suggested that maintenance costs decreased as ash and sulphur mass increased could be regarded as unreasonable because they did not agree with practical experience Consequently these correlations were dropped from further consideration independent of their statistical significance The final correlations were selected as those which produced the highest correlation coefficient value The correlations for the nine separate TVA power stations are listed in Table 35 There appears to be no relationship between the correlation coefficient and the number of units at a power station In addition to these separate power station correlations an overall correlation was developed The optimum correlations were obtained when the lag coefficient for ash and sulphur were set at six and ten months respectively
The reports and reviews of the study stress that the correlations developed for TVA are not necessarily applicable to other power stations because of some significant limitations of the study (Barrett and others 1982 Heap and others 1984 Folsom and others 1986b) First the correlations are based on only one utility - TVA This utility
has its own design philosophy for selecting units its own maintenance and operation strategy and for some units studied there is only one design fuel a bituminous coal Also over the 19 years of data evaluated the TVA units fired only Eastern and mid-Western US coals Thus the range was limited Furthermore TVAs coal purchasing strategy changed such that the coal quality deteriorated to provide higher levels of ash and sulphur as time progressed Thus it was to be expected that the range in ash and sulphur coefficients in the resulting correlations may be at least partially attributable to age effects Overall the study was viewed as an advance in coal quality impact assessment as it had attempted to address the problem of performance prediction and highlighted the inadequacies of coal quality and performance data records
Other studies have been carried out in an attempt to improve and extend the TVA analytical approach Heap and others (1984) reported that EPRI conducted a statistical study to determine whether the TVA methodology could be applied to a more diverse and larger data set that is 25 utilities The study focused on equivalent availability only No attempt was made to separate coal related and other outages Instead a wide range of boiler design parameters were included in the correlation The analysis also utilised the same coal variables as the TVA study ash sulphur and nwisture
As discussed earlier in Section 634 EPRI used an alternative approach to analyse the data In addition to using the log of equivalent availability as the dependent variable and linear ash and sulphur terms based on the as-fired coal data EPRI also used the equivalent availability directly as the dependent variable and the difference between the actual and power station design values of the ash sulphur and moisture content of the fuel as the independent variables This approach makes the effects of coal changes additive terms rather than multiplicative terms as in the TVA approach and the correlation exhibits a relationship that reflected engineering judgement such that the availability of a power station is degraded by deviation from the design coal specification Heap and others (1984) compared the correlations developed by the TVA and EPRI studies by using them to evaluate the effects on a 1000 MWe unit (see Figure 31) The base availability loss due to coal related effects was taken as 97 Base case coal was the design coal and the effects of increasing ash and sulphur content by
Computer models
Correlation predicts maximum 55465 h
100
lt 806
vi Q) OJ co 605 0 -0 Q) range for 6 ro correlations of ~ 40 large unit groups Cii 0 u 0 Ul 200 0
97
0
Base 5 ash increase
8760 (full year)
8000
CfJ
6000 ~ c Q) OJ CIl 5
4000 ~ Q)
ro ~ Cii
2000 8
o
2 sulphur increase
Decreasing coal quality ---
Figure 31 Comparison of TVA and EPRI availability correlations to a 1000 MW boiler (Heap and others 1984)
5 and 2 respectively were calculated The cost of availability loss was taken as $1000000 The ranges of predictions for the TVA correlations based on the 15 groups of similar boilers the six larger groups and the entire database are shown in Figure 31 The correlations based on similar units cover a wide range Note that the large change in coal quality as represented by the changes in ash and sulphur contents in each case evaluated resulted in some of
the correlations predicting greater outage hours than are contained in a year At the other extreme some of the correlations predict that performance would improve with a decrease in coal quality The range of correlations for the larger groups of units was smaller and shows an increase in cost with decrease in coal quality as does the overall correlation The EPRI correlation predicts a greater cost due to coal degradation than the TVA study by a factor of two
A statistical study conducted by the National Economic Research Associates (NERA) USA and reported by Corio (1982) evaluated the impacts of coal quality on gross heat rate and availability based on the performance of 171 coal-fired boilers with capacities greater than 200 MW included in the Edison Electric Institute (EEl) database Only those units which had burned coal exclusively for three or more years were included in the study As with the TVA and EPRI study the coal quality data were limited to the ash sulphur and mnisture contents
The NERA study developed a single correlation with parameters to account for the differences in unit design Table 36 lists the specific variables and coefficients determined in the regression analysis
Both the TVA and NERA coefficients for the correlations are positive indicating that an increase in ash and moisture will increase gross heat rate (GHR) These trends cannot be compared with the TVA boiler efficiency trends exactly as the dependent variables are different Folsom and others (1986b) in a review of the two studies made an approximate comparison by examining the relative changes in the dependent variables (percentage) as ash and moisture content vary This is equivalent to neglecting the NERA GHR correlation The
Table 36 NERA study - gross heat rate correlation (Corio 1982)
Class Variable
Coal quality
Unit designoperation
Ash H2O
Vintage
Age
Output factor
Firing configuration
Stearn conditions
Feedwater pump
Oil firing
Constant
Type
Linear Linear
Linear
Linear
Linear
Switch
Switch
Switch
Switch
Independent
Year - woo
Years
Reciprocal
Cyclone = 1 Other = 0
Supercritical =1 Subcritical = 0
Shaft = 1 Other = 0 Stearn = 11565 Other = 0
Oil = 1
Coefficient
1107 1326
6770
4884
11517640
18485
-11953
7255
31563
273500
Output factor = capacity factor(service hoursperiod hours) expressed as
85
Computer models
150 150
125 125
gf2 0
(l) (l)10 1015 0
co~ sectco gt gt C C (l) ~1lJ (l)
7gtlJ lJ a5 075 ~ a5 07500Q Q (l) (l)~ lJ ~O lJ
lt0~ ~ (l) 0- (l)
OJ OJ~0c 05 c 05 co co
r r U U
025 025
O-JL------------------------------o o 2 4 6 8 10 o 2 4 6 8 10
Ash
Figure 32 Comparison of ash and H20 effects on boiler efficiency and gross heat rate (Folsom and others 1986b)
comparison made is shown in Figure 32 where the selected trends of the overall TVA correlation are plotted against the trends of the NERA correlation The trends for moisture were shown to be similar but the effect of ash was shown to be a factor of about 45 greater for the NERA GHR correlation
More recently the Illinois Power Company (Behnam-Giulani and others 1991) conducted a statistical study based on a database containing NERC and Utility Data Institute (UDI) USA data of 5600 unit-years for coal-frred units from 1982-88 They developed four statistical models to describe heat rate equivalent forced-outage rate operation and maintenance costs and capital addition costs In terms of coal quality impacts the models indicated that
heat rate increased by 127 and 74 kJlkWh for each percentage point increase in ash and moisture content respectively OampM costs increase by 005 with each percentage point increase in ash capital addition costs including costs due to wear and tear increased by 010 $kW of installed capacity with each percentage point increase in ash Capital addition costs were shown to decrease with increasing percentage sulphur content This is contrary to actual experience and is believed to be an erroneous result caused by inaccuracies in the database
Some of the models for example the heat rate model were reported to display good accuracy while some others for example the equivalent forced-outage model proved to be less accurate It was believed that further refinement to the data and methodologies was necessary and for this reason the
study results were recommended for secondary (not primary) computations
It should also be noted that as in the earlier statistical studies only the coal qualities ash moisture and sulphur content were considered in the correlations This highlights the difficulty of obtaining relevant and reliable coal data and corresponding power station data to form such correlations
To summarise statistical methodologies have been shown to have several disadvantages
engineering data are required The TVA study evaluated boiler efficiency only and the NERA study evaluated gross heat rate only The statistical correlations provide only a portion of the information required to evaluate net heat rate the full range of designs cannot be correlated If separate correlations are developed for each unit or group of similar units the accuracies of the correlations are reduced due to the smaller number of data points Increasing the number of independent variables included in the correlation also reduces the statistical importance of each variable concurrent variation If two variables change in sympathy it is difficult to determine the effects of each variable independently coal quality variables are incomplete All the studies primarily correlated performance with the coal ash sulphur and moisture contents only due to the limited availability of coal quality data However several other coal quality parameters can have significant impacts on heat rate These effects cannot be evaluated statistically based on the existing databases
86
Computer models
database accuracies The accuracies of the statistical correlations are limited in part by the accuracies of the input data It is difficult to obtain coal samples that are representative of a full year or even a month of firing database representativeness Statistical correlations are based on limited databases poor accuracy The statistical correlations have fairly wide error bands
multitude of results For example for any given unit in the TVA system boiler efficiency can be evaluated by the individual correlation capacity correlation fuel type correlation and overall correlation Each of these correlations predicts a different effect of ash and moisture content Also the trends of ash and moisture content effects on boiler efficiency and gross heat rate predicted by the four studies are somewhat different particularly for ash
COAL PROPERTIES POWER STATION DATA
Total moisture Unit size Proximate analysis Transport Ultimate analysis Pulverisation
Sulphur Fly ash collection Calorific value Emission limits
HGI Ash disposal Ash fusion temperature
Ash resistivity
HEAT amp MASS BALANCE
(Combustion drying steam production flue gas loss FGD reheat)
STREAM FLOW RATES ampCOMPOSITION
(coal flue gas fly ash)
COAL TRANSPORT HANDLING STOCKPILING
POWER STATION OPERATIONS
(pulverisation electrostatic precipitation flue gas desulphurisation ash disposal)
NET POWER PRODUCTION
OPERATING COSTS
(centskWh as a function of fob coal price)
Figure 33 Outline of CIVEC model operation (Meyers and Atkinson 1991)
87
Computer models
732 Systems engineering analysis CCI Valuation of Energy Coals (CIVEC) Meyers and Atkinson (1991) have reported on the
Several advanced systems engineering-based models have development of ClVEC a techno-economic model by been developed in Australia Canada and the USA in the last Carbon Consulting International Australia to evaluate coals decade The models can be used to predict the overall on the basis of their cost effectiveness in terms of net power coal-related generation cost and become ultimately the generated when applied to a specific generating system The singular basis of comparison for all coals being considered valuation is based on a reference coal whose properties and taking into account the coals effect on availability power fob price are well established station capacity operating costs maintenance costs and power station performance as well as the unit price of the Details of the coals to be studied and specific power station coal In general the method used by systems engineering parameters are entered into the model Heat and mass models is to apply values to coals being considered with balances are determined using these parameters so that the respect to reference coals whose properties fob prices and annual coal requirement may be established The cost effect performance are well established of the coal properties are determined for different sections of
the power station (see Figure 33) The fob price of the study Many models are now available to run on personal coal is subsequently adjusted to give a power production cost computers whereas in the past large main frame systems equivalent to that obtained with the reference coal This were required to carry out the necessary computations model assumes that the overall power station design will be
suitable for the coals studied in terms of parameters such as Several illustrations that use these techniques based on fouling slagging and NOx emissions predictive calculations and comparison with the performance of reference coals and others that utilise a combination of An illustration of the use of ClVEC to assess a suite of these and statistical techniques are presented below In each typical steaming coals from New Zealand Australia and case the coal qualities used and assumptions made in the USA relative to a reference coal was reported by Meyers and model are highlighted Atkinson (1991) The reference coal used in the study was
Table 37 CIVEC coal specifications input (Meyers and Atkinson 1991)
Base Coal A Coal B Coal C CoalD
Total moisture as 80 140 150 100 90
Total ballast as 224 178 228 220 211
Proximate analysis ad Moisture 22 90 70 25 60 Ash 153 40 85 130 125 Volatile matter 258 370 280 315 335 Fixed carbon 567 500 565 530 480
Total sulphur ad 035 025 035 080 110
Heating value MJkg (gross ad) 280 276 281 289 285 MJkg (gross ar) 264 261 256 267 256
Ultimate analysis daf Carbon 839 800 835 840 830 Hydrogen 50 55 45 50 60 Nitrogen 16 20 20 20 15 Oxygen 91 125 96 82 84 Sulphur 04 00 04 08 11
Hardgrove grindability index 49 50 60 50
Freight rate U5$t 1000 1000 1000 1000 1000
total moisture (as) + Ash (as)
Coal quality data were obtained by averaging numerous coal qualities from various mines Coal A Typical New Zealand steaming Coal B Typical low ash low sulphur Australian steaming Coal C Typical high ash high sulphur Australian steaming Coa1D Typical high ash high sulphur US steaming
88
Computer models
Table 38 CIVEC power station operational parameters (Meyers and Atkinson 1991)
Reference coal Coal A Coal B Coal C Coal D
Quantity Mtly 1453 1483 1503 1448 1409 Boiler efficiency 889 880 885 884 878 Mill-capacity factor 093 127 120 108 105 - Power drawn MW 289 216 222 268 268 SOz in flue gas (ppm) 531 363 528 1168 1636
(gGJ) 231 153 214 498 703 Required ESP efficiency 998 993 996 998 998 Residue Mtly 0228 0068 0134 0219 0235
see Table 37 for coal types
Table 39 CIVEC factors contribution to utilisation value (Meyers and Atkinson 1991)
Basis Base coal at 4085 US$t fob standard plant 90 capacity
Coal type Cost variations US$1t
2 3 4 5 6 Utilisation value US$t fob
A -080 -025 180 270 250 070 4750 B -135 -040 100 150 040 030 4230 C 015 005 000 005 -395 -235 3480 D 135 040 -025 -035 -585 -300 3315
1 Variation in coal tonnage to provide same energy input 2 Difference in transport and handling costs 3 Maintenance costs (induding overheads) 4 Disposal costs (including overheads) 25 US$1t waste 5 FOD costs (including overheads and limestone 20 US$t)
6 Power consumption difference - mainly pulverisers and FOD
also an Australian Hunter Valley thennal coal which was well established with Japanese power utilities Table 37 summarises the properties for each coal used in the study The power station modelled was a 500 MW unit with a capacity factor of 90 Ash collection was implemented with a cold side ESP Each coal type was valued under these base conditions and also for a range of residue disposal costs (0-50 US$t) and 100 flue gas scrubbing with limestone costs set at 20 US$t Table 38 summarises the power station operational parameters for each coal studied Table 39 shows the utilisation value resulting from the model together with the component contributions to coal value It should be noted that highest utilisation value implies the best coal for the system For example coal A whilst requiring a small additional annual tonnage as a result of a slightly lower heating value with respect to the reference coal (see Table 39 - minor penalties indicated under factors 1 and 2) actually compares favourably with the base coal case due to its very low ash level (low residue disposal costs) and lower than reference sulphur level (low FGD costs) The authors of the report pointed out that unit availability and the handleability characteristics of each coal have not been taken into account and that the costs of domestic transport were not included in the study In this respect the model does not take into account 100 of available coal quality impacts on power station perfonnance but can be considered as an improved least cost type model as described in Section 71
COALBUY In 1976 Carolina Power And Light Company (CPampL) developed a program called COALBUY which they use to calculate the operating expense incurred by utilising coal of a given quality at a selected generating unit The program essentially evaluates a series of six potential penalties
boiler efficiency auxiliary power requirements coal handling equipment maintenance ash handling equipment maintenance ash storage cost replacement power due to load limitations
The program contains an extensive database for each CPampL coal-fired generating unit together with detailed specifications for a reference coal Each offered coal is compared with the reference when calculating potential operating penalties Any penalties are added to the offer price of the coal to obtain a total cost of burning it The program is also used to predict the extent to which a unit might be load-limited when burning off-specification coal Details utilised for each unit are given in Table 40 The operating data listed are taken from actual performance tests at a series of load levels
COALBUY is in fact a sub-routine of CPampL s EVAL
89
Computer models
Table 40 Model input output data - COALBUY (Corson 1988)
Developer Coal input Generating unit input Key output
Carolina Higher heating value Net unit heat rate Operating penalties Power amp Light Grindability Base boiler efficiency Total cost of coal ($IMBtu) USA Proximate analysis Estimated boiler radiation losses Load limitation on generating unit capacity
Total sulphur content Ambient air temperature Identification of system causing the load limitation Purchase price including Ambient air humidity ratio Operating characteristics of boiler fans with
transport Stack gas temperature reference to coal and purchased coal Standard deviation of the Unburned carbon in fly ash Boiler efficiency losses and related parameters
variation in higher Unburned carbon in bottom ash - boiler efficiency heating value Carbon dioxide and oxygen in the - auxiliary power requirement
boiler gases entering and leaving the - coal handling equipment maintenance air heater - ash handling equipment maintenance
Monthly unit demand profiles - ash storage cost - replacement power
The operating data listed above are taken from actual boiler tests at a series of load levels
Also includes escalation factors for database cost factors
program which was developed to maintain files on quotations a coal buyer in making a detailed assessment of cost and and purchase orders to select suppliers of spot-market coal performance impacts of using a candidate coal in his power and to plan the distribution of long-term and spot-market station Model input and output parameters are summarised purchases throughout CPampLs generating system each month in Table 41 (Corson 1988)
The system establishes the coal rank (based on ASTM D388 Coal Quality Advisor (CQA) guidelines) ash type and determines ash fouling and The CQA expert system was developed by a joint utility slagging characteristics based on empirical slagging and (Houston Lighting amp Power Company (lllampP)) and fouling indexes It compares the provided analysis values architectengineering company (Stone and Webster) team against those expected for the reference of coal and coal ash (Arora and others 1989) Its intended application is to assist Arora and others (1989) describe the specific functions in
Table 41 Model input output data - Coal Quality Advisor (CQA) (Arora and others 1989)
Developer Coal input Generating unit input Key output
Houston Lighting amp Power Stone amp Webster Engineering Corporation USA
Proximate analysis Higher heating value Ultimate analysis Sulphur forms Ash mineral analysis Ash fusion temperature Trace elements Equilibrium moisture Quartz content Coal size Coal cost (fob)
Pulveriser horse power input Number of mills in service Plant capacity factor PA temperature (OF) amp pressure (lbft2mill) Primary air to fuel ratio (lbairnbfue1 )
Plan area heat release rate actual (Btuh ft2 x 106)
Boiler efficiency () Approximate net heat rate (BtukWh) Limestone cost Total change in OampM costs ($y) Annual fuel flow (ty) Differential power costs at equivalent coal flow (ty)
Intermediate output variables Maximum mill capacity (th) Required coal flow (Pph) Coal flow per mill (th) Percent base mill Super heater gas velocity (ftsec) Reheater gas velocity (ftlsec) Air flow (lbh) Excess air () Fuel flow (Pph) from boiler calculations Annual fuel flow 075 capacity factor Gas temperature - out CF) Bottom ash flow (Pph) Fly ash flow (Pph) Volumetric heat release (Btuh x 106)
Furnace exit gas temperature (OF) Limestone usage rate (th) Unburned carbon (lbslOO lbs coal)
90
Computer models
greater detail than can be discussed here It should be noted that due to the lack of a suitable database the basis of OampM cost methods was a percentage of equipment capital costs for each major power station component
The model has been validated for HLampP use It has been reported to have been used for (Arora and others 1989)
blending of up to five coals to a specific mix or to achieve a specified quality for the blend (that is sulphur ash heating value) classifying the coal (blend) to permit assessment in various components of the power station determination of empirical slagging and fouling indices evaluating the required performance against the given limits for the major components of the power station determination of OampM costs and the net heat rate change for a candidate coal relative to a given base coal unit No 8 at HLampP Parish power station but it can be configured to enable evaluation of other coal-fired units in the HLampP system with minor changes
The impact assessment for each of the systems is classified by severity level and displayed to the user with appropriate recommendations
Coal Quality Engineering Analysis Model (CQEA) From 1963 to the mid-1970s NYSEG have used a coal evaluation program to determine bonuses and penalties on each parameter of the coal offered by suppliers (Mancini and
others 1988) In 1975 the company commenced a two-year coal quality study to develop a method of fitting the existing program to each of the five NYSEG generating stations The model approach was changed to combine generating station engineering data with coal analysis data in a workable package for fuel evaluation engineering and economic analyses The result is the CQEA which has been used by NYSEG since 1977
Table 42 summarises the coal input data generating unit data required and the key and intermediate output variables The CQEA is calibrated to each units characteristics The generating unit input data are reported to be recalibrated annually
An illustration of the capability of the CQEA is shown in Figure 34 It compares the overall production cost for five different coals burned in one unit (unit 5 of Figure 34) as calculated by CQEA If only delivered cost is used as a measure to purchase coal then coal 3 would be the lowest cost However the overall cost of coal 1 is about 80 ckWh lower than the overall cost of coal 3 Similarly it is shown that paying the highest cost for high-quality coal 2 compared to coal 1 is not overall economically beneficial Also if the choice were among coals 2 4 and 5 - which are almost equal - the best quality would be chosen knowing the results of the CQEA These results have been verified by actual experience of the above coals in the units discussed
The CQEA system is used by two different groups within
Table 42 Model input output data - Coal Quality Engineering Analysis (CQEA) (Mancini and others 1988)
Developer Coal input Generating unit input Key output
NYSEG Delivered price USA Heat content
Proximate analysis Sulphur Ash softening temperature Grindability
Maximum gross capacity Hours operating at peak and average power Station service power Turbine heat rate Forced draft fan inlet temperature Stack exit gas temperature Carbon in ash and ash as fly ash versus
bottom ash moisture added to ash for dust-free disposal
Excess combustion air Base pulveriser capacity Pulveriser capacity correction factors for
fineness and grindability Radiation amp unaccounted boiler loss Fuel oil rate for low volume coal Minimum volatiles in coal without ignition oil
Average gross generation Ash collection capacities fly ash
and bottom ash Ash and scrubber sludge disposal cost Flue gas desulphuriser removal
efficiency and OampM costs
Cost of coal and oil burned Ash disposal costs Maintenance costs for coal and ash handling equipment Scrubber OampM and waste disposal costs Replacement power cost Net output MWh Replacement power MWh
Intermediate output variables Boiler efficiency () Total station service power () Net station heat rate (B tukWh) Percent utilisation of capacity Total Btu fired in coal and oil
Additional system data Maintenance wage rate Replacement power demand and energy charge Fuel oil heating value and price
91
Computer models
D coal quality - related costs 16shy D delivered coal cost
14 c 3 ~ 12ifgt U5 0 100
u c 0
OJ 8 D 2 0shyD 6 (j)
iii ~ 4 a OJ
u 2
0 Coal 1
MJkg 256 ash 210 moisture 70 sulphur 21
Coal 2 Coal 3 Coal 4 CoalS
302 263 284 270 120 203 127 177 40 53 72 70 27 12 26 20
Figure 34 CQEA evaluation of the impact of different coals on overall production costs of one unit (Mancini and others 1987)
NYSEG These are the Perfonnance and Fuel Engineering group which maintains the CQEA calibration factors for each unit and the Fossil Fuel Supply group which uses the
BOILER bull subcritical PC bull supercritical PC bull parallelseries backpass bull flue gas recirculation
COAL PREPARATION bull 41 mill offerings bull vertical spindle mills bull exhauster mills bull other
r
BOnOM ASH SYSTEM bull wet system
- jet pumps - centrifugal pumps
COAL HANDLING bull rail truck bargeship conveyor unloading bull emergency and normal stockout bull stacker reclaimers lowering wells
other reclaim systems bull ring granulator hammermill crushers
CQEA as a tool for evaluating coal purchase offers from coal producers (Mancini and others 1987)
Coal Quality Impact Model (CQIM) In 1985 Black amp Veatch a US architect-engineering group and EPRI worked together to develop a comprehensive computer program for predicting coal quality impacts The result was the Coal Quality Impact Model (CQIM) As of the end of 1991 112 copies had been distributed to 72 different utilities and six different companies or agencies Black amp Veatch has also sold the program to eight companies including four outside of the US Four additional sales to non-EPRI member companies are in their last stages of negotiations This is the most widely used systemsshyengineering model in the world
The role of CQIM is to quantify both perfonnance and cost impacts associated with changes in coal quality (Evans 1991 Stallard and Mehta 1991) The equipment types modelled by CQIM are summarised in Figure 35 As described earlier for other models CQIM evaluates alternative coals by comparing them with a reference or current coal supply It is also designed to consider station-specific design and operation characteristics on a component-by-component basis as well as the unit as a whole This allows the CQIM to identify potential system limitations (sources of derate)
The effort required to collect CQIM input data varies according to the background of the user the availability of data and the purpose of the evaluation CQIM contains a
AIR HEATERS bull bisectors bull trisectors
PARTICULATE REMOVAL bull hot ESP bull cold ESP bull fabric filter
1 FLY ASH HANDLING bull pressurisedbull vacuum
FD FANS bull axial bull centrifugal
~
~ PA FANS bull axial bull centrifugal bull coldhot bull exhuasters
Figure 35 Equipment types modelled by CQIM (Galluzzo and others 1987)
ID FANS bull axial bull centrifugal
SRUBBER ADDITIVE bull limestone bull lime bull none
to stack
t GAS REHEAT bull 5 alternatives
f---shy FGD SYSTEM bull wet limestone bull spray dryer --- bull none
WASTE DISPOSAL bull stabilised waste bull fixated waste bull evaporation ponds bull other
92
Computer models
Table 43 Model input output data - Coal Quality Impact Model (CQIM) (Stallard and others 1988 Stallard and Mehta 1991)
Developer Coal input Generating unit input Key output
EPRI amp Heating value Black amp Veach Ultimate analysis USA Moisture content
Ash content Chlorine content Sodium content in ash HOI Ash fusion temperatures Ash analysis Fuel cost Transport cost
Unit size (MW net) Capacity factor () Net power level Auxiliary power requirements Auxiliary equipment specifications
and capacities Hours of operation Net turbine heat rate (BtukWh) Excess air level () Boiler losses Boiler dimensions Soot blowing details Tube bank configurations Maximum heat input per plan area (MBtuJhft2)
Design FEGT Maximum allowable flue gas velocity Economiser
Economic data Replacement energy cost ($millkWh) Limestone cost ($ton) Salarymaintenance rate ($person-year)
Discount rate Replacement power cost Limestonellime cost Total annual fuel related costs Transport costs Escalation rates Overall unit performance data - slagging fouling and erosion potentials - equipment performance and derate info - maintenance availability data - calculated derate by system - generation cost summary page Sensitivity analysis Comparison tables Error warnings
feature for supplementing data provided by the user This default information is based on the data entered by the user the overall power station configuration the characteristics of the design coal and established equipment design practices Since default data can be substituted for most missing data the program can be run with limited input Of course the more actual data used the more comprehensive the predictions
Table 43 illustrates the type of data required for conducting an initial screening evaluation of coal quality CQIM contains programs for translating each major performance impact into a discrete cost component
During the course of the development of the CQIM model validation was carried out by means of a host utility program Initially 12 utilities worked with EPRI to develop case studies to validate the CQIM equipment performance models The CQIM performance and cost predictions were compared with historical data and actual utility operating experience Any discrepancies were used to modify the program modules and improve the overall predictive capability of the CQIM The case studies covered a wide range of US unit designs and US coals With the sale of the CQIM to international utilities this has prompted the development of CQIM International which will have facilities to convert input data utilising SI units
There are several examples of literature describing the application and validation of the CQIM (Galluzzo and others 1987 Boushka 1988 Stallard and others 1989 Cox and others 1990 Kehoe and others 1990 Afonso and Molino 1991 Giovanni and others 1991 Vitta and others 1991)
Coal Quality Expert (CQE) The US Department of Energy (DOE) selected the
development of the CQE in Round 1 of the Clean Coal Technology program The project initiated in 1990 and scheduled for completion in August 1994 will cost $217 million
The CQE computer system is designed to give utilities a tool that will predict the total cost of impact of coal quality on boiler performance maintenance operational costs and emissions
Figure 36 shows the major components of the CQE system The foundation for the CQE is EPRIs CQIM (see section on CQIM) More than 20 software models and databases including the CQIM a flue gas desulphurisation model a coal cleaning model a transport model and a new power station construction model will be integrated into a single tool to enable planners and engineers to examine the cost and effects of coal quality on each facet of power generation from the mine to the stack The expert system is intended to evaluate numerous options including various qualities of coal available transport methods and alternative emissions control strategies to determine the least expensive emission control strategy for a given power station
It is intended that the CQE will include cost estimating models for new and retrofit coal cleaning processes power production equipment and emissions control systems Individual models are to be made available as they are developed The first of these models the Acid Rain Advisor (ARA) has already been released (CQ Inc 1992) The ARA developed primarily to assist users in managing US Clean Air Act compliance evaluations can be used to quantify costs and emissions allowance needs for potential utility compliance strategies
A core part of the CQE program is extensive data gathering
93
Computer models
ENGINEERING AND ECONOMIC MODELS
bull Coal Quality Impact Model
bull coal cleaning cost model
bull flue gas desulphurisation
bull NOx emissions
ADVANCED USER INTERFACE
Integrated report and graphic capabilities
CQE ASSISTANCE Integrated applications
bull strategic planning
bull plant engineering
bull fuel procurement
bull environmental strategies
bull acid rain advisor
Figure 36 Major components of the CQE system (Evans 1991)
and analysis to validate the models and it is one of the largest efforts ever attempted to link pre-combustion combustion and post-combustion technologies to solve power station emission problems (Evans 1991) Samples of the various coals identified for the project are being collected at mines commercial cleaning plants and the six host power stations Extensive measurements of the performance of all ancillary equipment are taken during the field tests Moreover the project will generate considerable data from laboratory bench- and pilot-scale combustion tests using the same coals All the data will be used to develop and validate the CQE models including those that predict mill wear slagging and fouling precipitator performance flue gas particulate removal NOx formation and the flue gas desulphurisation performance
IMPACT Ugursal and others (1990) reported the development of a computer-based techno-economic model that can predict the impact of coal quality and other key variables on the busbar cost of electricity generated by new power stations The IMPACT model has been structured to focus on four major cost sectors of the coal-to-electricity chain (see Figure 1) This includes transport power station post-combustion particulate and SOz emission controls and residue disposal
Table 44 Ranges of selected coal-ash combustibility parameter that predict approximate classification of CF values (Ugursal and others 1990)
Incombustibility index RI1 Classification of CF values
lt21 21--43 43-75 gt75
94
low laquo017) medium (017-D34) high (034-D47) severe (gt047)
INFORMATION AND DATA BANKS
bull fLe1 sources
bull plant specifications
bull transport rates
bull waste handling
bull coal quality information systems
The impact of coal characteristics on power station performance is quantified in IMPACT as follows
steam cycle heat rate calculation assumes that the boiler is designed for the given coal and operates at design load boiler efficiency is evaluated using the heat loss method (see Section 632) A notable additional approach adopted to evaluate unburnt combustible losses in the calculation of efficiency includes an incombustible parameter Rh which is inversely proportional to the base-to-acid ratio of coal ash Rh is directly proportional to the amount of unburnt combustibles in the fly ash The amount of unburnt combustibles is expressed by CF and can be defined as
CF = [(flyash combustible$ (lb of fly ash formed)] (lb of coal feed)
The approximate ranges of CF values that corresponds to the incombustibility parameter ranges are given in Table 44 Once CF is determined from Table 44 the percentage of combustibles in the coal feed that is lost in the flue gas can be determined from
CFx 100 coal feed combustIbles = n1 1 d b tmiddotbl70coa lee com us 1 es
where the percentage of coal feed combustibles = 100 - ash - moisture with the ash and moisture content determined from proximate analysis of the coal
IMPACT utilises empirical correlations (developed by regression of data published by Bechtel Power Corporation (Holstein 1981)) between auxiliary power consumption and the sum of the ash and moisture contents of the coal for both subcritical and supercritical units (Ugursal and others 1990) availability values of 80 are assumed to apply to new
Computer models
Table 45 Model input output data - IMPACT (Ugursal and others 1990)
Developer Coal input Generating unit input Key output
University of Ultimate analysis () Plant capacity (MW) Levalised busbar cost of electricity Nova Scotia Ash content Unit type Annual operational cost Canada Ash composition () Steam generator efficiency () Capital costs
Heating value Steam cycle heat rate (BtulkWh) Annual coal consumption Cost of coal Flue gas exit temperature
Average load Equivalent availability Auxiliary equipment specifications Cost of limestone
power stations This assumption is adopted due to the lack of information available quantifying the impact of coal quality on the availability of power stations coal consumption and coal bum rate of a given power station are calculated using an energy balance based on the results obtained from the parameters above and the specified annual generation capacity annual ash and S02 generation are determined by a mass balance on the annual coal consumption rate and the ash and sulphur contents of the coal
Although this model has yet to be fully validated the authors carried out sensitivity analyses for a number of coals with various levels of ash and sulphur (Ugursal and others 1990) on a representative power station with two 500 MW units The input and output parameters of the coals and power station for the model are summarised in Table 45 Overall from the study it was concluded that the capital and operating costs of most of the sectors of the coal-to-electricity chain increase with increasing ash content of the coal fIred The authors emphasised that the findings apply for the particular conditions of the case the results might be quite different under other site specific conditions
Coal quality impact study model (CQI) Kemeny (1988) reported on work performed to develop a method of analysis using a combination of statistical and engineering methods which could be applied to any power station operating system The method adopted also developed a model that computes a power stations total coal-related generation cost on a specific coal It was developed initially for an Italian power station Fusina 3 to determine the economics of burning four different coals at the station
The method adopted for the calculation of availability assumed that planned outages were unaffected by coal quality whereas their effects on forced outages was the sole influence on availability Because of the random nature of equipment failures an analysis of forced outage rates was carried out statistically Historical coal usage data were correlated against historical outage data to see if there was a coal quality relationship For Fusina 3 power station the coal type was changed so frequently that data from a single unit were considered suffIcient for such a study The results of the availability analysis are shown graphically in Figure 37 A low correlation coefficient of 0447 was observed for the relationship indicating that there was a fairly high probability
that the apparent correlation between forced outages and ash was due to random scatter of data points and not to any cause-and-effect relationship In addition the large negative y-axis indicated that the regression equation may not have been accurate across the full range of ash values In light of the results demonstrated by this study it would appear that it would be more prudent not to include the results of the availability analysis in the coal quality impact model However the investigators believed that the regression analysis conformed to engineering expectations and because of the probabilistic nature of forced outages it was quite unlikely that with the amount of data available outages would correlate very strongly with coal quality Therefore the results of the availability analysis were included in this coal quality impact model
Coal-related operating costs accounted for in the model cover any cost not specifically covered by fuel costs At Fusina 3 for example these areas included the cost of sulphur for S03 conditioning and the cost of ash disposal Other areas might include the cost of fuel additives scrubber related costs cost of additional equipment The effects of coal quality on the cost of routine and emergency maintenance at the power station is most easily measured statistically in a similar way in which forced outages were correlated
01000
~ L 800 (j)
~
L0 600 81 Q) 0 OJ co 5 400 -0 Q)
0 0
~4() 82 00 200 u
83 o
40 60 80 100
Ash throughput kty
o not included in regression
Figure 37 Correlations of forced outage hours against ash throughput using the cal model (Kemeny 1988)
95
Computer models
Table 46 Assessment of four coals for Fusina unit 3 using the CQI model (Kemeny 1988)
Coals
South Africa Polish American
Low ash High ash
Coal characteristics High heating value MJkg [Btulb] Ash content Sulphur Moisture content Carbon content Ash resistivity ohmcm x E13
Coal cost $GJ [$MMBtu]
Results from model Boiler efficiency Availability US$y Capacity - ESP limit - Auxiliary power
Fuel costs - coal - supplementary
OampM costs - maintenance - flue gas conditioning - ash disposal
Totals
2625 [11291] 1339 038 830
6474 375
153 [161]
8890 3905122
1764549 3765822
25565882 3450848
2806626 24916
458876
4172640
2707 [11639] 1226 063 780
6796 500
163 [172]
8889 3204389
1514442 3817118
27980093 3059766
2538408 9051
330618
424453886
3012 [12950] 742 081 720
7433 500
177 [187]
8931 336355
357460 4033183
33180022 1625800
1440618 o
175209
40798228
2830 [12173] 1152 075 710
7033 500
177 [187]
8886
2459658
2325523 o
228820
44008125
Without going into power station details as this is described elsewhere (Kemeny 1988) an illustration of the type of results produced by the model of the comparison of four coals from Poland South Africa and the USA is given in Table 46
As in the case of other similar models the value of the total coal-related production cost in the cost summary is just an indicator it is neither a calculation nor a prediction of the actual generating cost The number in this model does not include costs such as maintenance costs for non-coal-related systems However it can be used for comparative purposes Quite simply the coal which gives the lowest production cost is the most economical
More briefly other models that have been reported in the literature include
Waters (1987) reported the development of a computerised mathematical model known as ECUMEC Data taken from the model subroutines are used to calculate the power cost for example at the busbar including the cost of coal Once again the method used to assign an economic value to a coal is to select a base coal or yardstick coal to which a coal price (fob) can be ascribed The equivalent value of another coal is that price (fob) which gives the same power production cost as the base coal Waters (1987) demonstrated the
capability of the model by considering the effect of some coal properties such as sulphur ash and moisture content on the equivalent coal value in a 500 MW power station The base coal was a 15 ash Australian Hunter Valley coal The coal price (fob) was shown to be very dependent upon ash with a 5 ash coal worth approximately US$745 more per tonne than a 15 ash coal (based on 1987 prices) The effect of moisture on equivalent coal price is similar to ash but not as marked It was shown using the model that a 05 increase in sulphur content had a much greater effect on coal value than a 5 increase in ash content This was because the capital and operating costs associated with FGD to meet air quality requirements were very high a program developed by Southern Company Services USA to help estimate the benefits from cleaning coals The constituents of coal that were found to affect the cost factors were primarily ash moisture sulphur and carbon content (Blake 1988) the Consol Coal QualityPower Cost model which was used by Deiuliis and others (1991) to evaluate the performance of six US regional coals in a typical 500 MW pulverised coal-fired unit The study was focused on developing a cleanliness factor for model relating to heat flux and soot blower effectiveness data obtained from pilot combustion tests the Coal Utilisation Cost Model which utilises a three-step modelling approach-statistical analysis of
96
Computer models
historical data (source NERC) development of an engineering algorithms and evaluated cost calculations based on the algorithm results (Nadgauda and Hathaway 1990)
733 Integrated site models
With further advancements in computer and sensor technology in the last ten years integrated site models are being developed that allow the integration of information from unit models systems perfonnance and other models directly into the control room data system These programs allow the continuous monitoring of for example selected coal properties such as ash moisture and sulphur furnace and convective pass deposits and can define overall heat rates based on these continuous measurements taken from the unit (Elliott 1991) The diagnostics packages can also include a routine for predicting the implementation and impact of operating practices on heat rate (Nurick 1988 Alder and others 1992)
Smith (1991) and Reinschmidt (1991) have reviewed the wider application of integrated control systems from individual component control to full automation of the power
Coal quality COAL MANAGEMENT
as a function MODULEof time at mills
Coal quality collection and assessment
station and the new computer technologies that are being applied such as neural network approaches that processes input data without identification of particular algorithms connecting the output results with the input data and fuzzy logic An example of this application is the C-QUEL system
Coal quality evaluation system (C-QUEL) Mitas and others (1991) have reported on the current development of a comprehensive software system C-QUEL that will allow utilities to use on-line analysers to try to solve or mitigate existing coal-related problems This will be accomplished by the C-QUEL system by providing information about coal quality before it is burned predict potential effects on operation and provide recommendations of control actions which can be taken to adjust coal quality andor improve power station response to quality changes The use of on-line coal analysers has been reviewed by Makansi (1989) and Kirchner (1991)
C-QUEL is a suite of computer programs which can be used as a basis for control of various processes in a power station Figure 38 shows a schematic of the structure of the system Appropriate control actions will be determined based on a wide variety of information gathered by the operator on-line
ON-LINE PERFORMANCE MONITORING SYSTEM
Equipment status Current performance
Load demand
ON-LINE COAL ANALYSER
SUPERVISORY CONTROL MODULE
COAL QUALITY CONTROLACTION
RELATIONSHIP MODULES
Coal data logging
Monitor CQ and equipment modify operation to
meet goals
DATA ARCHIVE AND TRENDING
USER INTERFACE
EPRI COAL QUALITY IMPACT MODEL
Annunciation Predicted performance Interactive dialogue Information retrieval
Figure 38 Schematic showing the structure of the e-aUEL system (Mitas and others 1991)
97
Computer models
coal analyser real-time station data on-line performance calculations equipment performance predictions and coal flow models The EPRI Coal Quality Impact Model (CQIM) will be incorporated into C-QUEL to provide the prediction capability for the performance of all major power station systems directly impacted by coal quality Operational strategies as a result of expected unit performance will be evaluated by C-QUEL and provided to the operator These strategies will take into account the current and future unit generating requirements as well as cost information associated with each possible action Specific control recommendations and supporting information are presented to the power station operators
Figure 39 shows a simplified case as an example of the use of C-QUEL in which the primary goal is to maximise electrical generation from a base load power station Figure 39a depicts the sequence of events that can be expected at a particular point in time The operator is unaware that a change in coal quality has occurred until a
a) Without C-QUEL
Ash and moisture content have
increased
drop in load is detected In the second scenario Figure 39b the goal of maximising electrical production has been fed into the C-QUEL supervisory module Since decreased mill capacity will have a direct effect on generation this information together with a recommended course of action is given to the operator and allows him enough time to make the proposed adjustments before load production is affected Because of detection of the higher moisture and ash content of the coal supply by the on-line coal analyser a decrease in mill capacity was predicted To prevent any load reduction the operator would be instructed by the system to bring another mill into operation
The project team for development of the C-QUEL system consists of two host US utilities - Oklahoma Gas and Electric (OGampE) and Pennsylvania Electric (penelec) two engineering contractors - Black amp Veatch and Praxis Engineers and EPRI Demonstration of the system will take place at OGampEs Muskogee power station and the Penelec-operated Conemaugh plant OGampEs Muskogee
I I
Only two pulverisers are on-line consistent with the requirements
of the previous coal quality
I I I L_
On
Electrical production has
dropped
Operator determines decreased pulveriser capacity has caused the load drop and brings another pulveriser on-line
b) With C-QUEL Pulveriser module predicts Other controlaction modules decreased pulveriser capacity
Analyser detects Iincrease in coal ash and moisture conten t I
III I +0bull
Goalmaximise output
-
1 Supervisory module evaluates this information relative to operational
t--- goals and constraints and information from other modules
I
A message notifies the
Pulveriser 2
operator of potential generation loss and the need for an additional pulveriser
1-~e~C 1
I I L_
Operator brings another pulveriser on-line before the high ashhigh moisture coal is fed to the fuel preparation system Maximum electrical production is successfully maintained
Figure 39 Comparison of the operations with and without the use of e-aUEL (Mitas and others 1991)
98
power station fires primarily western low-sulphur coal that is currently blended with more expensive higher sulphur Oklahoma coal which also has a higher heating value on a 10 by heating value basis The station must also meet a strict SOz emission limit OGampE has installed an on-line analyser - PGNAA elemental analyser - that will provide data to assist in blending and feeding An elemental analyser has also been installed at the Conemaugh power station Initial data gathering will focus on the Muskogee power station (Mitas and others 1991)
Couch (1991) has also reviewed the influence of integrated computer control and modelling on coal preparation plant
74 Comments The studies described above demonstrate the feasibility of developing various quantitative relationships which are essential for optimum planning and operation of generating units Table 47 summarises the capabilities of the models described in this chapter Many of the results are based on data and methodologies which still require further refinement
When considering the two major techniques for assessing power station performance that is statistical and engineering analysis modelling a weak link with both approaches is within the coal specification parameters used in the correlations
Table 47 Summary of model types and capabilities
Computer models
For the purpose of selecting an economically attractive coal it is important to determine heat rate effects due to coal quality as accurately as possible In their review of statistical and engineering based relationships Folsom and others (1986b) did not believe that the correlations from statistical studies were close enough to be useful for this purpose Consequently the use of engineering correlations and experience to evaluate heat rate impacts was highlighted as the preferred procedure
Engineering based models have their critics also Many utilities apply least cost models for purchasing coals and component models and some acknowledge the benefits of expert unit or integrated models Others remain sceptical over the capability of devising a truly representative model of the coal combustion process Some of the reasons given for this scepticism include
the present methods that describe coal properties require substantial refinement for use in the models as they are not adequate for predictingaccounting for unit performance a belief that coal blending solutions based on pragmatism and simple empirical methods are more appropriate providing a here-and-now solution a belief that processes such as fouling and slagging and mill performance cannot be accurately modelled whilst the basic mechanisms are not clearly understood
Model type Modelling capabilities Developed by Application Comments Model name Assessmentcountry
Heat Capacity Avail- Maintenance Other of origin
rate costs ability costs
Least cost coal coal blend model
Least cost fuel system total fuel cost architectengineer buyer manualAustralia ICVM total fuel cost research organisation buyer manualAustralia Steam coal blending plan - total fuel cost supplier buyer manuallUSA Perfectblend total fuel cost research organisation buyer manuallUSA
Single component model Boiler models --I --I research organisation operator computerintershyand others utilityequip manufacturer national
Unit model Statistical
TVA study --I --I --I research organisationutility operator manualUSA EPR study --I --I --I research organisationutility operator manuallUSA NERA srudy --I --I research organisation operator manuallUSA PC study --I --I --I capital costs utility operator manuallUSA
Engineering ClVEC --I --I estimated total fuel costs research organisation buyer computerAustralia COALBUY --I --I --I --I total fuel costs utility buyer computerlUSA CQA --I --I --I estimated total fuel costs architect engineerutility buyeroperator computerlUSA CQEA --I --I --I coalash handling total fuel costs utility buyeroperator manuallUSA CQIM --I --I --I --I total fuel costs architect engineerutility supplierlbuyer computerlUSAUK
operator CQE --I --I --I --I total fuel costs architect engineerutility buyeroperator computerlUSA IMPACT --I --I --I --I total fuel costs research organisation buyeroperator computerCanada CQI --I --I --I statistical evaluation total fuel costs research organisationutility buyersoperator computerlUSA
Site model C-QUEL --I --I --I --I total fuel costs architect engineerutility operator computerlUSA
total fuel costs for engineering models refers to the total fuel-related production costs in terms of the price of electricity at the busbar
99
Computer models
new advanced boiler configurations such as low NOx
combustion regimes increase the complexity of boiler models many of the models have not been applied to a wide range of international coals and therefore have not received adequate validation
The analysis approach adopted by many of the unit models available can vary in complexity such that a form of quantitative predictability can be produced to a reasonable or to what may be deemed as a high level The lower level of prediction capability has been perceived by critics to produce too general a fmding In contrast the higher level may require more detailed unit specific information than a utility may have readily available such that special provisions would have to be made in order to collect the necessary data (Johnson and others 1991) This is known to be time consuming and is perceived by some operators to detract from the main utility priority that is to produce electricity Others believe that the models incorporate performance measurement errors that may compound to reduce the effectiveness of the model and make it only useful for comparing coals that show a wide range of coal property values
Many of the model descriptions have cited the beneficial role of the model in fuels purchasing It is considered that when models are used in such a manner they could become an improved means of communication between supplier buyer and user as they can ultimately aid the purchase of an economical coal of adequate quality for a particular power station The advantages of having the ability to assign an overall cost to a coal particularly in terms of its impact on component and overall power station performance could prove to be of technical and financial benefit to the utility in helping to justify supplier buyer or operator policies such as coal cleaning blending power station retrofitting or purchase of replacement energy to the advantage of the utility
In general however operators remain reluctant to move toward a predictive approach to coal quality impacts in preference to reliance on post mortem type remedies In the future integrated computer models such as C-QUEL may prove more acceptable when they can provide real time cause and effect information and advice on how to remedy problem situations as soon as they occur and can be seen to rely on dependable input data
100
8 Conclusions
Fuels purchasing and management presents an important opportunity for utilities to control costs It is also recognised that final judgements on coal selection often require a trade-off between these costs and qualitative factors such as diversity of supply reliability control of emissions for environmental reasons balance of trade and currency availabilities The contribution of coal to the cost of electricity extends far beyond the purchase price of the fuel Over the last fifteen years it has become generally accepted by coal-fired power station operators that the capacity availability and cost of operation of each individual component of the power station are materially affected by the quality of coal fed to it To generate power at least cost it is important to evaluate the overall total cost associated with each coal for a particular power station
The principal coal properties that were found to cause greatest concern to operators include
ash content and composition heating value sulphur content moisture content grindability volatile matter content
Enforcement of environmental legislation has resulted in the elevation of total sulphur content to a key position in the specification of coal along with total ash moisture and heating value Table 48 summarises the effects of these properties and other coal characteristics that are used as coal specifications for combustion on component and overall power station performance
Little has changed over the years in the way that coal is assessed and selected for combustion Operators continue to use quality parameters in their specifications that were mostly developed for coal using processes other than direct combustion Whilst many empirical relationships have been
established between coal specifications and certain component and plant performance indicators the coal characterisation tests themselves have been shown to have serious shortcomings and in some cases do not adequately reflect the process conditions For example
coal composition measurements cannot be used to explain the problems of dusting flowability freezing and oxidation that can occur during coal handling mill capacities for lower rank coals or coal blends are difficult to evaluate using existing grindability correlations combustion characteristics including flame shape stability and char burnout cannot be evaluated accurately based on standard coal composition tests the correlations that have been developed for slagging and fouling are inadequate there is considerable disagreement as to the best method of measuring fly ash resistivity there is no correlation between coal composition and fly ash fineness there is no adequate means to predict NOx emissions
Because the procurement specifications are based on tests which do not relate well to actual practice there is still a need for expensive large scale test burns to confirm suitability
Coal quality affects a wide variety of plant components and ultimately the overall station performance that is total system capacity availability maintenance costs substitute fuel costs plant replacement costs and the final cost of electricity There is a growing awareness that coal suppliers should take more responsibility with respect to determining the quality of coal made available on the market Suppliers that best understand the consumers fuel quality concerns prove to be the most successful in securing contracts and maintaining market share
Plant operators and other organisations are working to
101
Conclusions
Table 48 Summarymiddot of the impacts of coal quality on power station performance
Coal specification Power station component performance Overall power station performance
Environmental control
l u l
tl a
B
amp ~ o(l co S c r
~
~
E l
aI
0
~ C
co
~ B en
c= E co c E c ~
c= E 5 0 co c ~
U - 0 U
c au
~ u
lt5i if
c= ~ ~ amp 0 j c a u
6 en
c= sect l 0 0 1sect a u gtlt
0 Z
1(j at
4-lt a
E c
l 0
tl sect 0 ~ l
QI
0 ~
U
B ~ lta r
c= E S 0
U
sect c B c
ca ~
~ ~ ca gtlt
Ash content increase decrease
Heating value increase decrease
Sulphur content increase decrease
Moisture increase decrease
Hardgrove grindability index increase decrease
Volatile matter increase decrease
Ash fusion temperature increase decrease
Ash resistivity increase decrease
Sodium content increase decrease
Chlorine content increase decrease
Fuel ratio increase decrease
Free swelling index increase decrease
Size consist increase decrease
compiled from observations from literature and the lEA Coal Research survey worsened (or decreased for components marked ) improved (or increased for components marked )
102
improve their understanding of how their equipment or systems respond to particular coals and coal blends but the lack of data for appropriate direct correlations of plant performance and coal behaviour has hindered the development of true prediction capability Until these relationships have been developed and proven respecting differences in boiler design coal buyers will continue to operate at a disadvantage when selecting new sources of coal
With the advances that have been made in computer technology there has been some success in the development of computer models that demonstrate the feasibility of developing various quantitative relationships for optimum planning and operation of generating units Many utilities use least cost models for purchasing coals that have no performance prediction capability Many use component models that supply fundamental data of plant component performance There is a growing number of utilities that are adopting expert unit or integrated models that are being developed Others have shown scepticism over the capability of devising a truly representative model of a coal combustion plant for reasons that include the following
a belief that coal blending solutions based on pragmatism and simple empirical methods are more appropriate providing a here-and-now solution a belief that many of the coal quality impacts cannot be accurately modelled as the basic mechanisms are still not fully understood new advanced boiler configurations such as low NOx
combustion regimes increase the complexity of boiler models many of the models have not been applied to a wide range of international coals and therefore have not received adequate validation the present methods that describe coal properties require substantial refinement as used in the models as they have been found to be inadequate in many cases for predictingaccounting for unit performance
Many of the shortcomings in the traditional coal characterisation tests that form the basis for specifications for
Conclusions
combustion have been exposed by the efforts to develop computer models and their improved data processing Prior to their application manual comparisons provided only limited indications of coal behaviour and in many cases precluded the ability to attach a price to a change in performance as a result of a change in coal quality Development of the models has also initiated extensive validation exercises to acquire the necessary performance data In addition coal characterisation tests are being reassessed It is recognised that an overly conservative approach to the development and adoption of new techniques as characterisation tests which may more realistically reflect the conditions extant to coal combustion has also hindered progress into acquiring true predictive capability
Specific needs that have been identified during the course of this review include
the need to develop an internationally acceptable method(s) of defining coal characteristics so plant performance can be predicted more effectively specific relationships between boiler performance in particular for advanced boiler configurations such as low NOx combustion regimes and coal quality need to be developed For example the specific impact of sulphur chlorine sodium overall ash content and coal rank (or reactivity) on carbon burnout slagging fouling corrosion and abrasion all need to be established economic parameters to measure the impact of plant performance on the cost of electricity need to be established and agreed upon in the electric utility industry The accounting systems of many utilities are not designed to easily identify the costs associated with coal quality impacts These organisations need to review their methods particularly if they intend to take advantage of new developing tools that are available such as expert computer models
Successful resolution of these issues is fundamental to achieving optimum use of coal as pulverised fuel in utility power stations
103
9 References
Abbott M F Bilonick R A (1992) Applied heat flux and soot blower effectiveness measurements in the CONSOL pilot and research combustors In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast R USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 471-497 (1992) Afonso R F Molino N M (1991) Compliance coal and low volatile bituminous coal testing at New England power In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 421-436 (JulI991) Ainsworth C C Rai D (1987) Chemical characterization of fossil fuel combustion wastes EPRI-EA-5321 Palo Alto CA USA EPRI Technical Information Services 136 pp (Sep 1987) Akers D J Norton G A Buttermore W H Markuszewski R (1989) Trace elements in coal In Trace elements in coal and coal wastes EPRI-GS-6575 Palo Alto CA USA EPRI Technical Information Services pp 21-28 (Dec 1989) Alder G Klein K Rettberg L (1992) Optimization of automated sootblowing through on-line boiler heat balance modeling In Power-Gen 91 Tampa R USA 4-6 Dec 1991 Houston TX USA PennWell Conferences and Exhibitions pp 1863-1881 (1992) Allman W P (1987) Steam coal blending planning and economic analysis facilitated by computer-generated tables Journal of Coal Quality 6 (1) 19-22 (Jan 1987) Allman W P (1991) A cost-minimization planning model for the coal sourcingtransport network problem emphasizing environmental emission restrictions Energy Systems and Policy 15 (1) 65-73 (Jan-Mar 1991) Anson D (1988) Interpretation and use of empirical slagging criteria In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 181-1101 (1988) Arnold B J (1988) Workshop on defining coal handleability
its cost impact and control Palo Alto CA USA EPRI Technical Information Services 128 pp (Nov 1988) Arnold B J (1991) Effect of chemical and physical coal properties on handling behaviour Mining Engineering 43 (2) 228-231 (Feb 1991) Arnold B J OConnor D C (1992) The effect of coal quality on coal handling Paper presented at Impact of coal quality on power plant peljormance La Jolla CA USA 25-27 Aug 1992 Arnold P C (1990) Storage systems for coal the requirement for implementation of modern design techniques In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 40-46 (Jun 1990) Arora B R Racine J P Sirois R H Finn G A Hanna R S Kern E E Buffinton A L (1989) Coal quality advisor for coal buyer Paper presented at Expert systems applications for the electric power industry Orlando R USA 5-8 Jun 1989 Babcock amp Wilcox (1978) Steam its generation and use (39th edition) New York NY USA Babcock amp Wilcox Company vp (1978) Bailey J G Tate A Diessel C F K Wall T F (1990) A char morphology system with applications to coal combustion Fuel 69 (2) 225-239 (Feb 1990) Baker J W Bennett P Conroy A Naylor P Smith G B (1987) Utilization characteristics of Australian steaming coals in overseas power stations In Coal Power 87 The AUSIMM annual conference in association with the Mining and Metallurgical Institute ofJapan (MMlJ) Newcastle NSW Australia May 1987 Parkville Vic Australia The Australasian Institute of Mining and Metallurgy pp 303-311 (May 1987) Baker J W Holcombe D (1988a) Use of the drift velocity apparatus to determine electrostatic precipitation performance In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp N13-NI6 (1988)
104
References
Baker J W Holcombe D (1988b) Electrostatic precipitations and fabric collection In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp L121-L1239 (1988) Balling L Hein D (1989) DeNOx catalytic converters for various types of furnaces and fuels - development testing operation In 1989 Symposium on stationary combustion nitrogen oxide control San Francisco CA USA 6-9 Mar 1989 EPRI-GS-6423-vol 2 Palo Alto CA USA EPRI Technical Infonnation Services vol 2 pp 7A27-7A40 (JuI1989) Barrett R E (1990) Designing boilers to avoid slagging fouling Power 134 (2) 41-45 (Feb 1990) Barrett R E Holt E C Jr Mack G A Frank R L (1983) Power plant perfonnance Assessing the impact of coal quality In SME-AIME annual meeting Atlanta GA USA 6-10 Mar 1983 Littleton CO USA Society of Mining Engineers of AIME pp 1-12 (Mar 1983) Barrett R E Mack G A Holt E C Jr (1982) Examining relationships between coal characteristics and the perfonnance of IVA power plants TVA10PIEDT-8312 Columbus OH USA Batelle-Columbus 254 pp (Sep 1982) Barrett R E Tuckfield R C (1988) Correlation of slaggingfouling from utility operating data In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 163-180 (1988) Bauver W P Bianca J D Fishburn J D (1984) Characterization of erosion of heat transfer tubes in coal fired power plants ASME Paper 84-JPGC-F4-3 New York NY USA American Society of Mechanical Engineers vp (1984) Baxter L L (1992) Combustion model predicts properties of coal ash deposits Sandia Science News 27 (6) 4 (Jun 1992) Beer J M SarorllD A F Barta L E (1992) From properties of coal mineral matter to deposition tendencies of fly ash - a modelling route Journal of the Institute of Energy 65 (462) 55-62 (Mar 1992) Behnam-Guilani K Hickey G L Hipple M J (1991) Statistical models for predicting coal-fired generating unit costs and performance Proceedings of the American Power Conference 53 888-892 (1991) Bend S L (1989) Coal characterisation and combustion PhD Thesis Newcastle upon Tyne UK University of Newcastle upon Tyne 189 pp (Nov 1989) Bennett R Fogel W Aloia P (1988) Wet fuel handling A program to minimize plugging In Defining coal handleability Its cost impact and control Lexington KY USA 30 Apr-l May 1987 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Information Services pp 41-410 (Nov 1988) Benson S A Steadman E N Kalmanovitch D P (1988) Studies of the fonnation of alkali and alkaline earth aluminosilicates during coal combustion using a laboratory scale furnace In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 31-312 (1988) Berkowitz N (1985) The methods of coal chemistry In The chemistry of coal Amsterdam the Netherlands Elsevier Science Publishers pp 33-102 (1985)
Berkowitz N (1989) Atmospheric oxidation of coal In Sample selection aging and reactivity of coal New York NY USA John Wiley and Sons pp 217-253 (1989) Blake M W (1988) Estimating benefits from cleaning coals In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 667-676 (1988) Blake M W Robin T T (1982) Coal quality influence on operating plant cost Paper presented at Ninth annual engineering conference on reliability for the electric power industry Hershey PA USA 16-19 Jun 1982 Blondin J Girardeau M Nomine M (1988) Two simple tests for the assessment of wet fine coal handleability In Industrial practice offine coal processing KIimpel R R Luckie P T (eds) Littleton CO USA SME-AIME pp 253-255 (1988) Blough J L Kihara S Wolowodiuk W (1988) Effects of coal properties on superheater corrosion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 235-253 (1988) Boley D G (1984) Calcium chloride A new solution for frozen coal Power 128 (1) 67-69 (Jan 1984) Borio R W Levasseur A A (1986) Coal ash deposition in boilers ACS Symposium Series 103 288-302 (1986) Borio R W Levasseur A A Chow 0 K Miemiec L S (1992) Ash deposition a boiler manufacturers perspective In Engineering Foundation conference on inorganic transfonnations and ash deposition during combustion Palm Coast FL USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 95-120 (1992) Borio R W Plumley A L Sylvester W R (1978) Improved thennal efficiency by controlling of factors affecting metal wastage in pulverized coal-fired steam generators In Ash deposits and corrosion due to impurities in combustion gases Bryers R W (ed) Washington DC USA Hemisphere Publishing pp 163-183 (1978) Boushka M (1988) Application of EPRIs coal quality impact model In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Infonnation Services pp AI-A20 (May 1988) Boyd R K Kent J H (1986) Three-dimensional furnace computer modelling In Twentyjirst symposium (international) on combustion Munich Federal Republic of Gennany 3 Aug 1986 Pittsburgh PA USA The Combustion Institute pp 265-274 (1986) Boyd R K Lowe A (1988) Three-dimensional modeling of a pulverised-coal fired utility furnace In Coal combustion science and technology of industrial and utility application Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 165-172 (1988) Boyd R K Lowe A (1992) Sydney NSW Australia Pacific Power Services Personal communication (Sep 1992) Bretz E A (1991a) Specifying powerplant fuels and combustion systems Electrical World 205 (2) 40-45 (Feb 1991) Bretz E A (1991b) Innovation key to finding unusual ash-disposal options Electrical World 205 (7) 56-57 (Jul 1991) Brooks K Glasser D (1986) A simplified model of
105
References
spontaneous combustion in coal stockpiles Fuel 65 (8) 1035-1041 (Jug 1986) Brooks S Meadowcroft DB Morris C W Flatley T A (1983) J laboratory evaluation of alloys potentially resistant to furnace wall corrosion In Corrosion resistant materials in coal conversion systems Meadowcroft D B Manning M S (eds) London UK Jpplied Science Publishers pp 121-135 (1983) Brown K (1985) Sampling testing and analysis of coals In An intensive course on the characterisation of steaming coals Newcastle NSW Justralia 20-22 May 1985 Newcastle NSW Justralia University of Newcastle Institute of Coal Research pp 21-239 (May 1985) Bryers R W (1992) Fireside behaviour of mineral impurities in fuels from Marchwood 1963 to the Sheraton Palm Coast 1992 In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USJ 10-15 Mar 1991 New York NY USJ Jmerican Society of Mechanical Engineers pp 3-70 (1992) Bull D L (1992) Jsh deposition a utility perspective In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USJ 10-15 Mar 1991 New York NY USJ Jmerican Society of Mechanical Engineers pp 121-132 (1992) Burchill P (1987) Some observations on the variation of nitrogen content and functionality with coal rank In 1987 International conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Jmsterdam the Netherlands Elsevier Science Publishing Company pp 5-8 (1987) Byrne G J Juniper L A (1987) Utilization characteristics of Justralian steaming coals in overseas power stations In Coal Power 87 The AUSIMM annual conference in association with the Mining and Metallurgical Institute of Japan (MMIJ) Newcastle NSW Justralia May 1987 Parkville Vic Justralia The Justralasian Institute of Mining and Metallurgy pp 293-301 (May 1987) Cacka H Lang I Fabianova D (1989) Vliv prvkoveho slozeni uhli HDBS a jejich THF extraktu na nizkoteplotni oxidaci uhli (Effects of elementary composition of coal from the Sokolov brown coal basin and its tetrahydrofuran extracts on low-temperature oxidation) In 2 celostatni konference Samovolne vmecovani uhli v teoril a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSJV pp 1-14 (1989) Cagnetta A C Zelensky G (1983) Coal qualitydesigning a power plant for a wide range or dedicated coal supply In Fifth international coal utilization exhibition and conference Houston TX USJ 7-9 Dec 1982 Houston TX US1 EBJSCO Services Inc pp 3-14 (Dec 1983) Calarco V Bennett D (1989) United States acid rain legislation implications for the international coal markets In CoalTrans 89 sixth international coal trade and transportation conference London UK 16-18 Oct 1989 Worcester Park UK CoalTrans Conferences Ltd vp (1989) Carmichael R L (1987) Factors influencing selection of coals for existing power plants In International symposium on mining technology and science Xuzhou China 18 Sep 1985 Beijing China China Coal Industry Publishing House pp 1365-1371 (1987)
Carpenter A (1988) Coal classification IEJCR12 London UK IEJ Coal Research 104 pp (Oct 1988) Cerkanowicz A E Liskowitz J W Wecharatana M (1991) Potential model of the energy manufacturing process to predict properties of fly-ash as it relates to utilization In Eighth annual international Pittsburgh coal conference Coal - energy and the environment Pittsburgh PJ USJ 14-18 Oct 1991 Greenburg PA USJ Pittsburgh Coal Conference pp 839-842 (1991) Chamberlain R A C Hall D A (1973) The liability of coals to spontaneous combustion Colliery Guardian 221 (2) 65 (Feb 1973) Chen J Y Harris D J Smith I W Zhang D K Wall T F Stanmore B R (1991) Combustion reactivity of coals shyevaluation of laboratory techniques In 1991 international conference on coal science - proceedings Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 303-306 (Sep 1991) Chen X D (1991) The effect of moisture content on the spontaneous ignition process - a review In Proceedings of the fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Jssociation of New Zealand vol 2 pp 327-337 (1991) Chou SF Daniels P L Rodgers L W Theus G J Eskinazi D (1986) Fire-side corrosion in 10w-NOx
combustion systems In Proceedings Symposium on stationary combustion NOx control Boston MJ US1 6-9 May 1985 EPRI-CS-4360 Palo Jlto C1 US1 EPRI Technicallnfonnation Services pp 191-1922 (Jan 1986) Cichanowicz J E Harrison C D (1989) The role of coal cleaning in integrated environmental control In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Jlto C1 USA EPRI Technical Information Services pp 711-724 (Oct 1989) Clarke F Morris C W (1983) Combustion aspects of furnace wall corrosion In Corrosion resistant materials in coal conversion systems Meadowcroft D B Manning M I (eds) London UK Jpplied Science Publishers pp 47-61 (1983) Clarke L Sloss L (1992) Trace elements emissions from coal combustion and gasification IEJCR49 London UK IEJ Coal Research 111 pp (1992) Clemens A H Matheson T W Rogers D E (1990) DTJ studies of the low temperature oxidation of low rank coals Fuel 69 (2) 255-256 (Feb 1990) Coal Research Establishment British Coal Corporation (1991) Studies of the production ofnitrogen oxides and ash deposition from pulverised coal in relation to utilisation in low NOx burners EUR 13443 EN Luxembourg Commission of the European Communities 46 pp (1991) CoaiTrans International (1991) Coal in the environmentshysupplement CoalTrans International 6 (2) VI-XIII (MarlJpr 1991) Colijn H (1988a) Coal properties handleability and bin design In Defining coal handleability Its cost impact and control Lexington KY USJ 30 Jpr-1 May 1987 EPRI-CS-6015 Palo Jlto CJ USA EPRI Research Reports Center pp 21-219 (Nov 1988) Colijn H (1988b) Coal handleability as part of coal quality control In 1988 joint power generation conference
106
References
Philadelphia PA USA 25-29 Sep 1988 New York NY USA The American Society of Mechanical Engineers pp 25-41 (Sep 1988) Collins S (1990) Can problems arising from chlorine in coal be solved generically Power 134 (12) 59-60 (Dec 1990) Connelly L J (1988) Freeze condition agents and their use in the coal industry In Defining coal handleability Its cost impact and control Lexington KY USA 30 Apr-l May 1987 EPRI-CS-6015 Palo Alto CA USA EPRI Research Reports Center pp 31-327 (Nov 1988) Conroy A (1991) Grinding behaviour of hard coals Combustion News 1-4 (Nov 1991) Corder W C (1983) For lower power costs use high quality coal In Third European coal utilisation conference Amsterdam The Netherlands 11-13 Oct 1983 Rotterdam The Netherlands Industrial Presentations pp 221-240 (1983) Corio M R (1982) Heat rates and availability the use of econometric analysis in comparing electric generating unit performance New York NY USA National Economic Research Associates vp (1982) Corson P B (1988) Carolina Power and Light purchasing model (COALBUY) In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 41-410 (May 1988) Cortsen C E (1983) An evaluation of coal properties and their influence on the utilisation in power stations Report No2 2nd ed Fredericia Denmark ELSAM Coal Quality Committee 161 pp (Nov 1983) Couch G R (1988) Lignite resources and characteristics IEACR13 London UK IEA Coal Research 102 pp (Dec 1988) Couch G R (1989) Power generationfrom lignite IEACR19 London UK IEA Coal Research 67 pp (Dec 1989) Couch G R (1991) Advanced coal cleaning technology IEACR44 London UK IEA Coal Research 95 pp (1991) Cox J N Smith S R Metha A (1990) Field evaluation of EPRI coal quality impact model In Proceedings 1989 EPRl heat-rate improvement conference Knoxville TN USA 26-28 Sep 1989 EPRI-GS-6985 Palo Alto CA USA EPRI Research Reports Center pp 4B61-4B68 (Sep 1990) CQ Inc (1992) The Acid Rain Advisor Homer City PA USA CQ Inc 2 pp (1992) Crelling J C Skorupska N M Marsh H (1988) Reactivity of coal macerals and lithotypes Fuel 67 (6) 781-785 (lun 1988) Cumming J W (1980) The electrical resistance of coal ash at elevated temperatures Journal of the Institute of Energy 53 (416) 153-154 (Sep 1980) Cumming J W Livingston W R Hesselmann G J (1987) Coal reactivity assessment for boiler design In Coaltech 87 - Coaltrade 87 - conference papers London UK 9-11 Jun 1987 Schiedam the Netherlands Industrial Presentations pp 11-30 (1987) Cunliffe F (1990) Thornton UK Shell Research Limited Personal communication (1990) Dacey P W Cope D R (1986) Process development In Flue gas desulphurisation - system performance ICEASIB4 London UK IEA Coal Research pp 44-48 (Dec 1986) Daniel M (1991a) Power station coal use prospects to 2000 IEACR4l London UK IEA Coal Research 61 pp (Oct 1991)
Daniel P L (1991b) The effect of coal chlorides on furnace wall corrosion In First international conference on chlorine in coal Chicago IL USA 9-11 Oct 1989 Amsterdam the Netherlands Elsevier Science Publishers pp 207-224 (1991) Darby K (1983) Commercial precipitator design In Second CSIRO conference on electrostatic precipitation Bowral NSW Australia 17-19 Aug 1983 North Ryde NSW Australia Commonwealth Scientific Industrial Research Organisation pp L41-L431 (1983) Davidson R (1990) Effects on coal behaviour In Natural oxidation of coal IEACR29 London UK IEA Coal Research pp 55-65 (Sep 1990) Davis A (1984) Coal petrography and petrographic analysis In Coal geology and coal technology Ward C R (ed) Melbourne Vic Australia Blackwell Scientific Publications pp 74-112 (1984) Deiuliis N J Fink C E Abbott M F (1991) The impact of ash quantity and quality on boiler performance and power cost In Eighth annual international Pittsburgh coal conference Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greenburg PA USA Pittsburgh Coal Conference pp 975-980 (1991) Deutsch W (1922) Bewegung und Ladung der Elektrizitatstrager im Zylinderkondensator (Velocity and loading of charged particles in cyclinder capacitors) Annales der Physik 68 335-344 (1922) Diessel C F K Bailey J G (1989) The application of petrographic techniques to carbonisation and combustion research at the University of Newcastle In MINPET 89shyMineralogy-petrology symposium Sydney NSW Australia 6-8 Feb 1989 Sydney NSW Australia The Australasian Institute of Mining and Metallurgy pp 117-121 (Feb 1989) Donais R T Tyler A L Bakker W T (1988) Effects of coal properties on pulverizer abrasion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 21-217 (1988) Dooley B (1992) Boiler tube failures - a perspective and a vision In International conference on boiler tube failures in fossil plants San Diego CA USA 5-7 Nov 1991 EPRI-TR-100493 Palo Alto CA USA EPRI Distribution Centre pp 11-129 (Apr 1992) Doyle G (1989) Price premiums and inter-coal competition In CoalTrans 89 sixth international coal trade and transportation conference London UK 16-18 Oct 1989 Worcester Park UK CoalTrans Conferences Ltd pp 177-180 (1989) Dusak V (1986) Brown coal and its safe storage Energetika 36 (1011) 471-474 (Oct 1986) Eck G A (1987) Perfectblend coal blending computer program Journal of Coal Quality 6 (3) 100-101 (lui 1987) Electrical World (1987) Utilities report boiler failure chief culprit in forced outages Electrical World 201 (8) 50-52 (Aug 1987) Elliott M A (ed) (1981) Chemistry of coal utilizationshysecond supplementary volume New York NY USA John Wiley and Sons 2274 pp (1981) Elliott T C (1991) Monitoring powerplant performance Power 135 (9) 11-26 (Sep 1991) Elliott T C (1992) Coal handling and preparation Power 136 (1) 17-33 (Jan 1992) ERM Consultants Pty Ltd (1983) Australian case studies
107
References
which relate to coal quality andor consistency to efficiency and economy ofpower production Brisbane Qld Australia ERM Consultants Pty Ltd vp (Mar 1983) Essenhigh R H (1981) Fundamentals of coal combustion In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley and Sons pp 1153-1312 (1981) Evans R J (1991) A computer expert system to reduce power plant emissions PErC Review (4) 24-28 (1991) Falcon L M Falcon R M S (1987) The petrographic composition of Southern African coals in relation to friability hardness and abrasive indices Journal of South African Institute ofMining and Metallurgy 87 (10) 323-336 (Oct 1987) Falcon R M S Snyman C P (1986) An introduction to coal petrography atlas ofpetrographic constituents in the bituminous coals of South Africa Johannesburg South Africa Geological Society of South Africa 27 pp (1986) Falcon R Ham A J (1988) The characteristics of Southern African coals Journal of South African Institute ofMining and Metallurgy 88 (5) 145-161 (May 1988) Fiveland W A Wessel R A (1988) Numerical model for predicting perfonnance of three-dimensional pulverized-fuel fired furnaces Journal ofEngineering for Gas Turbines and Power 110 117-129 (1988) Flatley T Latham E P Morris C W (1981) Co-extruded tubes improve resistance to fuel ash corrosion in UK boilers Material Performance 20 (5) 12-17 (May 1981) Folsom B A Heap M P PoW J H (1986a) Effect of coal quality on power plant performance and costs - Volume 1 State-of-the-art review summary and program plan EPRl-CS-4283-Vol1 Palo Alto CA USA EPRl Technical Infonnation Services 262 pp (Feb 1986) Folsom B A Heap M P PoW J H Smith J L Corio M R (1986b) Effect of coal quality on power plant performance and costs - Volume 2 Review of coal quality impact evaluation procedures EPRl-CS-4283-Vo12 Palo Alto CA USA EPRl Technical Infonnation Services 387 pp (Feb 1986) Folsom B A Heap M P PoW J H Smith J L (1986c) Effect of coal quality on power plant performance and costs - Volume 3 Review of coal quality and power plant performance diagnostics EPRl-CS-4283-Vo13 Palo Alto CA USA EPRI Technical Infonnation Services 176 pp (Feb 1986) Fortune D B (1990) London UK Shell Coal International Ltd Personal communication (1990) Galluzzo N G Stallard G S Boushka M E Mehta A K (1987) Model predicts as-fired costs of changing coal sources Power 131 (6) 53-56 (Jun 1987) Gebel K Madlsperger G Hein K Bokenbrink D (1989) Entwicklung eines Kombinations DeNOx-Verfahrens unter Verwendung von feuerungstechnischen Minderungsrnassnahmen und Hamstoff-SNCR-Technik (Development of a combined DeNOx process using staged combustion and urea-SNCR technology) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Gennany 26-27 Apr 1989 Essen Federal Republic of Gennany VGB Kraftswerkstechnik GmbH pp 173-180 (Apr 1989) Gibb W H (1983) The nature of chlorine in coal and its
behaviour during combustion In Corrosion resistant materials for coal conversion systems Meadowcroft D B Manning M S (eds) London UK Applied Science Publishers pp 25-45 (1983) Gibb W H (1992) Nottingham UK PowerGen Ratcliffe Technology Centre Personal communication (Sep 1992) Gibbs L A Hallett W L H Hughes P M (1989) Coal devolatilization in an entrained flow reactor In The Combustion 1nstitute Canadian Section 1989 spring technical meeting Toronto Ontario Canada 31 May-2 Jun 1989 Ontario Canada The Combustion Institute pp 91-93 (1989) Giovanni D V Afonso R F Dyas B E Mehta A K (1991) Coal quality field test at New England power companys Salem Harbour Unit Three In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRl-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 379-398 (Jul 1991) Given P H (1984) An essay on the organic geochemistry of coal In Coal science volume 3 Gorbaty M L Larsen J Wender I (eds) Orlando FL USA Academic Press pp 63-252 (1984) Given P H Yarzab R F (1978) Coal analysis and mineral matter In Analytical methods for coal and coal products shyVolume II Karr C Jr (ed) New York NY USA Academic Press pp 3-42 (1978) Gluskoter H J Shimp N F Ruch R R (1981) Coal analyses trace elements and mineral matter In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley amp Sons pp 369-424 (1981) Goddard C W Duzy A F (1967) Measuring abrasiveness of solid fuels and other materials by a radiochemical method ASME paper no 67-WAIFU-l New York NY USA American Society of Mechanical Engineers vp (1967) Goetz G J Nsakala N Y Borio R W (1978) Development of methods for determining emissintives and adsorptivities of coal ash deposits In 1987 winter annual ASME meeting Boston MA USA 13 Dec 1978 New York NY USA American Society of Mechanical Engineers vp (1978) Gomer K (1988) Prediction of the turbulent flow heat release and heat transfer in utility boiler furnaces In Coal combustion Science and technology of industrial and utility applications Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 273-282 (1988) Gutberlet H (1988) Einfluss der Feuerungsart auf die Vergiftung von DeNOx-Katalysatoren durch Arsen (The effect of furnace type on the poisoning of DeNOx catalysts by arsenic) VGB Kraftwerkstechnik 68 (3) 287-293 (Mar 1988) Hainley D C Yavuzkurt S Scaroni A W (1986) Effect of coal properties on fluidized bed combustor perfonnance In Energy-sources technology conference and exhibition New Orleans LA USA 23 Feb 1986 New York NY USA American Society of Mechanical Engineers pp 43-54 (1986) Hampartsoumian E Murdoch M Pourkashanian M Williams A (1991) The reactivity of coal chars produced under various pyrolysing conditions In 1991 international conference on coal science - proceedings Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 271-274 (Sep 1991) Harb J N Smith E E (1990) Fireside corrosion in PC-fired
108
References
boilers Progress in Energy and Combustion Science 16 (3) 169-190 (1990) Hardgrove R M (1938) ASME technical paper Paper presented at ASME spring meeting Chicago IL USA 27 Jun 1938 Harrington R C Kaltenback R P Stratton H L (1988) Burner improvement program on a 650 MW supercritical steam generator - a case study In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 541-549 (Sep 1988) Harrison C Zera C (1990) A new way of doing business in coal-fired power generation Power Engineering 94 (4) 33-36 (Apr 1990) Hatt R M (1990) Fireside deposits in coal-fired utility boilers Progress in Energy and Combustion Science 16 (4) 235-241 (1990) Hatt R M (1991) Coal mining and preparation practices shyimpacts on power plant perfonnance In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 365-377 (Jul 1991) Heap M P Kramlich J C Pershing D W Pohl J H Richter W F Seeker W R (1986) Effect of coal quality on power plant performance and costs - Volume 4 Review of coal science fundamentals EPRI-CS-4283-Vo14 Palo Alto CA USA EPRI Technical Infonnation Services 574 pp (Feb 1986) Heap M P Pohl A S Folsom A S Mehta A K (1984) The effects of coal quality and the resulting ash deposition on the costs of power station operation (Die Bedeutung der Kohlqualitiit und der daraus resultierenden Aschelagerungen fur die Kostan des Kraftwerksbetriebes) In Internationale VGB-Konferenz Verschlackungen Verschmutzungen und Korrosionen in Wriimekraftwerken - Vortriige Essen Federal Republic of Gennany 29 Feb-2 Mar 1984 Essen Federal Republic of Gennany VGB Technische Vereinigung der Grosskraftwerksbetreiber eV pp 493-507 (1984) Heble J J Srinivaschar S Boni A A (1991) The behaviour of clay minerals under combustion conditions American Chemical Society Division of Fuel Chemistry Preprints 36 (1) 173-180 (Apr 1991) Heitmiiller W Schuster H (1991) Low-NOx pulverized coal firing systems and their components Infonnation No 189 Hausdruckerei Gennany Deutsche Babcock Energie- und Umwelttechnik AG 17 pp (Mar 1991) Hervol J D Mehta A K Levasseur A A Miemiec L S Lexa G F (1988) Benefits of coal cleaning on the capital and operating costs of a 550 MW boiler In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 81-824 (May 1988) Hewing A N Harvey M R (1981) Evaluating freeze conditioning agents for coal Power Engineering 85 (7) 74-75 (JuI1981) Hjalmarsson A-K (1990) NOx control technologies for coal combustion IEACRl24 London UK lEA Coal Research 102 pp (Jun 1990) Hjalmarsson A-K (1992) Interactions in emissions control for coal-fired plant IEACRl47 London UK lEA Coal Research 81 pp (Mar 1992) Hjalmarsson A-K Soud H N (1990) Systems for controlling
NOxfrom coal combustion IEACRl30 London UK lEA Coal Research 240 pp (Dec 1990) Hobbs M L Smith P J (1990) Algebraic multi-zoned radiation model for a two-zoned zero-dimensional cylindrical furnace Fuel 69 (11) 1420-1427 (Nov 1990) Hodde J A (1988) Least cost fuel system used to plan fuel purchases In 1988 joint power generation conference Philadelphia PA USA 25-29 Sep 1988 New York NY USA American Society of Mechanical Engineers pp 43-51 (Sep 1988) Holstein R A (1981) Coal fired power plant capital cost estimates EPRI-PE-1865 Palo Alto CA USA EPRI Technical Infonnation Services vp (1981) Horsfall D W Zitron Z (1982) High density beneficiation of coal In Proceedings sixth international conference on coal research London UK 4-8 Oct 1982 London UK National Coal Board pp 319-337 (1982) lEA Coal Industry Advisory Board (1985) Coal quality and ash characteristics Paris France OECDIIEA 63 pp (Jan 1985) IEEE (1984) IEEE standard criteria and guidelines for the laboratory measurement and reporting offly ash resistivity IEEE Standard 548-1984 New York NY USA Institute of Electrical and Electronics Engineers 30 pp (21 Dec 1984) ICCP International Committee for Coal Petrology (1963) International handbook of coal petrology - second edition Paris France Centre National de la Recherche Scientifique vp (1963) ICCP International Committee for Coal Petrology (1975) International handbook of coal petrology - supplement to the second edition Paris France Centre National de la Recherche Scientifique vp (1975) ICCP International Committee for Coal Petrology (1985) International handbook of coal petrology - edited reprint of 1975 supplement to the second edition Murchison D G Smith A H V (eds) Newcastle upon Tyne UK University of Newcastle upon Tyne vp (1985) International Energy Agency (1992) Coal information 1992 Paris France OECDIIEA 541 pp (1992) Iskhakov Kh A (1990) The role of sorbed moisture in coal oxidation Solid Fuel Chemistry (English translation) 24 (2) 17-21 (1990) Jacobs J P (1992) Essen Gennany VGB Technical Association of Large Power Plant Operators Personal communication (Sep 1992) Jamaluddin A S Fiveland W A (1990) Practical model for predicting unburned carbon and temperatures in large-scale boilers Paper presented at 1990 spring meeting combustion fundamentals and applications Cincinnati OH USA 20-22 May 1990 Jenson P T (1992) Fredericia Denmark ELSAM Personal communication (Sep 1992) Johanson J R (1989) Evaluating coal handling characteristics In 1989 joint power generation conference Dallas TX USA 22-26 Oct 1989 New York NY USA American Society of Mechanical Engineers pp 1-5 (Oct 1989) Johanson J R (1991) Identify hard-to-handle coal early Power Engineering 95 (11) 35-38 (Nov 1991) Johnson R P Plangemann R Rehm M (1991) Coal quality effects on boiler perfonnance an Eastern utility perspective In Effects of coal quality on power plants St Louis MI
109
References
USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 11-113 (Jul 1991) Jones A R Gibb W Johnston J (1992) Nottingham UK PowerGen Ratcliffe Technology Centre Personal communication (Mar 1992) Jones M L Benson S A (1988) An overview of slagginglfouling with Western coals In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 125-147 (1988) Jones R B McCourt C B Morley C King K (1985) Maceral and rank influences on the morphology of coal char Fuel 64 (10) 1460-1467 (Oct 1985) Juniper L Pohl J (1991) Techniques to control NOx
emissions from coal-fIred boilers Australian Combustion Technology Centre Combustion News 1-4 (May 1991) Jiintgen H (1987a) Coal characterization in relation to coal combustion Part I structural aspects and combustion Erdol Kohle Erdgas Petrochemie vereinigt mit Brennstoff-Chemie 40 (4) 153-165 (Apr 1987) Jiintgen H (1987b) Coal characterization in relation to coal combustion Part II environmental problems of combustion ErdOl Kohle Erdgas Petrochemie vereinigt mit Brennstoff-Chemie 40 (5) 204-208 (May 1987) Kalmanovitch D P (1991) A practical approach to predicting ash deposition In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 591-5102 (Jul 1991) Kapteijn F Bruinsma D Mol J Moolijn J A (1990) The characterisation of fly-chars from combustion the effect of temperature and rank on reactivity texture and composition Fuel Processing Technology 24 (113) 391-398 (1990) Kautz K (1982) Importance of maceral content in regard to the properties of coals of worldwide origin and its effects on combustion chamber design of large dry furnaces VGB Kraftwerkstechnik - English Issue 62 (3) 1-12 (Mar 1982) Kehoe D B Hervol J D Evans R J Levasseur A A (1990) Evaluating the effects of cleaned coals in utility boilers In Eleventh international coal preparation congress Tokyo Japan 22-25 Oct 1990 Tokyo Japan Mining and Materials Processing Institute of Japan pp 247-252 (1990) Kemeny P (1988) Coal quality impact on electric power generation costs case study Fusina unit 3 In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 631-655 (1988) King J G Maries M B Crossley H E (1936) Fonnulae for the calculation of coal analysis to a basis of coal substance free of mineral matter Journal for the Society of Chemistry and Industry 55 277-281 (1936) Kirchner A T (1991) On-line analysis of coal IEACR40 London UK lEA Coal Research 79 pp (Sep 1991) Kiss L T King TN (1979) Reporting of low-rank coal analysis - the distinction between minerals and inorganics Fuel 58 (7) 547-549 (Jul 1979) Klingspor J S Vernon J L (1988) Particulate control for coal combustion IEACR05 London UK lEA Coal Research 70 pp (Feb 1988) Klitgaard J (1988) Utility coal quality work at a cross-road Journal of Coal Quality 7 (2) 36-37 (Jun 1988) Knill K J (1987) A review offuel staging in pulverised coal
combustion systems IFRF-G-13a3 IJmuiden Netherlands International Flame Research Foundation 54 pp (Sep 1987) Kok A (1988) The effect of coal type on carbon burnout and NOx fonnation in pulverized coal combustion In Coaltech 88 - Coaltrade 88 seventh international conference on coal technology and coal trade Amsterdam the Netherlands 21-23 Nov 1988 Amsterdam the Netherlands Industrial Presentations (Europe) BV pp 1-14 B3 (1988) Kosvic T C Breen B P Yingling J C Mazumdar M Carpenter M Stothart B Plangemann R Maurer W (1988) A combined mechanisticstatistical approach to relating coal properties and boiler operating characteristics to the perfonnance of coal fIred boilers In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 71-717 (Sep 1988) Kremer H Grigoleit H Jacobs J (1990) Tendency of power station coals to fonn NOx - Results of VGB Research Project 89 VGB Kraftwerkstechnik - English Issue 70 (7) 478-484 (Jul 1990) Latham C E Fiveland W A La Rue A D (1991a) Numerical models as combustion system design tools In Eighth annual international Pittsburgh coal conference proceedings Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greenburg PA USA Pittsburgh Coal Conference pp 34-39 (1991) Latham E Meadowcroft D B Pinder L (1991b) The effects of coal chlorine on fireside corrosion In First international conference on chlorine in coal Chicago IL USA 9-11 Oct 1989 Amsterdam the Netherlands Elsevier Science Publishers pp 225-250 (1991) Laurendeau N M (1978) Heterogeneous kinetics of coal char gasification and combustion Progress in Energy and Combustion Science 4 (4) 221-270 (1978) Lee G K Thambimuthu K V Hill J M (1991) Assessment of ash sintering potential by conductance and dilatometry In Eight annual international Pittsburgh coal conference proceedings Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greensburg PA USA Pittsburgh Coal Conference pp 6-11 (1991) Llewellyn W (1991) A practical study of coal handleability In Proceedings of the fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Association of New Zealand vol 1 pp 115-126 (1991) Llinares V Caron M B Schmidt E J Szela F J (1982) The C-E availability data program 1982 further developments on MTTR and MTBF analysis Paper presented at Ninth annual engineering conference on reliability for the electric power industry Hershey PA USA 16-19 Jun 1982 Llinares V Lutz A B (1985) Long range forecast and availability improvement program In Proceedings of the 1985 joint ASMEIEEE power generation conference Milwaukee WI USA 20 Oct 1985 New York NY USA American Society of Mechanical Engineers vp (1985) Lockwood F C Mahmud T (1989) The prediction of swirl burner pulverized coal flames In Twenty-second symposium (international) on combustion Seattle WA USA 14-19 Aug 1988 Pittsburgh PA USA The Combustion Institute pp 165-173 (1989) Lowe A (1987) Important coal properties for power
110
References
generation In Geology and coal mining conference Sydney NSW Australia 13-15 Oct 1987 Sydney NSW Australia Geological Society of Australia Coal Geology Group pp 188-196 (Oct 1987) Lowe A (1988a) Effect of ash levels on large pulverised coal fired furnace performance In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 523-540 (Sep 1988) Lowe A (1988b) Effect of ash in coal on power plant availability In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 733-744 (1988) Luckie P T and others (1980) Coal grinding technology A manual for process engineers ERDA FE-2475-25 USA US Government Printing Office No 1980-640-258-2090 vp (1980) Luo X-L Boyd R K Kent J H (1991) Computational investigation of burnout in a furnace firing pulverised coal Journal of the Institute of Energy 64 (461) 230-238 (Dec 1991) Mackowsky M Th (1982) Minerals and trace elements occurring in coal In Stachs textbook of coal petrology Stach E Mackowsky M Th Teichrnller M Taylor G H Chandra D Teichrnller R (eds) Berlin Federal Republic of Germany Gebriider Borntraeger pp 153-171 (1982) Maher T P Smith MY (1990) A user-friendly coal value model for thermal coals In 1990 international coal engineering conference Sydney NSW Australia 19-21 lun 1990 Barton ACT Australia Institution of Engineers pp 259-263 (lun 1990) Mahr D (1988) Blending coal for quality control In 1988 joint power generation conference - coal quality control fundamentals and applications Philadelphia PA USA 25-29 Sep 1988 New York NY USA American Society of Mechanical Engineers pp 1-8 (Sep 1988) Makanski J (1989) Coal analyzers provide critical link for plant control functions Power 133 (2) 23-25 (Feb 1989) Malhotra V M Crelling J C (1987) Spontaneous combustion of coal and maceral enriched fractions under storage pneumatic transport conditions Final report DOEIPC79863-T13 Carbondale IL USA Coal Extraction and Utilization Research Center 97 pp (Mar 1987) Mancini R A Hopkins B W Hodde J A (1987) Coal quality engineering aids purchasing Power Engineering 91 (6) 16-20 (lun 1987) Mancini R A Hopkins B W Hodde J A (1988) Coal quality engineering analysis used to evaluate coal purchases In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 Palo Alto CA USA EPRI Research Reports Center pp 51-515 (May 1988) Mason D M Gandhi K (1980) Formulas for calculating the heating value of coal and char development tests and uses American Chemical Society Division of Fuel Chemistry Preprints 25 (3) 235-245 (1980) Matsuura S Uchida S (1988) Spontaneous combustion susceptibility of coals Saiko to Hoan 34 (10) 2-14 (25 Oct 1988) Matts S A Ohnfeldt P 0 (1973) Efficient gas cleaning with SF electrostatic precipitators Vaxjo Sweden Flakt Industri AB vp (1973)
McCartney R H Whittaker P S Planner J H (1990) A comparison of United States and Australian practices for power station coal handling facilities In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 lun 1990 Sydney NSW Australia Institution of Engineers pp 174-183 (lun 1990) Mehta A (1989) Coal quality impact model EPRl Journal 14 (8) 49-52 (Dec 1989) Mellanby-Lee H (1986) Effects of coal quality on the costs of electricity generation In Physical coal beneficiation and electricity costs ICEASC3 London UK lEA Coal Research pp 18-30 (Feb 1986) Meyers A D Atkinson B W (1991) Using techno-economic computer modelling to assess the utilisation value of New Zealand coal on the world market In Fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Association of New Zealand pp 160-171 (1991) Mikula R J Parsons I S (1991) Coal dustiness characterisation and control Coal Preparation 9 (314) 199-212 (1991) Misra M K Essenhigh R H (1990) Modelling of one-dimensional pulverised coal flames Paper presented at 1990 spring technical meeting combustion fundamentals and applications Cincinnati OH USA 20-22 May 1990 Mitas D Stallard S Anderson-Higgs A OConnor D (1991) Coal quality analysis linked to power plant control Power Engineering 95 (5) 29-32 (May 1991) Mittelbach G (1989) NOx- Minderung an Kohle-und Mtillkesseln mit dem TermoNOx Verfahren Vergleich von Untersuchungsergebnissen (NOx reduction at coal-fired plants and refuse incinerators with the ThermoNOx process a comparison of test results) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Germany 26-27 Apr 1989 Essen Federal Republic of Germany VGB Kraftswerkstechnik GmbH pp 194-200 (Apr 1989) Morgan M E (1987) Characterisation of coals for use in pulverised coal combustion In International conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 823-826 (1987) Morgan ME (1990) Effect of coal quality on the performance of low-NOx burners Journal of the Institute of Energy 66 (454) 3-8 (Mar 1990) Morgan P A Robertson S D Unsworth J F (1987) Combustion studies by thermogravimetric analysis Fuel 66 (2) 210-215 (Feb 1987) Morrison G F (1982) Control of sulphur oxides from coal combustion ICTISITR21 London UK lEA Coal Research 104 pp (Nov 1982) Morrison G F (1986) Understanding pulverised coal combustion ICTISITR34 London UK lEA Coal Research 46 pp (Dec 1986) Murtha M J (1982) Minerals extraction from ash state of the art In Proceedings of resources from coal coal wastes and ash workshop Reston VA USA 9 lun 1982 BNL-51679 DE83017775 Springfield VA USA National Technical Information Service pp 91-103 (1982) Muter R B Lawrence W F (1986) Mineral matter analysis a technique to improve bituminous coal ACS Symposium Series 301 443-448 (1986)
111
References
Myllynen H (1987) Which thermal coal In Coal Power 87 Neuss Dusseldorf Federal Republic of Germany 27-29 Oct 1987 Worcester Park UK CS Publications Ltd pp 37-42 (1987) Nadgauda S S Hathaway A J (1990) Coal utilization cost model for fuel procurement Journal of Coal Quality 9 (1) 17-21 (Mar 1990) Nakabayashi Y (1988) NOx removal from flue gas In The coal in Sweden conference on the role of coal in the Swedish energy system possibilities and limitation SOdertiilje Sweden 26-27 Oct 1988 Sdertlje Sweden Telge Energe AB pp 1-39 (Oct 1988) Nakata T Sato M Makino H (1988) Methods ofpredicting NOx emissions in coal combustion and unburned carbon in fly ash - effects of coal propenies CRIEPI-W-87003 Tokyo Japan Central Research Institute of the Electrical Power Industry 30 pp (Feb 1988) Nandi B N Brown T D Lee G K (1977) Inert coal macerals in combustion Fuel 56 (4) 125-130 (Apr 1977) Nayak R V Bauer F W Tonden T P (1987) Mineral matter in coal - origin identification and boiler erosion Journal of Coal Quality 6 (2) 37-43 (1987) Neavel R C (1981) Origin petrography and classification of coal In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley and Sons pp 91-158 (1981) Neavel R C Smith S E Hippo E J Miller R N (1986) Interrelationships between coal compositional parameters Fuel 65 (3) 312-320 (Mar 1986) Nemec J Dobal V (1988) Contribution to problem of coal spontaneous combustion Acta Montana Zpravy Hornickeho Ustavu CSAV (Ceskoslovenske Akademie Ved) (76) 9-20 (1988) Nicol S K Smitham J B (1990) Coal stockpile dust control In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 Jun 1990 Sydney NSW Australia Institution of Engineers pp 154-158 (Jun 1990) Noskievic P Kolat P Cech B (1987) Operational tests of burners for ignition and stabilization of pulverised coal Energetika 37 (5) 233-236 (May 1987) Nurick W (1988) An engineering approach to prediction of fuel impacts on utility boiler systems In Reducing electricity generation costs by improving coal quality Indiana PA USA 5-6 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 71-760 (May 1988) Oka N Murayama T Masuoka H Yamada S Yamada T Shinozaki S Shibaoka M Thomas C G (1987) The influence of rank and maceral composition on ignition and char burnout of pulverized coal Fuel Processing Technology 15 213-224 (Jan 1987) Osborn G A (1992) Review of sulphur and chlorine retention in coal-fIred boiler deposits Fuel 71 (2) 131-142 (Feb 1992) OKeefe W Hart R M Hopkins B W McIntire D C Harrison C D (1987) Do we need highly detailed coal specs Power 131 (10) 121-123 (Oct 1987) Parish B M (1970) Wear ofpulverisers Research report 363 Cheltenham UK National Coal Board Research Establishment vp (20 Mar 1970) Pasini S Trebbi G (1989) Evolutions of design and operation criteria for ENEL boilers Paper presented at Tenth international conference on power stations Liege Belgium 25-29 Sep 1989
Pavlikova H Machovic V Sebestova E (1989) Study of low-temperature coal oxidation by means of nuclear magnetic resonance spectrometers infrared spectrometers and electron spin resonance In 2 celostatni konference Samovolne vmecovani uhli v teorii a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSAV pp 1-14 (1989) Penninger A (1989) Effect of working parameters on flame stability for coal dust combustion In Tagung iiber Verbrennung und Feuerung14 Deutscher Flammentag (Meeting on combustion and furnaces 14 Gennan flame day) Stuttgart Federal Republic of Germany 5-6 Oct 1989 Dusseldorf Federal Republic of Germany Verein Deutscher Ingenieure (VDI) - Gesellschaft Energietechnik pp 669-679 (1989) Platfoot R (1990) Erosion life of tube banks in coal fired boilers In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 237-241 (Iun 1990) Pohl J S (1990) Procedure for evaluating the performance of low-grade fuels In Low-grade fuels Helsinki Finland 12-16 Jun 1989 Espoo Finland Valtion Teknillinen Tutkimuskeskus vol 1 pp 247-260 (1990) Potter E (1988) Correlations of ash chemistry with pilot-scale electrostatic precipitation experiments In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp N33-N34 (1988) PowerGen (1991) POSTMAN steady state plant modelling system Information sheet no 34 Nottingham UK PowerGen pic Power Technology Centre 2 pp (1991) Pronobis M (1989) Further fmdings concerning the effect of ash deposits upon the exchange of heat in convection boiler surfaces VGB Kraftwerkstechnik - English Issue 69 (11) 931-938 (Nov 1989) Raask E (1985) Mineral impurities in coal combustion shybehaviour problems and remedial measures London UK Hemisphere Publishing 506 pp (1985) Rademacher F J C (1990) Coal handling developments focusing on The Netherlands In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 282-288 (Jun 1990) Rees 0 W (1966) Chemistry uses and limitations of coal analysis Report of Investigations 220 Urbana IL USA lllinois State Geological Survey 50 pp (1966) Reinschmidt K F (1991) Neural networks next step for simulation and control Power Engineering 95 (11) 41-45 (Nov 1991) Repic B Radulovic P Sikmanovic S Grubor B (1988) Boilers start-up with pulverized coal Paper presented at 20 Kraftwerkstechnisches Kolloquium 1988 (20 power plant technical colloquium) Dresden Federal Republic of Germany 11-12 Oct 1988 Richter W Payne R Heap M P (1986) Influence of thermal properties of wall deposits on performance of pulverised fuel fired boiler combustion chambers ACS Symposium Series (301) 375-393 (1986) Richwine R R Quinn A D Mills J B Lowe S D (1989)
112
References
Results of the availability improvement program in the southern electric system Paper presented at Tenth international conference on power stations Liege Belgium 25-29 Sep 1989 Riley J T Gilleland S R Forsythe R F Graham H D Jr Hayes F J (1989) Nonadditive analytical values for coal blends In Proceedings of the seventh international coal testing conference Ashland KY USA 1989 Ashland KY USA Coal Testing Conference pp 32-38 (1989) Rittenhouse R C (1991) Fighting corrosion in air pollution control systems Power Engineering 95 (6) 23-29 (Jun 1991) Rittenhouse R C (1992) New fuel choices change coal handling and storage rules Power Engineering 96 (1) 17-21 (Jan 1992) Robinson G F (1985) A three-dimensional analytical model of a large tangentially fired furnace Journal of the Institute of Energy 116 226-150 (1985) Roy W R Griffin R A Dickerson D R Schuller R M (1984) illinois basin coal fly ashes 1 Chemical characterisation and solubility Environmental Science and Technology 18 (10) 734-739 (1984) Sadowski R S Hunt P J (1978) Consequences of specifying a boiler design fuel before source commitments are firm In Proceedings of the American power conference Vol 40 Chicago IL USA Apr 1978 Chicago IL USA illinois Institute of Technology pp 394-402 (1978) Sanyal A Livingston W R Marsh H Skorupska N M Field D J Edwards 1 AS (1991) Petrography of lignitic and bituminous coals application to assess coal combustibility for power generation In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 51-520 (JuI1991) Saxena S C (1990) Devolatilization and combustion characteristics of coal particles Progress in Energy and Combustion Science 16 (1) 55-94 (1990) Schaeffer J J (1988) Review of coal quality characteristics of potential utility fuel supply sources Journal of Coal Quality 7 (1) 19-22 (Jan 1988) Scieszka S F (1985) New concept for determining pulverizing properties of coal Fuel 64 (8) 1132-1142 (Aug 1985) Sebesta P Vodickova A (1989) Self-ignition of coal according to its reactivity to oxygen In Symposium on coal utilization trends and challenges Dhanbad India 13-14 Dec 1989 Dhanbad India Central Fuel Research Institute vp (1989) Sherman R A Pilcher J M (1938) An experimental investigation of the use of oil in the treatment of coal Transactions ofAmerican Society of Chemical Engineers 60 97-109 (1938) Shibaoka M Thomas C S Heng S Mackay G H (1987) Significance of morphological features of macerals in coal utilization research In 1987 international conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 107-110 (1987) Shida H Adacchi T Karagasaki M Kuminoto T Hisatome M Kobayashi Y (1984) Development of three-dimensional numerical analysis method of boiler furnace characteristics - part 1 flow analysis Technical Review 18-23 (1984)
Shigeta J-I Hamao Y Aoki H Kajigaya 1 (1987) Development of a coal ash corrosivity index for high temperature corrosion Journal of Engineering Materials and Technology 109 (4) 299-305 (Oct 1987) Shimada S Aumiiller A Klemm F (1991) Measurement of property change of coals stored in stockpile for a long time In 1991 international conference on coal science Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 925-928 (Sep 1991) Shonhardt J A (1990) Evaluation of spontaneous combustion characteristics of some Australian coals Coal Journal (Australia) (29) 21-31 (1990) Singer J G (1989a) Steam fundamentals In Standard handbook ofpower-plant engineering New York NY USA McGraw Hill pp 13-19 (1989) Singer J G (1989b) Pulverizers In Standard handbook of power-plant engineering New York NY USA McGraw Hill pp 1157-1182 (1989) Singer J G (1991) Combustion fossil power - a reference book on fuel burning and steam generation Windsor CN USA Combustion Engineering 1010 pp (1991) Skinner M S A (1988) The costs of burning coal In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Specialists pp 719-731 (1988) Skorupska N M Marsh H (1989) The importance of petrographic characterization of coal for combustion processes In Institute of Energy conference on applied energy research Swansea UK 5-7 Sep 1989 Bristol UK Adam Hilger pp 161-181 (1989) Skorupska N M Sanyal A Hesselman G J Crelling J C Edwards 1 A S Marsh H (1987) The use of an entrained flow reactor to assess the reactivity of coals of high inertinite content In 1987 intemational conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 827-831 (1987) Sligar J (1985) Coal pulverising mill section In Course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 101-1023 (May 1985) Sligar J (1992) Sydney NSW Australia Pacific Power Services Personal communication (Oct 1992) Smith D J (1991) Integrated control systems The next stop Power Engineering 95 (9) 17-21 (Sep 1991) Smith G (1985) Laboratory studies to support the marketing of Australian coals In Proceedings Coal research conference Wellington New Zealand 15-17 Oct 1985 Wellington New Zealand Coal Research Association of New Zealand vol 2 Paper 342 15 pp (1985) Smith 1 W (1982) The combustion rates of coal chars In Nineteenth symposium (international) on combustion Haifa Israel 8-13 Aug 1982 Pittsburgh PA USA The Combustion Institute pp 1045-1065 (1982) Smith 1 W Wall T F Stanmore B R Harris D J Chen J Y Zhang D K (1991a) Coal combustion testing optimum laboratory procedure NERDDP-EG-91-993 Canberra ACT Australia National Energy Research Development and Demonstration Council 89 pp (Feb 1991) Smith P J Davies P R Jamaluddin A S (1991b) Coupling fireside deposition with computational combustion predictions In Effects of coal quality on power plants St
113
References
Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 2119-2140 (Jul 1991) Smith P J Smoot L D (1987) Detailed model for practical pulverized coal furnaces and gasifiers In Proceedings of the AR and TD (Advanced Research and Technology Development) direct utilization and instrumentation and diagnostics contractors review meeting Morgantown WV USA 13 Oct 1987 DOEIMETC-886084-vol 1 Morgantown WV USA Morgantown Energy Technology Center pp 62-71 (Oct 1987) Smith S R (1988) Tennessee Valley Authoritys experience with switching to improved quality coal In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 Palo Alto CA USA EPRI Technical Infonnation Services pp 31-323 (May 1988) Smoot L D (1984) Modeling of coal-combustion processes Progress in Energy and Combustion Science 10 (2) 229-272 (1984) Smoot L D Smith P J (1985) Coal combustion and gasification New York NY USA Plenum Press 459 pp (1985) Sorter J G Folsom B A Richter W (1986) Application of pilot-scale coal evaluation to utility boilers In Joint ASMElIEEE Power generation conference Portland OR USA 19-23 Oct 1986 New York NY USA American Society of Mechanical Engineers pp 1-8 (Oct 1986) St Baker T C (1983) Technology of coal utilisation for electric power generation In Coal technology and coal utilisation Brisbane Qld Australia 29-31 Aug 1983 Brisbane Qld Australia Australian Mineral Foundation Inc pp 1-42 (Aug 1983) Stach E Mackowsky M Th Teichmiiller M and others (eds) (1982) Stachs textbook ofcoal petrology Berlin Federal Republic of Germany Gebriider Borntraeger 535 pp (1982) Stallard G S Galluzzo N G Brown R E Pavlish J H (1988) Implementing EPRIs state-of-the-art coal quality impact model into fuel procurement practices In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 677-693 (1988) Stallard G S Mehta A (1991) Using EPRI CQIM to evaluate acid rain strategies In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 257-275 (Jul 1991) Stallard S Galluzzo N G Mehta A K (1989) Demonstration coal quality impact model In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Alto CA USA EPRI Technical Infonnation Services pp 91-919 (Oct 1989) Stanmore B R (1990) Ash hopper explosions in coal-fired boilers In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 274-276 (Jun 1990) Strein D L (1989) Effects of changing coal quality on precipitator perfonnance In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Alto CA USA EPRI Technical Infonnation Services pp 41-417 (Oct 1989)
Swaine D J (1990) Methods of analysis In Trace elements in coal London UK Butterworths amp Co Ltd pp 50-76 (1990) Swanson A R Taggart I J Wood D L (1982) The economic value of coal for coal fired power stations In Coal Phoenix of the 80s - Proceedings 64th CIC coal symposium Halifax NS Canada 31 May-3 Jun 1981 Ottawa ON Canada Canadian Society for Chemical Engineering pp 324-329 (1982) Swithenbank J Garbett E S Boysan F Ayers W H (1988) Advance of research on coal combustion system modelling In International symposium on coal combustion Science and technology of industrial and utility applications Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 39-63 (1988) Tams D E (1990) Atmospheric fluidized beds - problems and solutions in practice In International conference on steam plant for the 1990s London UK 4-6 Apr 1990 Bury St Edmunds UK Mechanical Engineering Publications pp 117-124 (1990) Taraba B (1989) Effects of grain size and moisture on heat released during oxidation In 2 celostatni konference Samovolne vznecovani uhli v teorii a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSAV pp 1-9 (1989) Taubert U (1991) New developments in the waste disposal of coal-fired power plants VGB Kraftwerkstechnik - English Issue 2 (91) 86-91 (1991) Teichmillier M (1982) Origin of the petrographic constituents In Stachs textbook of coal petrology Stach E Mackowsky M Th Teichmller M and others (eds) Berlin Federal Republic of Germany Gebriider Borntraeger pp 219-294 (1982) Teyssler J (1988) Dependence of operating cost of a steam generator on inert content of the fuel Paper presented at Twentieth power plant technical colloquium Dresden Federal Republic of Germany 11-12 Oct 1988 Thielen W Odenthal H P Richter W (1987) Investigation of the influence of furnace geometry and coal properties on furnace perfonnance with the help of radiation transfer model In Fundamentals of the physical-chemistry of pulverised coal combustion Les Arcs France 28 Jul-1 Aug 1986 Dordrecht the Netherlands Martinus Nijhoff Publishers pp 424-436 (1987) Thompson A W Gibb W H (1988) Coal ash viscosity measurements on selected British coals as an aid to slagging propensity assessment In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 315-351 (1988) Tisch C Mancini R Sutton J Rini M (1990) Optimize p-c combustion to reduce carbon in fly ash Power 134 (12) 31-33 (Dec 1990) Tominaga H Sato M (1989) Development of a simulation for pulverised coal-fired boiler operation (part 4) evaluation of the FLUENT model Idemitsu Sekiyu Gijutsu 32 (1) 29-37 (1 Jan 1989) Truelove J (1985) Burners and flame stability In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle
114
References
NSW Australia University of Newcastle Institute of Coal Research pp 41-419 (May 1985) Tsai CoY Scaroni A W (1987) Reactivity ofbiturninous coal chars during the initial stage of pulverized-coal combustion Fuel 66 (10) 1400-1406 (Oct 1987) Ugursal V I AI Taweel A M (1990) A method for calculating the area requirement for power plant ash and FGD sludge disposal Journal of Coal Quality 9 (3) 87-90 (1990) Ugursal V I AI Taweel A M Mackay G D M (1990) Impact of coal quality on the cost of electrical power generation a technoeconomic model International Journal of Energy Research 14 (6) 683-699 (Aug 1990) Unsworth J F Barrett D J Roberts P T (1991) Coal quality and combustion performance an international perspective Amsterdam the Netherlands Elsevier Science Publishers 648 pp (1991) Vaninetti G E (1987) The importance of coal quality in marketing Journal of Coal Quality 6 (I) 5-7 (Jan 1987) Vernon J L (1989) Market impacts of sulphur control the consequences for coal lEACRlI8 London UK lEA Coal Research III pp (Oct 1989) Vernon J Soud H (1990) FGD installations on coal-fired plants lEACRl22 London UK lEA Coal Research 84 pp (Apr 1990) Vissar M Boysan F Weber R (1987) Computations of isothermal swirling vortices in the near burner zone Report on the MMF 1-1 investigation IFRF-F-336a9 Umiuden the Netherlands International Flame Research Foundation 179 pp (Iun 1987) Vitta P K Lowe S D Gallaspy D T Afonso R F Molino N M (1991) Application and validation of the coal quality impact model as part of the EPRI coal quality monitoring project In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 295-2117 (luI 1991) van Bush P Snyder T R Chang R L (1989) Determination of baghouse performance from coal and ash properties part II JAPCA Journal of the Air and Waste Management Association 39 (3) 361-372 (Mar 1989) Wagoner C L (1988) New opportunity to predict and verify effects of coal quality on the operation of heat exchangers through generic engineering In Reducing electricity generation costs by improving coal quality Indiana PA USA 5-6 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Information Services pp 61-626 (May 1988) Wain S E Livingston W R Sanyal A Williamson J (1992) Thermal and mechanical properties of boiler slags of relevance to sootblowing In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 459-470 (1992) Wall T F (1985a) Coal characterisation for combustion In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 11-119 (May 1985) Wall T F (1985b) Combustion of coal chars In An intensive course on the characterisation of steaming coals Newcastle
NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 51-529 (May 1985) Wall T F Wibberley L J McCol Stewart I (1985) The characterisation of steaming coals - limitations of the standard laboratory and pilot scale tests In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 111-1126 (May 1985) Walsh P M Beer J M Sarofun A F (1988) Estimation of aerodynamic effects on erosion of a tube by ash In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 219-234 (1988) Ward C P Pech J W Woodson H S (1988) Analytical model for coal combustion optimizing boiler operation through combustion control In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 Palo Alto CA USA EPRI Technical Information Services pp 621-629 (1988) Ward C R (1984) Chemical analysis and classification of coal In Coal geology and coal technology C R Ward (ed) Melbourne Vic Australia Blackwell Scientific Publications pp 40-73 (1984) Waters A G (1987) Implications of coal properties for thermal coal exports In Geology and coal mining conference Proceedings Sydney NSW Australia 13-15 Oct 1987 Sydney NSW Australia Geological Society of Australia Coal Geology Group pp AGWOI-AGW08 (1987) Wibberley L J (1985a) Effect of coal composition on deposit formation in PP fired boilers In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 91-918 (May 1985) Wibberley L J (1985b) Characterisation of coals for flyash and sulphur oxide emissions In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 71-715 (May 1985) Wibberley L J Wall T F (1986) An investigation of factors affecting the physical characteristics of fly ash formed in a laboratory scale combustor Combustion Science and Technology 48 177-190 (1986) Wigley F Williamson J Jones A R (1989) Slagging indices for UK coal and their relationship with mineral matter Fuel Processing Technology 24 (13) 383-389 (1989) Wollmann H-J (1990) Danger from residual coal content in hot fly ash VGB Krafiwerkstechnik - English Issue 70 (6) 404-408 (Iun 1990) Wright I G Williams D N Mehta A K (1988) Techniques to reduce fireside corrosion and fly ash erosion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 255-274 (1988) Wu E J Chen K Y (1987) Chemical form and leachability of inorganic trace elements in coal ash EPRI-EA-5115 Palo Alto CA USA EPRI Technical Information Services 202 pp (Iun 1987) Wu K T Payne R Li B Sheldon M (1990) Application of
115
References
engineering computer models and modeling techniques for evaluating boiler thermal performance and emissions control processes In Combustion modeling and burner replacement strategies ASMFIEEE joint power generation conference Boston MA USA 21-25 Oct 1990 New York NY USA American Society of Mechanical Engineers pp 1-8 (1990) Yancey H F Geer M R Price J D (1951) An investigation of the abrasiveness of coal and its associated impurities Mining Engineering 3 262-268 (1951) Yarkin E V Novikova I V (1988) Price as an incentive for improving quality of power fuel Eleckricheskie Stantsii (3) 8-11 (Mar 1988) Yavorskii I A Alaev G P Pugach L I Talankin L P (1968) Influence of the petrographic composition of coals on the efficiency of a pf fired boiler furnace Thermal Engineering (English translation of Teploenergetika) 15 (9) 108-113 (1968) Young R P DuBard J L Hovis L S (1989) Resistivity of fly ashlsorbent mixtures In Seventh symposium on the transfer and utilization ofparticulate control technology Nashville lN USA 22-25 Mar 1988 EPRI-GS-6208 Palo Alto CA USA EPRI Technical Information Services pp 11-115 (1989)
Zehner P (1989) Erfahrungen mit NOx-mindemden Massnahmen an Feuerungen grosser Dampferzeuger (Experience with combustion measures for NOx reduction at large steam generators) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Germany 26-27 Apr 1989 Essen Federal Republic of Germany VGB Kraftwerkstechnik GmbH pp 121-136 (1989) Zelkowski J Riepe W (1987) Generation of ash by hard coal power stations and problems of its utilization in the Federal Republic of Germany In Ash - a valuable resource Pretoria South Africa 1987 Pretoria South Africa Council for Scientific and Industrial Research vol 1 pp Bl-5 (1987) Ziesmer B C Barna L J Bull D L (1991) A utility perspective on western coals - operating experience and methods for screening potential fuel supplies In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 437-456 (Jul 1991) Zygarlicke C J Steadman E N Benoon S A (1990) Studies of transformations of inorganic constituents in a Texas lignite during combustion Progress in Energy and Combustion Science 16 (4) 195-204 (1990)
116
Appendix List of standards referred to in the report
American Society for Testing and Materials 1916 Race Street Philadelphia PA 19103 USA
D197-1987 Sampling and fineness test of pulverized coal
D291-1986 Cubic foot weight of crushed bituminous coal
D3172-1989
D3173-1987
D3174-1989
Proximate analysis of coal and coke
Moisture in the analysis sample of coal and coke
Ash in the analysis sample of coal and coke from coal
0409-1992 Grindability of coal by the Hardgrove-machine method
D3175-1989 Volatile matter in the analysis sample of coal and coke
D440-1986 Drop shatter test for coal D3176-1989 Ultimate analysis of coal and coke
D441-1986
D547-1941
D720-1991
Tumbler test for coal
Index of dustiness of coal and coke
Free-swelling index of coal
D3177-1989
D3178-1989
Total sulfur in the analysis sample of coal and coke
Carbon and hydrogen in the analysis sample of coal and coke
D1412-1989
D1756-1989
Equilibrium moisture of coal at 96 to 97 per cent relative humidity and 30D C
Carbon dioxide in coal
D3179-1989
D3286-1991
Nitrogen in the analysis sample of coal and coke
Gross CalOrifIC value of coal and coke by the isoperibol bomb calorimeter
D1857-1987 Fusibility of coal and coke ash D3302-1991 Total moisture in coal
D2015-1991 Gross calorific value of coal and coke by the adiabatic bomb calorimeter
D3682-1991 Major and minor elements in coal and coke ash by atomic absorption
D2361-1991
D2492-1990
D2795-1986
Chlorine in coal
Forms of sulfur in coal
Analysis of coal and coke ash
D3683-1978
D4326-1992
Trace elements in coal and coke ash by atomic absorption
Major and minor elements in coal and coke ash by X-ray fluorescence
D2798-1991 Microscopical determination of the reflectance of intrinite in a polished specimen of coal
D4749-1987 Performing the sieve analysis of coal and designating coal size
D2799-1992 Microscopical determination of volume per cent of physical components of coal
D5142-1990 Proximate analysis of the analysis sample of coal and coke by instrumental procedures
117
List of standards referred to in the report
Standards Association of Australia BS 1016 Part 6-1977 Ultimate analysis of coal 80-86 Arthur Street North Sydney NSW 2060 Australia
BS 1016 Part 8-1980 Chlorine in coal and coke
BS 1016 Part 11-1982 Forms of sulphur in coal
BS 1016 Part 12-1984 Caking and swelling properties of coal
BS 1016 Part 14-1979 Analysis of coal ash and coke ash
BS 1016 Part 15-1979 Fusibility of coal ash and coke ash
BS 1016 Part 17-1987 Size analysis of coal
BS 1016 Part 11-1990 Determination of the index of abrasion of coal
BS 1016 Part 20-1987 Determination of the Hardgrove grindability index of hard coal
BS 1016 Part 111-1990 Determination of abrasion index of coal
BS 6127 Part 3-1981 Petrographic analysis of bituminous coal and anthracite Part 3 Method of determining maceral group composition of bituminous coal and anthracite
BS 6127 Part 5-1981 Petrographic analysis of bituminous coal and anthracite Part 5 Method of determining microscopically the reflectance of vitrinite
Deutsches Institut rDr Normung eV Postfach 1107 1000 Berlin 30 Germany
DIN 22020 Part 3-1981 Mikroskopische Untersuchungen an Steinkohle Koks und Briketts Maceralanalyse an Komerschliffen (Microscopic method of analysing coal coke and briquettes maceral group analysis)
DIN 22020 Part 5-1981 Mikroskopische Untersuchungen an Steinkohle Koks und Briketts Reflexionsmessungen an Vitriniten (Microscopic method of analysing coal coke and briquettes measurement of the reflectance of vitrinite)
DIN 51 700-1967 Allgemeines und Ubersicht tiber Untersuchungsverfahren (General and overview of methods of analysis)
DIN 51 705-1979 Bestimmung der Schtittdichte (Determination of bulk density)
AS 1038 Parts 1-11
AS 1038 Part 1-1980
AS 1038 Part 3-1989
AS 1038 Part 5-1989
AS 1038 Part 6-1986
AS 1038 Part 8-1980
AS 1038 Part 11-1982
AS 1038 Part 121-1984
AS 1038 Part 141-1981
AS 1038 Part 15-1972
AS 1038 Part 17shy
AS 1038 Part 20-1981
AS 1038 Part 22-1983
AS 2486-1981
AS 2515-1981
AS 3381-1991
AS 3899-1991
Methods for the analysis and testing of coal and coke (metric units)
Total moisture in hard coal
Proximate analysis of hard coal
Gross specific energy of coal and coke
Ultimate analysis of coal
Chlorine in coal and coke
Forms of sulphur in coal
Determination of crucible swelling number of coal
Analysis of coal ash coke ash and mineral matter (borate fusion-flame atomic absorption method)
Fusibility of coal ash and coke ash
Size analysis of hard coal
Determination of Hardgrove Grindability Index of hard coal
Determination of mineral matter and water of hydration of minerals in coal
Microscopical determination of the reflectance of coal macerals
Determination of the maceral group composition of bituminous coal and anthracite (hard coal)
Size analysis of hard coal
Higher rank coals and coke - bulk density
British Standards Institution Sales Office Linford Wood Milton Keynes MK14 6LE UK
BS 1016 Parts 1-20
BS 1016 Part 1-1989
BS 1016 Part 3-1973
BS 1016 Part 5-1977
Methods for the analysis and testing of coal and coke
Total moisture of coal
Proximate of analysis coal
Gross calorific value of coal and coke
118
Appendix
DIN 51 717-1967
DIN 51 718-1978
DIN 51 719-1978
DIN 51 720-1978
DIN 51 721-1950
DIN 51 722shy
DIN 51 724-1975
DIN 51 726-1980
DIN 51 727-1976
DIN 51 729shy
DIN 51 730-1976
DIN 51 741-1974
DIN 51900shy
Bestimmung der Trommelfestigkeit und des Abriebs von Steinkohlenkoks (Detennination of abrasion indexdrum strength and abrasion of hard coal coke)
Bestimmung des Wassergehaltes (Detennination of water content)
Bestimmung des Aschegehaltes (Detennination of ash content)
Bestimmung des Gehaltes an Fliichtigen Bestandteilen (Detennination of volatile matter content)
Bestimmung des Gehaltes an Kohlenstoff und Wasserstoff (Detennination of content of carbon and hydrogen)
Bestimmung des Stickstoff-Gehaltes (gilt nur fur Kohlen) (Detennination of nitrogen (for coal only)
Bestimmung des Schwefelgehaltes Gesamtschwefel (Part 1 Detennination of sulphur content and total sulphur)
Bestimmung des Gehaltes an Carbonat-Kohlenstoff-dioxid (Detennination of content of carbonate carbon dioxide)
Bestimmung des Chlorgehaltes (Detennination of chlorine content)
Bestimmung der chemischen Zusammensetzung von Brennstoffasche (Detennination of chemical composition of fuel ash)
Bestimmung des Asche-Schmelzverhaltens (Detennination of ash melting behaviour)
Bestimmung der BHihzahl von Steinkohle (Determination of swelling capacityindex)
Priifung fester und fliissiger Brennstoffe Bestimmung des Brennwertes mit dem Bomben-Kalorimeter und Berechnung des Heizwertes (Testing of solid and liquid fuels detenninationlanalysis of the
heating value by bomb-calorimeter and calculation of the heating value)
Teil 2 - 1977 Verfahren mit isothermem Wassermantel (Part 2 Methods with isothermal water jacket)
Teil 3 - 1977 Verfahren mit adiabatischem Mantel (Part 3 Methods with adiabatic jacket)
International Organization for Standardization Casa Postale 56 CH 1211 Geneva 20 Switzerland
ISO 157-1975
ISO 331-1983
ISO 332-1981
ISO 334-1975
ISO 352- 1981
ISO 501-1981
ISO 540-1981
ISO 562-1981
ISO 589-1981
ISO 602-1983
ISO 625-1975
ISO 925
ISO 1018-1975
ISO 1171-1981
Hard coal - Detennination of forms of sulphur
Coal - Detennination of moisture in the analysis sample - Direct gravimetric method
Coal - Detennination of nitrogen shyMacro Kjeldahl method
Coal and coke - Detennination of total sulphur - Eschka method
Solid mineral fuels shyDetennination of chlorine - High temperature combustion method
Coal - Detennination of the crucible swelling number
Solid mineral fuels shyDetennination of fusibility of ash shyHigh temperature tube method
Hard coal and coke shyDetennination of volatile matter content
Hard coal - Detennination of total moisture
Coal - Detennination of mineral matter
Coal and coke - Detennination of carbon and hydrogen - Liebig method
Coal - Determination of carbon dioxide
Hard coal - Detennination of moisture-holding capacity
Solid mineral fuels shyDetennination of ash
119
List of standards referred to in the report
ISO 1921-1976
ISO 1953-1972
ISO 1994-1976
ISO 5074-1980
Solid mineral fuels shyDetermination of gross calorific value by the calorimeter bomb method and calculation of net calorific value
Hard coals - Size analysis
Hard coal - Determination of oxygen content
Hard coal - Determination of Hardgrove grindability index
ISO 7404 Part 3-1984
ISO 7404 Part 5-1984
Methods for the petrographic analysis of bituminous coal and anthracite Part 3 Method of determining maceral group composition
Methods for the petrographic analysis of bituminous coal and anthracite Part 5 Method of determining microscopically the reflectance of vitrinite
120
Related publications
Further lEA Coal Research publications on coal utilisation are listed below
Advanced coal cleaning technology G R Couch IEACRl44 ISBN 92-9029-197-4 95 pp December 1991
Power station refurbishment opportunities for coal D H Scott IEACRl42 ISBN 92-9029-195-8 58 pp October 1991
On-line analysis of coal A T Kirchner IEACR140 ISBN 92-9029-193-1 79 pp September 1991
Coal gasification for IGCC power generation Toshiishi Takematsu Chris Maude IEACR137 ISBN 92-9029-190-7 80 pp March 1991
Lignite upgrading G R Couch IEACRl23 ISBN 92-9029-176-172 pp May 1990
Power generation from lignite G R Couch IEACRl19 ISBN 92-9029-170-2 67 pp December 1989
Lignite resources and characteristics G R Couch IEACRl13 ISBN 92-9029-163-X 100 pp December 1988
Coal-fired MHD G F Morrison IEACRl06 ISBN 92-9029-151-6 32 pp April 1988
Biotechnology and coal G R Couch ICTISfTR38 ISBN 92-9029-147-8 56 pp March 1987
Understanding pulverised coal combustion G F Morrison ICTISfTR34 ISBN 92-9029-138-9 46 pp December 1986
Atmospheric f1uidised bed boilers for industry I F Thomas ICTISfTR35 ISBN 92-9029-136-2 69 pp November 1986
All reports are priced at pound60pound180 (membernon-member countries)
Other lEA Coal Research pUblications Details of lEA Coal Research publications are available from
Reviews assessments and analyses of supply transport and markets lEA Coal Research coal science Gemini House coal utilisation 10-18 Putney Hill coal and the environment London SW15 6AA
United Kingdom Coal abstracts Coal calendar Tel (0)81-7802111 Coal research projects Fax (0)81-7801746
Coal specifications - impact on power station performance
Nina M Skorupska
IEACRl52 January 1993 lEA Coal Research London
Copyright copy lEA Coal Research 1993
ISBN 92-9029-210-5
This report produced by lEA Coal Research has been reviewed in draft fonn by nominated experts in member countries and their comments have been taken into consideration It has been approved for distribution by the Executive Committee of lEA Coal Research
Whilst every effort has been made to ensure the accuracy of information contained in this report neither lEA Coal Research nor any of its employees nor any supporting country or organisation nor any contractor of lEA Coal Research makes any warranty expressed or implied or assumes any liability or responsibility for the accuracy completeness or usefulness of any information apparatus product or process disclosed or represents that its use would not infringe privately-owned rights
lEA Coal Research
lEA Coal Research was established in 1975 under the auspices of the International Energy Agency (lEA) and is currently supported by fourteen countries (Australia Austria Belgium Canada Denmark Finland Germany Italy Japan the Netherlands Spain Sweden the UK and the USA) and the Commission of the European Communities
lEA Coal Research provides information and analysis of all aspects of coal production and use including
supply transport and markets coal science coal utilisation coal and the environment
lEA Coal Research produces
periodicals including Coal abstracts a monthly current awareness journal giving details of the most recent and relevant items from the worlds literature on coal and Coal calendar a comprehensive descriptive calendar of recently-held and forthcoming meetings of interest to the coal industry technical assessments and economic reports on specific topics throughout the coal chain bibliographic databases on coal technology coal research projects and forthcoming events and numerical databanks on reserves and resources coal ports and coal-fired power stations
General enquiries about lEA Coal Research should be addressed to
Mr John Trubshaw Head of Service lEA Coal Research Gemini House 10-18 Putney Hill London SW 15 6AA United Kingdom
Telephone (0)81-780 2111 Fax (0)81-7801746
3
Abstract
This report examines the impacts of coal properties on power station perfonnance As most of the coal used to generate electricity is consumed as pulverised fuel the focus of the report is on performance in pulverised fuel (PF) power station units The properties that are currently employed as specifications for coal selection are reviewed together with their influence on power station performance Major coal-related items in a power station are considered in relation to those properties which affect their performance There is a review of tools being used for coal selection and prediction of station performance which includes an overview of the types of computer models that are available and those that are being developed
The principal coal properties that were found to cause greatest concern to operators included the ash sulphur moisture and volatile matter contents heating value and grindability Little has changed over the years in the way that coal is assessed and selected for combustion Operators continue to use tests as specifications that were mostly developed for coal uses other than combustion Because the procurement specifications are based on tests which do not relate well to actual practice there is still a need for expensive large scale test burns to confIrm suitability With the advances that have been made in computer technology there is a growing number of utilities that are adopting expert unit or integrated models that aid in the planning and operation of generating units Others have shown scepticism over the capability of devising a truly representative model of a coal combustion plant using the coal data produced from current testing procedures
Specific requirements that have been identified include the need to develop internationally acceptable methods of defining coal characteristics so that combustion plant perfonnance can be predicted more effectively There is also a need to establish economic parameters which can serve to measure the effects of coals on plant performance and hence on the cost of electricity
4
Contents
List of figures 7
List of tables 9
Acronyms and abbreviations 11
1 Introduction 13 11 Background 13
2 Coal specifications 15 21 Proximate analysis 17 22 Ultimate analysis of coal 20 23 Ash analysis and minerals 21 24 Forms of sulphur chlorine and trace elements 23 25 Coal mechanical and physical properties 23 26 Calculated indices 28 27 Comments 28
3 Pre-combustion performance 29 31 Coal handling and storage 29
311 Plugging and flowability 32 312 Freezing 34 313 Dusting 35 314 Oxidationspontaneous combustion 36
32 Mills 37 321 Drying 37 322 Grinding 38 323 Size classification and transport 42
33 Fans 42 34 Comments 45
4 Combustion performance 46 41 Burners 46 42 Steam generator 47
421 Combustion characteristics 47 422 Ash deposition 49
43 Comments 56
5
5 Post-combustion performance 57 51 Ash transport 57 52 Environmental control 58
521 Coal cleaning 59 522 Fly ash collection 60 523 Technologies for controlling gaseous emissions 63 524 Solid residue disposal 65
53 Comments 67
6 Coal-related effects on overall power station performance and costs 68 61 Capital costs 68 62 Cost of coal 68 63 Power station perfonnance and costs 69
631 Capacity 69 632 Heat rate 69 633 Maintenance 74 634 Availability 76
64 Comments 77
7 Computer models 79 71 Least cost coalcoal blend models 80 72 Component evaluation models 81 73 Unit models 82
731 Statistically-derived regression models 82 732 Systems engineering analysis 88 733 Integrated site models 97
74 Comments 99
8 Conclusions 101
9 References 104
Appendix List of standards referred to in the report 117
6
Figures
Schematic diagram of the coal-to-electricity chain 14
8 Three-day consolidation critical arching diameter (CAD)
18 Influence of ash characteristics of US coals on
23 Resistivity results for both power station fly ash and
2 Comparison of different coal classification systems 18
3 Mill throughput as a function of Hardgrove grindability index 24
4 Critical temperature points of the ash fusion test 25
5 Typical power station components 29
6 Typical flow patterns in bunkers 32
7 Surface moisture versus critical arching diameter (CAD) determined from shear tests 33
versus per cent fines in coal as a function of moisture content 33
9 Dewatering efficiency versus temperature 34
10 Size distributions of Australian export coal 35
11 Coal lift-off from a stockpile as a function of total moisture content 35
12 Influence of storage time on swelling index 37
13 Primary air temperature requirements depending on moisture content and coal type 39
14 Variation in capacity factor with HGI for different fineness grinds 40
15 HGI for several coals as a function of rank 41
16 Typical utility boiler fan arrangement 43
17 Fuel ratio as an indicator of coal reactivity 48
furnace size of 600 MW pulverised coal fired boilers 49
19 Mechanisms for fly ash formation 50
20 Heat flux recovery for different coals and soot blowing cycles 52
21 Effect of CaO and MgO on corrosivity deposit 53
22 Typical ash distribution 58
laboratory ash from Tallawarra power station feed coal 62
7
24 Laboratory resistivity curves of ash from a South African coal and from a blend of South African and Polish coals against temperature 62
25 Effects of grindability on vertical spindle pulveriser performance 72
26 Example of cost impact of a coal change on heat rate for a 1000 MW boiler 74
27 Adjusted maintenance cost accounts for TVAs Cumberland plant 75
28 Causes of coal-related outages 76
29 Boiler and boiler tubes equivalent availability factor (EAF) record 77
30 Mill engineering model analysis approach 82
31 Comparison of TVA and EPRI availability correlations to a 1000 MW boiler 85
32 Comparison of ash and H20 effects on boiler efficiency and gross heat rate 86
33 Outline of CIVEC model operation 87
34 CQEA evaluation of the impact of different coals on overall production costs of one unit 92
35 Equipment types modelled by CQIM 92
36 Major components of the CQE system 94
37 Correlations of forced outage hours against ash throughput using the CQI model 95
38 Schematic showing the structure of the C-QUEL system 97
39 Comparison of the operations with and without the use of the C-QUEL 98
8
5
10
15
20
25
Tables
1 Summary of coal quality requirements for power generation 16
2 Coal composition parameters standard measurements 17
3 Analysis of a given coal calculated to different bases 18
4 Rank and coal properties 19
Minerals in coal 22
6 Coal mechanical and physical parameters standard measurements 24
7 A summary of the major characteristics of the three maceral groups in hard coals 25
8 Summary of coal ash indices 26
9 lllustrative example of USA coal storage requirements 30
Conveyor Equipment Manufacturers Association (CEMA) material classification chart 31
11 CEMA codes for various coals 32
12 Analysis of ash and clay distribution in a coal by mesh size 33
13 Effect of coal properties on critical lift-off moisture content 35
14 Preferred range of coal properties 37
Maximum mill outlet temperatures for vertical spindle mills 38
16 Comparison of fineness recommendations 38
17 Summary of the effects of coal properties on power station component performance - I 44
18 Enrichment of iron in boiler wall deposits shycomparison of composition of ash deposits and as-fired coal ashes 52
19 Hardness of fly ash constituents 54
Properties of some coal ash components 54
21 Summary of the effects of coal properties on power station component performance - II 56
22 Summary of coal cleaning effects on boiler operation 59
23 Effect of coal type on total concentrations of selected elements from fly ash samples 65
24 Summary of the effects of coal properties on power station component performance - III 66
The effect of coal quality on the costs of a new power station 68
9
26 Ash contents of traded coals 69
31 Examples of boiler frreside variables station and cost
33 Comparison of coal energy costs based on gross heating
27 Calculation of boiler heat losses 70
28 Typical boiler losses for four Australian Queensland steaming coals 71
29 Total fuel costs for power stations of the Southern Company USA 75
30 Comparison of reduced boiler availability on the basis of hours in operation and type of fuel 76
components which may be affected by those variables when coal quality is changed 78
32 Model input output data - International Coal Value Model (ICVM) 80
value (at power station pulverisers) - in order of increasing cost 80
34 Boiler groupings in TVA study 83
35 TVA study - maintenance costs plant correlations for all coal-related equipment 84
36 NERA study - gross heat rate correlation 85
37 ClVEC coal specifications input 88
38 ClVEC power station operational parameters 89
39 ClVEC factors contribution to utilisation value 89
40 Model input output data - COALBUY 90
41 Model input output data - Coal Quality Advisor (CQA) 90
42 Model input output data - Coal Quality Engineering Analysis (CQEA) 91
43 Model input output data - Coal Quality Impact Model (CQIM) 93
44 Ranges of selected coal-ash combustibility parameter that predict approximate classification of CF values 94
45 Model input output data - IMPACT 95
46 Assessment of four coals for Fusina unit 3 using the CQI model 96
47 Summary of model types and capabilities 99
48 Summary of the impacts of coal quality on power station performance 102
10
Acronyms and abbreviations
ad AP ARA ASTM BSl Btu CAD CCSEM CEMA CGI cif CPampL CQA CQEA CQE CQIM CSIRO daf DIN dmmf DTF EEl EFR EPRl ESP FD FEGT FFV FGD FGET FGR fob FTIR GADS GHR GP HGI HLampP HR
air-dried auxiliary power Acid Rain Advisor American Society for Testing and Materials British Standards Institution British thermal unit critical arching diameter computer controlled scanning electron microscopy Conveyor Equipment Manufacturers Association continuous grindability index cost insurance freight Carolina Power and Light Company Coal Quality Advisor Coal Quality Engineering Analysis Coal Quality Expert Coal Quality Impact Model Commonwealth Scientific and Industrial Research Organisation (Australia) dry ash-free Deutsches Institut rur Normung (Germany) dry mineral matter-free drop tube furnace Edison Electric Institute (USA) entrained flow reactor Electric Power Research Institute (USA) electrostatic precipitator forced draft furnace exit gas temperature flow factor value flue gas desulphurisation flue gas exit temperature flue gas recirculation free on board Fourier transform infrared Generating Availability Data System (USA) gross heat rate gross power Hardgrove grindability index Houston Lighting amp Power Company (USA) heat rate
11
ICVM ill IEEE IFRF ISO LCFS kWh MCR MJlkg MWe MWh NERA NERC NHR nm NOx
NYSEG OGampE OampM PA PF PGNAA PN PP ppm ROM SCR SNCR TGA THR TVA UDI UK USA US DOE
International Coal Value Model induced draft Institute of Electronic and Electrical Engineers (UK) International Flame Research Foundation (The Netherlands) International Organization for Standardization Least cost fuel system kilowatt hour maximum continuous rating megajoule per kilogram megawatt (electrical) megawatt hours National Economic Research Associate (USA) North American Electric Reliability Council (USA) net heat rate nanometres nitrogen oxides New York State Electric amp Gas Company (USA) Oklahoma Gas amp Electric Company (USA) operation and maintenance primary air pulverised fuel Prompt Gamma Neutron Activation Analysis Polish Standards Committee Pacific Power parts per million run-of-mine selective catalytic reduction selective non-catalytic reduction thermal gravimetric analysis turbine heat rate Tennessee Valley Authority (USA) Utility Data Institute (USA) United Kingdom United States of America United States Department of Energy
12
1 Introduction
This report examines the impacts of coal properties on power stations buming pulverised fuels (PF) The properties that are currently examined when defining specifications for coal selection are reviewed together with their influence on power station performance The main power station components are considered in relation to those coal properties which affect their performance There is a review of tools being used for coal selection and prediction of station performance which includes an overview of the types of computer models that are both available and under development
In support of the study lEA Coal Research conducted a survey by questionnaire of power stations in 12 countries to obtain additional information about utility practice and experience of the effects of coal quality on power station performance The responses of station operators and research specialists to the questionnaire were of considerable value and much appreciated
11 Background Utilities are continually striving to produce power at the lowest possible cost This means that power stations must operate at optimal availability and rated output while maintaining efficient operation and maintenance schedules At the same time they must also meet relevant emission requirements
Operators of coal-frred stations have long known that coal composition and characteristics signifIcantly affect operation on a broad front Because a power station is a complex interrelated system a change in one area such as coal quality can reverberate throughout the whole system Figure 1 shows a schematic diagram of the coal-to-electricity chain To generate electricity to the busbar at minimum cost it is necessary to evaluate the total cost associated with each coal This includes the cost of any coal-related effects on the performance and availability of
power station components as indicated by Sections 4-7 in Figure 1 in addition to the delivered cost of the coal It is estimated that coal quality factors can contribute up to 60 of all unscheduled outages of coal-fired stations (Mancini and others 1988)
In some cases utilities have the opportunity to fire a range of coals in their power stations In general power stations have a design coal analysis with which initial performance guarantees are met It is also usual to have an allowable range for the most important coal properties within which it is expected that full load may be produced although possibly at reduced efficiencies Substantial deviations in one or more of the properties may result in impaired plant performance or even serious operating and maintenance problems
The quality of coal supplied to a power station may vary for many reasons including
typical day-to-day seam variations in individual coals longer term variations in coal quality due to seam depletion andor change of mining method inconsistencies due to inadequate preparation or poor quality control at the mine site variation in proportions of coals supplied from several traditional supply sources replacement of traditional supplies with sources with different properties due to changing availability or price switchinglblending requirements to meet changing emissions regulations intentional change of fuel quality to solve existing performance problems heavy reliance on recoveries from old stockpiles effects of weather
In order to select a coal supply utilities must try to predict the impacts of alternative coals on power station performance and overall power generation costs Since the type and design of boiler and auxiliary equipment are fixed the coal is
13
6
Introduction
PREPARATION PLANT TRANSPORTMINE
2 3
Figure 1 Schematic diagram of the coal-ta-electricity chain
usually selected to match these rather than the reverse There are numerous methods employed to help select an appropriate coal These can range from selecting coals on the basis of a limited number of design specifications based on proximate analysis through use of sophisticated computer models describing overall performance to expensive full
4 5
HANDLING AND MILLING
STORAGE
PARTICULATES REMOVAL - COMBUSTION~ bull
6B FGD
6C
WASTE DISPOSAL
9
ADDITIONAL UNIT
GENERATION CAPACITY
STEAM 7TURBINE
ELECTRICITY TO 8BUSBAR
scale test firing of sample loads over a limited time period It is recognised that a wide range of complex physical and chemical processes occur during preparation and combustion and so it is not surprising that these methods may still prove to be inadequate in providing a quantitative understanding of the impacts of coal quality
14
2 Coal specifications
The criteria for including particular properties of a coal in a specification used for a particular power station are varied Basic coal contracts can include as few as three or four base quality guarantees - stipulating a range of values for heating value ash content moisture and more recently sulphur More typical purchasing specifications incorporate additional properties such as volatile matter fixed carbon ash fusion temperatures grindability along with the base level specifications of heating value ash moisture and sulphur (Schaeffer 1988) More recently these have been expanded by some utilities to include trace element details and the petrographic composition of the coal Table 1 summarises the typical coal quality requirements for power generation The specification values indicated are derived from both the literature and analysis of the results obtained from the survey of boiler operators
Most of the properties described in Table 1 are measured using relatively simple standard tests More recently some coal specifications have emerged which appear even more complex and restrictive In addition to the standard characterisation tests they may include non-standard characterisation and combustion tests such as the use of thermal gravimetric analysers drop-tube furnaces and pilot-plant tests (see Section 42) It has been argued that such detailed specifications are not necessary (OKeefe and others 1987) may be excessively restrictive and could lead to increasing fuel cost as specific sources are no longer available (Mahr 1988 Harrison and Zera 1990) The advocates for detailed specifications argue that to use only a basic fuel specification for selection will leave the market open for many coals which may not perform as well as the design-specification coal (Vaninetti 1987 Myllynen 1987) They will most likely be attractively priced (Corder 1983 OKeefe and others 1987) but there is no assurance that the saving will necessarily minimise the overall cost of power generation In many cases buying the coal of lowest price can be false economy (see Chapter 6) for example if the coal adversely affects heat rate additional coal will be
needed If the selected coal cannot sustain full unit capacity or causes additional outages (availability loss) alternative units must be operated to make up the lost power possibly at considerable additional cost Also increased maintenance costs add directly to the total cost of power generation (Folsom and others 1986a Sotter and others 1986 Yarkin and Novikova 1988 Ziesmer and others 1991 Bretz 1991a)
Blending to meet quality specifications is gaining acceptance In most cases power stations do not fire only coal from a single seam in their boilers As coal occurs in heterogeneous deposits the supply from any mine is already a blend of material from different seams to meet the required specification This principle may be extended such that coals supplied to power stations can be blends from several different sources prepared at handling centres such as at Rotterdam The Netherlands (Rademacher 1990) Power stations themselves may have facilities for blending two or more coals on site Separately the coals may not meet specification but a homogeneous mix does (Ratt 1991) Most countries which depend solely on imported coals have commercial strategies stipulating that no single source should account for more than 40 of supply (Klitgaard 1988) Blending which extends the range of acceptable coals increases the number of supply opportunities It should be noted that the non-additive nature of some of the standard tests such as ash fusion tests and use of HGI values (see Section 25) makes blend evaluation for power station use inherently complex (Riley and others 1989)
The following sections examine the coal properties used in coal specifications and evaluate their significance in power station operation
Table 2 lists eighteen standard methods of measuring coal composition together with an indication of the relevance of the results to the utility industry As illustrated in Table 2 the key measurement methods are proximate analysis
15
Coal specifications
Table 1 Summary of coal quality requirements for power generation
Parameter Desired Typicallimits
Heating value (ar) MJkg high min 24-25 (23) Proximate analysis - Total moisture (ar) 4-8 max 12
- Ash (mt) low max 15-20 (max 30) - Volatile matter (rot) 20-35 min 20 (23) - side-fIred furnaces
15-20 max 20 - down-fIred pf furnaces Total sulphur (mt) low max 05-10 - dependent on local pollution regulations
Hardgrove grindability index (HGI) high
Maximum size mm 130-40 Fines less than 05 mm (15 max)
Proximate analysis Ultimate analysis
Chlorine (rot)
Ash analysis weight of ash
Ash fusion temperatures degC
Swelling index Ash resistivity Handleability
Trace elements
Vitrinite reflectogram
Maceral analysis
- Fixed carbon (rot) - Carbon (daf)
- Hydrogen (daf)
- Nitrogen (dat) low - Sulphur (dat)
- Oxygen (by diff daf) low
Silicon dioxide (Si02) Aluminium oxide (Ah03) Titanium oxide (Ti02) Ferric oxide (Fe203) Calcium oxide (CaO) Magnesium oxide (MgO) Sodium oxide (Na20) Potassium oxide (K20) Sulphite (SOn Phosphorus pentoxide (P20 S)
- initial deformation high - softening (H = W) high - hemispherical (H =lizW) high - fluid high
low ohmem at 120degC
As Cd Co Cr Cu
Hg Ni Pb Sb Se Tl Zn
Vitrinite Exinite Inertinite Mineral
min 50-55 (min 39) 50 limited by size accepted by pulveriser
limited for handling characteristics
(08-11)
max 01--03 (max 05)
(45-75) (15-35) (04-22) (1-12) (01-23) (02-14) (01--09) (08-26) (01-16) (01-15)
(gt1075) in reducing conditions (gt1150) for dry bottom furnaces (gt1180) Values are much lower for wet bottom (gt1225) furnaces
(max 5) if available if available
Declaration of presence
if available
55-80 5-15 10-25 to declare
Typical limits refer to those commonly quoted those in brackets indicate outer limits acceptable in some cases
Measurement basis ar shy as received mf - moisture free daf - dry ash-free
16
Coal specifications
Table 2 Coal composition parameters standard measurements (after Folsom and others 1986c)
Measurement Method Standards procedure
ASTM AS BS DIN ISO
Parameters measured
Relationship to power station performance
Proximate analysis 03172-89 Moisture D3173-87 Volatile matter D3175-89 Ash D3174-89 Fixed carbon
Ultimate analysis 03176-89 Oxygen Carbon 03178-89 Hydrogen 03178-89 Nitrogen 03179-89 Total sulphur 03177-83
10383-89 10383-89 10383-89 10383-89 10388-89
10386-86
103861-86 103861-86 103862-86 103863-86
10163-73 10163-73 10163-73 10163-73 10163-73
10166-77 10166-77 10166-77 10166-77 10166-77 10166-77
51700-67 51718-78 51720-78 51719-78
51700-67
51721-50 51721-50 51722 517241-75
331-83 562-81 1171-81
1994-76 625-75 625-75 332-81 334-75
H20 Ash VM FC
Part of proximate analysis
C H 0 N S Ash H2O
) Pm of 1_ analysis
These parameters affect all power station systems since they are the principal constituents of coal
Ash analysis D2795-89 AA-Elemental ash analysis Major 03682-87 AA-Elemental ash
1038141-81
1038141-81
101614-79
101614-79
51729-80
analysis Trace 03683-78 Mineral matter C02 in coal D1756-89 Forms of sulphur D2492-90 Chlorine D2361-91 Total moisture D3302-89 Equil moisture D1412-89
1038104-86 103822-83 103823-84 103811-82 10388-80 10381-80 103817-89
10166-77 101611-87 10168-84 10161-89 101621-87
51726 517242 51727-76 51718
602-83 925-80 157-75 352-81 589-81 1018-75 Surface moisture
Corrosion slagging fouling
Handling amp pulverisation
Proximate analysis by instrumental procedures D5142-90
AA Atomic Adsorption ASTM American Society for Testing and Materials AS Australian Standards
BS British Standards Institution DIN Deutsches Institut fur Normung ISO International Organization for Standardization
ultimate analysis and ash analysis Additionally other early 1800s at a time when carbonisation was the most chemical analyses are often carried out on coal samples important use of coal It was a means of broadly assessing Some of these tests are used to enable correction of the bulk distribution of products obtainable from a coal by proximate and ultimate analysis data to allow for mineral destructive distillation (Elliott 1981) It is widely accepted matter constituents while others are used to evaluate the by the utility industry and forms the basis of many coal coals suitability for specific purposes In most coal qualitypower station performance correlations The great producing and consuming countries national or international advantage of the tests required for proximate analysis is that standard techniques are used The titles of the standards they are all quite simple and can be performed with basic reported in this chapter and the addresses of the standards laboratory equipment So much so that they have been fully organisations are given in the Appendix automated in recent years The results of proximate analysis
although endorsed with long history and extensive Common causes of confusion in the comparison of coal and experience are empirical and only applicable if the tests are interpretation of analytical data as reviewed by Carpenter carried out under strict standardised conditions The five (1988) are characteristics obtainable from the procedure are
the different domestic and international coal total moisture classification schemes used (see Figure 2) air-dried moisture the wide range of analytical bases on which the coal data volatile matter may be reported and the failure of many workers to ash identify clearly the basis for their results Table 3 fixed carbon illustrates how results will vary for a single coal depending on the base used Proximate analysis reports moisture in only two categories
as total and air-dried although it actually occurs in coals in different forms Air-dried moisture is also referred to as21 Proximate analysis inherent moisture The total moisture of coal consists of
The proximate analysis of coal is the simplest and most surface and inherent moisture Surface moisture is the common form of coal evaluation It was introduced in the extraneous water held as films on the surface of the coal and
17
----- ---
---
01
Coal specifications
Volatile Australia
301a
302
303
301b 302 303
401-901 high volatile A bituminous
402-702 coal402 class 7 Ihigh volatile B bituminous
coal 902 high volatile
class ~inouscoal
I subbituminousclass subbituminous
B coal 11 A coal subbituminous
class ~
approximate C coal 12 volatile matter
f-- shy dmmf lignite A class class 6 32-40
13 class 7 32-43 class 8 34-49
class ~
class 9 41-49
-14 lignite B
class
-15
matter dmmf
2 6 8 9
10 115 135
14 15 17
195 20 22 24
275 28 31 32 33
36
44J
47J
Great Britain NCB
101 anthracite
102
201a dry Ol ~~ 201b I~~~I~ COcgt
202 ~EgE- co co ~co203 -OlO 02 -en8en t)204
FRG
meta-anthracite
anthracite
lean (non-caking)
coal
forge coal
fat (coking) coal
hard coals
gas coal
tgas flame coal
flame coal
shiny hard
brown coal
matt
soft brown coal
MJkg class 6 326
class 7
302 class 8
class 9 -256
- 221 soft
193 brown coals
147
Heating value MJkg
N S
173 131
179 136
198 151
gross net
3168 3067
3279 3175
3635 3520
-
medium volatile coals
30shy
40shy
50shy
60shy
70shy
International hard coals
class 0
class 1A
class 1B
class 2
class 3
class 4
hardclass 5 coals
class 6 moi sture
high ~ f 0Yo
brown coals
volatile I coals
and I
I~ class 8
-1Q class 9- - 20shy
North America ASTM
Imeta-anthraciteI
anthracite
semi-anthracite
low volatile bituminous
coal
medium volatile
bituminous coal
Calorific value mmmf
hard coals
class 1
class 2
class 3
class 4A
class 4B
hardclass 5 coals
Figure 2 Comparison of different coal classification systems (Couch 1988)
Table 3 Analysis of a given coal calculated to different bases
Condition or basis
Proximate analysis
H2O VM FC Ash
Ultimate analysis
C H 0
As received 339 2061 6653 947 7729 459 561
Dry 2133 6887 980 8000 436 269
Dry ash-free 2365 7635 8869 483 299
Analysis of US Pennsylvania Somerset County Upper Kittaning Bed No 3 Mine
In the ultimate analysis moisture on an as received basis is included in the hydrogen and oxygen Net heating value is calculated from the gross value using the relationship in ISO 1928
its content can vary in a coal over time The moisture present water is difficult to control separate assessment of inherent in other forms is regarded as the inherent moisture it is or air-dried moisture is also necessary as most other more or less constant for coals of a given rank (Ward 1984) analyses are carried out on air-dried material
A coal that is sold commercially usually contains a certain Surface moisture is important to the handleability of coal amount of surface moisture which forms part of the total (see also Section 31) With a content greater than 12 of weight of coal delivered Knowledge of the total moisture the coal weight problems such as bridging in bunkers and content of the coal is therefore essential to assess the value of blocking of feeders can be expected in the transport system any consignment However because the amount of surface (Cortsen 1983) In cold climates the excess surface moisture
I
18
Coal specifications
may freeze and act as a binder so incurring coal handling problems (Raask 1985)
Extremely low surface moisture content can cause environmental problems due to dust and enhanced risks of fire due to coal oxidation which causes heating and may lead to spontaneous combustion especially in low rank coals (see
also Sections 313 and 314)
Surface moisture and part of the inherent moisture of a coal can be released in the mills during grinding This means that the mill inlet or primary air temperature prior to milling must be increased for coals with a high total moisture content The surface moisture of the coal is converted to vapour during milling and forms part of the coal-air mixture in direct feed systems The vapour enters the furnace where it can cause a delay in coal ignition and increase flame length The effect however is small for coals with moisture contents not exceeding 10
The inherent moisture has a more direct influence on coal ignition and combustion Significant gasification of the coal particle to release combustible gases cannot start prior to the evaporation of the moisture from within the particle When firing a coal with a high inherent moisture content conditions can also be improved by increasing mill air inlet temperature
Total moisture in the coal contributes to the overall gas flow in the form of vapour (Cortsen 1983) This can influence the operation of fans that move the air flue gas and pulverised coal through the unit An increase in coal moisture will increase the flue gas volume flow rate thus necessitating an increased power requirement for the fans (see Section 33)
During the combustion process coal releases volatiles which include various amounts of hydrogen carbon oxides methane other low mOlecular weight hydrocarbons and water vapour Volatile yield of a coal is an important property providing a rough indication of the reactivity or combustibility of a coal and ease of ignition and hence flame stability The amount of volatiles actually released in practice is a function of both the coal and its combustion conditions including sample size particle size time rate of heating and maximum temperature reached In order to obtain a method for comparing coals a simple test was devised to obtain a value for the volatile matter content of a coal The volatile matter content as determined by proximate analysis represents the loss of weight corrected for moisture when the coal sample is heated to 900degC in specified apparatus under standardised conditions
Typical values of volatile matter content associated with different ranks of coal as determined by proximate analysis are given in Table 4 (Cunliffe 1990) It should be noted that some of the volatile matter may originate from the mineral matter present
The volatile matter content of a coal is used to assess the stability of the flame after ignition Under the same combustion conditions that is same burner configuration and amount of excess air a coal with a high volatile matter content will usually give stable ignition and a more intensive
Table 4 Rank and coal properties (Cunliffe 1990)
Type C H 0 Volatile Heating
(composition ) matter value daf MJkg
Wood 500 60 430 800 146
Peat 575 55 350 684 159
Lignite 700 50 230 526 216
Bituminous High volatile 770 55 150 421 258
Medium volatile 860 50 45 263 335
Low volatile 905 45 30 188 348
Semi-anthracite 905 45 30 188 348
Anthracite 940 30 15 41 346
daf dry ash-free basis
flame compared with a coal with a low volatile matter content Maintaining stable ignition is one of the most crucial aspects of pulverised coal firing since instability necessitates the use of pilot fuel and in extreme cases may incur the risk of furnace explosion (Cortsen 1983) Low laquo20) volatile matter coals can produce high-carbon residue ash In order to combat this adverse effect the coal would require extra-fine milling and combustion in boilers with a long flame path (Raask 1985) A high volatile matter content (gt30) can cause mill safety problems This is due to the increased possibility of mill fires resulting from spontaneous combustion of the coal (see Section 32) Volatile matter content values are often used to calculate combustibility indices which are used as an indication of the reactivity of a coal They are also included in formulae for the prediction of NOli release during coal combustion (Kok 1988)
Ash is the residue remaining following the complete combustion of all coal organic material and oxidation of the mineral matter present in the coal Ash is commonly used as an indication of the grade or quality of a coal since it provides a measure of the incombustible material present in the coal A higher ash content means a lower heating value of the coal as ash does not contribute any energy to the system It represents a dead weight during coal transport to and through a power station (Lowe 1988a) In order to maintain boiler output when switching from a low ash coal to another with similar specification but a higher ash content an increased throughput of material would be required to achieve the same loading Alternatively power station output may be constrained by the lack of capacity in the ash handling system
Ash content and its distribution within the coal influences ignition stability The transformation of mineral matter to ash is an endothermic reaction - requiring energy Thus some coal particles containing a high proportion of mineral matter may not ignite satisfactorily In some cases stack and unburnt carbon losses have been shown to increase as the heating value of the coal decreases with increased ash content A high-ash content may lower the accessibility of the carbon to combustion within the particle (Kapteijn and others 1990) In contrast to these situations Australian power stations have been known to combust coals with a
19
Coal specifications
high ash (gt25) content without support fuel satisfactorily (Sligar 1992)
High ash coals (gt20) can cause abrasion and particle impaction erosion wear of fuel handling plant mills burners boiler tubes and ash pipes if the plant is not designed for this (Raask 1985) Utilisation of a high ash coal may impair the performance of particulate control devices by ash overloading There may also be problems of accommodating higher ash levels for disposal (Bretz 1991b)
Possibly the most serious effects that ash constituents have upon the boiler performance are those connected with fouling slagging and corrosion of the heating surfaces These problems are discussed in Section 422
The fixed carbon content of coal is not measured directly but represents the difference in an air-dried coal between 100 and the sum of the moisture volatile matter and ash contents It still contains appreciable amounts of nitrogen sulphur hydrogen and possibly oxygen as absorbed or chemically combined material (Rees 1966)
The fixed carbon content of coal is used by the ASTM to classify coal according to rank (Carpenter 1988) It is also used as an estimate of the quantity of char (intermediate combustion product) that can be produced and to indicate the amount of unburnt carbon that might be found in the fly ash
In any assessment of data it should be noted that the final temperatures heating rates and residence times utilised in proximate analysis tests differ significantly from conditions experienced in power station boilers In proximate analysis depending upon the set of country standards used
moisture content is determined in a nitrogen atmosphere at around 100degC for 10 minutes volatile matter of a coal is determined under restricted conditions at 900degC after a residence time of up to seven minutes ash content is determined by combusting the organic component of the coal in air up to around 800dege
Conditions in a power station boiler have been reported to produce temperatures greater than 1700degC (3120degF) heating rates of 1O000-100OOOdegCs and particle residence times within the system of seconds rather than minutes Ideally the suitability of a coal for combustion use should take into account the operational conditions and aim to identify relationships between critical process requirements and specific properties of the coal on a more rational basis However proximate analysis is still widely used in the utility industry
There are also problems with interpreting the results from a proximate analysis Ideally the moisture fraction should contain only water the volatiles fraction should consist only of volatile hydrocarbons released during the initial stages of heating the fixed carbon would be the char after complete devolatilisation and ash only the oxidised remains of the mineral matter after combustion This is not always the case Many coals contain light hydrocarbons which are driven off from the coal at temperatures low enough to cause them to
appear in the moisture determination Consequently the moisture measurement is too high and corresponding volatiles measurement too low This can be a significant problem with lower rank coals (Folsom and others 1986c)
A similar problem occurs between volatiles and fixed carbon The mechanisms involved in thermal decomposition of coal are complex and variations in the particle size treatment times temperatures and heating rates may affect the results Volatile matter content usually includes a loss in weight due also to the decomposition of inorganic material especially carbonates which are known to decompose at temperatures in excess of 250degC (see Section 23) Since fIxed carbon is not a direct measurement but obtained by difference it will include any errors bias and scatter involved in the related determinations of moisture volatile matter and ash Thus the concept of well defmed quantities of fixed carbon and volatile matter for specific coals is subject to qualification
Ash as produced during proximate analysis is often used as the material for conducting chemical analysis and other tests for assessing ash behaviour in a power station The problems associated with this approach are discussed in Section 23
22 Ultimate analysis of coal Ultimate analysis involves the determination of the elemental composition ofthe organic fraction of coal (Ward 1984 Gluskoter and others 1981) Table 2 describes the standard measurement methods for ultimate analysis techniques for ASTM AS BS DIN and ISO In addition to ash and moisture element weight per cents of carbon hydrogen nitrogen sulphur and oxygen (which is determined by difference) are reported Ash and moisture are determined by the same method as in the proximate analysis and suffer from the same shortcomings The detection of the above elements are usually performed with classic oxidation decomposition andor reduction methods (Berkowitz 1985)
Carbon and hydrogen occur mainly as complex hydrocarbon compounds Carbon may also be present in inorganic carbonates The nitrogen found in coals appears to be confmed mainly to the organic compounds present (Ward 1984) The nitrogen content of coal has become an important issue with the increased awareness of air pollution by nitrogen oxides (NOx) Unfortunately there is no simple correlation between coal nitrogen content and nitrogen oxide emissions as unlike sulphur dioxide not all nitrogen oxide produced during combustion comes from the coal itself In combustion theory there are three different formation mechanisms for NOx thermal prompt and formation ofNOx from fuel-bound nitrogen although the reactions are not fully understood (Juniper and Pohl 1991) Only the third mechanism relates to oxidation of the nitrogen contained in coal (Hjalmarsson 1990) The nitrogen content in coal varies between 05 and 25 and is contained mostly in aromatic structures (Burchill 1987 Zehner 1989) Some of the fuel nitrogen is released during devolatilisation and in highly turbulent unstaged burners is rapidly oxidised The remainder of the fuel nitrogen remains in the char and is released at a similar rate to that of char combustion The effIciency of coal-bound nitrogen conversion to NOx has
20
Coal specifications
been estimated at 20-25 for the char and up to 60 for the volatile matter (Morgan 1990) NOx formation from fuel-bound nitrogen can be minimised by promoting devolatilisation in zones of high temperature under reducing conditions for example air staging This principle is exploited in low NOx burners However less can be done to mitigate NOx formation due to the combustion of post-devolatilisation char-bound nitrogen (Kremer and others 1990 Hjalmarsson 1990)
Sulphur is present in nearly all coals from trace amounts up to about 6 although higher levels are not unknown The presence of sulphur compounds in the coal and ash can have many deleterious effects on the operation of boilers for example
during combustion the sulphur is oxidised to S02 A small percentage generally not more than 2 is converted into S03 of which a substantial percentage may then be reabsorbed to form sulphates with the alkali metals in the ash Alkaline sulphates are undesirable in that they increase the tendency of fouling and corrosion of heat transfer surfaces (see Section 422) if the dew point of the combustion gases is reached the S03 present combines with condensing water vapour to produce sulphuric acid which can then cause severe corrosion in cool sections of the power station particularly flue gas ducts and treatment systems (see Section 422)
The main problem however is S02 which is emitted through the stack and constitutes an environmental problem due to the resulting formation of acid rain
The oxygen content of coal is traditionally determined by difference subtracting the sum of the measured elements (C + H + N + S) from 100 although there are procedures available for the direct determination of oxygen (Gluskoter and others 1981 Ward 1984) It is an important property as it can be used as an indicator of rank and the basic nature of the coal Coals tend to oxidise in air to form what is commonly known as weathered coal The oxygen content of a coal has also been used as a measure of the extent of oxidation
Whilst the procedures for elemental analysis described by national standards often differ in minutiae they generally yield closely similar results This can only be achieved by the rigorous adherence to test specifications as laid down by the standards careful sampling and sample preparation
Similar to proximate analysis corrections to the analysis data are necessary For example
contributions to the hydrogen content from residual coal moisture and dehydration of mineral matter because the hydrogen content in coal is determined by the conversion of all the hydrogen present to H20 contributions to the carbon and sulphur contents which are determined by conversion to C02 and S02 respectively because both C02 and S02 are released from any carbonates and sulphides or sulphates that may be contained in the mineral matter
The major limitation of ultimate analysis is the labour cost
and time required to conduct the analyses Several techniques and instruments have been developed to reduce these limitations Some utilise automated gas chromatographic or spectroscopic equipment attached to high temperature combustion furnaces to reduce the time and labour required for the analysis Others utilise a range of measurement techniques including nucleonic methods to provide a quasi-continuous analysis for example on-line analysers (Folsom and others 1986a Kirchner 1991)
23 Ash analysis and minerals Coal ash consists almost entirely of the decomposed residues of silicates carbonates sulphides and other minerals Originating for the most part from clays it consists mainly of alumino silicates so that its chemical composition can usually be expressed in terms of similar oxides to those found in clay minerals The composition of the ash may be used as a guide to the types of minerals originally present in the coal (Given and Yarzab 1978 Ward 1984)
Certain generalisations can be made on the influence of the ash composition on the fusion characteristics as determined by the ash fusion test
the nearer the composition approaches that of alumina silicate Al2032Si02 (Al203 =458 Si02 =542) the more refractory (infusible) it will be CaO MgO and Fe203 act as mild fluxes lowering the fusion temperatures especially in the presence of excess Si02 FeO and Na20 act as strong fluxes in lowering the fusion temperatures high sulphur contents lower the initial deformation temperature and widen the range of fusion temperatures
In practice power station operators are primarily interested in knowing how closely the laboratory-prepared ash content of coal represents the quantity and behaviour of ash produced in large boilers Therefore when interpreting the results of the ash analysis it is important to recognise that the analysis is conducted on a sample of ash produced by the procedures specified in the proximate analysis (for example ASTM D3172 - see Appendix) It does not therefore correspond to the mineral matter present in the parent coal or necessarily to the individual ash particles formed when fired in a utility boiler For example it would be incorrect to assume that the iron measured in the ash sample is necessarily present in the coal as Fe203 or that the aluminium is present as Ah03 (Folsom and others 1986c) The principal chemical reactions that affect the ash yield at different temperatures are
High temperature Low temperature combustion oxidation
(Na K Ca)0Si02xAL203 + S03~ (Na K Ca)S04 + Si02xA1203 2 FeO + 1z 02 ~ Fe203
The boiler ash cools rapidly at a rate of about 200degCs through the temperature range from 900degC to 250degC and
21
Coal specifications
during this short time interval there is only a limited degree of sulphation and oxidation taking place Thus the ash prepared in a laboratory furnace at 815degC has higher weight than that formed in the boiler furnace due to the absorption of S03 in sulphate and additional oxygen in the ferric oxide (Raask 1985) For many years ash analysis in this form has been the only method available for assessing fly ash and deposit composition These in turn would be used to assess a coals slagging fouling and corrosive propensities which are of concern for the efficient operation of the power station More recently investigators have recognised the importance of actual mineral matter composition and
Table 5 Minerals in coal (Mackowsky 1982)
Mineral group First stage of coalification
distribution within the parent coal particles as a better indicator of a coals slagging and fouling behaviour (Nayak and others 1987 Heble and others 1991 Zygarlicke and others 1990) (see also Section 422)
Mineral matter determination is carried out far less frequently than the relatively fast and inexpensive ash determination (Brown 1985) Table 5 describes the minerals found in coal and their method of deposition
Although the ash as measured by proximate analysis is often equated with the coal mineral matter there are significant
Second stage of coalification Occurrence
Syngenetic fonnation synsedimentary-early diagenetic Epigenetic formation (intimately intergrown)
Transported Newly fonned Deposited in Transfonnation by water or fissures cleats of syngenetic wind and cavaties minerals
(coarsely (intimately intergrown) intergrown)
Clay minerals Kaolinite common-very common Illite-Sericite Illite dominant-abundant Minerals with a layered structure Chlorite rare Montmorillonite rare-common Tonstein
Carbonates Siderite Ankerite Ankerite common-very common Dolomite Dolomite rare-common Calcite Calcite common-very common
Sulphides Pyrite Pyrite Pyrite rare-common Melnikovite rare Marcasite Marcasite rare
Galena rare Chalcopyrite rare
Oxides
Quartz
Phosphates
Heavy minerals and accessory
Hematite Goethite
Quartz grains Quartz Quartz
Apatite Apatite Phosphorite
Zircon Tounnaline Orthoclase Biotite
Chlorides Sulphates Nitrates
rare rare
rare-common
rare rare
rare very rare very rare very rare rare rare rare
dominant gt60 abundant 30-60 very common 10-30 of the total mineral matter common 5-10 content in the coal rare 5-1 very rare lt1
22
Coal specifications
differences For example dehydration decomposition and oxidation of mineral matter which may occur during the laboratory process can affect the composition of the ash as follows
FeS04nHzO FeS04 + nHZO dehydration reduces the weight of CaC03 CaO + COZ decomposition ash and adds to
volatile matter
FeS + 20z FeS04 oxidation adds to weight of ash
Similarly partial loss of volatile constituents in particular mercury (Hg) potassium (K) sodium (Na) chlorine (CI) phosphorus (P) and sulphur (S) means that the ash is qualitatively and quantitatively quite different from the mineral matter that gave rise to it Its behaviour which is ultimately determined by its composition is also different If the ash sample is used for subsequent composition analysis the concentration of sodium and other volatile inorganic elements may be significantly lower than in the original mineral matter
Carbonate minerals are common constituents of many coals (see Table 5) These minerals liberate carbon dioxide (C02) on heating and therefore can contribute to the total carbon content of the coal as determined by ultimate analysis Whilst the COz content of the mineral matter is important for the correction of other specifications it is not normally included on coal specification sheets for combustion
24 Forms of SUlphur chlorine and trace elements
Procedures for determining these properties are described in various national and international standards (see Table 2)
Sulphur in coal is generally recognised as existing in three forms inorganic sulphates iron pyrites (FeS2) and organic sulphur compounds known respectively as sulphate sulphur pyritic sulphur and organic sulphur Although the total sulphur content provides sufficient data for most commercial applications a knowledge of the relative amounts of the forms of sulphur present is useful for assessing the level to which the total sulphur content of a particular coal might be reduced by preparation processes Commercial preparation plants can generally remove much of the pyritic sulphur but have little effect on the organic sulphur content
Pyrite is one of the substances which enhance the risk of spontaneous combustion by promoting oxidation and consequent heating of the coal (Bretz 1991a) Pyrite is also a hard and heavy substance which adds to the abrasion of coal mills (Cortsen 1983) (see Section 322)
It appears that in many cases some of the sulphur in the coal is retained in the ash as sulphate Thus the sulphate in the ash is invariably greater than the sulphate in the original coal when both parameters are expressed as fractions of the weight of original coal This effect is so large with the lower rank lignites that the ash yield may actually be greater than
the mineral matter content Kiss and King (1979) showed that between 0 and 99 of the organic sulphur in Australian brown coals may be retained in the ash as sulphate The thermal decomposition of carboxylate salts is particularly efficient in trapping organic sulphur as sulphate in ash With higher rank coals that do not contain carboxyl groups it is carbonates or the oxides formed from pyrolysis that tend to fix sulphur as sulphate It is evident that the amount of sulphate in ash depends on both the sulphur content of the coal and the concentration and nature of the materials capable of fixing it during ashing Various national and international standards specify procedures for determining sulphate in ash
Although not strictly part of the usual ultimate analysis procedure determination of chlorine which may be present in the organic fraction of the coal as distinct from the mineral analysis of the ash is often included Chlorine can enter the coal in the form of mineral chlorides in saline strata waters but this accounts for less than 50 of the total amount The bulk of the chlorine is present as CIshyassociated with organic matter probably as hydrochlorides of pyridine bases (Gibb 1983) In general chlorine content in most coals is quite low though there are exceptions For example some British coals can contain up to 1 chlorine (Given 1984)
In combustion chlorine from both alkali chlorides and the organic fraction of coal can combine with other mineral elements and contribute to deposition and corrosion Chlorine content is also used as an indication of potential fouling tendencies as the majority of the alkali metals responsible for fouling problems are present in the original coal associated with chlorine Chlorine can also affect the control of the pH (aciditylbasicity) in FGD plants (Jacobs 1992)
Apart from the major impurities in coal which are measured in the normal analysis there are a wide variety of trace elements which can also occur Clarke and Sloss (1992) have reviewed the typical concentrations of trace elements in coals There is a growing interest in the emission of trace elements from stacks as atmospheric pollutants and one can expect more attention to be given to this over the coming years (Swaine 1990) There has also been increased anxiety over the possible leaching of trace elements from ash or flue gas desulphurisation waste which may be deposited on the ground as means of disposal or use (Clarke and Sloss 1992) (see also Section 524)
25 Coal mechanical and physical properties
The commercial evaluation of a coal also involves assessments of physical properties A variety of tests have been developed to quantify physical properties of coal but each one is usually related to a particular end use requirement Table 6 lists standard measurements for coal physical tests which are considered relevant for handling and combustion
23
ASTM American Society for Testing and Materials AS Australian Standards BS British Standards Institution DIN Deutsches Institut fUr Norrnung ISO International Organization for Standardization
Bulk density flow properties fineness friability and dustiness all affect the handleability of coal
bulk density measurements are designed to evaluate the density of the coal as it might lie in a pile or on a conveyor belt (Folsom and others 1986c) the size distribution test is used to evaluate the size distribution of coal prior to pulverisation This measurement is important as it can be used to determine the suitability of a coal for a particular mill type and is used to assess the efficiency of the mill system Particle size distribution is also determined for the coal sample after air drying and pulverisation Pulverised coal fineness and size distribution is particularly important for burner performance (see Section 41) there are several tests to evaluate coal friability They are designed to determine the extent of coal size degradation and dusting caused by handling stockpiling and grinding
Most modem coal-burning equipment requires the coal to be ground to a fine powder (pulverised) before it is fed into the boiler The Hardgrove grindability index (HGI) is designed to provide a measure of the relative grindability or ease of pulverisation of a coal The test has changed little over the years Traditionally the HGI is used to predict the capacity performance and energy requirement of milling equipment as well as determining the particle size of the grind produced (Wall 1985a) Coals with high HGI are relatively soft and easy to grind Those with a low value (less than 50) are hard and more difficult to make into pulverised fuel (Wall and others 1985 Ward 1984) The grindability of coals is important in the design and operation of milling equipment A fall in HGI of 15 units can cause up to 25 reduction in the mill capacity for a given PF product as shown by the
10--1-----shyOJ sect 5 Cl r
eOl
09 pound
middotE 0 OJ ~
~ 08
lt5 z
constant PF size distribution
50 48 46 44 42
Hardgrove grindability index (HGI)
Figure 3 Mill throughput as a function of Hardgrove grindabaility index (Fortune 1990)
graph in Figure 3 Coals with high HGI values in general cause few milling problems
The abrasion index is a measure of the abrasiveness of a particular coal and is used in the estimation of mill wear during grinding (Yancey and others 1951) The abrasion index is expressed in milligrams of metal as lost from the blades of the test mill per kilogram of coal
The free swelling index (FSI) also called the crucible swelling number is used to indicate the agglomerating characteristics of a coal when heated Although primarily intended as a quick guide to carbonisation characteristics it can be used as an indicator of char behaviour during combustion A high swelling number suggests that the coal
24
Coal specifications
particle may expand to fonn lightweight porous particles that ash residue at high temperatures can be a critical factor in fly in the air stream and could contribute to a high carbon selection of coals for combustion applications Ash fusion content in the fly ash The extent of swelling is a function of temperatures are often used to predict the relative slagging the rate of heating final temperature and ambient gas and fouling propensities of coal temperature (Essenhigh 1981) so that the actual effects in practice are greatly dependent on combustion conditions The The test involves observing the profiles of specifically swelling number is also significantly affected by the particle size distribution of the sample (Ward 1984) Knowledge of the swelling properties of a coal can be used to avoid agglomeration problems in fuel feed systems (Hainley and others 1986 Tarns 1990) The size of the char particle after devolatilisation and swelling has been found to have an important influence on the kinetics of the combustion process 2 3 4 (Morrison 1986 Jiintgen 1987b) IT 5T HT
1 Cone before heating
The FSI can also provide a broad indication of the degree of 2 IT (or ID) Initial deformation temperature 3 ST Softening temperature (H=W) oxidation of a given coal when compared with a fresh 4 HT Hemispherical temperature (H=12W)
unoxidised sample or against a background history of 5FT Fluid temperature
measurement for a particular coal (ASTM DnO Shimada and others 1991)
Figure 4 Critical temperature points of the ash fusion The ash fusion test (AFT) measures the softening and test (Singer 1991 ASTM D1857) melting behaviour of coal ash The behaviour ofthe coals
Table 7 A summary of the major characteristics of the three maceral groups in hard coals (Falcon and Snyman 1986)
Maceral group Reflectance Chemical properties Combustion properties plant origin
Description Rank Reflected Characteristic Typical products on Ignition Burnout light element heating
Vitrinite woody trunks Dark to Low rank to 05-11 intermediate light intermediate ill ill branches stems medium grey medium rank hydrogen hydrocarbons volatiles jj jj stalks bark leaf bituminous 11-16 content decreasing j j tissue shoots and rank j j detrital organic Pale grey High rank 16--20 j j matter gelified bituminous vitrinised in White anthracite 20-100 acquatic reducing conditions
Exinite cuticles spores Black- Low rank -00-05 early methane volatile- jjjj jjjj resin bodies algae brown gas rich accumulating in sub- Dark grey Bituminous -05--09 hydrogen- oil decreasing jjj jjj acquatic conditions -09-11 rich with rank
Pale grey Medium rank -11-16 condensates bituminous wet gases (j) (j)
Pale grey High rank (decreasing) (=vitrinite) bituminous to white to shadows anthracite -16--100
Inertinite as for vitrinite but Medium Low rank 07-16 hydrogen- low fusinitised in aerobic grey bituminous poor volatiles oxiding conditions Pale grey Medium rank -16--18 in all ranks
to white bituminous and yellow to anthracite -18-100 (j) (j) - white
Capacity or rate j = slow Capacity or rate shown in parenthesis refers to vitrinite jj = medium jjj = fast jjjj = very fast
5 FT
25
Coal specifications
Table 8 Summary of coal ash indices (Anson 1988 Folsom and others 1986c Wibberley and Wall 1986 Wigley and others
Index Factors
Ash descriptor Base-acid ratio (BfA)
Ash viscosity T250 of ash degC (OF) Silica ratio
Siagging propensity Base-acid ratio (BfA) (for Iignitic ash CaO + MgO gtFe203) Siagging factor (for bituminous ash CaO + MgO lt Fe203) Iron-calcium ratio Silica-alumina ratio
Slagging factor degC (OF)
Viscosity slagging factor
Fouling propensity Sodium content
Fouling factor
Total alkaline metal content in ash (expressed in equivalent Na203)
chlorine in dry coal
Strength of sintered fly ash Psi
Temperature ash viscosity = 250 poise SiOl(Si02 +Fe203 + CaO + MgO)
(BfA)(S dry)
Fe20 3fCaO SiOlAh03 Maximum hemispherical temperature + 4(minimum initial deformation temperature)
5 T25o(oxid-TlOooO(red)
975 Fs
(Fs ranges from 10-110 for temperature range 1037-1593degC (1900-2900degFraquo
Na203 (for Iignitic ash CaO + MgO gtFe203) (for bituminous ash CaO + MgO ltFe203)
BfA(Na20 in ash) (for bituminous ash CaO + MgO ltFe203) BfA(Na20 water solublellow temperature ash) Na20 + K20 (for bituminous ash CaO + MgO ltFe203)
oxid oxidising conditions red reducing conditions
shaped cones made from ash prepared by the proximate analysis method with a suitable binder The cones are gradually heated in a furnace under either an oxidising or reducing atmosphere until the ash softens and melts Temperatures corresponding to four characteristic cone profile conditions are noted These conditions are shown in Figure 4 The four cone shapes are defined as follows
initial deformation - the initial rounding of the cone tip softening temperature - height equal to width hemispherical temperature - height equal to one-half width fluid temperature - height equal to one-sixteenth width
Under reducing conditions AFTs are lower due to the greater fluxing action (basicity) of the ferrous ion (FeO) compared with the ferric ion which is present under oxidising conditions
The heating value or calorific value is the single most important coal index or quality value for use in steam power stations since it provides a direct measure of the heat released during combustion The energy liberated by a coal on combustion is due to the exothermic reactions of its
hydrocarbon content with oxygen Other materials in the coal such as nitrogen sulphur and the mineral matter also undergo chemical changes in the combustion process but many of these reactions are endothermic and act to reduce the total energy otherwise available
The standard laboratory test measures the gross heating value that is the total amount of energy given off by the coal including latent heat of condensation of vapour formed in the process Under practical conditions water vapour and other compounds (acid forming gases) can escape directly to the atmosphere without condensation and the recoverable heat given off under these conditions is known as the net heating value It can differ most significantly from the gross heating value in coals that have a high moisture content such as brown coals or lignites as the main difference between the two values is the latent heat of evaporation of water The net heating value can be calculated from the standard laboratory-determined gross value based on factors such as the moisture sulphur and chlorine contents of the coal concerned An example of a conversion formula which relates gross and net heating value reads (ISO 1928)
Qn = Qg - 0212 H - 00008 0 - 00245 M MJkg
26
Coal specifications
1989)
Tendenciesvalues
Low Medium Iligh Severe
gt1302 (2375) 1399-1149 (2550-2100) 1246-1121 (2275-2050) lt1204 (2200)
Viscosity proportional to silica ratio
lt05 05-10 10-175
lt06 06-20 20-26 gt26
lt031 or gt300 031-30 Low ~ High
gt1343 (2450) 1232-1343 (2250-2450) 1149-1232 (2100-2250) lt1149 (2100)
05-099 10-199 gt200
lt20 20-60 60-80 gt80 lt05 05-10 10-25 gt25 lt02 02-05 05-10 gt10 lt01 01-024 025-07 gt07
lt03 03-04 04-05 gt05
lt03 03-05 gt05
lt1000 1000-5000 5000-16000 gt16000
where Qn = net heating value Qg = gross heating value H = hydrogen (percentage fuel weight) 0 = oxygen content (percentage fuel weight) M = moisture content (percentage fuel weight)
In North America boiler thennal efficiency is usually quoted on the basis of the gross heating value whereas most European countries use net heating value
Various fonnulae for predicting the heating value of coal from ultimate analysis have been developed On a dry mineral matter-free basis the heating value relates directly to the composition of the coal substance Some of these fonnulae are reviewed by Mason and Gandhi (1980) and Raask (1985)
Petrographic analysis of coals is increasingly being used to add to the information necessary to assess the suitability of coal for combustion in a particular power station Coal petrology describes coal in tenns of its maceral and mineral matter composition (see Table 7) These components can be recognised and measured quantitatively with the aid of a microscope A comprehensive review of the features that
characterise the various members of the maceral groups and rules for their microscopic identification can be found in the Intemational Handbook of Coal Petrography (ICCP 1963 1975 1985) Stach and others (1982) gives an overview of the macerals and their physical and chemical properties and Teichmiiller (1982) Given (1984) Davis (1984) Falcon and Snyman (1986) and Carpenter (1988) provide a good description of the origin of macerals
Maceral composition can be linked to properties of significance for describing combustion perfonnance Relatively little attention has been given to assessing maceral effects on grindability The literature that is available provides a confusing and somewhat contradictory picture This could be a consequence of the relative grindabilities of vitrinite and inertinite reversing as the rank of coal increases (Unsworth and others 1991) The preferential population of macerals within particular size ranges has been reported by several investigators (Falcon and Snyman 1986 Skorupska and Marsh 1989) For example an investigation involving a medium rank bituminous coal revealed a difference between the grindability of vitrinite and inertinite of approximately 15 units with inertinite displaying a HGI value averaging
27
Coal specifications
55 Such differences can significantly influence mill throughput (Unsworth and others 1991)
In certain circumstances it has been reported that a petrographic assessment of coal rank has advantages over the other techniques used as standards (Neavel 1981 Unsworth and others 1991) Parameters such as volatile matter content fixed carbon heating value swelling indices are average properties of a coal sample As such they reflect coal rank but they are also affected by variations in maceral composition Measurement of vitrinite reflectance is widely used as an index of coal rank
Earlier investigators recognised that the carbonaceous materials present in fly ash were predominantly forms of inertinite (Yavorskii and others 1968 Nandi and others 1977 Kautz 1982) Since that time the influence of maceral composition on coal reactivity during combustion has been the subject of considerable study (Jones and others 1985 Falcon and Falcon 1987 Oka and others 1987 Shibaoka and others 1987 Bend 1989 Diessel and Bailey 1989 Skorupska and Marsh 1989 Sanyal and others 1991) It has now been applied in many cases to explain problems that occur during combustion when other traditional tests such as proximate analysis have failed (Sanyal and others 1991)
The application of petrographic assessment as a predictive tool is still believed to be some way off Two reasons for this are
the subjective identification and different criteria being applied by the different countries to distinguish macerals has led to unsatisfactory reproducibility in results This has been illustrated in international exchange exercises conducted by the ICCP in the past It has been clear for some time that there is a need to reduce subjectivity to a minimum This may be achieved by using automated assessment techniques limited validation on a power station boiler scale of the influence of macerals on boiler performance Present operational procedure at boiler scale does not lend itself well to simultaneously monitor performance and allow for full petrographic assessment of the feedstock coal
26 Calculated indices In an effort to extend the use of laboratory results a number of empirical indices have been developed based on the
measurements discussed in the previous subsections These indices have been used to relate coal composition to the performance of power station components While the indices are not measurements as such in many cases they are utilised in the same manner as coal properties The accuracy reproducibility and applicability of these indices depend directly on the specific measurement procedures employed Indices have been developed for
rank reactivity ash descriptor ash viscosity slagging propensity fouling propensity
Rank relationships with coal properties as used nationally and internationally are summarised earlier in Figure 2
Some combustion reactivity indices use a relationship of the proximate volatile matter and fixed carbon of a coal known as the fuel ratio lllustrations of the relationship are given in Section 421
The indices used to describe ash behaviour are summarised in Table 8 The indices can be included in coal specification sheets to help assess the suitability of a coal for combustion How they are used and their relationship to performance are discussed in Section 422 of this report
27 Comments Most coal evaluation testing for combustion relies on empirical procedures which were developed primarily for the carbonisation industry town gas and blast furnace coke manufacture using simple laboratory equipment under conditions which were intended to represent those found in that type of process Despite the shortcomings the techniques required to perform the tests such as for proximate analysis are so simple that they lend themselves to automation This removes much of the risk of operator error and produces repeatable results
As operating requirements become more stringent the weaknesses of some of these techniques are becoming increasingly apparent There is a growing need to develop tests and specifications which reflect more closely the conditions found in power station boilers
28
3
steam generator
burners
mills
environmental control
I
Pre-combustion performance
environmental controlcoal handling
and storage
ash transport fans
The following three chapters describe the effect of coal quality parameters on the performance of various component parts of coal-frred steam generator systems Figure 5 illustrates the components of a typical power station The main power station components include
coal handling and storage mills fans burners boiler ash transport technologies for controlling emissions
This chapter focuses on effects of coal quality on the pre-combustion components of a power station
31 Coal handling and storage The coal handling equipment includes all components which process coal from its delivery on site to the mills This includes a large amount of equipment which (depending on power station design) may include unloading facilities hoppers screens conveyors outside storage bulldozers reclaimers bunkers etc and of course the coal feeders to the mills (Folsom and others 1986b) A high level of automation and remote control is often incorporated in
Figure 5 Typical power station components
29
Pre-combustion performance
Table 9 Illustrative example of USA coal storage requirements (Folsom amp others 1986b)
Coal
Lignite Subbituminous Bituminous
midwest eastern
Heat to turbine 106 kJh 4591 4591 4591 4591 Boiler efficiency 835 862 885 905 Coal heat input 106 kJh 5499 5326 5185 5073 Coal HHV MJkg 14135 19771 26284 33285 Coal flowrate th 429 297 217 168
Design storage requirements t Bunkers 12 hours 5148 3564 2604 2016 Live 10 days 102960 71280 52080 40320 Dead 90 days 926640 641520 468720 362880
Storage time for eastern bituminous plant design t Bunkers hours 47 68 93 120 Live days 39 57 77 100 Dead days 35 51 69 902
equivalent storage time for a plant designed for eastern bituminous coal but fired with the coals listed
modern coal handling facilities including sophisticated stacking-out and reclaim facilities to achieve some degree of coal blending capability Slot bunker systems with bulldozer operated stacking and reclaimers are still preferred by many utilities because of capital cost savings and greater flexibility of stockpile management
Coal storage can be divided into two categories according to the purpose live (active) storage with short residence time which supplies fIring equipment directly and dead or reserve storage which may remain undisturbed for many months to guard against delays in shipments etc Live storage is usually under cover and reserve storage outdoors
When outdoor storage serves only as a reserve the normal practice is to take part of an incoming shipment and transfer it directly to live storage within the station while diverting the remainder to the outdoor pile
The coal storage components are generally sized to provide capacity equivalent to a fIxed time period of fIring at full load (McCartney and others 1990) Typical values are 12 hours for inplant storage in bunkers ten days for live storage and more than 90 days for reserve storage Capacity of the reserve pile can be for example a minimum 60-day supply at 75 of the maximum burn rate These time periods are specifIed by the architectengineer based on the utilitys desired operating procedures and other constraints such as political legislation for strategic stocking The key parameters for assessing the quantity of coal required are
power station capacity heat rate coal heating value
Steam generators of a given capacity operating at steady load
require a fIxed heat input per unit of time regardless of coal heating value (Carmichael 1987) Therefore if the actual heating value of the coal is reduced then the storage capacity and quantities that must be delivered to the utility via the transport system must be increased For example Folsom and others (l986b) compared the storage requirements for four coals of differing rank supplying a 500 MW steam-electric unit (see Table 9) For all performance parameters to remain constant over a wide range of coal heating values substantial variations in coal flow rate at full load are required with factors of as much as 21 in some cases The coal storage requirements for specifIc time periods reflect this same range of variation Also shown are the storage times required for fIring alternate coals in a unit designed to fIre a high heating value fuel an Eastern USA bituminous coal These changes may not affect the ability to operate the unit at high capacity for short time periods However the equipment which transports the coal may need to operate more frequently and this could limit the ability to fIre at full station capacity over an extended period Also normal power station operating procedures may need to be modifIed to permit fIlling the bunkers more than once per day etc
Most of the equipment which transports the coal operates intermittently Thus coal quality changes which result in coal flow rate changes will vary the duty cycle for the transport equipment An increase in flow rate requirements caused by a decrease in coal heating value or an increase in boiler heat rate will increase the duty cycle and may affect unit capacity Provided that these changes in flow rate are small or of limited duration most power stations will be able to tolerate them with no equipment modifIcations Large increases in flow rate for example those that may occur due to a shift from a bituminous coal to a lignite as described in Table 9 may require such long duty cycles that the normal operating procedures of the power stations and maintenance intervals
30
Pre-combustion performance
Table 10 Conveyor Equipment Manufacturers Association (CEMA) material classification chart (Colijn 1988a)
Major class Material characteristics included Code designation
Density
Size
Flowability
Abrasiveness
Miscellaneous properties or hazards
Bulk density loose
Very fine 200 mesh sieve (0075 mm) and under 100 mesh sieve (0150 mm) and under 40 mesh sieve (0406 mm) and under
Fine 6 mesh sieve (335 mm) and under
Granular 127 mm and under
Lumpy 76 mm and under 178 mm and under 406 mm and under
Irregular stringy fibrous cylindrical slabs etc
Very free flowing - flow functiongt 10 Free flowing - flow function gt4 but lt10 Average flowability - flow function gt2 but lt4 Sluggish - flow function lt2
Mildly abrasive - Index 1 - 17 Moderately abrasive - Index 18 - 67 Extremely abrasive - Index 68 - 416
Builds up and hardens Generates static electricity Decomposes - deteriorates in storage Flammability Becomes plastic or tends to soften Very dusty Aerates and becomes fluid Explosiveness Stickiness - adhesion Contaminable affecting use Degradable affecting use Gives off harmful or toxic gas or fumes Highly corrosive Mildly corrosive Hygroscopic Interlocks mats of agglomerates Oils present Packs under pressure Very light and fluffy - may be windswept Elevated temperature
Actual kgcoal flow
Azoo AIOO
~
C~
E
1 2 3 4
5 6 7
F G H J K L M N o P Q R S T U V W X Y Z
may be inadequate In such extreme cases the capacity of the transfer equipment may be insufficient even with continuous operation such that modifications will be required In some power stations it may be possible to increase the capacity of the transport equipment For example conveyor belt speeds may be increased However this can also lead to dust problems and increased spillage especially with friable coal
Unlike the other coal transport equipment the coal feeders operate continuously Thus any change in coal flow rate requirements must be met with an immediate change in feeder speed Coal feeders are usually designed with excess capacity so that minor changes in coal flow rate requirements can be tolerated easily The major changes required by significant changes in coal heating value such as switching
from a bituminous coal to a lignite would be beyond the capacity of most coal feed systems Another factor to consider is the feeder turndown Many feeders have a minimum operating speed beneath which problems such as uneven flow can occur
In addition to changes in the required coal flow rates coal characteristics can produce other detrimental effects on handling and storage systems
In a survey carried out at a coal handleability workshop (Arnold 1988) attendees from utilities and the mining community were asked to rank the problems from one (1 - worst) to ten (10 -least) The ratings are indicated next to each problem
31
Pre-combustion performance
plugging in bins (1) feeders (2) arching and caving in storage (10) flowability hang-up in bins (3) sticky coal on belts (4) freezing in transport (5) storage (8) dusting on conveyors (6) in stockpiles (7) oxidationspontaneous combustion (9)
Other concerns mentioned included abrasiveness of coal causing chute wear wet fuel hang-up in transfer towers sticky fuel in downcomers spillage and sliding from belts due to wetness hang-up in breakers excessive surface moisture and coal sticking in bottom-dumped rail cars Whilst relationships between coal properties and handleability have been established these are not the same as those needed for combustion purposes In fact some coal specifications do not usually include parameters which reflect the handling and storage properties of coal Colijn (1988a) reported that the Conveyor Equipment Manufacturers Association (CEMA) have made an effort to establish a listing of material properties and characteristics which influence the handling and storage of granular bulk materials including coal as shown in Table 10 The coding system has been developed to describe particular material properties such as density size flowability and abrasiveness Where material handling characteristics are in general not easily quantifiable they are listed as hazards - watch out Table II shows typical CEMA codes for various coal
Table 11 CEMA codes for various coals (Calijn 1988a)
Material description CEMA material code
Coal anthracite (River amp Culm) 6OB635TY Coal anthracite sized - 127 mm 58C-225 Coal bituminous mined 50 m amp under 52A4035 Coal bituminous mined 50D335LNXY Coal bituminous mined sized 50D335QV Coal bituminous mined run-of-mine 50Dx35 Coal bituminous mined slack 47C-245T Coal bituminous stripping not cleaned 55Dx46 Coal lignite 43D335T Coal char 24Cl35Q
x refers to a range of particle sizes
311 Plugging and flowability
The economic impact of plugging of coal transport facilities can be significant resulting in added manpower costs for clearance partial unit deratings or in some cases total shutdowns For example at 15 $MWh a typical 575 MW unit could lose over 1000 $h income as a result of partial deratings for each plugged silo (Bennett and others 1988)
No flow or limited flow problems are often due to the formation of stable arches andor increases in wall friction (Arnold 1990) Binsilo blockages occur when the coal has become sufficiently adhesive to form a stable arch which supports the weight of the coal above it Increases in wall friction which is a measure of the sliding resistance of the coal against the bin wall will result in coal adjacent to the wall moving slower than that in the centre zone This gives
mass flow funnel flow expanded flow
Figure 6 Typical flow patterns in bunkers (Colijn 1988a)
rise to different flow patterns in various parts of the bin (see Figure 6) For most coals three to four days outdoor storage increases the chances of one or both of the above problems occurring Coal flowability is directly related to various coal characteristics depending on the coal rank Some of the major contributing properties are (Llewellyn 1991)
surface moisture particle size distribution clay content changes in bulk density
Surface moisture is considered the most critical factor There is a level below which regardless of other factors coal flow problems do not occur There is also a critical surface moisture at which maximum adhesion and bulk coal strength will occur Above this level additional water flows away rises to the surface or in the extreme decreases strength due to slurry formation Adding moisture to dry coal first creates a lubricating effect and allows particles to slide against each other more easily and pack into a denser stronger material Surface tension develops as a form of physico-chemical bonding (known as hydrogen bonding) increases between water and coal particles
Particle size distribution contributes to flowability problems because it determines the available surface area and hence adhesion characteristics The proportion and size of the smallest particles in bulk coal have a great effect on its handleability In some coals the ash and clay content which is inherent in the coal concentrates in the fines fraction (see Table 12) This also influences coal flowability characteristics Average particle size can be affected by coal handling procedures and equipment or by natural causes A major factor influencing the size composition of a coal product is its friability Friability is a combination of the impact strength and fracture cleavage characteristics of the coal and its susceptibility to degradation due to a rubbing action during handling A high fines content if combined with a critical moisture level can result in a coal with very poor handling properties (Llewellyn 1991) In low rank coals large pieces may fall apart and produce excess fines in dry air If the coal is subsequently rewetted the combination
32
Pre-combustion performance
Table 12 Analysis of ash and clay distribution in a coal by mesh size (Bennett and others 1988)
Property Base fuel +6 Mesh (+335 mm)
6-50 Mesh (036-030 mm)
50-100 Mesh (030-015 mm)
-100 Mesh (-015 mm)
Weight Ash (Dry) Silica
10000 2277 6740
4514 1702 5850
4512 2320 6490
765 3596 7790
209 4153 8380
of increased surface area and moisture can have a substantial impact on flow characteristics
The clay content of coal affects its cohesive characteristics Increased clay content in strip mined subbituminous coal and lignites has been shown significantly to increase wall friction and shear strength at a given moisture content (Bennett and others 1988)
If all of the above factors increase simultaneously that is high surface moisture high clay high fmes percentage and coal is stored in a bin for several days drastic increases in coal bulk shear strength lead to significant adhesion bridging and consequent coal flowability problems
There are no coal specifications which relate to coal bulk shear strength although tests have been developed which provide bulk shear strength values for coals They are used as a measure of the cohesive strength or stickiness and have been used as a quantifying factor for problem coals Shear strength can be measured using either a rotational or a linear translational instrument Results from the rotational shear test can be obtained within an hour and may be used on-site to provide real time analyses (Bennett and others 1988 Colijn 1988a) The principle of the rotational shear tester is to provide an equally distributed shearing force across a horizontal plane in the coal sample This is done while the sample is placed under varied loads The bulk shear strength determined for a particular fuel handling situation can be represented as a value in applied pressure or as an arbitrary relative flow factor value (FFV) The FFV can be plotted relative to moisture and clay values A critical arching diameter (CAD) can be extracted by combining results from a shear tester with the bulk density of the coal Calculations can then be made for the geometric configuration of each type of coal container for particular types of coal thus negating possible problems of archingplugging in a binsilo Figure 7 shows the data derived from shear tests for more than twenty coals conducted by Colijn (1988b) The CAD was plotted against the surface moisture content for the coals and while a clear relationship between increasing moisture content and increasing CAD exists there is significant data scatter As discussed earlier other investigators (Blondin and others 1988 Arnold 1991) have shown that the amount of clay and fines also influence the CAD
As many coals have a tendency to increase their strength after a few days of consolidation it is often necessary to test the coals under these conditions For these cases a coal sample would be kept inside the shear cell under pressure for a number of days to simulate the time period during which the coal may be contained within a bin or silo Arnold (1991) reported a study conducted to define further the relationship
mass flow - instantaneous
2 E ~
til Q) E til 0 0) c
c ()
ro (ij ()
8
0
0
Figure 7
3 E
~ Q) E til 2 0 0)
~ c ()
ro (ij ()
8
0
0 0 0
o
0
6 o 00 oo0
o D cPo DO
0 CI o~ 0_o
--tJ 0 0 0 _ - shy
9 - Data for a variety of coal samples
2 4 6 8 10 12 14 16
Surface moisture
Surface moisture versus critical arching diameter (CAD) determined from shear tests (Coljjn 1988b)
3-day consolidation
10 moisture
+ 8 moisture
6 moisture
+ +
0
0 2 4 6 8 10 12 14
Fines -44 ~m (-325 mesh)
Figure 8 Three-day consolidation critical arching diameter (CAD) versus per cent fines in coal as a function of moisture content (Arnold 1991)
of coals and their handling behaviour Six coals that were combusted at an Eastern USA power station were selected The coals had very similar chemical analyses and all met the power station coal specification but exhibited a range of handling characteristics As an illustration of some of the preliminary results of the study Figure 8 shows the influence of the percentage fines (particles less than 44 lm in diameter) moisture content and consolidation time on the CAD calculated from shear tests conducted on one of the coals The instantaneous CAD values are not shown in Figure 8 but were in fact 30 lower in value than the three-day consolidation values Generally for all the coals studied the maximum value occurred at the highest moisture
33
Pre-combustion performance
contents and there was a tendency to increase with increasing fines content and increases in consolidation time
More recently Rittenhouse (1992) reported the development of a series of simplified empirical tests that can be run by power station staff members that make it possible to identify potential problem coals The results of the tests are indices that characterise the flowability of coal The individual indices are
arching index ratholing index hopper index chute index flow rate index density index
These can also be used to indicate when hopper modifications may extend the operating range of the system so that coals that are less than free flowing can be handled The tests are reviewed in greater detail by Johanson (1989 1991) Arnold and OConnor (1992) have recently reported the development of another simplified test that can be used more easily on-site and has been validated against the tri-axial shear tester
Coal flowability can be modified by the use of chemicals which specifically enhance the flow of wet coal Additive selection and performance depend greatly on fuel quality (Bennett and others 1988) The effectiveness of particular additives on problem coals is assessed by measurement of shear strength values produced
312 Freezing
Although it is difficult to assess the cost related specifically to coal moisture freezing during cold weather some of the potential problems are as follows
production losses at the mine beneficiation plant and the utilities increased labour costs associated with frozen coal removal less safe working conditions costs related to operation of thawing and mechanical removal equipment transport equipment damage due to mechanical or thermal means of removing frozen coal from ships rail cars or trucks demurrage costs on rail cars accelerated rail wear andor derailment
Work done in the mid-1970s showed that surface moisture of a coal caused the problems For freezing to occur the coal being handled must be exposed to sub-freezing temperatures for a sufficient period of time It is generally accepted however that no problems with handling should be expected unless the surface moisture exceeds approximately five per cent Total moisture content of the coal is inadequate as a sole indicator since coal that has a high inherent moisture may not freeze at 20 or more total moisture while coal with a low inherent moisture
may freeze and cause severe problems at seven per cent or below
Each coal type has a characteristic inherent moisture content defined here as the moisture contained in the fine pore structure itself Depending upon rank porosity and hydrophilicity of the coal inherent moisture ranges from less than one per cent to greater than 20 of the coal mass While surface moisture is undoubtedly the primary cause of coal freezing and the consequent handling problems other factors also influence the situation For example Connelly (1988) reported that at lower temperatures the increased viscosity of water renders the dewatering of coal processes less efficient Total moisture content of dewatered coals can be expected to increase at lower temperatures as shown in Figure 9
90
86 bull
t-O)
s 82 bull
iiimiddot0 E 78
Cii l 0V 0)
cr 74
72 bull
66
4 10 20 30 40 50 Temperature degC
Figure 9 Dewatering efficiency versus temperature (Connelly 1988)
Particle size is also important If the coal particle size were consistently large that is 127 cm (h inch) or larger it would be unlikely that the particles would pack together sufficiently to freeze and cause a serious problem Current mining methods use continuous longwall techniques to extract coal with consequent breakage and fines production For this reason it is impractical for beneficiation plants to furnish a product with a minimum particle size of 127 cm or greater for all shipments unless some form of agglomeration process is used Typically coal being shipped contains a wide range particle size distribution and a substantial amount of material less than 016 cm in diameter Because of this particle size distribution the fine particles of coal can pack between the larger ones and form a more continuous solid mass The finer particle size coal also tends to hold a larger percentage of surface moisture With the finer particle size and increased surface water more particle-to-particle contact occurs accentuating the freezing problems
The freezing process can be offset by the use of additives such as urea calcium chloride solution or polyhydroxy alcohols (Hewing and Harvey 1981 Boley 1984 Connelly 1988)
34
Pre-combustion performance
313 Dusting
Most bulk solid materials have the potential to generate dust during handling Dust can be generated while the coal is in motion such as during transfer from transport to storage and even as wind borne dust from stockpiles This creates safety as well as environmental problems The extent of dust problems may be related empirically to particle size distribution (the amount of fines) moisture content moisture holding capacity and the wind speed (Mikula and Parsons 1991) Nicol and Smitham (1990) reported that in the case of Australian export coals they are sold with a nominal top size of 5 cm but as was discussed earlier there is a wide range of size distributions covered by this specification Figure 10 shows the broad range of coal sizes that are exported This implies that the potential dustiness of coal is a variable with coal source Sherman and Pilcher (1938) have done considerable work in the area of dust control and have tested the size of dust particles in the ASTM D547 dust cabinet test and found that the diameters of particles range from 11 to 55 11m Devised in the 1930s the test is perceived to be somewhat dated as it was originally designed to simulate coal delivery into a bin
Nicol and Smitham (1990) investigated the effects of moisture on the lift-off potential of different coals over a range of wind velocities using a laboratory wind tunnel facility They found that depending on the coal size fraction the velocity to remove wet particles was between 25 and 75 greater than the dry particle removal velocity Alternatively the amount of coal removed at a given velocity is reduced as the moisture content increases Figure 11
99
80
E 60 -E 7 40
if ro 0
20 0
N middotw 10 m 0 c 5J
shaded area encompasses 90 of export coals with coarsest (lower) and finest (upper) size disributions also shown
0125 025 05 2 4 8 16 315 63 Particle Size mm
Figure 10 Size distributions of Australian export coal (Nicol and Smitham 1990)
illustrates the effect and shows that a critical moisture content of about 9 in the coal can be reached at which coal removal can be largely prevented The effects of different coals show up most clearly in the moisture content to prevent any dust emission that is the intercept on the moisture axis in Figure 10 Table 13 summarises the results for the three coals of different properties Rank and chemical properties such as volatile matter content are poor indicators of the propensity for different coals to dust Porosity as reflected in the moisture holding capacity does provide a useful indicator of the potential dustiness of coal Coals with a low moisture holding capacity that is a low equilibrium moisture have little internal porosity so that once this internal volume is filled the excess water remains at the particle surface where it is available to form bridges of water between adjacent particles preventing their removal in an air stream High moisture capacity coals require a greater amount of water to fill the internal volume before water is available at the surface to be an effective dust control agent Jensen (1992)
2000
o
N
E Oi ui Cf)
g Cii 0 ()
Q) gt ~ S E J u
1500
1000
500
0
0
0 0
0 0
amp0
0 ~ 0
0 0
0
0
o 2 4 6 8 10 12
Total moisture
Figure 11 Coal lift-off from a stockpile as a function of total moisture content (Nicol and Smitham 1990)
Table 13 Effect of coal properties on critical lift-off moisture content (Nicol amp Smitham 1990)
Coal Critical moisture Reflectance Australian coal Moisture holding content Ro max rank nomenclature capacity
1 100 094 high volatile bituminous A 25 2 115 120 medium volatile bituminous 40 3 210 073 high volatile bituminous A 120
66
35
Pre-combustion performance
reported that work carried out by ELSAM Denmark has shown that coals with a sUlface nwisture content of 2-3 was sufficient to prevent dusting of some coals
314 Oxidationspontaneous combustion
All coals when stored tend to combine to some extent with oxygen from the air in a process known as weathering (Davidson 1990) This causes some loss of heating value generally less than 1 in the first year of storage for most coals but may be up to 3 for low rank coals - and can change firing characteristics (Singer 1989a) Weathering also tends to promote reduction in size or crumbling (Llewellyn 1991)
Llewellyn (1991) also reported that grindability tests carried out on both fresh coal supplies and the coal stored on the surface of a stockpile indicated a clear separation in behaviour Surface samples were reported as being significantly harder (average 43 HGI) to grind than the fresh coal supply samples (average 52 HGI) The hardness increased with the age of the stockpiled coal A similar clear separation was found between the surface and the interior of the stockpile
Oxidation releases heat and if conditions in the stockpile are such that it occurs at a sufficiently rapid rate enough heat can be generated to cause spontaneous combustion (Sebesta and Vodickova 1989)
In brief the coal properties that have been found to influence oxidation and spontaneous combustion are
rank (heating value or volatile matter) moisture content ash content particle size
Malhotra and Crelling (1987) reported that as the rank of coals decreases the susceptibility for spontaneous combustion increases Cacka and others (1989) suggested that this phenomenon may be related to the increasing content of aliphatic structures which have a higher propensity to react with oxygen than aromatic structures present in coal However there are many anomalies to this straight rank order susceptibility Chamberlain and Hall (1973) have in fact pointed out that some higher rank coals may be more susceptible to spontaneous combustion
The mechanism of water adsorption into the pores of coal also releases heat so that heating in a stockpile will be dependent to some extent upon the inherent moisture (Matsuura and Uchida 1988 Iskhakov 1990) In most cases excess moisture can suppress the heating process (Taraba 1989) although cases have been reported where addition of water to an overheating stockpile can exacerbate the problem and these have been discussed in greater detail in a review by Chen (1991)
The mineral matter composition of coals can influence their susceptibility to oxidation Dusak (1986) reported incidents where mineral matter can play the role of oxidation
promoters by increasing oxidation rate and heat emission due possibly to exothermic reactions of the mineral matter itself with oxygen Work by Cacka and others (1989) determined that iron and titanium were particularly active in the coals under investigation Nemec and Dobal (1988) reported the influence of pyritic sulphur The magnitude of the influence on the oxidation process depends upon mineral matter size and its dissemination within the coal along with the rank moisture content and size of the coal
Particle size influences the surface area available for oxidation Several workers have reported that the smaller the particle size the greater the heat build up within coal stockpiles (Brooks and Glasser 1986 Nemec and Dobal 1988 Llewellyn 1991)
A number of tests have been devised to assess the extent of oxidation of a coal and its susceptibility to spontaneous combustion These include
crossing point test This measures the ignition temperature of a coal sample when it is heated at a constant temperature rate in a small cylindrical furnace The ignition temperature is measured as that at which the coal temperature crosses or becomes greater than the furnace temperature (Brown 1985) This can also be known as the runaway temperature (Gibb 1992) Differential thermal gravimetric analysers and calorimeters are also used to carry out a similar form of test (Clemens and others 1990 Shonhardt 1990) free swelling index test (see also Section 25) Shimada and others (1991) used free swelling index to monitor the extent of weathering of coals in a stockpile The swelling index of a Polish coal (K11) was seen to decrease significantly after a short storage time of three months (see Figure 12) It could also be used to distinguish between coal samples taken from the body (K11) of the coal stockpile and those from the slope (K11 slope) The test can only be applied to coals that exhibit a high initial swelling index as some coals with low initial swelling index (such as Kl in Figure 12) do not give any perceptible change after storage spectroscopic techniques Berkowitz (1989) has reviewed the spectroscopic methods utilised to detect oxidation of coal These can include Fourier transform shyinfra red (FTIR) spectroscopy electron spin resonance (ESR) nuclear magnetic resonance (NMR) and fluorescence microscopy (pavlikova and others 1989 Bend 1989)
Most of the above tests are not standardised With the exception of FSI which is generally used as an indicator of the caking nature of coals they usually are not included in a typical coal specification
At present none of the above effects can be quantified accurately The overall impact on operation and any required modifications must be based primarily on experience The influence of coal quality on the spontaneous combustion of the coal can be minimised by careful layout and construction of the stockpiles
36
Pre-combustion performance
bull 6
--- K1
0 K11
x L K11 slope 5 0
(]) 0 4 0 ~
0OJ sect 3CD ~ 0
(f)
2
L ~ - - - - - - - - - - - - 1f - - - - - - - - - - -- - - - - - shy II I
o 3 5 7 9 11 13 15 17 30 40 50 60 70
Storage time months
Figure 12 Influence of storage time on swelling index (Shimada and others 1991)
The special requirements for low rank coal storage are reviewed in an lEA Coal Research report entitled Power generation from lignite (Couch 1989)
32 Mills Most large steam-electric units are direct fIred that is the coal is supplied to the mills and is pulverised continuously with direct pneumatic transport of the pulverised coaVair mixture to the burners Thus the performance of the mills has a direct effect on the performance of the unit In modern practice a single mill can supply several burners In tangentially fIred systems all four bumers on a single elevation are typically supplied by a single mill In wall fIred systems a single mill may supply a complete row or another symmetrical array of burners A common design practice is to size systems to achieve full load with one or more mills out of service This allows time for maintenance and allows the spare mill to be brought on-line in the event that a failure occurs in one of the other mills
Because of their heterogeneous nature coals used for combustion can exhibit a wide range of grindabilities and require different milling actions to produce a suitably sized product Fine grinding of coal - generally 70 or more passing 75 11m (200 mesh) - is the standard commonly adopted to assure complete combustion of coal particles and to minimise deposits of ash and carbon on heat absorbing surfaces (Carmichael 1987) The different mill designs can be classified according to speed
low-speed mills are of the balVtube design with a large rotating steel cylinder and a charge of hardened balls Coal grinding occurs as the coal is crushed and abraded between the balls medium-speed mills are typically vertical spindle designs and grind the coal between rollers or balls and a bowl or face There are a number of designs in service differing in the specific design of the equipment which rotates size and shape of the grinding elements etc high-speed mills have a high-speed rotor which impacts and breaks the coal
Table 14 Preferred range of coal properties (Sligar 1985)
Mill type Low speed
Maximum capacity tJh 100 Turndown 41 Coalfeed top size mm 25 Coal moisture 0-10 Coal mineral matter 1-50 Coal quartz content 0-10 Coal fibre content 0-1 Hardgrove grindability
Medium High speed speed
100 30 41 51 35 32 0-20 0-15 1-30 1-15 0-3 0-1 0-10 (0-15)
index 30-5080 40-60 60-100 Coal reactivity low medium medium
The range of properties listed above is a preferred range and operation outside these limits is possible
Numerical values for the preferred range of coal properties appropriate for each mill type are given in Table 14 Most large steam-electric units use balVtube or vertical spindle mills
Coal mills integrate four separate processes all of which can be influenced by coal characteristics
drying grinding classifIcation transport
321 Drying
Earlier mills used external dryers before the coal was fed to the mills placing an economic disadvantage on the system Internal drying was developed to overcome this The surface moisture of the coal must be evaporated in the mill to avoid agglomeration of the particles (Sadowski and Hunt 1978) As the primary air is used for conveying the coal the only variable for drying is the temperature of this air The primary air temperature is adjusted to achieve a mill discharge temperature high enough to ensure complete drying in the
37
Pre-combustion performance
Table 15 Maximum mill outlet temperatures for vertical spindle mills (Babcock amp Wilcox 1978 Singer 1991)
Maximum temperature degC (OF)
Coal Babcock amp Wilcox Combustion Engineering
High volatile 66 (150) 71-77 (160-170) bituminous
Low volatile 66-79 (150-175) 82 (180) bituminous
Lignite 49-60 (120-140) 43-60 (110-140)
grinding zone For example Table 15 lists the maximum mill discharge temperatures recommended by Babcock amp Wilcox and Combustion Engineering The discharge temperatures are fixed for safety reasons and are dependent on coal type For bituminous coals the value is usually between 65degC and 90degC with the lower value for fuels of high volatility to reduce the potential for mill fires Higher temperatures of over 100degC have been reported to be used in some cases (Jones and others 1992) Standard proximate analysis volatile matter tests have been used to provide some indication of the likelihood of spontaneous combustion High volatile matter coals are more reactive and more susceptible to spontaneous combustion under these conditions
The primary air temperature required to dry the coal depends on several factors including its moisture (or ice) content temperature and specific heat together with airfuel ratio and mill design The required air temperature may be calculated via a simple energy balance (Folsom and others 1986b)
Figure 13 shows the effect of coal moisture on primary air temperature requirements for vertical spindle mills manufactured by Babcock amp Wilcox and Combustion Engineering As the moisture content of the coal increases so the inlet air temperature must increase to compensate Increases in the coal moisture content can impact unit capacity if the primary air supply system cannot provide air at a high enough temperature It should be noted that to
provide more heat to the drying process the aircoal ratio can be increased However the aircoal ratio affects classifier performance and other downstream operations such as burner performance pulverised coal transport and wear in the coal supply system These effects must be considered Increasing the air temperature increases the potential for mill fires since dry coal particles especially those recycled from the classifier may come into contact with the high temperature air entering the mill
Low-speed mills are most sensitive to coal surface moisture content The capacity of these mills falls in an approximately linear manner with increase in moisture content The decrease in mill capacity is of the order of 3 for each 1 increase in coal surface moisture This effect is present because of the use of a lower airfuel ratio with these mills lower primary air temperature and less efficient mixing within the mill body Medium- and high-speed mills are not nearly as sensitive to high moisture coal
322 Grinding
The size consistency of the coal feed has a direct effect on the power requirements of the mill (see Section 632) All three types of mill are affected by coal feed top size Table 14 gives the critical feed top size for all three types of mill Low-speed mills are particularly sensitive to coal top size Mill capacity falls in a regular manner with increase in coal feed top size In addition to the top size the overall particle size distribution is also of significance In all cases the presence of excessive proportions of fines in the feed to the mill acts to the detriment of the full output
The fineness required is usually related to the rank of a coal the higher the rank of the coal the fmer the particle size distribution needed to achieve satisfactory combustion that is an increase in fmeness with decreasing volatile matter content The approximate size ranges which are acceptable for coals of different rank to ensure complete combustion are shown in Table 16 Analysis of the combustion process shows that burnout is a function of the proportion of particles over 100 1JlIl rather than the amount less than 75 -Lm It is to be expected that increasing the 200 IJlIl oversize from 1 to
Table 16 Comparison of fineness recommendations ( passing 200 mesh -75 11m) (Babcock amp Wilcox 1978 Cortsen 1983)
Babcock amp Wilcox specification ASTM classification of coals by rank
Fixed carbon Fixed carbon below 69
Type of furnace 979-86 (petroleum coke)
859-78 779-69 BtuI1b gt13000 (gt303 MJkg)
BtuI1b 12900-11 000 (300-256 MJkg)
BtuI1b lt11 000 (lt256 MJkg)
Water-cooled 80 75 70 70 65 60
ELSAM Denmark specification
Volatile matter content dry ash-free () lt10 10-20 20-25 gt25
Water-cooled 85 80 75 70
38
Pre-combustion performance
Eastern USA coals (Combustion Engineering)
80a C leaving mixture temperature
H 2 0 entering-leaving
300 14-20
o 12-20 a
10-20
8-20
6-15
4-15
2-10
Babcock amp Wilcox
3000 a
(i100 CIl ~
gt 3
3 4 5 Cl
9 (1)kg of air leaving millkg of coal a 200 lt1l Cii Cl E
Midwestern USA coals (Combustion Engineering) 2 ill
nac leaving mixture temperature ~
laquo 100
JI 24-70 entering-leaving
22-65
26-75 H 0
~ 2
20-60
18-60300 shy16-55
o 2 4 6 8 1014-50 12-50 kg of coalkg of air
10-45 8-40
6-40
100
2
~
OJshysect
pound 0 ~
ES
2 3 4 5
kg of air leaving millkg of coal
Figure 13 Primary air temperature requirements depending on moisture content and coal type (Babcock amp Wilcox 1978 Singer 1991)
39
ie curve is unreliable in this area
60 lt75 ~m
lt75~m
lt75~m
90 lt75 ~m----shy
25 50 75 100
Pre-combustion performance
2 would have a much more significant increase on bumout than decreasing the under 75 lm from 70 to 65 Oversize particles are believed to contribute to slagging problems in boilers although there are no adequate correlations to relate particle size distribution to the incidence of slagging (Babcock amp Wilcox 1978 Singer 1991) The use of low NOx combustion strategies has required a policy of finer grinding for some coals in order to offset the increased unbumt carbon found in the fly ash (Heitmiiller and Schuster 1991)
The ease by which a coal can be ground within a particular type of apparatus is termed its grindability The most common measurement is the Hardgrove grindability index (HGI) (see Section 25) The HGI is widely accepted as the industry standard for evaluating the effects of coal quality on mill performance for high rank coals (Babcock amp Wilcox 1978 Singer 1991) The rated capacity of a mill is defined as the amount of coal (tlh) that can be ground to a fineness of 70 through a 75 lm sieve using a coal with HGI of 50 or 55 Mill manufacturers tend to be divided on how mill capacity is determined for a particular coal Some provide correlations relating the HGI of the coal to mill output for each standard mill size Other manufacturers depend on assessments made in proprietary small test mills or full size mill tests with large samples to give more confidence to anticipated performance of mills with the specification coal(s) With the multitude of mill designs available there is no reason to expect that the capacity of each type should be related to HGI according to any universal relationship
The Hardgrove test is limited in its application as it is a batch operation which is then related to a continuous process Mills
are air swept so that as comminution proceeds fine particles are quickly removed from the grinding elements whereas they remain in the grinding zone in the Hardgrove machine (Hardgrove 1938)
Values of HGI for coal lie in the range 25-11 O Within the range of 42-65 HGI is probably a good indicator of grindability providing the other properties (moisture specific energy etc) are considered Outside this range confidence in HGI is not so good (see Figure 14) Many attempts have been made to correlate HGI with coal composition (Singer 1991) but whilst there is a general trend with coal rank as seen in Figure 15 the scatter is enormous For example the HGI for high volatile bituminous A coals range from 30 to 75 a factor of 25 The scatter could be accounted for by the distribution of macerals in the coal (Fortune 1990) The milling properties of the different maceral types can give rise to segregation of macerals within particular size ranges For example vitrinite tends to be more brittle than exinite or inertinite and is usually concentrated in the finer fraction of the milled coal (Falcon and Falcon 1987 Conroy 1991) In addition vitrinite and exinite are more reactive than inertinite so that a greater concentration of inertinite will generally be found in the unbumt fuel than in the parent coal Inertinite also tends to concentrate in the larger particle size ranges where its lower reactivity has a noticeable effect on bumout It should be noted that this will depend on the different forms of inertinite as some types are more reactive than others (Bailey and others 1990) These observations are dependent greatly on maceral distribution within the coal Macerals in some coals occur in discrete layers whereas in others (for example South African coals) they can occur as intimate associations (Falcon and Ham 1988) The distribution as
20
16
ist5 12 2 2shy0 ro g- 08 ()
04
o
curves extrapolated to zero capacity usefull range for
(HGI =13) curves
range in which bituminous coals are found
Hardgrove grindability index (HGI)
Figure 14 Variation in capacity factor with HGI for different fineness grinds (Fortune 1990)
40
Pre-combustion performance
o
o o
bull Ball mill indexes
Hardgrove tests converted to equivalent Ball mill indexes
bull bull 0
ltlOl 0
etgtz l 2 2
100 - o o o
90
o80
a 70S xOl U ~ 60 pound 0 ro 50 U sect 01 Ol 40 gt e -e01 bull ro 30 I U 0 m
en enJ J Jroen middot0 middot020 Olen Olen ~ 0 0 degoJ _J _J ro ro c c 0 oen len~ gt 0 0 J c cmiddotE middotE EJ~ roc roc gtJ
C middot02 CEo
3 omiddotE omiddotE o~ ro10 3 0 _
Eg cp ro eO2 ~~~ gtJ gtJ middot~middotE gtEmiddotc 0 0 J c~ middotE c
0 0 uJ 3J Q)ouo 010 010 Ol- C01 J J Jc 0middot Ol =i Cf) Cf) Cf)roU Im Iltl ~o -10 Cf) ltl ~
0 9 10 11 12 13 14 15 16 70 80 90 100
Moist mineral-matter-free MJ Dry mineral-maller-free fixed carbon
Figure 15 HGI for several coals as a function of rank (Elliott 1981)
described will effect the particle composition and other coal to 77 and mainly in the 60 to 70 range In general such coals physical properties These effects cannot be predicted from would not be expected to cause difficulty with grinding proximate analysis and so could account for discrepancies in the anticipated performance of coals having similar The abrasive properties of a coal and especially its associated proximate analysis values but with different petrographic minerals cause wear of the grinding elements and other compositions surfaces in the mill The extent of this wear determines the
intervals between planned maintenance periods and the Grinding of coal blends in which the components have possibility of shutdowns It is therefore of great importance widely different HGI values have shown that care is required for an operator to have an idea of how long these periods are in the interpretation of the results Byrne and Juniper (1987) likely to be and how unplanned outages caused by excessive observed that in such cases the harder material tended to mill wear can be avoided concentrate in the coarser fractions of the pulverised fuel and the softer coal in the finer fractions It was believed that this Wear is caused by one of four mechanisms (Fortune 1990) was a consequence of the softer coal blanketing the harder coal and so preventing full grinding of all the fuel adhesion
surface fatigue One difficulty with HGI is reproducibility BS ISO and AS1M abrasion standards all state that a spread of three units is acceptable This corrosion is equivalent to a 4 change in mill capacity Comparisons from different laboratories have given a reproducibility of Adhesion and surface fatigue effects in milling are negligible around eight to nine (Fortune 1990) This is equivalent to a mill compared with abrasion and corrosion capacity variation spread of 12 which is clearly unacceptable as an indication of grinding performance The rate of abrasive wear in mills will depend in general on
the following factors Attempts have been made to develop alternative grindability indices but so far none of these has attained widespread use the type of coal used especially the amount and Typical of these is the continuous grindability index (CGI) composition of the incombustible minerals associated which relates mill performance to power input It was with the coal developed for low rank coal applications A new method has the material used for the mill rolls and bowls also been proposed for determining coal grindability and the design of the mill abrasivity properties using a single machine by Scieszka (1985) although it should be noted that this work was based The most widely used abrasion test is the Yancey Geer and on a limited range of coals with HGI values ranging from 39 Price (YGP) test (Yancey and others 1951) although its
41
Pre-combustion performance
repeatability varies with coal characteristics For abrasive coals the repeatability is about 3 However for coals with low abrasiveness repeatability may be as low as 18 Babcock Energy Scotland use a similar test but with a smaller coal sample (Cortsen 1983) Babcock amp Wilcox in the USA has developed an abrasion test using a radioactive tracer technique (Goddard and Duzy 1967) This test produces a measurement of mill wear albeit at a laboratory scale
Literature data indicate that coal itself is not very abrasive (Parish 1970) Of the associated minerals usually present in coal only quartz (SiOz) and pyrite (FeSz) are considered to be hard enough to cause significant wear Other minerals mainly clays are generally quite soft and friable and do not contribute much to mill wear The earlier studies have shown some correlation between wear and quartz or pyrite content of the coal but the correlations obtained were generally not widely applicable (Parish 1970) In investigations carried out by Donais and others (1988) it was found that as well as the total amount the size of the quartz and pyrite grains significantly affected the wear rate The study was carried out on eight different US coals using NIHARD rolls in both Babcock amp Wilcox and Combustion Engineering mills In general the data indicated that the coarser fractions of quartz and pyrite contribute more to mill wear than the finer size fractions The best correlation between the data was as described in the following expression
Abrasion (radial wear per tons of throughput) =F (3 Q+ P)
where F = constant
Q = ( Quartzgt100 Ilm) P = ( Pyrite gt300 Ilm)
Donais and others (1988) found that the intercept of the curve from the above relationship on the Y axis (mill wear) was well above zero indicating that the effect of the finer fractions of the quartz and pyrite are not negligible and that the coal itself or other minerals may also contribute to wear It should be noted that the size distribution of pyrite and quartz are not normally measured and are not usually included in coal specifications
Other experimental techniques for abrasion testing are summarised in an early report by Parish (1970)
Erosion by mineral particles picked up in the air stream carrying pulverised coal through the mill classifier and ducting is a recognised problem The following parameters affect erosion rates
stream velocity - erosion rate increases exponentially with velocity For ductile materials the exponent is about 23 for brittle materials the exponent ranges between 14 and 5 impingement angle on mill surfaces - maximum erosion rates occur at 30deg for ductile materials and at 90deg for brittle materials particle size - erosion rates increase with particle size up to a critical size above which no increase is observed
323 Size classification and transport
Reduction in oversize particles after initial milling is achieved by separation and recycling of particles through the mill to be reground until they are sufficiently small to pass through a classifier The classifIer can be adjusted to vary the final fineness of the coal Coal fineness affects essentially all processes occurring downstream of the mill including ignition flame stability flame shape ash deposition char burnout etc However if the classifier is adjusted for greater fineness to accommodate for example the firing of a lower volatile coal (see Section 41) the amount of material recycled back to the grinding zone increases This alters the grinding process and if the coal mass in the grinding zone increases too much the grinding elements may begin to skid or excessive spillage can occur The initial coal particle size and grindability can affect the fine tuning of the classifier
The primary air flow rate to the mill is based on the requirements of the burner mill and pulverised coal transport At full load the air flow rate usually corresponds to an aircoal mass ratio of about 20 For a given size of pipes the air flow rate can be adjusted over a narrow range only without causing de-entrainment of PF or increasing pipeline wear for lower or higher rates respectively For a given mill for example ring ball type roller mills supplied with design coal and having 20 of total air as primary air at full load the calculated coalair ratio changes from about 05 kgkg to about 036 kgkg by reducing load from 100 to 50
The relationship between primary air flow rate and coal flow rate is established by the mill manufacturer Moisture content of the coal determines the necessary primary air temperatures as discussed earlier in Section 321 Moisture content of the coal may therefore influence effective and accurate transport of the coal through the mill
33 Fans Coal fired steam-electric units use a number of fans to move air flue gas and pulverised coal The major type of fans include
forced draft (FD) fans - supply air to the wind box under positive pressure induced draft (ID) fans - withdraw flue gas from the furnace and balance furnace pressure primary air (PA) fans - supply air to the mills flue gas recirculation (FGR) fans - recirculate flue gas from the economiser outlet to the burners or the wind box
The performance of the fans can be impacted by changes in coal quality
A typical arrangement of the major fans at a steam-electric unit is illustrated in Figure 16 The major path flow involves the FD and ID fans It should be noted that the fan arrangement shown in Figure 16 is not fully representative of all coal fired steam-electric units The number and arrangement of the fans and other components can vary substantially Also the pressures and temperatures of the air
42
Pre-combustion performance
air FD forced draft exhaust to FGR flue gas recirculation stack - - - - - - flue gas 10 induced draft
-----_ _-- coalair PA primary air I
1_1I __ Tempertures are approximate and may vary with plant design and operating parameters ambient air I EMISSION I
PA HEATER (air side)
PULVERISERS
-
I PA 1 FAN
-
I CONTROL I I EQUIPMENT
--T-shyt 150degC
AIR HEATER (air side)
( V
I
EMISSION CONTROL
EQUIPMENT
air heater leakage
--------+--------shy
AIR HEATER (gas side)
I
r------ -----jI
I 3700C 1 I
CONVECTIVE COLLECTOR
FGR OUST
_PA__S_ __ 2DC
1 370degC
FGR FAN FUR~ACE
g
__roaka 0I 3700C
- - - - - -+ - - - - ~ - - - -~ - - shy
wind box
burners~bullbullbullbull ------------- bullbullbull ----------- ---- bullbull ------ bullbullbull -------------- bullbull - --- bullbull --shy
Figure 16 Typical utility boiler fan arrangement (Folsom and others 1986c Sligar 1992)
43
Pre-combustion performance
entering the fans depend on the overall plant design Thus to change in flow rate required evaluate the impact of coal quality on fan capacity it is change in system resistance necessary to specify the details of the fan design and change in fan inlet conditions operating characteristics as well as the power station change in rate of fan erosion arrangement To evaluate fan capacity only the characteristics at maximum performance settings need be The flow rate through the fan could be changed in a number considered of ways by changes in coal quality For example an increase
in coal moisture will increase the flue gas volume flow rate Changes in coal characteristics can impact fan performance Changes in heating value of the coal would require a change in four ways to the airfuel ratio and hence the firing rate The excess air
Table 17 Summary of the effects of coal properties on power station component performance - I (after Lowe 1987)
Property Contributing properties Effect
Coal handling and storage Heating value
Coal flow properties
Freezing
Dustiness
Combustibility (spontaneous combustion)
Mills
Drying
Mill throughput
Wear
Fans Flow rate
moisture ash ultimate analysis
moisture coal size distribution mineral matter analysis bulk density
types of moisture
moisture size analysis mineral matter analysis porosity
coal rank moisture size distribution sulphur
moisture
volatile matter
total moisture
Hardgrove grindability index (HGI)
raw coal top size
pulverised fuel size
distribution
mineral matter analysis (quartz amp pyrite) mineral matter size distribution
moisture slagging propensity fixed carbon
A 1 decrease in heating value increases required mass throughput of coal by 1
As flow properties degrade coal throughput remains relatively constant until catastrophic blockages occur at a critical flow property value This value is highly site specific
Surface moisture at low temperatures is the primary cause of freezing
Increased operating and maintenance costs with dusty coals Potential for increased loss of availability
Heating value of stockpiled coal decreases due to spontaneous combustion Plant layout and procedures are dictated by spontaneous combustion
MiD type
Low speed Medium speed Influences primary air requirements and power consumption for both types of mill Mfects the susceptibility of both mill types to mill fires
-3 throughput for 1 moisture -15 throughput for 1 increase moisture increase above
approx 12 moisture -1 throughput for 1 unit -1 throughput for 1 reduction in HGI unit reduction in HGI Caution when using HGI for interpreting coal blend behaviour -3 throughput for 5 mm increase No loss in throughput below in top size 60 mm top size Reduction in fraction passing Reduction in fraction passing
lt75 JlII1 mesh screen by 035 for lt75 Ilm screen by 09 for 1 increase in throughput 1 increase in throughput Influences the component operation and maintenance rate for both types of mill
An increase in moisture increases the flue gas volume flow rate Influences the excess air requirements
44
Pre-combustion performance
required for a specific coal depends on the slagging propensity of the coal carbon burnout and boiler steam temperature considerations These effects are difficult to predict and the actual value of excess air used is determined by the operators to achieve the best balance
The system resistance can also be affected in a number of ways For example fouling of the convective pass increases ID fan resistance on units with induced or balanced draft (Folsom and others 1986b) Fly ash loading in the flue gas can influence the performance for example increased fan blade erosion can occur with increased quantities of fly ash (Sligar 1992)
34 Comments Table 17 summarises the effects of coal properties on the performance of the power station components discussed in this chapter It has been shown that whilst many empirical
relationships have been developed and used to describe the problems that are encountered in the power station there are some signifIcant uncertainties related to many assumptions made These can include for the components described in Chapter 3 the following
coal handling and storage - oxidation dusting flowability and freezing cannot be predicted from coal composition measurements mills - there is no way to evaluate the fineness requirements accurately Mill capacity for blends of coals and for lower rank coals are difficult to evaluate using existing HGI correlations fans - air and gas flow rates depend on excess air Excess air depends on flame stability carbon burnout and slaggingfouling considerations There is no satisfactory method of predicting the effect of these relationships for specific coals Twenty per cent excess is often assumed
45
4 Combustion performance
41 Burners For ignition to take place four elements must be present
fuel air sufficiently high temperature ignition energy availability
A pulverised fuel burner solves this task by blowing a mixture of pulverised coal and air into a part of the furnace where there is a high temperature When lighting up the burner this high temperature is secured locally with an ignition system The burner itself however must be designed in such a way that a stable flame is achieved after the ignition flame is extinguished and it must be able to keep the flame stable and provide optimum combustion The loss of a flame on tum-down even within normal control ranges constitutes a serious dust explosion hazard (Cortsen 1983) Sustained combustion without support fuel also requires consistent coal quality Pockets of high ash can cause momentary extinction and subsequent risk of explosion when fuel returns
A number of physical and chemical processes occur extremely rapidly within the flame It is difficult to describe the number of interactions and complexity of the reactions occurring In spite of many years of theoretical flame research burner design is still based on practical experience though in more recent years this has been supplemented with pilot- and full-scale experiments (Knill 1987 Noskievic and others 1987 Harrington and others 1988 Kosvic and others 1988 Repic and others 1988 Penninger 1989)
Ignition stability is strongly influenced by the characteristics of the coal The conventional method of evaluating the impact of coal characteristics has been to consider the volatile content of the coal and the presence of inert material (moisture and ash) However even if two
coals have the same proximate analysis their ignition characteristics may still be very different due to differences in chemical structure
There are three distinct groups of coal with respect to ignition according to Truelove (1985)
lignites and subbituminous coals with high inherent moisture and high volatile matter content greater than 50 bituminous coals with proximate volatile matter content between 20 and 50 anthracite and semi-anthracite with volatile matter content less than 20
Notwithstanding the high volatile matter content low rank coals can still be difficult to ignite because the high moisture lowers the flame temperature and dilutes the volatilesair mixture The energy required to evaporate 15 moisture and superheat it is equal to the energy required to heat the coal material to 500degC When the moisture content exceeds 40 the coal can be dried using hot flue gas with the result that the primary coaVair stream is heavily loaded with inert water vapour and products of combustion In contrast to the difficulties associated with the ignition of low rank coals the char resulting from high-moisture high volatile matter coals is generally highly reactive
Low volatile coals are much more difficult to ignite In these cases the heat released during the combustion of volatiles is usually insufficient to raise the temperature of the char to ignition and hence sustain combustion It may be necessary to provide continuous support fuel to maintain combustion Ignition stability with low volatile coals can be enhanced by grinding the coal finer and using high preheat for the combustion air Table 16 shows recommendations for pulverised coal fineness based on the volatile matter content (Cortsen 1983) Bituminous coals with volatile contents above 25 should present few problems with ignition
46
Combustion performance
Modem independent burners all use strongly swirling air flows to achieve flame stability and control flame length and width and combustion intensity The application of swirl produces short and intense flames Although excess swirl especially in the primary stream may delay ignition due to rapid mixing of the primary coaVair stream with the relatively cool combustion secondary air
The effect of ash on flame stability has been studied at the International Flame Research Foundation (IFRF) in the Netherlands No significant differences in ignition and flame stability were found when firing 6 ash and 30 ash high volatile coals provided that the fuel was well mixed and delivered to the burner at consistent quality
In the efforts to cut NOx emissions virtually all the combustion-equipment manufacturers are involved in the development of low NOx coal burners Many utilities already utilise the technology Intensive research has focused on the formation of NOx which is influenced greatly by combustion conditions This is discussed further in Section 523
42 Steam generator The ability of the steam turbine to generate power at full capacity depends on an adequate supply of steam at the correct temperature and pressure The steam supply and quality is dependent on the heat release occurring in the furnace and the heat transfer from the resulting gases to the various boiler surfaces located in radiant and convective banks
The effects of coal characteristics on boiler heat transfer and ultimately steam conditions are complex and closely related to the arrangement of large steam generators Factors such as the layout of radiative and convective heat transfer surfaces in the gas side and location of boiling and non-boiling regions on the steam side are critical This section considers how coal characteristics can affect both heat release and heat transfer processes via the mechanisms of fuel combustion and ash deposition
421 Combustion characteristics
Insight into the influence of coal properties on pulverised coal combustion can be gained by examining the factors affecting combustion There is an extensive amount of literature which reviews the work carried out in the field of pulverised coal combustion An lEA Coal Research report Understanding pulverised coal combustion by Morrison (1986) reviews the literature mainly post 1980 on the fundamental processes and mechanisms of pulverised coal combustion Others include reviews by Laurendeau (1978) Essenhigh (1981) Smoot (1984) Smoot and Smith (1985) Heap and others (1986) and Singer (1991) Only a brief description will be given here
The combustion of individual coal particles comprises the following sequence of processes which are partly overlapping and are all dependent on both physical conditions and coal properties
heating of the particle
release of volatile matter combustion of volatile matter combustion of the char
Heating of the particles occurs very quickly The temperature gradient is 105_106degCs depending on the size of the particle Thus a 60 lm particle may achieve furnace temperature within 005-01 s
Release of volatiles occurs within the similar time span but varies with coal quality and particle size The initial gases released ignite and bum momentarily consuming the oxygen present in the air surrounding the particle At this stage the volatiles bum independently of the char particle The devolatilisation of coal at high heating rates is an important stage because it may control
the rate at which combustion proceeds the rate at which oxygen is consumed the rate and form of evolution of nitrogen sulphur and other species together with the mechanisms governing the fate of these species
Depending on temperature and coal quality char combustion may be initiated before combustion of all volatile constituents is completed For successful combustion the heat release associated with the gas-phase reaction must raise the bulk gas temperature sufficiently to ignite the char The rate of char combustion is dependent upon several factors
initial coal structure variations diffusion of reactants reaction by various species (02 H20 C02 H2) particle size effects developed pore diffusion char mineral content (catalysis) changes in surface area as the reaction proceeds char fracturing variations with temperature and pressure
The time required for consumption of a char particle represent a significant portion of the overall time required in the coal reaction process and can range from 03 s to over 1 s (Smoot 1984)
The watersteam temperature balance in a boiler is influenced greatly by the burning profile of the coal that is the rate at which coal passes through the different stages of combustion the heat release associated with them and take-up by watersteam (Singer 1991) During combustion gas temperatures are near 1800degC but the gases must cool to the design point temperatures (usually around 1200degC) of the convective sections of the boiler so that they may be maintained in a satisfactory condition of cleanliness (see Section 422) If the coal bums too quickly
too much heat may be absorbed in the radiant section of the boiler When the gases subsequently reach the superheater tubes they may be too cool to raise steam temperature to the levels necessary for efficient turbine operation and full capacity utilisation temperatures at the radiant section can rise too high and
47
Combustion performance
cause circulation problems or increased boiler slagging (see Section 422) thus raising the incidence of forced outages
If the coal bums too slowly temperatures in the radiant section do not reach design levels and gases reaching the superheater tubes may be hotter than l200dege Thus there can be a decrease in boiler efficiency through
decreased steam production fouling of superheater tubes (see Section 422) increased carbon loss loss of superheater temperature control increased risk of fires in the economiser hopper air heater and particulate control system higher than desired exit temperature of exhaust gases
Many attempts have been made to establish empirical correlations between combustion behaviour and coal properties The volatile matter content is most commonly used as an indicator for ignition behaviour of a particular fuel Similarly heating value and ash content provide a guide to flame stability
The heating value of the coal is important as it constitutes the amount of energy that can be imparted to the system Moisture and total ash content act as negative influences to the energy supply by affecting the adiabatic flame temperature and firing density
The combustibility or reactivity of a coal can be characterised by two factors (Wall 1985a)
volatile matter yield and composition (Jiintgen 1987a Morrison 1986 Saxena 1990) reactivity of char - char reactivity generally increases with decreasing rank in PF combustion (Smith 1982 Morgan and others 1987) so that the rate of combustion is similarly dependent on rank (Shibaoka and others 1987 Jiintgen 1987b Oka and others 1987) However Cumming and others (1987) and Bend (1989) found that rank was not an accurate guide for high volatile bituminous coals from different origins The amount of char produced has been shown to be related to the proximate analysis fixed carbon content petrographic composition and initial coal particle size
An index that relates both of the parameters above is the fuel ratio that is fixed carbon divided by volatile matter as determined by proximate analysis can be used as a measure of coal reactivity The fuel ratio provides an indication of the relative proportion of char to volatiles Although correlations between the fuel ratio and carbon burnout have been found (for example Baker and others 1987) there are exceptions (Oka and others 1987) A higher fuel ratio does not necessarily indicate a coal of lower reactivity and high carbon burnout (Figure 17) This is not surprising since both volatile matter and fixed carbon determinations relate to laboratory test conditions which do not represent the conditions encountered in PF boiler As was discussed in Section 21 proximate volatile yield is generally lower than the true volatile yield as it is sensitive to test conditions
20
C----------) indicates trend reversal
These comparisons 10 contradict the rule that a higher fuel ratio necessarily means higher unburnt carbon and lower reactivity
Coal sized to +125-150 Ilm 5
Peak temperature 1300degC
2
10
c o 0 CB U
c 05s
0 c J
02
01 -t----------+-------------
05
Fuel ratio fixed carbonvolatile matter
Figure 17 Fuel ratio as an indicator of coal reactivity (Smith 1985)
(Morgan 1987) Similarly proximate fixed carbon makes no allowance for the differing reactivity of chars formed from different coals (Oka and others 1987 Smith 1982) Fuel ratio has also been found to be unsuitable for assessing low rank coals
Many utilities have found that volatile matter content information alone is a poor indicator of coal furnace performance they are tuming to the use of advanced test methods Further test procedures have been developed by boiler manufacturers and utilities which give a better insight into the influence of coal properties on combustion characteristics For example thermal gravimetric analysis (TGA) may be used to evaluate the characteristics of coal with respect to particle coal heating and volatiles ignition It should be noted however that TGA test conditions can also differ largely from the conditions present in a PF boiler An example of a TGA test requires a coal sample to be heated at
10 20 40
48
Combustion performance
a controlled rate in a controlled environment The weight loss of the sample is recorded continuously as a function of time (or temperature) The burning profiles determined in TGA are often used as a characteristic fingerprint for a coal These will be compared to a standard coal with an established boiler performance (Cumming and others 1987 Morgan and others 1987) The TGA can also be used to determine the reactivity of coal chars prepared in situ or in other test apparatus such as drop tube furnaces (DTF) or entrained flow reactors (EFR) (Jones and others 1985 Morgan and others 1987 Crelling and others 1988 Hampartsoumian and others 1991)
The DTF or EFR apparatus can also be used to determine the reactivity of coalschars under a range of conditions The apparatus can be utilised under conditions similar to those experienced in a boiler In these tests a consistently higher extent of volatile release is measured than in the volatile matter test of the proximate analysis (Morrison 1986 Knill 1987 Gibbs and others 1989) Carbon burnout can be determined along with the reaction rates for the different stages of combustion (Wall 1985b Skorupska and others 1987 Tsai and Scaroni 1987 Diessel and Bailey 1989 Smith and others 1991a Chen and others 1991) This topic has also been reviewed by Unsworth and others (1991)
Other apparatus used for volatile matter release rates and coalchar reactivity determinations include the heated wire grid apparatus flat flame burners pyroprobe and pilot scale furnaces
All these tests provide data on the devolatilisation and combustion characteristics of coal in considerably more detail than the data provided by standard proximate analysis The boiler manufacturers have developed methods of utilising the test data to predict boiler performance However it should be recognised that these tests are used subject to individual choice and interpretation They are not widely accepted in the utility industry as standards Currently the tests results are meaningful only in the context of a background database for a particular installation which includes accumulated measurements on fuels in the specific test facilities as well as field operating systems The most direct method of utilising the tests would be to compare the performance of specific coals to a base coal whose performance in the subject boiler is well documented In cases where such an approach is not practical it is necessary to rely on laboratory data and modelling to extrapolate the results to full scale However the test procedures particularly in the case of DTF apparatus are complex and since the test facilities have been used primarily as research tools there are no accepted standards
422 Ash deposition
Ash deposition is one of the most important operational problems associated with the efficient utilisation of coal (lEA Coal Industry Advisory Board 1985 Jones and Benson 1988) Since deep cleaning of coal is expensive (Couch 1991) ash is present in all coal-fired furnaces and must be carefully controlled
Equipment manufacturers have used several approaches for
108wx 106d 126 w x 124 d
D D D L wxd 116wx108d
r130 h
U Eastern Western Lignite
bituminous subbituminous coal coal
Siagging propensity low-medium high severe high Fouling propensity low-medium high high high
Midwest (Illinois)
bituminous coal
Furnace size is also affected by coal heating value - moisture - volatile matter
Figure 18 Influence of ash characteristics of US coals on furnace size of 600 MW pulverised coal fired boilers (Babcock amp Wilcox 1978)
ash management to accommodate effective collection and disposal of the deposit Dry and wet bottom furnaces utilise very different operational conditions to achieve this goal (Hatt 1990) Most pulverised coal units that are offered today are of the dry bottom type although wet bottom or slagging bottom furnaces may still be offered for special applications
Since the presence of ash is unavoidable coal-fired power stations are designed to tolerate some deposit on tube surfaces without undue interference of unit operation Knowledge of ash deposition tendencies of coals is important for boiler manufacturers as boiler design features can be varied to accommodate difficult coals Figure 18 describes how one manufacturer accommodates various ash characteristics by adjustment of furnace dimensions and the number of deposition removal systems such as wall blowers The criteria of several utility boiler manufacturers for designing boilers to avoid deposition have been reported by Barrett and Tuckfield (1988) It was observed that each manufacturer applied a different set of criteria and placed different emphasis on the coal analyses details used for prediction of ash depositional behaviour
The occurrence of extensive ash deposits can create the following problems in a boiler
reduced heat transfer - due to a reduction in boiler surface absorptivity and thermal resistance of the deposit impedance ofgas flow - due to partial blockage of the gas path in the convective section of the boiler
49
Combustion performance
physical damage to pressure parts - due to excessive loading of the structures andor impact damage when pieces of the deposit break off and fall down through the furnace corrosion ofpressure parts - due to chemical attack of metal surfaces by constituents of ash erosion ofpressure parts - resulting from abrasive components of fly ash
If the deposits cannot be removed by wall blower or soot blower operation the load on the boiler may have to be reduced to lower furnace temperatures to the point where ash softening is controlled and wall andor soot blowers become effective It is not unusual to observe power stations that must drop loads to about one-third of capacity at night to shed slag accumulated during high-load day time operation (Barrett and Tuckfield 1988) In extreme cases the boiler
Extraneous minerals
must be shutdown and the deposit removed by hand Frequent maintenance and unscheduled shutdowns for removing these deposits and the repair of the effects of corrosion and erosion add substantially to the cost of power generation These problems can result in reduced generating capacities and in some cases costly modifications (Bull 1992)
Deposit problems within a boiler are classified as either slagging or fouling Different definitions of slagging or fouling are used by different people Some people refer to the nature of the deposit - defining molten deposits as slagging and dry deposits as fouling Others define slagging and fouling by the section of the boiler on which the deposit occurs (Borio and Levasseur 1986) For the purposes of this report slagging refers to deposits within the furnace and on widely spaced pendant superheaters in those areas of the unit
bull pyrite 1100degC --------- fusion clays 1300degC
quartz 1550degC
~ expansion
~
Inherent minerals
bull M cenospheres
Y
Na K Heterogeneous 8 ~ condensation Mg ~
80 Homogeneous I __ nucleation
MgO coalescence
surface enrichment
coalesce~--------------I~~ euroY-----~ bull 30~m
p~QD~--- quench ---1~~ ~Qi) 10-90 ~m
disintegration
~
Figure 19 Mechanisms for fly ash formation (Wibberley 1985b Jones and Benson 1988)
50
Combustion performance
which are directly exposed to flame radiation Fouling refers to deposits on the more closely spaced convection tubes in those areas of the unit not directly exposed to flame radiation
Ash slagging and fouling give rise to the first four problems listed above The fifth problem erosion is the result of the impingement of abrasive ash on pressure parts Often coal ash deposit effects are inter-related For example the build up of ash deposit layers on tube walls and superheaters does not only reduce furnace and overall boiler efficiency but can also increase the temperature level in furnace and convective passages and aggravate existing deposit problems The characteristics of the deposit layer change so as to reduce the heat transfer to the surface locally the gas temperature in the furnace will rise partially ameliorating the impact However the net effect is that furnace deposits (slagging) decrease the heat transfer in the radiant furnace and increase the furnace exit gas temperature This can lead to enhanced fouling problems in the convective pass if the ash particles enter the convective tube bundles in a sticky state Ash deposits accumulated on convection tubes can reduce the cross-sectional flow area increasing fan requirements and also creating higher local gas velocities which accelerate fly ash erosion In situ deposit reactions can produce liquid phase components which are instrumental in tube corrosion
The coal ash deposition process involves numerous aspects of coal combustion and mineral matter transformations reactions The importance of the furnace operating conditions on the combined results of the above areas must also be stressed For a given coal composition furnace temperatures combustion kinetics heat transfer to and from the deposit and residence times generally dictate the physical and chemical transformations which occur (Barrett 1990) The ash formation process is therefore dependent on the timetemperature history of the coal particle and the heterogeneous nature of the mineral matter in coal Each pulverised fuel particle may behave uniquely as a result of its composition Figure 19 summarises the mechanisms for fly ash formation
The ash transported through the combustion system only becomes a problem if it is first transported to the heat transfer surface and subsequently sticks to that surface Particle size particle density and shape affect transport behaviour (Borio and Levasseur 1986)
In addition to transport phenomena the three requirements for the formation of deposits from a gas stream containing inorganic vapour and fly ash are (Wibberley 1985b)
the vapours and fly ash penetrate the boundary layer of the tube and contact the metal surface the material adheres to the tube surface sufficient cohesion occurs in the deposit to allow continued growth without periodic shedding under the influence of its own weight vibration soot blowing temperature cycling in the furnace etc
The initial deposit layer is significant as it represents the boundary between the tube metal or rather oxide and the remainder of the deposit Adhesion between the tube and the
first deposit forming material from the fumace gases may involve several factors
surface attraction between the fine ashcharged ash and the tube inherent roughness of the tube which is increased by oxide whisker growth or growths of desublimed alkalis liquid phases on the tube surface formed by supercooling of condensing alkalis reactions involving desublimed alkalis or alkalis pyrrhotite fly ash sulphur compounds and the tube metal to form low melting point complex salts such as Na3Fe(S04)3 Tm = 627degC sticky fly ash particles with either supercooled sodium silicates or condensed alkalis on the surface of the ash and species migration through the deposit
As the deposit thickens the temperature at its outer surface increases at the rate of 30-100degCmm depending on the thermal conductivity of the deposit and the local heat flux to the deposit (Wibberley 1985a) The increasing temperature decreases the viscosity of any liquid phases present which in tum increases the retention of larger fly ash particles impinging on the tube and also the rate of deposit consolidation by sintering and sUlphation
As the size of the fly ash retained at the deposit surface increases its surface becomes increasingly irregular (secondary deposit layer) The rate of deposition is highest where the deposit extends furthest into the oncoming gas stream This causes projections to form Continued growth of the deposit depends on simultaneous growth and consolidation Consolidation involves sintering and sulphation which are enhanced by the increasing temperature in the outer regions of the growing deposit
Siagging Slagging deposits typically form on the water wall section of boilers near the burner region In this region the water wall tubes surfaces are typically in the region of 200degC to 425degC (400degF to 800degF) a temperature too low for mineral matter to form molten deposits The fireside layer of a slagging deposit may consist of a running fluid in which all the fly ash has dissolved or it may consist of a glassy phase impregnated with particles of fly ash (Bryers 1992) Formation of slagging deposits is a time dependent phenomenon Situations are commonly encountered within a boiler where initiation of slag deposits in one region of the boiler will propagate to other regions of the boiler as the heat transfer through the water wall tubes is continually reduced and the temperature of the flame and the deposit increases This influence on heat absorption has been demonstrated using pilot combustor facilities to monitor the effect and rate of deposit build up on heat flux on panels designed to simulate boiler water wall surfaces (Abbott and Bilonick 1992) Figure 20 shows the average per cent heat flux recovery for soot blowing cycles at two different coal firing rates for a range of US coals The work demonstrated that the ash deposits from different coals prove to have a range of tenacities as demonstrated by the different values of heat flux recovery
Determination of the elemental composition of slagging deposits in comparison with equivalent compositions of fly ash have
51
Combustion performance
1 washed Pittsburgh seam - medium sulphur 2 run-at-mine Pittsburgh seam - medium sulphur 3 Pittsburgh seam - low sulphur 4 Pittsburgh seam - high sulphur 5 Illinois No 6 seam - low sulphur 6 Roland seam 7 60 Roland40 Illinois No 6 - low sulphur blend
Figure 20 Heat flux recovery for different coals and soot blowing cycles (Abbott and Bilonick 1992)
shown that there is enrichment of some elements in the deposit (Borio and Levasseur 1986) The results of such an analysis are shown in Table 18 This analysis shows some depletion of silica (Si02) alumina (Ah03) and lime (CaO) in the deposit and an increase in hematite (Fe203) In some cases direct impaction of unspent pyrite on hanger tubes and the leading edge of the first row of convection bank tubes can cause an iron-rich deposit to form that is 75-90 Fe203 in the deposited ash The deposit is semi-fused as pyrrhotite and is further oxidised to hematite or magnetite While bulk analysis of deposits on water wall tubes can give an insight into the formation of the deposits still more information can be gained from chemical analysis of different layers within the deposits which are seldom homogeneous and vary with time
Wain and others (1992) have also illustrated that slag
deposits from different UK coals can exhibit a range of chemical and physical properties At one extreme the slag may be highly porous and friable having little mechanical strength while at the other extreme the slag deposit may be dense and fused with great strength Susceptibility to removal processes was shown to be related to the porosity of the slag formed which in tum is dependent upon ash composition and operating conditions Earlier work indicated that the physical state of the deposit can have a significant effect on the radiative properties In particular molten deposits show higher emissivitiesabsorptivities than sintered or powdery deposits (Goetz and others 1978) Thin molten deposits are less troublesome from a heat transfer aspect than thick sintered deposits However molten deposits are usually more difficult to remove and cause frozen deposits to collect in the lower reaches of the furnace where physical removal can no longer be carried out with wall blowers
Fouling In all coal-fired units ash deposits build up on the convective pass tube bundles due to the flow of the particulate laden flue gas over the tubes The boiler manufacturers attempt to design their units to avoid the uncontrollable build up of deposits in this region Fouling problems occur when the strength of the deposits is high and the action of soot blowers is unable to remove the deposits It should be noted that with fouling there is no analogue to the wet bottom approach to slagging that is units cannot be designed to accommodate fouling problems by ensuring that the ash deposits are removed from the convective pass tubes as liquids
As with slagging the bonding of ash particles to the tube surface depends on the physical state of the particles approaching the tubes and wetting action of the ash on the tube surface However in the convective pass the temperature difference between the particles (and gas) and the tube surface is much less than in the radiant furnace so that the quenching action of the particles impacting the tube surface is greatly reduced
Organically-bound sodium and sodium chloride are most frequently the cause of convective bank fouling in low rank coals and bituminous coals respectively (Osborn 1992) As discussed earlier many of the alkali metal compounds in coal
Table 18 Enrichment of iron in boiler wall deposits - comparison of composition of ash deposits and as-fired coal ashes (Borio and Levasseur 1986)
Unit sample Power station 1 Power station 2 Power station 3
As-fired Waterwal1 As-fued Waterwal1 As-fired Waterwal1 coal ash deposit coal ash deposit coal ash deposit
Ash composition Si02 470 333 502 551 497 418 Ah03 267 180 169 146 165 158 Fe203 146 435 59 183 120 285 CaO 22 12 128 72 65 90 MgO 07 05 35 20 09 09 Na20 04 02 06 05 11 06 K20 23 16 08 06 15 09 Ti02 13 08 09 08 11 07 S03 11 05 120 01 20 02
52
Combustion performance
vaporise readily at typical furnace temperatures They form hydroxides or oxides that react with S03 in the gas phase at the tube surface to form sodium sulphate They can react with ash particles to form low melting point eutectics or can nucleate on the surface of ash particles or tubes Thus alkali metal compounds can lead to sticky deposits on the tube surfaces Generally sodium and calcium sulphate dominate the initial layer of deposits As the deposits build up in thickness they can sinter into a strong fused mass They may include other ash particles completely encapsulated with calcium and sodium sulphate crystals The sintering process may be related to diffusion of materials through the deposits and solid phase reactions
As in the case of slagging fouling deposits also are not uniform but are built in layers of material which can differ in particle size and chemical composition
Corrosion Corrosion of the furnace wall tubes has resulted in metal depletion rates of 600 nmh or more compared to normal oxidation rates of about 8 nmh (Brooks and others 1983) Such severe corrosion drastically reduces the lifetime of the tubes and may lead to unexpected failure Fumace wall corrosion of steel tubes has been observed in virtually all types of pulverised coal boilers In extreme cases the result is tube failure and large scale requirements for replacement (Clarke and Morris 1983 Blough and others 1988) Currently corrosion is no longer the primary cause of forced boiler shutdowns owing to control strategies and regular maintenance However remedial measures are quite costly and current efforts seek to reduce this cost by substantially extending maintenance intervals (Flatley and others 1981)
The mechanisms which govern the corrosion of the furnace wall tubes are not well understood (Harb and Smith 1990) Corrosion behaviour is closely linked to conditions in the furnace Fireside corrosion can occur on both water walls and superheater tube surfaces Water wall corrosion results essentially from regions of persistent local substoichiometric combustion near the walls which may be due to coal devolatilisation andor inadequate coalair mixing The resulting low partial pressure of oxygen and a high partial pressure of sulphur (as H2S and S02) cause the formation of scales containing iron sulphides Sulphide scales grow more rapidly than the corresponding oxides They are less protective and can lead to increased stress when formed in an existing oxide scale This promotes rapid spalling of the tube surface (Wright and others 1988) Other species believed to participate in corrosion reactions include HCI This is formed on volatilisation in the flame Flatley and others (1981) postulated that HCl reacts with the outer scales of the previously formed protective oxide to create gaseous microchannels through which HCl gains access to the metal surface Once at the surface the HCI reacts with the iron to form a volatile iron chloride which is then transported back toward the bulk furnace gases The reducing environment is also known to lower ash fusion temperatures and increase mineral deposition which in turn can affect corrosion behaviour
Corrosion often occurs in definite patterns associated with the direction of the flame and has been linked to flame impingement (Borio and others 1978) Flame impingement
again creates severely reducing conditions high heat fluxes and leads to the generation of corrosive species Evidence exists that severe furnace wall corrosion of carbon steel is a consequence of poor local combustion associated with flame impingement and the delivery of unburnt coal particles to the tube surface (Flatley and others 1981) Strategies to limit NOx formation in some boilers can increase the likelihood of corrosion owing to the presence of reducing environments and enlargement of the flame zone (Chou and others 1986)
On higher temperature metal surfaces such as superheaters and reheaters two main causes of corrosion are
overheating which leads to accelerated oxidation of both fireside and steam side deposit related molten-salt attack
The latter form of corrosion can be related directly to the chemistry of the coal being burned and the steam (wall) temperature Molten salt attack concerns the development of conditions beneath a surface deposit which are conducive to the formation of a low melting salt ofthe type (NaK)3Fe(S04)3 These alkali-iron trisulphates form by reaction of alkali sulphates deposited from the flue gas with iron oxide on the tubes or from the fly ash in the presence of S03 (Shigeta and others 1987) The minimum melting point for these salts occurs at 552degC (1026degF) This type of corrosion has been associated with the presence of alkali metals sulphur and iron in coal
Chlorine can also be a contributing factor towards superheater metal corrosion if sulphate content is low While exact mechanisms can be argued there have been both liquid phase and gas phase corrosion when chlorides have been present (Latham and others 1991b Daniel 1991)
Calcium and magnesium which may also be found in coal mineral matter are known to be anticorrosive elements which inhibit the formation of alkali-iron trisulphates This is particularly true for acid-soluble calcium and magnesium contents which have an inhibiting ability for liquid-phase corrosion by forming a solid sulphate in the deposit for example calcium sulphate (Blough and others 1988) Work by Shigeta and others (1987) showed from corrosion tests that the corrosion rates were influenced by anti-corrosive elements (see Figure 21)
c 4 co E 0
-0 3E ( ()
Q 2 1 OJ
Qj
5
o 4 8 12 16
Contents of CaO and MgO
Figure 21 Effect of CaO and MgO on corrosivity deposit (Shigeta and others 1987)
20
53
Combustion performance
Erosion Erosion due to fly ash is recognised as the second most important cause of boiler tube failure (Dooley 1992) Considerable effort is being spent to understand the mechanism of fly ash erosion and to acquire the capability to predict erosion rates due to fly ash in boilers Fly ash is more erosive compared to the coal from which it originates one reason being the absence of the soft organic fraction
Table 19 Hardness of fly ash constituents (Nayak and others 1987)
Constituent Mohs Vickers Hardness kgmrnz
Mullite Vitreous material Free silica (quartz) Hematite Magnetite Coke particles with inherent and surface ash
Fume sulphate particles Anhydrite (CaS04)
5 550-600 7 1200-1500 5-6 500-1100 5-6 500-1100
3-5 100-500 (non-abrasive)
Erosion occurs at the outlet of the furnace section where the flue gas is made to tum over the top of the boiler while traversing pendant tube banks and in the rear pass especially on the sections of horizontal tube banks adjacent to the back wall of the rear pass (Wright and others 1988) Fly ash size and shape ash particle composition hardness and concentration and local gas velocities play important roles concerning the erosion phenomenon Table 19 lists the available data on hardness values of fly ash particles (Nayak and others 1987) The hardness characteristics of the major mineral contents in fly ash have not been studied extensively Work by Raask (1985) and Bauver and others (1984) has shown that quartz particles above a certain particle size are very influential in the erosion process and that furnace temperature history plays an important role in determining erosive characteristics of the particles
Many of the above phenomena discussed under the headings of Slagging Fouling Corrosion and Erosion have standard tests such as ash fusibility (see Section 25) as the basis for predicting their occurrence These bench-scale tests provide relative information on a coal which is used in a comparative
fashion with similar data on fuels of known behaviour Unfortunately although commonly used they do not always provide sufficient information to permit accurate comparison
The fusibility temperature measurement technique attempts to recognise the fact that mineral matter is made up of a mixture of compounds each having their own melting point (see Table 20) As a cone of ash is heated some of the compounds melt before the others and a mixture of melted and unmelted material results The structural integrity or deformation of the traditional ash cone changes with increasing temperature as more of the minerals melt However use of ash fusion data can be misleading Ash fusion tests typically are run in both a reducing and oxidising environment This means there is either sufficient oxygen in the atmosphere surrounding the ash particles to oxidise various minerals or there is not Generally an oxidising environment pertains throughout the combustion chamber of the boiler For a number of reasons there may be moments when as the coal and mineral particles pass through the combustion chamber there is not enough oxygen for oxidation to occur This is known as a reducing environment It is important to be aware of these conditions since if a reducing environment develops the ash fusion temperatures are lower than those occurring in oxidising conditions and can become low enough to cause slagging and fouling
The problems with ash fusion measurement is that recent results indicate that significant meltingsintering can occur before initial deformation is observed The fact that the timetemperature history of the laboratory ash is quite different from the conditions experienced in the boiler can result in differences in melting behaviour In addition the ash used in this technique may not represent the composition of the ash deposits that actually stick to the tube surfaces Often there is a major discrepancy between the composition of as-fired ash and that which is found in the deposits The discrepancies between fusion temperature results and actual slagging performance are usually greater on ashes that may look reasonably good in the laboratory One can usually assume with reasonable confidence that the melting temperature of the water wall deposits will be no higher than measured fusion temperatures although they can be and often are lower This is because deposition of lower melting constituents can and does occur with a resulting enrichment of lower melting material in the deposit Bearing all of these points in mind it is difficult to show confidence in this test as a predictor of performance
Table 20 Properties of some coal ash components (Singer 1991)
Element Oxide Melting temperature degC
Si SiOz 1716 Al Ah0 3 2043 Ti TiOz 1838 Fe Fez03 1566 Ca CaO 2521 Mg MgO 2799 Na NazO sublimes at 1276 K KzO decomposes at 348
54
Chemical Compound Melting property temperature degC
acidic NazSi03 877 acidic KzSi03 977 acidic Ah03NazO6SiOz 1099 basic Alz03KzO6SiOz 1149 basic FeSi03 1143 basic CaOFez03 1249 basic CaOMgO2SiOz 1391 basic CaSi03 1540
Other tests such as ash viscosity measurements suffer from shortcomings These tests are conducted on laboratory ash and on a composite ash sample Viscosity measurements are less subjective and more definitive than fluid temperature determination for the assessment of ash flow characteristics The usual procedure for assessing slag viscosity for wet bottom furnaces is to correlate the temperature at which the viscosity of coal ash slag is 250 poise This is defined as T250 Viscosities for dry bottom furnaces are usually conducted at higher temperatures These values can also be calculated from ash analysis Thompson and Gibb (1988) reported that in a study of nine UK coal ashes with a high iron content the slagging propensities as determined by ash viscosity tests was broadly in keeping with expectations though four of the samples showed contradictory behaviour During pulverised coal firing a severe problem may already exist before slag deposits reach the fluidrunning state Generally only a small quantity of liquid phase material exists in deposits and it is the particle-to-particle surface bonding which is most important
Tests utilising the electrical resistance properties of ash have also been developed and these are perceived as being superior to the standard ash fusibility test for providing an indicator of the onset of ash sintering (Cumming 1980 Lee and others 1991)
Much use is also made of the ash composition which is normally a compilation of the major elements in coal ash expressed as the oxide form Coal ash can be classified as one oftwo types viz
bituminous-type Fe203 in ash is greater than the sum of CaO + MgO in ash lignitic-type Fe203 in ash is less than the sum of CaO + MgO in ash
From the compilation of elements expressed as oxides from the ash analyses judgements are often made based on the quantity of key constituents like iron silicon aluminium and sodium
Using the results obtained from a standard ash analysis the measured oxides can be separated into basic and acidic components (see Table 8 and Table 20) The acidic components are those materials which will react with basic oxides They include Si02 Ab03 and Ti02 The basic ash constituents are those materials which will react with acidic oxides They include Fe203 CaO MgO Na20 and K20 The base to acid ratio is the ratio of the sum of the basic components to the sum of the acidic components Baseacid ratios are used as indicators of ash behaviour normally lower melting ashes fall in the 04 to 06 range It has been shown that baseacid ratios generally correlate well with ash softening temperatures so although baseacid ratios have helped explain why ash softening temperatures varied it has not improved the predictive capabilities (Borio and Levasseur 1986) Other ratios such as FeCa and SiAI have been used as indicators of ash deposit behaviour Ratios like these have helped to explain deposit characteristics but their
Combustion performance
use as a prime predictive tool is questionable especially since these ratios do not take into account selective deposition nor do they consider the total quantities of the constituents present An FeCa ratio of two could result from weight per cent ratios of 63 or 3015 the latter numbers would generally indicate a far worse situation than the former but the ratio does not show this
Many of the slagging and fouling indices described earlier in Table 8 are based upon certain ash constituent ratios and corrected using such factors as geographical area sulphur content sodium content etc One commonly used slagging index uses both BaseAcid ratio and sulphur content Factoring in sulphur content is likely to improve the sensitivity of this index to the influence of pyrite on slagging (As previously discussed iron-rich minerals often play an important role in slagging) However the use of such correction factors is often a crude substitute for more detailed knowledge of the fundamental ash properties Another example of this is the use of chlorine content in a coal as a fouling index This can be valid as a general rule if the chlorine is present as NaCI (thereby indicating the concentration of sodium which is an active form) and that the sodium will in fact cause the fouling Chlorine present in other forms mayor may not adversely affect fouling
Sintering strength tests have been used as an indication of fouling potential Assuming that correct ash compositions have been represented (which is less of a problem in the convection section than in the radiant section) worthwhile information may be obtained relative to a timetemperature versus bonding strength relationship Again in order for sintering tests to accurately predict actual behaviour it is necessary that tests be conducted with ash produced under representative furnace conditions (timetemperature history) (Kalmanovitch 1991)
The conventional analyses and developed indices may provide indications for limited parts of the coal spectrum but they share a flaw in that they take their point of departure in the end composition of the ash without taking account of the original minerals and intermediate products formed and transformed in the combustion zone (Cortsen 1983)
Information concerning the mineral forms present in the coals and the distribution of inorganic species within the coal matrix can be extremely important in extrapolating previous experience since the nature of the inorganic constituents contained in the coal can be the determining factor in their behaviour during the ash deposition process (Borio and Levasseur 1986) Generally speaking newer bench-scale techniques can be more sensitive to the conditions that exist in commercial furnaces than the older predictive methods Selective deposition for example has been recognised as a phenomenon which cannot be ignored More attention is being paid to fundamentals of the ash formation and deposition processes The use of new analytical techniques could give results that allow mineral matter to be identified according to composition mineral form distribution within the coal matrix and grain size Techniques such as computer-controlled scanning electron microscopy (CCSEM) scanning transmission electron microscopy
55
Combustion performance
Table 21 Summary of the effects of coal properties on power station component performance - II (after Lowe 1987)
Property Contributing properties Effect
Burners and steam generator Volatile matter
Ultimate analysis
Fuel ratio
Moisture
Slagging propensity
Furnace wall emissivity
Fouling propensity
carbon hydrogen nitrogen
fixed carbon volatile matter
ash elemental analysis ash fusion temperatures coal particle mineral analysis
ash elemental analysis wall deposit physical state
ash elemental analysis active alkalis (sodium amp potassium) ash fusion temperatures
Special burner design for flame stabilisation required below a dry ash-free volatile content of 25
Air requirements are affected by ultimate analysis unit increase of CIH ratio increases air requirements per unit heat release by 08
A 006 increase in efficiency loss due to unburnt carbon for 10 increase in fuel ratio at ratio of 16
A 1 increase in moisture decreases boiler efficiency by 025 requiring a proportional increase in firing rate
Slagging propensity generally ranked as low intermediate high or severe Response to slagging propensity is a function of unit thermal rating
Furnace wall emissivity is typically 08 a decrease of 1 will increase furnace outlet gas temperature by 16degC
Fouling propensity ranked low to severe Response to slagging propensity and is highly unit specific
(STEM) and X-ray diffraction can be used to characterise these properties on an individual particle basis New spectroscopies such as extended X-ray absorption fine structure spectroscopy (EXAFS) and electron energy loss spectroscopy (EELS) are capable of determining the electronic bonding structure and local atomic environment for organically associated forms of calcium sodium and sulphur Other new techniques such as Fourier transform infrared spectroscopy (FTIR) electron microprobe electron spectroscopy for chemical analysis (ESCA) all provide methods of improving present capabilities Thermal gravimetric analyses (TGA) and drop tube furnaces (DTF) have been used to characterise mineral matter decomposition and prepare ash samplesdeposits under near-boiler conditions respectively For example Benson and others (1988) have used a laminar flow DTF to study the formation of alkali and alkaline earth alumino silicates during coal combustion
A cautionary note though should be added here as many of the new techniques are still primarily focused on small fragments of the overall deposition process in order to permit manageable controlled studies in the laboratory Unfortunately the results are all too often not re-integrated in order to understand the total process But it cannot be doubted that a knowledge of the effects of the
aforementioned coal qualities is essential to avoid expensive delay in any changes to operational conditions in order to rectify deposition problems once they arise Information of performance in test reactors could also help to implement counter strategies to prevent the occurrence of deleterious incidents forewarned is forearmed
43 Comments Table 21 summarises the effects of coal properties on the performance of the power station components discussed in this chapter Whilst many empirical relationships have been developed and used to describe the problems that are encountered in the burner and boiler region of the power station it has been shown that significant uncertainties relate to many of the assumptions involved Flame shape and stability and char burnout cannot be predicted with certainty on the basis of coal composition data Correlations for slagging fouling erosion and corrosion have been shown to be inadequate
Power station operators still consider the problems of slagging fouling corrosion and erosion to be of greatest concern In view of this these subjects are the attention of a number of studies and have been reviewed extensively It is recognised that this topic merits a more extensive review than could be incorporated in this study
56
5 Post-combustion performance
51 Ash transport
The mineral matter entering with the coal exits the power station in the following five streams
mill rejects bottom ash economiser ash particulate collection system flue gas
The distribution between these streams depends on the power station design and operation as well as the coal composition Figure 22 shows a typical distribution However as described below this distribution may vary substantially
Most direct-fired mills have provision to reject pyrite extraneous material and excess coal introduced into the mill Under normal operating conditions the mass of the material rejected is a negligibly small fraction of the total coal flow rate However as the flow rate of coal into the mill is increased toward maximum capacity the amount of rejects increases Thus there is no effective way of estimating the effect of coal composition on mill rejects The mill reject system is typically oversized and would not be expected to limit mill operation except under unusual circumstances or where mill capacity is exceeded
The amount of ash removed at the bottom of the furnace is typically about 20 of the total ash content of the coal However the mass of bottom ash is difficult to measure accurately It may be estimated by measuring the mass of ash exiting with the flue gas and subtracting this from the ash entering the boiler with the coal However the errors of such an analysis procedure are considerable and the calculated mass of bottom ash may even be negative The factors which are probably the most important for determining the fraction of ash in the bottom ash are the design of the firing system the coal fineness bulk
velocities in the furnace and slagging Coal qualities that would directly influence these factors are
ash in the coal grindability of the coal slagging propensity of the fly ash
Due to the uncertainty in the mass of the bottom ash the handling system for the material is typically designed with considerable excess capacity Most systems operate intermittently so that an increase in bottom ash may be accommodated by an increase in duty cycle
The composition of the coal ash has an impact on the characteristics of the material captured as bottom ash Dry bottom furnaces are designed to maintain the ash in the hopper in a powdery non-sticky state The powdery ash slides down the hopper walls into the collection tank at the bottom of the furnace IT the ash has a low fusion temperature it may stick to the hopper or build up to running slag This material can accumulate at the bottom of the hopper and plug the hopper exit Solid slag deposits may fall from water walls higher in the fumace causing similar problems Wet bottom furnaces are designed to operate with running slag The slag must have a viscosity low enough to flow into the collection tank where it is quenched in water and shatters into small particles Typically the slag viscosity should be in the range of 250 poise at 1426degC (2600degF) for adequate fluidity (Babcock amp Wilcox 1978) If the viscosity increases plugging of the hopper bottom can occur similar to dry bottom furnaces
The strength of the ash can affect bottom ash system operation Many bottom ash systems are equipped with clinker grinders to reduce the size of the slag particles IT the slag particles are sufficiently large or strong they can disable the clinker grinder All the problems described above are related to the coal ash chemistry that is whether a fluid slag is formed and operating conditions
57
1-----++---------shy--
Post-combustion performance
Based on coal 10 ash 2791 MJkg
Unit 500 MW 1055 MJkWh
Mass kgkJ
Mass
Flow rate th
Coal ash
Mill rejects
Bottom ash
Economiser ash
Cyclone ESP
baghouse
Stack emissions
358
1000
1905
003
10
019
072
200
381
018
50
095
261
734
1398
002
06
012
Figure 22 Typical ash distribution (Folsom and others 1986c)
Occurrences of ash hopper explosions have been reported (Stanmore 1990) The exact mechanism for the explosions has not been elucidated Hypotheses of the cause include
chemical explosions involving iron-rich ash thermal explosions resulting from rapid quenching of falling hot deposits inducing a pressure wave within the water thermal explosion within the ash hopper causing entrainment of unburnt coal which then ignites to produce a secondary blast
Stanmore (1990) reports that work so far in this field has failed to uncover any boiler feature hopper type or coal composition which was common to all explosions investigated Corner-fired and wall-fired units experience the problem with both bituminous and subbituminous coals Both low and high ash content coals were involved with both high and low ash fusion temperatures
Ash-related explosions involving residual carbon in the ash can result from unfavourable furnace conditions which can occur during a cold start of a boiler Moreover variation in initial coal size can lead to poor grinding efficiencies giving rise to a wide pulverised coal size distribution and hence incomplete coal combustion (Stanmore 1990 Wol1mann 1990)
Most of the ash particles captured in the economiser hopper
are large because they are shed from the convective pass tube bundle deposits by the action of gravity flue gas flow rate or soot blowing The amount of ash varies with the fouling characteristics of the coal and cannot be predicted easily Economiser ash disposal systems are typically designed to handle about five per cent of the coal ash The presence of unburnt carbon in economiser ash can impact the operation of the collection system Poor coal reactivity can lead to high carbon content in the ash The carbon can continue to burn in the hopper and fuse the powdery material into a large mass which cannot flow from the hopper easily
Most of the ash exits the boiler as fly ash and is captured in particulate control equipment which may include cyclones ESPs fabric filters (baghouses) or scrubbers
52 Environmental control Since the early 1970s mandatory control of power station emissions has significantly increased the cost of generating electricity (CoalTrans International 1991) Initial concerns were focused on particulate emissions and have led to the development of efficient particulate removal systems Environmental concern about the use of coal is particularly tuned to the problem of emissions of SOx NOx and C02 to the atmosphere Trace elements are receiving increasing attention from the scientific and electric power communities who are attempting to evaluate the potential impact of trace
58
elements on the environment (Clarke and Sloss 1992) There is also the problem of disposal of the solid residues which are obtained from power stations
The capital and operating costs of emission control hardware can account for up to 40 of a power stations operating expenses (Cichanowicz and Harrison 1989) Increasingly coal-fired utilities are realising that in order to comply with ever tightening emission regulations their environmental control strategies must include adequate control of coal quality Emission control strategies related to coal quality can include
coal switching coal blending coal cleaning control of emissions during combustion post-combustion emission control
The impact of coal quality on emission control hardware has not been studied extensively Additional constraints in some cases are applied to coal quality during coal selection as a result of the implementation of emission controls
The following sections briefly review the emission control technologies available and attempts to highlight the coal characteristics and other considerations that affect the selection or efficient use of emission control systems
521 Coal cleaning
Historically coal has been cleaned to maintain specifications for delivered fuel quality and to reduce transport costs Coal cleaning benefits are usually greatest for coals which have to be transported over long distances to the point of use Conventional coal preparation plant mainly uses methods developed at least forty years ago Nevertheless in recent years there have been major advances in instrumentation and control which have resulted in reduced costs and greater consistency in the cleaned product
Utilities also have the option to incorporate coal cleaning strategies on site High mineral matter high sulphur coals could be purchased at lower prices and cleaned on site to boiler-related specifications The decision to implement this type of strategy is dependent essentially upon three factors
cost savings achieved by coal cleaning feasibility of residue disposal
Coal cleaning costs depend upon the initial cleaning plant capital costs cleaning plant operations and maintenance and the value of lesser-quality coal discarded in the cleaning process In general coal cleaning capital costs average about five per cent of the cost of the power station using the coal Direct operating costs are determined by labour consumables and power Discarded coal can account for as much as 50 of total cleaning costs (Cichanowicz and Harrison 1989)
Savings achieved by coal cleaning depend upon the depth of
Post-combustion performance
cleaning instigated (Elliott 1992) A review by Couch (1991) entitled Advanced coal cleaning technology provides a technical overview of recent developments in coal cleaning methods The fuel characteristics most significantly changed by cleaning are
mineral matter content and distribution sulphur content and form heating value
Reducing the mineral matter impurities and sulphur in the coal can have a signifIcant affect on a coals abrasiveness reduce ash loadings by up to 93 and potential S02 emissions by as much as 70 (Hervol and others 1988) Moreover coal cleaning can reduce environmental control costs by lowering the quantity of fly ash and S02 that must be removed after combustion Coal cleaning permits smaller and therefore less expensive flue gas processing equipment reduces reagent quantity and decreases the amount of solid waste requiring disposal Cleaned coal can improve station heat rate by reducing auxiliary power for flue gas handling systems and allowing lower air heater exit temperature thus increasing boiler efficiency Pilot scale combustion tests conducted by Cichanowicz and Harrison (1989) showed that boiler efficiency was greatly improved by coal cleaning as shown in Table 22
Table 22 Summary of coal cleaning effects on boiler operation (Cichanowicz and Harrison 1989)
Characteristics Run-of-mine Medium Deep coal cleaned cleaned
coal coal
Moisture 17 17 16 Sulphur 38 37 20 Ash 235 71 35 Heating value MJkg 2338 3103 3266 Flue gas S03 7 4 3
concentration ppm Air heater exit 136 120
temperature degC Boiler efficiency 884 901 Flue gas volume 6
reductionsect
dried sect includes flue gas temperature reduction and efficiency
improvement
Although the total ash content is reduced it must be noted that all ash constituents may not be removed equally Unfortunately those constituents which are primarily responsible for slagging and fouling are least affected so that problems in this area can be induced as a result of cleaning
As overall S02 emissions will be lowered by coal cleaning the benefits of this form of pollution reduction must be considered in the light of the ESP problems that might result from the use of low sulphur coal (see Section 522) and with regard to its adverse effects on collection efficiency (Strein
59
Post-combustion performance
1989) Coal cleaning has only peripheral implications for NOx and C02 emissions
An additional benefit of cleaning coals is the substantial removal of many trace elements especially heavy metals with the mineral components (Swaine 1990) Efficiencies for trace element extraction have been reported for various physical cleaning processes including density separation oil agglomeration float-sink separation and combinations of heavy-media cyclones froth flotation and hydraulic classifiers (Gluskoter and others 1981 Couch 1991)
The adoption of coal cleaning strategies on a power station site would require a knowledge of quality characteristics that affect cleaning These include
the amount nature and the size of the mineral matter If they are finely divided and dispersed they are difficult to liberate and to separate the size distribution of the coal affected by inherent friability and by mining and handling procedures All of the properties which affect coal handling have an influence here the relative proportions of pyritic and organic sulphur coal oxidation affecting surface properties the porosity of the particles
A number of tests have been developed specifically to assess the cleanability of a coal These have been reviewed in an lEA Coal Research report by Couch (1991) and will not be discussed here
522 Fly ash collection
Fly ash collection systems are required on virtually all coal-fired power stations to meet particulate emissions or opacity regulations The acceptable dust loading from collection equipment is usually about 01 gm3 A coal containing 20 ash typically provides an uncontrolled dust loading of about 30 gm2 so that a collection efficiency of 997 is required to meet acceptable emission standards For very fine particles such as fly ash such a high collection efficiency can only be achieved using electrostatic precipitators (ESP) or fabric filters
Electrostatic precipitators (ESP) ESPs have been studied extensively and a number of comprehensive texts are available that describe the process (Babcock amp Wilcox 1978 Singer 1991 Klingspor and Vernon 1988) The ESP process involves fly ash particle charging collection and removal
The perfonnance or collection efficiency of an ESP is defined as the mass of particulate matter collected divided by the mass of such material entering the ESP over a period of time One of the earliest and simplest equations for predicting the particulate collection efficiency of an ESP was that proposed by Anderson in 1919 and subsequently developed by Deutsch in 1922 The Deutsch-Anderson equation enables the collection efficiency to be predicted from the gas flow the precipitator size and the precipitation rate (or migration
velocity) ofthe particles It may be presented as follows (Deutsch1922)
where e = fractional precipitator collection efficiency (dimensionless)
a = total collecting electrode surface area (m2) v = gas flow rate (m3s) w = migration velocity of the particles (ms)
The ratio av is often referred to as the specific collecting area (SCA) and has dimensions slm When determined empirically the migration velocity w accounts for ash properties such as ash particle size distributions as well as for rapping losses and gas flow distribution The Deutsch-Anderson equation was recognised as having several limitations and so gives only approximate results for some operating regimes For this reason alternative equations have been developed often as modifications of the original Deutsch-Anderson equation For example Matts and Ohnfeldt (1973) introduced a semi-empirical factor and a constant based on particle size distribution and other ash properties which gives a more realistic approximation of actual precipitator behaviour
The equations discussed above describe how perfonnance is a function of ESP design flue gas flow conditions and the characteristics of the fly ash The impact of coal quality on ESP perfonnance is primarily via the influence of the chemical and physical properties of the fly ash on the migration velocity of the particles These include
ash resistivity ash quantity ash particle size and size distribution
Ash resistivity influences ESP power input Resistivity is critical for fly ash ESPs because it directly influences operational voltages and currents As the ash resistivity increases the flow of corona current decreases Generally speaking as the corona current decreases so does the precipitator efficiency Low resistivity ash (l08 ohm-cm and below) is also a problem because the ash easily loses its charge after being collected on the plates The uncharged particles are recharged and redeposited several times and some are eventually re-entrained into the flue gas and escape from the precipitator A limit on maximum gas velocity and special collector profiles are needed to overcome this problem
High resistivity ash (above 1011 ohm-cm) is considerably more difficult to precipitate with a risk of back corona discharge An explanation for this phenomenon is that the ash particles do not readily lose their charge when they reach the electrodes This results in difficulties when trying to remove the agglomerated ash When a deep enough deposit collects on the plate back corona may develop on the ash surface and the precipitator no longer operates efficiently Back corona is extremely detrimental to precipitator performance and occurs when particles migrate to the collecting surface but fail to dissipate their charge This
60
Post-combustion performance
causes a high potential gradient in the dust layer on the surface of the electrode and results in current conduction of opposed polarity to that of the discharge electrode
The range of dust resistivity is primarily affected by
chemistry of fly ash levels of sulphur trioxide and moisture content of the flue gas flue gas temperature
Key ash constituents which affect resistivity are ferric oxide Fez03 potassium oxide (KzO) and sodium oxide NazOshywhere a substantial reduction in either or both of these will cause an increase in fly ash resistivity Conversely a substantial increase in calcium oxide (CaO) magnesium oxide (MgO) aluminium oxide (Alz03) and silicon dioxide (SiOz) will cause ash resistivity to increase (Singer 1991) Strein (1989) describes the impact of coal cleaning in particular the removal of sulphur from coals and switching to low sulphur coals on ESP performance It was determined that coal cleaning was not always beneficial to good precipitator operation Although precipitators can be designed for low sulphur coals the use of low sulphur coals in other cases can lead to a reduction in precipitator collection efficiency and possible non compliance with stack opacity limits Precipitators constructed many years ago were likely to encounter problems if any change to a lower sulphur coal was encountered It was concluded that before a change in fuel was made a careful review should be made of the precipitator design data predicted precipitator performance and the coal and ash chemistry of the new fuel If the problem of high fly ash resistivity was encountered after a fuel switch of this nature flue gas conditioning must be considered in particular a S03 injection system The purpose of this is to supplement the naturally occurring S03 in the boiler flue gas stream to the extent necessary to reduce fly ash resistivity to an acceptable level
A number of electrostatic precipitator manufacturers have developed regression equations which make first order predictions of fly ash precipitation performance based on the elemental analysis of the ash in coal These equations are generally regarded as proprietary and are not published
CSIRO Australia have published details of correlations of ash chemistry with pilot-scale electrostatic precipitators Whilst many correlations used in the past have proved inadequate for precise prediction the most promising correlation was obtained when consideration was given to the elements that would contribute to the refractoriness of fly ash The best precision was obtained from the sum of the elemental analyses for silicon aluminium and iron calculated assuming (on an ash basis) Si+Al+Fe+Ti+Mn+Ca+Mg+Na+K+P+S = 100
The formula given for a precipitator outlet concentration of 01 gm3 and for coal at 15 ash content is in two parts (Potter 1988)
for Si+Al+Fe = a lt82 am = 1886 + 0565a for 82 lta lt90 am = -2864 + 428a
where am = required specific collecting area in mass units mZ(kgs) This value can also be represented as a percentage of the ash content (A) by multiplying by the factor f given by f = 1364 - 048810glO[(100A)-I]
Cortsen (1983) reports of the use of alkaline sulphate index (ASI) by utility operators to assess the ease of fly ash precipitation The ASI is calculated from a series of equations which relate S03 content of the flue gas and the corresponding chemical equivalent of the oxides of silicon aluminium calcium magnesium phosphorus sodium and potassium Coal ashes with ASI values between two and three are perceived difficult to collect while an ASI of six or above indicates easy precipitation The index was not considered as accurate in ESP evaluation as measurement of ash resistivity nor measurement of actual precipitator efficiency (Cortsen 1983)
Sulphur content of the coal can also influence ash resistivity Sulphur trioxide (S03) formed from the combustion of the sulphur reacts with water vapour to produce sulphuric acid (HZS04) at temperatures of approximately 500degC (950degF) In the cool part of the flue gas system there may be some deposition of HZS04 which depends on flue gas temperature and vapour pressure The HzS04 can be absorbed onto the fly ash particles and reduce their resistivity It has been shown that H2S04 can alter the fly ash resistivity either by completely absorbing on the dust particles or by chemically reacting to form sulphates Others have suggested that the formation of binary acid water aerosol is the primary mechanism by which HzS04 can affect fly ash resistivity Although the mechanism which accounts for the presence of absorbed H2S04 on fly ash particles is not clearly understood the net effect is reduction in fly ash resistivity
Increases in moisture content can adversely affect precipitator performance through impacts upstream of the ESPs The moisture content of the coal in conjunction with coal particle size and volatility can affect flame stability and combustion within the boiler furnace area If this causes excessive carbon content in the fly ash at the ESP inlet ESP performance will suffer because of the decreased resistivity of the fly ash
Flue gas temperature can also influence ash resistivity Peak resistivities occur between about 120degC and 230degC depending upon coal ash characteristics Above 230degC to 288degC the ash resistivity is inversely proportional to the absolute temperature while below 120degC to 149degC the resistivity is directly proportional to the absolute temperature (Singer 1991)
The quantity of fly ash produced from a particular coal can vary as discussed in Section 51 It is important to ensure that the total electrode collection surface area and rapping frequency is adequate to handle the quantity of fly ash produced so as to prevent re-entrainment of the material back into the gas stream after initial entrapment at the collecting plates (Strein 1989)
Migration velocity and therefore particle collection rates
61
Post-combustion performance
decrease in proportion to the size of the particle (Darby 1983 Wibberley 1985b) lithe coal is pulverised too finely before entering the boiler ESP perfonnance can be adversely affected due to reduction in particle size distribution of the fly ash at the precipitator inlet The fonnation of fine fly ash may be increased also by higher combustion temperatures and from coals that have a high Free swelling index Disintegration of swollen char particles precludes agglomeration of the mineral inclusions thus ensuring the production of finer ash particles (Wibberley 1985b)
Bench-scale tests that are nonnally perfonned on new coal samples include
preparation of ash samples in a test furnace fly ash resistivity measurement of drift velocity in an electric field
Ideally the ash analysed for the purpose of investigating ESP perfonnance should be taken from the boiler to which the ESP system under assessment is attached Baker and Holcombe (I988b) have demonstrated that the fly ash produced in a specially developed laboratory furnace could show similarities to fly ash resulting from combustion of the coal in approximately eight different power stations It was possible to reproduce the properties of the power station fly ash in tenns of electrical properties and elemental analysis
14 shyelectric stress 400 kVm
bull
13
10 - - ltgt power station fly ash
- simulated fly ash
Mass H2 0r fIgures Indicated = d fl r mass ry ue gas
015 9
80 100 150 200
TemperatureOC
Figure 23 Resistivity results for both power station fly ash and laboratory ash from Tallawarra power station feed coal (Baker and Holcombe 1988b)
and general shape although the material was coarser than nonnal power station fly ashes A comparison of the resistivities of boiler and laboratory ashes is illustrated in Figure 23
Measurement of ash resistivity must ideally be measured under the same gas and temperature conditions as those at which the precipitator will operate The packing density should also be the same as that of the dust layer deposited on the precipitator collectors Dust resistivity measurements do not correlate very well with experience in ash precipitation efficiency
Laboratory resistivity tests are not standardised by ASTM BS AS nor ISO The Institute of Electronic and Electrical Engineers in the UK standard IEEE 548-1984 describe a resistivity test designed for testing compressed fly ash at 96 water vapour by volume (IEEE 1984) Measurements of resistivity are usually taken during both heating and cooling of the sample (Young and others 1989) Figure 24 illustrates the resistivity curves against temperature for ashes from a South African coal and Polish and South African coal blend respectively It can be seen that there is a degree of hysteresis as a result of the effect of moisture in the ash
5
3
2
103
E Eo 5 c 0 4
2 323shy
s ~
200 Q)
a
102
5 4 South African coal 3 50 Polish50 South African coal
2
100 120 140 160 180 200
Temperature degC
Figure 24 Laboratory resistivity curves of ash from a South African coal and from a blend of South African and Polish coals against temperature (Cortsen 1983)
62
Post-combustion performance
which gives a lower resistivity and which disappears after the heating process (Cortsen 1983)
The drift or migration velocity in a particular electric field can be estimated by examining the dielectric constant and particle size distribution as well as the aerodynamic factors for the fly ash A technique has been developed for determining particle dielectric constant from resistivity cell tests and other measurements (Baker and Holcombe 1988a) Particle size analysis of simulated ash is not reliable because of the difference in severity of the combustion process between full scale and test combustor Optical and scanning electron microscopes can be used to assess the shape characteristics of the fly ash
Prediction of fly ash precipitation characteristics remains an inexact science so that both pilot plant testing and electrical simulation studies remain extremely important in determining the precipitability of fly ash in practice
Fabric filters Although the use of fabric filters has become more widespread in recent years with the continued preference for low sulphur coals and to reduce stack emissions further there are no coal quality tests which relate to their performance directly
As described in Section 523 in cases where sorbent injection into the flue gas is used to control sulphur emissions collection of the fine sorbent in the bag can confer a high surface area to the gas and enhance the sulphur collection performance
While the efficiency of fabric filters is very high it is important to note that problems may occur with the presence of fine ash and acid condensation derived from coal causing
retention of filter cake on the filter fabric after the cleaning cycle due to agglomeration of the cake improving its mechanical strength blinding of the apertures of the fabric by very fine particles clogging of the filter by condensation promoting filter cake agglomeration bag rotting due to acid condensation
523 Technologies for controlling gaseous emissions
A range of methods is available for control of gaseous emissions in particular for SOx and NOx Options include
emissions control in the combustor post-combustion control technologies
lEA Coal Research have produced several reports that review these technologies SOx control technologies are reported in Flue gas desulphurisation - system performance (Dacey and Cope 1986) FGD installations on coal-fired plants (Vernon and Soud 1990) Market impacts of sulphur control the consequences for coal (Vernon 1989) Technologies for
controlling NOx emissions are described in detail in the reports NOx control technologies for coal combustion (Hjalmarsson 1990) and Systems for controlling NOxfrom coal combustion (Hjalmarsson and Soud 1990)
Emissions control in the combustor In-furnace desulphurisation by injection of calcium-based sorbents is not a widely-used sulphur control technology at present mainly because of its inability to achieve as high sulphur removal rates in commercial use as wet or spray-dry scrubbers Promising results are being obtained with sorbent injection followed by enhanced collection in a fabric filter in New South Wales Australia (Boyd and Lowe 1992)
There are several potential problems that may arise from the injection of calcium-based sorbents such as limestone (CaC03) into pulverised coal flames
the additional calcium may interact with the coal ash to reduce the ash melting point with consequent risk of increased slagging and fouling it is necessary to handle increased quantities of solid residue the possible adverse effects of calcium addition on downstream equipment such as electrostatic precipitators and solid residue disposal (see Sections 522 and 524 respectively) the possible influence of sorbent injection on the radiative properties of the flame (Morrison 1982)
To date sorbent injection into the furnace has only been utilised in smaller power stations with low sulphur coal where its low capital costs are particularly favoured Sorbent utilisation rates are generally low although it still results in a significant volume of mixed fly ash and calcium sulphitesulphate residue requiring disposal (Vernon 1989)
The formation of NOx depends mainly on oxygen partial pressure temperature and coal properties such as the content of nitrogen and volatile matter Measures can also be taken to modify the combustion conditions so that they are less favourable for NOx formation (Hjalmarsson 1990) This is usually achieved by some form of air staging Combustion air is admitted in stages in such a way as to limit flame temperature
The implementation of low NOx combustion techniques is much easier and more effective in a new installation compared with a retrofIt Low NOx measures on existing boilers can affect the combustion the boiler and other parts of the power station Combustion measures especially on existing boilers are specific to each boiler Consequently it is difficult to transfer experience of the impact of coal qualities directly
Most NOx abatement investigations have concentrated on determining the coal properties that influence NOx formation such as total nitrogen content volatile matter content and particle size distribution and developing technologies for reducing NOx emissions (Nakata and others 1988) There is limited information available concerning the impact of coal properties on power station performance under low NOx
63
Post-combustion performance
combustion conditions Discussions with power station operators have revealed that coals which previously produced a satisfactory performance prior to low NOx modifications have caused increased carbon in fly ash andor fouling slagging and corrosion along with other problems under low NOx combustion conditions Some possible explanations for this behaviour are presented briefly below
combustion efficiency can be reduced combustion conditions that reduce NOx formation such as low combustion temperature and low excess air are not favourable for accomplishing complete combustion As a result of this the level of unburnt carbon in the fly ash tends to increase If this is not counteracted the high content of unburnt carbon can cause changed conditions in an electrostatic precipitator (Klingspor and Vernon 1988) and make the fly ash unsaleable (see
Section 524) changes may also occur in the characteristics of the fly ash due to the reduced combustion temperature This will make the fly ash less glassy changing its properties and making the fly ash less attractive for use in cement and concrete production the thermal conditions in both the water and the steam parts of the boiler may change through low NOx combustion leading to changes in the temperature profile of heat exchangers Combustion modifications can also lead to an increased furnace exit gas temperature (FEGT) Deposits on heat exchange surfaces can affect heat absorption The reducing atmospheres reduce the ash melting point and can aggravate the problem of causing heat surface slagging Low excess air and staged combustion can produce areas with a reducing atmosphere which cause corrosion to boiler tubes (Coal Research Establishment 1991) the higher pressure drop over burners requires a higher fan capacity This in addition to other measures such as increased mill energy to obtain the required fineness and flue gas recirculation leads to higher power consumption low NOx burners may give longer flames that can cause deposits by impingement Flame stability may also be influenced Decrease in flame stability is usually found at reduced load causing limitations to boiler load turn down
Low NOx combustion was in many cases expected to give a higher degree of slagging and fouling in the boiler The opposite however has also been found Either result causes changes in soot blowing operations (Hjalrnarsson 1990)
Post-combustion control technologies SOx emission is minimised mainly with low sulphur coal Beyond this control is carried out with flue gas desulphurisation (FGD) systems The vast majority of FGD systems use an alkaline sorbent to absorb the flue gas sulphur dioxide chemically There are a number of different types of FGD and the effects of coal changes on their performance depends on the specific design details - no generalisation can be made For example flue gas temperature and SOz level impact the performance of wet limelimestone scrubbers These same variables affect spray dry FGD systems differently (Hjalmarsson 1990)
In wet FGD systems the effects of chloride from coal are generally all negative Chloride concentrations can build to high levels in the wet scrubbing loop causing corrosion problems and greatly reducing scrubber liquid-phase alkalinity (Rittenhouse 1991) However the removal of HCl in spray-dry scrubbers can have both positive and negative effects The HCl in the system can improve SOz removal capabilities resulting in lower reagent costs This effect was noted during a full-scale test conducted by Northern States Power Company in 1983 The addition of an amount of calcium chloride equivalent to a 02-03 increase in chlorine content reduced lime consumption by 25 Pilot tests carried out by EPRI confmn this effect (Collins 1990) The savings in lime consumption usually outweigh the cost of any negative effects including
incomplete droplet drying corrosion of stainless steel components in the system increased pressure drop downstream of fabric filters degraded ESP performance
Reference manuals have been published at IEA Coal Research that evaluate the wide range of FGD systems (Vernon and Soud 1990 Dacey and Cope 1986)
Where power station limits for NOx emissions cannot be met by combustion control flue gas treatment has to be installed The dominant method in use is selective catalytic reduction (SCR) In the SCR method the NOx concentration in the flue gas is reduced through injection of ammonia in the presence of a catalyst The role of the catalyst catalyst types and the reaction mechanism are described extensively by Hjalmarsson (1990) The efficiency of NOx reduction is primarily dependent upon condition of the catalyst which in tum is dependent upon the type of catalyst its susceptibility to poisoning and its location in the flue gas flow
The positions that are used for catalyst location are high dust low dust and tail end In the high dust location between the economiser and the air preheater the flue gases passing through the catalyst contain all the fly ash gaseous contaminants and sulphur oxides from combustion This can cause degradation of the catalyst leading to a decrease in NOx reduction efficiency The main types of degradation that are coal quality related are
deposition of fly ash causing clogging of the pores of the catalyst (Balling and Hein 1989) poisoning of the active sites of the catalyst by compounds such as alkali ions (sodium potassium calcium and magnesium) especially in sulphated form and some trace elements such as arsenic (Gutbertlet 1988 Balling and Hein 1989) erosion of the catalyst A high fly ash content in addition to an uneven particulate concentration and size distribution are most likely to cause erosion problems
The lifetime of a catalyst in this position is considerably shorter than in other positions Nakabayashi (1988) reported from a comparison of the impact of position on catalyst characteristics that catalyst life can range from 2-3 years in
64
Post-combustion performance
Table 23 Effect of coal type on total concentrations of selected elements from fly ash samples (Ainsworth and Rai 1987)
Mean and range of concentrations in fly ashes (Ilglg solid) from
Element Bituminous Subbituminous Lignite
Arsenic 219 (11-1385) 191 (8-34) 544 (21-96)
Cadmium 117 laquo5-169) lt5 lt5
Chromium 245 (37-609) 73 (41-108) 284 laquo40-651)
Molybdenum 56 (7-236) 165 laquo4--55) 141 (8-197)
Selenium 123 laquo5-435) 142 laquo5-281) 184 laquo5-469)
Vanadium 290 (99-652) 133 laquo25-292) 209 (lt25-268)
Zinc 607 (65-2880) 148 (27-658) 647 (25-127)
mean value is followed by range in parenthesis for 26 8 and 5 fly ashes from bituminous subbituminous and lignite coals respectively
a high dust location compared to 3-5 years in the tail end position
A low dust location means that the catalyst is situated after a hot gas electrostatic precipitator and before the preheater The flue gas reaching the catalyst is almost dust free but still contains sulphur dioxide which may result in poisoning of the catalyst
Tail end systems have the catalyst situated in the end of the chain of flue gas purification equipment after the desulphurisation plant The flue gases reaching the catalyst therefore contain only small amounts of sulphur oxides and particulates
NOx can also be controlled through thermal reactions by using appropriate reducing chemicals The process is called selective non catalytic reduction (SNCR) It has been found that different conditions in the flue gases influence the reactions and the temperature window (Mittelbach 1989 Gebel and others 1989) High CO content (gt1000 ppm) reduces the removal efficiency High S02 content increases the reaction temperature (Hjarlmarsson 1990)
Numerous processes have been developed for combined desulphurisation and denitrification of gases Most processes are still at the laboratory scale and there are a few stations operating at full commercial scale Coal quality effects on combined removal processes have not been studied extensively The problems encountered during the implementation of the individual abatement technologies may also be exacerbated for the dual systems An lEA Coal Research report Interactions in emissions control for coal-fired plants (Hjarlmarsson 1992) examines the interactions between control of S02 NOx and particulate emissions with different combustion methods and also the production of solid and liquid residues An understanding of the impact of coal quality on emission control technologies must be achieved for future efficient implementation of control systems
Trace elements emissions during combustion can also become associated with fly ash andor bottom ash Because of vaporisation-condensation mechanisms most of the trace elements in fly ash are often higher in total concentrations than those found in the corresponding bottom ash (WU and Chen 1987) In addition the levels of many trace elements including Cr Mn Pb n and Zn are often concentrated on the surfaces of the fly ash particles Typical median concentrations of selected trace elements in fly ash from different coal types are shown in Table 23 In power stations equipped with wet FGD systems the sludge from the scrubbers is a combination of spent solvent calcium sulphate and sulphite precipitates and fly ash The quantity and distribution of trace elements occurring in sludge are essentially determined by the coal ash composition and may influence the disposal cost of the material (Akers and others 1989)
524 Solid residue disposal
A typical pulverised coal fired power station employing ESPs or baghouses for particulate control and FGD for SOx control can produce three types of residue bottom ash (including slag) fly ash and FGD sludge Although under favourable conditions increasingly large amounts of these residues are utilised for various purposes at a net profit to the utility (Murtha 1982 Taubert 1991) it is anticipated that utilisation will not eliminate the need for disposal at a net cost in the foreseeable future
Changing coal characteristics can impact both the quantity and characteristics of the residue Power stations with limited resources for residue disposal have to transport the ash to alternative locations Ash for disposal may be conveyed to the disposal site as a dilute slurry Cerkanowicz and others (1991) reported that physical and rheological properties of fly ashes vary from different power stations This can impact the flow properties of fly ashwater mixtures significantly
The major factors that affect the amount of residue produced
65
Post-combustion performance
Table 24 Summary of the effects of coal properties on power station component performance - III (after Lowe 1987)
Property Contributing properties
Ash and dust plant
Ash quantity per unit heat release
Slagging propensity
Ash solubility
Erosiveness
Clinker reactivity
Environmental control
Coal cleaning
Particulate control ESP Dust burden (Ash per unit gas volume) Gas flow per unit heat
Ash resistivity
Sulphur
Fabric filters Dust burden
Gas flow per unit heat
Combustion measures
Post combustion
Residue disposal
ash level heating value grindability
ash elemental analysis ash fusion temperature coal particle mineral matter
ash elemental analysis ash mineral composition
mineral matter elemental analysis coal size distribution trace element
ash heating value ultimate analysis CIH ratio moisture level
ash heating value ultimate analysis CIH ratio moisture level
sulphur nitrogen volatile matter
cWorine fly ash size trace elemental analysis
ash ash elemental analysis sulphur heating value trace elemental analysis chlorine content
Effect
A I increase in ash quantity per unit heat release increases the ash and dust plant duty by 1
High slagging propensity increases the duty on ash extraction plant Formation of large clinkers may cause blockages in hopper doors and contribute to ash crusher problems
For wet hopper systems with recirculated water formation of scale pipelines may cause problems
Increased erosiveness will increase wear in pipelines and sluiceways
Some coals produce clinker in the furnace which is prone to explosive release of energy on quenching in the ash hopper
Different techniques are required depending upon the type and size distribution of the mineral matter Coal particle size influences the efficiency of the cleaning process and overall organic coal recovery
A 1 increase in dust burden will increase emissions by 1
A 1 increase in gas flow per unit heat release will increase emissions by 15 A resistivity change of 1 order of magnitude would suggest an increase in emissions by a factor of 2 General trend for reducing resistivity as sulphur increases possibly one order of magnitude per 1 sulphur change Below 1 sulphur resistivity is dominated by other factors
Differential pressure will increase with dust burden
A 1 increase in gas flow per unit heat release will increase unit heat differential pressure over the filter bags by 1
Influences the amount of sorbent used and dust collecting efficiencies Use of low NO burners can influence the combustion conditions and promote slaggingfouling due to reducing conditions present
Can have a positive and negative influence on SO removal efficiencies Can cause a reduction in catalyst efficiency in the removal of NObull
Quantity and quality influenced by the properties Saleable byshyproducts can be contaminated by carbon carry-over and trace elements
Quality of FGD waste can be influenced by cWorine and trace elements content
66
Post-combustion performance
annually by a pulverised coal fIred power station are the following
coal consumption ash content of the coal sulphur content bottom ashfly ash ratio fly ash collection efficiency SOx removal efficiency
These in turn influence the land requirement for residue disposal Ugursal and Al Taweel (1990) use the parameters listed above for calculating the area requirement for power station ash and FGD sludge disposal
The characteristics of the solid residue are particularly important where the residue materials must meet specifIcations to be sold (Cerkanowicz and others 1991 Bretz 1991b) For example the key requirement for the use of fly ash in cement production is the carbon content (Tisch and others 1990) A typical specifIcation is less than 5 carbon A coal change which degrades mill performance affects flame stability or reduces the rate of char oxidation such as in the case of low NOx combustion measures may increase the carbon content enough to exceed this carbon specifIcation (Zelkowski and Riepe 1987) Such a change would result in a considerable net cost to the utility since the fly ash would need to be disposed in a landfill at some cost instead of being sold for cement production at a profIt (Folsom and others 1986b) Similar problems can occur with FGD solid residue use for gypsum production The chlorine content of the coal is becoming an increasingly important consideration for power stations that have an established market for the gypsum produced from FGD residue as the chlorine impacts the quality of the gypsum for sale
The trace element content of combustion residues is an important consideration for both disposal and utilisation purposes (Clarke and Sloss 1992) The concentrations in power station residues may vary signifIcantly depending primarily on the coal used and on the cleaning techniques and combustion methods employed Therefore if the residue disposal strategy of the power station includes residue utilisation then a detailed knowledge of trace element content of the coal being fired is essential An lEA Coal Research report Trace elements emissions from coal combustion and gasification examines the behaviour of trace elements within these systems in more detail than can be discussed here (Clarke and Sloss 1992)
53 Comments The properties of coal affect the performance of the post combustion components of the power station These impacts are summarised in Table 24 As has also been highlighted in Chapters 3 and 4 many empirical relationships have been developed and used to describe the problems that are encountered in these systems but there are some signifIcant uncertainties related to many assumptions made For the post-combustion components these can include
fly ash collection - there is considerable disagreement as to the best method of measuring fly ash resistivity There is no correlation between coal composition and fly ash fIneness technologies for controlling gaseous emissions - there is no adequate means to predict NOx emissions
Whenever a change in coal supply is considered it is important to pay attention to the downstream effects
67
6 Coal-related effects on overall power station performance and costs
The production of electricity at the lowest busbar cost at a coal-fired power station depends on
the capital costs of the power station the delivered cost of the coal consumed overall power station performance the way in which the capital costs are financed during the construction and operating life of the station (interest depreciation profits taxes etc) the cost of decommissioning the power station at the end of its life
Coal quality can affect each of the above factors except for the last two components The main aim of this chapter is to look at coal-related effects on overall power station performance and costs
61 Capital costs The capital costs in most cases are affected by the range of coal qualities envisaged at the design stage (Mellanby-Lee 1986) In a study done by Ebasco Services Inc (Cagnetta and Zelensky 1983) the capital costs of a new power station are estimated for a wide range coal and a dedicated coal specification The wide range coal characteristics encompass about 90 of the recoverable reserves east of the Mississippi in the USA while the dedicated coal characteristics vary over a much narrower range Table 25 gives details of coal quality values for both types of coal and the costs with respect to the design for the wide range coal type It can be seen that the cost of a power station to bum a wide range of coals is $54 million more expensive than the design for a dedicated coal supply
A decision to bum high sulphur coal in a power station may necessitate the installation of an FGD or other emission control technologies FGD the best established technology to control emissions can be costly typically adding up to 20 or more to the total capital cost for new capacity and around
Table 25 The effect of coal quality on the costs of a new power station (Cagnetta and Zelensky 1983)
Coal Wide range Dedicated
Heating value GIlt 2442-3315 2949-3282 Moisture 10-150 10-65 Ash 60-180 64-146 Sulphur 05-40 17-32 HGI 40-64 45-60
Power station capital costs $ million coal handling +03 base steam generators +66 base ash handling +10 base ESP +417 base FGD +46 base total 1086 1032
Figures are for a 2 x 600 MW net power station they exclude coal costs
30 to power station capital costs when retrofitted to existing power stations (Vernon 1989) Control costs for NOx an additional environmental consideration are lower adding some 6-10 to the total capital costs of large new plants but as with FGD costing more when retrofitted (Hjalmarsson 1990 Daniel 1991)
62 Cost of coal The cost of internationally traded coal varies considerably For the third quarter of 1991 the lEA reported that the average cif coal import prices in Europe Japan and the USA were 4927 4998 and 3425 US$lMt respectively The range of prices to the two major importing areas that is the EC and Japan were 4320-5068 US$lMt and 4451-5180 US$lMt respectively The variation in prices is influenced by geographic location transport costs and coal quality The lEA reported that countries describe thermal coal using different average coal quality values for example the lower
68
Coal-related effects on overall power station performance and costs
heating value of a steam coal as detennined by the EC is 2617 MJkg (6251 kcalkg) compared with Japan at 2466 MJkg (5890 kcalkg) (International Energy Agency 1992)
Ash contents of traded coal vary substantially from under 5 for Colombias Cerrej6n coal for example to over 20 for typical South African thermal coals (see Table 26) Most of the traded coals have an ash content below 15 with the average being around 12-13 Given the associated costs of ash handling and disposal (see Section 63) coals with high ash contents will attract a lower price than those with lower ash even when corrected for heat content because of the application of penalties Many utilities and traders have a formula for calculating price penalties in relation to ash content Estimates of penalties vary depending upon the equipment in place It is probable given the increasing concern about the disposal of combustion residues that these ash penalties may increase during the next decade and a half
Table 26 Ash contents of traded coals (Doyle 1989)
Low Medium High lt8 8-15 gt15
Colombia Canada South Africa Venezuela China Indonesia Australia
Poland USA South Africa
While ash characteristics have traditionally most worried boiler managers sulphur content has become more significant in recent years because it is the primary determinant of the cleanliness of a coal in relation to S02 emission standards Most traded coal is low sulphur Only a small volume has a sulphur content above 15 However as S02 emission standards have tightened there has been a noticeable downward shift in what is considered low sulphur coal The defmition of low sulphur is now perceived to be below 09-10 and an increasing amount of traded materials now below 06 Various studies have deduced that low sulphur coal could command a premium price of up to one third greater than high sulphur coal (Doyle 1989 Calarco and Bennett 1989) Doyle (1989) also reported that at the most general level the low sulphur premium must be less than or equal to the smaller of either FGD costs or coal cleaning costs Otherwise buyers would take higher sulphur coals In practice the situation is more complicated For some users regulations may make the use of low sulphur coal or FGD equipment compulsory An excessive premium on low sulphur coal may also bring gas frring inter-fuel competition into consideration
63 Power station performance and costs
Several investigations of coal qualitypower station performance relationships have been conducted by utilities and other organisations These have been reviewed by
Folsom and others (1986a) In general the manner in which station performance evaluation of the impacts of coal quality have been assessed was by considering the following four performance categories
capacity - the capability of the unit to produce design load
heat rate - a measure of the net energy conversion efficiency
maintenance - the cost of maintaining all components in suitable working order
availability - a measure of the degree to which the unit can be operated when required
A summary of coal quality effects on these categories is presented under these headings
631 Capacity
The utility industry uses a number of definitions for station capacity In this discussion the term capacity will refer to the maximum rate of power generation for a specific unit under given operating conditions It should be noted that changes in this definition of capacity mayor may not be of economic consequence to a utility The need to operate a specific unit depends on
utilitys power demand available capacity system-wide relative costs of operating the specific unit compared to other available units
Fuel quality can affect unit capacity in a number of ways An analysis of the way fuel quality affects the capacity of each component of a generating station can reveal the total impact This analysis must start with the component most critical in detennining power station capacity The next step is to estimate the effects on less critical components The effects of successively less critical components may be interactive with the impacts on more critical components In some cases a change in fuel quality may affect one component to such an extent that it becomes the most critical item
Since a coal-fired steam-electric unit has a large number of components detailed analysis can be quite complex In Chapters 3-5 the effects of coal characteristics on the seven major components of a power station were described The capacity of the component was often influenced by these effects In many cases these effects could be evaluated with reasonable accuracy using existing straight forward engineering procedures In other cases assumptions on coal behaviour had to be made to facilitate the calculations As was summarised in Sections 34 43 and 53 there are some significant uncertainties related to many assumptions made
632 Heat rate
Heat rate (HR) is an index of the overall efficiency of a power station expressed as the heat input in the form of coal (Qin (MJIhr or BtuIhr)) required to produce one unit of electrical energy It may be expressed on a gross or net basis Gross heat rate (GHR) is based on the total or gross power
69
Coal-related effects on overall power station performance and costs
(GP) produced by the turbine generator while the net heat rate (NHR) is based on the GP reduced by the auxiliary power (AP) NHR depends on the turbine heat rate (THR) boiler efficiency (BE) GP and AP and it may be calculated as follows
NHR= THR x GP BE (GP-AP)
The coal changes which affect heat rate are associated primarily with boiler thermal efficiency auxiliary power consumption and turbine cycle efficiency (via changes in steam conditions) The following three sections describe how coal characteristics can affect boiler efficiency auxiliary power consumption and turbine heat rate respectively
Boiler efficiency The most widely used method of evaluating the impacts of coal characteristics on boiler efficiency is to assess the heat losses from the boiler and to assume that the remainder of the heat is absorbed to produce superheated or reheated steam This approach has the advantage of eliminating direct measurement or calculation of heat transfer rates in each section of the boiler which are quite complex but can only be carried out with suitable probes on fully instrumented boilers
The procedure involves the calculation of around six types of heat losses (Corson 1988) These can be
dry flue gas loss heat losses due to fuel moisture heat loss due to moisture produced from the combustion of hydrogen in the fuel heat loss due to combustibles and sensible heat in the ash
heat loss due to radiation unaccounted heat losses
Dry flue gas loss which is usually the largest factor affecting boiler efficiency increases with higher exit gas temperatures or excess air values Every 35degC to 40degC increment in exit gas temperature is reported to reduce boiler efficiency by 1 A 1 increase in excess air by itself decreases boiler efficiency by 005 ill most boilers however increased excess air leads to higher flue gas exit temperatures (FGET) Consequently increases in excess air can have a twofold effect on unit efficiency (Singer 1991) Calculations of excess air requirements depend on
flame stability carbon burnout slagging and furnaceconvective pass heat transfer considerations
These are difficult to predict with existing correlations
Losses due to moisture and fuel hydrogen are calculated easily from the coal analysis data using straight forward chemical and physical relationships
illcomplete combustion is manifest primarily by carbon in the bottom and fly ash The carbon content of the ash is difficult to predict and is affected by the slagging and fouling characteristics of the coal If the furnace is large enough to avoid slagging and fouling problems the carbon content of the ash is often less than about 5 For any furnace the carbon content of the ash tends to increase as the excess air decreases Also carbon loss may vary with char reactivity which depends on coal characteristics such as particle size
Table 27 Calculation of boiler heat losses (Folsom and others 1986a)
Loss
Dry gas
Fuel moisture
Fuel hydrogen
Combustibles
Radiation
Data required
Coal ultimate analysis Excess air Exhaust temperature Product specific heat
Coal moisture content Exhaust temperature H20 latent and specific heat
Coal hydrogen content Exhaust temperature H20 latent and specific heat
Carbon content of ash Coal carbon and ash content Heating value of carbon
Total heat output Maximum continuous rating
Assumption Comments
Complete combustion based Carbon corrected for on ultimate analysis carbon lost to ash shy
usually the largest loss
Complete combustion of fuel hydrogen to H20
Neglects CO and HxCy emissions which are usually negligible
External surface temperature Usually less than 05 Ambient air velocity over surfaces Independent of coal characteristics Calculated using ABMA chart
Unaccounted None Allowance for Usually estimated as about 05 bottom ash quenching Independent of coal characteristics CO and HxCy emissions Miscellaneous
70
Coal-related effects on overall power station performance and costs
rank and petrographic composition and combustion as the heat absorption pattern in the boiler changes Also if conditions At present there is no satisfactory method of the acid dew point of the flue gases changes the operators predicting the carbon content of the fly ash andor may need to adjust furnace exit gas temperature (FEGT) so combustibles loss based on standard coal analysis alone as to maintain the minimum air heater metal temperature Most coal quality analyses merely assume that the carbon above the acid dew point to avoid air heater corrosion loss guarantee provided by a boiler manufacturer will not be Whilst largely empirical procedures are used the actual exceeded This is usually in the range of 5 since fly ash amount of available data are insufficient to determine the with higher carbon content has less value for subsequent use accuracy of this approach Thus improved procedures need such as feed stock for cement manufacture (see to be developed and evaluated for assessing excess air flue Section 524) For coals with 10 ash and 60 carbon as gas exhaust temperature and combustible loss as a function fired 5 in the fly ash corresponds to a carbon utilisation of coal characteristics for a given furnace efficiency of 9912 (Folsom and others 1986a)
A summary of the data required for calculating heat losses is Procedures have been developed to predict combustibles loss given in Table 27 Combustion handbooks published by the based on furnace models An example of this is a boiler manufacturers include detailed descriptions of 3-dimensional model developed by the Energy and procedures for evaluating these losses (Babcock amp Wilcox Environmental Research Corporation USA (EER) This 1978 Singer 1991) These calculations are complex but includes a char combustion sub-model which evaluates the nevertheless straightforward and can be automated via a combustion process as a function of the micro-environment computer program easily An illustration of typical boiler surrounding individual char particles (WU and others 1990) losses for four Australian Queensland steaming coals is given Several more simplified approaches to carbon loss prediction in Table 28 have been developed All involve burning the coal under controlled laboratory conditions measuring the carbon loss Auxiliary power consumption and then scaling these data to full-scale units (see Power station auxiliaries consume power for Section 421)
coal handling In the calculation of boiler efficiency the flue gas exit mills temperature (FGET) is usually assumed constant However a feedwater pumps detailed evaluation should consider that the FGET may vary soot blowing
Table 28 Typical boiler losses for four Australian Queensland steaming coals (St Baker 1983)
Coal type A B C D
As-burnt - Total moisture 70 160 100 110 -Ash 214 143 100 280 -Carbon 581 535 676 487 - Nitrogen 11 09 15 09 - Hydrogen 39 34 38 32 - Sulphur 04 03 02 02 -Oxygen 76 111 64 75 Unburnt carbon 05 05 05 05
Gross heating value GJt 2412 2120 2738 1998 Latent heat of evaporation 102 112 106 096 of H20 from coal OJt Net heat value GJt 2310 2008 2632 1902 Unburnt carbon loss GJt 017 017 017 017 Radiation amp other losses OJt 013 012 015 011 Total dry air per tonne of coal tit 9130 8180 10433 7556 Sensible heat in combustion air OJt 221 196 252 183 Total heat available OJt 2501 2175 2852 2057 Overall total combustion products t 10130 9108 11433 8556 Exit flue gases (at 130degC) OJt 0108 0110 0108 0110 Flue gas exit loss GJt 110 100 123 094
Heat balance Heat input in coal 1000 1000 1000 1000 - Flue gas exit loss 46 47 45 47 - Heat loss due to H20 42 52 39 48 - Loss to unburnt carbon 07 08 06 09 - Loss to radiation etc 05 05 05 05
Net heat to watersteam 900 888 905 891
71
----
-----------
Coal-related effects on overall power station performance and costs
fans 200 shyparticulate control
flue gas desulphurisation shy-~ 0
Auxiliary power is typically in the range of 50 to 100 of gross power and is highly dependent on the specific power station design However coal characteristics also affect power consumption for most of these components although the impacts in many cases are not large and can be evaluated by considering trends
The primary factors impacting the power requirements for coal handling are the design of the systems and the desired coal flow rate The design of coal handling systems varies substantially and power requirements can be determined accurately by considering the details of the specific designs Since coal handling equipment normally operates intermittently any change in coal flow rate will change the duty cycle of the equipment and the power consumption will be approximately proportional to the coal flow rate This assumes that no modifications to the coal handling equipment are made to increase capacity In some analyses the coal flow rate is assumed to be inversely proportional to the coal heating rate on the assumption that the total heat input remains constant However as discussed earlier any change in heating value may change the performance of several other power station components and impact overall heat rate This compounding effect means that changes in coal flow rate are often greater than would be expected based on heating value alone
The power required for coal grinding depends on mill design characteristics of the coal feed including its grindability and size distribution and the mill operating conditions including the coal flow rate and pulverised coal size distribution The manufacturers have developed power consumption correlations based primarily on Hardgrove grindability index (HGI) Cortsen (1983) reported that the power consumption of the mills at a Danish utility was mainly dependent on the grindability of coal In evaluating mill performance it must be recognised that for a given design the operating parameters are linked It is not possible to vary the coal flow rate HGI and pulverised coal size distribution independently This is illustrated in Figure 25 which shows the effects of an independent change of coal grindability on the performance of a pilot vertical spindle mill (Luckie and others 1980) However Folsom and others (1986a) put forward the theory that reasonably accurate evaluation of coal changes have been made by assuming that the power consumption varies linearly with the coal flow rate independent of coal grindability in cases where variations in HGI are small St Baker (1983) reported that the power consumption of mills increases with increases in moisture content
There are few data that can be used to determine the number of soot blowers and frequency of operation for a specific coal The usual procedure is to select the wall blower array based on experience with similar coals and to set the wall blower operating schedule during normal boiler operation to minimise slagging and fouling problems The actual frequency of soot blowing will depend on the severity of
a5 sect 5 0
Cii 0 ()
100 ---shy--constant coal flow rate ---
0
40 50 60 70
Hardgrove grindability index (HGI)
80
100 -
o 40 50 60 70 80
Hardgrove grindability index (HGI)
10 shy
5
o 40 50 60 70 80
Hardgrove grindability index (HGI)
Figure 25 Effects of grindability on vertical spindle pulveriser performance (Luckie and others 1980)
slagging and fouling In some cases certain boiler stages may be blown unnecessarily and incur a heat rate penalty Excessive blowing can result in erosion of the tube surfaces which leads to premature tube failure and subsequent forced outages Proper blowing schemes are critical in achieving target steam and flue gas exit temperatures Wall blowers can utilise steam or air as the blowing medium The steam consumption can be treated as auxiliary steam use and can be evaluated in terms of its impact on heat rate Compressed air is generated in motor driven air compressors and the compressor power consumption can be evaluated as part of the auxiliary power load which has a greater impact on overall heat rate
The power consumption of fans in a power station is based
72
Coal-related effects on overall power station performance and costs
on the required flow rate and pressure rise fan design and the method of fan control Given these parameters the power requirements may be calculated easily based on standard fan analysis procedures In general a coal change that causes an increase in flow rate or pressure rise for example as a result of a reduction of cross-sectional flow area due to ash deposit bridges will increase fan power requirements (Borio and Levasseur 1986)
Essentially all the power consumed by an electrostatic precipitator for particulate control is used to generate the corona The power consumed to charge and deposit particulates is negligible while collection efficiency increases with corona power (Folsom and others 1986b)
The auxiliary power requirements of the flue gas desulphurisation (FGD) systems depend on the equipment designs which vary substantially among operational systems employed internationally A number of reference manuals have been published which provide procedures for evaluating the impacts of coal quality on flue gas desulphurisation systems These manuals should be consulted to conduct a detailed evaluation of the impact of coal characteristics on flue gas desulphurisation system auxiliary power (Dacey and Cope 1986) Generally the FGD facility will require more auxiliary power when operating with a high sulphur coal
Turbine heat rate Turbine heat rate is an index of the efficiency of the steam cycle and generator set in converting heat supplied to the turbine in the form of superheated or reheated steam to electrical power The turbine heat rate depends on the specific design of the turbine cycle as well as the operating conditions principally the steam supply and the discharge conditions
Since the coal does not come into contact with the steam coal quality impacts on turbine heat rate are neglected in many analyses However coal quality can impact the steam supply characteristics by changing the distribution of heat absorption among the various heat transfer surfaces in the boiler as discussed earlier in this section It should be noted that this is distinct from the total quantity of heat absorbed which is related to the boiler efficiency Changes in the heat distribution may result in an inability to achieve the required superheat or reheat temperatures or necessitate excessive attemperation to moderate steam temperature Both effects can degrade turbine cycle efficiency significantly
Evaluation of the effects of coal characteristics on steam temperature and hence turbine heat rate requires analysis of the radiative and convective heat transfer occurring in the various boiler sections and consideration of the options available to boiler operators to vary steam conditions (see also Section 42) A wide range of heat transfer models of varying complexity for the furnace and convective surfaces have been created (Shida and others 1984 Robinson 1985 Boyd and Kent 1986 Fiveland and Wessel 1988 Pronobis 1989) (see also Section 72)
The effects of coal characteristics on heat transfer evaluated by these methods can be grouped into three categories
gas flow rate changes through the furnace and the tube bank due to the volume of combustion products which mainly affects convective heat transfer radiative heat transfer changes due to varying coal composition combustion conditions and particle deposition heat transfer change due to deposits resulting from slagging and fouling
The volume of combustion products from a coal of arbitrary composition can be evaluated easily by simple combustion principles given the firing rate and excess air The impact of volumetric air flow rate on radiant and convective pass heat transfer can be evaluated using the models The effects of coal composition on radiative heat transfer are more difficult to evaluate As coal composition changes the radiative characteristics of the reacting gases and particles change along with the characteristics of the wall deposits The emissivity and thermal resistance of the ash deposits have the greatest impacts Similarly the effects of fouling deposits on convective pass heat transfer are difficult to evaluate However tests of slagging in pilot-scale furnaces indicate that potassium sodium sulphur ash fusion temperature ash particle size and total ash might be important (Wagoner 1988 Pohl 1990) In contrast Wain and others (1992) have shown in a study of slags from UK power stations that the thermal conductivity of wall deposits is primarily influenced by the physical properties of the slag such as its porosity rather than by its chemical composition
Deposits are formed over the perimeter of the tube quite irregularly so that the effective shapes of the tubes immersed in the flow of flue gases are completely changed This not only impairs the efficiency of the heat exchanger because of the necessity to overcome the thermal resistance layer but leads also to changes of the heat transfer coefficient brought about by the changed flow pattern and the effective shape of the tube cross-sections In the course of time the properties of the deposits also change resulting in further changes of thermal resistance (Pronobis 1989) The ability to remove the deposit by soot blowing and recovery of lost heat transfer is also important and is determined by the thickness strength and phase of the deposit and the available soot blowing power (Wagoner 1988)
If the effects of these changes on heat transfer can be determined or assumed the turbine heat rate can be evaluated via thermodynamic analysis Several computer programs have been developed to analyse complex thermodynamic cycles The limiting factor of the models is the specification of the input parameters
In general the heat rate correlations are perceived to be adequate providing that certain key parameters such as excess air carbon loss and mineral matter impacts can be specified In many analyses these are assumed since coal quality impact data are usually not available An example of the cost implications of a coal change on heat rate for a 1000 MW boiler was compiled by Folsom and others (1986a) Figure 26 illustrates this effect based on various assumptions conceming the unit characteristics The relatively large change in coal quality is shown to result in a
73
Coal-related effects on overall power station performance and costs
Change in coal characteristics
Coal ash increase 10
Coal moisture increase 5
Coal heating value decrease 15
Char reactivity decrease
- carbon in ash increase 2
- excess air increase 0
Ash deposition
- superheat decrease 50degC
- reheat at temperature increase 5
- exhaust temperature increase 10
Loss component Cost impact
ESP
Coal handling
Carbon loss
Dry flue gas
Moisture loss
Fans
Turbine efficiency
070
010
055
079
048
066
118
65 capacity factor base line heat rate 10000 Btu kWh thermal efficiency 89 coal heating value 279 MJkg (12000 Btulb) coal ash 10 coal moisture 5 coal carbon 77 and coal cost 35 Sit
Figure 26 Example of cost impact of a coal change on heat rate for a 1000 MW boiler (Folsom and others 1986a)
cost impact in heat rate of $446 millioniy (1986 prices) which is equivalent to an availability loss of about 5
As an alternative to these fairly complex calculations some attempts have been made to correlate coal quality with heat rate and boiler efficiency statistically (Barrett and others 1983 Kemeny 1988)
Several organisations have developed methods to facilitate the calculation of coal quality impacts on heat rate Some of these methods use computer programs to calculate economic effects directly from coal quality data power station design information and economic assumptions Others make use of manual calculations and rely more on engineering judgement and experience with similar coals
The use of both statistical techniques and computer models is discussed in greater detail in Chapter 7
633 Maintenance
While it is widely accepted in the utility industry that coal characteristics can affect maintenance costs primarily via wear by abrasion and erosion and by corrosion of power station components there is at present no effective method for predicting the effects of a coal change on maintenance Utilities use a range of procedures to account for maintenance costs in coal-fired units Whilst these procedures generally meet utility needs they often make it difficult to evaluate actual coal quality impacts For example while the maintenance cost due to a tube failure may be identifiable it may not be possible to determine whether tube failures relate to coal quality water quality structural problems or other effects (Heap and others 1984) Another significant problem is that maintenance costs are due in part to phenomena which should be predictable and form part of scheduled
maintenance routine for example replacement of expendable components (such as worn mill rollers and balls) Unfortunately they are also due to unscheduled failures which may cause partial or full outages It has been demonstrated that both routine maintenance requirements and unscheduled outages can be affected by coal characteristics
The mechanisms involved in wear of components are discussed in more detail in Sections 32 and 422 For many components the major factor affecting wear rates and hence maintenance costs is the mass of material processed This will be directly related to the heating value of the coal and the heat rate of the power station However as discussed in Sections 32 and 422 certain coal minerals are identified as strongly influencing the rate of wear by abrasion in handling equipment and mills In some instances erosion rate depend on power station design and aerodynamic considerations (Walsh and others 1988 Platfoot 1990)
Increases in unscheduled maintenance costs and consequent reduced availability (see Section 634) even involving reduced boiler life which result from excessive boiler flue gas erosion and corrosion can be considerable In a review of the state-of-the-art methods of reducing fireside corrosion and fly ash erosion as factors responsible for tube failures in boilers Wright and others (1988) reported that both of the effects are considered to be major problems only on units burning coal that is rated as very aggressive (high sulphur alkalis and chlorine) or that contains a high percentage of erosive materials such as quartz and ash Fly ash erosion of primary superheater reheater and economiser tubes were considered to be more serious problems than fireside corrosion An interesting observation from the study was that although there were proven permanent solutions for most of the problems encountered such as coal and hardware modifications these were not widely accepted Evidently the
74
Coal-related effects on overall power station performance and costs
costs of these solutions were perceived to compare unfavourably with continued maintenance activities in spite of the inconvenience of several unscheduled outages annually for emergency maintenance
St Baker (1983) reported that a typical 20-day unscheduled outage on a single 350 MW generating unit to repair boiler erosion damage could cost more than A$2 million in 1983 in replacement power costs alone This would amount to more than A$33 million (US$25 million) at 1991 prices
In a study of the use of declining fuel quality in 110 and 200 MW Czechoslovak power stations Teyssler (1988) showed increased maintenance costs due to higher equipment wear Examples of costs were given as Czech crowns 15-25t ash output in 1988 (US$04-07 (1991raquo for the cost of repair and replacement of heating surfaces damaged by erosion a 1 increase in ash content was found to result in at least a 10 higher cost in mill component replacement
Smith (1988) in a paper describing Tennessee Valley Authority s (TVA) experience with switching to improved quality coal presents a comparison of performance variations at the Cumberland power station (2 x 1300 MW) and Paradise power station (2 x 704 MW 1 x 1150 MW) with coal quality over the period 1977-86 The results show that maintenance costs for the boilers burning equipment and ash handling equipment were reduced with improved quality coal Costs dropped by about US$15 millionyon average between 1980 and 1984 at the Cumberland power station In this case the improvement in quality was achieved by cleaning the coal supply Prior to coal washing the units exhibited extensive slagging fouling corrosion and tube leakages Figure 27 shows the effect of a coal quality change that occurred at Cumberland in 1982 The largest change after washing was a reduction in ash content from about 152 to 92 Sulphur was reduced from 35 to 28 and which heating value went up from 249 MJkg (10712 Btulb) to 271 MJkg (11635 Btulb) In contrast
10 o boilers
A burning equipment 9
LD ash handling equipment co en 8~
c Q 7E $ (j) 6 =gt t5 50 u (l) u 4c ro c 2 3c iii ~ 2
I 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986
Figure 27 Adjusted maintenance cost accounts for TVAs Cumberland plant (Smith 1988)
operation and maintenance costs for the Paradise power station do not show dramatic cost improvements on utilisation of washed coals because major modifications and maintenance improvements necessitating significant investment were also made to the station over the same time period TVA believe that damage done to the Cumberland boiler by years of operating with poor quality coal was still causing problems long after the change to washed coal (Smith 1988) This example illustrates the difficulty of obtaining valid information of coal quality effects on maintenance and other power station performance factors independently from the influence of other modifications and changes in operating procedure
Hodde (1988) in an investigation of work conducted by Blake and Robin (1982) which considered the contribution of coal quality effects to total fuel-related operating costs of the Southern Company USA (see Table 29) concluded that whilst the dominant portion of the total fuel-related bill is the delivered cost of fuel comprising about 80 the remaining costs are associated with problems due to coal quality It was shown that approximately three quarters of the quality-related costs are in maintenance and residue disposal From this assessment Hodde (1988) suggested that maintenance costs relate linearly with coal quality in particular ash and could be calculated in advance This figure together with the price of the coal would account for almost 90 of the total costs associated with the coal This simplified approach is adopted in a number of computer models (see Section 72) However the approach has been challenged by a number of other sources (Folsom and others 1986b Mancini and others 1987 Galluzzo and others 1987 Lowe 1988b) who report that maintenance costs are not linearly related to the mass of ash processed by a power station Additionally there is usually a substantial lag between the initial variation in ash content of the fuel and the first experience of its effect on maintenance costs Consequently care should be taken in the use of linearised maintenance cost assessments to allow for the effects of lead times and incubation
In general the relationships between maintenance costs and coal quality are difficult to assess due to four factors the inadequacies of records maintained by utilities the impact of non-coal-related factors power station design variations and delayed effects of coal quality impacts
Table 29 Total fuel costs for power stations of the Southern Company USA (Hodde 1988)
Costs of total For coals with ash content of
15 20
Delivered fuel cost 83 77
Waste disposal cost 5 6 Maintenance cost 7 9 Ash related unavailability 3 4 Other operating costs 2 4 Slagging and fouling -0 -0
Total 100 100
75
r ~ 250 lt9 c o t3 200 J 0 2 a 0 150 3 o a
Ui3 100
50
o 2 (ij 3
~
0 ro Q)r 0 a J
(fJ
0 ~ 0 gt
5 0
(ij 0 c Q)
3 ~ is
CD
~ 2 ro Q)r Q)
a
0 ltJ)
E 0 c 0 U w
c ~
-0 0 Q) u J 0
Ol c 6l Ol ro iii
Coal-related effects on overall power station performance and costs
Table 30 Comparison of reduced boiler availability on the basis of hours in operation and type of fuel (Pasini and Trebbi 1989)
Mean annual All boilers Hours in operation Type of fuel reduced availability lt105 gt105 oil-gas coal
Furnace wall 220 203 270 184 309 Secondary SH 054 032 113 045 075 Reheater 032 032 032 015 075 Primary SH 019 008 051 005 054 Economiser 013 005 036 012 014
Unheated 020 017 029 025 008 Casing 030 025 043 039 009 Others 045 075 048 045 045
Total 433 365 622 370 588
634 Availability
The availability of a power station is important to both system reliability and generating-company profit Improving availability only slightly can save considerably on reserve generating capacity and the cost of replacement power Availability can be defined as the percentage of time that a unit is available for operating regardless of whether electricity is actually generated The total electricity sent out from a power station is affected by the planned shutdowns for maintenance forced down-ratings forced outages and other reductions in its availability (Mellanby-Lee 1986)
While it is clear that availability can be affected by coal quality the nature of the relationship is not well understood Statistical data-gathering studies such as the programme conducted by the North American Electric Reliability Council (NERC) utilising the Generating Availability Data System (GADS) supplied data relating to the component cause of outages and load reduction but were not able to provide information as to why particular components failed (Electrical World 1987) A study conducted by Combustion Engineering USA has gathered information from coal-fired units of 390 MW and larger on the causes of outages and load reductions in nine major equipment categories related to steam generators Included were
water walls superheaters and reheaters economisers furnace soot blowingbottom ash removal equipment convection-section soot blowing and fly ash removal equipment boiler controls fans mills boiler circulating pumps
The study indicated that water wall superheater reheater and economiser tube leaks account for 80-90 of all forced outages whereas coal milling systems accounted for 50 of equivalent down-time hours in load reductions (Llinares and others 1982 Llinares and Lutz 1985) Pasini and Trebbi (1989) reported similar trends of reduced power station availability for ENEL Italy (see Table 30) Mancini and
others (1988) reported that in a study of the top eighteen causes of full and partial outages at coal-fired stations in the USA for the decade from 1971 through 1980 60 of these causes were related to coal-quality (see Figure 28)
A record of boiler tube erosion at two Australian power stations Munmorah (4 x 350 MW) and Liddell (4 x 500 MW) illustrates the considerable costs that can result from excessive flue gas dust burdens in boilers supplied with off-specification coals particularly ash content above the design level They have experience of
up to 7 per annum additional reduced availability due to outages for the repair of boiler tube leaks reduced boiler life before major refurbishment affecting the economic life and gross power station output over
350
300 Coal related outages represent 60 of total power station outages
E
Figure 28 Causes of coal-related outages (Mancini and others 1988)
76
Coal-related effects on overall power station performance and costs
Southern Electric System USA 10 ] D US Industry average
8
7
6
J lLshy 5 ltt w
4 9339
3
2
90
Early units Early units Later units 1975-77 1985-87
Figure 29 Boiler and boiler tubes equivalent availability factor (EAF) record (Richwine and others 1989)
which the power stations initial capital costs could be recovered the necessity to be complemented by a greater level of standby generating capacity in order to ensure adequate reliability of electricity supply to consumers (St Baker 1983)
Richwine and others (1989) reported the results of an availability improvement programme in the Southern Electric System (SES) USA coal-fired units Due to a decline in availability between 1970-76 increased attention was given to this factor such that from 1977 to 1988 an improvement of over 22 percentage points was achieved This turnaround was accomplished by recognising the problems implementing appropriate solutions and adopting new power station practices The problems included coal-related cases such as boiler tube superheater reheater and economiser tube failures arising from fly ash erosion and slagging Figure 29 shows the increase in equivalent availability factor (EAF) achieved when coal quality upgrades were adopted along with tube maintenance during planned outages and the design improvements of later units to incorporate a wider range of coals while maintaining high reliability Problems encountered with mill operation were recognised as being a result of coal characteristics Many units experienced outages due to fires and flow problems due to high moisture coal
It has been suggested that a 5 increased outage rate for a power station designed for a 30 ash coal compared for one designed for 15 ash is a reasonable allowance for possible loss of availability (ERM Consultants 1983)
Due to the undefinable relationship between availability loss and coal characteristics engineering correlations cannot be used directly to evaluate the impacts of coal quality on availability At present the only way to calculate availability loss due to particular coal parameters seems to be to correlate
performance observations in the operating boiler with coal quality data Illustrations of these type of observations have been given above On a larger scale than single power station observations the statistical studies conducted by TVA (Barrett and others 1982) EPRI (Heap and others 1984) and the National Economic Research Associates (NERA) (Corio 1982) (see also Section 731) provided correlations for availability parameters of boilers with
ash sulphur and the age of the boiler (TVA study) actual ash sulphur and moisture content utilised and differences between actual and design values a complex relationship involving 13 independent variables
Most of the methodologies above resulted in equivalent availability values increasing with ash and sulphur contents which is contrary to expectation The correlation utilising the difference between actual and design coal quality values with availability agreed with expectation in that the availability of a power station should be degraded by deviation from the design coal specification A more detailed account of statistical studies is given in Section 731
64 Comments In any final analysis the economic trade offs which take into account system availability cost of coal (at various quality levels) maintenance costs substitute fuel and capacity costs station replacement costs etc must be analysed for each operating situation Only then can any meaningful and specific conclusions about the cost impact of coal quality on the cost of electricity be made Final judgements are often required to compare these costs with other factors such as diversity of supply reliability control of emissions for environmental reasons balance of trade and currency availabilities in order to make final coal selection decisions
Whichever judgement is made it is widely accepted that the capacity availability and cost of operation of each individual boiler are materially affected by the quality of coal fed to it It is generally believed that availability does not depend on the quality of the design coal and will only be affected if the actual coal burnt is outside the design range (Cagnetta and Zelensky 1983) However experience at some stations have shown that substantial losses in availability or down ratings can occur when the quality of the coal used is not outside the design range A summary of these effects is shown in Table 31 The missing links though in coal quality evaluations are the lack of information concerning power station performance and the ability to attach a price to a change in performance as a result of a change in coal quality
There is also the problem that some affects of a change in coal quality require time to show themselves Proper allowance must also be made for this incubation period
Hitherto the accounting systems of many utilities have not been designed to identify easily the costs associated with coal quality impacts (Skinner 1988) These systems need to
77
Coal-related effects on overall power station performance and costs
Table 31 Examples of boiler fireside variables station and cost components which may be affected by those variables when coal quality is changed (Sotter and others 1986)
Variable type Boiler design Operating conditions cost component
affected Coal quality
Capacity Ash size distribution - organic associations - separate species Moisture content Hardgrove grindability index Sulphur content
Heat rate illtimate analysis Moisture content Slow burning macerals Slagging fouling indices (Steam temperature control)
Maintenance Ash content Ash composition (abrasiveness slagging tendency)
Availability Ash Na 0 CaO Fez03 SiOz etc
be updated and improved if utilities wish to take full advantage of new tools that are becoming available In particular improved data are required to support the
Number of mills Precipitator collecting area
Burner type Furnace size
Number and placement of soot blowers
Heat releasefurnace area Convective tube spacing
Excess air
Excess air Coal particle sizes Burner settings
Load history
Load history Soot blowing interval
increasingly sophisticated computer models which can be used to predict the effect of fuel quality on station performance
78
7 Computer models
The decision to buy particular quality coals from either local interstate or from international sources must include a quantitative evaluation of the impact of coal quality on performance of the power station and ultimately the cost of electric power generation As has been demonstrated in Chapter 6 and illustrated further in this chapter the cheapest coal to buy does not necessarily produce the cheapest electricity Because of the large number of processes involved in the coal-to-electricity chain and the complicated nature of coal-power station interactions engineering and economic evaluation studies are usually both time consuming and costly The methodologies adopted can range from manual calculations and a reliance on practical experience with similar coals through to elaborate computer models which calculate performance and resulting economic impacts directly from coal quality data power station design information and economic factors Use of a computer based model to quantify the impact of coal and system parameters on the cost of electrical generation could substantially reduce the time and cost of these studies In theory such a model would be used to evaluate various approaches and the most economic action could be selected with relative ease (Ugursal and others 1990) However it should be noted that the results from the models are only as good as the data used in particular the coal properties measured to predict combustion performance
For the purpose of this report the types of models available for the evaluation of part or all of the coal-to-electricity chain (see Figure 1) have been identified as belonging to one of four categories described below
least cost coalcoal blend models that assess the cost of coals and their associated transport costs They can calculate suitable coal blends according to power station design specifications to provide the lowest cost purchasing plan They may also include allowances for some maintenance and disposal factors
component evaluation models that predict the performanceefficiency of the subsystems of the power station such as mills boiler ESPs unit models that offer coal quality impact evaluation of an entire power station and in some cases attempt to supply costs of the impacts on generation Two methods most commonly put forward as evaluation techniques include
statistically-derived regression analyses leading to overall power station inputoutput models developed for specifying general utility power station requirements These models however do not usually contain detailed predictions of system operation or design requirements
systems engineering analysis for defining relative impacts of fuel properties on each systems performance These types of models are being developed by both equipment manufacturers and research contractors and utilise in addition to fuel property data (that is proximate and ultimate analyses and slagging and fouling indices) special bench-scale measurements of key parameters and pilot-scale data These data combined with the proprietary models can allow for the determination of operating limits for specific units
integrated site models that bring together the information from unit models systems performance and other models and are integrated directly into the control room data system
In this chapter brief examples of the above methodologies are described with particular emphasis given to unit models which are known to include coal quality impact assessments Although particular attention is given to coal specification details used by the models the overall intention is to provide a cross-section of the procedures and the capabilities of the various methodologies
79
Computer models
71 Least cost coalcoal blend models
Least cost models in most cases use linear relationships for the evaluation and purchasing of fuels for power stations The technique is used to find the lowest cost purchasing plan for a utility fuel buyer from among a large number of fuel supplies available and will meet the constraints imposed by the fuel supplies and by the utilityS system The programs are usually designed to run on personal computers and to be user-friendly (Allman 1987 Bek 1987 Hodde 1988 Maher and Smith 1990)
Examples of this type of model include the International Coal Value Model (ICVM) (Maher and Smith 1990) Least Cost Fuel System (LCFS) (Hodde 1988) and Perfectblend (Bck 1987) and Steam coal blending plan (Allman 1987 1991) for blending coals
Least cost coalcoal blend models are reported to have the ability to conduct an economic evaluation of thermal coals as traded on the world market The main users of the models are identified as power companies buying coals of various properties and costs from a number of sources In many cases
blending of coals would also be employed The coals would be selected by the model in accordance with the coal specification requirements of the power stations based on their design and operating experience They are designed as a tool to determine the real cost of coal and energy at the inlet of the power station being considered (see Figure 1 Sections 1-4 of the coal-to-electricity chain) They permit comparison of all coal properties within allowable power station coal specifications including other coals and blends It allows for the blending of a large number of coals in any desired proportions (Maher and Smith 1990) Examples of the types of input data required and the items included in the results for a Least cost model are given in Tables 32 and 33
This type of model does not apply merits or demerits in value for particular properties for example sulphur The reason given by the developers is that the effect of such properties is very site-specific being dependent on the design of the power station and accessories for example flue-gas desulphurisation environmental regulations applying residue disposal costs etc
Hodde (1988) illustrated the use of the Least Cost Fuel System model by considering a utility system with three
Table 32 Model input output data -International Coal Value Model (ICVM) (Maher amp Smith 1990)
Developer Coal input Generating unit input Key output
Joint Coal Board CSIRO Australia
Gross specific energy Total moisture Proximate analysis Elemental analysis Chlorine Phosphorus Free swelling index Hardgrove index Ash fusion temperatures degC Top size mm Fines ltlmm Sulphur form Ash analysis Cost fob cif Currencies amp
exchange rates Ocean freight costs Insurance costs Handling costs
Power station power output MW Generated thermal efficiency Capacity factor
Gross and net specific energy and other properties calculated to different bases and units
Slagging and fouling tendencies Average blend properties with non-linearity warnings CoalconsumptionUy Ash production Uy Cost of coal at pulverisers in various currencies on a
tonne per consignment and per energy unit basis Thermal coal database
Table 33 Comparison of coal energy costs based on gross heating value (at power station pulverisers) - in order of increasing cost (Maher and Smith 1990)
Coal Cost US$GJ Total Specifications moisture
ash VM gross specific energy MJlkg
BBB 206 90 1193 330 2953 AAA 212 95 1238 316 2909 Blend 2 220 84 1434 288 2903 Blend 1 222 86 1406 291 2901 CCC 229 80 1596 260 2869
80
Computer models
coal-fired power stations evaluating the purchase of coal from eleven coal sources supplying contract and spot deliveries Like the ICVM model the objective function to be minimised includes the sum of the fob mine coal cost transport cost and coal quality costs for all three stations on the system But unlike the ICVM the LCFS includes additional costs related to coal quality that are net of the following
maintenance costs assumed to be linearly proportional to the tons of ash processed by each power station ash disposal costs also assumed to be linearly proportional to the tons of coal burned at each station fuel handling costs assumed to be linearly proportional to the tons of coal burned at each station FGD operation and maintenance cost and FGD residue disposal costs assumed to be linearly proportional to the tons of sulphur removed from the flue gas revenue from the sale of ash for construction material assumed to be linearly proportional to the ash content of the fuel
These factors are calculated separately and fed into the LCFS model Additional constraints can be added for utility application For example some utilities are located in regions which have legislated that a certain fraction of the coal burned for power production must be sourced from the region
These programs make only limited provision for coal quality because most of the effects on costs are non-linear so that they cannot be accommodated by these models Warnings are issued by some models of the non-linear behaviour of coal blend properties for example Hardgrove grindability index ash fusion temperatures and ash analysis
Coal quality impacts that are not assessed by the simple models include
slagging and fouling costs cost of reduced boiler availability impacts of coal quality on gross power station heat rate and boiler efficiency impacts of coal quality on the capacity of various station systems including mills fans and ash handling systems
72 Component evaluation models Since the mid-1970s boiler manufacturers utilities and other research centres have been developing advanced numerical system models that can be used to optimise performance of power station components and hence improve overall system performance Most of the development effort has been directed to modelling the boiler With the increasing availability of substantial computing power numerical simulation of combustion systems is now feasible and provides a new engineering tool for evaluating designs and the complex interactions in the flow and combustion processes More recently the techniques have been applied to improve understanding of NOx formation and control in increasingly complex combustion systems For boilers the intricacy of the models range from single zoned one-dimensional (I-D) models
that predict combustion and thermal efficiency for boilers with staged or unstaged combustion systems (Smith and Smoot 1987 Hobbs and Smith 1990 Misra and Essenhigh 1990) to models attempting to solve the fully elliptic multi-zoned three-dimensional systems with finite difference approximations of the conservation equations for mass momentum turbulence combustion and heat transfer (Thielen and others 1987 Boyd and Lowe 1988 Gomer 1988 Jarnaluddin and Fiveland 1990 Luo and others 1991) A widely used boiler computer code known as FLUENT has also been applied to model PF boilers (Tominaga and Sato 1989 Swithenbank and others 1988 Vissar and others 1987 Lockwood and Mahmud 1989) Other examples are documented in literature and a review of the application of these types of models to addressing both NOx formation and unburned carbon has been presented recently by Latham and others (1991a)
The output from these models includes coal particle trajectories within the boiler predictions of unburned carbon involving coal devolatilisation and char burnout models furnace exit gas temperatures (FEGT) species concentrations heat release and heat absorption (Latham and others 1991a)
The coal characteristics that have been found to have the greatest influence in these boiler models are
ultimate analysis carbon hydrogen nitrogen sulphur oxygen
moisture content volatile matter content ash content heating value particle size distribution
Most of the models do not include provision for the effects of fouling and slagging propensity of a particular coal on heat transfer Work on developing computer models that describes the transformation of mineral matter during combustion the mechanism of ash deposition on surfaces as well as the physical properties of the ash deposit after deposition has been initiated (Hobbs and Smith 1990 Smith and others 1991b Beer and others 1992) Baxter (1992) has recently reported the development of a model that considers ash deposit local viscosity index of refraction and ash composition (ADLVIC) in coal-fIred power stations In contrast to other ash deposition predictor models which are based on the elemental composition of ash ADLVIC is based on the mineralogical description of a coals inorganic matter and can be used to predict changes in these mineral properties with time and their effect on ash deposition as the particles flow through the boiler It has received some validation during a three week test burn in a 600 MW boiler operated by Centrallllinois Public Services The approach of using mineralogical descriptions of a coals inorganic matter has also been utilised in a model called the Slagging Advisor developed by PSI Technologies (Heble and others 1991)
81
Computer models
I
Performance factors
MAXIMUM MILL CAPACITY
INLET AIR TEMPERATURE
GRIND CHARACTERISTICS
POWER ~
I
I
I I
Indicescorrelations
Fineness bull passing 200 mesh bull gt50 mesh
Grindability bull
bull HGI Wear
bull abrasion index bull ash burden bull wear index bull equal life
moisture
Pulverised coal distribution bull Rosin - Rammler distribution
function perameter
Mass throughputMMBtu
HGI
moisture
i
Engineering analysis model
COMPOSITE MILL MODEL
- Maximum capacity bull base capacity (as new - of MCR) bull 10ssMMBtu throughput
- Inlet air temperature bull minimum inlet temperature
- Mill power
I
U)0 ttl
~ 0 Q5
~ 0 0 E
Q Level 1 predictions
Q Level 2 predictions
Figure 3D Mill engineering model analysis approach (Nurick 1988)
Nurick (1988) describes an engineering model for the detennination of performance factors for each major system component as impacted by coal quality The modelling approach for each component is described For example Figure 30 illustrates the analysis approach for the mill engineering model The figure also highlights two levels of prediction capability The first level is based on the manual assessment of indicescorrelations of the coal properties and the second level refers to predictions from correlations obtained from application of the mill model The latter predictions can be included into an overall power station model In this particular case the overall performance model does not include any cost evaluations These models can form part of larger more comprehensive systems engineering unit models as described in Section 73
73 Unit models The development of models to assess the impact of coal quality on overall power station performance was initiated in the 1970s when statistical methods were used to compare historical power station performance and cost data (such as forced outage hours or maintenance costs) with coal use and coal quality data in order to fmd working relationships
More recently engineering-based methods have been employed to predict power station performance directly from coal characteristics by using individual component models as modules in an overall power station model In some of the unit models both statistical assessments and operating experience are employed to produce an overall assessment
731 Statistically-derived regression models
Most statistical studies of coal quality impacts on power station performance have been conducted by utilities and research organisations in the US A notable and extensively publicised statistical study has been performed by Battelle Columbus Laboratories and Hoffman-Hold Incorporated on Tennessee Valley Authoritys (TVA) coal-fired power stations (Barrett and others 1982)
The TVA study was aimed at evaluation of how coal quality impacts on boiler operation and costs Information was collected from nine TVA power stations for the period 1962 to 1980 based on monthly proximate analyses of the coal used power station outages maintenance costs boiler
82
Computer models
Table 34 Boiler groupings in TVA study (Barrett and others 1982)
Plant and unit Size Manufac- Firing Stearn Year put Capacity Coal Firing configuration MWlUnit turer methodsect temperature into
degC COF) commercial gt500 MW lt500 MW Midshy
operation Large Small Eastern Western Wall Tangential
Bull Run 1 950 CE PF-DB 538538degC 1967 j j
(10001OOOdegF) Colbert 1-4 200 BampW PF-DB 566566degC 1955 j j
(l0501050degF) Colbert 5 550 BampW PF-DB 566538degC 1965 j j
(10501OOOdegF) Gallatin 1-2 300 CE PF-DB 566566degC 1956 j j j
(l0501050degF) Gallatin 3-4 328 CE PF-DB 566566degC 1959 j j j
(l0501050degF) John Sevier 1-4 200 CE PF-DB 566566degC 1955-6 j j
(l0501050degF) Johnsonville 1-6 125 CE PF-DB 538538degC 1951-3 j j j
(l 0001 OOOdegF) Johnsonville 7-10 173 FW PF-DB 566538degC 1958-9 j j j
(l 0501OOOdegF) Kingston 1-4 175 CE PF-DB 538538degC 1954 j j j
(l0001OOOdegF) Kingston 5-9 200 CE PF-DB 566566degC 1955 j j j
(l0501050degF) Paradise 1-2 704 BampW Cyc 566538degC 1963 j j
(l 0501OOOdegF) Paradise 3 1150 BampW Cyc 538538degC 1970 j j
(l 0001 OOOdegF) Shawnee 1-10 175 BampW PF-DB 538538degC 1953-6 j j j
(l0001 OOOdegF) Widows Creek 1-6 141 BampW PF-DB 538538degCj[ 1952-4 j j
(l 0001ooodegF) Widows Creek 7-8 550 CE PF-DB 566538degC 1961-5
(l 0501 OOOdegF)
BampW = Babcock amp Wilcox CE = Combustion Engineering FW = Foster Wheeler PF = pulverised fuel Cyc= cyclone fired DB = dry bottom
II Units 1-4 do not have reheat
efficiency and where available griruklbility data The data were organised into 15 groups of similar boilers (see Table 34) In addition six aggregates of these 15 groups were assembled based on the capacity of the boilers (greater or less than 500 MW) coal characteristics (Eastern or Western US coal) and firing configuration (wall or tangential)
A variety of statistical techniques including linear and non-linear multiple regression techniques were used to look for meaningful relationships Power station boiler capacity was considered for inclusion in the analysis but dropped due to lack of precise historical data Operating costs other than maintenance costs as determined by TVA were not deemed dependent on coal quality so that analysis in this area was also discontinued (Barrett and others 1983)
In spite of the fact that considerable quantities of data were available within the TVA system it was recognised at the time that the data were not designed to support this study Hence the preferred data such as data on boiler capacity and detailed coal analyses were not always available The investigators sometimes found themselves under severe
limitations They persisted because they believed that the results from what was originally conceived as a limited study might provide utilities with additional useful information for making decisions conceming coal purchase and use
The study identified some quantitative relationships between certain coal quality properties and power station performance and cost However the statistical analyses suffered from the difficulty of co-linearity (or correlated variables) as it was found that the impact of ash and sulphur also generally increased with boiler age due to unavoidable changes in the quality of the coal supplies over time Analysis of data from most TVA units showed that the ash and moisture contents of the coal together with boiler age had the greatest effect on boiler efficiency (see later Figure 32 on page 86)
Availability on the other hand was found to be influenced mainly by ash and sulphur content of the coal although boiler age was still relevant Only outages attributed to equipment that were exposed to coal flue gas or ash were considered in the analysis Over the range of ash fired at TVA power stations (generally 12 to 14) the statistical relationship indicated that for a typical power station the outage hours
83
Computer models
may vary by 360 hy because of changes in ash content alone Likewise over the range of sulphur values for TVA power stations (generally 10 to 50) outage hours at a typical power station may vary by as much as 870 hy due to sulphur alone
Only maintenance costs for coal-related equipment were considered relevant for evaluating the operating cost variations when fIring different coals It was found that ash sulphur content of the coal and power station boiler age were the independent variables although it was determined eventually that age was not a signifIcant factor affecting maintenance costs so that was dropped from further consideration This is somewhat surprising since it is commonly accepted that maintenance costs for most types of equipment increase with equipment age However the effects of age may have been overshadowed by the effects of changes in coal quality with time especially increasing ash
It was reasoned that maintenance costs were not an instantaneous effect of coal quality but rather a result of firing the coal over a period of time To account for delayed or integrated effects over time (for example erosion) the ash and sulphur mass variables were allocated a lag coefficient of several months in the correlations It was reasoned that correlations which suggested that maintenance costs decreased as ash and sulphur mass increased could be regarded as unreasonable because they did not agree with practical experience Consequently these correlations were dropped from further consideration independent of their statistical significance The final correlations were selected as those which produced the highest correlation coefficient value The correlations for the nine separate TVA power stations are listed in Table 35 There appears to be no relationship between the correlation coefficient and the number of units at a power station In addition to these separate power station correlations an overall correlation was developed The optimum correlations were obtained when the lag coefficient for ash and sulphur were set at six and ten months respectively
The reports and reviews of the study stress that the correlations developed for TVA are not necessarily applicable to other power stations because of some significant limitations of the study (Barrett and others 1982 Heap and others 1984 Folsom and others 1986b) First the correlations are based on only one utility - TVA This utility
has its own design philosophy for selecting units its own maintenance and operation strategy and for some units studied there is only one design fuel a bituminous coal Also over the 19 years of data evaluated the TVA units fired only Eastern and mid-Western US coals Thus the range was limited Furthermore TVAs coal purchasing strategy changed such that the coal quality deteriorated to provide higher levels of ash and sulphur as time progressed Thus it was to be expected that the range in ash and sulphur coefficients in the resulting correlations may be at least partially attributable to age effects Overall the study was viewed as an advance in coal quality impact assessment as it had attempted to address the problem of performance prediction and highlighted the inadequacies of coal quality and performance data records
Other studies have been carried out in an attempt to improve and extend the TVA analytical approach Heap and others (1984) reported that EPRI conducted a statistical study to determine whether the TVA methodology could be applied to a more diverse and larger data set that is 25 utilities The study focused on equivalent availability only No attempt was made to separate coal related and other outages Instead a wide range of boiler design parameters were included in the correlation The analysis also utilised the same coal variables as the TVA study ash sulphur and nwisture
As discussed earlier in Section 634 EPRI used an alternative approach to analyse the data In addition to using the log of equivalent availability as the dependent variable and linear ash and sulphur terms based on the as-fired coal data EPRI also used the equivalent availability directly as the dependent variable and the difference between the actual and power station design values of the ash sulphur and moisture content of the fuel as the independent variables This approach makes the effects of coal changes additive terms rather than multiplicative terms as in the TVA approach and the correlation exhibits a relationship that reflected engineering judgement such that the availability of a power station is degraded by deviation from the design coal specification Heap and others (1984) compared the correlations developed by the TVA and EPRI studies by using them to evaluate the effects on a 1000 MWe unit (see Figure 31) The base availability loss due to coal related effects was taken as 97 Base case coal was the design coal and the effects of increasing ash and sulphur content by
Computer models
Correlation predicts maximum 55465 h
100
lt 806
vi Q) OJ co 605 0 -0 Q) range for 6 ro correlations of ~ 40 large unit groups Cii 0 u 0 Ul 200 0
97
0
Base 5 ash increase
8760 (full year)
8000
CfJ
6000 ~ c Q) OJ CIl 5
4000 ~ Q)
ro ~ Cii
2000 8
o
2 sulphur increase
Decreasing coal quality ---
Figure 31 Comparison of TVA and EPRI availability correlations to a 1000 MW boiler (Heap and others 1984)
5 and 2 respectively were calculated The cost of availability loss was taken as $1000000 The ranges of predictions for the TVA correlations based on the 15 groups of similar boilers the six larger groups and the entire database are shown in Figure 31 The correlations based on similar units cover a wide range Note that the large change in coal quality as represented by the changes in ash and sulphur contents in each case evaluated resulted in some of
the correlations predicting greater outage hours than are contained in a year At the other extreme some of the correlations predict that performance would improve with a decrease in coal quality The range of correlations for the larger groups of units was smaller and shows an increase in cost with decrease in coal quality as does the overall correlation The EPRI correlation predicts a greater cost due to coal degradation than the TVA study by a factor of two
A statistical study conducted by the National Economic Research Associates (NERA) USA and reported by Corio (1982) evaluated the impacts of coal quality on gross heat rate and availability based on the performance of 171 coal-fired boilers with capacities greater than 200 MW included in the Edison Electric Institute (EEl) database Only those units which had burned coal exclusively for three or more years were included in the study As with the TVA and EPRI study the coal quality data were limited to the ash sulphur and mnisture contents
The NERA study developed a single correlation with parameters to account for the differences in unit design Table 36 lists the specific variables and coefficients determined in the regression analysis
Both the TVA and NERA coefficients for the correlations are positive indicating that an increase in ash and moisture will increase gross heat rate (GHR) These trends cannot be compared with the TVA boiler efficiency trends exactly as the dependent variables are different Folsom and others (1986b) in a review of the two studies made an approximate comparison by examining the relative changes in the dependent variables (percentage) as ash and moisture content vary This is equivalent to neglecting the NERA GHR correlation The
Table 36 NERA study - gross heat rate correlation (Corio 1982)
Class Variable
Coal quality
Unit designoperation
Ash H2O
Vintage
Age
Output factor
Firing configuration
Stearn conditions
Feedwater pump
Oil firing
Constant
Type
Linear Linear
Linear
Linear
Linear
Switch
Switch
Switch
Switch
Independent
Year - woo
Years
Reciprocal
Cyclone = 1 Other = 0
Supercritical =1 Subcritical = 0
Shaft = 1 Other = 0 Stearn = 11565 Other = 0
Oil = 1
Coefficient
1107 1326
6770
4884
11517640
18485
-11953
7255
31563
273500
Output factor = capacity factor(service hoursperiod hours) expressed as
85
Computer models
150 150
125 125
gf2 0
(l) (l)10 1015 0
co~ sectco gt gt C C (l) ~1lJ (l)
7gtlJ lJ a5 075 ~ a5 07500Q Q (l) (l)~ lJ ~O lJ
lt0~ ~ (l) 0- (l)
OJ OJ~0c 05 c 05 co co
r r U U
025 025
O-JL------------------------------o o 2 4 6 8 10 o 2 4 6 8 10
Ash
Figure 32 Comparison of ash and H20 effects on boiler efficiency and gross heat rate (Folsom and others 1986b)
comparison made is shown in Figure 32 where the selected trends of the overall TVA correlation are plotted against the trends of the NERA correlation The trends for moisture were shown to be similar but the effect of ash was shown to be a factor of about 45 greater for the NERA GHR correlation
More recently the Illinois Power Company (Behnam-Giulani and others 1991) conducted a statistical study based on a database containing NERC and Utility Data Institute (UDI) USA data of 5600 unit-years for coal-frred units from 1982-88 They developed four statistical models to describe heat rate equivalent forced-outage rate operation and maintenance costs and capital addition costs In terms of coal quality impacts the models indicated that
heat rate increased by 127 and 74 kJlkWh for each percentage point increase in ash and moisture content respectively OampM costs increase by 005 with each percentage point increase in ash capital addition costs including costs due to wear and tear increased by 010 $kW of installed capacity with each percentage point increase in ash Capital addition costs were shown to decrease with increasing percentage sulphur content This is contrary to actual experience and is believed to be an erroneous result caused by inaccuracies in the database
Some of the models for example the heat rate model were reported to display good accuracy while some others for example the equivalent forced-outage model proved to be less accurate It was believed that further refinement to the data and methodologies was necessary and for this reason the
study results were recommended for secondary (not primary) computations
It should also be noted that as in the earlier statistical studies only the coal qualities ash moisture and sulphur content were considered in the correlations This highlights the difficulty of obtaining relevant and reliable coal data and corresponding power station data to form such correlations
To summarise statistical methodologies have been shown to have several disadvantages
engineering data are required The TVA study evaluated boiler efficiency only and the NERA study evaluated gross heat rate only The statistical correlations provide only a portion of the information required to evaluate net heat rate the full range of designs cannot be correlated If separate correlations are developed for each unit or group of similar units the accuracies of the correlations are reduced due to the smaller number of data points Increasing the number of independent variables included in the correlation also reduces the statistical importance of each variable concurrent variation If two variables change in sympathy it is difficult to determine the effects of each variable independently coal quality variables are incomplete All the studies primarily correlated performance with the coal ash sulphur and moisture contents only due to the limited availability of coal quality data However several other coal quality parameters can have significant impacts on heat rate These effects cannot be evaluated statistically based on the existing databases
86
Computer models
database accuracies The accuracies of the statistical correlations are limited in part by the accuracies of the input data It is difficult to obtain coal samples that are representative of a full year or even a month of firing database representativeness Statistical correlations are based on limited databases poor accuracy The statistical correlations have fairly wide error bands
multitude of results For example for any given unit in the TVA system boiler efficiency can be evaluated by the individual correlation capacity correlation fuel type correlation and overall correlation Each of these correlations predicts a different effect of ash and moisture content Also the trends of ash and moisture content effects on boiler efficiency and gross heat rate predicted by the four studies are somewhat different particularly for ash
COAL PROPERTIES POWER STATION DATA
Total moisture Unit size Proximate analysis Transport Ultimate analysis Pulverisation
Sulphur Fly ash collection Calorific value Emission limits
HGI Ash disposal Ash fusion temperature
Ash resistivity
HEAT amp MASS BALANCE
(Combustion drying steam production flue gas loss FGD reheat)
STREAM FLOW RATES ampCOMPOSITION
(coal flue gas fly ash)
COAL TRANSPORT HANDLING STOCKPILING
POWER STATION OPERATIONS
(pulverisation electrostatic precipitation flue gas desulphurisation ash disposal)
NET POWER PRODUCTION
OPERATING COSTS
(centskWh as a function of fob coal price)
Figure 33 Outline of CIVEC model operation (Meyers and Atkinson 1991)
87
Computer models
732 Systems engineering analysis CCI Valuation of Energy Coals (CIVEC) Meyers and Atkinson (1991) have reported on the
Several advanced systems engineering-based models have development of ClVEC a techno-economic model by been developed in Australia Canada and the USA in the last Carbon Consulting International Australia to evaluate coals decade The models can be used to predict the overall on the basis of their cost effectiveness in terms of net power coal-related generation cost and become ultimately the generated when applied to a specific generating system The singular basis of comparison for all coals being considered valuation is based on a reference coal whose properties and taking into account the coals effect on availability power fob price are well established station capacity operating costs maintenance costs and power station performance as well as the unit price of the Details of the coals to be studied and specific power station coal In general the method used by systems engineering parameters are entered into the model Heat and mass models is to apply values to coals being considered with balances are determined using these parameters so that the respect to reference coals whose properties fob prices and annual coal requirement may be established The cost effect performance are well established of the coal properties are determined for different sections of
the power station (see Figure 33) The fob price of the study Many models are now available to run on personal coal is subsequently adjusted to give a power production cost computers whereas in the past large main frame systems equivalent to that obtained with the reference coal This were required to carry out the necessary computations model assumes that the overall power station design will be
suitable for the coals studied in terms of parameters such as Several illustrations that use these techniques based on fouling slagging and NOx emissions predictive calculations and comparison with the performance of reference coals and others that utilise a combination of An illustration of the use of ClVEC to assess a suite of these and statistical techniques are presented below In each typical steaming coals from New Zealand Australia and case the coal qualities used and assumptions made in the USA relative to a reference coal was reported by Meyers and model are highlighted Atkinson (1991) The reference coal used in the study was
Table 37 CIVEC coal specifications input (Meyers and Atkinson 1991)
Base Coal A Coal B Coal C CoalD
Total moisture as 80 140 150 100 90
Total ballast as 224 178 228 220 211
Proximate analysis ad Moisture 22 90 70 25 60 Ash 153 40 85 130 125 Volatile matter 258 370 280 315 335 Fixed carbon 567 500 565 530 480
Total sulphur ad 035 025 035 080 110
Heating value MJkg (gross ad) 280 276 281 289 285 MJkg (gross ar) 264 261 256 267 256
Ultimate analysis daf Carbon 839 800 835 840 830 Hydrogen 50 55 45 50 60 Nitrogen 16 20 20 20 15 Oxygen 91 125 96 82 84 Sulphur 04 00 04 08 11
Hardgrove grindability index 49 50 60 50
Freight rate U5$t 1000 1000 1000 1000 1000
total moisture (as) + Ash (as)
Coal quality data were obtained by averaging numerous coal qualities from various mines Coal A Typical New Zealand steaming Coal B Typical low ash low sulphur Australian steaming Coal C Typical high ash high sulphur Australian steaming Coa1D Typical high ash high sulphur US steaming
88
Computer models
Table 38 CIVEC power station operational parameters (Meyers and Atkinson 1991)
Reference coal Coal A Coal B Coal C Coal D
Quantity Mtly 1453 1483 1503 1448 1409 Boiler efficiency 889 880 885 884 878 Mill-capacity factor 093 127 120 108 105 - Power drawn MW 289 216 222 268 268 SOz in flue gas (ppm) 531 363 528 1168 1636
(gGJ) 231 153 214 498 703 Required ESP efficiency 998 993 996 998 998 Residue Mtly 0228 0068 0134 0219 0235
see Table 37 for coal types
Table 39 CIVEC factors contribution to utilisation value (Meyers and Atkinson 1991)
Basis Base coal at 4085 US$t fob standard plant 90 capacity
Coal type Cost variations US$1t
2 3 4 5 6 Utilisation value US$t fob
A -080 -025 180 270 250 070 4750 B -135 -040 100 150 040 030 4230 C 015 005 000 005 -395 -235 3480 D 135 040 -025 -035 -585 -300 3315
1 Variation in coal tonnage to provide same energy input 2 Difference in transport and handling costs 3 Maintenance costs (induding overheads) 4 Disposal costs (including overheads) 25 US$1t waste 5 FOD costs (including overheads and limestone 20 US$t)
6 Power consumption difference - mainly pulverisers and FOD
also an Australian Hunter Valley thennal coal which was well established with Japanese power utilities Table 37 summarises the properties for each coal used in the study The power station modelled was a 500 MW unit with a capacity factor of 90 Ash collection was implemented with a cold side ESP Each coal type was valued under these base conditions and also for a range of residue disposal costs (0-50 US$t) and 100 flue gas scrubbing with limestone costs set at 20 US$t Table 38 summarises the power station operational parameters for each coal studied Table 39 shows the utilisation value resulting from the model together with the component contributions to coal value It should be noted that highest utilisation value implies the best coal for the system For example coal A whilst requiring a small additional annual tonnage as a result of a slightly lower heating value with respect to the reference coal (see Table 39 - minor penalties indicated under factors 1 and 2) actually compares favourably with the base coal case due to its very low ash level (low residue disposal costs) and lower than reference sulphur level (low FGD costs) The authors of the report pointed out that unit availability and the handleability characteristics of each coal have not been taken into account and that the costs of domestic transport were not included in the study In this respect the model does not take into account 100 of available coal quality impacts on power station perfonnance but can be considered as an improved least cost type model as described in Section 71
COALBUY In 1976 Carolina Power And Light Company (CPampL) developed a program called COALBUY which they use to calculate the operating expense incurred by utilising coal of a given quality at a selected generating unit The program essentially evaluates a series of six potential penalties
boiler efficiency auxiliary power requirements coal handling equipment maintenance ash handling equipment maintenance ash storage cost replacement power due to load limitations
The program contains an extensive database for each CPampL coal-fired generating unit together with detailed specifications for a reference coal Each offered coal is compared with the reference when calculating potential operating penalties Any penalties are added to the offer price of the coal to obtain a total cost of burning it The program is also used to predict the extent to which a unit might be load-limited when burning off-specification coal Details utilised for each unit are given in Table 40 The operating data listed are taken from actual performance tests at a series of load levels
COALBUY is in fact a sub-routine of CPampL s EVAL
89
Computer models
Table 40 Model input output data - COALBUY (Corson 1988)
Developer Coal input Generating unit input Key output
Carolina Higher heating value Net unit heat rate Operating penalties Power amp Light Grindability Base boiler efficiency Total cost of coal ($IMBtu) USA Proximate analysis Estimated boiler radiation losses Load limitation on generating unit capacity
Total sulphur content Ambient air temperature Identification of system causing the load limitation Purchase price including Ambient air humidity ratio Operating characteristics of boiler fans with
transport Stack gas temperature reference to coal and purchased coal Standard deviation of the Unburned carbon in fly ash Boiler efficiency losses and related parameters
variation in higher Unburned carbon in bottom ash - boiler efficiency heating value Carbon dioxide and oxygen in the - auxiliary power requirement
boiler gases entering and leaving the - coal handling equipment maintenance air heater - ash handling equipment maintenance
Monthly unit demand profiles - ash storage cost - replacement power
The operating data listed above are taken from actual boiler tests at a series of load levels
Also includes escalation factors for database cost factors
program which was developed to maintain files on quotations a coal buyer in making a detailed assessment of cost and and purchase orders to select suppliers of spot-market coal performance impacts of using a candidate coal in his power and to plan the distribution of long-term and spot-market station Model input and output parameters are summarised purchases throughout CPampLs generating system each month in Table 41 (Corson 1988)
The system establishes the coal rank (based on ASTM D388 Coal Quality Advisor (CQA) guidelines) ash type and determines ash fouling and The CQA expert system was developed by a joint utility slagging characteristics based on empirical slagging and (Houston Lighting amp Power Company (lllampP)) and fouling indexes It compares the provided analysis values architectengineering company (Stone and Webster) team against those expected for the reference of coal and coal ash (Arora and others 1989) Its intended application is to assist Arora and others (1989) describe the specific functions in
Table 41 Model input output data - Coal Quality Advisor (CQA) (Arora and others 1989)
Developer Coal input Generating unit input Key output
Houston Lighting amp Power Stone amp Webster Engineering Corporation USA
Proximate analysis Higher heating value Ultimate analysis Sulphur forms Ash mineral analysis Ash fusion temperature Trace elements Equilibrium moisture Quartz content Coal size Coal cost (fob)
Pulveriser horse power input Number of mills in service Plant capacity factor PA temperature (OF) amp pressure (lbft2mill) Primary air to fuel ratio (lbairnbfue1 )
Plan area heat release rate actual (Btuh ft2 x 106)
Boiler efficiency () Approximate net heat rate (BtukWh) Limestone cost Total change in OampM costs ($y) Annual fuel flow (ty) Differential power costs at equivalent coal flow (ty)
Intermediate output variables Maximum mill capacity (th) Required coal flow (Pph) Coal flow per mill (th) Percent base mill Super heater gas velocity (ftsec) Reheater gas velocity (ftlsec) Air flow (lbh) Excess air () Fuel flow (Pph) from boiler calculations Annual fuel flow 075 capacity factor Gas temperature - out CF) Bottom ash flow (Pph) Fly ash flow (Pph) Volumetric heat release (Btuh x 106)
Furnace exit gas temperature (OF) Limestone usage rate (th) Unburned carbon (lbslOO lbs coal)
90
Computer models
greater detail than can be discussed here It should be noted that due to the lack of a suitable database the basis of OampM cost methods was a percentage of equipment capital costs for each major power station component
The model has been validated for HLampP use It has been reported to have been used for (Arora and others 1989)
blending of up to five coals to a specific mix or to achieve a specified quality for the blend (that is sulphur ash heating value) classifying the coal (blend) to permit assessment in various components of the power station determination of empirical slagging and fouling indices evaluating the required performance against the given limits for the major components of the power station determination of OampM costs and the net heat rate change for a candidate coal relative to a given base coal unit No 8 at HLampP Parish power station but it can be configured to enable evaluation of other coal-fired units in the HLampP system with minor changes
The impact assessment for each of the systems is classified by severity level and displayed to the user with appropriate recommendations
Coal Quality Engineering Analysis Model (CQEA) From 1963 to the mid-1970s NYSEG have used a coal evaluation program to determine bonuses and penalties on each parameter of the coal offered by suppliers (Mancini and
others 1988) In 1975 the company commenced a two-year coal quality study to develop a method of fitting the existing program to each of the five NYSEG generating stations The model approach was changed to combine generating station engineering data with coal analysis data in a workable package for fuel evaluation engineering and economic analyses The result is the CQEA which has been used by NYSEG since 1977
Table 42 summarises the coal input data generating unit data required and the key and intermediate output variables The CQEA is calibrated to each units characteristics The generating unit input data are reported to be recalibrated annually
An illustration of the capability of the CQEA is shown in Figure 34 It compares the overall production cost for five different coals burned in one unit (unit 5 of Figure 34) as calculated by CQEA If only delivered cost is used as a measure to purchase coal then coal 3 would be the lowest cost However the overall cost of coal 1 is about 80 ckWh lower than the overall cost of coal 3 Similarly it is shown that paying the highest cost for high-quality coal 2 compared to coal 1 is not overall economically beneficial Also if the choice were among coals 2 4 and 5 - which are almost equal - the best quality would be chosen knowing the results of the CQEA These results have been verified by actual experience of the above coals in the units discussed
The CQEA system is used by two different groups within
Table 42 Model input output data - Coal Quality Engineering Analysis (CQEA) (Mancini and others 1988)
Developer Coal input Generating unit input Key output
NYSEG Delivered price USA Heat content
Proximate analysis Sulphur Ash softening temperature Grindability
Maximum gross capacity Hours operating at peak and average power Station service power Turbine heat rate Forced draft fan inlet temperature Stack exit gas temperature Carbon in ash and ash as fly ash versus
bottom ash moisture added to ash for dust-free disposal
Excess combustion air Base pulveriser capacity Pulveriser capacity correction factors for
fineness and grindability Radiation amp unaccounted boiler loss Fuel oil rate for low volume coal Minimum volatiles in coal without ignition oil
Average gross generation Ash collection capacities fly ash
and bottom ash Ash and scrubber sludge disposal cost Flue gas desulphuriser removal
efficiency and OampM costs
Cost of coal and oil burned Ash disposal costs Maintenance costs for coal and ash handling equipment Scrubber OampM and waste disposal costs Replacement power cost Net output MWh Replacement power MWh
Intermediate output variables Boiler efficiency () Total station service power () Net station heat rate (B tukWh) Percent utilisation of capacity Total Btu fired in coal and oil
Additional system data Maintenance wage rate Replacement power demand and energy charge Fuel oil heating value and price
91
Computer models
D coal quality - related costs 16shy D delivered coal cost
14 c 3 ~ 12ifgt U5 0 100
u c 0
OJ 8 D 2 0shyD 6 (j)
iii ~ 4 a OJ
u 2
0 Coal 1
MJkg 256 ash 210 moisture 70 sulphur 21
Coal 2 Coal 3 Coal 4 CoalS
302 263 284 270 120 203 127 177 40 53 72 70 27 12 26 20
Figure 34 CQEA evaluation of the impact of different coals on overall production costs of one unit (Mancini and others 1987)
NYSEG These are the Perfonnance and Fuel Engineering group which maintains the CQEA calibration factors for each unit and the Fossil Fuel Supply group which uses the
BOILER bull subcritical PC bull supercritical PC bull parallelseries backpass bull flue gas recirculation
COAL PREPARATION bull 41 mill offerings bull vertical spindle mills bull exhauster mills bull other
r
BOnOM ASH SYSTEM bull wet system
- jet pumps - centrifugal pumps
COAL HANDLING bull rail truck bargeship conveyor unloading bull emergency and normal stockout bull stacker reclaimers lowering wells
other reclaim systems bull ring granulator hammermill crushers
CQEA as a tool for evaluating coal purchase offers from coal producers (Mancini and others 1987)
Coal Quality Impact Model (CQIM) In 1985 Black amp Veatch a US architect-engineering group and EPRI worked together to develop a comprehensive computer program for predicting coal quality impacts The result was the Coal Quality Impact Model (CQIM) As of the end of 1991 112 copies had been distributed to 72 different utilities and six different companies or agencies Black amp Veatch has also sold the program to eight companies including four outside of the US Four additional sales to non-EPRI member companies are in their last stages of negotiations This is the most widely used systemsshyengineering model in the world
The role of CQIM is to quantify both perfonnance and cost impacts associated with changes in coal quality (Evans 1991 Stallard and Mehta 1991) The equipment types modelled by CQIM are summarised in Figure 35 As described earlier for other models CQIM evaluates alternative coals by comparing them with a reference or current coal supply It is also designed to consider station-specific design and operation characteristics on a component-by-component basis as well as the unit as a whole This allows the CQIM to identify potential system limitations (sources of derate)
The effort required to collect CQIM input data varies according to the background of the user the availability of data and the purpose of the evaluation CQIM contains a
AIR HEATERS bull bisectors bull trisectors
PARTICULATE REMOVAL bull hot ESP bull cold ESP bull fabric filter
1 FLY ASH HANDLING bull pressurisedbull vacuum
FD FANS bull axial bull centrifugal
~
~ PA FANS bull axial bull centrifugal bull coldhot bull exhuasters
Figure 35 Equipment types modelled by CQIM (Galluzzo and others 1987)
ID FANS bull axial bull centrifugal
SRUBBER ADDITIVE bull limestone bull lime bull none
to stack
t GAS REHEAT bull 5 alternatives
f---shy FGD SYSTEM bull wet limestone bull spray dryer --- bull none
WASTE DISPOSAL bull stabilised waste bull fixated waste bull evaporation ponds bull other
92
Computer models
Table 43 Model input output data - Coal Quality Impact Model (CQIM) (Stallard and others 1988 Stallard and Mehta 1991)
Developer Coal input Generating unit input Key output
EPRI amp Heating value Black amp Veach Ultimate analysis USA Moisture content
Ash content Chlorine content Sodium content in ash HOI Ash fusion temperatures Ash analysis Fuel cost Transport cost
Unit size (MW net) Capacity factor () Net power level Auxiliary power requirements Auxiliary equipment specifications
and capacities Hours of operation Net turbine heat rate (BtukWh) Excess air level () Boiler losses Boiler dimensions Soot blowing details Tube bank configurations Maximum heat input per plan area (MBtuJhft2)
Design FEGT Maximum allowable flue gas velocity Economiser
Economic data Replacement energy cost ($millkWh) Limestone cost ($ton) Salarymaintenance rate ($person-year)
Discount rate Replacement power cost Limestonellime cost Total annual fuel related costs Transport costs Escalation rates Overall unit performance data - slagging fouling and erosion potentials - equipment performance and derate info - maintenance availability data - calculated derate by system - generation cost summary page Sensitivity analysis Comparison tables Error warnings
feature for supplementing data provided by the user This default information is based on the data entered by the user the overall power station configuration the characteristics of the design coal and established equipment design practices Since default data can be substituted for most missing data the program can be run with limited input Of course the more actual data used the more comprehensive the predictions
Table 43 illustrates the type of data required for conducting an initial screening evaluation of coal quality CQIM contains programs for translating each major performance impact into a discrete cost component
During the course of the development of the CQIM model validation was carried out by means of a host utility program Initially 12 utilities worked with EPRI to develop case studies to validate the CQIM equipment performance models The CQIM performance and cost predictions were compared with historical data and actual utility operating experience Any discrepancies were used to modify the program modules and improve the overall predictive capability of the CQIM The case studies covered a wide range of US unit designs and US coals With the sale of the CQIM to international utilities this has prompted the development of CQIM International which will have facilities to convert input data utilising SI units
There are several examples of literature describing the application and validation of the CQIM (Galluzzo and others 1987 Boushka 1988 Stallard and others 1989 Cox and others 1990 Kehoe and others 1990 Afonso and Molino 1991 Giovanni and others 1991 Vitta and others 1991)
Coal Quality Expert (CQE) The US Department of Energy (DOE) selected the
development of the CQE in Round 1 of the Clean Coal Technology program The project initiated in 1990 and scheduled for completion in August 1994 will cost $217 million
The CQE computer system is designed to give utilities a tool that will predict the total cost of impact of coal quality on boiler performance maintenance operational costs and emissions
Figure 36 shows the major components of the CQE system The foundation for the CQE is EPRIs CQIM (see section on CQIM) More than 20 software models and databases including the CQIM a flue gas desulphurisation model a coal cleaning model a transport model and a new power station construction model will be integrated into a single tool to enable planners and engineers to examine the cost and effects of coal quality on each facet of power generation from the mine to the stack The expert system is intended to evaluate numerous options including various qualities of coal available transport methods and alternative emissions control strategies to determine the least expensive emission control strategy for a given power station
It is intended that the CQE will include cost estimating models for new and retrofit coal cleaning processes power production equipment and emissions control systems Individual models are to be made available as they are developed The first of these models the Acid Rain Advisor (ARA) has already been released (CQ Inc 1992) The ARA developed primarily to assist users in managing US Clean Air Act compliance evaluations can be used to quantify costs and emissions allowance needs for potential utility compliance strategies
A core part of the CQE program is extensive data gathering
93
Computer models
ENGINEERING AND ECONOMIC MODELS
bull Coal Quality Impact Model
bull coal cleaning cost model
bull flue gas desulphurisation
bull NOx emissions
ADVANCED USER INTERFACE
Integrated report and graphic capabilities
CQE ASSISTANCE Integrated applications
bull strategic planning
bull plant engineering
bull fuel procurement
bull environmental strategies
bull acid rain advisor
Figure 36 Major components of the CQE system (Evans 1991)
and analysis to validate the models and it is one of the largest efforts ever attempted to link pre-combustion combustion and post-combustion technologies to solve power station emission problems (Evans 1991) Samples of the various coals identified for the project are being collected at mines commercial cleaning plants and the six host power stations Extensive measurements of the performance of all ancillary equipment are taken during the field tests Moreover the project will generate considerable data from laboratory bench- and pilot-scale combustion tests using the same coals All the data will be used to develop and validate the CQE models including those that predict mill wear slagging and fouling precipitator performance flue gas particulate removal NOx formation and the flue gas desulphurisation performance
IMPACT Ugursal and others (1990) reported the development of a computer-based techno-economic model that can predict the impact of coal quality and other key variables on the busbar cost of electricity generated by new power stations The IMPACT model has been structured to focus on four major cost sectors of the coal-to-electricity chain (see Figure 1) This includes transport power station post-combustion particulate and SOz emission controls and residue disposal
Table 44 Ranges of selected coal-ash combustibility parameter that predict approximate classification of CF values (Ugursal and others 1990)
Incombustibility index RI1 Classification of CF values
lt21 21--43 43-75 gt75
94
low laquo017) medium (017-D34) high (034-D47) severe (gt047)
INFORMATION AND DATA BANKS
bull fLe1 sources
bull plant specifications
bull transport rates
bull waste handling
bull coal quality information systems
The impact of coal characteristics on power station performance is quantified in IMPACT as follows
steam cycle heat rate calculation assumes that the boiler is designed for the given coal and operates at design load boiler efficiency is evaluated using the heat loss method (see Section 632) A notable additional approach adopted to evaluate unburnt combustible losses in the calculation of efficiency includes an incombustible parameter Rh which is inversely proportional to the base-to-acid ratio of coal ash Rh is directly proportional to the amount of unburnt combustibles in the fly ash The amount of unburnt combustibles is expressed by CF and can be defined as
CF = [(flyash combustible$ (lb of fly ash formed)] (lb of coal feed)
The approximate ranges of CF values that corresponds to the incombustibility parameter ranges are given in Table 44 Once CF is determined from Table 44 the percentage of combustibles in the coal feed that is lost in the flue gas can be determined from
CFx 100 coal feed combustIbles = n1 1 d b tmiddotbl70coa lee com us 1 es
where the percentage of coal feed combustibles = 100 - ash - moisture with the ash and moisture content determined from proximate analysis of the coal
IMPACT utilises empirical correlations (developed by regression of data published by Bechtel Power Corporation (Holstein 1981)) between auxiliary power consumption and the sum of the ash and moisture contents of the coal for both subcritical and supercritical units (Ugursal and others 1990) availability values of 80 are assumed to apply to new
Computer models
Table 45 Model input output data - IMPACT (Ugursal and others 1990)
Developer Coal input Generating unit input Key output
University of Ultimate analysis () Plant capacity (MW) Levalised busbar cost of electricity Nova Scotia Ash content Unit type Annual operational cost Canada Ash composition () Steam generator efficiency () Capital costs
Heating value Steam cycle heat rate (BtulkWh) Annual coal consumption Cost of coal Flue gas exit temperature
Average load Equivalent availability Auxiliary equipment specifications Cost of limestone
power stations This assumption is adopted due to the lack of information available quantifying the impact of coal quality on the availability of power stations coal consumption and coal bum rate of a given power station are calculated using an energy balance based on the results obtained from the parameters above and the specified annual generation capacity annual ash and S02 generation are determined by a mass balance on the annual coal consumption rate and the ash and sulphur contents of the coal
Although this model has yet to be fully validated the authors carried out sensitivity analyses for a number of coals with various levels of ash and sulphur (Ugursal and others 1990) on a representative power station with two 500 MW units The input and output parameters of the coals and power station for the model are summarised in Table 45 Overall from the study it was concluded that the capital and operating costs of most of the sectors of the coal-to-electricity chain increase with increasing ash content of the coal fIred The authors emphasised that the findings apply for the particular conditions of the case the results might be quite different under other site specific conditions
Coal quality impact study model (CQI) Kemeny (1988) reported on work performed to develop a method of analysis using a combination of statistical and engineering methods which could be applied to any power station operating system The method adopted also developed a model that computes a power stations total coal-related generation cost on a specific coal It was developed initially for an Italian power station Fusina 3 to determine the economics of burning four different coals at the station
The method adopted for the calculation of availability assumed that planned outages were unaffected by coal quality whereas their effects on forced outages was the sole influence on availability Because of the random nature of equipment failures an analysis of forced outage rates was carried out statistically Historical coal usage data were correlated against historical outage data to see if there was a coal quality relationship For Fusina 3 power station the coal type was changed so frequently that data from a single unit were considered suffIcient for such a study The results of the availability analysis are shown graphically in Figure 37 A low correlation coefficient of 0447 was observed for the relationship indicating that there was a fairly high probability
that the apparent correlation between forced outages and ash was due to random scatter of data points and not to any cause-and-effect relationship In addition the large negative y-axis indicated that the regression equation may not have been accurate across the full range of ash values In light of the results demonstrated by this study it would appear that it would be more prudent not to include the results of the availability analysis in the coal quality impact model However the investigators believed that the regression analysis conformed to engineering expectations and because of the probabilistic nature of forced outages it was quite unlikely that with the amount of data available outages would correlate very strongly with coal quality Therefore the results of the availability analysis were included in this coal quality impact model
Coal-related operating costs accounted for in the model cover any cost not specifically covered by fuel costs At Fusina 3 for example these areas included the cost of sulphur for S03 conditioning and the cost of ash disposal Other areas might include the cost of fuel additives scrubber related costs cost of additional equipment The effects of coal quality on the cost of routine and emergency maintenance at the power station is most easily measured statistically in a similar way in which forced outages were correlated
01000
~ L 800 (j)
~
L0 600 81 Q) 0 OJ co 5 400 -0 Q)
0 0
~4() 82 00 200 u
83 o
40 60 80 100
Ash throughput kty
o not included in regression
Figure 37 Correlations of forced outage hours against ash throughput using the cal model (Kemeny 1988)
95
Computer models
Table 46 Assessment of four coals for Fusina unit 3 using the CQI model (Kemeny 1988)
Coals
South Africa Polish American
Low ash High ash
Coal characteristics High heating value MJkg [Btulb] Ash content Sulphur Moisture content Carbon content Ash resistivity ohmcm x E13
Coal cost $GJ [$MMBtu]
Results from model Boiler efficiency Availability US$y Capacity - ESP limit - Auxiliary power
Fuel costs - coal - supplementary
OampM costs - maintenance - flue gas conditioning - ash disposal
Totals
2625 [11291] 1339 038 830
6474 375
153 [161]
8890 3905122
1764549 3765822
25565882 3450848
2806626 24916
458876
4172640
2707 [11639] 1226 063 780
6796 500
163 [172]
8889 3204389
1514442 3817118
27980093 3059766
2538408 9051
330618
424453886
3012 [12950] 742 081 720
7433 500
177 [187]
8931 336355
357460 4033183
33180022 1625800
1440618 o
175209
40798228
2830 [12173] 1152 075 710
7033 500
177 [187]
8886
2459658
2325523 o
228820
44008125
Without going into power station details as this is described elsewhere (Kemeny 1988) an illustration of the type of results produced by the model of the comparison of four coals from Poland South Africa and the USA is given in Table 46
As in the case of other similar models the value of the total coal-related production cost in the cost summary is just an indicator it is neither a calculation nor a prediction of the actual generating cost The number in this model does not include costs such as maintenance costs for non-coal-related systems However it can be used for comparative purposes Quite simply the coal which gives the lowest production cost is the most economical
More briefly other models that have been reported in the literature include
Waters (1987) reported the development of a computerised mathematical model known as ECUMEC Data taken from the model subroutines are used to calculate the power cost for example at the busbar including the cost of coal Once again the method used to assign an economic value to a coal is to select a base coal or yardstick coal to which a coal price (fob) can be ascribed The equivalent value of another coal is that price (fob) which gives the same power production cost as the base coal Waters (1987) demonstrated the
capability of the model by considering the effect of some coal properties such as sulphur ash and moisture content on the equivalent coal value in a 500 MW power station The base coal was a 15 ash Australian Hunter Valley coal The coal price (fob) was shown to be very dependent upon ash with a 5 ash coal worth approximately US$745 more per tonne than a 15 ash coal (based on 1987 prices) The effect of moisture on equivalent coal price is similar to ash but not as marked It was shown using the model that a 05 increase in sulphur content had a much greater effect on coal value than a 5 increase in ash content This was because the capital and operating costs associated with FGD to meet air quality requirements were very high a program developed by Southern Company Services USA to help estimate the benefits from cleaning coals The constituents of coal that were found to affect the cost factors were primarily ash moisture sulphur and carbon content (Blake 1988) the Consol Coal QualityPower Cost model which was used by Deiuliis and others (1991) to evaluate the performance of six US regional coals in a typical 500 MW pulverised coal-fired unit The study was focused on developing a cleanliness factor for model relating to heat flux and soot blower effectiveness data obtained from pilot combustion tests the Coal Utilisation Cost Model which utilises a three-step modelling approach-statistical analysis of
96
Computer models
historical data (source NERC) development of an engineering algorithms and evaluated cost calculations based on the algorithm results (Nadgauda and Hathaway 1990)
733 Integrated site models
With further advancements in computer and sensor technology in the last ten years integrated site models are being developed that allow the integration of information from unit models systems perfonnance and other models directly into the control room data system These programs allow the continuous monitoring of for example selected coal properties such as ash moisture and sulphur furnace and convective pass deposits and can define overall heat rates based on these continuous measurements taken from the unit (Elliott 1991) The diagnostics packages can also include a routine for predicting the implementation and impact of operating practices on heat rate (Nurick 1988 Alder and others 1992)
Smith (1991) and Reinschmidt (1991) have reviewed the wider application of integrated control systems from individual component control to full automation of the power
Coal quality COAL MANAGEMENT
as a function MODULEof time at mills
Coal quality collection and assessment
station and the new computer technologies that are being applied such as neural network approaches that processes input data without identification of particular algorithms connecting the output results with the input data and fuzzy logic An example of this application is the C-QUEL system
Coal quality evaluation system (C-QUEL) Mitas and others (1991) have reported on the current development of a comprehensive software system C-QUEL that will allow utilities to use on-line analysers to try to solve or mitigate existing coal-related problems This will be accomplished by the C-QUEL system by providing information about coal quality before it is burned predict potential effects on operation and provide recommendations of control actions which can be taken to adjust coal quality andor improve power station response to quality changes The use of on-line coal analysers has been reviewed by Makansi (1989) and Kirchner (1991)
C-QUEL is a suite of computer programs which can be used as a basis for control of various processes in a power station Figure 38 shows a schematic of the structure of the system Appropriate control actions will be determined based on a wide variety of information gathered by the operator on-line
ON-LINE PERFORMANCE MONITORING SYSTEM
Equipment status Current performance
Load demand
ON-LINE COAL ANALYSER
SUPERVISORY CONTROL MODULE
COAL QUALITY CONTROLACTION
RELATIONSHIP MODULES
Coal data logging
Monitor CQ and equipment modify operation to
meet goals
DATA ARCHIVE AND TRENDING
USER INTERFACE
EPRI COAL QUALITY IMPACT MODEL
Annunciation Predicted performance Interactive dialogue Information retrieval
Figure 38 Schematic showing the structure of the e-aUEL system (Mitas and others 1991)
97
Computer models
coal analyser real-time station data on-line performance calculations equipment performance predictions and coal flow models The EPRI Coal Quality Impact Model (CQIM) will be incorporated into C-QUEL to provide the prediction capability for the performance of all major power station systems directly impacted by coal quality Operational strategies as a result of expected unit performance will be evaluated by C-QUEL and provided to the operator These strategies will take into account the current and future unit generating requirements as well as cost information associated with each possible action Specific control recommendations and supporting information are presented to the power station operators
Figure 39 shows a simplified case as an example of the use of C-QUEL in which the primary goal is to maximise electrical generation from a base load power station Figure 39a depicts the sequence of events that can be expected at a particular point in time The operator is unaware that a change in coal quality has occurred until a
a) Without C-QUEL
Ash and moisture content have
increased
drop in load is detected In the second scenario Figure 39b the goal of maximising electrical production has been fed into the C-QUEL supervisory module Since decreased mill capacity will have a direct effect on generation this information together with a recommended course of action is given to the operator and allows him enough time to make the proposed adjustments before load production is affected Because of detection of the higher moisture and ash content of the coal supply by the on-line coal analyser a decrease in mill capacity was predicted To prevent any load reduction the operator would be instructed by the system to bring another mill into operation
The project team for development of the C-QUEL system consists of two host US utilities - Oklahoma Gas and Electric (OGampE) and Pennsylvania Electric (penelec) two engineering contractors - Black amp Veatch and Praxis Engineers and EPRI Demonstration of the system will take place at OGampEs Muskogee power station and the Penelec-operated Conemaugh plant OGampEs Muskogee
I I
Only two pulverisers are on-line consistent with the requirements
of the previous coal quality
I I I L_
On
Electrical production has
dropped
Operator determines decreased pulveriser capacity has caused the load drop and brings another pulveriser on-line
b) With C-QUEL Pulveriser module predicts Other controlaction modules decreased pulveriser capacity
Analyser detects Iincrease in coal ash and moisture conten t I
III I +0bull
Goalmaximise output
-
1 Supervisory module evaluates this information relative to operational
t--- goals and constraints and information from other modules
I
A message notifies the
Pulveriser 2
operator of potential generation loss and the need for an additional pulveriser
1-~e~C 1
I I L_
Operator brings another pulveriser on-line before the high ashhigh moisture coal is fed to the fuel preparation system Maximum electrical production is successfully maintained
Figure 39 Comparison of the operations with and without the use of e-aUEL (Mitas and others 1991)
98
power station fires primarily western low-sulphur coal that is currently blended with more expensive higher sulphur Oklahoma coal which also has a higher heating value on a 10 by heating value basis The station must also meet a strict SOz emission limit OGampE has installed an on-line analyser - PGNAA elemental analyser - that will provide data to assist in blending and feeding An elemental analyser has also been installed at the Conemaugh power station Initial data gathering will focus on the Muskogee power station (Mitas and others 1991)
Couch (1991) has also reviewed the influence of integrated computer control and modelling on coal preparation plant
74 Comments The studies described above demonstrate the feasibility of developing various quantitative relationships which are essential for optimum planning and operation of generating units Table 47 summarises the capabilities of the models described in this chapter Many of the results are based on data and methodologies which still require further refinement
When considering the two major techniques for assessing power station performance that is statistical and engineering analysis modelling a weak link with both approaches is within the coal specification parameters used in the correlations
Table 47 Summary of model types and capabilities
Computer models
For the purpose of selecting an economically attractive coal it is important to determine heat rate effects due to coal quality as accurately as possible In their review of statistical and engineering based relationships Folsom and others (1986b) did not believe that the correlations from statistical studies were close enough to be useful for this purpose Consequently the use of engineering correlations and experience to evaluate heat rate impacts was highlighted as the preferred procedure
Engineering based models have their critics also Many utilities apply least cost models for purchasing coals and component models and some acknowledge the benefits of expert unit or integrated models Others remain sceptical over the capability of devising a truly representative model of the coal combustion process Some of the reasons given for this scepticism include
the present methods that describe coal properties require substantial refinement for use in the models as they are not adequate for predictingaccounting for unit performance a belief that coal blending solutions based on pragmatism and simple empirical methods are more appropriate providing a here-and-now solution a belief that processes such as fouling and slagging and mill performance cannot be accurately modelled whilst the basic mechanisms are not clearly understood
Model type Modelling capabilities Developed by Application Comments Model name Assessmentcountry
Heat Capacity Avail- Maintenance Other of origin
rate costs ability costs
Least cost coal coal blend model
Least cost fuel system total fuel cost architectengineer buyer manualAustralia ICVM total fuel cost research organisation buyer manualAustralia Steam coal blending plan - total fuel cost supplier buyer manuallUSA Perfectblend total fuel cost research organisation buyer manuallUSA
Single component model Boiler models --I --I research organisation operator computerintershyand others utilityequip manufacturer national
Unit model Statistical
TVA study --I --I --I research organisationutility operator manualUSA EPR study --I --I --I research organisationutility operator manuallUSA NERA srudy --I --I research organisation operator manuallUSA PC study --I --I --I capital costs utility operator manuallUSA
Engineering ClVEC --I --I estimated total fuel costs research organisation buyer computerAustralia COALBUY --I --I --I --I total fuel costs utility buyer computerlUSA CQA --I --I --I estimated total fuel costs architect engineerutility buyeroperator computerlUSA CQEA --I --I --I coalash handling total fuel costs utility buyeroperator manuallUSA CQIM --I --I --I --I total fuel costs architect engineerutility supplierlbuyer computerlUSAUK
operator CQE --I --I --I --I total fuel costs architect engineerutility buyeroperator computerlUSA IMPACT --I --I --I --I total fuel costs research organisation buyeroperator computerCanada CQI --I --I --I statistical evaluation total fuel costs research organisationutility buyersoperator computerlUSA
Site model C-QUEL --I --I --I --I total fuel costs architect engineerutility operator computerlUSA
total fuel costs for engineering models refers to the total fuel-related production costs in terms of the price of electricity at the busbar
99
Computer models
new advanced boiler configurations such as low NOx
combustion regimes increase the complexity of boiler models many of the models have not been applied to a wide range of international coals and therefore have not received adequate validation
The analysis approach adopted by many of the unit models available can vary in complexity such that a form of quantitative predictability can be produced to a reasonable or to what may be deemed as a high level The lower level of prediction capability has been perceived by critics to produce too general a fmding In contrast the higher level may require more detailed unit specific information than a utility may have readily available such that special provisions would have to be made in order to collect the necessary data (Johnson and others 1991) This is known to be time consuming and is perceived by some operators to detract from the main utility priority that is to produce electricity Others believe that the models incorporate performance measurement errors that may compound to reduce the effectiveness of the model and make it only useful for comparing coals that show a wide range of coal property values
Many of the model descriptions have cited the beneficial role of the model in fuels purchasing It is considered that when models are used in such a manner they could become an improved means of communication between supplier buyer and user as they can ultimately aid the purchase of an economical coal of adequate quality for a particular power station The advantages of having the ability to assign an overall cost to a coal particularly in terms of its impact on component and overall power station performance could prove to be of technical and financial benefit to the utility in helping to justify supplier buyer or operator policies such as coal cleaning blending power station retrofitting or purchase of replacement energy to the advantage of the utility
In general however operators remain reluctant to move toward a predictive approach to coal quality impacts in preference to reliance on post mortem type remedies In the future integrated computer models such as C-QUEL may prove more acceptable when they can provide real time cause and effect information and advice on how to remedy problem situations as soon as they occur and can be seen to rely on dependable input data
100
8 Conclusions
Fuels purchasing and management presents an important opportunity for utilities to control costs It is also recognised that final judgements on coal selection often require a trade-off between these costs and qualitative factors such as diversity of supply reliability control of emissions for environmental reasons balance of trade and currency availabilities The contribution of coal to the cost of electricity extends far beyond the purchase price of the fuel Over the last fifteen years it has become generally accepted by coal-fired power station operators that the capacity availability and cost of operation of each individual component of the power station are materially affected by the quality of coal fed to it To generate power at least cost it is important to evaluate the overall total cost associated with each coal for a particular power station
The principal coal properties that were found to cause greatest concern to operators include
ash content and composition heating value sulphur content moisture content grindability volatile matter content
Enforcement of environmental legislation has resulted in the elevation of total sulphur content to a key position in the specification of coal along with total ash moisture and heating value Table 48 summarises the effects of these properties and other coal characteristics that are used as coal specifications for combustion on component and overall power station performance
Little has changed over the years in the way that coal is assessed and selected for combustion Operators continue to use quality parameters in their specifications that were mostly developed for coal using processes other than direct combustion Whilst many empirical relationships have been
established between coal specifications and certain component and plant performance indicators the coal characterisation tests themselves have been shown to have serious shortcomings and in some cases do not adequately reflect the process conditions For example
coal composition measurements cannot be used to explain the problems of dusting flowability freezing and oxidation that can occur during coal handling mill capacities for lower rank coals or coal blends are difficult to evaluate using existing grindability correlations combustion characteristics including flame shape stability and char burnout cannot be evaluated accurately based on standard coal composition tests the correlations that have been developed for slagging and fouling are inadequate there is considerable disagreement as to the best method of measuring fly ash resistivity there is no correlation between coal composition and fly ash fineness there is no adequate means to predict NOx emissions
Because the procurement specifications are based on tests which do not relate well to actual practice there is still a need for expensive large scale test burns to confirm suitability
Coal quality affects a wide variety of plant components and ultimately the overall station performance that is total system capacity availability maintenance costs substitute fuel costs plant replacement costs and the final cost of electricity There is a growing awareness that coal suppliers should take more responsibility with respect to determining the quality of coal made available on the market Suppliers that best understand the consumers fuel quality concerns prove to be the most successful in securing contracts and maintaining market share
Plant operators and other organisations are working to
101
Conclusions
Table 48 Summarymiddot of the impacts of coal quality on power station performance
Coal specification Power station component performance Overall power station performance
Environmental control
l u l
tl a
B
amp ~ o(l co S c r
~
~
E l
aI
0
~ C
co
~ B en
c= E co c E c ~
c= E 5 0 co c ~
U - 0 U
c au
~ u
lt5i if
c= ~ ~ amp 0 j c a u
6 en
c= sect l 0 0 1sect a u gtlt
0 Z
1(j at
4-lt a
E c
l 0
tl sect 0 ~ l
QI
0 ~
U
B ~ lta r
c= E S 0
U
sect c B c
ca ~
~ ~ ca gtlt
Ash content increase decrease
Heating value increase decrease
Sulphur content increase decrease
Moisture increase decrease
Hardgrove grindability index increase decrease
Volatile matter increase decrease
Ash fusion temperature increase decrease
Ash resistivity increase decrease
Sodium content increase decrease
Chlorine content increase decrease
Fuel ratio increase decrease
Free swelling index increase decrease
Size consist increase decrease
compiled from observations from literature and the lEA Coal Research survey worsened (or decreased for components marked ) improved (or increased for components marked )
102
improve their understanding of how their equipment or systems respond to particular coals and coal blends but the lack of data for appropriate direct correlations of plant performance and coal behaviour has hindered the development of true prediction capability Until these relationships have been developed and proven respecting differences in boiler design coal buyers will continue to operate at a disadvantage when selecting new sources of coal
With the advances that have been made in computer technology there has been some success in the development of computer models that demonstrate the feasibility of developing various quantitative relationships for optimum planning and operation of generating units Many utilities use least cost models for purchasing coals that have no performance prediction capability Many use component models that supply fundamental data of plant component performance There is a growing number of utilities that are adopting expert unit or integrated models that are being developed Others have shown scepticism over the capability of devising a truly representative model of a coal combustion plant for reasons that include the following
a belief that coal blending solutions based on pragmatism and simple empirical methods are more appropriate providing a here-and-now solution a belief that many of the coal quality impacts cannot be accurately modelled as the basic mechanisms are still not fully understood new advanced boiler configurations such as low NOx
combustion regimes increase the complexity of boiler models many of the models have not been applied to a wide range of international coals and therefore have not received adequate validation the present methods that describe coal properties require substantial refinement as used in the models as they have been found to be inadequate in many cases for predictingaccounting for unit performance
Many of the shortcomings in the traditional coal characterisation tests that form the basis for specifications for
Conclusions
combustion have been exposed by the efforts to develop computer models and their improved data processing Prior to their application manual comparisons provided only limited indications of coal behaviour and in many cases precluded the ability to attach a price to a change in performance as a result of a change in coal quality Development of the models has also initiated extensive validation exercises to acquire the necessary performance data In addition coal characterisation tests are being reassessed It is recognised that an overly conservative approach to the development and adoption of new techniques as characterisation tests which may more realistically reflect the conditions extant to coal combustion has also hindered progress into acquiring true predictive capability
Specific needs that have been identified during the course of this review include
the need to develop an internationally acceptable method(s) of defining coal characteristics so plant performance can be predicted more effectively specific relationships between boiler performance in particular for advanced boiler configurations such as low NOx combustion regimes and coal quality need to be developed For example the specific impact of sulphur chlorine sodium overall ash content and coal rank (or reactivity) on carbon burnout slagging fouling corrosion and abrasion all need to be established economic parameters to measure the impact of plant performance on the cost of electricity need to be established and agreed upon in the electric utility industry The accounting systems of many utilities are not designed to easily identify the costs associated with coal quality impacts These organisations need to review their methods particularly if they intend to take advantage of new developing tools that are available such as expert computer models
Successful resolution of these issues is fundamental to achieving optimum use of coal as pulverised fuel in utility power stations
103
9 References
Abbott M F Bilonick R A (1992) Applied heat flux and soot blower effectiveness measurements in the CONSOL pilot and research combustors In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast R USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 471-497 (1992) Afonso R F Molino N M (1991) Compliance coal and low volatile bituminous coal testing at New England power In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 421-436 (JulI991) Ainsworth C C Rai D (1987) Chemical characterization of fossil fuel combustion wastes EPRI-EA-5321 Palo Alto CA USA EPRI Technical Information Services 136 pp (Sep 1987) Akers D J Norton G A Buttermore W H Markuszewski R (1989) Trace elements in coal In Trace elements in coal and coal wastes EPRI-GS-6575 Palo Alto CA USA EPRI Technical Information Services pp 21-28 (Dec 1989) Alder G Klein K Rettberg L (1992) Optimization of automated sootblowing through on-line boiler heat balance modeling In Power-Gen 91 Tampa R USA 4-6 Dec 1991 Houston TX USA PennWell Conferences and Exhibitions pp 1863-1881 (1992) Allman W P (1987) Steam coal blending planning and economic analysis facilitated by computer-generated tables Journal of Coal Quality 6 (1) 19-22 (Jan 1987) Allman W P (1991) A cost-minimization planning model for the coal sourcingtransport network problem emphasizing environmental emission restrictions Energy Systems and Policy 15 (1) 65-73 (Jan-Mar 1991) Anson D (1988) Interpretation and use of empirical slagging criteria In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 181-1101 (1988) Arnold B J (1988) Workshop on defining coal handleability
its cost impact and control Palo Alto CA USA EPRI Technical Information Services 128 pp (Nov 1988) Arnold B J (1991) Effect of chemical and physical coal properties on handling behaviour Mining Engineering 43 (2) 228-231 (Feb 1991) Arnold B J OConnor D C (1992) The effect of coal quality on coal handling Paper presented at Impact of coal quality on power plant peljormance La Jolla CA USA 25-27 Aug 1992 Arnold P C (1990) Storage systems for coal the requirement for implementation of modern design techniques In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 40-46 (Jun 1990) Arora B R Racine J P Sirois R H Finn G A Hanna R S Kern E E Buffinton A L (1989) Coal quality advisor for coal buyer Paper presented at Expert systems applications for the electric power industry Orlando R USA 5-8 Jun 1989 Babcock amp Wilcox (1978) Steam its generation and use (39th edition) New York NY USA Babcock amp Wilcox Company vp (1978) Bailey J G Tate A Diessel C F K Wall T F (1990) A char morphology system with applications to coal combustion Fuel 69 (2) 225-239 (Feb 1990) Baker J W Bennett P Conroy A Naylor P Smith G B (1987) Utilization characteristics of Australian steaming coals in overseas power stations In Coal Power 87 The AUSIMM annual conference in association with the Mining and Metallurgical Institute ofJapan (MMlJ) Newcastle NSW Australia May 1987 Parkville Vic Australia The Australasian Institute of Mining and Metallurgy pp 303-311 (May 1987) Baker J W Holcombe D (1988a) Use of the drift velocity apparatus to determine electrostatic precipitation performance In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp N13-NI6 (1988)
104
References
Baker J W Holcombe D (1988b) Electrostatic precipitations and fabric collection In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp L121-L1239 (1988) Balling L Hein D (1989) DeNOx catalytic converters for various types of furnaces and fuels - development testing operation In 1989 Symposium on stationary combustion nitrogen oxide control San Francisco CA USA 6-9 Mar 1989 EPRI-GS-6423-vol 2 Palo Alto CA USA EPRI Technical Infonnation Services vol 2 pp 7A27-7A40 (JuI1989) Barrett R E (1990) Designing boilers to avoid slagging fouling Power 134 (2) 41-45 (Feb 1990) Barrett R E Holt E C Jr Mack G A Frank R L (1983) Power plant perfonnance Assessing the impact of coal quality In SME-AIME annual meeting Atlanta GA USA 6-10 Mar 1983 Littleton CO USA Society of Mining Engineers of AIME pp 1-12 (Mar 1983) Barrett R E Mack G A Holt E C Jr (1982) Examining relationships between coal characteristics and the perfonnance of IVA power plants TVA10PIEDT-8312 Columbus OH USA Batelle-Columbus 254 pp (Sep 1982) Barrett R E Tuckfield R C (1988) Correlation of slaggingfouling from utility operating data In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 163-180 (1988) Bauver W P Bianca J D Fishburn J D (1984) Characterization of erosion of heat transfer tubes in coal fired power plants ASME Paper 84-JPGC-F4-3 New York NY USA American Society of Mechanical Engineers vp (1984) Baxter L L (1992) Combustion model predicts properties of coal ash deposits Sandia Science News 27 (6) 4 (Jun 1992) Beer J M SarorllD A F Barta L E (1992) From properties of coal mineral matter to deposition tendencies of fly ash - a modelling route Journal of the Institute of Energy 65 (462) 55-62 (Mar 1992) Behnam-Guilani K Hickey G L Hipple M J (1991) Statistical models for predicting coal-fired generating unit costs and performance Proceedings of the American Power Conference 53 888-892 (1991) Bend S L (1989) Coal characterisation and combustion PhD Thesis Newcastle upon Tyne UK University of Newcastle upon Tyne 189 pp (Nov 1989) Bennett R Fogel W Aloia P (1988) Wet fuel handling A program to minimize plugging In Defining coal handleability Its cost impact and control Lexington KY USA 30 Apr-l May 1987 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Information Services pp 41-410 (Nov 1988) Benson S A Steadman E N Kalmanovitch D P (1988) Studies of the fonnation of alkali and alkaline earth aluminosilicates during coal combustion using a laboratory scale furnace In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 31-312 (1988) Berkowitz N (1985) The methods of coal chemistry In The chemistry of coal Amsterdam the Netherlands Elsevier Science Publishers pp 33-102 (1985)
Berkowitz N (1989) Atmospheric oxidation of coal In Sample selection aging and reactivity of coal New York NY USA John Wiley and Sons pp 217-253 (1989) Blake M W (1988) Estimating benefits from cleaning coals In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 667-676 (1988) Blake M W Robin T T (1982) Coal quality influence on operating plant cost Paper presented at Ninth annual engineering conference on reliability for the electric power industry Hershey PA USA 16-19 Jun 1982 Blondin J Girardeau M Nomine M (1988) Two simple tests for the assessment of wet fine coal handleability In Industrial practice offine coal processing KIimpel R R Luckie P T (eds) Littleton CO USA SME-AIME pp 253-255 (1988) Blough J L Kihara S Wolowodiuk W (1988) Effects of coal properties on superheater corrosion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 235-253 (1988) Boley D G (1984) Calcium chloride A new solution for frozen coal Power 128 (1) 67-69 (Jan 1984) Borio R W Levasseur A A (1986) Coal ash deposition in boilers ACS Symposium Series 103 288-302 (1986) Borio R W Levasseur A A Chow 0 K Miemiec L S (1992) Ash deposition a boiler manufacturers perspective In Engineering Foundation conference on inorganic transfonnations and ash deposition during combustion Palm Coast FL USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 95-120 (1992) Borio R W Plumley A L Sylvester W R (1978) Improved thennal efficiency by controlling of factors affecting metal wastage in pulverized coal-fired steam generators In Ash deposits and corrosion due to impurities in combustion gases Bryers R W (ed) Washington DC USA Hemisphere Publishing pp 163-183 (1978) Boushka M (1988) Application of EPRIs coal quality impact model In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Infonnation Services pp AI-A20 (May 1988) Boyd R K Kent J H (1986) Three-dimensional furnace computer modelling In Twentyjirst symposium (international) on combustion Munich Federal Republic of Gennany 3 Aug 1986 Pittsburgh PA USA The Combustion Institute pp 265-274 (1986) Boyd R K Lowe A (1988) Three-dimensional modeling of a pulverised-coal fired utility furnace In Coal combustion science and technology of industrial and utility application Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 165-172 (1988) Boyd R K Lowe A (1992) Sydney NSW Australia Pacific Power Services Personal communication (Sep 1992) Bretz E A (1991a) Specifying powerplant fuels and combustion systems Electrical World 205 (2) 40-45 (Feb 1991) Bretz E A (1991b) Innovation key to finding unusual ash-disposal options Electrical World 205 (7) 56-57 (Jul 1991) Brooks K Glasser D (1986) A simplified model of
105
References
spontaneous combustion in coal stockpiles Fuel 65 (8) 1035-1041 (Jug 1986) Brooks S Meadowcroft DB Morris C W Flatley T A (1983) J laboratory evaluation of alloys potentially resistant to furnace wall corrosion In Corrosion resistant materials in coal conversion systems Meadowcroft D B Manning M S (eds) London UK Jpplied Science Publishers pp 121-135 (1983) Brown K (1985) Sampling testing and analysis of coals In An intensive course on the characterisation of steaming coals Newcastle NSW Justralia 20-22 May 1985 Newcastle NSW Justralia University of Newcastle Institute of Coal Research pp 21-239 (May 1985) Bryers R W (1992) Fireside behaviour of mineral impurities in fuels from Marchwood 1963 to the Sheraton Palm Coast 1992 In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USJ 10-15 Mar 1991 New York NY USJ Jmerican Society of Mechanical Engineers pp 3-70 (1992) Bull D L (1992) Jsh deposition a utility perspective In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USJ 10-15 Mar 1991 New York NY USJ Jmerican Society of Mechanical Engineers pp 121-132 (1992) Burchill P (1987) Some observations on the variation of nitrogen content and functionality with coal rank In 1987 International conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Jmsterdam the Netherlands Elsevier Science Publishing Company pp 5-8 (1987) Byrne G J Juniper L A (1987) Utilization characteristics of Justralian steaming coals in overseas power stations In Coal Power 87 The AUSIMM annual conference in association with the Mining and Metallurgical Institute of Japan (MMIJ) Newcastle NSW Justralia May 1987 Parkville Vic Justralia The Justralasian Institute of Mining and Metallurgy pp 293-301 (May 1987) Cacka H Lang I Fabianova D (1989) Vliv prvkoveho slozeni uhli HDBS a jejich THF extraktu na nizkoteplotni oxidaci uhli (Effects of elementary composition of coal from the Sokolov brown coal basin and its tetrahydrofuran extracts on low-temperature oxidation) In 2 celostatni konference Samovolne vmecovani uhli v teoril a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSJV pp 1-14 (1989) Cagnetta A C Zelensky G (1983) Coal qualitydesigning a power plant for a wide range or dedicated coal supply In Fifth international coal utilization exhibition and conference Houston TX USJ 7-9 Dec 1982 Houston TX US1 EBJSCO Services Inc pp 3-14 (Dec 1983) Calarco V Bennett D (1989) United States acid rain legislation implications for the international coal markets In CoalTrans 89 sixth international coal trade and transportation conference London UK 16-18 Oct 1989 Worcester Park UK CoalTrans Conferences Ltd vp (1989) Carmichael R L (1987) Factors influencing selection of coals for existing power plants In International symposium on mining technology and science Xuzhou China 18 Sep 1985 Beijing China China Coal Industry Publishing House pp 1365-1371 (1987)
Carpenter A (1988) Coal classification IEJCR12 London UK IEJ Coal Research 104 pp (Oct 1988) Cerkanowicz A E Liskowitz J W Wecharatana M (1991) Potential model of the energy manufacturing process to predict properties of fly-ash as it relates to utilization In Eighth annual international Pittsburgh coal conference Coal - energy and the environment Pittsburgh PJ USJ 14-18 Oct 1991 Greenburg PA USJ Pittsburgh Coal Conference pp 839-842 (1991) Chamberlain R A C Hall D A (1973) The liability of coals to spontaneous combustion Colliery Guardian 221 (2) 65 (Feb 1973) Chen J Y Harris D J Smith I W Zhang D K Wall T F Stanmore B R (1991) Combustion reactivity of coals shyevaluation of laboratory techniques In 1991 international conference on coal science - proceedings Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 303-306 (Sep 1991) Chen X D (1991) The effect of moisture content on the spontaneous ignition process - a review In Proceedings of the fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Jssociation of New Zealand vol 2 pp 327-337 (1991) Chou SF Daniels P L Rodgers L W Theus G J Eskinazi D (1986) Fire-side corrosion in 10w-NOx
combustion systems In Proceedings Symposium on stationary combustion NOx control Boston MJ US1 6-9 May 1985 EPRI-CS-4360 Palo Jlto C1 US1 EPRI Technicallnfonnation Services pp 191-1922 (Jan 1986) Cichanowicz J E Harrison C D (1989) The role of coal cleaning in integrated environmental control In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Jlto C1 USA EPRI Technical Information Services pp 711-724 (Oct 1989) Clarke F Morris C W (1983) Combustion aspects of furnace wall corrosion In Corrosion resistant materials in coal conversion systems Meadowcroft D B Manning M I (eds) London UK Jpplied Science Publishers pp 47-61 (1983) Clarke L Sloss L (1992) Trace elements emissions from coal combustion and gasification IEJCR49 London UK IEJ Coal Research 111 pp (1992) Clemens A H Matheson T W Rogers D E (1990) DTJ studies of the low temperature oxidation of low rank coals Fuel 69 (2) 255-256 (Feb 1990) Coal Research Establishment British Coal Corporation (1991) Studies of the production ofnitrogen oxides and ash deposition from pulverised coal in relation to utilisation in low NOx burners EUR 13443 EN Luxembourg Commission of the European Communities 46 pp (1991) CoaiTrans International (1991) Coal in the environmentshysupplement CoalTrans International 6 (2) VI-XIII (MarlJpr 1991) Colijn H (1988a) Coal properties handleability and bin design In Defining coal handleability Its cost impact and control Lexington KY USJ 30 Jpr-1 May 1987 EPRI-CS-6015 Palo Jlto CJ USA EPRI Research Reports Center pp 21-219 (Nov 1988) Colijn H (1988b) Coal handleability as part of coal quality control In 1988 joint power generation conference
106
References
Philadelphia PA USA 25-29 Sep 1988 New York NY USA The American Society of Mechanical Engineers pp 25-41 (Sep 1988) Collins S (1990) Can problems arising from chlorine in coal be solved generically Power 134 (12) 59-60 (Dec 1990) Connelly L J (1988) Freeze condition agents and their use in the coal industry In Defining coal handleability Its cost impact and control Lexington KY USA 30 Apr-l May 1987 EPRI-CS-6015 Palo Alto CA USA EPRI Research Reports Center pp 31-327 (Nov 1988) Conroy A (1991) Grinding behaviour of hard coals Combustion News 1-4 (Nov 1991) Corder W C (1983) For lower power costs use high quality coal In Third European coal utilisation conference Amsterdam The Netherlands 11-13 Oct 1983 Rotterdam The Netherlands Industrial Presentations pp 221-240 (1983) Corio M R (1982) Heat rates and availability the use of econometric analysis in comparing electric generating unit performance New York NY USA National Economic Research Associates vp (1982) Corson P B (1988) Carolina Power and Light purchasing model (COALBUY) In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 41-410 (May 1988) Cortsen C E (1983) An evaluation of coal properties and their influence on the utilisation in power stations Report No2 2nd ed Fredericia Denmark ELSAM Coal Quality Committee 161 pp (Nov 1983) Couch G R (1988) Lignite resources and characteristics IEACR13 London UK IEA Coal Research 102 pp (Dec 1988) Couch G R (1989) Power generationfrom lignite IEACR19 London UK IEA Coal Research 67 pp (Dec 1989) Couch G R (1991) Advanced coal cleaning technology IEACR44 London UK IEA Coal Research 95 pp (1991) Cox J N Smith S R Metha A (1990) Field evaluation of EPRI coal quality impact model In Proceedings 1989 EPRl heat-rate improvement conference Knoxville TN USA 26-28 Sep 1989 EPRI-GS-6985 Palo Alto CA USA EPRI Research Reports Center pp 4B61-4B68 (Sep 1990) CQ Inc (1992) The Acid Rain Advisor Homer City PA USA CQ Inc 2 pp (1992) Crelling J C Skorupska N M Marsh H (1988) Reactivity of coal macerals and lithotypes Fuel 67 (6) 781-785 (lun 1988) Cumming J W (1980) The electrical resistance of coal ash at elevated temperatures Journal of the Institute of Energy 53 (416) 153-154 (Sep 1980) Cumming J W Livingston W R Hesselmann G J (1987) Coal reactivity assessment for boiler design In Coaltech 87 - Coaltrade 87 - conference papers London UK 9-11 Jun 1987 Schiedam the Netherlands Industrial Presentations pp 11-30 (1987) Cunliffe F (1990) Thornton UK Shell Research Limited Personal communication (1990) Dacey P W Cope D R (1986) Process development In Flue gas desulphurisation - system performance ICEASIB4 London UK IEA Coal Research pp 44-48 (Dec 1986) Daniel M (1991a) Power station coal use prospects to 2000 IEACR4l London UK IEA Coal Research 61 pp (Oct 1991)
Daniel P L (1991b) The effect of coal chlorides on furnace wall corrosion In First international conference on chlorine in coal Chicago IL USA 9-11 Oct 1989 Amsterdam the Netherlands Elsevier Science Publishers pp 207-224 (1991) Darby K (1983) Commercial precipitator design In Second CSIRO conference on electrostatic precipitation Bowral NSW Australia 17-19 Aug 1983 North Ryde NSW Australia Commonwealth Scientific Industrial Research Organisation pp L41-L431 (1983) Davidson R (1990) Effects on coal behaviour In Natural oxidation of coal IEACR29 London UK IEA Coal Research pp 55-65 (Sep 1990) Davis A (1984) Coal petrography and petrographic analysis In Coal geology and coal technology Ward C R (ed) Melbourne Vic Australia Blackwell Scientific Publications pp 74-112 (1984) Deiuliis N J Fink C E Abbott M F (1991) The impact of ash quantity and quality on boiler performance and power cost In Eighth annual international Pittsburgh coal conference Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greenburg PA USA Pittsburgh Coal Conference pp 975-980 (1991) Deutsch W (1922) Bewegung und Ladung der Elektrizitatstrager im Zylinderkondensator (Velocity and loading of charged particles in cyclinder capacitors) Annales der Physik 68 335-344 (1922) Diessel C F K Bailey J G (1989) The application of petrographic techniques to carbonisation and combustion research at the University of Newcastle In MINPET 89shyMineralogy-petrology symposium Sydney NSW Australia 6-8 Feb 1989 Sydney NSW Australia The Australasian Institute of Mining and Metallurgy pp 117-121 (Feb 1989) Donais R T Tyler A L Bakker W T (1988) Effects of coal properties on pulverizer abrasion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 21-217 (1988) Dooley B (1992) Boiler tube failures - a perspective and a vision In International conference on boiler tube failures in fossil plants San Diego CA USA 5-7 Nov 1991 EPRI-TR-100493 Palo Alto CA USA EPRI Distribution Centre pp 11-129 (Apr 1992) Doyle G (1989) Price premiums and inter-coal competition In CoalTrans 89 sixth international coal trade and transportation conference London UK 16-18 Oct 1989 Worcester Park UK CoalTrans Conferences Ltd pp 177-180 (1989) Dusak V (1986) Brown coal and its safe storage Energetika 36 (1011) 471-474 (Oct 1986) Eck G A (1987) Perfectblend coal blending computer program Journal of Coal Quality 6 (3) 100-101 (lui 1987) Electrical World (1987) Utilities report boiler failure chief culprit in forced outages Electrical World 201 (8) 50-52 (Aug 1987) Elliott M A (ed) (1981) Chemistry of coal utilizationshysecond supplementary volume New York NY USA John Wiley and Sons 2274 pp (1981) Elliott T C (1991) Monitoring powerplant performance Power 135 (9) 11-26 (Sep 1991) Elliott T C (1992) Coal handling and preparation Power 136 (1) 17-33 (Jan 1992) ERM Consultants Pty Ltd (1983) Australian case studies
107
References
which relate to coal quality andor consistency to efficiency and economy ofpower production Brisbane Qld Australia ERM Consultants Pty Ltd vp (Mar 1983) Essenhigh R H (1981) Fundamentals of coal combustion In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley and Sons pp 1153-1312 (1981) Evans R J (1991) A computer expert system to reduce power plant emissions PErC Review (4) 24-28 (1991) Falcon L M Falcon R M S (1987) The petrographic composition of Southern African coals in relation to friability hardness and abrasive indices Journal of South African Institute ofMining and Metallurgy 87 (10) 323-336 (Oct 1987) Falcon R M S Snyman C P (1986) An introduction to coal petrography atlas ofpetrographic constituents in the bituminous coals of South Africa Johannesburg South Africa Geological Society of South Africa 27 pp (1986) Falcon R Ham A J (1988) The characteristics of Southern African coals Journal of South African Institute ofMining and Metallurgy 88 (5) 145-161 (May 1988) Fiveland W A Wessel R A (1988) Numerical model for predicting perfonnance of three-dimensional pulverized-fuel fired furnaces Journal ofEngineering for Gas Turbines and Power 110 117-129 (1988) Flatley T Latham E P Morris C W (1981) Co-extruded tubes improve resistance to fuel ash corrosion in UK boilers Material Performance 20 (5) 12-17 (May 1981) Folsom B A Heap M P PoW J H (1986a) Effect of coal quality on power plant performance and costs - Volume 1 State-of-the-art review summary and program plan EPRl-CS-4283-Vol1 Palo Alto CA USA EPRl Technical Infonnation Services 262 pp (Feb 1986) Folsom B A Heap M P PoW J H Smith J L Corio M R (1986b) Effect of coal quality on power plant performance and costs - Volume 2 Review of coal quality impact evaluation procedures EPRl-CS-4283-Vo12 Palo Alto CA USA EPRl Technical Infonnation Services 387 pp (Feb 1986) Folsom B A Heap M P PoW J H Smith J L (1986c) Effect of coal quality on power plant performance and costs - Volume 3 Review of coal quality and power plant performance diagnostics EPRl-CS-4283-Vo13 Palo Alto CA USA EPRI Technical Infonnation Services 176 pp (Feb 1986) Fortune D B (1990) London UK Shell Coal International Ltd Personal communication (1990) Galluzzo N G Stallard G S Boushka M E Mehta A K (1987) Model predicts as-fired costs of changing coal sources Power 131 (6) 53-56 (Jun 1987) Gebel K Madlsperger G Hein K Bokenbrink D (1989) Entwicklung eines Kombinations DeNOx-Verfahrens unter Verwendung von feuerungstechnischen Minderungsrnassnahmen und Hamstoff-SNCR-Technik (Development of a combined DeNOx process using staged combustion and urea-SNCR technology) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Gennany 26-27 Apr 1989 Essen Federal Republic of Gennany VGB Kraftswerkstechnik GmbH pp 173-180 (Apr 1989) Gibb W H (1983) The nature of chlorine in coal and its
behaviour during combustion In Corrosion resistant materials for coal conversion systems Meadowcroft D B Manning M S (eds) London UK Applied Science Publishers pp 25-45 (1983) Gibb W H (1992) Nottingham UK PowerGen Ratcliffe Technology Centre Personal communication (Sep 1992) Gibbs L A Hallett W L H Hughes P M (1989) Coal devolatilization in an entrained flow reactor In The Combustion 1nstitute Canadian Section 1989 spring technical meeting Toronto Ontario Canada 31 May-2 Jun 1989 Ontario Canada The Combustion Institute pp 91-93 (1989) Giovanni D V Afonso R F Dyas B E Mehta A K (1991) Coal quality field test at New England power companys Salem Harbour Unit Three In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRl-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 379-398 (Jul 1991) Given P H (1984) An essay on the organic geochemistry of coal In Coal science volume 3 Gorbaty M L Larsen J Wender I (eds) Orlando FL USA Academic Press pp 63-252 (1984) Given P H Yarzab R F (1978) Coal analysis and mineral matter In Analytical methods for coal and coal products shyVolume II Karr C Jr (ed) New York NY USA Academic Press pp 3-42 (1978) Gluskoter H J Shimp N F Ruch R R (1981) Coal analyses trace elements and mineral matter In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley amp Sons pp 369-424 (1981) Goddard C W Duzy A F (1967) Measuring abrasiveness of solid fuels and other materials by a radiochemical method ASME paper no 67-WAIFU-l New York NY USA American Society of Mechanical Engineers vp (1967) Goetz G J Nsakala N Y Borio R W (1978) Development of methods for determining emissintives and adsorptivities of coal ash deposits In 1987 winter annual ASME meeting Boston MA USA 13 Dec 1978 New York NY USA American Society of Mechanical Engineers vp (1978) Gomer K (1988) Prediction of the turbulent flow heat release and heat transfer in utility boiler furnaces In Coal combustion Science and technology of industrial and utility applications Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 273-282 (1988) Gutberlet H (1988) Einfluss der Feuerungsart auf die Vergiftung von DeNOx-Katalysatoren durch Arsen (The effect of furnace type on the poisoning of DeNOx catalysts by arsenic) VGB Kraftwerkstechnik 68 (3) 287-293 (Mar 1988) Hainley D C Yavuzkurt S Scaroni A W (1986) Effect of coal properties on fluidized bed combustor perfonnance In Energy-sources technology conference and exhibition New Orleans LA USA 23 Feb 1986 New York NY USA American Society of Mechanical Engineers pp 43-54 (1986) Hampartsoumian E Murdoch M Pourkashanian M Williams A (1991) The reactivity of coal chars produced under various pyrolysing conditions In 1991 international conference on coal science - proceedings Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 271-274 (Sep 1991) Harb J N Smith E E (1990) Fireside corrosion in PC-fired
108
References
boilers Progress in Energy and Combustion Science 16 (3) 169-190 (1990) Hardgrove R M (1938) ASME technical paper Paper presented at ASME spring meeting Chicago IL USA 27 Jun 1938 Harrington R C Kaltenback R P Stratton H L (1988) Burner improvement program on a 650 MW supercritical steam generator - a case study In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 541-549 (Sep 1988) Harrison C Zera C (1990) A new way of doing business in coal-fired power generation Power Engineering 94 (4) 33-36 (Apr 1990) Hatt R M (1990) Fireside deposits in coal-fired utility boilers Progress in Energy and Combustion Science 16 (4) 235-241 (1990) Hatt R M (1991) Coal mining and preparation practices shyimpacts on power plant perfonnance In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 365-377 (Jul 1991) Heap M P Kramlich J C Pershing D W Pohl J H Richter W F Seeker W R (1986) Effect of coal quality on power plant performance and costs - Volume 4 Review of coal science fundamentals EPRI-CS-4283-Vo14 Palo Alto CA USA EPRI Technical Infonnation Services 574 pp (Feb 1986) Heap M P Pohl A S Folsom A S Mehta A K (1984) The effects of coal quality and the resulting ash deposition on the costs of power station operation (Die Bedeutung der Kohlqualitiit und der daraus resultierenden Aschelagerungen fur die Kostan des Kraftwerksbetriebes) In Internationale VGB-Konferenz Verschlackungen Verschmutzungen und Korrosionen in Wriimekraftwerken - Vortriige Essen Federal Republic of Gennany 29 Feb-2 Mar 1984 Essen Federal Republic of Gennany VGB Technische Vereinigung der Grosskraftwerksbetreiber eV pp 493-507 (1984) Heble J J Srinivaschar S Boni A A (1991) The behaviour of clay minerals under combustion conditions American Chemical Society Division of Fuel Chemistry Preprints 36 (1) 173-180 (Apr 1991) Heitmiiller W Schuster H (1991) Low-NOx pulverized coal firing systems and their components Infonnation No 189 Hausdruckerei Gennany Deutsche Babcock Energie- und Umwelttechnik AG 17 pp (Mar 1991) Hervol J D Mehta A K Levasseur A A Miemiec L S Lexa G F (1988) Benefits of coal cleaning on the capital and operating costs of a 550 MW boiler In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 81-824 (May 1988) Hewing A N Harvey M R (1981) Evaluating freeze conditioning agents for coal Power Engineering 85 (7) 74-75 (JuI1981) Hjalmarsson A-K (1990) NOx control technologies for coal combustion IEACRl24 London UK lEA Coal Research 102 pp (Jun 1990) Hjalmarsson A-K (1992) Interactions in emissions control for coal-fired plant IEACRl47 London UK lEA Coal Research 81 pp (Mar 1992) Hjalmarsson A-K Soud H N (1990) Systems for controlling
NOxfrom coal combustion IEACRl30 London UK lEA Coal Research 240 pp (Dec 1990) Hobbs M L Smith P J (1990) Algebraic multi-zoned radiation model for a two-zoned zero-dimensional cylindrical furnace Fuel 69 (11) 1420-1427 (Nov 1990) Hodde J A (1988) Least cost fuel system used to plan fuel purchases In 1988 joint power generation conference Philadelphia PA USA 25-29 Sep 1988 New York NY USA American Society of Mechanical Engineers pp 43-51 (Sep 1988) Holstein R A (1981) Coal fired power plant capital cost estimates EPRI-PE-1865 Palo Alto CA USA EPRI Technical Infonnation Services vp (1981) Horsfall D W Zitron Z (1982) High density beneficiation of coal In Proceedings sixth international conference on coal research London UK 4-8 Oct 1982 London UK National Coal Board pp 319-337 (1982) lEA Coal Industry Advisory Board (1985) Coal quality and ash characteristics Paris France OECDIIEA 63 pp (Jan 1985) IEEE (1984) IEEE standard criteria and guidelines for the laboratory measurement and reporting offly ash resistivity IEEE Standard 548-1984 New York NY USA Institute of Electrical and Electronics Engineers 30 pp (21 Dec 1984) ICCP International Committee for Coal Petrology (1963) International handbook of coal petrology - second edition Paris France Centre National de la Recherche Scientifique vp (1963) ICCP International Committee for Coal Petrology (1975) International handbook of coal petrology - supplement to the second edition Paris France Centre National de la Recherche Scientifique vp (1975) ICCP International Committee for Coal Petrology (1985) International handbook of coal petrology - edited reprint of 1975 supplement to the second edition Murchison D G Smith A H V (eds) Newcastle upon Tyne UK University of Newcastle upon Tyne vp (1985) International Energy Agency (1992) Coal information 1992 Paris France OECDIIEA 541 pp (1992) Iskhakov Kh A (1990) The role of sorbed moisture in coal oxidation Solid Fuel Chemistry (English translation) 24 (2) 17-21 (1990) Jacobs J P (1992) Essen Gennany VGB Technical Association of Large Power Plant Operators Personal communication (Sep 1992) Jamaluddin A S Fiveland W A (1990) Practical model for predicting unburned carbon and temperatures in large-scale boilers Paper presented at 1990 spring meeting combustion fundamentals and applications Cincinnati OH USA 20-22 May 1990 Jenson P T (1992) Fredericia Denmark ELSAM Personal communication (Sep 1992) Johanson J R (1989) Evaluating coal handling characteristics In 1989 joint power generation conference Dallas TX USA 22-26 Oct 1989 New York NY USA American Society of Mechanical Engineers pp 1-5 (Oct 1989) Johanson J R (1991) Identify hard-to-handle coal early Power Engineering 95 (11) 35-38 (Nov 1991) Johnson R P Plangemann R Rehm M (1991) Coal quality effects on boiler perfonnance an Eastern utility perspective In Effects of coal quality on power plants St Louis MI
109
References
USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 11-113 (Jul 1991) Jones A R Gibb W Johnston J (1992) Nottingham UK PowerGen Ratcliffe Technology Centre Personal communication (Mar 1992) Jones M L Benson S A (1988) An overview of slagginglfouling with Western coals In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 125-147 (1988) Jones R B McCourt C B Morley C King K (1985) Maceral and rank influences on the morphology of coal char Fuel 64 (10) 1460-1467 (Oct 1985) Juniper L Pohl J (1991) Techniques to control NOx
emissions from coal-fIred boilers Australian Combustion Technology Centre Combustion News 1-4 (May 1991) Jiintgen H (1987a) Coal characterization in relation to coal combustion Part I structural aspects and combustion Erdol Kohle Erdgas Petrochemie vereinigt mit Brennstoff-Chemie 40 (4) 153-165 (Apr 1987) Jiintgen H (1987b) Coal characterization in relation to coal combustion Part II environmental problems of combustion ErdOl Kohle Erdgas Petrochemie vereinigt mit Brennstoff-Chemie 40 (5) 204-208 (May 1987) Kalmanovitch D P (1991) A practical approach to predicting ash deposition In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 591-5102 (Jul 1991) Kapteijn F Bruinsma D Mol J Moolijn J A (1990) The characterisation of fly-chars from combustion the effect of temperature and rank on reactivity texture and composition Fuel Processing Technology 24 (113) 391-398 (1990) Kautz K (1982) Importance of maceral content in regard to the properties of coals of worldwide origin and its effects on combustion chamber design of large dry furnaces VGB Kraftwerkstechnik - English Issue 62 (3) 1-12 (Mar 1982) Kehoe D B Hervol J D Evans R J Levasseur A A (1990) Evaluating the effects of cleaned coals in utility boilers In Eleventh international coal preparation congress Tokyo Japan 22-25 Oct 1990 Tokyo Japan Mining and Materials Processing Institute of Japan pp 247-252 (1990) Kemeny P (1988) Coal quality impact on electric power generation costs case study Fusina unit 3 In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 631-655 (1988) King J G Maries M B Crossley H E (1936) Fonnulae for the calculation of coal analysis to a basis of coal substance free of mineral matter Journal for the Society of Chemistry and Industry 55 277-281 (1936) Kirchner A T (1991) On-line analysis of coal IEACR40 London UK lEA Coal Research 79 pp (Sep 1991) Kiss L T King TN (1979) Reporting of low-rank coal analysis - the distinction between minerals and inorganics Fuel 58 (7) 547-549 (Jul 1979) Klingspor J S Vernon J L (1988) Particulate control for coal combustion IEACR05 London UK lEA Coal Research 70 pp (Feb 1988) Klitgaard J (1988) Utility coal quality work at a cross-road Journal of Coal Quality 7 (2) 36-37 (Jun 1988) Knill K J (1987) A review offuel staging in pulverised coal
combustion systems IFRF-G-13a3 IJmuiden Netherlands International Flame Research Foundation 54 pp (Sep 1987) Kok A (1988) The effect of coal type on carbon burnout and NOx fonnation in pulverized coal combustion In Coaltech 88 - Coaltrade 88 seventh international conference on coal technology and coal trade Amsterdam the Netherlands 21-23 Nov 1988 Amsterdam the Netherlands Industrial Presentations (Europe) BV pp 1-14 B3 (1988) Kosvic T C Breen B P Yingling J C Mazumdar M Carpenter M Stothart B Plangemann R Maurer W (1988) A combined mechanisticstatistical approach to relating coal properties and boiler operating characteristics to the perfonnance of coal fIred boilers In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 71-717 (Sep 1988) Kremer H Grigoleit H Jacobs J (1990) Tendency of power station coals to fonn NOx - Results of VGB Research Project 89 VGB Kraftwerkstechnik - English Issue 70 (7) 478-484 (Jul 1990) Latham C E Fiveland W A La Rue A D (1991a) Numerical models as combustion system design tools In Eighth annual international Pittsburgh coal conference proceedings Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greenburg PA USA Pittsburgh Coal Conference pp 34-39 (1991) Latham E Meadowcroft D B Pinder L (1991b) The effects of coal chlorine on fireside corrosion In First international conference on chlorine in coal Chicago IL USA 9-11 Oct 1989 Amsterdam the Netherlands Elsevier Science Publishers pp 225-250 (1991) Laurendeau N M (1978) Heterogeneous kinetics of coal char gasification and combustion Progress in Energy and Combustion Science 4 (4) 221-270 (1978) Lee G K Thambimuthu K V Hill J M (1991) Assessment of ash sintering potential by conductance and dilatometry In Eight annual international Pittsburgh coal conference proceedings Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greensburg PA USA Pittsburgh Coal Conference pp 6-11 (1991) Llewellyn W (1991) A practical study of coal handleability In Proceedings of the fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Association of New Zealand vol 1 pp 115-126 (1991) Llinares V Caron M B Schmidt E J Szela F J (1982) The C-E availability data program 1982 further developments on MTTR and MTBF analysis Paper presented at Ninth annual engineering conference on reliability for the electric power industry Hershey PA USA 16-19 Jun 1982 Llinares V Lutz A B (1985) Long range forecast and availability improvement program In Proceedings of the 1985 joint ASMEIEEE power generation conference Milwaukee WI USA 20 Oct 1985 New York NY USA American Society of Mechanical Engineers vp (1985) Lockwood F C Mahmud T (1989) The prediction of swirl burner pulverized coal flames In Twenty-second symposium (international) on combustion Seattle WA USA 14-19 Aug 1988 Pittsburgh PA USA The Combustion Institute pp 165-173 (1989) Lowe A (1987) Important coal properties for power
110
References
generation In Geology and coal mining conference Sydney NSW Australia 13-15 Oct 1987 Sydney NSW Australia Geological Society of Australia Coal Geology Group pp 188-196 (Oct 1987) Lowe A (1988a) Effect of ash levels on large pulverised coal fired furnace performance In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 523-540 (Sep 1988) Lowe A (1988b) Effect of ash in coal on power plant availability In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 733-744 (1988) Luckie P T and others (1980) Coal grinding technology A manual for process engineers ERDA FE-2475-25 USA US Government Printing Office No 1980-640-258-2090 vp (1980) Luo X-L Boyd R K Kent J H (1991) Computational investigation of burnout in a furnace firing pulverised coal Journal of the Institute of Energy 64 (461) 230-238 (Dec 1991) Mackowsky M Th (1982) Minerals and trace elements occurring in coal In Stachs textbook of coal petrology Stach E Mackowsky M Th Teichrnller M Taylor G H Chandra D Teichrnller R (eds) Berlin Federal Republic of Germany Gebriider Borntraeger pp 153-171 (1982) Maher T P Smith MY (1990) A user-friendly coal value model for thermal coals In 1990 international coal engineering conference Sydney NSW Australia 19-21 lun 1990 Barton ACT Australia Institution of Engineers pp 259-263 (lun 1990) Mahr D (1988) Blending coal for quality control In 1988 joint power generation conference - coal quality control fundamentals and applications Philadelphia PA USA 25-29 Sep 1988 New York NY USA American Society of Mechanical Engineers pp 1-8 (Sep 1988) Makanski J (1989) Coal analyzers provide critical link for plant control functions Power 133 (2) 23-25 (Feb 1989) Malhotra V M Crelling J C (1987) Spontaneous combustion of coal and maceral enriched fractions under storage pneumatic transport conditions Final report DOEIPC79863-T13 Carbondale IL USA Coal Extraction and Utilization Research Center 97 pp (Mar 1987) Mancini R A Hopkins B W Hodde J A (1987) Coal quality engineering aids purchasing Power Engineering 91 (6) 16-20 (lun 1987) Mancini R A Hopkins B W Hodde J A (1988) Coal quality engineering analysis used to evaluate coal purchases In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 Palo Alto CA USA EPRI Research Reports Center pp 51-515 (May 1988) Mason D M Gandhi K (1980) Formulas for calculating the heating value of coal and char development tests and uses American Chemical Society Division of Fuel Chemistry Preprints 25 (3) 235-245 (1980) Matsuura S Uchida S (1988) Spontaneous combustion susceptibility of coals Saiko to Hoan 34 (10) 2-14 (25 Oct 1988) Matts S A Ohnfeldt P 0 (1973) Efficient gas cleaning with SF electrostatic precipitators Vaxjo Sweden Flakt Industri AB vp (1973)
McCartney R H Whittaker P S Planner J H (1990) A comparison of United States and Australian practices for power station coal handling facilities In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 lun 1990 Sydney NSW Australia Institution of Engineers pp 174-183 (lun 1990) Mehta A (1989) Coal quality impact model EPRl Journal 14 (8) 49-52 (Dec 1989) Mellanby-Lee H (1986) Effects of coal quality on the costs of electricity generation In Physical coal beneficiation and electricity costs ICEASC3 London UK lEA Coal Research pp 18-30 (Feb 1986) Meyers A D Atkinson B W (1991) Using techno-economic computer modelling to assess the utilisation value of New Zealand coal on the world market In Fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Association of New Zealand pp 160-171 (1991) Mikula R J Parsons I S (1991) Coal dustiness characterisation and control Coal Preparation 9 (314) 199-212 (1991) Misra M K Essenhigh R H (1990) Modelling of one-dimensional pulverised coal flames Paper presented at 1990 spring technical meeting combustion fundamentals and applications Cincinnati OH USA 20-22 May 1990 Mitas D Stallard S Anderson-Higgs A OConnor D (1991) Coal quality analysis linked to power plant control Power Engineering 95 (5) 29-32 (May 1991) Mittelbach G (1989) NOx- Minderung an Kohle-und Mtillkesseln mit dem TermoNOx Verfahren Vergleich von Untersuchungsergebnissen (NOx reduction at coal-fired plants and refuse incinerators with the ThermoNOx process a comparison of test results) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Germany 26-27 Apr 1989 Essen Federal Republic of Germany VGB Kraftswerkstechnik GmbH pp 194-200 (Apr 1989) Morgan M E (1987) Characterisation of coals for use in pulverised coal combustion In International conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 823-826 (1987) Morgan ME (1990) Effect of coal quality on the performance of low-NOx burners Journal of the Institute of Energy 66 (454) 3-8 (Mar 1990) Morgan P A Robertson S D Unsworth J F (1987) Combustion studies by thermogravimetric analysis Fuel 66 (2) 210-215 (Feb 1987) Morrison G F (1982) Control of sulphur oxides from coal combustion ICTISITR21 London UK lEA Coal Research 104 pp (Nov 1982) Morrison G F (1986) Understanding pulverised coal combustion ICTISITR34 London UK lEA Coal Research 46 pp (Dec 1986) Murtha M J (1982) Minerals extraction from ash state of the art In Proceedings of resources from coal coal wastes and ash workshop Reston VA USA 9 lun 1982 BNL-51679 DE83017775 Springfield VA USA National Technical Information Service pp 91-103 (1982) Muter R B Lawrence W F (1986) Mineral matter analysis a technique to improve bituminous coal ACS Symposium Series 301 443-448 (1986)
111
References
Myllynen H (1987) Which thermal coal In Coal Power 87 Neuss Dusseldorf Federal Republic of Germany 27-29 Oct 1987 Worcester Park UK CS Publications Ltd pp 37-42 (1987) Nadgauda S S Hathaway A J (1990) Coal utilization cost model for fuel procurement Journal of Coal Quality 9 (1) 17-21 (Mar 1990) Nakabayashi Y (1988) NOx removal from flue gas In The coal in Sweden conference on the role of coal in the Swedish energy system possibilities and limitation SOdertiilje Sweden 26-27 Oct 1988 Sdertlje Sweden Telge Energe AB pp 1-39 (Oct 1988) Nakata T Sato M Makino H (1988) Methods ofpredicting NOx emissions in coal combustion and unburned carbon in fly ash - effects of coal propenies CRIEPI-W-87003 Tokyo Japan Central Research Institute of the Electrical Power Industry 30 pp (Feb 1988) Nandi B N Brown T D Lee G K (1977) Inert coal macerals in combustion Fuel 56 (4) 125-130 (Apr 1977) Nayak R V Bauer F W Tonden T P (1987) Mineral matter in coal - origin identification and boiler erosion Journal of Coal Quality 6 (2) 37-43 (1987) Neavel R C (1981) Origin petrography and classification of coal In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley and Sons pp 91-158 (1981) Neavel R C Smith S E Hippo E J Miller R N (1986) Interrelationships between coal compositional parameters Fuel 65 (3) 312-320 (Mar 1986) Nemec J Dobal V (1988) Contribution to problem of coal spontaneous combustion Acta Montana Zpravy Hornickeho Ustavu CSAV (Ceskoslovenske Akademie Ved) (76) 9-20 (1988) Nicol S K Smitham J B (1990) Coal stockpile dust control In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 Jun 1990 Sydney NSW Australia Institution of Engineers pp 154-158 (Jun 1990) Noskievic P Kolat P Cech B (1987) Operational tests of burners for ignition and stabilization of pulverised coal Energetika 37 (5) 233-236 (May 1987) Nurick W (1988) An engineering approach to prediction of fuel impacts on utility boiler systems In Reducing electricity generation costs by improving coal quality Indiana PA USA 5-6 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 71-760 (May 1988) Oka N Murayama T Masuoka H Yamada S Yamada T Shinozaki S Shibaoka M Thomas C G (1987) The influence of rank and maceral composition on ignition and char burnout of pulverized coal Fuel Processing Technology 15 213-224 (Jan 1987) Osborn G A (1992) Review of sulphur and chlorine retention in coal-fIred boiler deposits Fuel 71 (2) 131-142 (Feb 1992) OKeefe W Hart R M Hopkins B W McIntire D C Harrison C D (1987) Do we need highly detailed coal specs Power 131 (10) 121-123 (Oct 1987) Parish B M (1970) Wear ofpulverisers Research report 363 Cheltenham UK National Coal Board Research Establishment vp (20 Mar 1970) Pasini S Trebbi G (1989) Evolutions of design and operation criteria for ENEL boilers Paper presented at Tenth international conference on power stations Liege Belgium 25-29 Sep 1989
Pavlikova H Machovic V Sebestova E (1989) Study of low-temperature coal oxidation by means of nuclear magnetic resonance spectrometers infrared spectrometers and electron spin resonance In 2 celostatni konference Samovolne vmecovani uhli v teorii a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSAV pp 1-14 (1989) Penninger A (1989) Effect of working parameters on flame stability for coal dust combustion In Tagung iiber Verbrennung und Feuerung14 Deutscher Flammentag (Meeting on combustion and furnaces 14 Gennan flame day) Stuttgart Federal Republic of Germany 5-6 Oct 1989 Dusseldorf Federal Republic of Germany Verein Deutscher Ingenieure (VDI) - Gesellschaft Energietechnik pp 669-679 (1989) Platfoot R (1990) Erosion life of tube banks in coal fired boilers In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 237-241 (Iun 1990) Pohl J S (1990) Procedure for evaluating the performance of low-grade fuels In Low-grade fuels Helsinki Finland 12-16 Jun 1989 Espoo Finland Valtion Teknillinen Tutkimuskeskus vol 1 pp 247-260 (1990) Potter E (1988) Correlations of ash chemistry with pilot-scale electrostatic precipitation experiments In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp N33-N34 (1988) PowerGen (1991) POSTMAN steady state plant modelling system Information sheet no 34 Nottingham UK PowerGen pic Power Technology Centre 2 pp (1991) Pronobis M (1989) Further fmdings concerning the effect of ash deposits upon the exchange of heat in convection boiler surfaces VGB Kraftwerkstechnik - English Issue 69 (11) 931-938 (Nov 1989) Raask E (1985) Mineral impurities in coal combustion shybehaviour problems and remedial measures London UK Hemisphere Publishing 506 pp (1985) Rademacher F J C (1990) Coal handling developments focusing on The Netherlands In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 282-288 (Jun 1990) Rees 0 W (1966) Chemistry uses and limitations of coal analysis Report of Investigations 220 Urbana IL USA lllinois State Geological Survey 50 pp (1966) Reinschmidt K F (1991) Neural networks next step for simulation and control Power Engineering 95 (11) 41-45 (Nov 1991) Repic B Radulovic P Sikmanovic S Grubor B (1988) Boilers start-up with pulverized coal Paper presented at 20 Kraftwerkstechnisches Kolloquium 1988 (20 power plant technical colloquium) Dresden Federal Republic of Germany 11-12 Oct 1988 Richter W Payne R Heap M P (1986) Influence of thermal properties of wall deposits on performance of pulverised fuel fired boiler combustion chambers ACS Symposium Series (301) 375-393 (1986) Richwine R R Quinn A D Mills J B Lowe S D (1989)
112
References
Results of the availability improvement program in the southern electric system Paper presented at Tenth international conference on power stations Liege Belgium 25-29 Sep 1989 Riley J T Gilleland S R Forsythe R F Graham H D Jr Hayes F J (1989) Nonadditive analytical values for coal blends In Proceedings of the seventh international coal testing conference Ashland KY USA 1989 Ashland KY USA Coal Testing Conference pp 32-38 (1989) Rittenhouse R C (1991) Fighting corrosion in air pollution control systems Power Engineering 95 (6) 23-29 (Jun 1991) Rittenhouse R C (1992) New fuel choices change coal handling and storage rules Power Engineering 96 (1) 17-21 (Jan 1992) Robinson G F (1985) A three-dimensional analytical model of a large tangentially fired furnace Journal of the Institute of Energy 116 226-150 (1985) Roy W R Griffin R A Dickerson D R Schuller R M (1984) illinois basin coal fly ashes 1 Chemical characterisation and solubility Environmental Science and Technology 18 (10) 734-739 (1984) Sadowski R S Hunt P J (1978) Consequences of specifying a boiler design fuel before source commitments are firm In Proceedings of the American power conference Vol 40 Chicago IL USA Apr 1978 Chicago IL USA illinois Institute of Technology pp 394-402 (1978) Sanyal A Livingston W R Marsh H Skorupska N M Field D J Edwards 1 AS (1991) Petrography of lignitic and bituminous coals application to assess coal combustibility for power generation In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 51-520 (JuI1991) Saxena S C (1990) Devolatilization and combustion characteristics of coal particles Progress in Energy and Combustion Science 16 (1) 55-94 (1990) Schaeffer J J (1988) Review of coal quality characteristics of potential utility fuel supply sources Journal of Coal Quality 7 (1) 19-22 (Jan 1988) Scieszka S F (1985) New concept for determining pulverizing properties of coal Fuel 64 (8) 1132-1142 (Aug 1985) Sebesta P Vodickova A (1989) Self-ignition of coal according to its reactivity to oxygen In Symposium on coal utilization trends and challenges Dhanbad India 13-14 Dec 1989 Dhanbad India Central Fuel Research Institute vp (1989) Sherman R A Pilcher J M (1938) An experimental investigation of the use of oil in the treatment of coal Transactions ofAmerican Society of Chemical Engineers 60 97-109 (1938) Shibaoka M Thomas C S Heng S Mackay G H (1987) Significance of morphological features of macerals in coal utilization research In 1987 international conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 107-110 (1987) Shida H Adacchi T Karagasaki M Kuminoto T Hisatome M Kobayashi Y (1984) Development of three-dimensional numerical analysis method of boiler furnace characteristics - part 1 flow analysis Technical Review 18-23 (1984)
Shigeta J-I Hamao Y Aoki H Kajigaya 1 (1987) Development of a coal ash corrosivity index for high temperature corrosion Journal of Engineering Materials and Technology 109 (4) 299-305 (Oct 1987) Shimada S Aumiiller A Klemm F (1991) Measurement of property change of coals stored in stockpile for a long time In 1991 international conference on coal science Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 925-928 (Sep 1991) Shonhardt J A (1990) Evaluation of spontaneous combustion characteristics of some Australian coals Coal Journal (Australia) (29) 21-31 (1990) Singer J G (1989a) Steam fundamentals In Standard handbook ofpower-plant engineering New York NY USA McGraw Hill pp 13-19 (1989) Singer J G (1989b) Pulverizers In Standard handbook of power-plant engineering New York NY USA McGraw Hill pp 1157-1182 (1989) Singer J G (1991) Combustion fossil power - a reference book on fuel burning and steam generation Windsor CN USA Combustion Engineering 1010 pp (1991) Skinner M S A (1988) The costs of burning coal In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Specialists pp 719-731 (1988) Skorupska N M Marsh H (1989) The importance of petrographic characterization of coal for combustion processes In Institute of Energy conference on applied energy research Swansea UK 5-7 Sep 1989 Bristol UK Adam Hilger pp 161-181 (1989) Skorupska N M Sanyal A Hesselman G J Crelling J C Edwards 1 A S Marsh H (1987) The use of an entrained flow reactor to assess the reactivity of coals of high inertinite content In 1987 intemational conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 827-831 (1987) Sligar J (1985) Coal pulverising mill section In Course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 101-1023 (May 1985) Sligar J (1992) Sydney NSW Australia Pacific Power Services Personal communication (Oct 1992) Smith D J (1991) Integrated control systems The next stop Power Engineering 95 (9) 17-21 (Sep 1991) Smith G (1985) Laboratory studies to support the marketing of Australian coals In Proceedings Coal research conference Wellington New Zealand 15-17 Oct 1985 Wellington New Zealand Coal Research Association of New Zealand vol 2 Paper 342 15 pp (1985) Smith 1 W (1982) The combustion rates of coal chars In Nineteenth symposium (international) on combustion Haifa Israel 8-13 Aug 1982 Pittsburgh PA USA The Combustion Institute pp 1045-1065 (1982) Smith 1 W Wall T F Stanmore B R Harris D J Chen J Y Zhang D K (1991a) Coal combustion testing optimum laboratory procedure NERDDP-EG-91-993 Canberra ACT Australia National Energy Research Development and Demonstration Council 89 pp (Feb 1991) Smith P J Davies P R Jamaluddin A S (1991b) Coupling fireside deposition with computational combustion predictions In Effects of coal quality on power plants St
113
References
Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 2119-2140 (Jul 1991) Smith P J Smoot L D (1987) Detailed model for practical pulverized coal furnaces and gasifiers In Proceedings of the AR and TD (Advanced Research and Technology Development) direct utilization and instrumentation and diagnostics contractors review meeting Morgantown WV USA 13 Oct 1987 DOEIMETC-886084-vol 1 Morgantown WV USA Morgantown Energy Technology Center pp 62-71 (Oct 1987) Smith S R (1988) Tennessee Valley Authoritys experience with switching to improved quality coal In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 Palo Alto CA USA EPRI Technical Infonnation Services pp 31-323 (May 1988) Smoot L D (1984) Modeling of coal-combustion processes Progress in Energy and Combustion Science 10 (2) 229-272 (1984) Smoot L D Smith P J (1985) Coal combustion and gasification New York NY USA Plenum Press 459 pp (1985) Sorter J G Folsom B A Richter W (1986) Application of pilot-scale coal evaluation to utility boilers In Joint ASMElIEEE Power generation conference Portland OR USA 19-23 Oct 1986 New York NY USA American Society of Mechanical Engineers pp 1-8 (Oct 1986) St Baker T C (1983) Technology of coal utilisation for electric power generation In Coal technology and coal utilisation Brisbane Qld Australia 29-31 Aug 1983 Brisbane Qld Australia Australian Mineral Foundation Inc pp 1-42 (Aug 1983) Stach E Mackowsky M Th Teichmiiller M and others (eds) (1982) Stachs textbook ofcoal petrology Berlin Federal Republic of Germany Gebriider Borntraeger 535 pp (1982) Stallard G S Galluzzo N G Brown R E Pavlish J H (1988) Implementing EPRIs state-of-the-art coal quality impact model into fuel procurement practices In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 677-693 (1988) Stallard G S Mehta A (1991) Using EPRI CQIM to evaluate acid rain strategies In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 257-275 (Jul 1991) Stallard S Galluzzo N G Mehta A K (1989) Demonstration coal quality impact model In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Alto CA USA EPRI Technical Infonnation Services pp 91-919 (Oct 1989) Stanmore B R (1990) Ash hopper explosions in coal-fired boilers In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 274-276 (Jun 1990) Strein D L (1989) Effects of changing coal quality on precipitator perfonnance In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Alto CA USA EPRI Technical Infonnation Services pp 41-417 (Oct 1989)
Swaine D J (1990) Methods of analysis In Trace elements in coal London UK Butterworths amp Co Ltd pp 50-76 (1990) Swanson A R Taggart I J Wood D L (1982) The economic value of coal for coal fired power stations In Coal Phoenix of the 80s - Proceedings 64th CIC coal symposium Halifax NS Canada 31 May-3 Jun 1981 Ottawa ON Canada Canadian Society for Chemical Engineering pp 324-329 (1982) Swithenbank J Garbett E S Boysan F Ayers W H (1988) Advance of research on coal combustion system modelling In International symposium on coal combustion Science and technology of industrial and utility applications Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 39-63 (1988) Tams D E (1990) Atmospheric fluidized beds - problems and solutions in practice In International conference on steam plant for the 1990s London UK 4-6 Apr 1990 Bury St Edmunds UK Mechanical Engineering Publications pp 117-124 (1990) Taraba B (1989) Effects of grain size and moisture on heat released during oxidation In 2 celostatni konference Samovolne vznecovani uhli v teorii a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSAV pp 1-9 (1989) Taubert U (1991) New developments in the waste disposal of coal-fired power plants VGB Kraftwerkstechnik - English Issue 2 (91) 86-91 (1991) Teichmillier M (1982) Origin of the petrographic constituents In Stachs textbook of coal petrology Stach E Mackowsky M Th Teichmller M and others (eds) Berlin Federal Republic of Germany Gebriider Borntraeger pp 219-294 (1982) Teyssler J (1988) Dependence of operating cost of a steam generator on inert content of the fuel Paper presented at Twentieth power plant technical colloquium Dresden Federal Republic of Germany 11-12 Oct 1988 Thielen W Odenthal H P Richter W (1987) Investigation of the influence of furnace geometry and coal properties on furnace perfonnance with the help of radiation transfer model In Fundamentals of the physical-chemistry of pulverised coal combustion Les Arcs France 28 Jul-1 Aug 1986 Dordrecht the Netherlands Martinus Nijhoff Publishers pp 424-436 (1987) Thompson A W Gibb W H (1988) Coal ash viscosity measurements on selected British coals as an aid to slagging propensity assessment In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 315-351 (1988) Tisch C Mancini R Sutton J Rini M (1990) Optimize p-c combustion to reduce carbon in fly ash Power 134 (12) 31-33 (Dec 1990) Tominaga H Sato M (1989) Development of a simulation for pulverised coal-fired boiler operation (part 4) evaluation of the FLUENT model Idemitsu Sekiyu Gijutsu 32 (1) 29-37 (1 Jan 1989) Truelove J (1985) Burners and flame stability In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle
114
References
NSW Australia University of Newcastle Institute of Coal Research pp 41-419 (May 1985) Tsai CoY Scaroni A W (1987) Reactivity ofbiturninous coal chars during the initial stage of pulverized-coal combustion Fuel 66 (10) 1400-1406 (Oct 1987) Ugursal V I AI Taweel A M (1990) A method for calculating the area requirement for power plant ash and FGD sludge disposal Journal of Coal Quality 9 (3) 87-90 (1990) Ugursal V I AI Taweel A M Mackay G D M (1990) Impact of coal quality on the cost of electrical power generation a technoeconomic model International Journal of Energy Research 14 (6) 683-699 (Aug 1990) Unsworth J F Barrett D J Roberts P T (1991) Coal quality and combustion performance an international perspective Amsterdam the Netherlands Elsevier Science Publishers 648 pp (1991) Vaninetti G E (1987) The importance of coal quality in marketing Journal of Coal Quality 6 (I) 5-7 (Jan 1987) Vernon J L (1989) Market impacts of sulphur control the consequences for coal lEACRlI8 London UK lEA Coal Research III pp (Oct 1989) Vernon J Soud H (1990) FGD installations on coal-fired plants lEACRl22 London UK lEA Coal Research 84 pp (Apr 1990) Vissar M Boysan F Weber R (1987) Computations of isothermal swirling vortices in the near burner zone Report on the MMF 1-1 investigation IFRF-F-336a9 Umiuden the Netherlands International Flame Research Foundation 179 pp (Iun 1987) Vitta P K Lowe S D Gallaspy D T Afonso R F Molino N M (1991) Application and validation of the coal quality impact model as part of the EPRI coal quality monitoring project In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 295-2117 (luI 1991) van Bush P Snyder T R Chang R L (1989) Determination of baghouse performance from coal and ash properties part II JAPCA Journal of the Air and Waste Management Association 39 (3) 361-372 (Mar 1989) Wagoner C L (1988) New opportunity to predict and verify effects of coal quality on the operation of heat exchangers through generic engineering In Reducing electricity generation costs by improving coal quality Indiana PA USA 5-6 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Information Services pp 61-626 (May 1988) Wain S E Livingston W R Sanyal A Williamson J (1992) Thermal and mechanical properties of boiler slags of relevance to sootblowing In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 459-470 (1992) Wall T F (1985a) Coal characterisation for combustion In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 11-119 (May 1985) Wall T F (1985b) Combustion of coal chars In An intensive course on the characterisation of steaming coals Newcastle
NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 51-529 (May 1985) Wall T F Wibberley L J McCol Stewart I (1985) The characterisation of steaming coals - limitations of the standard laboratory and pilot scale tests In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 111-1126 (May 1985) Walsh P M Beer J M Sarofun A F (1988) Estimation of aerodynamic effects on erosion of a tube by ash In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 219-234 (1988) Ward C P Pech J W Woodson H S (1988) Analytical model for coal combustion optimizing boiler operation through combustion control In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 Palo Alto CA USA EPRI Technical Information Services pp 621-629 (1988) Ward C R (1984) Chemical analysis and classification of coal In Coal geology and coal technology C R Ward (ed) Melbourne Vic Australia Blackwell Scientific Publications pp 40-73 (1984) Waters A G (1987) Implications of coal properties for thermal coal exports In Geology and coal mining conference Proceedings Sydney NSW Australia 13-15 Oct 1987 Sydney NSW Australia Geological Society of Australia Coal Geology Group pp AGWOI-AGW08 (1987) Wibberley L J (1985a) Effect of coal composition on deposit formation in PP fired boilers In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 91-918 (May 1985) Wibberley L J (1985b) Characterisation of coals for flyash and sulphur oxide emissions In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 71-715 (May 1985) Wibberley L J Wall T F (1986) An investigation of factors affecting the physical characteristics of fly ash formed in a laboratory scale combustor Combustion Science and Technology 48 177-190 (1986) Wigley F Williamson J Jones A R (1989) Slagging indices for UK coal and their relationship with mineral matter Fuel Processing Technology 24 (13) 383-389 (1989) Wollmann H-J (1990) Danger from residual coal content in hot fly ash VGB Krafiwerkstechnik - English Issue 70 (6) 404-408 (Iun 1990) Wright I G Williams D N Mehta A K (1988) Techniques to reduce fireside corrosion and fly ash erosion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 255-274 (1988) Wu E J Chen K Y (1987) Chemical form and leachability of inorganic trace elements in coal ash EPRI-EA-5115 Palo Alto CA USA EPRI Technical Information Services 202 pp (Iun 1987) Wu K T Payne R Li B Sheldon M (1990) Application of
115
References
engineering computer models and modeling techniques for evaluating boiler thermal performance and emissions control processes In Combustion modeling and burner replacement strategies ASMFIEEE joint power generation conference Boston MA USA 21-25 Oct 1990 New York NY USA American Society of Mechanical Engineers pp 1-8 (1990) Yancey H F Geer M R Price J D (1951) An investigation of the abrasiveness of coal and its associated impurities Mining Engineering 3 262-268 (1951) Yarkin E V Novikova I V (1988) Price as an incentive for improving quality of power fuel Eleckricheskie Stantsii (3) 8-11 (Mar 1988) Yavorskii I A Alaev G P Pugach L I Talankin L P (1968) Influence of the petrographic composition of coals on the efficiency of a pf fired boiler furnace Thermal Engineering (English translation of Teploenergetika) 15 (9) 108-113 (1968) Young R P DuBard J L Hovis L S (1989) Resistivity of fly ashlsorbent mixtures In Seventh symposium on the transfer and utilization ofparticulate control technology Nashville lN USA 22-25 Mar 1988 EPRI-GS-6208 Palo Alto CA USA EPRI Technical Information Services pp 11-115 (1989)
Zehner P (1989) Erfahrungen mit NOx-mindemden Massnahmen an Feuerungen grosser Dampferzeuger (Experience with combustion measures for NOx reduction at large steam generators) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Germany 26-27 Apr 1989 Essen Federal Republic of Germany VGB Kraftwerkstechnik GmbH pp 121-136 (1989) Zelkowski J Riepe W (1987) Generation of ash by hard coal power stations and problems of its utilization in the Federal Republic of Germany In Ash - a valuable resource Pretoria South Africa 1987 Pretoria South Africa Council for Scientific and Industrial Research vol 1 pp Bl-5 (1987) Ziesmer B C Barna L J Bull D L (1991) A utility perspective on western coals - operating experience and methods for screening potential fuel supplies In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 437-456 (Jul 1991) Zygarlicke C J Steadman E N Benoon S A (1990) Studies of transformations of inorganic constituents in a Texas lignite during combustion Progress in Energy and Combustion Science 16 (4) 195-204 (1990)
116
Appendix List of standards referred to in the report
American Society for Testing and Materials 1916 Race Street Philadelphia PA 19103 USA
D197-1987 Sampling and fineness test of pulverized coal
D291-1986 Cubic foot weight of crushed bituminous coal
D3172-1989
D3173-1987
D3174-1989
Proximate analysis of coal and coke
Moisture in the analysis sample of coal and coke
Ash in the analysis sample of coal and coke from coal
0409-1992 Grindability of coal by the Hardgrove-machine method
D3175-1989 Volatile matter in the analysis sample of coal and coke
D440-1986 Drop shatter test for coal D3176-1989 Ultimate analysis of coal and coke
D441-1986
D547-1941
D720-1991
Tumbler test for coal
Index of dustiness of coal and coke
Free-swelling index of coal
D3177-1989
D3178-1989
Total sulfur in the analysis sample of coal and coke
Carbon and hydrogen in the analysis sample of coal and coke
D1412-1989
D1756-1989
Equilibrium moisture of coal at 96 to 97 per cent relative humidity and 30D C
Carbon dioxide in coal
D3179-1989
D3286-1991
Nitrogen in the analysis sample of coal and coke
Gross CalOrifIC value of coal and coke by the isoperibol bomb calorimeter
D1857-1987 Fusibility of coal and coke ash D3302-1991 Total moisture in coal
D2015-1991 Gross calorific value of coal and coke by the adiabatic bomb calorimeter
D3682-1991 Major and minor elements in coal and coke ash by atomic absorption
D2361-1991
D2492-1990
D2795-1986
Chlorine in coal
Forms of sulfur in coal
Analysis of coal and coke ash
D3683-1978
D4326-1992
Trace elements in coal and coke ash by atomic absorption
Major and minor elements in coal and coke ash by X-ray fluorescence
D2798-1991 Microscopical determination of the reflectance of intrinite in a polished specimen of coal
D4749-1987 Performing the sieve analysis of coal and designating coal size
D2799-1992 Microscopical determination of volume per cent of physical components of coal
D5142-1990 Proximate analysis of the analysis sample of coal and coke by instrumental procedures
117
List of standards referred to in the report
Standards Association of Australia BS 1016 Part 6-1977 Ultimate analysis of coal 80-86 Arthur Street North Sydney NSW 2060 Australia
BS 1016 Part 8-1980 Chlorine in coal and coke
BS 1016 Part 11-1982 Forms of sulphur in coal
BS 1016 Part 12-1984 Caking and swelling properties of coal
BS 1016 Part 14-1979 Analysis of coal ash and coke ash
BS 1016 Part 15-1979 Fusibility of coal ash and coke ash
BS 1016 Part 17-1987 Size analysis of coal
BS 1016 Part 11-1990 Determination of the index of abrasion of coal
BS 1016 Part 20-1987 Determination of the Hardgrove grindability index of hard coal
BS 1016 Part 111-1990 Determination of abrasion index of coal
BS 6127 Part 3-1981 Petrographic analysis of bituminous coal and anthracite Part 3 Method of determining maceral group composition of bituminous coal and anthracite
BS 6127 Part 5-1981 Petrographic analysis of bituminous coal and anthracite Part 5 Method of determining microscopically the reflectance of vitrinite
Deutsches Institut rDr Normung eV Postfach 1107 1000 Berlin 30 Germany
DIN 22020 Part 3-1981 Mikroskopische Untersuchungen an Steinkohle Koks und Briketts Maceralanalyse an Komerschliffen (Microscopic method of analysing coal coke and briquettes maceral group analysis)
DIN 22020 Part 5-1981 Mikroskopische Untersuchungen an Steinkohle Koks und Briketts Reflexionsmessungen an Vitriniten (Microscopic method of analysing coal coke and briquettes measurement of the reflectance of vitrinite)
DIN 51 700-1967 Allgemeines und Ubersicht tiber Untersuchungsverfahren (General and overview of methods of analysis)
DIN 51 705-1979 Bestimmung der Schtittdichte (Determination of bulk density)
AS 1038 Parts 1-11
AS 1038 Part 1-1980
AS 1038 Part 3-1989
AS 1038 Part 5-1989
AS 1038 Part 6-1986
AS 1038 Part 8-1980
AS 1038 Part 11-1982
AS 1038 Part 121-1984
AS 1038 Part 141-1981
AS 1038 Part 15-1972
AS 1038 Part 17shy
AS 1038 Part 20-1981
AS 1038 Part 22-1983
AS 2486-1981
AS 2515-1981
AS 3381-1991
AS 3899-1991
Methods for the analysis and testing of coal and coke (metric units)
Total moisture in hard coal
Proximate analysis of hard coal
Gross specific energy of coal and coke
Ultimate analysis of coal
Chlorine in coal and coke
Forms of sulphur in coal
Determination of crucible swelling number of coal
Analysis of coal ash coke ash and mineral matter (borate fusion-flame atomic absorption method)
Fusibility of coal ash and coke ash
Size analysis of hard coal
Determination of Hardgrove Grindability Index of hard coal
Determination of mineral matter and water of hydration of minerals in coal
Microscopical determination of the reflectance of coal macerals
Determination of the maceral group composition of bituminous coal and anthracite (hard coal)
Size analysis of hard coal
Higher rank coals and coke - bulk density
British Standards Institution Sales Office Linford Wood Milton Keynes MK14 6LE UK
BS 1016 Parts 1-20
BS 1016 Part 1-1989
BS 1016 Part 3-1973
BS 1016 Part 5-1977
Methods for the analysis and testing of coal and coke
Total moisture of coal
Proximate of analysis coal
Gross calorific value of coal and coke
118
Appendix
DIN 51 717-1967
DIN 51 718-1978
DIN 51 719-1978
DIN 51 720-1978
DIN 51 721-1950
DIN 51 722shy
DIN 51 724-1975
DIN 51 726-1980
DIN 51 727-1976
DIN 51 729shy
DIN 51 730-1976
DIN 51 741-1974
DIN 51900shy
Bestimmung der Trommelfestigkeit und des Abriebs von Steinkohlenkoks (Detennination of abrasion indexdrum strength and abrasion of hard coal coke)
Bestimmung des Wassergehaltes (Detennination of water content)
Bestimmung des Aschegehaltes (Detennination of ash content)
Bestimmung des Gehaltes an Fliichtigen Bestandteilen (Detennination of volatile matter content)
Bestimmung des Gehaltes an Kohlenstoff und Wasserstoff (Detennination of content of carbon and hydrogen)
Bestimmung des Stickstoff-Gehaltes (gilt nur fur Kohlen) (Detennination of nitrogen (for coal only)
Bestimmung des Schwefelgehaltes Gesamtschwefel (Part 1 Detennination of sulphur content and total sulphur)
Bestimmung des Gehaltes an Carbonat-Kohlenstoff-dioxid (Detennination of content of carbonate carbon dioxide)
Bestimmung des Chlorgehaltes (Detennination of chlorine content)
Bestimmung der chemischen Zusammensetzung von Brennstoffasche (Detennination of chemical composition of fuel ash)
Bestimmung des Asche-Schmelzverhaltens (Detennination of ash melting behaviour)
Bestimmung der BHihzahl von Steinkohle (Determination of swelling capacityindex)
Priifung fester und fliissiger Brennstoffe Bestimmung des Brennwertes mit dem Bomben-Kalorimeter und Berechnung des Heizwertes (Testing of solid and liquid fuels detenninationlanalysis of the
heating value by bomb-calorimeter and calculation of the heating value)
Teil 2 - 1977 Verfahren mit isothermem Wassermantel (Part 2 Methods with isothermal water jacket)
Teil 3 - 1977 Verfahren mit adiabatischem Mantel (Part 3 Methods with adiabatic jacket)
International Organization for Standardization Casa Postale 56 CH 1211 Geneva 20 Switzerland
ISO 157-1975
ISO 331-1983
ISO 332-1981
ISO 334-1975
ISO 352- 1981
ISO 501-1981
ISO 540-1981
ISO 562-1981
ISO 589-1981
ISO 602-1983
ISO 625-1975
ISO 925
ISO 1018-1975
ISO 1171-1981
Hard coal - Detennination of forms of sulphur
Coal - Detennination of moisture in the analysis sample - Direct gravimetric method
Coal - Detennination of nitrogen shyMacro Kjeldahl method
Coal and coke - Detennination of total sulphur - Eschka method
Solid mineral fuels shyDetennination of chlorine - High temperature combustion method
Coal - Detennination of the crucible swelling number
Solid mineral fuels shyDetennination of fusibility of ash shyHigh temperature tube method
Hard coal and coke shyDetennination of volatile matter content
Hard coal - Detennination of total moisture
Coal - Detennination of mineral matter
Coal and coke - Detennination of carbon and hydrogen - Liebig method
Coal - Determination of carbon dioxide
Hard coal - Detennination of moisture-holding capacity
Solid mineral fuels shyDetennination of ash
119
List of standards referred to in the report
ISO 1921-1976
ISO 1953-1972
ISO 1994-1976
ISO 5074-1980
Solid mineral fuels shyDetermination of gross calorific value by the calorimeter bomb method and calculation of net calorific value
Hard coals - Size analysis
Hard coal - Determination of oxygen content
Hard coal - Determination of Hardgrove grindability index
ISO 7404 Part 3-1984
ISO 7404 Part 5-1984
Methods for the petrographic analysis of bituminous coal and anthracite Part 3 Method of determining maceral group composition
Methods for the petrographic analysis of bituminous coal and anthracite Part 5 Method of determining microscopically the reflectance of vitrinite
120
Related publications
Further lEA Coal Research publications on coal utilisation are listed below
Advanced coal cleaning technology G R Couch IEACRl44 ISBN 92-9029-197-4 95 pp December 1991
Power station refurbishment opportunities for coal D H Scott IEACRl42 ISBN 92-9029-195-8 58 pp October 1991
On-line analysis of coal A T Kirchner IEACR140 ISBN 92-9029-193-1 79 pp September 1991
Coal gasification for IGCC power generation Toshiishi Takematsu Chris Maude IEACR137 ISBN 92-9029-190-7 80 pp March 1991
Lignite upgrading G R Couch IEACRl23 ISBN 92-9029-176-172 pp May 1990
Power generation from lignite G R Couch IEACRl19 ISBN 92-9029-170-2 67 pp December 1989
Lignite resources and characteristics G R Couch IEACRl13 ISBN 92-9029-163-X 100 pp December 1988
Coal-fired MHD G F Morrison IEACRl06 ISBN 92-9029-151-6 32 pp April 1988
Biotechnology and coal G R Couch ICTISfTR38 ISBN 92-9029-147-8 56 pp March 1987
Understanding pulverised coal combustion G F Morrison ICTISfTR34 ISBN 92-9029-138-9 46 pp December 1986
Atmospheric f1uidised bed boilers for industry I F Thomas ICTISfTR35 ISBN 92-9029-136-2 69 pp November 1986
All reports are priced at pound60pound180 (membernon-member countries)
Other lEA Coal Research pUblications Details of lEA Coal Research publications are available from
Reviews assessments and analyses of supply transport and markets lEA Coal Research coal science Gemini House coal utilisation 10-18 Putney Hill coal and the environment London SW15 6AA
United Kingdom Coal abstracts Coal calendar Tel (0)81-7802111 Coal research projects Fax (0)81-7801746
Copyright copy lEA Coal Research 1993
ISBN 92-9029-210-5
This report produced by lEA Coal Research has been reviewed in draft fonn by nominated experts in member countries and their comments have been taken into consideration It has been approved for distribution by the Executive Committee of lEA Coal Research
Whilst every effort has been made to ensure the accuracy of information contained in this report neither lEA Coal Research nor any of its employees nor any supporting country or organisation nor any contractor of lEA Coal Research makes any warranty expressed or implied or assumes any liability or responsibility for the accuracy completeness or usefulness of any information apparatus product or process disclosed or represents that its use would not infringe privately-owned rights
lEA Coal Research
lEA Coal Research was established in 1975 under the auspices of the International Energy Agency (lEA) and is currently supported by fourteen countries (Australia Austria Belgium Canada Denmark Finland Germany Italy Japan the Netherlands Spain Sweden the UK and the USA) and the Commission of the European Communities
lEA Coal Research provides information and analysis of all aspects of coal production and use including
supply transport and markets coal science coal utilisation coal and the environment
lEA Coal Research produces
periodicals including Coal abstracts a monthly current awareness journal giving details of the most recent and relevant items from the worlds literature on coal and Coal calendar a comprehensive descriptive calendar of recently-held and forthcoming meetings of interest to the coal industry technical assessments and economic reports on specific topics throughout the coal chain bibliographic databases on coal technology coal research projects and forthcoming events and numerical databanks on reserves and resources coal ports and coal-fired power stations
General enquiries about lEA Coal Research should be addressed to
Mr John Trubshaw Head of Service lEA Coal Research Gemini House 10-18 Putney Hill London SW 15 6AA United Kingdom
Telephone (0)81-780 2111 Fax (0)81-7801746
3
Abstract
This report examines the impacts of coal properties on power station perfonnance As most of the coal used to generate electricity is consumed as pulverised fuel the focus of the report is on performance in pulverised fuel (PF) power station units The properties that are currently employed as specifications for coal selection are reviewed together with their influence on power station performance Major coal-related items in a power station are considered in relation to those properties which affect their performance There is a review of tools being used for coal selection and prediction of station performance which includes an overview of the types of computer models that are available and those that are being developed
The principal coal properties that were found to cause greatest concern to operators included the ash sulphur moisture and volatile matter contents heating value and grindability Little has changed over the years in the way that coal is assessed and selected for combustion Operators continue to use tests as specifications that were mostly developed for coal uses other than combustion Because the procurement specifications are based on tests which do not relate well to actual practice there is still a need for expensive large scale test burns to confIrm suitability With the advances that have been made in computer technology there is a growing number of utilities that are adopting expert unit or integrated models that aid in the planning and operation of generating units Others have shown scepticism over the capability of devising a truly representative model of a coal combustion plant using the coal data produced from current testing procedures
Specific requirements that have been identified include the need to develop internationally acceptable methods of defining coal characteristics so that combustion plant perfonnance can be predicted more effectively There is also a need to establish economic parameters which can serve to measure the effects of coals on plant performance and hence on the cost of electricity
4
Contents
List of figures 7
List of tables 9
Acronyms and abbreviations 11
1 Introduction 13 11 Background 13
2 Coal specifications 15 21 Proximate analysis 17 22 Ultimate analysis of coal 20 23 Ash analysis and minerals 21 24 Forms of sulphur chlorine and trace elements 23 25 Coal mechanical and physical properties 23 26 Calculated indices 28 27 Comments 28
3 Pre-combustion performance 29 31 Coal handling and storage 29
311 Plugging and flowability 32 312 Freezing 34 313 Dusting 35 314 Oxidationspontaneous combustion 36
32 Mills 37 321 Drying 37 322 Grinding 38 323 Size classification and transport 42
33 Fans 42 34 Comments 45
4 Combustion performance 46 41 Burners 46 42 Steam generator 47
421 Combustion characteristics 47 422 Ash deposition 49
43 Comments 56
5
5 Post-combustion performance 57 51 Ash transport 57 52 Environmental control 58
521 Coal cleaning 59 522 Fly ash collection 60 523 Technologies for controlling gaseous emissions 63 524 Solid residue disposal 65
53 Comments 67
6 Coal-related effects on overall power station performance and costs 68 61 Capital costs 68 62 Cost of coal 68 63 Power station perfonnance and costs 69
631 Capacity 69 632 Heat rate 69 633 Maintenance 74 634 Availability 76
64 Comments 77
7 Computer models 79 71 Least cost coalcoal blend models 80 72 Component evaluation models 81 73 Unit models 82
731 Statistically-derived regression models 82 732 Systems engineering analysis 88 733 Integrated site models 97
74 Comments 99
8 Conclusions 101
9 References 104
Appendix List of standards referred to in the report 117
6
Figures
Schematic diagram of the coal-to-electricity chain 14
8 Three-day consolidation critical arching diameter (CAD)
18 Influence of ash characteristics of US coals on
23 Resistivity results for both power station fly ash and
2 Comparison of different coal classification systems 18
3 Mill throughput as a function of Hardgrove grindability index 24
4 Critical temperature points of the ash fusion test 25
5 Typical power station components 29
6 Typical flow patterns in bunkers 32
7 Surface moisture versus critical arching diameter (CAD) determined from shear tests 33
versus per cent fines in coal as a function of moisture content 33
9 Dewatering efficiency versus temperature 34
10 Size distributions of Australian export coal 35
11 Coal lift-off from a stockpile as a function of total moisture content 35
12 Influence of storage time on swelling index 37
13 Primary air temperature requirements depending on moisture content and coal type 39
14 Variation in capacity factor with HGI for different fineness grinds 40
15 HGI for several coals as a function of rank 41
16 Typical utility boiler fan arrangement 43
17 Fuel ratio as an indicator of coal reactivity 48
furnace size of 600 MW pulverised coal fired boilers 49
19 Mechanisms for fly ash formation 50
20 Heat flux recovery for different coals and soot blowing cycles 52
21 Effect of CaO and MgO on corrosivity deposit 53
22 Typical ash distribution 58
laboratory ash from Tallawarra power station feed coal 62
7
24 Laboratory resistivity curves of ash from a South African coal and from a blend of South African and Polish coals against temperature 62
25 Effects of grindability on vertical spindle pulveriser performance 72
26 Example of cost impact of a coal change on heat rate for a 1000 MW boiler 74
27 Adjusted maintenance cost accounts for TVAs Cumberland plant 75
28 Causes of coal-related outages 76
29 Boiler and boiler tubes equivalent availability factor (EAF) record 77
30 Mill engineering model analysis approach 82
31 Comparison of TVA and EPRI availability correlations to a 1000 MW boiler 85
32 Comparison of ash and H20 effects on boiler efficiency and gross heat rate 86
33 Outline of CIVEC model operation 87
34 CQEA evaluation of the impact of different coals on overall production costs of one unit 92
35 Equipment types modelled by CQIM 92
36 Major components of the CQE system 94
37 Correlations of forced outage hours against ash throughput using the CQI model 95
38 Schematic showing the structure of the C-QUEL system 97
39 Comparison of the operations with and without the use of the C-QUEL 98
8
5
10
15
20
25
Tables
1 Summary of coal quality requirements for power generation 16
2 Coal composition parameters standard measurements 17
3 Analysis of a given coal calculated to different bases 18
4 Rank and coal properties 19
Minerals in coal 22
6 Coal mechanical and physical parameters standard measurements 24
7 A summary of the major characteristics of the three maceral groups in hard coals 25
8 Summary of coal ash indices 26
9 lllustrative example of USA coal storage requirements 30
Conveyor Equipment Manufacturers Association (CEMA) material classification chart 31
11 CEMA codes for various coals 32
12 Analysis of ash and clay distribution in a coal by mesh size 33
13 Effect of coal properties on critical lift-off moisture content 35
14 Preferred range of coal properties 37
Maximum mill outlet temperatures for vertical spindle mills 38
16 Comparison of fineness recommendations 38
17 Summary of the effects of coal properties on power station component performance - I 44
18 Enrichment of iron in boiler wall deposits shycomparison of composition of ash deposits and as-fired coal ashes 52
19 Hardness of fly ash constituents 54
Properties of some coal ash components 54
21 Summary of the effects of coal properties on power station component performance - II 56
22 Summary of coal cleaning effects on boiler operation 59
23 Effect of coal type on total concentrations of selected elements from fly ash samples 65
24 Summary of the effects of coal properties on power station component performance - III 66
The effect of coal quality on the costs of a new power station 68
9
26 Ash contents of traded coals 69
31 Examples of boiler frreside variables station and cost
33 Comparison of coal energy costs based on gross heating
27 Calculation of boiler heat losses 70
28 Typical boiler losses for four Australian Queensland steaming coals 71
29 Total fuel costs for power stations of the Southern Company USA 75
30 Comparison of reduced boiler availability on the basis of hours in operation and type of fuel 76
components which may be affected by those variables when coal quality is changed 78
32 Model input output data - International Coal Value Model (ICVM) 80
value (at power station pulverisers) - in order of increasing cost 80
34 Boiler groupings in TVA study 83
35 TVA study - maintenance costs plant correlations for all coal-related equipment 84
36 NERA study - gross heat rate correlation 85
37 ClVEC coal specifications input 88
38 ClVEC power station operational parameters 89
39 ClVEC factors contribution to utilisation value 89
40 Model input output data - COALBUY 90
41 Model input output data - Coal Quality Advisor (CQA) 90
42 Model input output data - Coal Quality Engineering Analysis (CQEA) 91
43 Model input output data - Coal Quality Impact Model (CQIM) 93
44 Ranges of selected coal-ash combustibility parameter that predict approximate classification of CF values 94
45 Model input output data - IMPACT 95
46 Assessment of four coals for Fusina unit 3 using the CQI model 96
47 Summary of model types and capabilities 99
48 Summary of the impacts of coal quality on power station performance 102
10
Acronyms and abbreviations
ad AP ARA ASTM BSl Btu CAD CCSEM CEMA CGI cif CPampL CQA CQEA CQE CQIM CSIRO daf DIN dmmf DTF EEl EFR EPRl ESP FD FEGT FFV FGD FGET FGR fob FTIR GADS GHR GP HGI HLampP HR
air-dried auxiliary power Acid Rain Advisor American Society for Testing and Materials British Standards Institution British thermal unit critical arching diameter computer controlled scanning electron microscopy Conveyor Equipment Manufacturers Association continuous grindability index cost insurance freight Carolina Power and Light Company Coal Quality Advisor Coal Quality Engineering Analysis Coal Quality Expert Coal Quality Impact Model Commonwealth Scientific and Industrial Research Organisation (Australia) dry ash-free Deutsches Institut rur Normung (Germany) dry mineral matter-free drop tube furnace Edison Electric Institute (USA) entrained flow reactor Electric Power Research Institute (USA) electrostatic precipitator forced draft furnace exit gas temperature flow factor value flue gas desulphurisation flue gas exit temperature flue gas recirculation free on board Fourier transform infrared Generating Availability Data System (USA) gross heat rate gross power Hardgrove grindability index Houston Lighting amp Power Company (USA) heat rate
11
ICVM ill IEEE IFRF ISO LCFS kWh MCR MJlkg MWe MWh NERA NERC NHR nm NOx
NYSEG OGampE OampM PA PF PGNAA PN PP ppm ROM SCR SNCR TGA THR TVA UDI UK USA US DOE
International Coal Value Model induced draft Institute of Electronic and Electrical Engineers (UK) International Flame Research Foundation (The Netherlands) International Organization for Standardization Least cost fuel system kilowatt hour maximum continuous rating megajoule per kilogram megawatt (electrical) megawatt hours National Economic Research Associate (USA) North American Electric Reliability Council (USA) net heat rate nanometres nitrogen oxides New York State Electric amp Gas Company (USA) Oklahoma Gas amp Electric Company (USA) operation and maintenance primary air pulverised fuel Prompt Gamma Neutron Activation Analysis Polish Standards Committee Pacific Power parts per million run-of-mine selective catalytic reduction selective non-catalytic reduction thermal gravimetric analysis turbine heat rate Tennessee Valley Authority (USA) Utility Data Institute (USA) United Kingdom United States of America United States Department of Energy
12
1 Introduction
This report examines the impacts of coal properties on power stations buming pulverised fuels (PF) The properties that are currently examined when defining specifications for coal selection are reviewed together with their influence on power station performance The main power station components are considered in relation to those coal properties which affect their performance There is a review of tools being used for coal selection and prediction of station performance which includes an overview of the types of computer models that are both available and under development
In support of the study lEA Coal Research conducted a survey by questionnaire of power stations in 12 countries to obtain additional information about utility practice and experience of the effects of coal quality on power station performance The responses of station operators and research specialists to the questionnaire were of considerable value and much appreciated
11 Background Utilities are continually striving to produce power at the lowest possible cost This means that power stations must operate at optimal availability and rated output while maintaining efficient operation and maintenance schedules At the same time they must also meet relevant emission requirements
Operators of coal-frred stations have long known that coal composition and characteristics signifIcantly affect operation on a broad front Because a power station is a complex interrelated system a change in one area such as coal quality can reverberate throughout the whole system Figure 1 shows a schematic diagram of the coal-to-electricity chain To generate electricity to the busbar at minimum cost it is necessary to evaluate the total cost associated with each coal This includes the cost of any coal-related effects on the performance and availability of
power station components as indicated by Sections 4-7 in Figure 1 in addition to the delivered cost of the coal It is estimated that coal quality factors can contribute up to 60 of all unscheduled outages of coal-fired stations (Mancini and others 1988)
In some cases utilities have the opportunity to fire a range of coals in their power stations In general power stations have a design coal analysis with which initial performance guarantees are met It is also usual to have an allowable range for the most important coal properties within which it is expected that full load may be produced although possibly at reduced efficiencies Substantial deviations in one or more of the properties may result in impaired plant performance or even serious operating and maintenance problems
The quality of coal supplied to a power station may vary for many reasons including
typical day-to-day seam variations in individual coals longer term variations in coal quality due to seam depletion andor change of mining method inconsistencies due to inadequate preparation or poor quality control at the mine site variation in proportions of coals supplied from several traditional supply sources replacement of traditional supplies with sources with different properties due to changing availability or price switchinglblending requirements to meet changing emissions regulations intentional change of fuel quality to solve existing performance problems heavy reliance on recoveries from old stockpiles effects of weather
In order to select a coal supply utilities must try to predict the impacts of alternative coals on power station performance and overall power generation costs Since the type and design of boiler and auxiliary equipment are fixed the coal is
13
6
Introduction
PREPARATION PLANT TRANSPORTMINE
2 3
Figure 1 Schematic diagram of the coal-ta-electricity chain
usually selected to match these rather than the reverse There are numerous methods employed to help select an appropriate coal These can range from selecting coals on the basis of a limited number of design specifications based on proximate analysis through use of sophisticated computer models describing overall performance to expensive full
4 5
HANDLING AND MILLING
STORAGE
PARTICULATES REMOVAL - COMBUSTION~ bull
6B FGD
6C
WASTE DISPOSAL
9
ADDITIONAL UNIT
GENERATION CAPACITY
STEAM 7TURBINE
ELECTRICITY TO 8BUSBAR
scale test firing of sample loads over a limited time period It is recognised that a wide range of complex physical and chemical processes occur during preparation and combustion and so it is not surprising that these methods may still prove to be inadequate in providing a quantitative understanding of the impacts of coal quality
14
2 Coal specifications
The criteria for including particular properties of a coal in a specification used for a particular power station are varied Basic coal contracts can include as few as three or four base quality guarantees - stipulating a range of values for heating value ash content moisture and more recently sulphur More typical purchasing specifications incorporate additional properties such as volatile matter fixed carbon ash fusion temperatures grindability along with the base level specifications of heating value ash moisture and sulphur (Schaeffer 1988) More recently these have been expanded by some utilities to include trace element details and the petrographic composition of the coal Table 1 summarises the typical coal quality requirements for power generation The specification values indicated are derived from both the literature and analysis of the results obtained from the survey of boiler operators
Most of the properties described in Table 1 are measured using relatively simple standard tests More recently some coal specifications have emerged which appear even more complex and restrictive In addition to the standard characterisation tests they may include non-standard characterisation and combustion tests such as the use of thermal gravimetric analysers drop-tube furnaces and pilot-plant tests (see Section 42) It has been argued that such detailed specifications are not necessary (OKeefe and others 1987) may be excessively restrictive and could lead to increasing fuel cost as specific sources are no longer available (Mahr 1988 Harrison and Zera 1990) The advocates for detailed specifications argue that to use only a basic fuel specification for selection will leave the market open for many coals which may not perform as well as the design-specification coal (Vaninetti 1987 Myllynen 1987) They will most likely be attractively priced (Corder 1983 OKeefe and others 1987) but there is no assurance that the saving will necessarily minimise the overall cost of power generation In many cases buying the coal of lowest price can be false economy (see Chapter 6) for example if the coal adversely affects heat rate additional coal will be
needed If the selected coal cannot sustain full unit capacity or causes additional outages (availability loss) alternative units must be operated to make up the lost power possibly at considerable additional cost Also increased maintenance costs add directly to the total cost of power generation (Folsom and others 1986a Sotter and others 1986 Yarkin and Novikova 1988 Ziesmer and others 1991 Bretz 1991a)
Blending to meet quality specifications is gaining acceptance In most cases power stations do not fire only coal from a single seam in their boilers As coal occurs in heterogeneous deposits the supply from any mine is already a blend of material from different seams to meet the required specification This principle may be extended such that coals supplied to power stations can be blends from several different sources prepared at handling centres such as at Rotterdam The Netherlands (Rademacher 1990) Power stations themselves may have facilities for blending two or more coals on site Separately the coals may not meet specification but a homogeneous mix does (Ratt 1991) Most countries which depend solely on imported coals have commercial strategies stipulating that no single source should account for more than 40 of supply (Klitgaard 1988) Blending which extends the range of acceptable coals increases the number of supply opportunities It should be noted that the non-additive nature of some of the standard tests such as ash fusion tests and use of HGI values (see Section 25) makes blend evaluation for power station use inherently complex (Riley and others 1989)
The following sections examine the coal properties used in coal specifications and evaluate their significance in power station operation
Table 2 lists eighteen standard methods of measuring coal composition together with an indication of the relevance of the results to the utility industry As illustrated in Table 2 the key measurement methods are proximate analysis
15
Coal specifications
Table 1 Summary of coal quality requirements for power generation
Parameter Desired Typicallimits
Heating value (ar) MJkg high min 24-25 (23) Proximate analysis - Total moisture (ar) 4-8 max 12
- Ash (mt) low max 15-20 (max 30) - Volatile matter (rot) 20-35 min 20 (23) - side-fIred furnaces
15-20 max 20 - down-fIred pf furnaces Total sulphur (mt) low max 05-10 - dependent on local pollution regulations
Hardgrove grindability index (HGI) high
Maximum size mm 130-40 Fines less than 05 mm (15 max)
Proximate analysis Ultimate analysis
Chlorine (rot)
Ash analysis weight of ash
Ash fusion temperatures degC
Swelling index Ash resistivity Handleability
Trace elements
Vitrinite reflectogram
Maceral analysis
- Fixed carbon (rot) - Carbon (daf)
- Hydrogen (daf)
- Nitrogen (dat) low - Sulphur (dat)
- Oxygen (by diff daf) low
Silicon dioxide (Si02) Aluminium oxide (Ah03) Titanium oxide (Ti02) Ferric oxide (Fe203) Calcium oxide (CaO) Magnesium oxide (MgO) Sodium oxide (Na20) Potassium oxide (K20) Sulphite (SOn Phosphorus pentoxide (P20 S)
- initial deformation high - softening (H = W) high - hemispherical (H =lizW) high - fluid high
low ohmem at 120degC
As Cd Co Cr Cu
Hg Ni Pb Sb Se Tl Zn
Vitrinite Exinite Inertinite Mineral
min 50-55 (min 39) 50 limited by size accepted by pulveriser
limited for handling characteristics
(08-11)
max 01--03 (max 05)
(45-75) (15-35) (04-22) (1-12) (01-23) (02-14) (01--09) (08-26) (01-16) (01-15)
(gt1075) in reducing conditions (gt1150) for dry bottom furnaces (gt1180) Values are much lower for wet bottom (gt1225) furnaces
(max 5) if available if available
Declaration of presence
if available
55-80 5-15 10-25 to declare
Typical limits refer to those commonly quoted those in brackets indicate outer limits acceptable in some cases
Measurement basis ar shy as received mf - moisture free daf - dry ash-free
16
Coal specifications
Table 2 Coal composition parameters standard measurements (after Folsom and others 1986c)
Measurement Method Standards procedure
ASTM AS BS DIN ISO
Parameters measured
Relationship to power station performance
Proximate analysis 03172-89 Moisture D3173-87 Volatile matter D3175-89 Ash D3174-89 Fixed carbon
Ultimate analysis 03176-89 Oxygen Carbon 03178-89 Hydrogen 03178-89 Nitrogen 03179-89 Total sulphur 03177-83
10383-89 10383-89 10383-89 10383-89 10388-89
10386-86
103861-86 103861-86 103862-86 103863-86
10163-73 10163-73 10163-73 10163-73 10163-73
10166-77 10166-77 10166-77 10166-77 10166-77 10166-77
51700-67 51718-78 51720-78 51719-78
51700-67
51721-50 51721-50 51722 517241-75
331-83 562-81 1171-81
1994-76 625-75 625-75 332-81 334-75
H20 Ash VM FC
Part of proximate analysis
C H 0 N S Ash H2O
) Pm of 1_ analysis
These parameters affect all power station systems since they are the principal constituents of coal
Ash analysis D2795-89 AA-Elemental ash analysis Major 03682-87 AA-Elemental ash
1038141-81
1038141-81
101614-79
101614-79
51729-80
analysis Trace 03683-78 Mineral matter C02 in coal D1756-89 Forms of sulphur D2492-90 Chlorine D2361-91 Total moisture D3302-89 Equil moisture D1412-89
1038104-86 103822-83 103823-84 103811-82 10388-80 10381-80 103817-89
10166-77 101611-87 10168-84 10161-89 101621-87
51726 517242 51727-76 51718
602-83 925-80 157-75 352-81 589-81 1018-75 Surface moisture
Corrosion slagging fouling
Handling amp pulverisation
Proximate analysis by instrumental procedures D5142-90
AA Atomic Adsorption ASTM American Society for Testing and Materials AS Australian Standards
BS British Standards Institution DIN Deutsches Institut fur Normung ISO International Organization for Standardization
ultimate analysis and ash analysis Additionally other early 1800s at a time when carbonisation was the most chemical analyses are often carried out on coal samples important use of coal It was a means of broadly assessing Some of these tests are used to enable correction of the bulk distribution of products obtainable from a coal by proximate and ultimate analysis data to allow for mineral destructive distillation (Elliott 1981) It is widely accepted matter constituents while others are used to evaluate the by the utility industry and forms the basis of many coal coals suitability for specific purposes In most coal qualitypower station performance correlations The great producing and consuming countries national or international advantage of the tests required for proximate analysis is that standard techniques are used The titles of the standards they are all quite simple and can be performed with basic reported in this chapter and the addresses of the standards laboratory equipment So much so that they have been fully organisations are given in the Appendix automated in recent years The results of proximate analysis
although endorsed with long history and extensive Common causes of confusion in the comparison of coal and experience are empirical and only applicable if the tests are interpretation of analytical data as reviewed by Carpenter carried out under strict standardised conditions The five (1988) are characteristics obtainable from the procedure are
the different domestic and international coal total moisture classification schemes used (see Figure 2) air-dried moisture the wide range of analytical bases on which the coal data volatile matter may be reported and the failure of many workers to ash identify clearly the basis for their results Table 3 fixed carbon illustrates how results will vary for a single coal depending on the base used Proximate analysis reports moisture in only two categories
as total and air-dried although it actually occurs in coals in different forms Air-dried moisture is also referred to as21 Proximate analysis inherent moisture The total moisture of coal consists of
The proximate analysis of coal is the simplest and most surface and inherent moisture Surface moisture is the common form of coal evaluation It was introduced in the extraneous water held as films on the surface of the coal and
17
----- ---
---
01
Coal specifications
Volatile Australia
301a
302
303
301b 302 303
401-901 high volatile A bituminous
402-702 coal402 class 7 Ihigh volatile B bituminous
coal 902 high volatile
class ~inouscoal
I subbituminousclass subbituminous
B coal 11 A coal subbituminous
class ~
approximate C coal 12 volatile matter
f-- shy dmmf lignite A class class 6 32-40
13 class 7 32-43 class 8 34-49
class ~
class 9 41-49
-14 lignite B
class
-15
matter dmmf
2 6 8 9
10 115 135
14 15 17
195 20 22 24
275 28 31 32 33
36
44J
47J
Great Britain NCB
101 anthracite
102
201a dry Ol ~~ 201b I~~~I~ COcgt
202 ~EgE- co co ~co203 -OlO 02 -en8en t)204
FRG
meta-anthracite
anthracite
lean (non-caking)
coal
forge coal
fat (coking) coal
hard coals
gas coal
tgas flame coal
flame coal
shiny hard
brown coal
matt
soft brown coal
MJkg class 6 326
class 7
302 class 8
class 9 -256
- 221 soft
193 brown coals
147
Heating value MJkg
N S
173 131
179 136
198 151
gross net
3168 3067
3279 3175
3635 3520
-
medium volatile coals
30shy
40shy
50shy
60shy
70shy
International hard coals
class 0
class 1A
class 1B
class 2
class 3
class 4
hardclass 5 coals
class 6 moi sture
high ~ f 0Yo
brown coals
volatile I coals
and I
I~ class 8
-1Q class 9- - 20shy
North America ASTM
Imeta-anthraciteI
anthracite
semi-anthracite
low volatile bituminous
coal
medium volatile
bituminous coal
Calorific value mmmf
hard coals
class 1
class 2
class 3
class 4A
class 4B
hardclass 5 coals
Figure 2 Comparison of different coal classification systems (Couch 1988)
Table 3 Analysis of a given coal calculated to different bases
Condition or basis
Proximate analysis
H2O VM FC Ash
Ultimate analysis
C H 0
As received 339 2061 6653 947 7729 459 561
Dry 2133 6887 980 8000 436 269
Dry ash-free 2365 7635 8869 483 299
Analysis of US Pennsylvania Somerset County Upper Kittaning Bed No 3 Mine
In the ultimate analysis moisture on an as received basis is included in the hydrogen and oxygen Net heating value is calculated from the gross value using the relationship in ISO 1928
its content can vary in a coal over time The moisture present water is difficult to control separate assessment of inherent in other forms is regarded as the inherent moisture it is or air-dried moisture is also necessary as most other more or less constant for coals of a given rank (Ward 1984) analyses are carried out on air-dried material
A coal that is sold commercially usually contains a certain Surface moisture is important to the handleability of coal amount of surface moisture which forms part of the total (see also Section 31) With a content greater than 12 of weight of coal delivered Knowledge of the total moisture the coal weight problems such as bridging in bunkers and content of the coal is therefore essential to assess the value of blocking of feeders can be expected in the transport system any consignment However because the amount of surface (Cortsen 1983) In cold climates the excess surface moisture
I
18
Coal specifications
may freeze and act as a binder so incurring coal handling problems (Raask 1985)
Extremely low surface moisture content can cause environmental problems due to dust and enhanced risks of fire due to coal oxidation which causes heating and may lead to spontaneous combustion especially in low rank coals (see
also Sections 313 and 314)
Surface moisture and part of the inherent moisture of a coal can be released in the mills during grinding This means that the mill inlet or primary air temperature prior to milling must be increased for coals with a high total moisture content The surface moisture of the coal is converted to vapour during milling and forms part of the coal-air mixture in direct feed systems The vapour enters the furnace where it can cause a delay in coal ignition and increase flame length The effect however is small for coals with moisture contents not exceeding 10
The inherent moisture has a more direct influence on coal ignition and combustion Significant gasification of the coal particle to release combustible gases cannot start prior to the evaporation of the moisture from within the particle When firing a coal with a high inherent moisture content conditions can also be improved by increasing mill air inlet temperature
Total moisture in the coal contributes to the overall gas flow in the form of vapour (Cortsen 1983) This can influence the operation of fans that move the air flue gas and pulverised coal through the unit An increase in coal moisture will increase the flue gas volume flow rate thus necessitating an increased power requirement for the fans (see Section 33)
During the combustion process coal releases volatiles which include various amounts of hydrogen carbon oxides methane other low mOlecular weight hydrocarbons and water vapour Volatile yield of a coal is an important property providing a rough indication of the reactivity or combustibility of a coal and ease of ignition and hence flame stability The amount of volatiles actually released in practice is a function of both the coal and its combustion conditions including sample size particle size time rate of heating and maximum temperature reached In order to obtain a method for comparing coals a simple test was devised to obtain a value for the volatile matter content of a coal The volatile matter content as determined by proximate analysis represents the loss of weight corrected for moisture when the coal sample is heated to 900degC in specified apparatus under standardised conditions
Typical values of volatile matter content associated with different ranks of coal as determined by proximate analysis are given in Table 4 (Cunliffe 1990) It should be noted that some of the volatile matter may originate from the mineral matter present
The volatile matter content of a coal is used to assess the stability of the flame after ignition Under the same combustion conditions that is same burner configuration and amount of excess air a coal with a high volatile matter content will usually give stable ignition and a more intensive
Table 4 Rank and coal properties (Cunliffe 1990)
Type C H 0 Volatile Heating
(composition ) matter value daf MJkg
Wood 500 60 430 800 146
Peat 575 55 350 684 159
Lignite 700 50 230 526 216
Bituminous High volatile 770 55 150 421 258
Medium volatile 860 50 45 263 335
Low volatile 905 45 30 188 348
Semi-anthracite 905 45 30 188 348
Anthracite 940 30 15 41 346
daf dry ash-free basis
flame compared with a coal with a low volatile matter content Maintaining stable ignition is one of the most crucial aspects of pulverised coal firing since instability necessitates the use of pilot fuel and in extreme cases may incur the risk of furnace explosion (Cortsen 1983) Low laquo20) volatile matter coals can produce high-carbon residue ash In order to combat this adverse effect the coal would require extra-fine milling and combustion in boilers with a long flame path (Raask 1985) A high volatile matter content (gt30) can cause mill safety problems This is due to the increased possibility of mill fires resulting from spontaneous combustion of the coal (see Section 32) Volatile matter content values are often used to calculate combustibility indices which are used as an indication of the reactivity of a coal They are also included in formulae for the prediction of NOli release during coal combustion (Kok 1988)
Ash is the residue remaining following the complete combustion of all coal organic material and oxidation of the mineral matter present in the coal Ash is commonly used as an indication of the grade or quality of a coal since it provides a measure of the incombustible material present in the coal A higher ash content means a lower heating value of the coal as ash does not contribute any energy to the system It represents a dead weight during coal transport to and through a power station (Lowe 1988a) In order to maintain boiler output when switching from a low ash coal to another with similar specification but a higher ash content an increased throughput of material would be required to achieve the same loading Alternatively power station output may be constrained by the lack of capacity in the ash handling system
Ash content and its distribution within the coal influences ignition stability The transformation of mineral matter to ash is an endothermic reaction - requiring energy Thus some coal particles containing a high proportion of mineral matter may not ignite satisfactorily In some cases stack and unburnt carbon losses have been shown to increase as the heating value of the coal decreases with increased ash content A high-ash content may lower the accessibility of the carbon to combustion within the particle (Kapteijn and others 1990) In contrast to these situations Australian power stations have been known to combust coals with a
19
Coal specifications
high ash (gt25) content without support fuel satisfactorily (Sligar 1992)
High ash coals (gt20) can cause abrasion and particle impaction erosion wear of fuel handling plant mills burners boiler tubes and ash pipes if the plant is not designed for this (Raask 1985) Utilisation of a high ash coal may impair the performance of particulate control devices by ash overloading There may also be problems of accommodating higher ash levels for disposal (Bretz 1991b)
Possibly the most serious effects that ash constituents have upon the boiler performance are those connected with fouling slagging and corrosion of the heating surfaces These problems are discussed in Section 422
The fixed carbon content of coal is not measured directly but represents the difference in an air-dried coal between 100 and the sum of the moisture volatile matter and ash contents It still contains appreciable amounts of nitrogen sulphur hydrogen and possibly oxygen as absorbed or chemically combined material (Rees 1966)
The fixed carbon content of coal is used by the ASTM to classify coal according to rank (Carpenter 1988) It is also used as an estimate of the quantity of char (intermediate combustion product) that can be produced and to indicate the amount of unburnt carbon that might be found in the fly ash
In any assessment of data it should be noted that the final temperatures heating rates and residence times utilised in proximate analysis tests differ significantly from conditions experienced in power station boilers In proximate analysis depending upon the set of country standards used
moisture content is determined in a nitrogen atmosphere at around 100degC for 10 minutes volatile matter of a coal is determined under restricted conditions at 900degC after a residence time of up to seven minutes ash content is determined by combusting the organic component of the coal in air up to around 800dege
Conditions in a power station boiler have been reported to produce temperatures greater than 1700degC (3120degF) heating rates of 1O000-100OOOdegCs and particle residence times within the system of seconds rather than minutes Ideally the suitability of a coal for combustion use should take into account the operational conditions and aim to identify relationships between critical process requirements and specific properties of the coal on a more rational basis However proximate analysis is still widely used in the utility industry
There are also problems with interpreting the results from a proximate analysis Ideally the moisture fraction should contain only water the volatiles fraction should consist only of volatile hydrocarbons released during the initial stages of heating the fixed carbon would be the char after complete devolatilisation and ash only the oxidised remains of the mineral matter after combustion This is not always the case Many coals contain light hydrocarbons which are driven off from the coal at temperatures low enough to cause them to
appear in the moisture determination Consequently the moisture measurement is too high and corresponding volatiles measurement too low This can be a significant problem with lower rank coals (Folsom and others 1986c)
A similar problem occurs between volatiles and fixed carbon The mechanisms involved in thermal decomposition of coal are complex and variations in the particle size treatment times temperatures and heating rates may affect the results Volatile matter content usually includes a loss in weight due also to the decomposition of inorganic material especially carbonates which are known to decompose at temperatures in excess of 250degC (see Section 23) Since fIxed carbon is not a direct measurement but obtained by difference it will include any errors bias and scatter involved in the related determinations of moisture volatile matter and ash Thus the concept of well defmed quantities of fixed carbon and volatile matter for specific coals is subject to qualification
Ash as produced during proximate analysis is often used as the material for conducting chemical analysis and other tests for assessing ash behaviour in a power station The problems associated with this approach are discussed in Section 23
22 Ultimate analysis of coal Ultimate analysis involves the determination of the elemental composition ofthe organic fraction of coal (Ward 1984 Gluskoter and others 1981) Table 2 describes the standard measurement methods for ultimate analysis techniques for ASTM AS BS DIN and ISO In addition to ash and moisture element weight per cents of carbon hydrogen nitrogen sulphur and oxygen (which is determined by difference) are reported Ash and moisture are determined by the same method as in the proximate analysis and suffer from the same shortcomings The detection of the above elements are usually performed with classic oxidation decomposition andor reduction methods (Berkowitz 1985)
Carbon and hydrogen occur mainly as complex hydrocarbon compounds Carbon may also be present in inorganic carbonates The nitrogen found in coals appears to be confmed mainly to the organic compounds present (Ward 1984) The nitrogen content of coal has become an important issue with the increased awareness of air pollution by nitrogen oxides (NOx) Unfortunately there is no simple correlation between coal nitrogen content and nitrogen oxide emissions as unlike sulphur dioxide not all nitrogen oxide produced during combustion comes from the coal itself In combustion theory there are three different formation mechanisms for NOx thermal prompt and formation ofNOx from fuel-bound nitrogen although the reactions are not fully understood (Juniper and Pohl 1991) Only the third mechanism relates to oxidation of the nitrogen contained in coal (Hjalmarsson 1990) The nitrogen content in coal varies between 05 and 25 and is contained mostly in aromatic structures (Burchill 1987 Zehner 1989) Some of the fuel nitrogen is released during devolatilisation and in highly turbulent unstaged burners is rapidly oxidised The remainder of the fuel nitrogen remains in the char and is released at a similar rate to that of char combustion The effIciency of coal-bound nitrogen conversion to NOx has
20
Coal specifications
been estimated at 20-25 for the char and up to 60 for the volatile matter (Morgan 1990) NOx formation from fuel-bound nitrogen can be minimised by promoting devolatilisation in zones of high temperature under reducing conditions for example air staging This principle is exploited in low NOx burners However less can be done to mitigate NOx formation due to the combustion of post-devolatilisation char-bound nitrogen (Kremer and others 1990 Hjalmarsson 1990)
Sulphur is present in nearly all coals from trace amounts up to about 6 although higher levels are not unknown The presence of sulphur compounds in the coal and ash can have many deleterious effects on the operation of boilers for example
during combustion the sulphur is oxidised to S02 A small percentage generally not more than 2 is converted into S03 of which a substantial percentage may then be reabsorbed to form sulphates with the alkali metals in the ash Alkaline sulphates are undesirable in that they increase the tendency of fouling and corrosion of heat transfer surfaces (see Section 422) if the dew point of the combustion gases is reached the S03 present combines with condensing water vapour to produce sulphuric acid which can then cause severe corrosion in cool sections of the power station particularly flue gas ducts and treatment systems (see Section 422)
The main problem however is S02 which is emitted through the stack and constitutes an environmental problem due to the resulting formation of acid rain
The oxygen content of coal is traditionally determined by difference subtracting the sum of the measured elements (C + H + N + S) from 100 although there are procedures available for the direct determination of oxygen (Gluskoter and others 1981 Ward 1984) It is an important property as it can be used as an indicator of rank and the basic nature of the coal Coals tend to oxidise in air to form what is commonly known as weathered coal The oxygen content of a coal has also been used as a measure of the extent of oxidation
Whilst the procedures for elemental analysis described by national standards often differ in minutiae they generally yield closely similar results This can only be achieved by the rigorous adherence to test specifications as laid down by the standards careful sampling and sample preparation
Similar to proximate analysis corrections to the analysis data are necessary For example
contributions to the hydrogen content from residual coal moisture and dehydration of mineral matter because the hydrogen content in coal is determined by the conversion of all the hydrogen present to H20 contributions to the carbon and sulphur contents which are determined by conversion to C02 and S02 respectively because both C02 and S02 are released from any carbonates and sulphides or sulphates that may be contained in the mineral matter
The major limitation of ultimate analysis is the labour cost
and time required to conduct the analyses Several techniques and instruments have been developed to reduce these limitations Some utilise automated gas chromatographic or spectroscopic equipment attached to high temperature combustion furnaces to reduce the time and labour required for the analysis Others utilise a range of measurement techniques including nucleonic methods to provide a quasi-continuous analysis for example on-line analysers (Folsom and others 1986a Kirchner 1991)
23 Ash analysis and minerals Coal ash consists almost entirely of the decomposed residues of silicates carbonates sulphides and other minerals Originating for the most part from clays it consists mainly of alumino silicates so that its chemical composition can usually be expressed in terms of similar oxides to those found in clay minerals The composition of the ash may be used as a guide to the types of minerals originally present in the coal (Given and Yarzab 1978 Ward 1984)
Certain generalisations can be made on the influence of the ash composition on the fusion characteristics as determined by the ash fusion test
the nearer the composition approaches that of alumina silicate Al2032Si02 (Al203 =458 Si02 =542) the more refractory (infusible) it will be CaO MgO and Fe203 act as mild fluxes lowering the fusion temperatures especially in the presence of excess Si02 FeO and Na20 act as strong fluxes in lowering the fusion temperatures high sulphur contents lower the initial deformation temperature and widen the range of fusion temperatures
In practice power station operators are primarily interested in knowing how closely the laboratory-prepared ash content of coal represents the quantity and behaviour of ash produced in large boilers Therefore when interpreting the results of the ash analysis it is important to recognise that the analysis is conducted on a sample of ash produced by the procedures specified in the proximate analysis (for example ASTM D3172 - see Appendix) It does not therefore correspond to the mineral matter present in the parent coal or necessarily to the individual ash particles formed when fired in a utility boiler For example it would be incorrect to assume that the iron measured in the ash sample is necessarily present in the coal as Fe203 or that the aluminium is present as Ah03 (Folsom and others 1986c) The principal chemical reactions that affect the ash yield at different temperatures are
High temperature Low temperature combustion oxidation
(Na K Ca)0Si02xAL203 + S03~ (Na K Ca)S04 + Si02xA1203 2 FeO + 1z 02 ~ Fe203
The boiler ash cools rapidly at a rate of about 200degCs through the temperature range from 900degC to 250degC and
21
Coal specifications
during this short time interval there is only a limited degree of sulphation and oxidation taking place Thus the ash prepared in a laboratory furnace at 815degC has higher weight than that formed in the boiler furnace due to the absorption of S03 in sulphate and additional oxygen in the ferric oxide (Raask 1985) For many years ash analysis in this form has been the only method available for assessing fly ash and deposit composition These in turn would be used to assess a coals slagging fouling and corrosive propensities which are of concern for the efficient operation of the power station More recently investigators have recognised the importance of actual mineral matter composition and
Table 5 Minerals in coal (Mackowsky 1982)
Mineral group First stage of coalification
distribution within the parent coal particles as a better indicator of a coals slagging and fouling behaviour (Nayak and others 1987 Heble and others 1991 Zygarlicke and others 1990) (see also Section 422)
Mineral matter determination is carried out far less frequently than the relatively fast and inexpensive ash determination (Brown 1985) Table 5 describes the minerals found in coal and their method of deposition
Although the ash as measured by proximate analysis is often equated with the coal mineral matter there are significant
Second stage of coalification Occurrence
Syngenetic fonnation synsedimentary-early diagenetic Epigenetic formation (intimately intergrown)
Transported Newly fonned Deposited in Transfonnation by water or fissures cleats of syngenetic wind and cavaties minerals
(coarsely (intimately intergrown) intergrown)
Clay minerals Kaolinite common-very common Illite-Sericite Illite dominant-abundant Minerals with a layered structure Chlorite rare Montmorillonite rare-common Tonstein
Carbonates Siderite Ankerite Ankerite common-very common Dolomite Dolomite rare-common Calcite Calcite common-very common
Sulphides Pyrite Pyrite Pyrite rare-common Melnikovite rare Marcasite Marcasite rare
Galena rare Chalcopyrite rare
Oxides
Quartz
Phosphates
Heavy minerals and accessory
Hematite Goethite
Quartz grains Quartz Quartz
Apatite Apatite Phosphorite
Zircon Tounnaline Orthoclase Biotite
Chlorides Sulphates Nitrates
rare rare
rare-common
rare rare
rare very rare very rare very rare rare rare rare
dominant gt60 abundant 30-60 very common 10-30 of the total mineral matter common 5-10 content in the coal rare 5-1 very rare lt1
22
Coal specifications
differences For example dehydration decomposition and oxidation of mineral matter which may occur during the laboratory process can affect the composition of the ash as follows
FeS04nHzO FeS04 + nHZO dehydration reduces the weight of CaC03 CaO + COZ decomposition ash and adds to
volatile matter
FeS + 20z FeS04 oxidation adds to weight of ash
Similarly partial loss of volatile constituents in particular mercury (Hg) potassium (K) sodium (Na) chlorine (CI) phosphorus (P) and sulphur (S) means that the ash is qualitatively and quantitatively quite different from the mineral matter that gave rise to it Its behaviour which is ultimately determined by its composition is also different If the ash sample is used for subsequent composition analysis the concentration of sodium and other volatile inorganic elements may be significantly lower than in the original mineral matter
Carbonate minerals are common constituents of many coals (see Table 5) These minerals liberate carbon dioxide (C02) on heating and therefore can contribute to the total carbon content of the coal as determined by ultimate analysis Whilst the COz content of the mineral matter is important for the correction of other specifications it is not normally included on coal specification sheets for combustion
24 Forms of SUlphur chlorine and trace elements
Procedures for determining these properties are described in various national and international standards (see Table 2)
Sulphur in coal is generally recognised as existing in three forms inorganic sulphates iron pyrites (FeS2) and organic sulphur compounds known respectively as sulphate sulphur pyritic sulphur and organic sulphur Although the total sulphur content provides sufficient data for most commercial applications a knowledge of the relative amounts of the forms of sulphur present is useful for assessing the level to which the total sulphur content of a particular coal might be reduced by preparation processes Commercial preparation plants can generally remove much of the pyritic sulphur but have little effect on the organic sulphur content
Pyrite is one of the substances which enhance the risk of spontaneous combustion by promoting oxidation and consequent heating of the coal (Bretz 1991a) Pyrite is also a hard and heavy substance which adds to the abrasion of coal mills (Cortsen 1983) (see Section 322)
It appears that in many cases some of the sulphur in the coal is retained in the ash as sulphate Thus the sulphate in the ash is invariably greater than the sulphate in the original coal when both parameters are expressed as fractions of the weight of original coal This effect is so large with the lower rank lignites that the ash yield may actually be greater than
the mineral matter content Kiss and King (1979) showed that between 0 and 99 of the organic sulphur in Australian brown coals may be retained in the ash as sulphate The thermal decomposition of carboxylate salts is particularly efficient in trapping organic sulphur as sulphate in ash With higher rank coals that do not contain carboxyl groups it is carbonates or the oxides formed from pyrolysis that tend to fix sulphur as sulphate It is evident that the amount of sulphate in ash depends on both the sulphur content of the coal and the concentration and nature of the materials capable of fixing it during ashing Various national and international standards specify procedures for determining sulphate in ash
Although not strictly part of the usual ultimate analysis procedure determination of chlorine which may be present in the organic fraction of the coal as distinct from the mineral analysis of the ash is often included Chlorine can enter the coal in the form of mineral chlorides in saline strata waters but this accounts for less than 50 of the total amount The bulk of the chlorine is present as CIshyassociated with organic matter probably as hydrochlorides of pyridine bases (Gibb 1983) In general chlorine content in most coals is quite low though there are exceptions For example some British coals can contain up to 1 chlorine (Given 1984)
In combustion chlorine from both alkali chlorides and the organic fraction of coal can combine with other mineral elements and contribute to deposition and corrosion Chlorine content is also used as an indication of potential fouling tendencies as the majority of the alkali metals responsible for fouling problems are present in the original coal associated with chlorine Chlorine can also affect the control of the pH (aciditylbasicity) in FGD plants (Jacobs 1992)
Apart from the major impurities in coal which are measured in the normal analysis there are a wide variety of trace elements which can also occur Clarke and Sloss (1992) have reviewed the typical concentrations of trace elements in coals There is a growing interest in the emission of trace elements from stacks as atmospheric pollutants and one can expect more attention to be given to this over the coming years (Swaine 1990) There has also been increased anxiety over the possible leaching of trace elements from ash or flue gas desulphurisation waste which may be deposited on the ground as means of disposal or use (Clarke and Sloss 1992) (see also Section 524)
25 Coal mechanical and physical properties
The commercial evaluation of a coal also involves assessments of physical properties A variety of tests have been developed to quantify physical properties of coal but each one is usually related to a particular end use requirement Table 6 lists standard measurements for coal physical tests which are considered relevant for handling and combustion
23
ASTM American Society for Testing and Materials AS Australian Standards BS British Standards Institution DIN Deutsches Institut fUr Norrnung ISO International Organization for Standardization
Bulk density flow properties fineness friability and dustiness all affect the handleability of coal
bulk density measurements are designed to evaluate the density of the coal as it might lie in a pile or on a conveyor belt (Folsom and others 1986c) the size distribution test is used to evaluate the size distribution of coal prior to pulverisation This measurement is important as it can be used to determine the suitability of a coal for a particular mill type and is used to assess the efficiency of the mill system Particle size distribution is also determined for the coal sample after air drying and pulverisation Pulverised coal fineness and size distribution is particularly important for burner performance (see Section 41) there are several tests to evaluate coal friability They are designed to determine the extent of coal size degradation and dusting caused by handling stockpiling and grinding
Most modem coal-burning equipment requires the coal to be ground to a fine powder (pulverised) before it is fed into the boiler The Hardgrove grindability index (HGI) is designed to provide a measure of the relative grindability or ease of pulverisation of a coal The test has changed little over the years Traditionally the HGI is used to predict the capacity performance and energy requirement of milling equipment as well as determining the particle size of the grind produced (Wall 1985a) Coals with high HGI are relatively soft and easy to grind Those with a low value (less than 50) are hard and more difficult to make into pulverised fuel (Wall and others 1985 Ward 1984) The grindability of coals is important in the design and operation of milling equipment A fall in HGI of 15 units can cause up to 25 reduction in the mill capacity for a given PF product as shown by the
10--1-----shyOJ sect 5 Cl r
eOl
09 pound
middotE 0 OJ ~
~ 08
lt5 z
constant PF size distribution
50 48 46 44 42
Hardgrove grindability index (HGI)
Figure 3 Mill throughput as a function of Hardgrove grindabaility index (Fortune 1990)
graph in Figure 3 Coals with high HGI values in general cause few milling problems
The abrasion index is a measure of the abrasiveness of a particular coal and is used in the estimation of mill wear during grinding (Yancey and others 1951) The abrasion index is expressed in milligrams of metal as lost from the blades of the test mill per kilogram of coal
The free swelling index (FSI) also called the crucible swelling number is used to indicate the agglomerating characteristics of a coal when heated Although primarily intended as a quick guide to carbonisation characteristics it can be used as an indicator of char behaviour during combustion A high swelling number suggests that the coal
24
Coal specifications
particle may expand to fonn lightweight porous particles that ash residue at high temperatures can be a critical factor in fly in the air stream and could contribute to a high carbon selection of coals for combustion applications Ash fusion content in the fly ash The extent of swelling is a function of temperatures are often used to predict the relative slagging the rate of heating final temperature and ambient gas and fouling propensities of coal temperature (Essenhigh 1981) so that the actual effects in practice are greatly dependent on combustion conditions The The test involves observing the profiles of specifically swelling number is also significantly affected by the particle size distribution of the sample (Ward 1984) Knowledge of the swelling properties of a coal can be used to avoid agglomeration problems in fuel feed systems (Hainley and others 1986 Tarns 1990) The size of the char particle after devolatilisation and swelling has been found to have an important influence on the kinetics of the combustion process 2 3 4 (Morrison 1986 Jiintgen 1987b) IT 5T HT
1 Cone before heating
The FSI can also provide a broad indication of the degree of 2 IT (or ID) Initial deformation temperature 3 ST Softening temperature (H=W) oxidation of a given coal when compared with a fresh 4 HT Hemispherical temperature (H=12W)
unoxidised sample or against a background history of 5FT Fluid temperature
measurement for a particular coal (ASTM DnO Shimada and others 1991)
Figure 4 Critical temperature points of the ash fusion The ash fusion test (AFT) measures the softening and test (Singer 1991 ASTM D1857) melting behaviour of coal ash The behaviour ofthe coals
Table 7 A summary of the major characteristics of the three maceral groups in hard coals (Falcon and Snyman 1986)
Maceral group Reflectance Chemical properties Combustion properties plant origin
Description Rank Reflected Characteristic Typical products on Ignition Burnout light element heating
Vitrinite woody trunks Dark to Low rank to 05-11 intermediate light intermediate ill ill branches stems medium grey medium rank hydrogen hydrocarbons volatiles jj jj stalks bark leaf bituminous 11-16 content decreasing j j tissue shoots and rank j j detrital organic Pale grey High rank 16--20 j j matter gelified bituminous vitrinised in White anthracite 20-100 acquatic reducing conditions
Exinite cuticles spores Black- Low rank -00-05 early methane volatile- jjjj jjjj resin bodies algae brown gas rich accumulating in sub- Dark grey Bituminous -05--09 hydrogen- oil decreasing jjj jjj acquatic conditions -09-11 rich with rank
Pale grey Medium rank -11-16 condensates bituminous wet gases (j) (j)
Pale grey High rank (decreasing) (=vitrinite) bituminous to white to shadows anthracite -16--100
Inertinite as for vitrinite but Medium Low rank 07-16 hydrogen- low fusinitised in aerobic grey bituminous poor volatiles oxiding conditions Pale grey Medium rank -16--18 in all ranks
to white bituminous and yellow to anthracite -18-100 (j) (j) - white
Capacity or rate j = slow Capacity or rate shown in parenthesis refers to vitrinite jj = medium jjj = fast jjjj = very fast
5 FT
25
Coal specifications
Table 8 Summary of coal ash indices (Anson 1988 Folsom and others 1986c Wibberley and Wall 1986 Wigley and others
Index Factors
Ash descriptor Base-acid ratio (BfA)
Ash viscosity T250 of ash degC (OF) Silica ratio
Siagging propensity Base-acid ratio (BfA) (for Iignitic ash CaO + MgO gtFe203) Siagging factor (for bituminous ash CaO + MgO lt Fe203) Iron-calcium ratio Silica-alumina ratio
Slagging factor degC (OF)
Viscosity slagging factor
Fouling propensity Sodium content
Fouling factor
Total alkaline metal content in ash (expressed in equivalent Na203)
chlorine in dry coal
Strength of sintered fly ash Psi
Temperature ash viscosity = 250 poise SiOl(Si02 +Fe203 + CaO + MgO)
(BfA)(S dry)
Fe20 3fCaO SiOlAh03 Maximum hemispherical temperature + 4(minimum initial deformation temperature)
5 T25o(oxid-TlOooO(red)
975 Fs
(Fs ranges from 10-110 for temperature range 1037-1593degC (1900-2900degFraquo
Na203 (for Iignitic ash CaO + MgO gtFe203) (for bituminous ash CaO + MgO ltFe203)
BfA(Na20 in ash) (for bituminous ash CaO + MgO ltFe203) BfA(Na20 water solublellow temperature ash) Na20 + K20 (for bituminous ash CaO + MgO ltFe203)
oxid oxidising conditions red reducing conditions
shaped cones made from ash prepared by the proximate analysis method with a suitable binder The cones are gradually heated in a furnace under either an oxidising or reducing atmosphere until the ash softens and melts Temperatures corresponding to four characteristic cone profile conditions are noted These conditions are shown in Figure 4 The four cone shapes are defined as follows
initial deformation - the initial rounding of the cone tip softening temperature - height equal to width hemispherical temperature - height equal to one-half width fluid temperature - height equal to one-sixteenth width
Under reducing conditions AFTs are lower due to the greater fluxing action (basicity) of the ferrous ion (FeO) compared with the ferric ion which is present under oxidising conditions
The heating value or calorific value is the single most important coal index or quality value for use in steam power stations since it provides a direct measure of the heat released during combustion The energy liberated by a coal on combustion is due to the exothermic reactions of its
hydrocarbon content with oxygen Other materials in the coal such as nitrogen sulphur and the mineral matter also undergo chemical changes in the combustion process but many of these reactions are endothermic and act to reduce the total energy otherwise available
The standard laboratory test measures the gross heating value that is the total amount of energy given off by the coal including latent heat of condensation of vapour formed in the process Under practical conditions water vapour and other compounds (acid forming gases) can escape directly to the atmosphere without condensation and the recoverable heat given off under these conditions is known as the net heating value It can differ most significantly from the gross heating value in coals that have a high moisture content such as brown coals or lignites as the main difference between the two values is the latent heat of evaporation of water The net heating value can be calculated from the standard laboratory-determined gross value based on factors such as the moisture sulphur and chlorine contents of the coal concerned An example of a conversion formula which relates gross and net heating value reads (ISO 1928)
Qn = Qg - 0212 H - 00008 0 - 00245 M MJkg
26
Coal specifications
1989)
Tendenciesvalues
Low Medium Iligh Severe
gt1302 (2375) 1399-1149 (2550-2100) 1246-1121 (2275-2050) lt1204 (2200)
Viscosity proportional to silica ratio
lt05 05-10 10-175
lt06 06-20 20-26 gt26
lt031 or gt300 031-30 Low ~ High
gt1343 (2450) 1232-1343 (2250-2450) 1149-1232 (2100-2250) lt1149 (2100)
05-099 10-199 gt200
lt20 20-60 60-80 gt80 lt05 05-10 10-25 gt25 lt02 02-05 05-10 gt10 lt01 01-024 025-07 gt07
lt03 03-04 04-05 gt05
lt03 03-05 gt05
lt1000 1000-5000 5000-16000 gt16000
where Qn = net heating value Qg = gross heating value H = hydrogen (percentage fuel weight) 0 = oxygen content (percentage fuel weight) M = moisture content (percentage fuel weight)
In North America boiler thennal efficiency is usually quoted on the basis of the gross heating value whereas most European countries use net heating value
Various fonnulae for predicting the heating value of coal from ultimate analysis have been developed On a dry mineral matter-free basis the heating value relates directly to the composition of the coal substance Some of these fonnulae are reviewed by Mason and Gandhi (1980) and Raask (1985)
Petrographic analysis of coals is increasingly being used to add to the information necessary to assess the suitability of coal for combustion in a particular power station Coal petrology describes coal in tenns of its maceral and mineral matter composition (see Table 7) These components can be recognised and measured quantitatively with the aid of a microscope A comprehensive review of the features that
characterise the various members of the maceral groups and rules for their microscopic identification can be found in the Intemational Handbook of Coal Petrography (ICCP 1963 1975 1985) Stach and others (1982) gives an overview of the macerals and their physical and chemical properties and Teichmiiller (1982) Given (1984) Davis (1984) Falcon and Snyman (1986) and Carpenter (1988) provide a good description of the origin of macerals
Maceral composition can be linked to properties of significance for describing combustion perfonnance Relatively little attention has been given to assessing maceral effects on grindability The literature that is available provides a confusing and somewhat contradictory picture This could be a consequence of the relative grindabilities of vitrinite and inertinite reversing as the rank of coal increases (Unsworth and others 1991) The preferential population of macerals within particular size ranges has been reported by several investigators (Falcon and Snyman 1986 Skorupska and Marsh 1989) For example an investigation involving a medium rank bituminous coal revealed a difference between the grindability of vitrinite and inertinite of approximately 15 units with inertinite displaying a HGI value averaging
27
Coal specifications
55 Such differences can significantly influence mill throughput (Unsworth and others 1991)
In certain circumstances it has been reported that a petrographic assessment of coal rank has advantages over the other techniques used as standards (Neavel 1981 Unsworth and others 1991) Parameters such as volatile matter content fixed carbon heating value swelling indices are average properties of a coal sample As such they reflect coal rank but they are also affected by variations in maceral composition Measurement of vitrinite reflectance is widely used as an index of coal rank
Earlier investigators recognised that the carbonaceous materials present in fly ash were predominantly forms of inertinite (Yavorskii and others 1968 Nandi and others 1977 Kautz 1982) Since that time the influence of maceral composition on coal reactivity during combustion has been the subject of considerable study (Jones and others 1985 Falcon and Falcon 1987 Oka and others 1987 Shibaoka and others 1987 Bend 1989 Diessel and Bailey 1989 Skorupska and Marsh 1989 Sanyal and others 1991) It has now been applied in many cases to explain problems that occur during combustion when other traditional tests such as proximate analysis have failed (Sanyal and others 1991)
The application of petrographic assessment as a predictive tool is still believed to be some way off Two reasons for this are
the subjective identification and different criteria being applied by the different countries to distinguish macerals has led to unsatisfactory reproducibility in results This has been illustrated in international exchange exercises conducted by the ICCP in the past It has been clear for some time that there is a need to reduce subjectivity to a minimum This may be achieved by using automated assessment techniques limited validation on a power station boiler scale of the influence of macerals on boiler performance Present operational procedure at boiler scale does not lend itself well to simultaneously monitor performance and allow for full petrographic assessment of the feedstock coal
26 Calculated indices In an effort to extend the use of laboratory results a number of empirical indices have been developed based on the
measurements discussed in the previous subsections These indices have been used to relate coal composition to the performance of power station components While the indices are not measurements as such in many cases they are utilised in the same manner as coal properties The accuracy reproducibility and applicability of these indices depend directly on the specific measurement procedures employed Indices have been developed for
rank reactivity ash descriptor ash viscosity slagging propensity fouling propensity
Rank relationships with coal properties as used nationally and internationally are summarised earlier in Figure 2
Some combustion reactivity indices use a relationship of the proximate volatile matter and fixed carbon of a coal known as the fuel ratio lllustrations of the relationship are given in Section 421
The indices used to describe ash behaviour are summarised in Table 8 The indices can be included in coal specification sheets to help assess the suitability of a coal for combustion How they are used and their relationship to performance are discussed in Section 422 of this report
27 Comments Most coal evaluation testing for combustion relies on empirical procedures which were developed primarily for the carbonisation industry town gas and blast furnace coke manufacture using simple laboratory equipment under conditions which were intended to represent those found in that type of process Despite the shortcomings the techniques required to perform the tests such as for proximate analysis are so simple that they lend themselves to automation This removes much of the risk of operator error and produces repeatable results
As operating requirements become more stringent the weaknesses of some of these techniques are becoming increasingly apparent There is a growing need to develop tests and specifications which reflect more closely the conditions found in power station boilers
28
3
steam generator
burners
mills
environmental control
I
Pre-combustion performance
environmental controlcoal handling
and storage
ash transport fans
The following three chapters describe the effect of coal quality parameters on the performance of various component parts of coal-frred steam generator systems Figure 5 illustrates the components of a typical power station The main power station components include
coal handling and storage mills fans burners boiler ash transport technologies for controlling emissions
This chapter focuses on effects of coal quality on the pre-combustion components of a power station
31 Coal handling and storage The coal handling equipment includes all components which process coal from its delivery on site to the mills This includes a large amount of equipment which (depending on power station design) may include unloading facilities hoppers screens conveyors outside storage bulldozers reclaimers bunkers etc and of course the coal feeders to the mills (Folsom and others 1986b) A high level of automation and remote control is often incorporated in
Figure 5 Typical power station components
29
Pre-combustion performance
Table 9 Illustrative example of USA coal storage requirements (Folsom amp others 1986b)
Coal
Lignite Subbituminous Bituminous
midwest eastern
Heat to turbine 106 kJh 4591 4591 4591 4591 Boiler efficiency 835 862 885 905 Coal heat input 106 kJh 5499 5326 5185 5073 Coal HHV MJkg 14135 19771 26284 33285 Coal flowrate th 429 297 217 168
Design storage requirements t Bunkers 12 hours 5148 3564 2604 2016 Live 10 days 102960 71280 52080 40320 Dead 90 days 926640 641520 468720 362880
Storage time for eastern bituminous plant design t Bunkers hours 47 68 93 120 Live days 39 57 77 100 Dead days 35 51 69 902
equivalent storage time for a plant designed for eastern bituminous coal but fired with the coals listed
modern coal handling facilities including sophisticated stacking-out and reclaim facilities to achieve some degree of coal blending capability Slot bunker systems with bulldozer operated stacking and reclaimers are still preferred by many utilities because of capital cost savings and greater flexibility of stockpile management
Coal storage can be divided into two categories according to the purpose live (active) storage with short residence time which supplies fIring equipment directly and dead or reserve storage which may remain undisturbed for many months to guard against delays in shipments etc Live storage is usually under cover and reserve storage outdoors
When outdoor storage serves only as a reserve the normal practice is to take part of an incoming shipment and transfer it directly to live storage within the station while diverting the remainder to the outdoor pile
The coal storage components are generally sized to provide capacity equivalent to a fIxed time period of fIring at full load (McCartney and others 1990) Typical values are 12 hours for inplant storage in bunkers ten days for live storage and more than 90 days for reserve storage Capacity of the reserve pile can be for example a minimum 60-day supply at 75 of the maximum burn rate These time periods are specifIed by the architectengineer based on the utilitys desired operating procedures and other constraints such as political legislation for strategic stocking The key parameters for assessing the quantity of coal required are
power station capacity heat rate coal heating value
Steam generators of a given capacity operating at steady load
require a fIxed heat input per unit of time regardless of coal heating value (Carmichael 1987) Therefore if the actual heating value of the coal is reduced then the storage capacity and quantities that must be delivered to the utility via the transport system must be increased For example Folsom and others (l986b) compared the storage requirements for four coals of differing rank supplying a 500 MW steam-electric unit (see Table 9) For all performance parameters to remain constant over a wide range of coal heating values substantial variations in coal flow rate at full load are required with factors of as much as 21 in some cases The coal storage requirements for specifIc time periods reflect this same range of variation Also shown are the storage times required for fIring alternate coals in a unit designed to fIre a high heating value fuel an Eastern USA bituminous coal These changes may not affect the ability to operate the unit at high capacity for short time periods However the equipment which transports the coal may need to operate more frequently and this could limit the ability to fIre at full station capacity over an extended period Also normal power station operating procedures may need to be modifIed to permit fIlling the bunkers more than once per day etc
Most of the equipment which transports the coal operates intermittently Thus coal quality changes which result in coal flow rate changes will vary the duty cycle for the transport equipment An increase in flow rate requirements caused by a decrease in coal heating value or an increase in boiler heat rate will increase the duty cycle and may affect unit capacity Provided that these changes in flow rate are small or of limited duration most power stations will be able to tolerate them with no equipment modifIcations Large increases in flow rate for example those that may occur due to a shift from a bituminous coal to a lignite as described in Table 9 may require such long duty cycles that the normal operating procedures of the power stations and maintenance intervals
30
Pre-combustion performance
Table 10 Conveyor Equipment Manufacturers Association (CEMA) material classification chart (Colijn 1988a)
Major class Material characteristics included Code designation
Density
Size
Flowability
Abrasiveness
Miscellaneous properties or hazards
Bulk density loose
Very fine 200 mesh sieve (0075 mm) and under 100 mesh sieve (0150 mm) and under 40 mesh sieve (0406 mm) and under
Fine 6 mesh sieve (335 mm) and under
Granular 127 mm and under
Lumpy 76 mm and under 178 mm and under 406 mm and under
Irregular stringy fibrous cylindrical slabs etc
Very free flowing - flow functiongt 10 Free flowing - flow function gt4 but lt10 Average flowability - flow function gt2 but lt4 Sluggish - flow function lt2
Mildly abrasive - Index 1 - 17 Moderately abrasive - Index 18 - 67 Extremely abrasive - Index 68 - 416
Builds up and hardens Generates static electricity Decomposes - deteriorates in storage Flammability Becomes plastic or tends to soften Very dusty Aerates and becomes fluid Explosiveness Stickiness - adhesion Contaminable affecting use Degradable affecting use Gives off harmful or toxic gas or fumes Highly corrosive Mildly corrosive Hygroscopic Interlocks mats of agglomerates Oils present Packs under pressure Very light and fluffy - may be windswept Elevated temperature
Actual kgcoal flow
Azoo AIOO
~
C~
E
1 2 3 4
5 6 7
F G H J K L M N o P Q R S T U V W X Y Z
may be inadequate In such extreme cases the capacity of the transfer equipment may be insufficient even with continuous operation such that modifications will be required In some power stations it may be possible to increase the capacity of the transport equipment For example conveyor belt speeds may be increased However this can also lead to dust problems and increased spillage especially with friable coal
Unlike the other coal transport equipment the coal feeders operate continuously Thus any change in coal flow rate requirements must be met with an immediate change in feeder speed Coal feeders are usually designed with excess capacity so that minor changes in coal flow rate requirements can be tolerated easily The major changes required by significant changes in coal heating value such as switching
from a bituminous coal to a lignite would be beyond the capacity of most coal feed systems Another factor to consider is the feeder turndown Many feeders have a minimum operating speed beneath which problems such as uneven flow can occur
In addition to changes in the required coal flow rates coal characteristics can produce other detrimental effects on handling and storage systems
In a survey carried out at a coal handleability workshop (Arnold 1988) attendees from utilities and the mining community were asked to rank the problems from one (1 - worst) to ten (10 -least) The ratings are indicated next to each problem
31
Pre-combustion performance
plugging in bins (1) feeders (2) arching and caving in storage (10) flowability hang-up in bins (3) sticky coal on belts (4) freezing in transport (5) storage (8) dusting on conveyors (6) in stockpiles (7) oxidationspontaneous combustion (9)
Other concerns mentioned included abrasiveness of coal causing chute wear wet fuel hang-up in transfer towers sticky fuel in downcomers spillage and sliding from belts due to wetness hang-up in breakers excessive surface moisture and coal sticking in bottom-dumped rail cars Whilst relationships between coal properties and handleability have been established these are not the same as those needed for combustion purposes In fact some coal specifications do not usually include parameters which reflect the handling and storage properties of coal Colijn (1988a) reported that the Conveyor Equipment Manufacturers Association (CEMA) have made an effort to establish a listing of material properties and characteristics which influence the handling and storage of granular bulk materials including coal as shown in Table 10 The coding system has been developed to describe particular material properties such as density size flowability and abrasiveness Where material handling characteristics are in general not easily quantifiable they are listed as hazards - watch out Table II shows typical CEMA codes for various coal
Table 11 CEMA codes for various coals (Calijn 1988a)
Material description CEMA material code
Coal anthracite (River amp Culm) 6OB635TY Coal anthracite sized - 127 mm 58C-225 Coal bituminous mined 50 m amp under 52A4035 Coal bituminous mined 50D335LNXY Coal bituminous mined sized 50D335QV Coal bituminous mined run-of-mine 50Dx35 Coal bituminous mined slack 47C-245T Coal bituminous stripping not cleaned 55Dx46 Coal lignite 43D335T Coal char 24Cl35Q
x refers to a range of particle sizes
311 Plugging and flowability
The economic impact of plugging of coal transport facilities can be significant resulting in added manpower costs for clearance partial unit deratings or in some cases total shutdowns For example at 15 $MWh a typical 575 MW unit could lose over 1000 $h income as a result of partial deratings for each plugged silo (Bennett and others 1988)
No flow or limited flow problems are often due to the formation of stable arches andor increases in wall friction (Arnold 1990) Binsilo blockages occur when the coal has become sufficiently adhesive to form a stable arch which supports the weight of the coal above it Increases in wall friction which is a measure of the sliding resistance of the coal against the bin wall will result in coal adjacent to the wall moving slower than that in the centre zone This gives
mass flow funnel flow expanded flow
Figure 6 Typical flow patterns in bunkers (Colijn 1988a)
rise to different flow patterns in various parts of the bin (see Figure 6) For most coals three to four days outdoor storage increases the chances of one or both of the above problems occurring Coal flowability is directly related to various coal characteristics depending on the coal rank Some of the major contributing properties are (Llewellyn 1991)
surface moisture particle size distribution clay content changes in bulk density
Surface moisture is considered the most critical factor There is a level below which regardless of other factors coal flow problems do not occur There is also a critical surface moisture at which maximum adhesion and bulk coal strength will occur Above this level additional water flows away rises to the surface or in the extreme decreases strength due to slurry formation Adding moisture to dry coal first creates a lubricating effect and allows particles to slide against each other more easily and pack into a denser stronger material Surface tension develops as a form of physico-chemical bonding (known as hydrogen bonding) increases between water and coal particles
Particle size distribution contributes to flowability problems because it determines the available surface area and hence adhesion characteristics The proportion and size of the smallest particles in bulk coal have a great effect on its handleability In some coals the ash and clay content which is inherent in the coal concentrates in the fines fraction (see Table 12) This also influences coal flowability characteristics Average particle size can be affected by coal handling procedures and equipment or by natural causes A major factor influencing the size composition of a coal product is its friability Friability is a combination of the impact strength and fracture cleavage characteristics of the coal and its susceptibility to degradation due to a rubbing action during handling A high fines content if combined with a critical moisture level can result in a coal with very poor handling properties (Llewellyn 1991) In low rank coals large pieces may fall apart and produce excess fines in dry air If the coal is subsequently rewetted the combination
32
Pre-combustion performance
Table 12 Analysis of ash and clay distribution in a coal by mesh size (Bennett and others 1988)
Property Base fuel +6 Mesh (+335 mm)
6-50 Mesh (036-030 mm)
50-100 Mesh (030-015 mm)
-100 Mesh (-015 mm)
Weight Ash (Dry) Silica
10000 2277 6740
4514 1702 5850
4512 2320 6490
765 3596 7790
209 4153 8380
of increased surface area and moisture can have a substantial impact on flow characteristics
The clay content of coal affects its cohesive characteristics Increased clay content in strip mined subbituminous coal and lignites has been shown significantly to increase wall friction and shear strength at a given moisture content (Bennett and others 1988)
If all of the above factors increase simultaneously that is high surface moisture high clay high fmes percentage and coal is stored in a bin for several days drastic increases in coal bulk shear strength lead to significant adhesion bridging and consequent coal flowability problems
There are no coal specifications which relate to coal bulk shear strength although tests have been developed which provide bulk shear strength values for coals They are used as a measure of the cohesive strength or stickiness and have been used as a quantifying factor for problem coals Shear strength can be measured using either a rotational or a linear translational instrument Results from the rotational shear test can be obtained within an hour and may be used on-site to provide real time analyses (Bennett and others 1988 Colijn 1988a) The principle of the rotational shear tester is to provide an equally distributed shearing force across a horizontal plane in the coal sample This is done while the sample is placed under varied loads The bulk shear strength determined for a particular fuel handling situation can be represented as a value in applied pressure or as an arbitrary relative flow factor value (FFV) The FFV can be plotted relative to moisture and clay values A critical arching diameter (CAD) can be extracted by combining results from a shear tester with the bulk density of the coal Calculations can then be made for the geometric configuration of each type of coal container for particular types of coal thus negating possible problems of archingplugging in a binsilo Figure 7 shows the data derived from shear tests for more than twenty coals conducted by Colijn (1988b) The CAD was plotted against the surface moisture content for the coals and while a clear relationship between increasing moisture content and increasing CAD exists there is significant data scatter As discussed earlier other investigators (Blondin and others 1988 Arnold 1991) have shown that the amount of clay and fines also influence the CAD
As many coals have a tendency to increase their strength after a few days of consolidation it is often necessary to test the coals under these conditions For these cases a coal sample would be kept inside the shear cell under pressure for a number of days to simulate the time period during which the coal may be contained within a bin or silo Arnold (1991) reported a study conducted to define further the relationship
mass flow - instantaneous
2 E ~
til Q) E til 0 0) c
c ()
ro (ij ()
8
0
0
Figure 7
3 E
~ Q) E til 2 0 0)
~ c ()
ro (ij ()
8
0
0 0 0
o
0
6 o 00 oo0
o D cPo DO
0 CI o~ 0_o
--tJ 0 0 0 _ - shy
9 - Data for a variety of coal samples
2 4 6 8 10 12 14 16
Surface moisture
Surface moisture versus critical arching diameter (CAD) determined from shear tests (Coljjn 1988b)
3-day consolidation
10 moisture
+ 8 moisture
6 moisture
+ +
0
0 2 4 6 8 10 12 14
Fines -44 ~m (-325 mesh)
Figure 8 Three-day consolidation critical arching diameter (CAD) versus per cent fines in coal as a function of moisture content (Arnold 1991)
of coals and their handling behaviour Six coals that were combusted at an Eastern USA power station were selected The coals had very similar chemical analyses and all met the power station coal specification but exhibited a range of handling characteristics As an illustration of some of the preliminary results of the study Figure 8 shows the influence of the percentage fines (particles less than 44 lm in diameter) moisture content and consolidation time on the CAD calculated from shear tests conducted on one of the coals The instantaneous CAD values are not shown in Figure 8 but were in fact 30 lower in value than the three-day consolidation values Generally for all the coals studied the maximum value occurred at the highest moisture
33
Pre-combustion performance
contents and there was a tendency to increase with increasing fines content and increases in consolidation time
More recently Rittenhouse (1992) reported the development of a series of simplified empirical tests that can be run by power station staff members that make it possible to identify potential problem coals The results of the tests are indices that characterise the flowability of coal The individual indices are
arching index ratholing index hopper index chute index flow rate index density index
These can also be used to indicate when hopper modifications may extend the operating range of the system so that coals that are less than free flowing can be handled The tests are reviewed in greater detail by Johanson (1989 1991) Arnold and OConnor (1992) have recently reported the development of another simplified test that can be used more easily on-site and has been validated against the tri-axial shear tester
Coal flowability can be modified by the use of chemicals which specifically enhance the flow of wet coal Additive selection and performance depend greatly on fuel quality (Bennett and others 1988) The effectiveness of particular additives on problem coals is assessed by measurement of shear strength values produced
312 Freezing
Although it is difficult to assess the cost related specifically to coal moisture freezing during cold weather some of the potential problems are as follows
production losses at the mine beneficiation plant and the utilities increased labour costs associated with frozen coal removal less safe working conditions costs related to operation of thawing and mechanical removal equipment transport equipment damage due to mechanical or thermal means of removing frozen coal from ships rail cars or trucks demurrage costs on rail cars accelerated rail wear andor derailment
Work done in the mid-1970s showed that surface moisture of a coal caused the problems For freezing to occur the coal being handled must be exposed to sub-freezing temperatures for a sufficient period of time It is generally accepted however that no problems with handling should be expected unless the surface moisture exceeds approximately five per cent Total moisture content of the coal is inadequate as a sole indicator since coal that has a high inherent moisture may not freeze at 20 or more total moisture while coal with a low inherent moisture
may freeze and cause severe problems at seven per cent or below
Each coal type has a characteristic inherent moisture content defined here as the moisture contained in the fine pore structure itself Depending upon rank porosity and hydrophilicity of the coal inherent moisture ranges from less than one per cent to greater than 20 of the coal mass While surface moisture is undoubtedly the primary cause of coal freezing and the consequent handling problems other factors also influence the situation For example Connelly (1988) reported that at lower temperatures the increased viscosity of water renders the dewatering of coal processes less efficient Total moisture content of dewatered coals can be expected to increase at lower temperatures as shown in Figure 9
90
86 bull
t-O)
s 82 bull
iiimiddot0 E 78
Cii l 0V 0)
cr 74
72 bull
66
4 10 20 30 40 50 Temperature degC
Figure 9 Dewatering efficiency versus temperature (Connelly 1988)
Particle size is also important If the coal particle size were consistently large that is 127 cm (h inch) or larger it would be unlikely that the particles would pack together sufficiently to freeze and cause a serious problem Current mining methods use continuous longwall techniques to extract coal with consequent breakage and fines production For this reason it is impractical for beneficiation plants to furnish a product with a minimum particle size of 127 cm or greater for all shipments unless some form of agglomeration process is used Typically coal being shipped contains a wide range particle size distribution and a substantial amount of material less than 016 cm in diameter Because of this particle size distribution the fine particles of coal can pack between the larger ones and form a more continuous solid mass The finer particle size coal also tends to hold a larger percentage of surface moisture With the finer particle size and increased surface water more particle-to-particle contact occurs accentuating the freezing problems
The freezing process can be offset by the use of additives such as urea calcium chloride solution or polyhydroxy alcohols (Hewing and Harvey 1981 Boley 1984 Connelly 1988)
34
Pre-combustion performance
313 Dusting
Most bulk solid materials have the potential to generate dust during handling Dust can be generated while the coal is in motion such as during transfer from transport to storage and even as wind borne dust from stockpiles This creates safety as well as environmental problems The extent of dust problems may be related empirically to particle size distribution (the amount of fines) moisture content moisture holding capacity and the wind speed (Mikula and Parsons 1991) Nicol and Smitham (1990) reported that in the case of Australian export coals they are sold with a nominal top size of 5 cm but as was discussed earlier there is a wide range of size distributions covered by this specification Figure 10 shows the broad range of coal sizes that are exported This implies that the potential dustiness of coal is a variable with coal source Sherman and Pilcher (1938) have done considerable work in the area of dust control and have tested the size of dust particles in the ASTM D547 dust cabinet test and found that the diameters of particles range from 11 to 55 11m Devised in the 1930s the test is perceived to be somewhat dated as it was originally designed to simulate coal delivery into a bin
Nicol and Smitham (1990) investigated the effects of moisture on the lift-off potential of different coals over a range of wind velocities using a laboratory wind tunnel facility They found that depending on the coal size fraction the velocity to remove wet particles was between 25 and 75 greater than the dry particle removal velocity Alternatively the amount of coal removed at a given velocity is reduced as the moisture content increases Figure 11
99
80
E 60 -E 7 40
if ro 0
20 0
N middotw 10 m 0 c 5J
shaded area encompasses 90 of export coals with coarsest (lower) and finest (upper) size disributions also shown
0125 025 05 2 4 8 16 315 63 Particle Size mm
Figure 10 Size distributions of Australian export coal (Nicol and Smitham 1990)
illustrates the effect and shows that a critical moisture content of about 9 in the coal can be reached at which coal removal can be largely prevented The effects of different coals show up most clearly in the moisture content to prevent any dust emission that is the intercept on the moisture axis in Figure 10 Table 13 summarises the results for the three coals of different properties Rank and chemical properties such as volatile matter content are poor indicators of the propensity for different coals to dust Porosity as reflected in the moisture holding capacity does provide a useful indicator of the potential dustiness of coal Coals with a low moisture holding capacity that is a low equilibrium moisture have little internal porosity so that once this internal volume is filled the excess water remains at the particle surface where it is available to form bridges of water between adjacent particles preventing their removal in an air stream High moisture capacity coals require a greater amount of water to fill the internal volume before water is available at the surface to be an effective dust control agent Jensen (1992)
2000
o
N
E Oi ui Cf)
g Cii 0 ()
Q) gt ~ S E J u
1500
1000
500
0
0
0 0
0 0
amp0
0 ~ 0
0 0
0
0
o 2 4 6 8 10 12
Total moisture
Figure 11 Coal lift-off from a stockpile as a function of total moisture content (Nicol and Smitham 1990)
Table 13 Effect of coal properties on critical lift-off moisture content (Nicol amp Smitham 1990)
Coal Critical moisture Reflectance Australian coal Moisture holding content Ro max rank nomenclature capacity
1 100 094 high volatile bituminous A 25 2 115 120 medium volatile bituminous 40 3 210 073 high volatile bituminous A 120
66
35
Pre-combustion performance
reported that work carried out by ELSAM Denmark has shown that coals with a sUlface nwisture content of 2-3 was sufficient to prevent dusting of some coals
314 Oxidationspontaneous combustion
All coals when stored tend to combine to some extent with oxygen from the air in a process known as weathering (Davidson 1990) This causes some loss of heating value generally less than 1 in the first year of storage for most coals but may be up to 3 for low rank coals - and can change firing characteristics (Singer 1989a) Weathering also tends to promote reduction in size or crumbling (Llewellyn 1991)
Llewellyn (1991) also reported that grindability tests carried out on both fresh coal supplies and the coal stored on the surface of a stockpile indicated a clear separation in behaviour Surface samples were reported as being significantly harder (average 43 HGI) to grind than the fresh coal supply samples (average 52 HGI) The hardness increased with the age of the stockpiled coal A similar clear separation was found between the surface and the interior of the stockpile
Oxidation releases heat and if conditions in the stockpile are such that it occurs at a sufficiently rapid rate enough heat can be generated to cause spontaneous combustion (Sebesta and Vodickova 1989)
In brief the coal properties that have been found to influence oxidation and spontaneous combustion are
rank (heating value or volatile matter) moisture content ash content particle size
Malhotra and Crelling (1987) reported that as the rank of coals decreases the susceptibility for spontaneous combustion increases Cacka and others (1989) suggested that this phenomenon may be related to the increasing content of aliphatic structures which have a higher propensity to react with oxygen than aromatic structures present in coal However there are many anomalies to this straight rank order susceptibility Chamberlain and Hall (1973) have in fact pointed out that some higher rank coals may be more susceptible to spontaneous combustion
The mechanism of water adsorption into the pores of coal also releases heat so that heating in a stockpile will be dependent to some extent upon the inherent moisture (Matsuura and Uchida 1988 Iskhakov 1990) In most cases excess moisture can suppress the heating process (Taraba 1989) although cases have been reported where addition of water to an overheating stockpile can exacerbate the problem and these have been discussed in greater detail in a review by Chen (1991)
The mineral matter composition of coals can influence their susceptibility to oxidation Dusak (1986) reported incidents where mineral matter can play the role of oxidation
promoters by increasing oxidation rate and heat emission due possibly to exothermic reactions of the mineral matter itself with oxygen Work by Cacka and others (1989) determined that iron and titanium were particularly active in the coals under investigation Nemec and Dobal (1988) reported the influence of pyritic sulphur The magnitude of the influence on the oxidation process depends upon mineral matter size and its dissemination within the coal along with the rank moisture content and size of the coal
Particle size influences the surface area available for oxidation Several workers have reported that the smaller the particle size the greater the heat build up within coal stockpiles (Brooks and Glasser 1986 Nemec and Dobal 1988 Llewellyn 1991)
A number of tests have been devised to assess the extent of oxidation of a coal and its susceptibility to spontaneous combustion These include
crossing point test This measures the ignition temperature of a coal sample when it is heated at a constant temperature rate in a small cylindrical furnace The ignition temperature is measured as that at which the coal temperature crosses or becomes greater than the furnace temperature (Brown 1985) This can also be known as the runaway temperature (Gibb 1992) Differential thermal gravimetric analysers and calorimeters are also used to carry out a similar form of test (Clemens and others 1990 Shonhardt 1990) free swelling index test (see also Section 25) Shimada and others (1991) used free swelling index to monitor the extent of weathering of coals in a stockpile The swelling index of a Polish coal (K11) was seen to decrease significantly after a short storage time of three months (see Figure 12) It could also be used to distinguish between coal samples taken from the body (K11) of the coal stockpile and those from the slope (K11 slope) The test can only be applied to coals that exhibit a high initial swelling index as some coals with low initial swelling index (such as Kl in Figure 12) do not give any perceptible change after storage spectroscopic techniques Berkowitz (1989) has reviewed the spectroscopic methods utilised to detect oxidation of coal These can include Fourier transform shyinfra red (FTIR) spectroscopy electron spin resonance (ESR) nuclear magnetic resonance (NMR) and fluorescence microscopy (pavlikova and others 1989 Bend 1989)
Most of the above tests are not standardised With the exception of FSI which is generally used as an indicator of the caking nature of coals they usually are not included in a typical coal specification
At present none of the above effects can be quantified accurately The overall impact on operation and any required modifications must be based primarily on experience The influence of coal quality on the spontaneous combustion of the coal can be minimised by careful layout and construction of the stockpiles
36
Pre-combustion performance
bull 6
--- K1
0 K11
x L K11 slope 5 0
(]) 0 4 0 ~
0OJ sect 3CD ~ 0
(f)
2
L ~ - - - - - - - - - - - - 1f - - - - - - - - - - -- - - - - - shy II I
o 3 5 7 9 11 13 15 17 30 40 50 60 70
Storage time months
Figure 12 Influence of storage time on swelling index (Shimada and others 1991)
The special requirements for low rank coal storage are reviewed in an lEA Coal Research report entitled Power generation from lignite (Couch 1989)
32 Mills Most large steam-electric units are direct fIred that is the coal is supplied to the mills and is pulverised continuously with direct pneumatic transport of the pulverised coaVair mixture to the burners Thus the performance of the mills has a direct effect on the performance of the unit In modern practice a single mill can supply several burners In tangentially fIred systems all four bumers on a single elevation are typically supplied by a single mill In wall fIred systems a single mill may supply a complete row or another symmetrical array of burners A common design practice is to size systems to achieve full load with one or more mills out of service This allows time for maintenance and allows the spare mill to be brought on-line in the event that a failure occurs in one of the other mills
Because of their heterogeneous nature coals used for combustion can exhibit a wide range of grindabilities and require different milling actions to produce a suitably sized product Fine grinding of coal - generally 70 or more passing 75 11m (200 mesh) - is the standard commonly adopted to assure complete combustion of coal particles and to minimise deposits of ash and carbon on heat absorbing surfaces (Carmichael 1987) The different mill designs can be classified according to speed
low-speed mills are of the balVtube design with a large rotating steel cylinder and a charge of hardened balls Coal grinding occurs as the coal is crushed and abraded between the balls medium-speed mills are typically vertical spindle designs and grind the coal between rollers or balls and a bowl or face There are a number of designs in service differing in the specific design of the equipment which rotates size and shape of the grinding elements etc high-speed mills have a high-speed rotor which impacts and breaks the coal
Table 14 Preferred range of coal properties (Sligar 1985)
Mill type Low speed
Maximum capacity tJh 100 Turndown 41 Coalfeed top size mm 25 Coal moisture 0-10 Coal mineral matter 1-50 Coal quartz content 0-10 Coal fibre content 0-1 Hardgrove grindability
Medium High speed speed
100 30 41 51 35 32 0-20 0-15 1-30 1-15 0-3 0-1 0-10 (0-15)
index 30-5080 40-60 60-100 Coal reactivity low medium medium
The range of properties listed above is a preferred range and operation outside these limits is possible
Numerical values for the preferred range of coal properties appropriate for each mill type are given in Table 14 Most large steam-electric units use balVtube or vertical spindle mills
Coal mills integrate four separate processes all of which can be influenced by coal characteristics
drying grinding classifIcation transport
321 Drying
Earlier mills used external dryers before the coal was fed to the mills placing an economic disadvantage on the system Internal drying was developed to overcome this The surface moisture of the coal must be evaporated in the mill to avoid agglomeration of the particles (Sadowski and Hunt 1978) As the primary air is used for conveying the coal the only variable for drying is the temperature of this air The primary air temperature is adjusted to achieve a mill discharge temperature high enough to ensure complete drying in the
37
Pre-combustion performance
Table 15 Maximum mill outlet temperatures for vertical spindle mills (Babcock amp Wilcox 1978 Singer 1991)
Maximum temperature degC (OF)
Coal Babcock amp Wilcox Combustion Engineering
High volatile 66 (150) 71-77 (160-170) bituminous
Low volatile 66-79 (150-175) 82 (180) bituminous
Lignite 49-60 (120-140) 43-60 (110-140)
grinding zone For example Table 15 lists the maximum mill discharge temperatures recommended by Babcock amp Wilcox and Combustion Engineering The discharge temperatures are fixed for safety reasons and are dependent on coal type For bituminous coals the value is usually between 65degC and 90degC with the lower value for fuels of high volatility to reduce the potential for mill fires Higher temperatures of over 100degC have been reported to be used in some cases (Jones and others 1992) Standard proximate analysis volatile matter tests have been used to provide some indication of the likelihood of spontaneous combustion High volatile matter coals are more reactive and more susceptible to spontaneous combustion under these conditions
The primary air temperature required to dry the coal depends on several factors including its moisture (or ice) content temperature and specific heat together with airfuel ratio and mill design The required air temperature may be calculated via a simple energy balance (Folsom and others 1986b)
Figure 13 shows the effect of coal moisture on primary air temperature requirements for vertical spindle mills manufactured by Babcock amp Wilcox and Combustion Engineering As the moisture content of the coal increases so the inlet air temperature must increase to compensate Increases in the coal moisture content can impact unit capacity if the primary air supply system cannot provide air at a high enough temperature It should be noted that to
provide more heat to the drying process the aircoal ratio can be increased However the aircoal ratio affects classifier performance and other downstream operations such as burner performance pulverised coal transport and wear in the coal supply system These effects must be considered Increasing the air temperature increases the potential for mill fires since dry coal particles especially those recycled from the classifier may come into contact with the high temperature air entering the mill
Low-speed mills are most sensitive to coal surface moisture content The capacity of these mills falls in an approximately linear manner with increase in moisture content The decrease in mill capacity is of the order of 3 for each 1 increase in coal surface moisture This effect is present because of the use of a lower airfuel ratio with these mills lower primary air temperature and less efficient mixing within the mill body Medium- and high-speed mills are not nearly as sensitive to high moisture coal
322 Grinding
The size consistency of the coal feed has a direct effect on the power requirements of the mill (see Section 632) All three types of mill are affected by coal feed top size Table 14 gives the critical feed top size for all three types of mill Low-speed mills are particularly sensitive to coal top size Mill capacity falls in a regular manner with increase in coal feed top size In addition to the top size the overall particle size distribution is also of significance In all cases the presence of excessive proportions of fines in the feed to the mill acts to the detriment of the full output
The fineness required is usually related to the rank of a coal the higher the rank of the coal the fmer the particle size distribution needed to achieve satisfactory combustion that is an increase in fmeness with decreasing volatile matter content The approximate size ranges which are acceptable for coals of different rank to ensure complete combustion are shown in Table 16 Analysis of the combustion process shows that burnout is a function of the proportion of particles over 100 1JlIl rather than the amount less than 75 -Lm It is to be expected that increasing the 200 IJlIl oversize from 1 to
Table 16 Comparison of fineness recommendations ( passing 200 mesh -75 11m) (Babcock amp Wilcox 1978 Cortsen 1983)
Babcock amp Wilcox specification ASTM classification of coals by rank
Fixed carbon Fixed carbon below 69
Type of furnace 979-86 (petroleum coke)
859-78 779-69 BtuI1b gt13000 (gt303 MJkg)
BtuI1b 12900-11 000 (300-256 MJkg)
BtuI1b lt11 000 (lt256 MJkg)
Water-cooled 80 75 70 70 65 60
ELSAM Denmark specification
Volatile matter content dry ash-free () lt10 10-20 20-25 gt25
Water-cooled 85 80 75 70
38
Pre-combustion performance
Eastern USA coals (Combustion Engineering)
80a C leaving mixture temperature
H 2 0 entering-leaving
300 14-20
o 12-20 a
10-20
8-20
6-15
4-15
2-10
Babcock amp Wilcox
3000 a
(i100 CIl ~
gt 3
3 4 5 Cl
9 (1)kg of air leaving millkg of coal a 200 lt1l Cii Cl E
Midwestern USA coals (Combustion Engineering) 2 ill
nac leaving mixture temperature ~
laquo 100
JI 24-70 entering-leaving
22-65
26-75 H 0
~ 2
20-60
18-60300 shy16-55
o 2 4 6 8 1014-50 12-50 kg of coalkg of air
10-45 8-40
6-40
100
2
~
OJshysect
pound 0 ~
ES
2 3 4 5
kg of air leaving millkg of coal
Figure 13 Primary air temperature requirements depending on moisture content and coal type (Babcock amp Wilcox 1978 Singer 1991)
39
ie curve is unreliable in this area
60 lt75 ~m
lt75~m
lt75~m
90 lt75 ~m----shy
25 50 75 100
Pre-combustion performance
2 would have a much more significant increase on bumout than decreasing the under 75 lm from 70 to 65 Oversize particles are believed to contribute to slagging problems in boilers although there are no adequate correlations to relate particle size distribution to the incidence of slagging (Babcock amp Wilcox 1978 Singer 1991) The use of low NOx combustion strategies has required a policy of finer grinding for some coals in order to offset the increased unbumt carbon found in the fly ash (Heitmiiller and Schuster 1991)
The ease by which a coal can be ground within a particular type of apparatus is termed its grindability The most common measurement is the Hardgrove grindability index (HGI) (see Section 25) The HGI is widely accepted as the industry standard for evaluating the effects of coal quality on mill performance for high rank coals (Babcock amp Wilcox 1978 Singer 1991) The rated capacity of a mill is defined as the amount of coal (tlh) that can be ground to a fineness of 70 through a 75 lm sieve using a coal with HGI of 50 or 55 Mill manufacturers tend to be divided on how mill capacity is determined for a particular coal Some provide correlations relating the HGI of the coal to mill output for each standard mill size Other manufacturers depend on assessments made in proprietary small test mills or full size mill tests with large samples to give more confidence to anticipated performance of mills with the specification coal(s) With the multitude of mill designs available there is no reason to expect that the capacity of each type should be related to HGI according to any universal relationship
The Hardgrove test is limited in its application as it is a batch operation which is then related to a continuous process Mills
are air swept so that as comminution proceeds fine particles are quickly removed from the grinding elements whereas they remain in the grinding zone in the Hardgrove machine (Hardgrove 1938)
Values of HGI for coal lie in the range 25-11 O Within the range of 42-65 HGI is probably a good indicator of grindability providing the other properties (moisture specific energy etc) are considered Outside this range confidence in HGI is not so good (see Figure 14) Many attempts have been made to correlate HGI with coal composition (Singer 1991) but whilst there is a general trend with coal rank as seen in Figure 15 the scatter is enormous For example the HGI for high volatile bituminous A coals range from 30 to 75 a factor of 25 The scatter could be accounted for by the distribution of macerals in the coal (Fortune 1990) The milling properties of the different maceral types can give rise to segregation of macerals within particular size ranges For example vitrinite tends to be more brittle than exinite or inertinite and is usually concentrated in the finer fraction of the milled coal (Falcon and Falcon 1987 Conroy 1991) In addition vitrinite and exinite are more reactive than inertinite so that a greater concentration of inertinite will generally be found in the unbumt fuel than in the parent coal Inertinite also tends to concentrate in the larger particle size ranges where its lower reactivity has a noticeable effect on bumout It should be noted that this will depend on the different forms of inertinite as some types are more reactive than others (Bailey and others 1990) These observations are dependent greatly on maceral distribution within the coal Macerals in some coals occur in discrete layers whereas in others (for example South African coals) they can occur as intimate associations (Falcon and Ham 1988) The distribution as
20
16
ist5 12 2 2shy0 ro g- 08 ()
04
o
curves extrapolated to zero capacity usefull range for
(HGI =13) curves
range in which bituminous coals are found
Hardgrove grindability index (HGI)
Figure 14 Variation in capacity factor with HGI for different fineness grinds (Fortune 1990)
40
Pre-combustion performance
o
o o
bull Ball mill indexes
Hardgrove tests converted to equivalent Ball mill indexes
bull bull 0
ltlOl 0
etgtz l 2 2
100 - o o o
90
o80
a 70S xOl U ~ 60 pound 0 ro 50 U sect 01 Ol 40 gt e -e01 bull ro 30 I U 0 m
en enJ J Jroen middot0 middot020 Olen Olen ~ 0 0 degoJ _J _J ro ro c c 0 oen len~ gt 0 0 J c cmiddotE middotE EJ~ roc roc gtJ
C middot02 CEo
3 omiddotE omiddotE o~ ro10 3 0 _
Eg cp ro eO2 ~~~ gtJ gtJ middot~middotE gtEmiddotc 0 0 J c~ middotE c
0 0 uJ 3J Q)ouo 010 010 Ol- C01 J J Jc 0middot Ol =i Cf) Cf) Cf)roU Im Iltl ~o -10 Cf) ltl ~
0 9 10 11 12 13 14 15 16 70 80 90 100
Moist mineral-matter-free MJ Dry mineral-maller-free fixed carbon
Figure 15 HGI for several coals as a function of rank (Elliott 1981)
described will effect the particle composition and other coal to 77 and mainly in the 60 to 70 range In general such coals physical properties These effects cannot be predicted from would not be expected to cause difficulty with grinding proximate analysis and so could account for discrepancies in the anticipated performance of coals having similar The abrasive properties of a coal and especially its associated proximate analysis values but with different petrographic minerals cause wear of the grinding elements and other compositions surfaces in the mill The extent of this wear determines the
intervals between planned maintenance periods and the Grinding of coal blends in which the components have possibility of shutdowns It is therefore of great importance widely different HGI values have shown that care is required for an operator to have an idea of how long these periods are in the interpretation of the results Byrne and Juniper (1987) likely to be and how unplanned outages caused by excessive observed that in such cases the harder material tended to mill wear can be avoided concentrate in the coarser fractions of the pulverised fuel and the softer coal in the finer fractions It was believed that this Wear is caused by one of four mechanisms (Fortune 1990) was a consequence of the softer coal blanketing the harder coal and so preventing full grinding of all the fuel adhesion
surface fatigue One difficulty with HGI is reproducibility BS ISO and AS1M abrasion standards all state that a spread of three units is acceptable This corrosion is equivalent to a 4 change in mill capacity Comparisons from different laboratories have given a reproducibility of Adhesion and surface fatigue effects in milling are negligible around eight to nine (Fortune 1990) This is equivalent to a mill compared with abrasion and corrosion capacity variation spread of 12 which is clearly unacceptable as an indication of grinding performance The rate of abrasive wear in mills will depend in general on
the following factors Attempts have been made to develop alternative grindability indices but so far none of these has attained widespread use the type of coal used especially the amount and Typical of these is the continuous grindability index (CGI) composition of the incombustible minerals associated which relates mill performance to power input It was with the coal developed for low rank coal applications A new method has the material used for the mill rolls and bowls also been proposed for determining coal grindability and the design of the mill abrasivity properties using a single machine by Scieszka (1985) although it should be noted that this work was based The most widely used abrasion test is the Yancey Geer and on a limited range of coals with HGI values ranging from 39 Price (YGP) test (Yancey and others 1951) although its
41
Pre-combustion performance
repeatability varies with coal characteristics For abrasive coals the repeatability is about 3 However for coals with low abrasiveness repeatability may be as low as 18 Babcock Energy Scotland use a similar test but with a smaller coal sample (Cortsen 1983) Babcock amp Wilcox in the USA has developed an abrasion test using a radioactive tracer technique (Goddard and Duzy 1967) This test produces a measurement of mill wear albeit at a laboratory scale
Literature data indicate that coal itself is not very abrasive (Parish 1970) Of the associated minerals usually present in coal only quartz (SiOz) and pyrite (FeSz) are considered to be hard enough to cause significant wear Other minerals mainly clays are generally quite soft and friable and do not contribute much to mill wear The earlier studies have shown some correlation between wear and quartz or pyrite content of the coal but the correlations obtained were generally not widely applicable (Parish 1970) In investigations carried out by Donais and others (1988) it was found that as well as the total amount the size of the quartz and pyrite grains significantly affected the wear rate The study was carried out on eight different US coals using NIHARD rolls in both Babcock amp Wilcox and Combustion Engineering mills In general the data indicated that the coarser fractions of quartz and pyrite contribute more to mill wear than the finer size fractions The best correlation between the data was as described in the following expression
Abrasion (radial wear per tons of throughput) =F (3 Q+ P)
where F = constant
Q = ( Quartzgt100 Ilm) P = ( Pyrite gt300 Ilm)
Donais and others (1988) found that the intercept of the curve from the above relationship on the Y axis (mill wear) was well above zero indicating that the effect of the finer fractions of the quartz and pyrite are not negligible and that the coal itself or other minerals may also contribute to wear It should be noted that the size distribution of pyrite and quartz are not normally measured and are not usually included in coal specifications
Other experimental techniques for abrasion testing are summarised in an early report by Parish (1970)
Erosion by mineral particles picked up in the air stream carrying pulverised coal through the mill classifier and ducting is a recognised problem The following parameters affect erosion rates
stream velocity - erosion rate increases exponentially with velocity For ductile materials the exponent is about 23 for brittle materials the exponent ranges between 14 and 5 impingement angle on mill surfaces - maximum erosion rates occur at 30deg for ductile materials and at 90deg for brittle materials particle size - erosion rates increase with particle size up to a critical size above which no increase is observed
323 Size classification and transport
Reduction in oversize particles after initial milling is achieved by separation and recycling of particles through the mill to be reground until they are sufficiently small to pass through a classifier The classifIer can be adjusted to vary the final fineness of the coal Coal fineness affects essentially all processes occurring downstream of the mill including ignition flame stability flame shape ash deposition char burnout etc However if the classifier is adjusted for greater fineness to accommodate for example the firing of a lower volatile coal (see Section 41) the amount of material recycled back to the grinding zone increases This alters the grinding process and if the coal mass in the grinding zone increases too much the grinding elements may begin to skid or excessive spillage can occur The initial coal particle size and grindability can affect the fine tuning of the classifier
The primary air flow rate to the mill is based on the requirements of the burner mill and pulverised coal transport At full load the air flow rate usually corresponds to an aircoal mass ratio of about 20 For a given size of pipes the air flow rate can be adjusted over a narrow range only without causing de-entrainment of PF or increasing pipeline wear for lower or higher rates respectively For a given mill for example ring ball type roller mills supplied with design coal and having 20 of total air as primary air at full load the calculated coalair ratio changes from about 05 kgkg to about 036 kgkg by reducing load from 100 to 50
The relationship between primary air flow rate and coal flow rate is established by the mill manufacturer Moisture content of the coal determines the necessary primary air temperatures as discussed earlier in Section 321 Moisture content of the coal may therefore influence effective and accurate transport of the coal through the mill
33 Fans Coal fired steam-electric units use a number of fans to move air flue gas and pulverised coal The major type of fans include
forced draft (FD) fans - supply air to the wind box under positive pressure induced draft (ID) fans - withdraw flue gas from the furnace and balance furnace pressure primary air (PA) fans - supply air to the mills flue gas recirculation (FGR) fans - recirculate flue gas from the economiser outlet to the burners or the wind box
The performance of the fans can be impacted by changes in coal quality
A typical arrangement of the major fans at a steam-electric unit is illustrated in Figure 16 The major path flow involves the FD and ID fans It should be noted that the fan arrangement shown in Figure 16 is not fully representative of all coal fired steam-electric units The number and arrangement of the fans and other components can vary substantially Also the pressures and temperatures of the air
42
Pre-combustion performance
air FD forced draft exhaust to FGR flue gas recirculation stack - - - - - - flue gas 10 induced draft
-----_ _-- coalair PA primary air I
1_1I __ Tempertures are approximate and may vary with plant design and operating parameters ambient air I EMISSION I
PA HEATER (air side)
PULVERISERS
-
I PA 1 FAN
-
I CONTROL I I EQUIPMENT
--T-shyt 150degC
AIR HEATER (air side)
( V
I
EMISSION CONTROL
EQUIPMENT
air heater leakage
--------+--------shy
AIR HEATER (gas side)
I
r------ -----jI
I 3700C 1 I
CONVECTIVE COLLECTOR
FGR OUST
_PA__S_ __ 2DC
1 370degC
FGR FAN FUR~ACE
g
__roaka 0I 3700C
- - - - - -+ - - - - ~ - - - -~ - - shy
wind box
burners~bullbullbullbull ------------- bullbullbull ----------- ---- bullbull ------ bullbullbull -------------- bullbull - --- bullbull --shy
Figure 16 Typical utility boiler fan arrangement (Folsom and others 1986c Sligar 1992)
43
Pre-combustion performance
entering the fans depend on the overall plant design Thus to change in flow rate required evaluate the impact of coal quality on fan capacity it is change in system resistance necessary to specify the details of the fan design and change in fan inlet conditions operating characteristics as well as the power station change in rate of fan erosion arrangement To evaluate fan capacity only the characteristics at maximum performance settings need be The flow rate through the fan could be changed in a number considered of ways by changes in coal quality For example an increase
in coal moisture will increase the flue gas volume flow rate Changes in coal characteristics can impact fan performance Changes in heating value of the coal would require a change in four ways to the airfuel ratio and hence the firing rate The excess air
Table 17 Summary of the effects of coal properties on power station component performance - I (after Lowe 1987)
Property Contributing properties Effect
Coal handling and storage Heating value
Coal flow properties
Freezing
Dustiness
Combustibility (spontaneous combustion)
Mills
Drying
Mill throughput
Wear
Fans Flow rate
moisture ash ultimate analysis
moisture coal size distribution mineral matter analysis bulk density
types of moisture
moisture size analysis mineral matter analysis porosity
coal rank moisture size distribution sulphur
moisture
volatile matter
total moisture
Hardgrove grindability index (HGI)
raw coal top size
pulverised fuel size
distribution
mineral matter analysis (quartz amp pyrite) mineral matter size distribution
moisture slagging propensity fixed carbon
A 1 decrease in heating value increases required mass throughput of coal by 1
As flow properties degrade coal throughput remains relatively constant until catastrophic blockages occur at a critical flow property value This value is highly site specific
Surface moisture at low temperatures is the primary cause of freezing
Increased operating and maintenance costs with dusty coals Potential for increased loss of availability
Heating value of stockpiled coal decreases due to spontaneous combustion Plant layout and procedures are dictated by spontaneous combustion
MiD type
Low speed Medium speed Influences primary air requirements and power consumption for both types of mill Mfects the susceptibility of both mill types to mill fires
-3 throughput for 1 moisture -15 throughput for 1 increase moisture increase above
approx 12 moisture -1 throughput for 1 unit -1 throughput for 1 reduction in HGI unit reduction in HGI Caution when using HGI for interpreting coal blend behaviour -3 throughput for 5 mm increase No loss in throughput below in top size 60 mm top size Reduction in fraction passing Reduction in fraction passing
lt75 JlII1 mesh screen by 035 for lt75 Ilm screen by 09 for 1 increase in throughput 1 increase in throughput Influences the component operation and maintenance rate for both types of mill
An increase in moisture increases the flue gas volume flow rate Influences the excess air requirements
44
Pre-combustion performance
required for a specific coal depends on the slagging propensity of the coal carbon burnout and boiler steam temperature considerations These effects are difficult to predict and the actual value of excess air used is determined by the operators to achieve the best balance
The system resistance can also be affected in a number of ways For example fouling of the convective pass increases ID fan resistance on units with induced or balanced draft (Folsom and others 1986b) Fly ash loading in the flue gas can influence the performance for example increased fan blade erosion can occur with increased quantities of fly ash (Sligar 1992)
34 Comments Table 17 summarises the effects of coal properties on the performance of the power station components discussed in this chapter It has been shown that whilst many empirical
relationships have been developed and used to describe the problems that are encountered in the power station there are some signifIcant uncertainties related to many assumptions made These can include for the components described in Chapter 3 the following
coal handling and storage - oxidation dusting flowability and freezing cannot be predicted from coal composition measurements mills - there is no way to evaluate the fineness requirements accurately Mill capacity for blends of coals and for lower rank coals are difficult to evaluate using existing HGI correlations fans - air and gas flow rates depend on excess air Excess air depends on flame stability carbon burnout and slaggingfouling considerations There is no satisfactory method of predicting the effect of these relationships for specific coals Twenty per cent excess is often assumed
45
4 Combustion performance
41 Burners For ignition to take place four elements must be present
fuel air sufficiently high temperature ignition energy availability
A pulverised fuel burner solves this task by blowing a mixture of pulverised coal and air into a part of the furnace where there is a high temperature When lighting up the burner this high temperature is secured locally with an ignition system The burner itself however must be designed in such a way that a stable flame is achieved after the ignition flame is extinguished and it must be able to keep the flame stable and provide optimum combustion The loss of a flame on tum-down even within normal control ranges constitutes a serious dust explosion hazard (Cortsen 1983) Sustained combustion without support fuel also requires consistent coal quality Pockets of high ash can cause momentary extinction and subsequent risk of explosion when fuel returns
A number of physical and chemical processes occur extremely rapidly within the flame It is difficult to describe the number of interactions and complexity of the reactions occurring In spite of many years of theoretical flame research burner design is still based on practical experience though in more recent years this has been supplemented with pilot- and full-scale experiments (Knill 1987 Noskievic and others 1987 Harrington and others 1988 Kosvic and others 1988 Repic and others 1988 Penninger 1989)
Ignition stability is strongly influenced by the characteristics of the coal The conventional method of evaluating the impact of coal characteristics has been to consider the volatile content of the coal and the presence of inert material (moisture and ash) However even if two
coals have the same proximate analysis their ignition characteristics may still be very different due to differences in chemical structure
There are three distinct groups of coal with respect to ignition according to Truelove (1985)
lignites and subbituminous coals with high inherent moisture and high volatile matter content greater than 50 bituminous coals with proximate volatile matter content between 20 and 50 anthracite and semi-anthracite with volatile matter content less than 20
Notwithstanding the high volatile matter content low rank coals can still be difficult to ignite because the high moisture lowers the flame temperature and dilutes the volatilesair mixture The energy required to evaporate 15 moisture and superheat it is equal to the energy required to heat the coal material to 500degC When the moisture content exceeds 40 the coal can be dried using hot flue gas with the result that the primary coaVair stream is heavily loaded with inert water vapour and products of combustion In contrast to the difficulties associated with the ignition of low rank coals the char resulting from high-moisture high volatile matter coals is generally highly reactive
Low volatile coals are much more difficult to ignite In these cases the heat released during the combustion of volatiles is usually insufficient to raise the temperature of the char to ignition and hence sustain combustion It may be necessary to provide continuous support fuel to maintain combustion Ignition stability with low volatile coals can be enhanced by grinding the coal finer and using high preheat for the combustion air Table 16 shows recommendations for pulverised coal fineness based on the volatile matter content (Cortsen 1983) Bituminous coals with volatile contents above 25 should present few problems with ignition
46
Combustion performance
Modem independent burners all use strongly swirling air flows to achieve flame stability and control flame length and width and combustion intensity The application of swirl produces short and intense flames Although excess swirl especially in the primary stream may delay ignition due to rapid mixing of the primary coaVair stream with the relatively cool combustion secondary air
The effect of ash on flame stability has been studied at the International Flame Research Foundation (IFRF) in the Netherlands No significant differences in ignition and flame stability were found when firing 6 ash and 30 ash high volatile coals provided that the fuel was well mixed and delivered to the burner at consistent quality
In the efforts to cut NOx emissions virtually all the combustion-equipment manufacturers are involved in the development of low NOx coal burners Many utilities already utilise the technology Intensive research has focused on the formation of NOx which is influenced greatly by combustion conditions This is discussed further in Section 523
42 Steam generator The ability of the steam turbine to generate power at full capacity depends on an adequate supply of steam at the correct temperature and pressure The steam supply and quality is dependent on the heat release occurring in the furnace and the heat transfer from the resulting gases to the various boiler surfaces located in radiant and convective banks
The effects of coal characteristics on boiler heat transfer and ultimately steam conditions are complex and closely related to the arrangement of large steam generators Factors such as the layout of radiative and convective heat transfer surfaces in the gas side and location of boiling and non-boiling regions on the steam side are critical This section considers how coal characteristics can affect both heat release and heat transfer processes via the mechanisms of fuel combustion and ash deposition
421 Combustion characteristics
Insight into the influence of coal properties on pulverised coal combustion can be gained by examining the factors affecting combustion There is an extensive amount of literature which reviews the work carried out in the field of pulverised coal combustion An lEA Coal Research report Understanding pulverised coal combustion by Morrison (1986) reviews the literature mainly post 1980 on the fundamental processes and mechanisms of pulverised coal combustion Others include reviews by Laurendeau (1978) Essenhigh (1981) Smoot (1984) Smoot and Smith (1985) Heap and others (1986) and Singer (1991) Only a brief description will be given here
The combustion of individual coal particles comprises the following sequence of processes which are partly overlapping and are all dependent on both physical conditions and coal properties
heating of the particle
release of volatile matter combustion of volatile matter combustion of the char
Heating of the particles occurs very quickly The temperature gradient is 105_106degCs depending on the size of the particle Thus a 60 lm particle may achieve furnace temperature within 005-01 s
Release of volatiles occurs within the similar time span but varies with coal quality and particle size The initial gases released ignite and bum momentarily consuming the oxygen present in the air surrounding the particle At this stage the volatiles bum independently of the char particle The devolatilisation of coal at high heating rates is an important stage because it may control
the rate at which combustion proceeds the rate at which oxygen is consumed the rate and form of evolution of nitrogen sulphur and other species together with the mechanisms governing the fate of these species
Depending on temperature and coal quality char combustion may be initiated before combustion of all volatile constituents is completed For successful combustion the heat release associated with the gas-phase reaction must raise the bulk gas temperature sufficiently to ignite the char The rate of char combustion is dependent upon several factors
initial coal structure variations diffusion of reactants reaction by various species (02 H20 C02 H2) particle size effects developed pore diffusion char mineral content (catalysis) changes in surface area as the reaction proceeds char fracturing variations with temperature and pressure
The time required for consumption of a char particle represent a significant portion of the overall time required in the coal reaction process and can range from 03 s to over 1 s (Smoot 1984)
The watersteam temperature balance in a boiler is influenced greatly by the burning profile of the coal that is the rate at which coal passes through the different stages of combustion the heat release associated with them and take-up by watersteam (Singer 1991) During combustion gas temperatures are near 1800degC but the gases must cool to the design point temperatures (usually around 1200degC) of the convective sections of the boiler so that they may be maintained in a satisfactory condition of cleanliness (see Section 422) If the coal bums too quickly
too much heat may be absorbed in the radiant section of the boiler When the gases subsequently reach the superheater tubes they may be too cool to raise steam temperature to the levels necessary for efficient turbine operation and full capacity utilisation temperatures at the radiant section can rise too high and
47
Combustion performance
cause circulation problems or increased boiler slagging (see Section 422) thus raising the incidence of forced outages
If the coal bums too slowly temperatures in the radiant section do not reach design levels and gases reaching the superheater tubes may be hotter than l200dege Thus there can be a decrease in boiler efficiency through
decreased steam production fouling of superheater tubes (see Section 422) increased carbon loss loss of superheater temperature control increased risk of fires in the economiser hopper air heater and particulate control system higher than desired exit temperature of exhaust gases
Many attempts have been made to establish empirical correlations between combustion behaviour and coal properties The volatile matter content is most commonly used as an indicator for ignition behaviour of a particular fuel Similarly heating value and ash content provide a guide to flame stability
The heating value of the coal is important as it constitutes the amount of energy that can be imparted to the system Moisture and total ash content act as negative influences to the energy supply by affecting the adiabatic flame temperature and firing density
The combustibility or reactivity of a coal can be characterised by two factors (Wall 1985a)
volatile matter yield and composition (Jiintgen 1987a Morrison 1986 Saxena 1990) reactivity of char - char reactivity generally increases with decreasing rank in PF combustion (Smith 1982 Morgan and others 1987) so that the rate of combustion is similarly dependent on rank (Shibaoka and others 1987 Jiintgen 1987b Oka and others 1987) However Cumming and others (1987) and Bend (1989) found that rank was not an accurate guide for high volatile bituminous coals from different origins The amount of char produced has been shown to be related to the proximate analysis fixed carbon content petrographic composition and initial coal particle size
An index that relates both of the parameters above is the fuel ratio that is fixed carbon divided by volatile matter as determined by proximate analysis can be used as a measure of coal reactivity The fuel ratio provides an indication of the relative proportion of char to volatiles Although correlations between the fuel ratio and carbon burnout have been found (for example Baker and others 1987) there are exceptions (Oka and others 1987) A higher fuel ratio does not necessarily indicate a coal of lower reactivity and high carbon burnout (Figure 17) This is not surprising since both volatile matter and fixed carbon determinations relate to laboratory test conditions which do not represent the conditions encountered in PF boiler As was discussed in Section 21 proximate volatile yield is generally lower than the true volatile yield as it is sensitive to test conditions
20
C----------) indicates trend reversal
These comparisons 10 contradict the rule that a higher fuel ratio necessarily means higher unburnt carbon and lower reactivity
Coal sized to +125-150 Ilm 5
Peak temperature 1300degC
2
10
c o 0 CB U
c 05s
0 c J
02
01 -t----------+-------------
05
Fuel ratio fixed carbonvolatile matter
Figure 17 Fuel ratio as an indicator of coal reactivity (Smith 1985)
(Morgan 1987) Similarly proximate fixed carbon makes no allowance for the differing reactivity of chars formed from different coals (Oka and others 1987 Smith 1982) Fuel ratio has also been found to be unsuitable for assessing low rank coals
Many utilities have found that volatile matter content information alone is a poor indicator of coal furnace performance they are tuming to the use of advanced test methods Further test procedures have been developed by boiler manufacturers and utilities which give a better insight into the influence of coal properties on combustion characteristics For example thermal gravimetric analysis (TGA) may be used to evaluate the characteristics of coal with respect to particle coal heating and volatiles ignition It should be noted however that TGA test conditions can also differ largely from the conditions present in a PF boiler An example of a TGA test requires a coal sample to be heated at
10 20 40
48
Combustion performance
a controlled rate in a controlled environment The weight loss of the sample is recorded continuously as a function of time (or temperature) The burning profiles determined in TGA are often used as a characteristic fingerprint for a coal These will be compared to a standard coal with an established boiler performance (Cumming and others 1987 Morgan and others 1987) The TGA can also be used to determine the reactivity of coal chars prepared in situ or in other test apparatus such as drop tube furnaces (DTF) or entrained flow reactors (EFR) (Jones and others 1985 Morgan and others 1987 Crelling and others 1988 Hampartsoumian and others 1991)
The DTF or EFR apparatus can also be used to determine the reactivity of coalschars under a range of conditions The apparatus can be utilised under conditions similar to those experienced in a boiler In these tests a consistently higher extent of volatile release is measured than in the volatile matter test of the proximate analysis (Morrison 1986 Knill 1987 Gibbs and others 1989) Carbon burnout can be determined along with the reaction rates for the different stages of combustion (Wall 1985b Skorupska and others 1987 Tsai and Scaroni 1987 Diessel and Bailey 1989 Smith and others 1991a Chen and others 1991) This topic has also been reviewed by Unsworth and others (1991)
Other apparatus used for volatile matter release rates and coalchar reactivity determinations include the heated wire grid apparatus flat flame burners pyroprobe and pilot scale furnaces
All these tests provide data on the devolatilisation and combustion characteristics of coal in considerably more detail than the data provided by standard proximate analysis The boiler manufacturers have developed methods of utilising the test data to predict boiler performance However it should be recognised that these tests are used subject to individual choice and interpretation They are not widely accepted in the utility industry as standards Currently the tests results are meaningful only in the context of a background database for a particular installation which includes accumulated measurements on fuels in the specific test facilities as well as field operating systems The most direct method of utilising the tests would be to compare the performance of specific coals to a base coal whose performance in the subject boiler is well documented In cases where such an approach is not practical it is necessary to rely on laboratory data and modelling to extrapolate the results to full scale However the test procedures particularly in the case of DTF apparatus are complex and since the test facilities have been used primarily as research tools there are no accepted standards
422 Ash deposition
Ash deposition is one of the most important operational problems associated with the efficient utilisation of coal (lEA Coal Industry Advisory Board 1985 Jones and Benson 1988) Since deep cleaning of coal is expensive (Couch 1991) ash is present in all coal-fired furnaces and must be carefully controlled
Equipment manufacturers have used several approaches for
108wx 106d 126 w x 124 d
D D D L wxd 116wx108d
r130 h
U Eastern Western Lignite
bituminous subbituminous coal coal
Siagging propensity low-medium high severe high Fouling propensity low-medium high high high
Midwest (Illinois)
bituminous coal
Furnace size is also affected by coal heating value - moisture - volatile matter
Figure 18 Influence of ash characteristics of US coals on furnace size of 600 MW pulverised coal fired boilers (Babcock amp Wilcox 1978)
ash management to accommodate effective collection and disposal of the deposit Dry and wet bottom furnaces utilise very different operational conditions to achieve this goal (Hatt 1990) Most pulverised coal units that are offered today are of the dry bottom type although wet bottom or slagging bottom furnaces may still be offered for special applications
Since the presence of ash is unavoidable coal-fired power stations are designed to tolerate some deposit on tube surfaces without undue interference of unit operation Knowledge of ash deposition tendencies of coals is important for boiler manufacturers as boiler design features can be varied to accommodate difficult coals Figure 18 describes how one manufacturer accommodates various ash characteristics by adjustment of furnace dimensions and the number of deposition removal systems such as wall blowers The criteria of several utility boiler manufacturers for designing boilers to avoid deposition have been reported by Barrett and Tuckfield (1988) It was observed that each manufacturer applied a different set of criteria and placed different emphasis on the coal analyses details used for prediction of ash depositional behaviour
The occurrence of extensive ash deposits can create the following problems in a boiler
reduced heat transfer - due to a reduction in boiler surface absorptivity and thermal resistance of the deposit impedance ofgas flow - due to partial blockage of the gas path in the convective section of the boiler
49
Combustion performance
physical damage to pressure parts - due to excessive loading of the structures andor impact damage when pieces of the deposit break off and fall down through the furnace corrosion ofpressure parts - due to chemical attack of metal surfaces by constituents of ash erosion ofpressure parts - resulting from abrasive components of fly ash
If the deposits cannot be removed by wall blower or soot blower operation the load on the boiler may have to be reduced to lower furnace temperatures to the point where ash softening is controlled and wall andor soot blowers become effective It is not unusual to observe power stations that must drop loads to about one-third of capacity at night to shed slag accumulated during high-load day time operation (Barrett and Tuckfield 1988) In extreme cases the boiler
Extraneous minerals
must be shutdown and the deposit removed by hand Frequent maintenance and unscheduled shutdowns for removing these deposits and the repair of the effects of corrosion and erosion add substantially to the cost of power generation These problems can result in reduced generating capacities and in some cases costly modifications (Bull 1992)
Deposit problems within a boiler are classified as either slagging or fouling Different definitions of slagging or fouling are used by different people Some people refer to the nature of the deposit - defining molten deposits as slagging and dry deposits as fouling Others define slagging and fouling by the section of the boiler on which the deposit occurs (Borio and Levasseur 1986) For the purposes of this report slagging refers to deposits within the furnace and on widely spaced pendant superheaters in those areas of the unit
bull pyrite 1100degC --------- fusion clays 1300degC
quartz 1550degC
~ expansion
~
Inherent minerals
bull M cenospheres
Y
Na K Heterogeneous 8 ~ condensation Mg ~
80 Homogeneous I __ nucleation
MgO coalescence
surface enrichment
coalesce~--------------I~~ euroY-----~ bull 30~m
p~QD~--- quench ---1~~ ~Qi) 10-90 ~m
disintegration
~
Figure 19 Mechanisms for fly ash formation (Wibberley 1985b Jones and Benson 1988)
50
Combustion performance
which are directly exposed to flame radiation Fouling refers to deposits on the more closely spaced convection tubes in those areas of the unit not directly exposed to flame radiation
Ash slagging and fouling give rise to the first four problems listed above The fifth problem erosion is the result of the impingement of abrasive ash on pressure parts Often coal ash deposit effects are inter-related For example the build up of ash deposit layers on tube walls and superheaters does not only reduce furnace and overall boiler efficiency but can also increase the temperature level in furnace and convective passages and aggravate existing deposit problems The characteristics of the deposit layer change so as to reduce the heat transfer to the surface locally the gas temperature in the furnace will rise partially ameliorating the impact However the net effect is that furnace deposits (slagging) decrease the heat transfer in the radiant furnace and increase the furnace exit gas temperature This can lead to enhanced fouling problems in the convective pass if the ash particles enter the convective tube bundles in a sticky state Ash deposits accumulated on convection tubes can reduce the cross-sectional flow area increasing fan requirements and also creating higher local gas velocities which accelerate fly ash erosion In situ deposit reactions can produce liquid phase components which are instrumental in tube corrosion
The coal ash deposition process involves numerous aspects of coal combustion and mineral matter transformations reactions The importance of the furnace operating conditions on the combined results of the above areas must also be stressed For a given coal composition furnace temperatures combustion kinetics heat transfer to and from the deposit and residence times generally dictate the physical and chemical transformations which occur (Barrett 1990) The ash formation process is therefore dependent on the timetemperature history of the coal particle and the heterogeneous nature of the mineral matter in coal Each pulverised fuel particle may behave uniquely as a result of its composition Figure 19 summarises the mechanisms for fly ash formation
The ash transported through the combustion system only becomes a problem if it is first transported to the heat transfer surface and subsequently sticks to that surface Particle size particle density and shape affect transport behaviour (Borio and Levasseur 1986)
In addition to transport phenomena the three requirements for the formation of deposits from a gas stream containing inorganic vapour and fly ash are (Wibberley 1985b)
the vapours and fly ash penetrate the boundary layer of the tube and contact the metal surface the material adheres to the tube surface sufficient cohesion occurs in the deposit to allow continued growth without periodic shedding under the influence of its own weight vibration soot blowing temperature cycling in the furnace etc
The initial deposit layer is significant as it represents the boundary between the tube metal or rather oxide and the remainder of the deposit Adhesion between the tube and the
first deposit forming material from the fumace gases may involve several factors
surface attraction between the fine ashcharged ash and the tube inherent roughness of the tube which is increased by oxide whisker growth or growths of desublimed alkalis liquid phases on the tube surface formed by supercooling of condensing alkalis reactions involving desublimed alkalis or alkalis pyrrhotite fly ash sulphur compounds and the tube metal to form low melting point complex salts such as Na3Fe(S04)3 Tm = 627degC sticky fly ash particles with either supercooled sodium silicates or condensed alkalis on the surface of the ash and species migration through the deposit
As the deposit thickens the temperature at its outer surface increases at the rate of 30-100degCmm depending on the thermal conductivity of the deposit and the local heat flux to the deposit (Wibberley 1985a) The increasing temperature decreases the viscosity of any liquid phases present which in tum increases the retention of larger fly ash particles impinging on the tube and also the rate of deposit consolidation by sintering and sUlphation
As the size of the fly ash retained at the deposit surface increases its surface becomes increasingly irregular (secondary deposit layer) The rate of deposition is highest where the deposit extends furthest into the oncoming gas stream This causes projections to form Continued growth of the deposit depends on simultaneous growth and consolidation Consolidation involves sintering and sulphation which are enhanced by the increasing temperature in the outer regions of the growing deposit
Siagging Slagging deposits typically form on the water wall section of boilers near the burner region In this region the water wall tubes surfaces are typically in the region of 200degC to 425degC (400degF to 800degF) a temperature too low for mineral matter to form molten deposits The fireside layer of a slagging deposit may consist of a running fluid in which all the fly ash has dissolved or it may consist of a glassy phase impregnated with particles of fly ash (Bryers 1992) Formation of slagging deposits is a time dependent phenomenon Situations are commonly encountered within a boiler where initiation of slag deposits in one region of the boiler will propagate to other regions of the boiler as the heat transfer through the water wall tubes is continually reduced and the temperature of the flame and the deposit increases This influence on heat absorption has been demonstrated using pilot combustor facilities to monitor the effect and rate of deposit build up on heat flux on panels designed to simulate boiler water wall surfaces (Abbott and Bilonick 1992) Figure 20 shows the average per cent heat flux recovery for soot blowing cycles at two different coal firing rates for a range of US coals The work demonstrated that the ash deposits from different coals prove to have a range of tenacities as demonstrated by the different values of heat flux recovery
Determination of the elemental composition of slagging deposits in comparison with equivalent compositions of fly ash have
51
Combustion performance
1 washed Pittsburgh seam - medium sulphur 2 run-at-mine Pittsburgh seam - medium sulphur 3 Pittsburgh seam - low sulphur 4 Pittsburgh seam - high sulphur 5 Illinois No 6 seam - low sulphur 6 Roland seam 7 60 Roland40 Illinois No 6 - low sulphur blend
Figure 20 Heat flux recovery for different coals and soot blowing cycles (Abbott and Bilonick 1992)
shown that there is enrichment of some elements in the deposit (Borio and Levasseur 1986) The results of such an analysis are shown in Table 18 This analysis shows some depletion of silica (Si02) alumina (Ah03) and lime (CaO) in the deposit and an increase in hematite (Fe203) In some cases direct impaction of unspent pyrite on hanger tubes and the leading edge of the first row of convection bank tubes can cause an iron-rich deposit to form that is 75-90 Fe203 in the deposited ash The deposit is semi-fused as pyrrhotite and is further oxidised to hematite or magnetite While bulk analysis of deposits on water wall tubes can give an insight into the formation of the deposits still more information can be gained from chemical analysis of different layers within the deposits which are seldom homogeneous and vary with time
Wain and others (1992) have also illustrated that slag
deposits from different UK coals can exhibit a range of chemical and physical properties At one extreme the slag may be highly porous and friable having little mechanical strength while at the other extreme the slag deposit may be dense and fused with great strength Susceptibility to removal processes was shown to be related to the porosity of the slag formed which in tum is dependent upon ash composition and operating conditions Earlier work indicated that the physical state of the deposit can have a significant effect on the radiative properties In particular molten deposits show higher emissivitiesabsorptivities than sintered or powdery deposits (Goetz and others 1978) Thin molten deposits are less troublesome from a heat transfer aspect than thick sintered deposits However molten deposits are usually more difficult to remove and cause frozen deposits to collect in the lower reaches of the furnace where physical removal can no longer be carried out with wall blowers
Fouling In all coal-fired units ash deposits build up on the convective pass tube bundles due to the flow of the particulate laden flue gas over the tubes The boiler manufacturers attempt to design their units to avoid the uncontrollable build up of deposits in this region Fouling problems occur when the strength of the deposits is high and the action of soot blowers is unable to remove the deposits It should be noted that with fouling there is no analogue to the wet bottom approach to slagging that is units cannot be designed to accommodate fouling problems by ensuring that the ash deposits are removed from the convective pass tubes as liquids
As with slagging the bonding of ash particles to the tube surface depends on the physical state of the particles approaching the tubes and wetting action of the ash on the tube surface However in the convective pass the temperature difference between the particles (and gas) and the tube surface is much less than in the radiant furnace so that the quenching action of the particles impacting the tube surface is greatly reduced
Organically-bound sodium and sodium chloride are most frequently the cause of convective bank fouling in low rank coals and bituminous coals respectively (Osborn 1992) As discussed earlier many of the alkali metal compounds in coal
Table 18 Enrichment of iron in boiler wall deposits - comparison of composition of ash deposits and as-fired coal ashes (Borio and Levasseur 1986)
Unit sample Power station 1 Power station 2 Power station 3
As-fired Waterwal1 As-fued Waterwal1 As-fired Waterwal1 coal ash deposit coal ash deposit coal ash deposit
Ash composition Si02 470 333 502 551 497 418 Ah03 267 180 169 146 165 158 Fe203 146 435 59 183 120 285 CaO 22 12 128 72 65 90 MgO 07 05 35 20 09 09 Na20 04 02 06 05 11 06 K20 23 16 08 06 15 09 Ti02 13 08 09 08 11 07 S03 11 05 120 01 20 02
52
Combustion performance
vaporise readily at typical furnace temperatures They form hydroxides or oxides that react with S03 in the gas phase at the tube surface to form sodium sulphate They can react with ash particles to form low melting point eutectics or can nucleate on the surface of ash particles or tubes Thus alkali metal compounds can lead to sticky deposits on the tube surfaces Generally sodium and calcium sulphate dominate the initial layer of deposits As the deposits build up in thickness they can sinter into a strong fused mass They may include other ash particles completely encapsulated with calcium and sodium sulphate crystals The sintering process may be related to diffusion of materials through the deposits and solid phase reactions
As in the case of slagging fouling deposits also are not uniform but are built in layers of material which can differ in particle size and chemical composition
Corrosion Corrosion of the furnace wall tubes has resulted in metal depletion rates of 600 nmh or more compared to normal oxidation rates of about 8 nmh (Brooks and others 1983) Such severe corrosion drastically reduces the lifetime of the tubes and may lead to unexpected failure Fumace wall corrosion of steel tubes has been observed in virtually all types of pulverised coal boilers In extreme cases the result is tube failure and large scale requirements for replacement (Clarke and Morris 1983 Blough and others 1988) Currently corrosion is no longer the primary cause of forced boiler shutdowns owing to control strategies and regular maintenance However remedial measures are quite costly and current efforts seek to reduce this cost by substantially extending maintenance intervals (Flatley and others 1981)
The mechanisms which govern the corrosion of the furnace wall tubes are not well understood (Harb and Smith 1990) Corrosion behaviour is closely linked to conditions in the furnace Fireside corrosion can occur on both water walls and superheater tube surfaces Water wall corrosion results essentially from regions of persistent local substoichiometric combustion near the walls which may be due to coal devolatilisation andor inadequate coalair mixing The resulting low partial pressure of oxygen and a high partial pressure of sulphur (as H2S and S02) cause the formation of scales containing iron sulphides Sulphide scales grow more rapidly than the corresponding oxides They are less protective and can lead to increased stress when formed in an existing oxide scale This promotes rapid spalling of the tube surface (Wright and others 1988) Other species believed to participate in corrosion reactions include HCI This is formed on volatilisation in the flame Flatley and others (1981) postulated that HCl reacts with the outer scales of the previously formed protective oxide to create gaseous microchannels through which HCl gains access to the metal surface Once at the surface the HCI reacts with the iron to form a volatile iron chloride which is then transported back toward the bulk furnace gases The reducing environment is also known to lower ash fusion temperatures and increase mineral deposition which in turn can affect corrosion behaviour
Corrosion often occurs in definite patterns associated with the direction of the flame and has been linked to flame impingement (Borio and others 1978) Flame impingement
again creates severely reducing conditions high heat fluxes and leads to the generation of corrosive species Evidence exists that severe furnace wall corrosion of carbon steel is a consequence of poor local combustion associated with flame impingement and the delivery of unburnt coal particles to the tube surface (Flatley and others 1981) Strategies to limit NOx formation in some boilers can increase the likelihood of corrosion owing to the presence of reducing environments and enlargement of the flame zone (Chou and others 1986)
On higher temperature metal surfaces such as superheaters and reheaters two main causes of corrosion are
overheating which leads to accelerated oxidation of both fireside and steam side deposit related molten-salt attack
The latter form of corrosion can be related directly to the chemistry of the coal being burned and the steam (wall) temperature Molten salt attack concerns the development of conditions beneath a surface deposit which are conducive to the formation of a low melting salt ofthe type (NaK)3Fe(S04)3 These alkali-iron trisulphates form by reaction of alkali sulphates deposited from the flue gas with iron oxide on the tubes or from the fly ash in the presence of S03 (Shigeta and others 1987) The minimum melting point for these salts occurs at 552degC (1026degF) This type of corrosion has been associated with the presence of alkali metals sulphur and iron in coal
Chlorine can also be a contributing factor towards superheater metal corrosion if sulphate content is low While exact mechanisms can be argued there have been both liquid phase and gas phase corrosion when chlorides have been present (Latham and others 1991b Daniel 1991)
Calcium and magnesium which may also be found in coal mineral matter are known to be anticorrosive elements which inhibit the formation of alkali-iron trisulphates This is particularly true for acid-soluble calcium and magnesium contents which have an inhibiting ability for liquid-phase corrosion by forming a solid sulphate in the deposit for example calcium sulphate (Blough and others 1988) Work by Shigeta and others (1987) showed from corrosion tests that the corrosion rates were influenced by anti-corrosive elements (see Figure 21)
c 4 co E 0
-0 3E ( ()
Q 2 1 OJ
Qj
5
o 4 8 12 16
Contents of CaO and MgO
Figure 21 Effect of CaO and MgO on corrosivity deposit (Shigeta and others 1987)
20
53
Combustion performance
Erosion Erosion due to fly ash is recognised as the second most important cause of boiler tube failure (Dooley 1992) Considerable effort is being spent to understand the mechanism of fly ash erosion and to acquire the capability to predict erosion rates due to fly ash in boilers Fly ash is more erosive compared to the coal from which it originates one reason being the absence of the soft organic fraction
Table 19 Hardness of fly ash constituents (Nayak and others 1987)
Constituent Mohs Vickers Hardness kgmrnz
Mullite Vitreous material Free silica (quartz) Hematite Magnetite Coke particles with inherent and surface ash
Fume sulphate particles Anhydrite (CaS04)
5 550-600 7 1200-1500 5-6 500-1100 5-6 500-1100
3-5 100-500 (non-abrasive)
Erosion occurs at the outlet of the furnace section where the flue gas is made to tum over the top of the boiler while traversing pendant tube banks and in the rear pass especially on the sections of horizontal tube banks adjacent to the back wall of the rear pass (Wright and others 1988) Fly ash size and shape ash particle composition hardness and concentration and local gas velocities play important roles concerning the erosion phenomenon Table 19 lists the available data on hardness values of fly ash particles (Nayak and others 1987) The hardness characteristics of the major mineral contents in fly ash have not been studied extensively Work by Raask (1985) and Bauver and others (1984) has shown that quartz particles above a certain particle size are very influential in the erosion process and that furnace temperature history plays an important role in determining erosive characteristics of the particles
Many of the above phenomena discussed under the headings of Slagging Fouling Corrosion and Erosion have standard tests such as ash fusibility (see Section 25) as the basis for predicting their occurrence These bench-scale tests provide relative information on a coal which is used in a comparative
fashion with similar data on fuels of known behaviour Unfortunately although commonly used they do not always provide sufficient information to permit accurate comparison
The fusibility temperature measurement technique attempts to recognise the fact that mineral matter is made up of a mixture of compounds each having their own melting point (see Table 20) As a cone of ash is heated some of the compounds melt before the others and a mixture of melted and unmelted material results The structural integrity or deformation of the traditional ash cone changes with increasing temperature as more of the minerals melt However use of ash fusion data can be misleading Ash fusion tests typically are run in both a reducing and oxidising environment This means there is either sufficient oxygen in the atmosphere surrounding the ash particles to oxidise various minerals or there is not Generally an oxidising environment pertains throughout the combustion chamber of the boiler For a number of reasons there may be moments when as the coal and mineral particles pass through the combustion chamber there is not enough oxygen for oxidation to occur This is known as a reducing environment It is important to be aware of these conditions since if a reducing environment develops the ash fusion temperatures are lower than those occurring in oxidising conditions and can become low enough to cause slagging and fouling
The problems with ash fusion measurement is that recent results indicate that significant meltingsintering can occur before initial deformation is observed The fact that the timetemperature history of the laboratory ash is quite different from the conditions experienced in the boiler can result in differences in melting behaviour In addition the ash used in this technique may not represent the composition of the ash deposits that actually stick to the tube surfaces Often there is a major discrepancy between the composition of as-fired ash and that which is found in the deposits The discrepancies between fusion temperature results and actual slagging performance are usually greater on ashes that may look reasonably good in the laboratory One can usually assume with reasonable confidence that the melting temperature of the water wall deposits will be no higher than measured fusion temperatures although they can be and often are lower This is because deposition of lower melting constituents can and does occur with a resulting enrichment of lower melting material in the deposit Bearing all of these points in mind it is difficult to show confidence in this test as a predictor of performance
Table 20 Properties of some coal ash components (Singer 1991)
Element Oxide Melting temperature degC
Si SiOz 1716 Al Ah0 3 2043 Ti TiOz 1838 Fe Fez03 1566 Ca CaO 2521 Mg MgO 2799 Na NazO sublimes at 1276 K KzO decomposes at 348
54
Chemical Compound Melting property temperature degC
acidic NazSi03 877 acidic KzSi03 977 acidic Ah03NazO6SiOz 1099 basic Alz03KzO6SiOz 1149 basic FeSi03 1143 basic CaOFez03 1249 basic CaOMgO2SiOz 1391 basic CaSi03 1540
Other tests such as ash viscosity measurements suffer from shortcomings These tests are conducted on laboratory ash and on a composite ash sample Viscosity measurements are less subjective and more definitive than fluid temperature determination for the assessment of ash flow characteristics The usual procedure for assessing slag viscosity for wet bottom furnaces is to correlate the temperature at which the viscosity of coal ash slag is 250 poise This is defined as T250 Viscosities for dry bottom furnaces are usually conducted at higher temperatures These values can also be calculated from ash analysis Thompson and Gibb (1988) reported that in a study of nine UK coal ashes with a high iron content the slagging propensities as determined by ash viscosity tests was broadly in keeping with expectations though four of the samples showed contradictory behaviour During pulverised coal firing a severe problem may already exist before slag deposits reach the fluidrunning state Generally only a small quantity of liquid phase material exists in deposits and it is the particle-to-particle surface bonding which is most important
Tests utilising the electrical resistance properties of ash have also been developed and these are perceived as being superior to the standard ash fusibility test for providing an indicator of the onset of ash sintering (Cumming 1980 Lee and others 1991)
Much use is also made of the ash composition which is normally a compilation of the major elements in coal ash expressed as the oxide form Coal ash can be classified as one oftwo types viz
bituminous-type Fe203 in ash is greater than the sum of CaO + MgO in ash lignitic-type Fe203 in ash is less than the sum of CaO + MgO in ash
From the compilation of elements expressed as oxides from the ash analyses judgements are often made based on the quantity of key constituents like iron silicon aluminium and sodium
Using the results obtained from a standard ash analysis the measured oxides can be separated into basic and acidic components (see Table 8 and Table 20) The acidic components are those materials which will react with basic oxides They include Si02 Ab03 and Ti02 The basic ash constituents are those materials which will react with acidic oxides They include Fe203 CaO MgO Na20 and K20 The base to acid ratio is the ratio of the sum of the basic components to the sum of the acidic components Baseacid ratios are used as indicators of ash behaviour normally lower melting ashes fall in the 04 to 06 range It has been shown that baseacid ratios generally correlate well with ash softening temperatures so although baseacid ratios have helped explain why ash softening temperatures varied it has not improved the predictive capabilities (Borio and Levasseur 1986) Other ratios such as FeCa and SiAI have been used as indicators of ash deposit behaviour Ratios like these have helped to explain deposit characteristics but their
Combustion performance
use as a prime predictive tool is questionable especially since these ratios do not take into account selective deposition nor do they consider the total quantities of the constituents present An FeCa ratio of two could result from weight per cent ratios of 63 or 3015 the latter numbers would generally indicate a far worse situation than the former but the ratio does not show this
Many of the slagging and fouling indices described earlier in Table 8 are based upon certain ash constituent ratios and corrected using such factors as geographical area sulphur content sodium content etc One commonly used slagging index uses both BaseAcid ratio and sulphur content Factoring in sulphur content is likely to improve the sensitivity of this index to the influence of pyrite on slagging (As previously discussed iron-rich minerals often play an important role in slagging) However the use of such correction factors is often a crude substitute for more detailed knowledge of the fundamental ash properties Another example of this is the use of chlorine content in a coal as a fouling index This can be valid as a general rule if the chlorine is present as NaCI (thereby indicating the concentration of sodium which is an active form) and that the sodium will in fact cause the fouling Chlorine present in other forms mayor may not adversely affect fouling
Sintering strength tests have been used as an indication of fouling potential Assuming that correct ash compositions have been represented (which is less of a problem in the convection section than in the radiant section) worthwhile information may be obtained relative to a timetemperature versus bonding strength relationship Again in order for sintering tests to accurately predict actual behaviour it is necessary that tests be conducted with ash produced under representative furnace conditions (timetemperature history) (Kalmanovitch 1991)
The conventional analyses and developed indices may provide indications for limited parts of the coal spectrum but they share a flaw in that they take their point of departure in the end composition of the ash without taking account of the original minerals and intermediate products formed and transformed in the combustion zone (Cortsen 1983)
Information concerning the mineral forms present in the coals and the distribution of inorganic species within the coal matrix can be extremely important in extrapolating previous experience since the nature of the inorganic constituents contained in the coal can be the determining factor in their behaviour during the ash deposition process (Borio and Levasseur 1986) Generally speaking newer bench-scale techniques can be more sensitive to the conditions that exist in commercial furnaces than the older predictive methods Selective deposition for example has been recognised as a phenomenon which cannot be ignored More attention is being paid to fundamentals of the ash formation and deposition processes The use of new analytical techniques could give results that allow mineral matter to be identified according to composition mineral form distribution within the coal matrix and grain size Techniques such as computer-controlled scanning electron microscopy (CCSEM) scanning transmission electron microscopy
55
Combustion performance
Table 21 Summary of the effects of coal properties on power station component performance - II (after Lowe 1987)
Property Contributing properties Effect
Burners and steam generator Volatile matter
Ultimate analysis
Fuel ratio
Moisture
Slagging propensity
Furnace wall emissivity
Fouling propensity
carbon hydrogen nitrogen
fixed carbon volatile matter
ash elemental analysis ash fusion temperatures coal particle mineral analysis
ash elemental analysis wall deposit physical state
ash elemental analysis active alkalis (sodium amp potassium) ash fusion temperatures
Special burner design for flame stabilisation required below a dry ash-free volatile content of 25
Air requirements are affected by ultimate analysis unit increase of CIH ratio increases air requirements per unit heat release by 08
A 006 increase in efficiency loss due to unburnt carbon for 10 increase in fuel ratio at ratio of 16
A 1 increase in moisture decreases boiler efficiency by 025 requiring a proportional increase in firing rate
Slagging propensity generally ranked as low intermediate high or severe Response to slagging propensity is a function of unit thermal rating
Furnace wall emissivity is typically 08 a decrease of 1 will increase furnace outlet gas temperature by 16degC
Fouling propensity ranked low to severe Response to slagging propensity and is highly unit specific
(STEM) and X-ray diffraction can be used to characterise these properties on an individual particle basis New spectroscopies such as extended X-ray absorption fine structure spectroscopy (EXAFS) and electron energy loss spectroscopy (EELS) are capable of determining the electronic bonding structure and local atomic environment for organically associated forms of calcium sodium and sulphur Other new techniques such as Fourier transform infrared spectroscopy (FTIR) electron microprobe electron spectroscopy for chemical analysis (ESCA) all provide methods of improving present capabilities Thermal gravimetric analyses (TGA) and drop tube furnaces (DTF) have been used to characterise mineral matter decomposition and prepare ash samplesdeposits under near-boiler conditions respectively For example Benson and others (1988) have used a laminar flow DTF to study the formation of alkali and alkaline earth alumino silicates during coal combustion
A cautionary note though should be added here as many of the new techniques are still primarily focused on small fragments of the overall deposition process in order to permit manageable controlled studies in the laboratory Unfortunately the results are all too often not re-integrated in order to understand the total process But it cannot be doubted that a knowledge of the effects of the
aforementioned coal qualities is essential to avoid expensive delay in any changes to operational conditions in order to rectify deposition problems once they arise Information of performance in test reactors could also help to implement counter strategies to prevent the occurrence of deleterious incidents forewarned is forearmed
43 Comments Table 21 summarises the effects of coal properties on the performance of the power station components discussed in this chapter Whilst many empirical relationships have been developed and used to describe the problems that are encountered in the burner and boiler region of the power station it has been shown that significant uncertainties relate to many of the assumptions involved Flame shape and stability and char burnout cannot be predicted with certainty on the basis of coal composition data Correlations for slagging fouling erosion and corrosion have been shown to be inadequate
Power station operators still consider the problems of slagging fouling corrosion and erosion to be of greatest concern In view of this these subjects are the attention of a number of studies and have been reviewed extensively It is recognised that this topic merits a more extensive review than could be incorporated in this study
56
5 Post-combustion performance
51 Ash transport
The mineral matter entering with the coal exits the power station in the following five streams
mill rejects bottom ash economiser ash particulate collection system flue gas
The distribution between these streams depends on the power station design and operation as well as the coal composition Figure 22 shows a typical distribution However as described below this distribution may vary substantially
Most direct-fired mills have provision to reject pyrite extraneous material and excess coal introduced into the mill Under normal operating conditions the mass of the material rejected is a negligibly small fraction of the total coal flow rate However as the flow rate of coal into the mill is increased toward maximum capacity the amount of rejects increases Thus there is no effective way of estimating the effect of coal composition on mill rejects The mill reject system is typically oversized and would not be expected to limit mill operation except under unusual circumstances or where mill capacity is exceeded
The amount of ash removed at the bottom of the furnace is typically about 20 of the total ash content of the coal However the mass of bottom ash is difficult to measure accurately It may be estimated by measuring the mass of ash exiting with the flue gas and subtracting this from the ash entering the boiler with the coal However the errors of such an analysis procedure are considerable and the calculated mass of bottom ash may even be negative The factors which are probably the most important for determining the fraction of ash in the bottom ash are the design of the firing system the coal fineness bulk
velocities in the furnace and slagging Coal qualities that would directly influence these factors are
ash in the coal grindability of the coal slagging propensity of the fly ash
Due to the uncertainty in the mass of the bottom ash the handling system for the material is typically designed with considerable excess capacity Most systems operate intermittently so that an increase in bottom ash may be accommodated by an increase in duty cycle
The composition of the coal ash has an impact on the characteristics of the material captured as bottom ash Dry bottom furnaces are designed to maintain the ash in the hopper in a powdery non-sticky state The powdery ash slides down the hopper walls into the collection tank at the bottom of the furnace IT the ash has a low fusion temperature it may stick to the hopper or build up to running slag This material can accumulate at the bottom of the hopper and plug the hopper exit Solid slag deposits may fall from water walls higher in the fumace causing similar problems Wet bottom furnaces are designed to operate with running slag The slag must have a viscosity low enough to flow into the collection tank where it is quenched in water and shatters into small particles Typically the slag viscosity should be in the range of 250 poise at 1426degC (2600degF) for adequate fluidity (Babcock amp Wilcox 1978) If the viscosity increases plugging of the hopper bottom can occur similar to dry bottom furnaces
The strength of the ash can affect bottom ash system operation Many bottom ash systems are equipped with clinker grinders to reduce the size of the slag particles IT the slag particles are sufficiently large or strong they can disable the clinker grinder All the problems described above are related to the coal ash chemistry that is whether a fluid slag is formed and operating conditions
57
1-----++---------shy--
Post-combustion performance
Based on coal 10 ash 2791 MJkg
Unit 500 MW 1055 MJkWh
Mass kgkJ
Mass
Flow rate th
Coal ash
Mill rejects
Bottom ash
Economiser ash
Cyclone ESP
baghouse
Stack emissions
358
1000
1905
003
10
019
072
200
381
018
50
095
261
734
1398
002
06
012
Figure 22 Typical ash distribution (Folsom and others 1986c)
Occurrences of ash hopper explosions have been reported (Stanmore 1990) The exact mechanism for the explosions has not been elucidated Hypotheses of the cause include
chemical explosions involving iron-rich ash thermal explosions resulting from rapid quenching of falling hot deposits inducing a pressure wave within the water thermal explosion within the ash hopper causing entrainment of unburnt coal which then ignites to produce a secondary blast
Stanmore (1990) reports that work so far in this field has failed to uncover any boiler feature hopper type or coal composition which was common to all explosions investigated Corner-fired and wall-fired units experience the problem with both bituminous and subbituminous coals Both low and high ash content coals were involved with both high and low ash fusion temperatures
Ash-related explosions involving residual carbon in the ash can result from unfavourable furnace conditions which can occur during a cold start of a boiler Moreover variation in initial coal size can lead to poor grinding efficiencies giving rise to a wide pulverised coal size distribution and hence incomplete coal combustion (Stanmore 1990 Wol1mann 1990)
Most of the ash particles captured in the economiser hopper
are large because they are shed from the convective pass tube bundle deposits by the action of gravity flue gas flow rate or soot blowing The amount of ash varies with the fouling characteristics of the coal and cannot be predicted easily Economiser ash disposal systems are typically designed to handle about five per cent of the coal ash The presence of unburnt carbon in economiser ash can impact the operation of the collection system Poor coal reactivity can lead to high carbon content in the ash The carbon can continue to burn in the hopper and fuse the powdery material into a large mass which cannot flow from the hopper easily
Most of the ash exits the boiler as fly ash and is captured in particulate control equipment which may include cyclones ESPs fabric filters (baghouses) or scrubbers
52 Environmental control Since the early 1970s mandatory control of power station emissions has significantly increased the cost of generating electricity (CoalTrans International 1991) Initial concerns were focused on particulate emissions and have led to the development of efficient particulate removal systems Environmental concern about the use of coal is particularly tuned to the problem of emissions of SOx NOx and C02 to the atmosphere Trace elements are receiving increasing attention from the scientific and electric power communities who are attempting to evaluate the potential impact of trace
58
elements on the environment (Clarke and Sloss 1992) There is also the problem of disposal of the solid residues which are obtained from power stations
The capital and operating costs of emission control hardware can account for up to 40 of a power stations operating expenses (Cichanowicz and Harrison 1989) Increasingly coal-fired utilities are realising that in order to comply with ever tightening emission regulations their environmental control strategies must include adequate control of coal quality Emission control strategies related to coal quality can include
coal switching coal blending coal cleaning control of emissions during combustion post-combustion emission control
The impact of coal quality on emission control hardware has not been studied extensively Additional constraints in some cases are applied to coal quality during coal selection as a result of the implementation of emission controls
The following sections briefly review the emission control technologies available and attempts to highlight the coal characteristics and other considerations that affect the selection or efficient use of emission control systems
521 Coal cleaning
Historically coal has been cleaned to maintain specifications for delivered fuel quality and to reduce transport costs Coal cleaning benefits are usually greatest for coals which have to be transported over long distances to the point of use Conventional coal preparation plant mainly uses methods developed at least forty years ago Nevertheless in recent years there have been major advances in instrumentation and control which have resulted in reduced costs and greater consistency in the cleaned product
Utilities also have the option to incorporate coal cleaning strategies on site High mineral matter high sulphur coals could be purchased at lower prices and cleaned on site to boiler-related specifications The decision to implement this type of strategy is dependent essentially upon three factors
cost savings achieved by coal cleaning feasibility of residue disposal
Coal cleaning costs depend upon the initial cleaning plant capital costs cleaning plant operations and maintenance and the value of lesser-quality coal discarded in the cleaning process In general coal cleaning capital costs average about five per cent of the cost of the power station using the coal Direct operating costs are determined by labour consumables and power Discarded coal can account for as much as 50 of total cleaning costs (Cichanowicz and Harrison 1989)
Savings achieved by coal cleaning depend upon the depth of
Post-combustion performance
cleaning instigated (Elliott 1992) A review by Couch (1991) entitled Advanced coal cleaning technology provides a technical overview of recent developments in coal cleaning methods The fuel characteristics most significantly changed by cleaning are
mineral matter content and distribution sulphur content and form heating value
Reducing the mineral matter impurities and sulphur in the coal can have a signifIcant affect on a coals abrasiveness reduce ash loadings by up to 93 and potential S02 emissions by as much as 70 (Hervol and others 1988) Moreover coal cleaning can reduce environmental control costs by lowering the quantity of fly ash and S02 that must be removed after combustion Coal cleaning permits smaller and therefore less expensive flue gas processing equipment reduces reagent quantity and decreases the amount of solid waste requiring disposal Cleaned coal can improve station heat rate by reducing auxiliary power for flue gas handling systems and allowing lower air heater exit temperature thus increasing boiler efficiency Pilot scale combustion tests conducted by Cichanowicz and Harrison (1989) showed that boiler efficiency was greatly improved by coal cleaning as shown in Table 22
Table 22 Summary of coal cleaning effects on boiler operation (Cichanowicz and Harrison 1989)
Characteristics Run-of-mine Medium Deep coal cleaned cleaned
coal coal
Moisture 17 17 16 Sulphur 38 37 20 Ash 235 71 35 Heating value MJkg 2338 3103 3266 Flue gas S03 7 4 3
concentration ppm Air heater exit 136 120
temperature degC Boiler efficiency 884 901 Flue gas volume 6
reductionsect
dried sect includes flue gas temperature reduction and efficiency
improvement
Although the total ash content is reduced it must be noted that all ash constituents may not be removed equally Unfortunately those constituents which are primarily responsible for slagging and fouling are least affected so that problems in this area can be induced as a result of cleaning
As overall S02 emissions will be lowered by coal cleaning the benefits of this form of pollution reduction must be considered in the light of the ESP problems that might result from the use of low sulphur coal (see Section 522) and with regard to its adverse effects on collection efficiency (Strein
59
Post-combustion performance
1989) Coal cleaning has only peripheral implications for NOx and C02 emissions
An additional benefit of cleaning coals is the substantial removal of many trace elements especially heavy metals with the mineral components (Swaine 1990) Efficiencies for trace element extraction have been reported for various physical cleaning processes including density separation oil agglomeration float-sink separation and combinations of heavy-media cyclones froth flotation and hydraulic classifiers (Gluskoter and others 1981 Couch 1991)
The adoption of coal cleaning strategies on a power station site would require a knowledge of quality characteristics that affect cleaning These include
the amount nature and the size of the mineral matter If they are finely divided and dispersed they are difficult to liberate and to separate the size distribution of the coal affected by inherent friability and by mining and handling procedures All of the properties which affect coal handling have an influence here the relative proportions of pyritic and organic sulphur coal oxidation affecting surface properties the porosity of the particles
A number of tests have been developed specifically to assess the cleanability of a coal These have been reviewed in an lEA Coal Research report by Couch (1991) and will not be discussed here
522 Fly ash collection
Fly ash collection systems are required on virtually all coal-fired power stations to meet particulate emissions or opacity regulations The acceptable dust loading from collection equipment is usually about 01 gm3 A coal containing 20 ash typically provides an uncontrolled dust loading of about 30 gm2 so that a collection efficiency of 997 is required to meet acceptable emission standards For very fine particles such as fly ash such a high collection efficiency can only be achieved using electrostatic precipitators (ESP) or fabric filters
Electrostatic precipitators (ESP) ESPs have been studied extensively and a number of comprehensive texts are available that describe the process (Babcock amp Wilcox 1978 Singer 1991 Klingspor and Vernon 1988) The ESP process involves fly ash particle charging collection and removal
The perfonnance or collection efficiency of an ESP is defined as the mass of particulate matter collected divided by the mass of such material entering the ESP over a period of time One of the earliest and simplest equations for predicting the particulate collection efficiency of an ESP was that proposed by Anderson in 1919 and subsequently developed by Deutsch in 1922 The Deutsch-Anderson equation enables the collection efficiency to be predicted from the gas flow the precipitator size and the precipitation rate (or migration
velocity) ofthe particles It may be presented as follows (Deutsch1922)
where e = fractional precipitator collection efficiency (dimensionless)
a = total collecting electrode surface area (m2) v = gas flow rate (m3s) w = migration velocity of the particles (ms)
The ratio av is often referred to as the specific collecting area (SCA) and has dimensions slm When determined empirically the migration velocity w accounts for ash properties such as ash particle size distributions as well as for rapping losses and gas flow distribution The Deutsch-Anderson equation was recognised as having several limitations and so gives only approximate results for some operating regimes For this reason alternative equations have been developed often as modifications of the original Deutsch-Anderson equation For example Matts and Ohnfeldt (1973) introduced a semi-empirical factor and a constant based on particle size distribution and other ash properties which gives a more realistic approximation of actual precipitator behaviour
The equations discussed above describe how perfonnance is a function of ESP design flue gas flow conditions and the characteristics of the fly ash The impact of coal quality on ESP perfonnance is primarily via the influence of the chemical and physical properties of the fly ash on the migration velocity of the particles These include
ash resistivity ash quantity ash particle size and size distribution
Ash resistivity influences ESP power input Resistivity is critical for fly ash ESPs because it directly influences operational voltages and currents As the ash resistivity increases the flow of corona current decreases Generally speaking as the corona current decreases so does the precipitator efficiency Low resistivity ash (l08 ohm-cm and below) is also a problem because the ash easily loses its charge after being collected on the plates The uncharged particles are recharged and redeposited several times and some are eventually re-entrained into the flue gas and escape from the precipitator A limit on maximum gas velocity and special collector profiles are needed to overcome this problem
High resistivity ash (above 1011 ohm-cm) is considerably more difficult to precipitate with a risk of back corona discharge An explanation for this phenomenon is that the ash particles do not readily lose their charge when they reach the electrodes This results in difficulties when trying to remove the agglomerated ash When a deep enough deposit collects on the plate back corona may develop on the ash surface and the precipitator no longer operates efficiently Back corona is extremely detrimental to precipitator performance and occurs when particles migrate to the collecting surface but fail to dissipate their charge This
60
Post-combustion performance
causes a high potential gradient in the dust layer on the surface of the electrode and results in current conduction of opposed polarity to that of the discharge electrode
The range of dust resistivity is primarily affected by
chemistry of fly ash levels of sulphur trioxide and moisture content of the flue gas flue gas temperature
Key ash constituents which affect resistivity are ferric oxide Fez03 potassium oxide (KzO) and sodium oxide NazOshywhere a substantial reduction in either or both of these will cause an increase in fly ash resistivity Conversely a substantial increase in calcium oxide (CaO) magnesium oxide (MgO) aluminium oxide (Alz03) and silicon dioxide (SiOz) will cause ash resistivity to increase (Singer 1991) Strein (1989) describes the impact of coal cleaning in particular the removal of sulphur from coals and switching to low sulphur coals on ESP performance It was determined that coal cleaning was not always beneficial to good precipitator operation Although precipitators can be designed for low sulphur coals the use of low sulphur coals in other cases can lead to a reduction in precipitator collection efficiency and possible non compliance with stack opacity limits Precipitators constructed many years ago were likely to encounter problems if any change to a lower sulphur coal was encountered It was concluded that before a change in fuel was made a careful review should be made of the precipitator design data predicted precipitator performance and the coal and ash chemistry of the new fuel If the problem of high fly ash resistivity was encountered after a fuel switch of this nature flue gas conditioning must be considered in particular a S03 injection system The purpose of this is to supplement the naturally occurring S03 in the boiler flue gas stream to the extent necessary to reduce fly ash resistivity to an acceptable level
A number of electrostatic precipitator manufacturers have developed regression equations which make first order predictions of fly ash precipitation performance based on the elemental analysis of the ash in coal These equations are generally regarded as proprietary and are not published
CSIRO Australia have published details of correlations of ash chemistry with pilot-scale electrostatic precipitators Whilst many correlations used in the past have proved inadequate for precise prediction the most promising correlation was obtained when consideration was given to the elements that would contribute to the refractoriness of fly ash The best precision was obtained from the sum of the elemental analyses for silicon aluminium and iron calculated assuming (on an ash basis) Si+Al+Fe+Ti+Mn+Ca+Mg+Na+K+P+S = 100
The formula given for a precipitator outlet concentration of 01 gm3 and for coal at 15 ash content is in two parts (Potter 1988)
for Si+Al+Fe = a lt82 am = 1886 + 0565a for 82 lta lt90 am = -2864 + 428a
where am = required specific collecting area in mass units mZ(kgs) This value can also be represented as a percentage of the ash content (A) by multiplying by the factor f given by f = 1364 - 048810glO[(100A)-I]
Cortsen (1983) reports of the use of alkaline sulphate index (ASI) by utility operators to assess the ease of fly ash precipitation The ASI is calculated from a series of equations which relate S03 content of the flue gas and the corresponding chemical equivalent of the oxides of silicon aluminium calcium magnesium phosphorus sodium and potassium Coal ashes with ASI values between two and three are perceived difficult to collect while an ASI of six or above indicates easy precipitation The index was not considered as accurate in ESP evaluation as measurement of ash resistivity nor measurement of actual precipitator efficiency (Cortsen 1983)
Sulphur content of the coal can also influence ash resistivity Sulphur trioxide (S03) formed from the combustion of the sulphur reacts with water vapour to produce sulphuric acid (HZS04) at temperatures of approximately 500degC (950degF) In the cool part of the flue gas system there may be some deposition of HZS04 which depends on flue gas temperature and vapour pressure The HzS04 can be absorbed onto the fly ash particles and reduce their resistivity It has been shown that H2S04 can alter the fly ash resistivity either by completely absorbing on the dust particles or by chemically reacting to form sulphates Others have suggested that the formation of binary acid water aerosol is the primary mechanism by which HzS04 can affect fly ash resistivity Although the mechanism which accounts for the presence of absorbed H2S04 on fly ash particles is not clearly understood the net effect is reduction in fly ash resistivity
Increases in moisture content can adversely affect precipitator performance through impacts upstream of the ESPs The moisture content of the coal in conjunction with coal particle size and volatility can affect flame stability and combustion within the boiler furnace area If this causes excessive carbon content in the fly ash at the ESP inlet ESP performance will suffer because of the decreased resistivity of the fly ash
Flue gas temperature can also influence ash resistivity Peak resistivities occur between about 120degC and 230degC depending upon coal ash characteristics Above 230degC to 288degC the ash resistivity is inversely proportional to the absolute temperature while below 120degC to 149degC the resistivity is directly proportional to the absolute temperature (Singer 1991)
The quantity of fly ash produced from a particular coal can vary as discussed in Section 51 It is important to ensure that the total electrode collection surface area and rapping frequency is adequate to handle the quantity of fly ash produced so as to prevent re-entrainment of the material back into the gas stream after initial entrapment at the collecting plates (Strein 1989)
Migration velocity and therefore particle collection rates
61
Post-combustion performance
decrease in proportion to the size of the particle (Darby 1983 Wibberley 1985b) lithe coal is pulverised too finely before entering the boiler ESP perfonnance can be adversely affected due to reduction in particle size distribution of the fly ash at the precipitator inlet The fonnation of fine fly ash may be increased also by higher combustion temperatures and from coals that have a high Free swelling index Disintegration of swollen char particles precludes agglomeration of the mineral inclusions thus ensuring the production of finer ash particles (Wibberley 1985b)
Bench-scale tests that are nonnally perfonned on new coal samples include
preparation of ash samples in a test furnace fly ash resistivity measurement of drift velocity in an electric field
Ideally the ash analysed for the purpose of investigating ESP perfonnance should be taken from the boiler to which the ESP system under assessment is attached Baker and Holcombe (I988b) have demonstrated that the fly ash produced in a specially developed laboratory furnace could show similarities to fly ash resulting from combustion of the coal in approximately eight different power stations It was possible to reproduce the properties of the power station fly ash in tenns of electrical properties and elemental analysis
14 shyelectric stress 400 kVm
bull
13
10 - - ltgt power station fly ash
- simulated fly ash
Mass H2 0r fIgures Indicated = d fl r mass ry ue gas
015 9
80 100 150 200
TemperatureOC
Figure 23 Resistivity results for both power station fly ash and laboratory ash from Tallawarra power station feed coal (Baker and Holcombe 1988b)
and general shape although the material was coarser than nonnal power station fly ashes A comparison of the resistivities of boiler and laboratory ashes is illustrated in Figure 23
Measurement of ash resistivity must ideally be measured under the same gas and temperature conditions as those at which the precipitator will operate The packing density should also be the same as that of the dust layer deposited on the precipitator collectors Dust resistivity measurements do not correlate very well with experience in ash precipitation efficiency
Laboratory resistivity tests are not standardised by ASTM BS AS nor ISO The Institute of Electronic and Electrical Engineers in the UK standard IEEE 548-1984 describe a resistivity test designed for testing compressed fly ash at 96 water vapour by volume (IEEE 1984) Measurements of resistivity are usually taken during both heating and cooling of the sample (Young and others 1989) Figure 24 illustrates the resistivity curves against temperature for ashes from a South African coal and Polish and South African coal blend respectively It can be seen that there is a degree of hysteresis as a result of the effect of moisture in the ash
5
3
2
103
E Eo 5 c 0 4
2 323shy
s ~
200 Q)
a
102
5 4 South African coal 3 50 Polish50 South African coal
2
100 120 140 160 180 200
Temperature degC
Figure 24 Laboratory resistivity curves of ash from a South African coal and from a blend of South African and Polish coals against temperature (Cortsen 1983)
62
Post-combustion performance
which gives a lower resistivity and which disappears after the heating process (Cortsen 1983)
The drift or migration velocity in a particular electric field can be estimated by examining the dielectric constant and particle size distribution as well as the aerodynamic factors for the fly ash A technique has been developed for determining particle dielectric constant from resistivity cell tests and other measurements (Baker and Holcombe 1988a) Particle size analysis of simulated ash is not reliable because of the difference in severity of the combustion process between full scale and test combustor Optical and scanning electron microscopes can be used to assess the shape characteristics of the fly ash
Prediction of fly ash precipitation characteristics remains an inexact science so that both pilot plant testing and electrical simulation studies remain extremely important in determining the precipitability of fly ash in practice
Fabric filters Although the use of fabric filters has become more widespread in recent years with the continued preference for low sulphur coals and to reduce stack emissions further there are no coal quality tests which relate to their performance directly
As described in Section 523 in cases where sorbent injection into the flue gas is used to control sulphur emissions collection of the fine sorbent in the bag can confer a high surface area to the gas and enhance the sulphur collection performance
While the efficiency of fabric filters is very high it is important to note that problems may occur with the presence of fine ash and acid condensation derived from coal causing
retention of filter cake on the filter fabric after the cleaning cycle due to agglomeration of the cake improving its mechanical strength blinding of the apertures of the fabric by very fine particles clogging of the filter by condensation promoting filter cake agglomeration bag rotting due to acid condensation
523 Technologies for controlling gaseous emissions
A range of methods is available for control of gaseous emissions in particular for SOx and NOx Options include
emissions control in the combustor post-combustion control technologies
lEA Coal Research have produced several reports that review these technologies SOx control technologies are reported in Flue gas desulphurisation - system performance (Dacey and Cope 1986) FGD installations on coal-fired plants (Vernon and Soud 1990) Market impacts of sulphur control the consequences for coal (Vernon 1989) Technologies for
controlling NOx emissions are described in detail in the reports NOx control technologies for coal combustion (Hjalmarsson 1990) and Systems for controlling NOxfrom coal combustion (Hjalmarsson and Soud 1990)
Emissions control in the combustor In-furnace desulphurisation by injection of calcium-based sorbents is not a widely-used sulphur control technology at present mainly because of its inability to achieve as high sulphur removal rates in commercial use as wet or spray-dry scrubbers Promising results are being obtained with sorbent injection followed by enhanced collection in a fabric filter in New South Wales Australia (Boyd and Lowe 1992)
There are several potential problems that may arise from the injection of calcium-based sorbents such as limestone (CaC03) into pulverised coal flames
the additional calcium may interact with the coal ash to reduce the ash melting point with consequent risk of increased slagging and fouling it is necessary to handle increased quantities of solid residue the possible adverse effects of calcium addition on downstream equipment such as electrostatic precipitators and solid residue disposal (see Sections 522 and 524 respectively) the possible influence of sorbent injection on the radiative properties of the flame (Morrison 1982)
To date sorbent injection into the furnace has only been utilised in smaller power stations with low sulphur coal where its low capital costs are particularly favoured Sorbent utilisation rates are generally low although it still results in a significant volume of mixed fly ash and calcium sulphitesulphate residue requiring disposal (Vernon 1989)
The formation of NOx depends mainly on oxygen partial pressure temperature and coal properties such as the content of nitrogen and volatile matter Measures can also be taken to modify the combustion conditions so that they are less favourable for NOx formation (Hjalmarsson 1990) This is usually achieved by some form of air staging Combustion air is admitted in stages in such a way as to limit flame temperature
The implementation of low NOx combustion techniques is much easier and more effective in a new installation compared with a retrofIt Low NOx measures on existing boilers can affect the combustion the boiler and other parts of the power station Combustion measures especially on existing boilers are specific to each boiler Consequently it is difficult to transfer experience of the impact of coal qualities directly
Most NOx abatement investigations have concentrated on determining the coal properties that influence NOx formation such as total nitrogen content volatile matter content and particle size distribution and developing technologies for reducing NOx emissions (Nakata and others 1988) There is limited information available concerning the impact of coal properties on power station performance under low NOx
63
Post-combustion performance
combustion conditions Discussions with power station operators have revealed that coals which previously produced a satisfactory performance prior to low NOx modifications have caused increased carbon in fly ash andor fouling slagging and corrosion along with other problems under low NOx combustion conditions Some possible explanations for this behaviour are presented briefly below
combustion efficiency can be reduced combustion conditions that reduce NOx formation such as low combustion temperature and low excess air are not favourable for accomplishing complete combustion As a result of this the level of unburnt carbon in the fly ash tends to increase If this is not counteracted the high content of unburnt carbon can cause changed conditions in an electrostatic precipitator (Klingspor and Vernon 1988) and make the fly ash unsaleable (see
Section 524) changes may also occur in the characteristics of the fly ash due to the reduced combustion temperature This will make the fly ash less glassy changing its properties and making the fly ash less attractive for use in cement and concrete production the thermal conditions in both the water and the steam parts of the boiler may change through low NOx combustion leading to changes in the temperature profile of heat exchangers Combustion modifications can also lead to an increased furnace exit gas temperature (FEGT) Deposits on heat exchange surfaces can affect heat absorption The reducing atmospheres reduce the ash melting point and can aggravate the problem of causing heat surface slagging Low excess air and staged combustion can produce areas with a reducing atmosphere which cause corrosion to boiler tubes (Coal Research Establishment 1991) the higher pressure drop over burners requires a higher fan capacity This in addition to other measures such as increased mill energy to obtain the required fineness and flue gas recirculation leads to higher power consumption low NOx burners may give longer flames that can cause deposits by impingement Flame stability may also be influenced Decrease in flame stability is usually found at reduced load causing limitations to boiler load turn down
Low NOx combustion was in many cases expected to give a higher degree of slagging and fouling in the boiler The opposite however has also been found Either result causes changes in soot blowing operations (Hjalrnarsson 1990)
Post-combustion control technologies SOx emission is minimised mainly with low sulphur coal Beyond this control is carried out with flue gas desulphurisation (FGD) systems The vast majority of FGD systems use an alkaline sorbent to absorb the flue gas sulphur dioxide chemically There are a number of different types of FGD and the effects of coal changes on their performance depends on the specific design details - no generalisation can be made For example flue gas temperature and SOz level impact the performance of wet limelimestone scrubbers These same variables affect spray dry FGD systems differently (Hjalmarsson 1990)
In wet FGD systems the effects of chloride from coal are generally all negative Chloride concentrations can build to high levels in the wet scrubbing loop causing corrosion problems and greatly reducing scrubber liquid-phase alkalinity (Rittenhouse 1991) However the removal of HCl in spray-dry scrubbers can have both positive and negative effects The HCl in the system can improve SOz removal capabilities resulting in lower reagent costs This effect was noted during a full-scale test conducted by Northern States Power Company in 1983 The addition of an amount of calcium chloride equivalent to a 02-03 increase in chlorine content reduced lime consumption by 25 Pilot tests carried out by EPRI confmn this effect (Collins 1990) The savings in lime consumption usually outweigh the cost of any negative effects including
incomplete droplet drying corrosion of stainless steel components in the system increased pressure drop downstream of fabric filters degraded ESP performance
Reference manuals have been published at IEA Coal Research that evaluate the wide range of FGD systems (Vernon and Soud 1990 Dacey and Cope 1986)
Where power station limits for NOx emissions cannot be met by combustion control flue gas treatment has to be installed The dominant method in use is selective catalytic reduction (SCR) In the SCR method the NOx concentration in the flue gas is reduced through injection of ammonia in the presence of a catalyst The role of the catalyst catalyst types and the reaction mechanism are described extensively by Hjalmarsson (1990) The efficiency of NOx reduction is primarily dependent upon condition of the catalyst which in tum is dependent upon the type of catalyst its susceptibility to poisoning and its location in the flue gas flow
The positions that are used for catalyst location are high dust low dust and tail end In the high dust location between the economiser and the air preheater the flue gases passing through the catalyst contain all the fly ash gaseous contaminants and sulphur oxides from combustion This can cause degradation of the catalyst leading to a decrease in NOx reduction efficiency The main types of degradation that are coal quality related are
deposition of fly ash causing clogging of the pores of the catalyst (Balling and Hein 1989) poisoning of the active sites of the catalyst by compounds such as alkali ions (sodium potassium calcium and magnesium) especially in sulphated form and some trace elements such as arsenic (Gutbertlet 1988 Balling and Hein 1989) erosion of the catalyst A high fly ash content in addition to an uneven particulate concentration and size distribution are most likely to cause erosion problems
The lifetime of a catalyst in this position is considerably shorter than in other positions Nakabayashi (1988) reported from a comparison of the impact of position on catalyst characteristics that catalyst life can range from 2-3 years in
64
Post-combustion performance
Table 23 Effect of coal type on total concentrations of selected elements from fly ash samples (Ainsworth and Rai 1987)
Mean and range of concentrations in fly ashes (Ilglg solid) from
Element Bituminous Subbituminous Lignite
Arsenic 219 (11-1385) 191 (8-34) 544 (21-96)
Cadmium 117 laquo5-169) lt5 lt5
Chromium 245 (37-609) 73 (41-108) 284 laquo40-651)
Molybdenum 56 (7-236) 165 laquo4--55) 141 (8-197)
Selenium 123 laquo5-435) 142 laquo5-281) 184 laquo5-469)
Vanadium 290 (99-652) 133 laquo25-292) 209 (lt25-268)
Zinc 607 (65-2880) 148 (27-658) 647 (25-127)
mean value is followed by range in parenthesis for 26 8 and 5 fly ashes from bituminous subbituminous and lignite coals respectively
a high dust location compared to 3-5 years in the tail end position
A low dust location means that the catalyst is situated after a hot gas electrostatic precipitator and before the preheater The flue gas reaching the catalyst is almost dust free but still contains sulphur dioxide which may result in poisoning of the catalyst
Tail end systems have the catalyst situated in the end of the chain of flue gas purification equipment after the desulphurisation plant The flue gases reaching the catalyst therefore contain only small amounts of sulphur oxides and particulates
NOx can also be controlled through thermal reactions by using appropriate reducing chemicals The process is called selective non catalytic reduction (SNCR) It has been found that different conditions in the flue gases influence the reactions and the temperature window (Mittelbach 1989 Gebel and others 1989) High CO content (gt1000 ppm) reduces the removal efficiency High S02 content increases the reaction temperature (Hjarlmarsson 1990)
Numerous processes have been developed for combined desulphurisation and denitrification of gases Most processes are still at the laboratory scale and there are a few stations operating at full commercial scale Coal quality effects on combined removal processes have not been studied extensively The problems encountered during the implementation of the individual abatement technologies may also be exacerbated for the dual systems An lEA Coal Research report Interactions in emissions control for coal-fired plants (Hjarlmarsson 1992) examines the interactions between control of S02 NOx and particulate emissions with different combustion methods and also the production of solid and liquid residues An understanding of the impact of coal quality on emission control technologies must be achieved for future efficient implementation of control systems
Trace elements emissions during combustion can also become associated with fly ash andor bottom ash Because of vaporisation-condensation mechanisms most of the trace elements in fly ash are often higher in total concentrations than those found in the corresponding bottom ash (WU and Chen 1987) In addition the levels of many trace elements including Cr Mn Pb n and Zn are often concentrated on the surfaces of the fly ash particles Typical median concentrations of selected trace elements in fly ash from different coal types are shown in Table 23 In power stations equipped with wet FGD systems the sludge from the scrubbers is a combination of spent solvent calcium sulphate and sulphite precipitates and fly ash The quantity and distribution of trace elements occurring in sludge are essentially determined by the coal ash composition and may influence the disposal cost of the material (Akers and others 1989)
524 Solid residue disposal
A typical pulverised coal fired power station employing ESPs or baghouses for particulate control and FGD for SOx control can produce three types of residue bottom ash (including slag) fly ash and FGD sludge Although under favourable conditions increasingly large amounts of these residues are utilised for various purposes at a net profit to the utility (Murtha 1982 Taubert 1991) it is anticipated that utilisation will not eliminate the need for disposal at a net cost in the foreseeable future
Changing coal characteristics can impact both the quantity and characteristics of the residue Power stations with limited resources for residue disposal have to transport the ash to alternative locations Ash for disposal may be conveyed to the disposal site as a dilute slurry Cerkanowicz and others (1991) reported that physical and rheological properties of fly ashes vary from different power stations This can impact the flow properties of fly ashwater mixtures significantly
The major factors that affect the amount of residue produced
65
Post-combustion performance
Table 24 Summary of the effects of coal properties on power station component performance - III (after Lowe 1987)
Property Contributing properties
Ash and dust plant
Ash quantity per unit heat release
Slagging propensity
Ash solubility
Erosiveness
Clinker reactivity
Environmental control
Coal cleaning
Particulate control ESP Dust burden (Ash per unit gas volume) Gas flow per unit heat
Ash resistivity
Sulphur
Fabric filters Dust burden
Gas flow per unit heat
Combustion measures
Post combustion
Residue disposal
ash level heating value grindability
ash elemental analysis ash fusion temperature coal particle mineral matter
ash elemental analysis ash mineral composition
mineral matter elemental analysis coal size distribution trace element
ash heating value ultimate analysis CIH ratio moisture level
ash heating value ultimate analysis CIH ratio moisture level
sulphur nitrogen volatile matter
cWorine fly ash size trace elemental analysis
ash ash elemental analysis sulphur heating value trace elemental analysis chlorine content
Effect
A I increase in ash quantity per unit heat release increases the ash and dust plant duty by 1
High slagging propensity increases the duty on ash extraction plant Formation of large clinkers may cause blockages in hopper doors and contribute to ash crusher problems
For wet hopper systems with recirculated water formation of scale pipelines may cause problems
Increased erosiveness will increase wear in pipelines and sluiceways
Some coals produce clinker in the furnace which is prone to explosive release of energy on quenching in the ash hopper
Different techniques are required depending upon the type and size distribution of the mineral matter Coal particle size influences the efficiency of the cleaning process and overall organic coal recovery
A 1 increase in dust burden will increase emissions by 1
A 1 increase in gas flow per unit heat release will increase emissions by 15 A resistivity change of 1 order of magnitude would suggest an increase in emissions by a factor of 2 General trend for reducing resistivity as sulphur increases possibly one order of magnitude per 1 sulphur change Below 1 sulphur resistivity is dominated by other factors
Differential pressure will increase with dust burden
A 1 increase in gas flow per unit heat release will increase unit heat differential pressure over the filter bags by 1
Influences the amount of sorbent used and dust collecting efficiencies Use of low NO burners can influence the combustion conditions and promote slaggingfouling due to reducing conditions present
Can have a positive and negative influence on SO removal efficiencies Can cause a reduction in catalyst efficiency in the removal of NObull
Quantity and quality influenced by the properties Saleable byshyproducts can be contaminated by carbon carry-over and trace elements
Quality of FGD waste can be influenced by cWorine and trace elements content
66
Post-combustion performance
annually by a pulverised coal fIred power station are the following
coal consumption ash content of the coal sulphur content bottom ashfly ash ratio fly ash collection efficiency SOx removal efficiency
These in turn influence the land requirement for residue disposal Ugursal and Al Taweel (1990) use the parameters listed above for calculating the area requirement for power station ash and FGD sludge disposal
The characteristics of the solid residue are particularly important where the residue materials must meet specifIcations to be sold (Cerkanowicz and others 1991 Bretz 1991b) For example the key requirement for the use of fly ash in cement production is the carbon content (Tisch and others 1990) A typical specifIcation is less than 5 carbon A coal change which degrades mill performance affects flame stability or reduces the rate of char oxidation such as in the case of low NOx combustion measures may increase the carbon content enough to exceed this carbon specifIcation (Zelkowski and Riepe 1987) Such a change would result in a considerable net cost to the utility since the fly ash would need to be disposed in a landfill at some cost instead of being sold for cement production at a profIt (Folsom and others 1986b) Similar problems can occur with FGD solid residue use for gypsum production The chlorine content of the coal is becoming an increasingly important consideration for power stations that have an established market for the gypsum produced from FGD residue as the chlorine impacts the quality of the gypsum for sale
The trace element content of combustion residues is an important consideration for both disposal and utilisation purposes (Clarke and Sloss 1992) The concentrations in power station residues may vary signifIcantly depending primarily on the coal used and on the cleaning techniques and combustion methods employed Therefore if the residue disposal strategy of the power station includes residue utilisation then a detailed knowledge of trace element content of the coal being fired is essential An lEA Coal Research report Trace elements emissions from coal combustion and gasification examines the behaviour of trace elements within these systems in more detail than can be discussed here (Clarke and Sloss 1992)
53 Comments The properties of coal affect the performance of the post combustion components of the power station These impacts are summarised in Table 24 As has also been highlighted in Chapters 3 and 4 many empirical relationships have been developed and used to describe the problems that are encountered in these systems but there are some signifIcant uncertainties related to many assumptions made For the post-combustion components these can include
fly ash collection - there is considerable disagreement as to the best method of measuring fly ash resistivity There is no correlation between coal composition and fly ash fIneness technologies for controlling gaseous emissions - there is no adequate means to predict NOx emissions
Whenever a change in coal supply is considered it is important to pay attention to the downstream effects
67
6 Coal-related effects on overall power station performance and costs
The production of electricity at the lowest busbar cost at a coal-fired power station depends on
the capital costs of the power station the delivered cost of the coal consumed overall power station performance the way in which the capital costs are financed during the construction and operating life of the station (interest depreciation profits taxes etc) the cost of decommissioning the power station at the end of its life
Coal quality can affect each of the above factors except for the last two components The main aim of this chapter is to look at coal-related effects on overall power station performance and costs
61 Capital costs The capital costs in most cases are affected by the range of coal qualities envisaged at the design stage (Mellanby-Lee 1986) In a study done by Ebasco Services Inc (Cagnetta and Zelensky 1983) the capital costs of a new power station are estimated for a wide range coal and a dedicated coal specification The wide range coal characteristics encompass about 90 of the recoverable reserves east of the Mississippi in the USA while the dedicated coal characteristics vary over a much narrower range Table 25 gives details of coal quality values for both types of coal and the costs with respect to the design for the wide range coal type It can be seen that the cost of a power station to bum a wide range of coals is $54 million more expensive than the design for a dedicated coal supply
A decision to bum high sulphur coal in a power station may necessitate the installation of an FGD or other emission control technologies FGD the best established technology to control emissions can be costly typically adding up to 20 or more to the total capital cost for new capacity and around
Table 25 The effect of coal quality on the costs of a new power station (Cagnetta and Zelensky 1983)
Coal Wide range Dedicated
Heating value GIlt 2442-3315 2949-3282 Moisture 10-150 10-65 Ash 60-180 64-146 Sulphur 05-40 17-32 HGI 40-64 45-60
Power station capital costs $ million coal handling +03 base steam generators +66 base ash handling +10 base ESP +417 base FGD +46 base total 1086 1032
Figures are for a 2 x 600 MW net power station they exclude coal costs
30 to power station capital costs when retrofitted to existing power stations (Vernon 1989) Control costs for NOx an additional environmental consideration are lower adding some 6-10 to the total capital costs of large new plants but as with FGD costing more when retrofitted (Hjalmarsson 1990 Daniel 1991)
62 Cost of coal The cost of internationally traded coal varies considerably For the third quarter of 1991 the lEA reported that the average cif coal import prices in Europe Japan and the USA were 4927 4998 and 3425 US$lMt respectively The range of prices to the two major importing areas that is the EC and Japan were 4320-5068 US$lMt and 4451-5180 US$lMt respectively The variation in prices is influenced by geographic location transport costs and coal quality The lEA reported that countries describe thermal coal using different average coal quality values for example the lower
68
Coal-related effects on overall power station performance and costs
heating value of a steam coal as detennined by the EC is 2617 MJkg (6251 kcalkg) compared with Japan at 2466 MJkg (5890 kcalkg) (International Energy Agency 1992)
Ash contents of traded coal vary substantially from under 5 for Colombias Cerrej6n coal for example to over 20 for typical South African thermal coals (see Table 26) Most of the traded coals have an ash content below 15 with the average being around 12-13 Given the associated costs of ash handling and disposal (see Section 63) coals with high ash contents will attract a lower price than those with lower ash even when corrected for heat content because of the application of penalties Many utilities and traders have a formula for calculating price penalties in relation to ash content Estimates of penalties vary depending upon the equipment in place It is probable given the increasing concern about the disposal of combustion residues that these ash penalties may increase during the next decade and a half
Table 26 Ash contents of traded coals (Doyle 1989)
Low Medium High lt8 8-15 gt15
Colombia Canada South Africa Venezuela China Indonesia Australia
Poland USA South Africa
While ash characteristics have traditionally most worried boiler managers sulphur content has become more significant in recent years because it is the primary determinant of the cleanliness of a coal in relation to S02 emission standards Most traded coal is low sulphur Only a small volume has a sulphur content above 15 However as S02 emission standards have tightened there has been a noticeable downward shift in what is considered low sulphur coal The defmition of low sulphur is now perceived to be below 09-10 and an increasing amount of traded materials now below 06 Various studies have deduced that low sulphur coal could command a premium price of up to one third greater than high sulphur coal (Doyle 1989 Calarco and Bennett 1989) Doyle (1989) also reported that at the most general level the low sulphur premium must be less than or equal to the smaller of either FGD costs or coal cleaning costs Otherwise buyers would take higher sulphur coals In practice the situation is more complicated For some users regulations may make the use of low sulphur coal or FGD equipment compulsory An excessive premium on low sulphur coal may also bring gas frring inter-fuel competition into consideration
63 Power station performance and costs
Several investigations of coal qualitypower station performance relationships have been conducted by utilities and other organisations These have been reviewed by
Folsom and others (1986a) In general the manner in which station performance evaluation of the impacts of coal quality have been assessed was by considering the following four performance categories
capacity - the capability of the unit to produce design load
heat rate - a measure of the net energy conversion efficiency
maintenance - the cost of maintaining all components in suitable working order
availability - a measure of the degree to which the unit can be operated when required
A summary of coal quality effects on these categories is presented under these headings
631 Capacity
The utility industry uses a number of definitions for station capacity In this discussion the term capacity will refer to the maximum rate of power generation for a specific unit under given operating conditions It should be noted that changes in this definition of capacity mayor may not be of economic consequence to a utility The need to operate a specific unit depends on
utilitys power demand available capacity system-wide relative costs of operating the specific unit compared to other available units
Fuel quality can affect unit capacity in a number of ways An analysis of the way fuel quality affects the capacity of each component of a generating station can reveal the total impact This analysis must start with the component most critical in detennining power station capacity The next step is to estimate the effects on less critical components The effects of successively less critical components may be interactive with the impacts on more critical components In some cases a change in fuel quality may affect one component to such an extent that it becomes the most critical item
Since a coal-fired steam-electric unit has a large number of components detailed analysis can be quite complex In Chapters 3-5 the effects of coal characteristics on the seven major components of a power station were described The capacity of the component was often influenced by these effects In many cases these effects could be evaluated with reasonable accuracy using existing straight forward engineering procedures In other cases assumptions on coal behaviour had to be made to facilitate the calculations As was summarised in Sections 34 43 and 53 there are some significant uncertainties related to many assumptions made
632 Heat rate
Heat rate (HR) is an index of the overall efficiency of a power station expressed as the heat input in the form of coal (Qin (MJIhr or BtuIhr)) required to produce one unit of electrical energy It may be expressed on a gross or net basis Gross heat rate (GHR) is based on the total or gross power
69
Coal-related effects on overall power station performance and costs
(GP) produced by the turbine generator while the net heat rate (NHR) is based on the GP reduced by the auxiliary power (AP) NHR depends on the turbine heat rate (THR) boiler efficiency (BE) GP and AP and it may be calculated as follows
NHR= THR x GP BE (GP-AP)
The coal changes which affect heat rate are associated primarily with boiler thermal efficiency auxiliary power consumption and turbine cycle efficiency (via changes in steam conditions) The following three sections describe how coal characteristics can affect boiler efficiency auxiliary power consumption and turbine heat rate respectively
Boiler efficiency The most widely used method of evaluating the impacts of coal characteristics on boiler efficiency is to assess the heat losses from the boiler and to assume that the remainder of the heat is absorbed to produce superheated or reheated steam This approach has the advantage of eliminating direct measurement or calculation of heat transfer rates in each section of the boiler which are quite complex but can only be carried out with suitable probes on fully instrumented boilers
The procedure involves the calculation of around six types of heat losses (Corson 1988) These can be
dry flue gas loss heat losses due to fuel moisture heat loss due to moisture produced from the combustion of hydrogen in the fuel heat loss due to combustibles and sensible heat in the ash
heat loss due to radiation unaccounted heat losses
Dry flue gas loss which is usually the largest factor affecting boiler efficiency increases with higher exit gas temperatures or excess air values Every 35degC to 40degC increment in exit gas temperature is reported to reduce boiler efficiency by 1 A 1 increase in excess air by itself decreases boiler efficiency by 005 ill most boilers however increased excess air leads to higher flue gas exit temperatures (FGET) Consequently increases in excess air can have a twofold effect on unit efficiency (Singer 1991) Calculations of excess air requirements depend on
flame stability carbon burnout slagging and furnaceconvective pass heat transfer considerations
These are difficult to predict with existing correlations
Losses due to moisture and fuel hydrogen are calculated easily from the coal analysis data using straight forward chemical and physical relationships
illcomplete combustion is manifest primarily by carbon in the bottom and fly ash The carbon content of the ash is difficult to predict and is affected by the slagging and fouling characteristics of the coal If the furnace is large enough to avoid slagging and fouling problems the carbon content of the ash is often less than about 5 For any furnace the carbon content of the ash tends to increase as the excess air decreases Also carbon loss may vary with char reactivity which depends on coal characteristics such as particle size
Table 27 Calculation of boiler heat losses (Folsom and others 1986a)
Loss
Dry gas
Fuel moisture
Fuel hydrogen
Combustibles
Radiation
Data required
Coal ultimate analysis Excess air Exhaust temperature Product specific heat
Coal moisture content Exhaust temperature H20 latent and specific heat
Coal hydrogen content Exhaust temperature H20 latent and specific heat
Carbon content of ash Coal carbon and ash content Heating value of carbon
Total heat output Maximum continuous rating
Assumption Comments
Complete combustion based Carbon corrected for on ultimate analysis carbon lost to ash shy
usually the largest loss
Complete combustion of fuel hydrogen to H20
Neglects CO and HxCy emissions which are usually negligible
External surface temperature Usually less than 05 Ambient air velocity over surfaces Independent of coal characteristics Calculated using ABMA chart
Unaccounted None Allowance for Usually estimated as about 05 bottom ash quenching Independent of coal characteristics CO and HxCy emissions Miscellaneous
70
Coal-related effects on overall power station performance and costs
rank and petrographic composition and combustion as the heat absorption pattern in the boiler changes Also if conditions At present there is no satisfactory method of the acid dew point of the flue gases changes the operators predicting the carbon content of the fly ash andor may need to adjust furnace exit gas temperature (FEGT) so combustibles loss based on standard coal analysis alone as to maintain the minimum air heater metal temperature Most coal quality analyses merely assume that the carbon above the acid dew point to avoid air heater corrosion loss guarantee provided by a boiler manufacturer will not be Whilst largely empirical procedures are used the actual exceeded This is usually in the range of 5 since fly ash amount of available data are insufficient to determine the with higher carbon content has less value for subsequent use accuracy of this approach Thus improved procedures need such as feed stock for cement manufacture (see to be developed and evaluated for assessing excess air flue Section 524) For coals with 10 ash and 60 carbon as gas exhaust temperature and combustible loss as a function fired 5 in the fly ash corresponds to a carbon utilisation of coal characteristics for a given furnace efficiency of 9912 (Folsom and others 1986a)
A summary of the data required for calculating heat losses is Procedures have been developed to predict combustibles loss given in Table 27 Combustion handbooks published by the based on furnace models An example of this is a boiler manufacturers include detailed descriptions of 3-dimensional model developed by the Energy and procedures for evaluating these losses (Babcock amp Wilcox Environmental Research Corporation USA (EER) This 1978 Singer 1991) These calculations are complex but includes a char combustion sub-model which evaluates the nevertheless straightforward and can be automated via a combustion process as a function of the micro-environment computer program easily An illustration of typical boiler surrounding individual char particles (WU and others 1990) losses for four Australian Queensland steaming coals is given Several more simplified approaches to carbon loss prediction in Table 28 have been developed All involve burning the coal under controlled laboratory conditions measuring the carbon loss Auxiliary power consumption and then scaling these data to full-scale units (see Power station auxiliaries consume power for Section 421)
coal handling In the calculation of boiler efficiency the flue gas exit mills temperature (FGET) is usually assumed constant However a feedwater pumps detailed evaluation should consider that the FGET may vary soot blowing
Table 28 Typical boiler losses for four Australian Queensland steaming coals (St Baker 1983)
Coal type A B C D
As-burnt - Total moisture 70 160 100 110 -Ash 214 143 100 280 -Carbon 581 535 676 487 - Nitrogen 11 09 15 09 - Hydrogen 39 34 38 32 - Sulphur 04 03 02 02 -Oxygen 76 111 64 75 Unburnt carbon 05 05 05 05
Gross heating value GJt 2412 2120 2738 1998 Latent heat of evaporation 102 112 106 096 of H20 from coal OJt Net heat value GJt 2310 2008 2632 1902 Unburnt carbon loss GJt 017 017 017 017 Radiation amp other losses OJt 013 012 015 011 Total dry air per tonne of coal tit 9130 8180 10433 7556 Sensible heat in combustion air OJt 221 196 252 183 Total heat available OJt 2501 2175 2852 2057 Overall total combustion products t 10130 9108 11433 8556 Exit flue gases (at 130degC) OJt 0108 0110 0108 0110 Flue gas exit loss GJt 110 100 123 094
Heat balance Heat input in coal 1000 1000 1000 1000 - Flue gas exit loss 46 47 45 47 - Heat loss due to H20 42 52 39 48 - Loss to unburnt carbon 07 08 06 09 - Loss to radiation etc 05 05 05 05
Net heat to watersteam 900 888 905 891
71
----
-----------
Coal-related effects on overall power station performance and costs
fans 200 shyparticulate control
flue gas desulphurisation shy-~ 0
Auxiliary power is typically in the range of 50 to 100 of gross power and is highly dependent on the specific power station design However coal characteristics also affect power consumption for most of these components although the impacts in many cases are not large and can be evaluated by considering trends
The primary factors impacting the power requirements for coal handling are the design of the systems and the desired coal flow rate The design of coal handling systems varies substantially and power requirements can be determined accurately by considering the details of the specific designs Since coal handling equipment normally operates intermittently any change in coal flow rate will change the duty cycle of the equipment and the power consumption will be approximately proportional to the coal flow rate This assumes that no modifications to the coal handling equipment are made to increase capacity In some analyses the coal flow rate is assumed to be inversely proportional to the coal heating rate on the assumption that the total heat input remains constant However as discussed earlier any change in heating value may change the performance of several other power station components and impact overall heat rate This compounding effect means that changes in coal flow rate are often greater than would be expected based on heating value alone
The power required for coal grinding depends on mill design characteristics of the coal feed including its grindability and size distribution and the mill operating conditions including the coal flow rate and pulverised coal size distribution The manufacturers have developed power consumption correlations based primarily on Hardgrove grindability index (HGI) Cortsen (1983) reported that the power consumption of the mills at a Danish utility was mainly dependent on the grindability of coal In evaluating mill performance it must be recognised that for a given design the operating parameters are linked It is not possible to vary the coal flow rate HGI and pulverised coal size distribution independently This is illustrated in Figure 25 which shows the effects of an independent change of coal grindability on the performance of a pilot vertical spindle mill (Luckie and others 1980) However Folsom and others (1986a) put forward the theory that reasonably accurate evaluation of coal changes have been made by assuming that the power consumption varies linearly with the coal flow rate independent of coal grindability in cases where variations in HGI are small St Baker (1983) reported that the power consumption of mills increases with increases in moisture content
There are few data that can be used to determine the number of soot blowers and frequency of operation for a specific coal The usual procedure is to select the wall blower array based on experience with similar coals and to set the wall blower operating schedule during normal boiler operation to minimise slagging and fouling problems The actual frequency of soot blowing will depend on the severity of
a5 sect 5 0
Cii 0 ()
100 ---shy--constant coal flow rate ---
0
40 50 60 70
Hardgrove grindability index (HGI)
80
100 -
o 40 50 60 70 80
Hardgrove grindability index (HGI)
10 shy
5
o 40 50 60 70 80
Hardgrove grindability index (HGI)
Figure 25 Effects of grindability on vertical spindle pulveriser performance (Luckie and others 1980)
slagging and fouling In some cases certain boiler stages may be blown unnecessarily and incur a heat rate penalty Excessive blowing can result in erosion of the tube surfaces which leads to premature tube failure and subsequent forced outages Proper blowing schemes are critical in achieving target steam and flue gas exit temperatures Wall blowers can utilise steam or air as the blowing medium The steam consumption can be treated as auxiliary steam use and can be evaluated in terms of its impact on heat rate Compressed air is generated in motor driven air compressors and the compressor power consumption can be evaluated as part of the auxiliary power load which has a greater impact on overall heat rate
The power consumption of fans in a power station is based
72
Coal-related effects on overall power station performance and costs
on the required flow rate and pressure rise fan design and the method of fan control Given these parameters the power requirements may be calculated easily based on standard fan analysis procedures In general a coal change that causes an increase in flow rate or pressure rise for example as a result of a reduction of cross-sectional flow area due to ash deposit bridges will increase fan power requirements (Borio and Levasseur 1986)
Essentially all the power consumed by an electrostatic precipitator for particulate control is used to generate the corona The power consumed to charge and deposit particulates is negligible while collection efficiency increases with corona power (Folsom and others 1986b)
The auxiliary power requirements of the flue gas desulphurisation (FGD) systems depend on the equipment designs which vary substantially among operational systems employed internationally A number of reference manuals have been published which provide procedures for evaluating the impacts of coal quality on flue gas desulphurisation systems These manuals should be consulted to conduct a detailed evaluation of the impact of coal characteristics on flue gas desulphurisation system auxiliary power (Dacey and Cope 1986) Generally the FGD facility will require more auxiliary power when operating with a high sulphur coal
Turbine heat rate Turbine heat rate is an index of the efficiency of the steam cycle and generator set in converting heat supplied to the turbine in the form of superheated or reheated steam to electrical power The turbine heat rate depends on the specific design of the turbine cycle as well as the operating conditions principally the steam supply and the discharge conditions
Since the coal does not come into contact with the steam coal quality impacts on turbine heat rate are neglected in many analyses However coal quality can impact the steam supply characteristics by changing the distribution of heat absorption among the various heat transfer surfaces in the boiler as discussed earlier in this section It should be noted that this is distinct from the total quantity of heat absorbed which is related to the boiler efficiency Changes in the heat distribution may result in an inability to achieve the required superheat or reheat temperatures or necessitate excessive attemperation to moderate steam temperature Both effects can degrade turbine cycle efficiency significantly
Evaluation of the effects of coal characteristics on steam temperature and hence turbine heat rate requires analysis of the radiative and convective heat transfer occurring in the various boiler sections and consideration of the options available to boiler operators to vary steam conditions (see also Section 42) A wide range of heat transfer models of varying complexity for the furnace and convective surfaces have been created (Shida and others 1984 Robinson 1985 Boyd and Kent 1986 Fiveland and Wessel 1988 Pronobis 1989) (see also Section 72)
The effects of coal characteristics on heat transfer evaluated by these methods can be grouped into three categories
gas flow rate changes through the furnace and the tube bank due to the volume of combustion products which mainly affects convective heat transfer radiative heat transfer changes due to varying coal composition combustion conditions and particle deposition heat transfer change due to deposits resulting from slagging and fouling
The volume of combustion products from a coal of arbitrary composition can be evaluated easily by simple combustion principles given the firing rate and excess air The impact of volumetric air flow rate on radiant and convective pass heat transfer can be evaluated using the models The effects of coal composition on radiative heat transfer are more difficult to evaluate As coal composition changes the radiative characteristics of the reacting gases and particles change along with the characteristics of the wall deposits The emissivity and thermal resistance of the ash deposits have the greatest impacts Similarly the effects of fouling deposits on convective pass heat transfer are difficult to evaluate However tests of slagging in pilot-scale furnaces indicate that potassium sodium sulphur ash fusion temperature ash particle size and total ash might be important (Wagoner 1988 Pohl 1990) In contrast Wain and others (1992) have shown in a study of slags from UK power stations that the thermal conductivity of wall deposits is primarily influenced by the physical properties of the slag such as its porosity rather than by its chemical composition
Deposits are formed over the perimeter of the tube quite irregularly so that the effective shapes of the tubes immersed in the flow of flue gases are completely changed This not only impairs the efficiency of the heat exchanger because of the necessity to overcome the thermal resistance layer but leads also to changes of the heat transfer coefficient brought about by the changed flow pattern and the effective shape of the tube cross-sections In the course of time the properties of the deposits also change resulting in further changes of thermal resistance (Pronobis 1989) The ability to remove the deposit by soot blowing and recovery of lost heat transfer is also important and is determined by the thickness strength and phase of the deposit and the available soot blowing power (Wagoner 1988)
If the effects of these changes on heat transfer can be determined or assumed the turbine heat rate can be evaluated via thermodynamic analysis Several computer programs have been developed to analyse complex thermodynamic cycles The limiting factor of the models is the specification of the input parameters
In general the heat rate correlations are perceived to be adequate providing that certain key parameters such as excess air carbon loss and mineral matter impacts can be specified In many analyses these are assumed since coal quality impact data are usually not available An example of the cost implications of a coal change on heat rate for a 1000 MW boiler was compiled by Folsom and others (1986a) Figure 26 illustrates this effect based on various assumptions conceming the unit characteristics The relatively large change in coal quality is shown to result in a
73
Coal-related effects on overall power station performance and costs
Change in coal characteristics
Coal ash increase 10
Coal moisture increase 5
Coal heating value decrease 15
Char reactivity decrease
- carbon in ash increase 2
- excess air increase 0
Ash deposition
- superheat decrease 50degC
- reheat at temperature increase 5
- exhaust temperature increase 10
Loss component Cost impact
ESP
Coal handling
Carbon loss
Dry flue gas
Moisture loss
Fans
Turbine efficiency
070
010
055
079
048
066
118
65 capacity factor base line heat rate 10000 Btu kWh thermal efficiency 89 coal heating value 279 MJkg (12000 Btulb) coal ash 10 coal moisture 5 coal carbon 77 and coal cost 35 Sit
Figure 26 Example of cost impact of a coal change on heat rate for a 1000 MW boiler (Folsom and others 1986a)
cost impact in heat rate of $446 millioniy (1986 prices) which is equivalent to an availability loss of about 5
As an alternative to these fairly complex calculations some attempts have been made to correlate coal quality with heat rate and boiler efficiency statistically (Barrett and others 1983 Kemeny 1988)
Several organisations have developed methods to facilitate the calculation of coal quality impacts on heat rate Some of these methods use computer programs to calculate economic effects directly from coal quality data power station design information and economic assumptions Others make use of manual calculations and rely more on engineering judgement and experience with similar coals
The use of both statistical techniques and computer models is discussed in greater detail in Chapter 7
633 Maintenance
While it is widely accepted in the utility industry that coal characteristics can affect maintenance costs primarily via wear by abrasion and erosion and by corrosion of power station components there is at present no effective method for predicting the effects of a coal change on maintenance Utilities use a range of procedures to account for maintenance costs in coal-fired units Whilst these procedures generally meet utility needs they often make it difficult to evaluate actual coal quality impacts For example while the maintenance cost due to a tube failure may be identifiable it may not be possible to determine whether tube failures relate to coal quality water quality structural problems or other effects (Heap and others 1984) Another significant problem is that maintenance costs are due in part to phenomena which should be predictable and form part of scheduled
maintenance routine for example replacement of expendable components (such as worn mill rollers and balls) Unfortunately they are also due to unscheduled failures which may cause partial or full outages It has been demonstrated that both routine maintenance requirements and unscheduled outages can be affected by coal characteristics
The mechanisms involved in wear of components are discussed in more detail in Sections 32 and 422 For many components the major factor affecting wear rates and hence maintenance costs is the mass of material processed This will be directly related to the heating value of the coal and the heat rate of the power station However as discussed in Sections 32 and 422 certain coal minerals are identified as strongly influencing the rate of wear by abrasion in handling equipment and mills In some instances erosion rate depend on power station design and aerodynamic considerations (Walsh and others 1988 Platfoot 1990)
Increases in unscheduled maintenance costs and consequent reduced availability (see Section 634) even involving reduced boiler life which result from excessive boiler flue gas erosion and corrosion can be considerable In a review of the state-of-the-art methods of reducing fireside corrosion and fly ash erosion as factors responsible for tube failures in boilers Wright and others (1988) reported that both of the effects are considered to be major problems only on units burning coal that is rated as very aggressive (high sulphur alkalis and chlorine) or that contains a high percentage of erosive materials such as quartz and ash Fly ash erosion of primary superheater reheater and economiser tubes were considered to be more serious problems than fireside corrosion An interesting observation from the study was that although there were proven permanent solutions for most of the problems encountered such as coal and hardware modifications these were not widely accepted Evidently the
74
Coal-related effects on overall power station performance and costs
costs of these solutions were perceived to compare unfavourably with continued maintenance activities in spite of the inconvenience of several unscheduled outages annually for emergency maintenance
St Baker (1983) reported that a typical 20-day unscheduled outage on a single 350 MW generating unit to repair boiler erosion damage could cost more than A$2 million in 1983 in replacement power costs alone This would amount to more than A$33 million (US$25 million) at 1991 prices
In a study of the use of declining fuel quality in 110 and 200 MW Czechoslovak power stations Teyssler (1988) showed increased maintenance costs due to higher equipment wear Examples of costs were given as Czech crowns 15-25t ash output in 1988 (US$04-07 (1991raquo for the cost of repair and replacement of heating surfaces damaged by erosion a 1 increase in ash content was found to result in at least a 10 higher cost in mill component replacement
Smith (1988) in a paper describing Tennessee Valley Authority s (TVA) experience with switching to improved quality coal presents a comparison of performance variations at the Cumberland power station (2 x 1300 MW) and Paradise power station (2 x 704 MW 1 x 1150 MW) with coal quality over the period 1977-86 The results show that maintenance costs for the boilers burning equipment and ash handling equipment were reduced with improved quality coal Costs dropped by about US$15 millionyon average between 1980 and 1984 at the Cumberland power station In this case the improvement in quality was achieved by cleaning the coal supply Prior to coal washing the units exhibited extensive slagging fouling corrosion and tube leakages Figure 27 shows the effect of a coal quality change that occurred at Cumberland in 1982 The largest change after washing was a reduction in ash content from about 152 to 92 Sulphur was reduced from 35 to 28 and which heating value went up from 249 MJkg (10712 Btulb) to 271 MJkg (11635 Btulb) In contrast
10 o boilers
A burning equipment 9
LD ash handling equipment co en 8~
c Q 7E $ (j) 6 =gt t5 50 u (l) u 4c ro c 2 3c iii ~ 2
I 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986
Figure 27 Adjusted maintenance cost accounts for TVAs Cumberland plant (Smith 1988)
operation and maintenance costs for the Paradise power station do not show dramatic cost improvements on utilisation of washed coals because major modifications and maintenance improvements necessitating significant investment were also made to the station over the same time period TVA believe that damage done to the Cumberland boiler by years of operating with poor quality coal was still causing problems long after the change to washed coal (Smith 1988) This example illustrates the difficulty of obtaining valid information of coal quality effects on maintenance and other power station performance factors independently from the influence of other modifications and changes in operating procedure
Hodde (1988) in an investigation of work conducted by Blake and Robin (1982) which considered the contribution of coal quality effects to total fuel-related operating costs of the Southern Company USA (see Table 29) concluded that whilst the dominant portion of the total fuel-related bill is the delivered cost of fuel comprising about 80 the remaining costs are associated with problems due to coal quality It was shown that approximately three quarters of the quality-related costs are in maintenance and residue disposal From this assessment Hodde (1988) suggested that maintenance costs relate linearly with coal quality in particular ash and could be calculated in advance This figure together with the price of the coal would account for almost 90 of the total costs associated with the coal This simplified approach is adopted in a number of computer models (see Section 72) However the approach has been challenged by a number of other sources (Folsom and others 1986b Mancini and others 1987 Galluzzo and others 1987 Lowe 1988b) who report that maintenance costs are not linearly related to the mass of ash processed by a power station Additionally there is usually a substantial lag between the initial variation in ash content of the fuel and the first experience of its effect on maintenance costs Consequently care should be taken in the use of linearised maintenance cost assessments to allow for the effects of lead times and incubation
In general the relationships between maintenance costs and coal quality are difficult to assess due to four factors the inadequacies of records maintained by utilities the impact of non-coal-related factors power station design variations and delayed effects of coal quality impacts
Table 29 Total fuel costs for power stations of the Southern Company USA (Hodde 1988)
Costs of total For coals with ash content of
15 20
Delivered fuel cost 83 77
Waste disposal cost 5 6 Maintenance cost 7 9 Ash related unavailability 3 4 Other operating costs 2 4 Slagging and fouling -0 -0
Total 100 100
75
r ~ 250 lt9 c o t3 200 J 0 2 a 0 150 3 o a
Ui3 100
50
o 2 (ij 3
~
0 ro Q)r 0 a J
(fJ
0 ~ 0 gt
5 0
(ij 0 c Q)
3 ~ is
CD
~ 2 ro Q)r Q)
a
0 ltJ)
E 0 c 0 U w
c ~
-0 0 Q) u J 0
Ol c 6l Ol ro iii
Coal-related effects on overall power station performance and costs
Table 30 Comparison of reduced boiler availability on the basis of hours in operation and type of fuel (Pasini and Trebbi 1989)
Mean annual All boilers Hours in operation Type of fuel reduced availability lt105 gt105 oil-gas coal
Furnace wall 220 203 270 184 309 Secondary SH 054 032 113 045 075 Reheater 032 032 032 015 075 Primary SH 019 008 051 005 054 Economiser 013 005 036 012 014
Unheated 020 017 029 025 008 Casing 030 025 043 039 009 Others 045 075 048 045 045
Total 433 365 622 370 588
634 Availability
The availability of a power station is important to both system reliability and generating-company profit Improving availability only slightly can save considerably on reserve generating capacity and the cost of replacement power Availability can be defined as the percentage of time that a unit is available for operating regardless of whether electricity is actually generated The total electricity sent out from a power station is affected by the planned shutdowns for maintenance forced down-ratings forced outages and other reductions in its availability (Mellanby-Lee 1986)
While it is clear that availability can be affected by coal quality the nature of the relationship is not well understood Statistical data-gathering studies such as the programme conducted by the North American Electric Reliability Council (NERC) utilising the Generating Availability Data System (GADS) supplied data relating to the component cause of outages and load reduction but were not able to provide information as to why particular components failed (Electrical World 1987) A study conducted by Combustion Engineering USA has gathered information from coal-fired units of 390 MW and larger on the causes of outages and load reductions in nine major equipment categories related to steam generators Included were
water walls superheaters and reheaters economisers furnace soot blowingbottom ash removal equipment convection-section soot blowing and fly ash removal equipment boiler controls fans mills boiler circulating pumps
The study indicated that water wall superheater reheater and economiser tube leaks account for 80-90 of all forced outages whereas coal milling systems accounted for 50 of equivalent down-time hours in load reductions (Llinares and others 1982 Llinares and Lutz 1985) Pasini and Trebbi (1989) reported similar trends of reduced power station availability for ENEL Italy (see Table 30) Mancini and
others (1988) reported that in a study of the top eighteen causes of full and partial outages at coal-fired stations in the USA for the decade from 1971 through 1980 60 of these causes were related to coal-quality (see Figure 28)
A record of boiler tube erosion at two Australian power stations Munmorah (4 x 350 MW) and Liddell (4 x 500 MW) illustrates the considerable costs that can result from excessive flue gas dust burdens in boilers supplied with off-specification coals particularly ash content above the design level They have experience of
up to 7 per annum additional reduced availability due to outages for the repair of boiler tube leaks reduced boiler life before major refurbishment affecting the economic life and gross power station output over
350
300 Coal related outages represent 60 of total power station outages
E
Figure 28 Causes of coal-related outages (Mancini and others 1988)
76
Coal-related effects on overall power station performance and costs
Southern Electric System USA 10 ] D US Industry average
8
7
6
J lLshy 5 ltt w
4 9339
3
2
90
Early units Early units Later units 1975-77 1985-87
Figure 29 Boiler and boiler tubes equivalent availability factor (EAF) record (Richwine and others 1989)
which the power stations initial capital costs could be recovered the necessity to be complemented by a greater level of standby generating capacity in order to ensure adequate reliability of electricity supply to consumers (St Baker 1983)
Richwine and others (1989) reported the results of an availability improvement programme in the Southern Electric System (SES) USA coal-fired units Due to a decline in availability between 1970-76 increased attention was given to this factor such that from 1977 to 1988 an improvement of over 22 percentage points was achieved This turnaround was accomplished by recognising the problems implementing appropriate solutions and adopting new power station practices The problems included coal-related cases such as boiler tube superheater reheater and economiser tube failures arising from fly ash erosion and slagging Figure 29 shows the increase in equivalent availability factor (EAF) achieved when coal quality upgrades were adopted along with tube maintenance during planned outages and the design improvements of later units to incorporate a wider range of coals while maintaining high reliability Problems encountered with mill operation were recognised as being a result of coal characteristics Many units experienced outages due to fires and flow problems due to high moisture coal
It has been suggested that a 5 increased outage rate for a power station designed for a 30 ash coal compared for one designed for 15 ash is a reasonable allowance for possible loss of availability (ERM Consultants 1983)
Due to the undefinable relationship between availability loss and coal characteristics engineering correlations cannot be used directly to evaluate the impacts of coal quality on availability At present the only way to calculate availability loss due to particular coal parameters seems to be to correlate
performance observations in the operating boiler with coal quality data Illustrations of these type of observations have been given above On a larger scale than single power station observations the statistical studies conducted by TVA (Barrett and others 1982) EPRI (Heap and others 1984) and the National Economic Research Associates (NERA) (Corio 1982) (see also Section 731) provided correlations for availability parameters of boilers with
ash sulphur and the age of the boiler (TVA study) actual ash sulphur and moisture content utilised and differences between actual and design values a complex relationship involving 13 independent variables
Most of the methodologies above resulted in equivalent availability values increasing with ash and sulphur contents which is contrary to expectation The correlation utilising the difference between actual and design coal quality values with availability agreed with expectation in that the availability of a power station should be degraded by deviation from the design coal specification A more detailed account of statistical studies is given in Section 731
64 Comments In any final analysis the economic trade offs which take into account system availability cost of coal (at various quality levels) maintenance costs substitute fuel and capacity costs station replacement costs etc must be analysed for each operating situation Only then can any meaningful and specific conclusions about the cost impact of coal quality on the cost of electricity be made Final judgements are often required to compare these costs with other factors such as diversity of supply reliability control of emissions for environmental reasons balance of trade and currency availabilities in order to make final coal selection decisions
Whichever judgement is made it is widely accepted that the capacity availability and cost of operation of each individual boiler are materially affected by the quality of coal fed to it It is generally believed that availability does not depend on the quality of the design coal and will only be affected if the actual coal burnt is outside the design range (Cagnetta and Zelensky 1983) However experience at some stations have shown that substantial losses in availability or down ratings can occur when the quality of the coal used is not outside the design range A summary of these effects is shown in Table 31 The missing links though in coal quality evaluations are the lack of information concerning power station performance and the ability to attach a price to a change in performance as a result of a change in coal quality
There is also the problem that some affects of a change in coal quality require time to show themselves Proper allowance must also be made for this incubation period
Hitherto the accounting systems of many utilities have not been designed to identify easily the costs associated with coal quality impacts (Skinner 1988) These systems need to
77
Coal-related effects on overall power station performance and costs
Table 31 Examples of boiler fireside variables station and cost components which may be affected by those variables when coal quality is changed (Sotter and others 1986)
Variable type Boiler design Operating conditions cost component
affected Coal quality
Capacity Ash size distribution - organic associations - separate species Moisture content Hardgrove grindability index Sulphur content
Heat rate illtimate analysis Moisture content Slow burning macerals Slagging fouling indices (Steam temperature control)
Maintenance Ash content Ash composition (abrasiveness slagging tendency)
Availability Ash Na 0 CaO Fez03 SiOz etc
be updated and improved if utilities wish to take full advantage of new tools that are becoming available In particular improved data are required to support the
Number of mills Precipitator collecting area
Burner type Furnace size
Number and placement of soot blowers
Heat releasefurnace area Convective tube spacing
Excess air
Excess air Coal particle sizes Burner settings
Load history
Load history Soot blowing interval
increasingly sophisticated computer models which can be used to predict the effect of fuel quality on station performance
78
7 Computer models
The decision to buy particular quality coals from either local interstate or from international sources must include a quantitative evaluation of the impact of coal quality on performance of the power station and ultimately the cost of electric power generation As has been demonstrated in Chapter 6 and illustrated further in this chapter the cheapest coal to buy does not necessarily produce the cheapest electricity Because of the large number of processes involved in the coal-to-electricity chain and the complicated nature of coal-power station interactions engineering and economic evaluation studies are usually both time consuming and costly The methodologies adopted can range from manual calculations and a reliance on practical experience with similar coals through to elaborate computer models which calculate performance and resulting economic impacts directly from coal quality data power station design information and economic factors Use of a computer based model to quantify the impact of coal and system parameters on the cost of electrical generation could substantially reduce the time and cost of these studies In theory such a model would be used to evaluate various approaches and the most economic action could be selected with relative ease (Ugursal and others 1990) However it should be noted that the results from the models are only as good as the data used in particular the coal properties measured to predict combustion performance
For the purpose of this report the types of models available for the evaluation of part or all of the coal-to-electricity chain (see Figure 1) have been identified as belonging to one of four categories described below
least cost coalcoal blend models that assess the cost of coals and their associated transport costs They can calculate suitable coal blends according to power station design specifications to provide the lowest cost purchasing plan They may also include allowances for some maintenance and disposal factors
component evaluation models that predict the performanceefficiency of the subsystems of the power station such as mills boiler ESPs unit models that offer coal quality impact evaluation of an entire power station and in some cases attempt to supply costs of the impacts on generation Two methods most commonly put forward as evaluation techniques include
statistically-derived regression analyses leading to overall power station inputoutput models developed for specifying general utility power station requirements These models however do not usually contain detailed predictions of system operation or design requirements
systems engineering analysis for defining relative impacts of fuel properties on each systems performance These types of models are being developed by both equipment manufacturers and research contractors and utilise in addition to fuel property data (that is proximate and ultimate analyses and slagging and fouling indices) special bench-scale measurements of key parameters and pilot-scale data These data combined with the proprietary models can allow for the determination of operating limits for specific units
integrated site models that bring together the information from unit models systems performance and other models and are integrated directly into the control room data system
In this chapter brief examples of the above methodologies are described with particular emphasis given to unit models which are known to include coal quality impact assessments Although particular attention is given to coal specification details used by the models the overall intention is to provide a cross-section of the procedures and the capabilities of the various methodologies
79
Computer models
71 Least cost coalcoal blend models
Least cost models in most cases use linear relationships for the evaluation and purchasing of fuels for power stations The technique is used to find the lowest cost purchasing plan for a utility fuel buyer from among a large number of fuel supplies available and will meet the constraints imposed by the fuel supplies and by the utilityS system The programs are usually designed to run on personal computers and to be user-friendly (Allman 1987 Bek 1987 Hodde 1988 Maher and Smith 1990)
Examples of this type of model include the International Coal Value Model (ICVM) (Maher and Smith 1990) Least Cost Fuel System (LCFS) (Hodde 1988) and Perfectblend (Bck 1987) and Steam coal blending plan (Allman 1987 1991) for blending coals
Least cost coalcoal blend models are reported to have the ability to conduct an economic evaluation of thermal coals as traded on the world market The main users of the models are identified as power companies buying coals of various properties and costs from a number of sources In many cases
blending of coals would also be employed The coals would be selected by the model in accordance with the coal specification requirements of the power stations based on their design and operating experience They are designed as a tool to determine the real cost of coal and energy at the inlet of the power station being considered (see Figure 1 Sections 1-4 of the coal-to-electricity chain) They permit comparison of all coal properties within allowable power station coal specifications including other coals and blends It allows for the blending of a large number of coals in any desired proportions (Maher and Smith 1990) Examples of the types of input data required and the items included in the results for a Least cost model are given in Tables 32 and 33
This type of model does not apply merits or demerits in value for particular properties for example sulphur The reason given by the developers is that the effect of such properties is very site-specific being dependent on the design of the power station and accessories for example flue-gas desulphurisation environmental regulations applying residue disposal costs etc
Hodde (1988) illustrated the use of the Least Cost Fuel System model by considering a utility system with three
Table 32 Model input output data -International Coal Value Model (ICVM) (Maher amp Smith 1990)
Developer Coal input Generating unit input Key output
Joint Coal Board CSIRO Australia
Gross specific energy Total moisture Proximate analysis Elemental analysis Chlorine Phosphorus Free swelling index Hardgrove index Ash fusion temperatures degC Top size mm Fines ltlmm Sulphur form Ash analysis Cost fob cif Currencies amp
exchange rates Ocean freight costs Insurance costs Handling costs
Power station power output MW Generated thermal efficiency Capacity factor
Gross and net specific energy and other properties calculated to different bases and units
Slagging and fouling tendencies Average blend properties with non-linearity warnings CoalconsumptionUy Ash production Uy Cost of coal at pulverisers in various currencies on a
tonne per consignment and per energy unit basis Thermal coal database
Table 33 Comparison of coal energy costs based on gross heating value (at power station pulverisers) - in order of increasing cost (Maher and Smith 1990)
Coal Cost US$GJ Total Specifications moisture
ash VM gross specific energy MJlkg
BBB 206 90 1193 330 2953 AAA 212 95 1238 316 2909 Blend 2 220 84 1434 288 2903 Blend 1 222 86 1406 291 2901 CCC 229 80 1596 260 2869
80
Computer models
coal-fired power stations evaluating the purchase of coal from eleven coal sources supplying contract and spot deliveries Like the ICVM model the objective function to be minimised includes the sum of the fob mine coal cost transport cost and coal quality costs for all three stations on the system But unlike the ICVM the LCFS includes additional costs related to coal quality that are net of the following
maintenance costs assumed to be linearly proportional to the tons of ash processed by each power station ash disposal costs also assumed to be linearly proportional to the tons of coal burned at each station fuel handling costs assumed to be linearly proportional to the tons of coal burned at each station FGD operation and maintenance cost and FGD residue disposal costs assumed to be linearly proportional to the tons of sulphur removed from the flue gas revenue from the sale of ash for construction material assumed to be linearly proportional to the ash content of the fuel
These factors are calculated separately and fed into the LCFS model Additional constraints can be added for utility application For example some utilities are located in regions which have legislated that a certain fraction of the coal burned for power production must be sourced from the region
These programs make only limited provision for coal quality because most of the effects on costs are non-linear so that they cannot be accommodated by these models Warnings are issued by some models of the non-linear behaviour of coal blend properties for example Hardgrove grindability index ash fusion temperatures and ash analysis
Coal quality impacts that are not assessed by the simple models include
slagging and fouling costs cost of reduced boiler availability impacts of coal quality on gross power station heat rate and boiler efficiency impacts of coal quality on the capacity of various station systems including mills fans and ash handling systems
72 Component evaluation models Since the mid-1970s boiler manufacturers utilities and other research centres have been developing advanced numerical system models that can be used to optimise performance of power station components and hence improve overall system performance Most of the development effort has been directed to modelling the boiler With the increasing availability of substantial computing power numerical simulation of combustion systems is now feasible and provides a new engineering tool for evaluating designs and the complex interactions in the flow and combustion processes More recently the techniques have been applied to improve understanding of NOx formation and control in increasingly complex combustion systems For boilers the intricacy of the models range from single zoned one-dimensional (I-D) models
that predict combustion and thermal efficiency for boilers with staged or unstaged combustion systems (Smith and Smoot 1987 Hobbs and Smith 1990 Misra and Essenhigh 1990) to models attempting to solve the fully elliptic multi-zoned three-dimensional systems with finite difference approximations of the conservation equations for mass momentum turbulence combustion and heat transfer (Thielen and others 1987 Boyd and Lowe 1988 Gomer 1988 Jarnaluddin and Fiveland 1990 Luo and others 1991) A widely used boiler computer code known as FLUENT has also been applied to model PF boilers (Tominaga and Sato 1989 Swithenbank and others 1988 Vissar and others 1987 Lockwood and Mahmud 1989) Other examples are documented in literature and a review of the application of these types of models to addressing both NOx formation and unburned carbon has been presented recently by Latham and others (1991a)
The output from these models includes coal particle trajectories within the boiler predictions of unburned carbon involving coal devolatilisation and char burnout models furnace exit gas temperatures (FEGT) species concentrations heat release and heat absorption (Latham and others 1991a)
The coal characteristics that have been found to have the greatest influence in these boiler models are
ultimate analysis carbon hydrogen nitrogen sulphur oxygen
moisture content volatile matter content ash content heating value particle size distribution
Most of the models do not include provision for the effects of fouling and slagging propensity of a particular coal on heat transfer Work on developing computer models that describes the transformation of mineral matter during combustion the mechanism of ash deposition on surfaces as well as the physical properties of the ash deposit after deposition has been initiated (Hobbs and Smith 1990 Smith and others 1991b Beer and others 1992) Baxter (1992) has recently reported the development of a model that considers ash deposit local viscosity index of refraction and ash composition (ADLVIC) in coal-fIred power stations In contrast to other ash deposition predictor models which are based on the elemental composition of ash ADLVIC is based on the mineralogical description of a coals inorganic matter and can be used to predict changes in these mineral properties with time and their effect on ash deposition as the particles flow through the boiler It has received some validation during a three week test burn in a 600 MW boiler operated by Centrallllinois Public Services The approach of using mineralogical descriptions of a coals inorganic matter has also been utilised in a model called the Slagging Advisor developed by PSI Technologies (Heble and others 1991)
81
Computer models
I
Performance factors
MAXIMUM MILL CAPACITY
INLET AIR TEMPERATURE
GRIND CHARACTERISTICS
POWER ~
I
I
I I
Indicescorrelations
Fineness bull passing 200 mesh bull gt50 mesh
Grindability bull
bull HGI Wear
bull abrasion index bull ash burden bull wear index bull equal life
moisture
Pulverised coal distribution bull Rosin - Rammler distribution
function perameter
Mass throughputMMBtu
HGI
moisture
i
Engineering analysis model
COMPOSITE MILL MODEL
- Maximum capacity bull base capacity (as new - of MCR) bull 10ssMMBtu throughput
- Inlet air temperature bull minimum inlet temperature
- Mill power
I
U)0 ttl
~ 0 Q5
~ 0 0 E
Q Level 1 predictions
Q Level 2 predictions
Figure 3D Mill engineering model analysis approach (Nurick 1988)
Nurick (1988) describes an engineering model for the detennination of performance factors for each major system component as impacted by coal quality The modelling approach for each component is described For example Figure 30 illustrates the analysis approach for the mill engineering model The figure also highlights two levels of prediction capability The first level is based on the manual assessment of indicescorrelations of the coal properties and the second level refers to predictions from correlations obtained from application of the mill model The latter predictions can be included into an overall power station model In this particular case the overall performance model does not include any cost evaluations These models can form part of larger more comprehensive systems engineering unit models as described in Section 73
73 Unit models The development of models to assess the impact of coal quality on overall power station performance was initiated in the 1970s when statistical methods were used to compare historical power station performance and cost data (such as forced outage hours or maintenance costs) with coal use and coal quality data in order to fmd working relationships
More recently engineering-based methods have been employed to predict power station performance directly from coal characteristics by using individual component models as modules in an overall power station model In some of the unit models both statistical assessments and operating experience are employed to produce an overall assessment
731 Statistically-derived regression models
Most statistical studies of coal quality impacts on power station performance have been conducted by utilities and research organisations in the US A notable and extensively publicised statistical study has been performed by Battelle Columbus Laboratories and Hoffman-Hold Incorporated on Tennessee Valley Authoritys (TVA) coal-fired power stations (Barrett and others 1982)
The TVA study was aimed at evaluation of how coal quality impacts on boiler operation and costs Information was collected from nine TVA power stations for the period 1962 to 1980 based on monthly proximate analyses of the coal used power station outages maintenance costs boiler
82
Computer models
Table 34 Boiler groupings in TVA study (Barrett and others 1982)
Plant and unit Size Manufac- Firing Stearn Year put Capacity Coal Firing configuration MWlUnit turer methodsect temperature into
degC COF) commercial gt500 MW lt500 MW Midshy
operation Large Small Eastern Western Wall Tangential
Bull Run 1 950 CE PF-DB 538538degC 1967 j j
(10001OOOdegF) Colbert 1-4 200 BampW PF-DB 566566degC 1955 j j
(l0501050degF) Colbert 5 550 BampW PF-DB 566538degC 1965 j j
(10501OOOdegF) Gallatin 1-2 300 CE PF-DB 566566degC 1956 j j j
(l0501050degF) Gallatin 3-4 328 CE PF-DB 566566degC 1959 j j j
(l0501050degF) John Sevier 1-4 200 CE PF-DB 566566degC 1955-6 j j
(l0501050degF) Johnsonville 1-6 125 CE PF-DB 538538degC 1951-3 j j j
(l 0001 OOOdegF) Johnsonville 7-10 173 FW PF-DB 566538degC 1958-9 j j j
(l 0501OOOdegF) Kingston 1-4 175 CE PF-DB 538538degC 1954 j j j
(l0001OOOdegF) Kingston 5-9 200 CE PF-DB 566566degC 1955 j j j
(l0501050degF) Paradise 1-2 704 BampW Cyc 566538degC 1963 j j
(l 0501OOOdegF) Paradise 3 1150 BampW Cyc 538538degC 1970 j j
(l 0001 OOOdegF) Shawnee 1-10 175 BampW PF-DB 538538degC 1953-6 j j j
(l0001 OOOdegF) Widows Creek 1-6 141 BampW PF-DB 538538degCj[ 1952-4 j j
(l 0001ooodegF) Widows Creek 7-8 550 CE PF-DB 566538degC 1961-5
(l 0501 OOOdegF)
BampW = Babcock amp Wilcox CE = Combustion Engineering FW = Foster Wheeler PF = pulverised fuel Cyc= cyclone fired DB = dry bottom
II Units 1-4 do not have reheat
efficiency and where available griruklbility data The data were organised into 15 groups of similar boilers (see Table 34) In addition six aggregates of these 15 groups were assembled based on the capacity of the boilers (greater or less than 500 MW) coal characteristics (Eastern or Western US coal) and firing configuration (wall or tangential)
A variety of statistical techniques including linear and non-linear multiple regression techniques were used to look for meaningful relationships Power station boiler capacity was considered for inclusion in the analysis but dropped due to lack of precise historical data Operating costs other than maintenance costs as determined by TVA were not deemed dependent on coal quality so that analysis in this area was also discontinued (Barrett and others 1983)
In spite of the fact that considerable quantities of data were available within the TVA system it was recognised at the time that the data were not designed to support this study Hence the preferred data such as data on boiler capacity and detailed coal analyses were not always available The investigators sometimes found themselves under severe
limitations They persisted because they believed that the results from what was originally conceived as a limited study might provide utilities with additional useful information for making decisions conceming coal purchase and use
The study identified some quantitative relationships between certain coal quality properties and power station performance and cost However the statistical analyses suffered from the difficulty of co-linearity (or correlated variables) as it was found that the impact of ash and sulphur also generally increased with boiler age due to unavoidable changes in the quality of the coal supplies over time Analysis of data from most TVA units showed that the ash and moisture contents of the coal together with boiler age had the greatest effect on boiler efficiency (see later Figure 32 on page 86)
Availability on the other hand was found to be influenced mainly by ash and sulphur content of the coal although boiler age was still relevant Only outages attributed to equipment that were exposed to coal flue gas or ash were considered in the analysis Over the range of ash fired at TVA power stations (generally 12 to 14) the statistical relationship indicated that for a typical power station the outage hours
83
Computer models
may vary by 360 hy because of changes in ash content alone Likewise over the range of sulphur values for TVA power stations (generally 10 to 50) outage hours at a typical power station may vary by as much as 870 hy due to sulphur alone
Only maintenance costs for coal-related equipment were considered relevant for evaluating the operating cost variations when fIring different coals It was found that ash sulphur content of the coal and power station boiler age were the independent variables although it was determined eventually that age was not a signifIcant factor affecting maintenance costs so that was dropped from further consideration This is somewhat surprising since it is commonly accepted that maintenance costs for most types of equipment increase with equipment age However the effects of age may have been overshadowed by the effects of changes in coal quality with time especially increasing ash
It was reasoned that maintenance costs were not an instantaneous effect of coal quality but rather a result of firing the coal over a period of time To account for delayed or integrated effects over time (for example erosion) the ash and sulphur mass variables were allocated a lag coefficient of several months in the correlations It was reasoned that correlations which suggested that maintenance costs decreased as ash and sulphur mass increased could be regarded as unreasonable because they did not agree with practical experience Consequently these correlations were dropped from further consideration independent of their statistical significance The final correlations were selected as those which produced the highest correlation coefficient value The correlations for the nine separate TVA power stations are listed in Table 35 There appears to be no relationship between the correlation coefficient and the number of units at a power station In addition to these separate power station correlations an overall correlation was developed The optimum correlations were obtained when the lag coefficient for ash and sulphur were set at six and ten months respectively
The reports and reviews of the study stress that the correlations developed for TVA are not necessarily applicable to other power stations because of some significant limitations of the study (Barrett and others 1982 Heap and others 1984 Folsom and others 1986b) First the correlations are based on only one utility - TVA This utility
has its own design philosophy for selecting units its own maintenance and operation strategy and for some units studied there is only one design fuel a bituminous coal Also over the 19 years of data evaluated the TVA units fired only Eastern and mid-Western US coals Thus the range was limited Furthermore TVAs coal purchasing strategy changed such that the coal quality deteriorated to provide higher levels of ash and sulphur as time progressed Thus it was to be expected that the range in ash and sulphur coefficients in the resulting correlations may be at least partially attributable to age effects Overall the study was viewed as an advance in coal quality impact assessment as it had attempted to address the problem of performance prediction and highlighted the inadequacies of coal quality and performance data records
Other studies have been carried out in an attempt to improve and extend the TVA analytical approach Heap and others (1984) reported that EPRI conducted a statistical study to determine whether the TVA methodology could be applied to a more diverse and larger data set that is 25 utilities The study focused on equivalent availability only No attempt was made to separate coal related and other outages Instead a wide range of boiler design parameters were included in the correlation The analysis also utilised the same coal variables as the TVA study ash sulphur and nwisture
As discussed earlier in Section 634 EPRI used an alternative approach to analyse the data In addition to using the log of equivalent availability as the dependent variable and linear ash and sulphur terms based on the as-fired coal data EPRI also used the equivalent availability directly as the dependent variable and the difference between the actual and power station design values of the ash sulphur and moisture content of the fuel as the independent variables This approach makes the effects of coal changes additive terms rather than multiplicative terms as in the TVA approach and the correlation exhibits a relationship that reflected engineering judgement such that the availability of a power station is degraded by deviation from the design coal specification Heap and others (1984) compared the correlations developed by the TVA and EPRI studies by using them to evaluate the effects on a 1000 MWe unit (see Figure 31) The base availability loss due to coal related effects was taken as 97 Base case coal was the design coal and the effects of increasing ash and sulphur content by
Computer models
Correlation predicts maximum 55465 h
100
lt 806
vi Q) OJ co 605 0 -0 Q) range for 6 ro correlations of ~ 40 large unit groups Cii 0 u 0 Ul 200 0
97
0
Base 5 ash increase
8760 (full year)
8000
CfJ
6000 ~ c Q) OJ CIl 5
4000 ~ Q)
ro ~ Cii
2000 8
o
2 sulphur increase
Decreasing coal quality ---
Figure 31 Comparison of TVA and EPRI availability correlations to a 1000 MW boiler (Heap and others 1984)
5 and 2 respectively were calculated The cost of availability loss was taken as $1000000 The ranges of predictions for the TVA correlations based on the 15 groups of similar boilers the six larger groups and the entire database are shown in Figure 31 The correlations based on similar units cover a wide range Note that the large change in coal quality as represented by the changes in ash and sulphur contents in each case evaluated resulted in some of
the correlations predicting greater outage hours than are contained in a year At the other extreme some of the correlations predict that performance would improve with a decrease in coal quality The range of correlations for the larger groups of units was smaller and shows an increase in cost with decrease in coal quality as does the overall correlation The EPRI correlation predicts a greater cost due to coal degradation than the TVA study by a factor of two
A statistical study conducted by the National Economic Research Associates (NERA) USA and reported by Corio (1982) evaluated the impacts of coal quality on gross heat rate and availability based on the performance of 171 coal-fired boilers with capacities greater than 200 MW included in the Edison Electric Institute (EEl) database Only those units which had burned coal exclusively for three or more years were included in the study As with the TVA and EPRI study the coal quality data were limited to the ash sulphur and mnisture contents
The NERA study developed a single correlation with parameters to account for the differences in unit design Table 36 lists the specific variables and coefficients determined in the regression analysis
Both the TVA and NERA coefficients for the correlations are positive indicating that an increase in ash and moisture will increase gross heat rate (GHR) These trends cannot be compared with the TVA boiler efficiency trends exactly as the dependent variables are different Folsom and others (1986b) in a review of the two studies made an approximate comparison by examining the relative changes in the dependent variables (percentage) as ash and moisture content vary This is equivalent to neglecting the NERA GHR correlation The
Table 36 NERA study - gross heat rate correlation (Corio 1982)
Class Variable
Coal quality
Unit designoperation
Ash H2O
Vintage
Age
Output factor
Firing configuration
Stearn conditions
Feedwater pump
Oil firing
Constant
Type
Linear Linear
Linear
Linear
Linear
Switch
Switch
Switch
Switch
Independent
Year - woo
Years
Reciprocal
Cyclone = 1 Other = 0
Supercritical =1 Subcritical = 0
Shaft = 1 Other = 0 Stearn = 11565 Other = 0
Oil = 1
Coefficient
1107 1326
6770
4884
11517640
18485
-11953
7255
31563
273500
Output factor = capacity factor(service hoursperiod hours) expressed as
85
Computer models
150 150
125 125
gf2 0
(l) (l)10 1015 0
co~ sectco gt gt C C (l) ~1lJ (l)
7gtlJ lJ a5 075 ~ a5 07500Q Q (l) (l)~ lJ ~O lJ
lt0~ ~ (l) 0- (l)
OJ OJ~0c 05 c 05 co co
r r U U
025 025
O-JL------------------------------o o 2 4 6 8 10 o 2 4 6 8 10
Ash
Figure 32 Comparison of ash and H20 effects on boiler efficiency and gross heat rate (Folsom and others 1986b)
comparison made is shown in Figure 32 where the selected trends of the overall TVA correlation are plotted against the trends of the NERA correlation The trends for moisture were shown to be similar but the effect of ash was shown to be a factor of about 45 greater for the NERA GHR correlation
More recently the Illinois Power Company (Behnam-Giulani and others 1991) conducted a statistical study based on a database containing NERC and Utility Data Institute (UDI) USA data of 5600 unit-years for coal-frred units from 1982-88 They developed four statistical models to describe heat rate equivalent forced-outage rate operation and maintenance costs and capital addition costs In terms of coal quality impacts the models indicated that
heat rate increased by 127 and 74 kJlkWh for each percentage point increase in ash and moisture content respectively OampM costs increase by 005 with each percentage point increase in ash capital addition costs including costs due to wear and tear increased by 010 $kW of installed capacity with each percentage point increase in ash Capital addition costs were shown to decrease with increasing percentage sulphur content This is contrary to actual experience and is believed to be an erroneous result caused by inaccuracies in the database
Some of the models for example the heat rate model were reported to display good accuracy while some others for example the equivalent forced-outage model proved to be less accurate It was believed that further refinement to the data and methodologies was necessary and for this reason the
study results were recommended for secondary (not primary) computations
It should also be noted that as in the earlier statistical studies only the coal qualities ash moisture and sulphur content were considered in the correlations This highlights the difficulty of obtaining relevant and reliable coal data and corresponding power station data to form such correlations
To summarise statistical methodologies have been shown to have several disadvantages
engineering data are required The TVA study evaluated boiler efficiency only and the NERA study evaluated gross heat rate only The statistical correlations provide only a portion of the information required to evaluate net heat rate the full range of designs cannot be correlated If separate correlations are developed for each unit or group of similar units the accuracies of the correlations are reduced due to the smaller number of data points Increasing the number of independent variables included in the correlation also reduces the statistical importance of each variable concurrent variation If two variables change in sympathy it is difficult to determine the effects of each variable independently coal quality variables are incomplete All the studies primarily correlated performance with the coal ash sulphur and moisture contents only due to the limited availability of coal quality data However several other coal quality parameters can have significant impacts on heat rate These effects cannot be evaluated statistically based on the existing databases
86
Computer models
database accuracies The accuracies of the statistical correlations are limited in part by the accuracies of the input data It is difficult to obtain coal samples that are representative of a full year or even a month of firing database representativeness Statistical correlations are based on limited databases poor accuracy The statistical correlations have fairly wide error bands
multitude of results For example for any given unit in the TVA system boiler efficiency can be evaluated by the individual correlation capacity correlation fuel type correlation and overall correlation Each of these correlations predicts a different effect of ash and moisture content Also the trends of ash and moisture content effects on boiler efficiency and gross heat rate predicted by the four studies are somewhat different particularly for ash
COAL PROPERTIES POWER STATION DATA
Total moisture Unit size Proximate analysis Transport Ultimate analysis Pulverisation
Sulphur Fly ash collection Calorific value Emission limits
HGI Ash disposal Ash fusion temperature
Ash resistivity
HEAT amp MASS BALANCE
(Combustion drying steam production flue gas loss FGD reheat)
STREAM FLOW RATES ampCOMPOSITION
(coal flue gas fly ash)
COAL TRANSPORT HANDLING STOCKPILING
POWER STATION OPERATIONS
(pulverisation electrostatic precipitation flue gas desulphurisation ash disposal)
NET POWER PRODUCTION
OPERATING COSTS
(centskWh as a function of fob coal price)
Figure 33 Outline of CIVEC model operation (Meyers and Atkinson 1991)
87
Computer models
732 Systems engineering analysis CCI Valuation of Energy Coals (CIVEC) Meyers and Atkinson (1991) have reported on the
Several advanced systems engineering-based models have development of ClVEC a techno-economic model by been developed in Australia Canada and the USA in the last Carbon Consulting International Australia to evaluate coals decade The models can be used to predict the overall on the basis of their cost effectiveness in terms of net power coal-related generation cost and become ultimately the generated when applied to a specific generating system The singular basis of comparison for all coals being considered valuation is based on a reference coal whose properties and taking into account the coals effect on availability power fob price are well established station capacity operating costs maintenance costs and power station performance as well as the unit price of the Details of the coals to be studied and specific power station coal In general the method used by systems engineering parameters are entered into the model Heat and mass models is to apply values to coals being considered with balances are determined using these parameters so that the respect to reference coals whose properties fob prices and annual coal requirement may be established The cost effect performance are well established of the coal properties are determined for different sections of
the power station (see Figure 33) The fob price of the study Many models are now available to run on personal coal is subsequently adjusted to give a power production cost computers whereas in the past large main frame systems equivalent to that obtained with the reference coal This were required to carry out the necessary computations model assumes that the overall power station design will be
suitable for the coals studied in terms of parameters such as Several illustrations that use these techniques based on fouling slagging and NOx emissions predictive calculations and comparison with the performance of reference coals and others that utilise a combination of An illustration of the use of ClVEC to assess a suite of these and statistical techniques are presented below In each typical steaming coals from New Zealand Australia and case the coal qualities used and assumptions made in the USA relative to a reference coal was reported by Meyers and model are highlighted Atkinson (1991) The reference coal used in the study was
Table 37 CIVEC coal specifications input (Meyers and Atkinson 1991)
Base Coal A Coal B Coal C CoalD
Total moisture as 80 140 150 100 90
Total ballast as 224 178 228 220 211
Proximate analysis ad Moisture 22 90 70 25 60 Ash 153 40 85 130 125 Volatile matter 258 370 280 315 335 Fixed carbon 567 500 565 530 480
Total sulphur ad 035 025 035 080 110
Heating value MJkg (gross ad) 280 276 281 289 285 MJkg (gross ar) 264 261 256 267 256
Ultimate analysis daf Carbon 839 800 835 840 830 Hydrogen 50 55 45 50 60 Nitrogen 16 20 20 20 15 Oxygen 91 125 96 82 84 Sulphur 04 00 04 08 11
Hardgrove grindability index 49 50 60 50
Freight rate U5$t 1000 1000 1000 1000 1000
total moisture (as) + Ash (as)
Coal quality data were obtained by averaging numerous coal qualities from various mines Coal A Typical New Zealand steaming Coal B Typical low ash low sulphur Australian steaming Coal C Typical high ash high sulphur Australian steaming Coa1D Typical high ash high sulphur US steaming
88
Computer models
Table 38 CIVEC power station operational parameters (Meyers and Atkinson 1991)
Reference coal Coal A Coal B Coal C Coal D
Quantity Mtly 1453 1483 1503 1448 1409 Boiler efficiency 889 880 885 884 878 Mill-capacity factor 093 127 120 108 105 - Power drawn MW 289 216 222 268 268 SOz in flue gas (ppm) 531 363 528 1168 1636
(gGJ) 231 153 214 498 703 Required ESP efficiency 998 993 996 998 998 Residue Mtly 0228 0068 0134 0219 0235
see Table 37 for coal types
Table 39 CIVEC factors contribution to utilisation value (Meyers and Atkinson 1991)
Basis Base coal at 4085 US$t fob standard plant 90 capacity
Coal type Cost variations US$1t
2 3 4 5 6 Utilisation value US$t fob
A -080 -025 180 270 250 070 4750 B -135 -040 100 150 040 030 4230 C 015 005 000 005 -395 -235 3480 D 135 040 -025 -035 -585 -300 3315
1 Variation in coal tonnage to provide same energy input 2 Difference in transport and handling costs 3 Maintenance costs (induding overheads) 4 Disposal costs (including overheads) 25 US$1t waste 5 FOD costs (including overheads and limestone 20 US$t)
6 Power consumption difference - mainly pulverisers and FOD
also an Australian Hunter Valley thennal coal which was well established with Japanese power utilities Table 37 summarises the properties for each coal used in the study The power station modelled was a 500 MW unit with a capacity factor of 90 Ash collection was implemented with a cold side ESP Each coal type was valued under these base conditions and also for a range of residue disposal costs (0-50 US$t) and 100 flue gas scrubbing with limestone costs set at 20 US$t Table 38 summarises the power station operational parameters for each coal studied Table 39 shows the utilisation value resulting from the model together with the component contributions to coal value It should be noted that highest utilisation value implies the best coal for the system For example coal A whilst requiring a small additional annual tonnage as a result of a slightly lower heating value with respect to the reference coal (see Table 39 - minor penalties indicated under factors 1 and 2) actually compares favourably with the base coal case due to its very low ash level (low residue disposal costs) and lower than reference sulphur level (low FGD costs) The authors of the report pointed out that unit availability and the handleability characteristics of each coal have not been taken into account and that the costs of domestic transport were not included in the study In this respect the model does not take into account 100 of available coal quality impacts on power station perfonnance but can be considered as an improved least cost type model as described in Section 71
COALBUY In 1976 Carolina Power And Light Company (CPampL) developed a program called COALBUY which they use to calculate the operating expense incurred by utilising coal of a given quality at a selected generating unit The program essentially evaluates a series of six potential penalties
boiler efficiency auxiliary power requirements coal handling equipment maintenance ash handling equipment maintenance ash storage cost replacement power due to load limitations
The program contains an extensive database for each CPampL coal-fired generating unit together with detailed specifications for a reference coal Each offered coal is compared with the reference when calculating potential operating penalties Any penalties are added to the offer price of the coal to obtain a total cost of burning it The program is also used to predict the extent to which a unit might be load-limited when burning off-specification coal Details utilised for each unit are given in Table 40 The operating data listed are taken from actual performance tests at a series of load levels
COALBUY is in fact a sub-routine of CPampL s EVAL
89
Computer models
Table 40 Model input output data - COALBUY (Corson 1988)
Developer Coal input Generating unit input Key output
Carolina Higher heating value Net unit heat rate Operating penalties Power amp Light Grindability Base boiler efficiency Total cost of coal ($IMBtu) USA Proximate analysis Estimated boiler radiation losses Load limitation on generating unit capacity
Total sulphur content Ambient air temperature Identification of system causing the load limitation Purchase price including Ambient air humidity ratio Operating characteristics of boiler fans with
transport Stack gas temperature reference to coal and purchased coal Standard deviation of the Unburned carbon in fly ash Boiler efficiency losses and related parameters
variation in higher Unburned carbon in bottom ash - boiler efficiency heating value Carbon dioxide and oxygen in the - auxiliary power requirement
boiler gases entering and leaving the - coal handling equipment maintenance air heater - ash handling equipment maintenance
Monthly unit demand profiles - ash storage cost - replacement power
The operating data listed above are taken from actual boiler tests at a series of load levels
Also includes escalation factors for database cost factors
program which was developed to maintain files on quotations a coal buyer in making a detailed assessment of cost and and purchase orders to select suppliers of spot-market coal performance impacts of using a candidate coal in his power and to plan the distribution of long-term and spot-market station Model input and output parameters are summarised purchases throughout CPampLs generating system each month in Table 41 (Corson 1988)
The system establishes the coal rank (based on ASTM D388 Coal Quality Advisor (CQA) guidelines) ash type and determines ash fouling and The CQA expert system was developed by a joint utility slagging characteristics based on empirical slagging and (Houston Lighting amp Power Company (lllampP)) and fouling indexes It compares the provided analysis values architectengineering company (Stone and Webster) team against those expected for the reference of coal and coal ash (Arora and others 1989) Its intended application is to assist Arora and others (1989) describe the specific functions in
Table 41 Model input output data - Coal Quality Advisor (CQA) (Arora and others 1989)
Developer Coal input Generating unit input Key output
Houston Lighting amp Power Stone amp Webster Engineering Corporation USA
Proximate analysis Higher heating value Ultimate analysis Sulphur forms Ash mineral analysis Ash fusion temperature Trace elements Equilibrium moisture Quartz content Coal size Coal cost (fob)
Pulveriser horse power input Number of mills in service Plant capacity factor PA temperature (OF) amp pressure (lbft2mill) Primary air to fuel ratio (lbairnbfue1 )
Plan area heat release rate actual (Btuh ft2 x 106)
Boiler efficiency () Approximate net heat rate (BtukWh) Limestone cost Total change in OampM costs ($y) Annual fuel flow (ty) Differential power costs at equivalent coal flow (ty)
Intermediate output variables Maximum mill capacity (th) Required coal flow (Pph) Coal flow per mill (th) Percent base mill Super heater gas velocity (ftsec) Reheater gas velocity (ftlsec) Air flow (lbh) Excess air () Fuel flow (Pph) from boiler calculations Annual fuel flow 075 capacity factor Gas temperature - out CF) Bottom ash flow (Pph) Fly ash flow (Pph) Volumetric heat release (Btuh x 106)
Furnace exit gas temperature (OF) Limestone usage rate (th) Unburned carbon (lbslOO lbs coal)
90
Computer models
greater detail than can be discussed here It should be noted that due to the lack of a suitable database the basis of OampM cost methods was a percentage of equipment capital costs for each major power station component
The model has been validated for HLampP use It has been reported to have been used for (Arora and others 1989)
blending of up to five coals to a specific mix or to achieve a specified quality for the blend (that is sulphur ash heating value) classifying the coal (blend) to permit assessment in various components of the power station determination of empirical slagging and fouling indices evaluating the required performance against the given limits for the major components of the power station determination of OampM costs and the net heat rate change for a candidate coal relative to a given base coal unit No 8 at HLampP Parish power station but it can be configured to enable evaluation of other coal-fired units in the HLampP system with minor changes
The impact assessment for each of the systems is classified by severity level and displayed to the user with appropriate recommendations
Coal Quality Engineering Analysis Model (CQEA) From 1963 to the mid-1970s NYSEG have used a coal evaluation program to determine bonuses and penalties on each parameter of the coal offered by suppliers (Mancini and
others 1988) In 1975 the company commenced a two-year coal quality study to develop a method of fitting the existing program to each of the five NYSEG generating stations The model approach was changed to combine generating station engineering data with coal analysis data in a workable package for fuel evaluation engineering and economic analyses The result is the CQEA which has been used by NYSEG since 1977
Table 42 summarises the coal input data generating unit data required and the key and intermediate output variables The CQEA is calibrated to each units characteristics The generating unit input data are reported to be recalibrated annually
An illustration of the capability of the CQEA is shown in Figure 34 It compares the overall production cost for five different coals burned in one unit (unit 5 of Figure 34) as calculated by CQEA If only delivered cost is used as a measure to purchase coal then coal 3 would be the lowest cost However the overall cost of coal 1 is about 80 ckWh lower than the overall cost of coal 3 Similarly it is shown that paying the highest cost for high-quality coal 2 compared to coal 1 is not overall economically beneficial Also if the choice were among coals 2 4 and 5 - which are almost equal - the best quality would be chosen knowing the results of the CQEA These results have been verified by actual experience of the above coals in the units discussed
The CQEA system is used by two different groups within
Table 42 Model input output data - Coal Quality Engineering Analysis (CQEA) (Mancini and others 1988)
Developer Coal input Generating unit input Key output
NYSEG Delivered price USA Heat content
Proximate analysis Sulphur Ash softening temperature Grindability
Maximum gross capacity Hours operating at peak and average power Station service power Turbine heat rate Forced draft fan inlet temperature Stack exit gas temperature Carbon in ash and ash as fly ash versus
bottom ash moisture added to ash for dust-free disposal
Excess combustion air Base pulveriser capacity Pulveriser capacity correction factors for
fineness and grindability Radiation amp unaccounted boiler loss Fuel oil rate for low volume coal Minimum volatiles in coal without ignition oil
Average gross generation Ash collection capacities fly ash
and bottom ash Ash and scrubber sludge disposal cost Flue gas desulphuriser removal
efficiency and OampM costs
Cost of coal and oil burned Ash disposal costs Maintenance costs for coal and ash handling equipment Scrubber OampM and waste disposal costs Replacement power cost Net output MWh Replacement power MWh
Intermediate output variables Boiler efficiency () Total station service power () Net station heat rate (B tukWh) Percent utilisation of capacity Total Btu fired in coal and oil
Additional system data Maintenance wage rate Replacement power demand and energy charge Fuel oil heating value and price
91
Computer models
D coal quality - related costs 16shy D delivered coal cost
14 c 3 ~ 12ifgt U5 0 100
u c 0
OJ 8 D 2 0shyD 6 (j)
iii ~ 4 a OJ
u 2
0 Coal 1
MJkg 256 ash 210 moisture 70 sulphur 21
Coal 2 Coal 3 Coal 4 CoalS
302 263 284 270 120 203 127 177 40 53 72 70 27 12 26 20
Figure 34 CQEA evaluation of the impact of different coals on overall production costs of one unit (Mancini and others 1987)
NYSEG These are the Perfonnance and Fuel Engineering group which maintains the CQEA calibration factors for each unit and the Fossil Fuel Supply group which uses the
BOILER bull subcritical PC bull supercritical PC bull parallelseries backpass bull flue gas recirculation
COAL PREPARATION bull 41 mill offerings bull vertical spindle mills bull exhauster mills bull other
r
BOnOM ASH SYSTEM bull wet system
- jet pumps - centrifugal pumps
COAL HANDLING bull rail truck bargeship conveyor unloading bull emergency and normal stockout bull stacker reclaimers lowering wells
other reclaim systems bull ring granulator hammermill crushers
CQEA as a tool for evaluating coal purchase offers from coal producers (Mancini and others 1987)
Coal Quality Impact Model (CQIM) In 1985 Black amp Veatch a US architect-engineering group and EPRI worked together to develop a comprehensive computer program for predicting coal quality impacts The result was the Coal Quality Impact Model (CQIM) As of the end of 1991 112 copies had been distributed to 72 different utilities and six different companies or agencies Black amp Veatch has also sold the program to eight companies including four outside of the US Four additional sales to non-EPRI member companies are in their last stages of negotiations This is the most widely used systemsshyengineering model in the world
The role of CQIM is to quantify both perfonnance and cost impacts associated with changes in coal quality (Evans 1991 Stallard and Mehta 1991) The equipment types modelled by CQIM are summarised in Figure 35 As described earlier for other models CQIM evaluates alternative coals by comparing them with a reference or current coal supply It is also designed to consider station-specific design and operation characteristics on a component-by-component basis as well as the unit as a whole This allows the CQIM to identify potential system limitations (sources of derate)
The effort required to collect CQIM input data varies according to the background of the user the availability of data and the purpose of the evaluation CQIM contains a
AIR HEATERS bull bisectors bull trisectors
PARTICULATE REMOVAL bull hot ESP bull cold ESP bull fabric filter
1 FLY ASH HANDLING bull pressurisedbull vacuum
FD FANS bull axial bull centrifugal
~
~ PA FANS bull axial bull centrifugal bull coldhot bull exhuasters
Figure 35 Equipment types modelled by CQIM (Galluzzo and others 1987)
ID FANS bull axial bull centrifugal
SRUBBER ADDITIVE bull limestone bull lime bull none
to stack
t GAS REHEAT bull 5 alternatives
f---shy FGD SYSTEM bull wet limestone bull spray dryer --- bull none
WASTE DISPOSAL bull stabilised waste bull fixated waste bull evaporation ponds bull other
92
Computer models
Table 43 Model input output data - Coal Quality Impact Model (CQIM) (Stallard and others 1988 Stallard and Mehta 1991)
Developer Coal input Generating unit input Key output
EPRI amp Heating value Black amp Veach Ultimate analysis USA Moisture content
Ash content Chlorine content Sodium content in ash HOI Ash fusion temperatures Ash analysis Fuel cost Transport cost
Unit size (MW net) Capacity factor () Net power level Auxiliary power requirements Auxiliary equipment specifications
and capacities Hours of operation Net turbine heat rate (BtukWh) Excess air level () Boiler losses Boiler dimensions Soot blowing details Tube bank configurations Maximum heat input per plan area (MBtuJhft2)
Design FEGT Maximum allowable flue gas velocity Economiser
Economic data Replacement energy cost ($millkWh) Limestone cost ($ton) Salarymaintenance rate ($person-year)
Discount rate Replacement power cost Limestonellime cost Total annual fuel related costs Transport costs Escalation rates Overall unit performance data - slagging fouling and erosion potentials - equipment performance and derate info - maintenance availability data - calculated derate by system - generation cost summary page Sensitivity analysis Comparison tables Error warnings
feature for supplementing data provided by the user This default information is based on the data entered by the user the overall power station configuration the characteristics of the design coal and established equipment design practices Since default data can be substituted for most missing data the program can be run with limited input Of course the more actual data used the more comprehensive the predictions
Table 43 illustrates the type of data required for conducting an initial screening evaluation of coal quality CQIM contains programs for translating each major performance impact into a discrete cost component
During the course of the development of the CQIM model validation was carried out by means of a host utility program Initially 12 utilities worked with EPRI to develop case studies to validate the CQIM equipment performance models The CQIM performance and cost predictions were compared with historical data and actual utility operating experience Any discrepancies were used to modify the program modules and improve the overall predictive capability of the CQIM The case studies covered a wide range of US unit designs and US coals With the sale of the CQIM to international utilities this has prompted the development of CQIM International which will have facilities to convert input data utilising SI units
There are several examples of literature describing the application and validation of the CQIM (Galluzzo and others 1987 Boushka 1988 Stallard and others 1989 Cox and others 1990 Kehoe and others 1990 Afonso and Molino 1991 Giovanni and others 1991 Vitta and others 1991)
Coal Quality Expert (CQE) The US Department of Energy (DOE) selected the
development of the CQE in Round 1 of the Clean Coal Technology program The project initiated in 1990 and scheduled for completion in August 1994 will cost $217 million
The CQE computer system is designed to give utilities a tool that will predict the total cost of impact of coal quality on boiler performance maintenance operational costs and emissions
Figure 36 shows the major components of the CQE system The foundation for the CQE is EPRIs CQIM (see section on CQIM) More than 20 software models and databases including the CQIM a flue gas desulphurisation model a coal cleaning model a transport model and a new power station construction model will be integrated into a single tool to enable planners and engineers to examine the cost and effects of coal quality on each facet of power generation from the mine to the stack The expert system is intended to evaluate numerous options including various qualities of coal available transport methods and alternative emissions control strategies to determine the least expensive emission control strategy for a given power station
It is intended that the CQE will include cost estimating models for new and retrofit coal cleaning processes power production equipment and emissions control systems Individual models are to be made available as they are developed The first of these models the Acid Rain Advisor (ARA) has already been released (CQ Inc 1992) The ARA developed primarily to assist users in managing US Clean Air Act compliance evaluations can be used to quantify costs and emissions allowance needs for potential utility compliance strategies
A core part of the CQE program is extensive data gathering
93
Computer models
ENGINEERING AND ECONOMIC MODELS
bull Coal Quality Impact Model
bull coal cleaning cost model
bull flue gas desulphurisation
bull NOx emissions
ADVANCED USER INTERFACE
Integrated report and graphic capabilities
CQE ASSISTANCE Integrated applications
bull strategic planning
bull plant engineering
bull fuel procurement
bull environmental strategies
bull acid rain advisor
Figure 36 Major components of the CQE system (Evans 1991)
and analysis to validate the models and it is one of the largest efforts ever attempted to link pre-combustion combustion and post-combustion technologies to solve power station emission problems (Evans 1991) Samples of the various coals identified for the project are being collected at mines commercial cleaning plants and the six host power stations Extensive measurements of the performance of all ancillary equipment are taken during the field tests Moreover the project will generate considerable data from laboratory bench- and pilot-scale combustion tests using the same coals All the data will be used to develop and validate the CQE models including those that predict mill wear slagging and fouling precipitator performance flue gas particulate removal NOx formation and the flue gas desulphurisation performance
IMPACT Ugursal and others (1990) reported the development of a computer-based techno-economic model that can predict the impact of coal quality and other key variables on the busbar cost of electricity generated by new power stations The IMPACT model has been structured to focus on four major cost sectors of the coal-to-electricity chain (see Figure 1) This includes transport power station post-combustion particulate and SOz emission controls and residue disposal
Table 44 Ranges of selected coal-ash combustibility parameter that predict approximate classification of CF values (Ugursal and others 1990)
Incombustibility index RI1 Classification of CF values
lt21 21--43 43-75 gt75
94
low laquo017) medium (017-D34) high (034-D47) severe (gt047)
INFORMATION AND DATA BANKS
bull fLe1 sources
bull plant specifications
bull transport rates
bull waste handling
bull coal quality information systems
The impact of coal characteristics on power station performance is quantified in IMPACT as follows
steam cycle heat rate calculation assumes that the boiler is designed for the given coal and operates at design load boiler efficiency is evaluated using the heat loss method (see Section 632) A notable additional approach adopted to evaluate unburnt combustible losses in the calculation of efficiency includes an incombustible parameter Rh which is inversely proportional to the base-to-acid ratio of coal ash Rh is directly proportional to the amount of unburnt combustibles in the fly ash The amount of unburnt combustibles is expressed by CF and can be defined as
CF = [(flyash combustible$ (lb of fly ash formed)] (lb of coal feed)
The approximate ranges of CF values that corresponds to the incombustibility parameter ranges are given in Table 44 Once CF is determined from Table 44 the percentage of combustibles in the coal feed that is lost in the flue gas can be determined from
CFx 100 coal feed combustIbles = n1 1 d b tmiddotbl70coa lee com us 1 es
where the percentage of coal feed combustibles = 100 - ash - moisture with the ash and moisture content determined from proximate analysis of the coal
IMPACT utilises empirical correlations (developed by regression of data published by Bechtel Power Corporation (Holstein 1981)) between auxiliary power consumption and the sum of the ash and moisture contents of the coal for both subcritical and supercritical units (Ugursal and others 1990) availability values of 80 are assumed to apply to new
Computer models
Table 45 Model input output data - IMPACT (Ugursal and others 1990)
Developer Coal input Generating unit input Key output
University of Ultimate analysis () Plant capacity (MW) Levalised busbar cost of electricity Nova Scotia Ash content Unit type Annual operational cost Canada Ash composition () Steam generator efficiency () Capital costs
Heating value Steam cycle heat rate (BtulkWh) Annual coal consumption Cost of coal Flue gas exit temperature
Average load Equivalent availability Auxiliary equipment specifications Cost of limestone
power stations This assumption is adopted due to the lack of information available quantifying the impact of coal quality on the availability of power stations coal consumption and coal bum rate of a given power station are calculated using an energy balance based on the results obtained from the parameters above and the specified annual generation capacity annual ash and S02 generation are determined by a mass balance on the annual coal consumption rate and the ash and sulphur contents of the coal
Although this model has yet to be fully validated the authors carried out sensitivity analyses for a number of coals with various levels of ash and sulphur (Ugursal and others 1990) on a representative power station with two 500 MW units The input and output parameters of the coals and power station for the model are summarised in Table 45 Overall from the study it was concluded that the capital and operating costs of most of the sectors of the coal-to-electricity chain increase with increasing ash content of the coal fIred The authors emphasised that the findings apply for the particular conditions of the case the results might be quite different under other site specific conditions
Coal quality impact study model (CQI) Kemeny (1988) reported on work performed to develop a method of analysis using a combination of statistical and engineering methods which could be applied to any power station operating system The method adopted also developed a model that computes a power stations total coal-related generation cost on a specific coal It was developed initially for an Italian power station Fusina 3 to determine the economics of burning four different coals at the station
The method adopted for the calculation of availability assumed that planned outages were unaffected by coal quality whereas their effects on forced outages was the sole influence on availability Because of the random nature of equipment failures an analysis of forced outage rates was carried out statistically Historical coal usage data were correlated against historical outage data to see if there was a coal quality relationship For Fusina 3 power station the coal type was changed so frequently that data from a single unit were considered suffIcient for such a study The results of the availability analysis are shown graphically in Figure 37 A low correlation coefficient of 0447 was observed for the relationship indicating that there was a fairly high probability
that the apparent correlation between forced outages and ash was due to random scatter of data points and not to any cause-and-effect relationship In addition the large negative y-axis indicated that the regression equation may not have been accurate across the full range of ash values In light of the results demonstrated by this study it would appear that it would be more prudent not to include the results of the availability analysis in the coal quality impact model However the investigators believed that the regression analysis conformed to engineering expectations and because of the probabilistic nature of forced outages it was quite unlikely that with the amount of data available outages would correlate very strongly with coal quality Therefore the results of the availability analysis were included in this coal quality impact model
Coal-related operating costs accounted for in the model cover any cost not specifically covered by fuel costs At Fusina 3 for example these areas included the cost of sulphur for S03 conditioning and the cost of ash disposal Other areas might include the cost of fuel additives scrubber related costs cost of additional equipment The effects of coal quality on the cost of routine and emergency maintenance at the power station is most easily measured statistically in a similar way in which forced outages were correlated
01000
~ L 800 (j)
~
L0 600 81 Q) 0 OJ co 5 400 -0 Q)
0 0
~4() 82 00 200 u
83 o
40 60 80 100
Ash throughput kty
o not included in regression
Figure 37 Correlations of forced outage hours against ash throughput using the cal model (Kemeny 1988)
95
Computer models
Table 46 Assessment of four coals for Fusina unit 3 using the CQI model (Kemeny 1988)
Coals
South Africa Polish American
Low ash High ash
Coal characteristics High heating value MJkg [Btulb] Ash content Sulphur Moisture content Carbon content Ash resistivity ohmcm x E13
Coal cost $GJ [$MMBtu]
Results from model Boiler efficiency Availability US$y Capacity - ESP limit - Auxiliary power
Fuel costs - coal - supplementary
OampM costs - maintenance - flue gas conditioning - ash disposal
Totals
2625 [11291] 1339 038 830
6474 375
153 [161]
8890 3905122
1764549 3765822
25565882 3450848
2806626 24916
458876
4172640
2707 [11639] 1226 063 780
6796 500
163 [172]
8889 3204389
1514442 3817118
27980093 3059766
2538408 9051
330618
424453886
3012 [12950] 742 081 720
7433 500
177 [187]
8931 336355
357460 4033183
33180022 1625800
1440618 o
175209
40798228
2830 [12173] 1152 075 710
7033 500
177 [187]
8886
2459658
2325523 o
228820
44008125
Without going into power station details as this is described elsewhere (Kemeny 1988) an illustration of the type of results produced by the model of the comparison of four coals from Poland South Africa and the USA is given in Table 46
As in the case of other similar models the value of the total coal-related production cost in the cost summary is just an indicator it is neither a calculation nor a prediction of the actual generating cost The number in this model does not include costs such as maintenance costs for non-coal-related systems However it can be used for comparative purposes Quite simply the coal which gives the lowest production cost is the most economical
More briefly other models that have been reported in the literature include
Waters (1987) reported the development of a computerised mathematical model known as ECUMEC Data taken from the model subroutines are used to calculate the power cost for example at the busbar including the cost of coal Once again the method used to assign an economic value to a coal is to select a base coal or yardstick coal to which a coal price (fob) can be ascribed The equivalent value of another coal is that price (fob) which gives the same power production cost as the base coal Waters (1987) demonstrated the
capability of the model by considering the effect of some coal properties such as sulphur ash and moisture content on the equivalent coal value in a 500 MW power station The base coal was a 15 ash Australian Hunter Valley coal The coal price (fob) was shown to be very dependent upon ash with a 5 ash coal worth approximately US$745 more per tonne than a 15 ash coal (based on 1987 prices) The effect of moisture on equivalent coal price is similar to ash but not as marked It was shown using the model that a 05 increase in sulphur content had a much greater effect on coal value than a 5 increase in ash content This was because the capital and operating costs associated with FGD to meet air quality requirements were very high a program developed by Southern Company Services USA to help estimate the benefits from cleaning coals The constituents of coal that were found to affect the cost factors were primarily ash moisture sulphur and carbon content (Blake 1988) the Consol Coal QualityPower Cost model which was used by Deiuliis and others (1991) to evaluate the performance of six US regional coals in a typical 500 MW pulverised coal-fired unit The study was focused on developing a cleanliness factor for model relating to heat flux and soot blower effectiveness data obtained from pilot combustion tests the Coal Utilisation Cost Model which utilises a three-step modelling approach-statistical analysis of
96
Computer models
historical data (source NERC) development of an engineering algorithms and evaluated cost calculations based on the algorithm results (Nadgauda and Hathaway 1990)
733 Integrated site models
With further advancements in computer and sensor technology in the last ten years integrated site models are being developed that allow the integration of information from unit models systems perfonnance and other models directly into the control room data system These programs allow the continuous monitoring of for example selected coal properties such as ash moisture and sulphur furnace and convective pass deposits and can define overall heat rates based on these continuous measurements taken from the unit (Elliott 1991) The diagnostics packages can also include a routine for predicting the implementation and impact of operating practices on heat rate (Nurick 1988 Alder and others 1992)
Smith (1991) and Reinschmidt (1991) have reviewed the wider application of integrated control systems from individual component control to full automation of the power
Coal quality COAL MANAGEMENT
as a function MODULEof time at mills
Coal quality collection and assessment
station and the new computer technologies that are being applied such as neural network approaches that processes input data without identification of particular algorithms connecting the output results with the input data and fuzzy logic An example of this application is the C-QUEL system
Coal quality evaluation system (C-QUEL) Mitas and others (1991) have reported on the current development of a comprehensive software system C-QUEL that will allow utilities to use on-line analysers to try to solve or mitigate existing coal-related problems This will be accomplished by the C-QUEL system by providing information about coal quality before it is burned predict potential effects on operation and provide recommendations of control actions which can be taken to adjust coal quality andor improve power station response to quality changes The use of on-line coal analysers has been reviewed by Makansi (1989) and Kirchner (1991)
C-QUEL is a suite of computer programs which can be used as a basis for control of various processes in a power station Figure 38 shows a schematic of the structure of the system Appropriate control actions will be determined based on a wide variety of information gathered by the operator on-line
ON-LINE PERFORMANCE MONITORING SYSTEM
Equipment status Current performance
Load demand
ON-LINE COAL ANALYSER
SUPERVISORY CONTROL MODULE
COAL QUALITY CONTROLACTION
RELATIONSHIP MODULES
Coal data logging
Monitor CQ and equipment modify operation to
meet goals
DATA ARCHIVE AND TRENDING
USER INTERFACE
EPRI COAL QUALITY IMPACT MODEL
Annunciation Predicted performance Interactive dialogue Information retrieval
Figure 38 Schematic showing the structure of the e-aUEL system (Mitas and others 1991)
97
Computer models
coal analyser real-time station data on-line performance calculations equipment performance predictions and coal flow models The EPRI Coal Quality Impact Model (CQIM) will be incorporated into C-QUEL to provide the prediction capability for the performance of all major power station systems directly impacted by coal quality Operational strategies as a result of expected unit performance will be evaluated by C-QUEL and provided to the operator These strategies will take into account the current and future unit generating requirements as well as cost information associated with each possible action Specific control recommendations and supporting information are presented to the power station operators
Figure 39 shows a simplified case as an example of the use of C-QUEL in which the primary goal is to maximise electrical generation from a base load power station Figure 39a depicts the sequence of events that can be expected at a particular point in time The operator is unaware that a change in coal quality has occurred until a
a) Without C-QUEL
Ash and moisture content have
increased
drop in load is detected In the second scenario Figure 39b the goal of maximising electrical production has been fed into the C-QUEL supervisory module Since decreased mill capacity will have a direct effect on generation this information together with a recommended course of action is given to the operator and allows him enough time to make the proposed adjustments before load production is affected Because of detection of the higher moisture and ash content of the coal supply by the on-line coal analyser a decrease in mill capacity was predicted To prevent any load reduction the operator would be instructed by the system to bring another mill into operation
The project team for development of the C-QUEL system consists of two host US utilities - Oklahoma Gas and Electric (OGampE) and Pennsylvania Electric (penelec) two engineering contractors - Black amp Veatch and Praxis Engineers and EPRI Demonstration of the system will take place at OGampEs Muskogee power station and the Penelec-operated Conemaugh plant OGampEs Muskogee
I I
Only two pulverisers are on-line consistent with the requirements
of the previous coal quality
I I I L_
On
Electrical production has
dropped
Operator determines decreased pulveriser capacity has caused the load drop and brings another pulveriser on-line
b) With C-QUEL Pulveriser module predicts Other controlaction modules decreased pulveriser capacity
Analyser detects Iincrease in coal ash and moisture conten t I
III I +0bull
Goalmaximise output
-
1 Supervisory module evaluates this information relative to operational
t--- goals and constraints and information from other modules
I
A message notifies the
Pulveriser 2
operator of potential generation loss and the need for an additional pulveriser
1-~e~C 1
I I L_
Operator brings another pulveriser on-line before the high ashhigh moisture coal is fed to the fuel preparation system Maximum electrical production is successfully maintained
Figure 39 Comparison of the operations with and without the use of e-aUEL (Mitas and others 1991)
98
power station fires primarily western low-sulphur coal that is currently blended with more expensive higher sulphur Oklahoma coal which also has a higher heating value on a 10 by heating value basis The station must also meet a strict SOz emission limit OGampE has installed an on-line analyser - PGNAA elemental analyser - that will provide data to assist in blending and feeding An elemental analyser has also been installed at the Conemaugh power station Initial data gathering will focus on the Muskogee power station (Mitas and others 1991)
Couch (1991) has also reviewed the influence of integrated computer control and modelling on coal preparation plant
74 Comments The studies described above demonstrate the feasibility of developing various quantitative relationships which are essential for optimum planning and operation of generating units Table 47 summarises the capabilities of the models described in this chapter Many of the results are based on data and methodologies which still require further refinement
When considering the two major techniques for assessing power station performance that is statistical and engineering analysis modelling a weak link with both approaches is within the coal specification parameters used in the correlations
Table 47 Summary of model types and capabilities
Computer models
For the purpose of selecting an economically attractive coal it is important to determine heat rate effects due to coal quality as accurately as possible In their review of statistical and engineering based relationships Folsom and others (1986b) did not believe that the correlations from statistical studies were close enough to be useful for this purpose Consequently the use of engineering correlations and experience to evaluate heat rate impacts was highlighted as the preferred procedure
Engineering based models have their critics also Many utilities apply least cost models for purchasing coals and component models and some acknowledge the benefits of expert unit or integrated models Others remain sceptical over the capability of devising a truly representative model of the coal combustion process Some of the reasons given for this scepticism include
the present methods that describe coal properties require substantial refinement for use in the models as they are not adequate for predictingaccounting for unit performance a belief that coal blending solutions based on pragmatism and simple empirical methods are more appropriate providing a here-and-now solution a belief that processes such as fouling and slagging and mill performance cannot be accurately modelled whilst the basic mechanisms are not clearly understood
Model type Modelling capabilities Developed by Application Comments Model name Assessmentcountry
Heat Capacity Avail- Maintenance Other of origin
rate costs ability costs
Least cost coal coal blend model
Least cost fuel system total fuel cost architectengineer buyer manualAustralia ICVM total fuel cost research organisation buyer manualAustralia Steam coal blending plan - total fuel cost supplier buyer manuallUSA Perfectblend total fuel cost research organisation buyer manuallUSA
Single component model Boiler models --I --I research organisation operator computerintershyand others utilityequip manufacturer national
Unit model Statistical
TVA study --I --I --I research organisationutility operator manualUSA EPR study --I --I --I research organisationutility operator manuallUSA NERA srudy --I --I research organisation operator manuallUSA PC study --I --I --I capital costs utility operator manuallUSA
Engineering ClVEC --I --I estimated total fuel costs research organisation buyer computerAustralia COALBUY --I --I --I --I total fuel costs utility buyer computerlUSA CQA --I --I --I estimated total fuel costs architect engineerutility buyeroperator computerlUSA CQEA --I --I --I coalash handling total fuel costs utility buyeroperator manuallUSA CQIM --I --I --I --I total fuel costs architect engineerutility supplierlbuyer computerlUSAUK
operator CQE --I --I --I --I total fuel costs architect engineerutility buyeroperator computerlUSA IMPACT --I --I --I --I total fuel costs research organisation buyeroperator computerCanada CQI --I --I --I statistical evaluation total fuel costs research organisationutility buyersoperator computerlUSA
Site model C-QUEL --I --I --I --I total fuel costs architect engineerutility operator computerlUSA
total fuel costs for engineering models refers to the total fuel-related production costs in terms of the price of electricity at the busbar
99
Computer models
new advanced boiler configurations such as low NOx
combustion regimes increase the complexity of boiler models many of the models have not been applied to a wide range of international coals and therefore have not received adequate validation
The analysis approach adopted by many of the unit models available can vary in complexity such that a form of quantitative predictability can be produced to a reasonable or to what may be deemed as a high level The lower level of prediction capability has been perceived by critics to produce too general a fmding In contrast the higher level may require more detailed unit specific information than a utility may have readily available such that special provisions would have to be made in order to collect the necessary data (Johnson and others 1991) This is known to be time consuming and is perceived by some operators to detract from the main utility priority that is to produce electricity Others believe that the models incorporate performance measurement errors that may compound to reduce the effectiveness of the model and make it only useful for comparing coals that show a wide range of coal property values
Many of the model descriptions have cited the beneficial role of the model in fuels purchasing It is considered that when models are used in such a manner they could become an improved means of communication between supplier buyer and user as they can ultimately aid the purchase of an economical coal of adequate quality for a particular power station The advantages of having the ability to assign an overall cost to a coal particularly in terms of its impact on component and overall power station performance could prove to be of technical and financial benefit to the utility in helping to justify supplier buyer or operator policies such as coal cleaning blending power station retrofitting or purchase of replacement energy to the advantage of the utility
In general however operators remain reluctant to move toward a predictive approach to coal quality impacts in preference to reliance on post mortem type remedies In the future integrated computer models such as C-QUEL may prove more acceptable when they can provide real time cause and effect information and advice on how to remedy problem situations as soon as they occur and can be seen to rely on dependable input data
100
8 Conclusions
Fuels purchasing and management presents an important opportunity for utilities to control costs It is also recognised that final judgements on coal selection often require a trade-off between these costs and qualitative factors such as diversity of supply reliability control of emissions for environmental reasons balance of trade and currency availabilities The contribution of coal to the cost of electricity extends far beyond the purchase price of the fuel Over the last fifteen years it has become generally accepted by coal-fired power station operators that the capacity availability and cost of operation of each individual component of the power station are materially affected by the quality of coal fed to it To generate power at least cost it is important to evaluate the overall total cost associated with each coal for a particular power station
The principal coal properties that were found to cause greatest concern to operators include
ash content and composition heating value sulphur content moisture content grindability volatile matter content
Enforcement of environmental legislation has resulted in the elevation of total sulphur content to a key position in the specification of coal along with total ash moisture and heating value Table 48 summarises the effects of these properties and other coal characteristics that are used as coal specifications for combustion on component and overall power station performance
Little has changed over the years in the way that coal is assessed and selected for combustion Operators continue to use quality parameters in their specifications that were mostly developed for coal using processes other than direct combustion Whilst many empirical relationships have been
established between coal specifications and certain component and plant performance indicators the coal characterisation tests themselves have been shown to have serious shortcomings and in some cases do not adequately reflect the process conditions For example
coal composition measurements cannot be used to explain the problems of dusting flowability freezing and oxidation that can occur during coal handling mill capacities for lower rank coals or coal blends are difficult to evaluate using existing grindability correlations combustion characteristics including flame shape stability and char burnout cannot be evaluated accurately based on standard coal composition tests the correlations that have been developed for slagging and fouling are inadequate there is considerable disagreement as to the best method of measuring fly ash resistivity there is no correlation between coal composition and fly ash fineness there is no adequate means to predict NOx emissions
Because the procurement specifications are based on tests which do not relate well to actual practice there is still a need for expensive large scale test burns to confirm suitability
Coal quality affects a wide variety of plant components and ultimately the overall station performance that is total system capacity availability maintenance costs substitute fuel costs plant replacement costs and the final cost of electricity There is a growing awareness that coal suppliers should take more responsibility with respect to determining the quality of coal made available on the market Suppliers that best understand the consumers fuel quality concerns prove to be the most successful in securing contracts and maintaining market share
Plant operators and other organisations are working to
101
Conclusions
Table 48 Summarymiddot of the impacts of coal quality on power station performance
Coal specification Power station component performance Overall power station performance
Environmental control
l u l
tl a
B
amp ~ o(l co S c r
~
~
E l
aI
0
~ C
co
~ B en
c= E co c E c ~
c= E 5 0 co c ~
U - 0 U
c au
~ u
lt5i if
c= ~ ~ amp 0 j c a u
6 en
c= sect l 0 0 1sect a u gtlt
0 Z
1(j at
4-lt a
E c
l 0
tl sect 0 ~ l
QI
0 ~
U
B ~ lta r
c= E S 0
U
sect c B c
ca ~
~ ~ ca gtlt
Ash content increase decrease
Heating value increase decrease
Sulphur content increase decrease
Moisture increase decrease
Hardgrove grindability index increase decrease
Volatile matter increase decrease
Ash fusion temperature increase decrease
Ash resistivity increase decrease
Sodium content increase decrease
Chlorine content increase decrease
Fuel ratio increase decrease
Free swelling index increase decrease
Size consist increase decrease
compiled from observations from literature and the lEA Coal Research survey worsened (or decreased for components marked ) improved (or increased for components marked )
102
improve their understanding of how their equipment or systems respond to particular coals and coal blends but the lack of data for appropriate direct correlations of plant performance and coal behaviour has hindered the development of true prediction capability Until these relationships have been developed and proven respecting differences in boiler design coal buyers will continue to operate at a disadvantage when selecting new sources of coal
With the advances that have been made in computer technology there has been some success in the development of computer models that demonstrate the feasibility of developing various quantitative relationships for optimum planning and operation of generating units Many utilities use least cost models for purchasing coals that have no performance prediction capability Many use component models that supply fundamental data of plant component performance There is a growing number of utilities that are adopting expert unit or integrated models that are being developed Others have shown scepticism over the capability of devising a truly representative model of a coal combustion plant for reasons that include the following
a belief that coal blending solutions based on pragmatism and simple empirical methods are more appropriate providing a here-and-now solution a belief that many of the coal quality impacts cannot be accurately modelled as the basic mechanisms are still not fully understood new advanced boiler configurations such as low NOx
combustion regimes increase the complexity of boiler models many of the models have not been applied to a wide range of international coals and therefore have not received adequate validation the present methods that describe coal properties require substantial refinement as used in the models as they have been found to be inadequate in many cases for predictingaccounting for unit performance
Many of the shortcomings in the traditional coal characterisation tests that form the basis for specifications for
Conclusions
combustion have been exposed by the efforts to develop computer models and their improved data processing Prior to their application manual comparisons provided only limited indications of coal behaviour and in many cases precluded the ability to attach a price to a change in performance as a result of a change in coal quality Development of the models has also initiated extensive validation exercises to acquire the necessary performance data In addition coal characterisation tests are being reassessed It is recognised that an overly conservative approach to the development and adoption of new techniques as characterisation tests which may more realistically reflect the conditions extant to coal combustion has also hindered progress into acquiring true predictive capability
Specific needs that have been identified during the course of this review include
the need to develop an internationally acceptable method(s) of defining coal characteristics so plant performance can be predicted more effectively specific relationships between boiler performance in particular for advanced boiler configurations such as low NOx combustion regimes and coal quality need to be developed For example the specific impact of sulphur chlorine sodium overall ash content and coal rank (or reactivity) on carbon burnout slagging fouling corrosion and abrasion all need to be established economic parameters to measure the impact of plant performance on the cost of electricity need to be established and agreed upon in the electric utility industry The accounting systems of many utilities are not designed to easily identify the costs associated with coal quality impacts These organisations need to review their methods particularly if they intend to take advantage of new developing tools that are available such as expert computer models
Successful resolution of these issues is fundamental to achieving optimum use of coal as pulverised fuel in utility power stations
103
9 References
Abbott M F Bilonick R A (1992) Applied heat flux and soot blower effectiveness measurements in the CONSOL pilot and research combustors In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast R USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 471-497 (1992) Afonso R F Molino N M (1991) Compliance coal and low volatile bituminous coal testing at New England power In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 421-436 (JulI991) Ainsworth C C Rai D (1987) Chemical characterization of fossil fuel combustion wastes EPRI-EA-5321 Palo Alto CA USA EPRI Technical Information Services 136 pp (Sep 1987) Akers D J Norton G A Buttermore W H Markuszewski R (1989) Trace elements in coal In Trace elements in coal and coal wastes EPRI-GS-6575 Palo Alto CA USA EPRI Technical Information Services pp 21-28 (Dec 1989) Alder G Klein K Rettberg L (1992) Optimization of automated sootblowing through on-line boiler heat balance modeling In Power-Gen 91 Tampa R USA 4-6 Dec 1991 Houston TX USA PennWell Conferences and Exhibitions pp 1863-1881 (1992) Allman W P (1987) Steam coal blending planning and economic analysis facilitated by computer-generated tables Journal of Coal Quality 6 (1) 19-22 (Jan 1987) Allman W P (1991) A cost-minimization planning model for the coal sourcingtransport network problem emphasizing environmental emission restrictions Energy Systems and Policy 15 (1) 65-73 (Jan-Mar 1991) Anson D (1988) Interpretation and use of empirical slagging criteria In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 181-1101 (1988) Arnold B J (1988) Workshop on defining coal handleability
its cost impact and control Palo Alto CA USA EPRI Technical Information Services 128 pp (Nov 1988) Arnold B J (1991) Effect of chemical and physical coal properties on handling behaviour Mining Engineering 43 (2) 228-231 (Feb 1991) Arnold B J OConnor D C (1992) The effect of coal quality on coal handling Paper presented at Impact of coal quality on power plant peljormance La Jolla CA USA 25-27 Aug 1992 Arnold P C (1990) Storage systems for coal the requirement for implementation of modern design techniques In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 40-46 (Jun 1990) Arora B R Racine J P Sirois R H Finn G A Hanna R S Kern E E Buffinton A L (1989) Coal quality advisor for coal buyer Paper presented at Expert systems applications for the electric power industry Orlando R USA 5-8 Jun 1989 Babcock amp Wilcox (1978) Steam its generation and use (39th edition) New York NY USA Babcock amp Wilcox Company vp (1978) Bailey J G Tate A Diessel C F K Wall T F (1990) A char morphology system with applications to coal combustion Fuel 69 (2) 225-239 (Feb 1990) Baker J W Bennett P Conroy A Naylor P Smith G B (1987) Utilization characteristics of Australian steaming coals in overseas power stations In Coal Power 87 The AUSIMM annual conference in association with the Mining and Metallurgical Institute ofJapan (MMlJ) Newcastle NSW Australia May 1987 Parkville Vic Australia The Australasian Institute of Mining and Metallurgy pp 303-311 (May 1987) Baker J W Holcombe D (1988a) Use of the drift velocity apparatus to determine electrostatic precipitation performance In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp N13-NI6 (1988)
104
References
Baker J W Holcombe D (1988b) Electrostatic precipitations and fabric collection In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp L121-L1239 (1988) Balling L Hein D (1989) DeNOx catalytic converters for various types of furnaces and fuels - development testing operation In 1989 Symposium on stationary combustion nitrogen oxide control San Francisco CA USA 6-9 Mar 1989 EPRI-GS-6423-vol 2 Palo Alto CA USA EPRI Technical Infonnation Services vol 2 pp 7A27-7A40 (JuI1989) Barrett R E (1990) Designing boilers to avoid slagging fouling Power 134 (2) 41-45 (Feb 1990) Barrett R E Holt E C Jr Mack G A Frank R L (1983) Power plant perfonnance Assessing the impact of coal quality In SME-AIME annual meeting Atlanta GA USA 6-10 Mar 1983 Littleton CO USA Society of Mining Engineers of AIME pp 1-12 (Mar 1983) Barrett R E Mack G A Holt E C Jr (1982) Examining relationships between coal characteristics and the perfonnance of IVA power plants TVA10PIEDT-8312 Columbus OH USA Batelle-Columbus 254 pp (Sep 1982) Barrett R E Tuckfield R C (1988) Correlation of slaggingfouling from utility operating data In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 163-180 (1988) Bauver W P Bianca J D Fishburn J D (1984) Characterization of erosion of heat transfer tubes in coal fired power plants ASME Paper 84-JPGC-F4-3 New York NY USA American Society of Mechanical Engineers vp (1984) Baxter L L (1992) Combustion model predicts properties of coal ash deposits Sandia Science News 27 (6) 4 (Jun 1992) Beer J M SarorllD A F Barta L E (1992) From properties of coal mineral matter to deposition tendencies of fly ash - a modelling route Journal of the Institute of Energy 65 (462) 55-62 (Mar 1992) Behnam-Guilani K Hickey G L Hipple M J (1991) Statistical models for predicting coal-fired generating unit costs and performance Proceedings of the American Power Conference 53 888-892 (1991) Bend S L (1989) Coal characterisation and combustion PhD Thesis Newcastle upon Tyne UK University of Newcastle upon Tyne 189 pp (Nov 1989) Bennett R Fogel W Aloia P (1988) Wet fuel handling A program to minimize plugging In Defining coal handleability Its cost impact and control Lexington KY USA 30 Apr-l May 1987 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Information Services pp 41-410 (Nov 1988) Benson S A Steadman E N Kalmanovitch D P (1988) Studies of the fonnation of alkali and alkaline earth aluminosilicates during coal combustion using a laboratory scale furnace In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 31-312 (1988) Berkowitz N (1985) The methods of coal chemistry In The chemistry of coal Amsterdam the Netherlands Elsevier Science Publishers pp 33-102 (1985)
Berkowitz N (1989) Atmospheric oxidation of coal In Sample selection aging and reactivity of coal New York NY USA John Wiley and Sons pp 217-253 (1989) Blake M W (1988) Estimating benefits from cleaning coals In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 667-676 (1988) Blake M W Robin T T (1982) Coal quality influence on operating plant cost Paper presented at Ninth annual engineering conference on reliability for the electric power industry Hershey PA USA 16-19 Jun 1982 Blondin J Girardeau M Nomine M (1988) Two simple tests for the assessment of wet fine coal handleability In Industrial practice offine coal processing KIimpel R R Luckie P T (eds) Littleton CO USA SME-AIME pp 253-255 (1988) Blough J L Kihara S Wolowodiuk W (1988) Effects of coal properties on superheater corrosion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 235-253 (1988) Boley D G (1984) Calcium chloride A new solution for frozen coal Power 128 (1) 67-69 (Jan 1984) Borio R W Levasseur A A (1986) Coal ash deposition in boilers ACS Symposium Series 103 288-302 (1986) Borio R W Levasseur A A Chow 0 K Miemiec L S (1992) Ash deposition a boiler manufacturers perspective In Engineering Foundation conference on inorganic transfonnations and ash deposition during combustion Palm Coast FL USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 95-120 (1992) Borio R W Plumley A L Sylvester W R (1978) Improved thennal efficiency by controlling of factors affecting metal wastage in pulverized coal-fired steam generators In Ash deposits and corrosion due to impurities in combustion gases Bryers R W (ed) Washington DC USA Hemisphere Publishing pp 163-183 (1978) Boushka M (1988) Application of EPRIs coal quality impact model In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Infonnation Services pp AI-A20 (May 1988) Boyd R K Kent J H (1986) Three-dimensional furnace computer modelling In Twentyjirst symposium (international) on combustion Munich Federal Republic of Gennany 3 Aug 1986 Pittsburgh PA USA The Combustion Institute pp 265-274 (1986) Boyd R K Lowe A (1988) Three-dimensional modeling of a pulverised-coal fired utility furnace In Coal combustion science and technology of industrial and utility application Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 165-172 (1988) Boyd R K Lowe A (1992) Sydney NSW Australia Pacific Power Services Personal communication (Sep 1992) Bretz E A (1991a) Specifying powerplant fuels and combustion systems Electrical World 205 (2) 40-45 (Feb 1991) Bretz E A (1991b) Innovation key to finding unusual ash-disposal options Electrical World 205 (7) 56-57 (Jul 1991) Brooks K Glasser D (1986) A simplified model of
105
References
spontaneous combustion in coal stockpiles Fuel 65 (8) 1035-1041 (Jug 1986) Brooks S Meadowcroft DB Morris C W Flatley T A (1983) J laboratory evaluation of alloys potentially resistant to furnace wall corrosion In Corrosion resistant materials in coal conversion systems Meadowcroft D B Manning M S (eds) London UK Jpplied Science Publishers pp 121-135 (1983) Brown K (1985) Sampling testing and analysis of coals In An intensive course on the characterisation of steaming coals Newcastle NSW Justralia 20-22 May 1985 Newcastle NSW Justralia University of Newcastle Institute of Coal Research pp 21-239 (May 1985) Bryers R W (1992) Fireside behaviour of mineral impurities in fuels from Marchwood 1963 to the Sheraton Palm Coast 1992 In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USJ 10-15 Mar 1991 New York NY USJ Jmerican Society of Mechanical Engineers pp 3-70 (1992) Bull D L (1992) Jsh deposition a utility perspective In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USJ 10-15 Mar 1991 New York NY USJ Jmerican Society of Mechanical Engineers pp 121-132 (1992) Burchill P (1987) Some observations on the variation of nitrogen content and functionality with coal rank In 1987 International conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Jmsterdam the Netherlands Elsevier Science Publishing Company pp 5-8 (1987) Byrne G J Juniper L A (1987) Utilization characteristics of Justralian steaming coals in overseas power stations In Coal Power 87 The AUSIMM annual conference in association with the Mining and Metallurgical Institute of Japan (MMIJ) Newcastle NSW Justralia May 1987 Parkville Vic Justralia The Justralasian Institute of Mining and Metallurgy pp 293-301 (May 1987) Cacka H Lang I Fabianova D (1989) Vliv prvkoveho slozeni uhli HDBS a jejich THF extraktu na nizkoteplotni oxidaci uhli (Effects of elementary composition of coal from the Sokolov brown coal basin and its tetrahydrofuran extracts on low-temperature oxidation) In 2 celostatni konference Samovolne vmecovani uhli v teoril a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSJV pp 1-14 (1989) Cagnetta A C Zelensky G (1983) Coal qualitydesigning a power plant for a wide range or dedicated coal supply In Fifth international coal utilization exhibition and conference Houston TX USJ 7-9 Dec 1982 Houston TX US1 EBJSCO Services Inc pp 3-14 (Dec 1983) Calarco V Bennett D (1989) United States acid rain legislation implications for the international coal markets In CoalTrans 89 sixth international coal trade and transportation conference London UK 16-18 Oct 1989 Worcester Park UK CoalTrans Conferences Ltd vp (1989) Carmichael R L (1987) Factors influencing selection of coals for existing power plants In International symposium on mining technology and science Xuzhou China 18 Sep 1985 Beijing China China Coal Industry Publishing House pp 1365-1371 (1987)
Carpenter A (1988) Coal classification IEJCR12 London UK IEJ Coal Research 104 pp (Oct 1988) Cerkanowicz A E Liskowitz J W Wecharatana M (1991) Potential model of the energy manufacturing process to predict properties of fly-ash as it relates to utilization In Eighth annual international Pittsburgh coal conference Coal - energy and the environment Pittsburgh PJ USJ 14-18 Oct 1991 Greenburg PA USJ Pittsburgh Coal Conference pp 839-842 (1991) Chamberlain R A C Hall D A (1973) The liability of coals to spontaneous combustion Colliery Guardian 221 (2) 65 (Feb 1973) Chen J Y Harris D J Smith I W Zhang D K Wall T F Stanmore B R (1991) Combustion reactivity of coals shyevaluation of laboratory techniques In 1991 international conference on coal science - proceedings Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 303-306 (Sep 1991) Chen X D (1991) The effect of moisture content on the spontaneous ignition process - a review In Proceedings of the fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Jssociation of New Zealand vol 2 pp 327-337 (1991) Chou SF Daniels P L Rodgers L W Theus G J Eskinazi D (1986) Fire-side corrosion in 10w-NOx
combustion systems In Proceedings Symposium on stationary combustion NOx control Boston MJ US1 6-9 May 1985 EPRI-CS-4360 Palo Jlto C1 US1 EPRI Technicallnfonnation Services pp 191-1922 (Jan 1986) Cichanowicz J E Harrison C D (1989) The role of coal cleaning in integrated environmental control In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Jlto C1 USA EPRI Technical Information Services pp 711-724 (Oct 1989) Clarke F Morris C W (1983) Combustion aspects of furnace wall corrosion In Corrosion resistant materials in coal conversion systems Meadowcroft D B Manning M I (eds) London UK Jpplied Science Publishers pp 47-61 (1983) Clarke L Sloss L (1992) Trace elements emissions from coal combustion and gasification IEJCR49 London UK IEJ Coal Research 111 pp (1992) Clemens A H Matheson T W Rogers D E (1990) DTJ studies of the low temperature oxidation of low rank coals Fuel 69 (2) 255-256 (Feb 1990) Coal Research Establishment British Coal Corporation (1991) Studies of the production ofnitrogen oxides and ash deposition from pulverised coal in relation to utilisation in low NOx burners EUR 13443 EN Luxembourg Commission of the European Communities 46 pp (1991) CoaiTrans International (1991) Coal in the environmentshysupplement CoalTrans International 6 (2) VI-XIII (MarlJpr 1991) Colijn H (1988a) Coal properties handleability and bin design In Defining coal handleability Its cost impact and control Lexington KY USJ 30 Jpr-1 May 1987 EPRI-CS-6015 Palo Jlto CJ USA EPRI Research Reports Center pp 21-219 (Nov 1988) Colijn H (1988b) Coal handleability as part of coal quality control In 1988 joint power generation conference
106
References
Philadelphia PA USA 25-29 Sep 1988 New York NY USA The American Society of Mechanical Engineers pp 25-41 (Sep 1988) Collins S (1990) Can problems arising from chlorine in coal be solved generically Power 134 (12) 59-60 (Dec 1990) Connelly L J (1988) Freeze condition agents and their use in the coal industry In Defining coal handleability Its cost impact and control Lexington KY USA 30 Apr-l May 1987 EPRI-CS-6015 Palo Alto CA USA EPRI Research Reports Center pp 31-327 (Nov 1988) Conroy A (1991) Grinding behaviour of hard coals Combustion News 1-4 (Nov 1991) Corder W C (1983) For lower power costs use high quality coal In Third European coal utilisation conference Amsterdam The Netherlands 11-13 Oct 1983 Rotterdam The Netherlands Industrial Presentations pp 221-240 (1983) Corio M R (1982) Heat rates and availability the use of econometric analysis in comparing electric generating unit performance New York NY USA National Economic Research Associates vp (1982) Corson P B (1988) Carolina Power and Light purchasing model (COALBUY) In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 41-410 (May 1988) Cortsen C E (1983) An evaluation of coal properties and their influence on the utilisation in power stations Report No2 2nd ed Fredericia Denmark ELSAM Coal Quality Committee 161 pp (Nov 1983) Couch G R (1988) Lignite resources and characteristics IEACR13 London UK IEA Coal Research 102 pp (Dec 1988) Couch G R (1989) Power generationfrom lignite IEACR19 London UK IEA Coal Research 67 pp (Dec 1989) Couch G R (1991) Advanced coal cleaning technology IEACR44 London UK IEA Coal Research 95 pp (1991) Cox J N Smith S R Metha A (1990) Field evaluation of EPRI coal quality impact model In Proceedings 1989 EPRl heat-rate improvement conference Knoxville TN USA 26-28 Sep 1989 EPRI-GS-6985 Palo Alto CA USA EPRI Research Reports Center pp 4B61-4B68 (Sep 1990) CQ Inc (1992) The Acid Rain Advisor Homer City PA USA CQ Inc 2 pp (1992) Crelling J C Skorupska N M Marsh H (1988) Reactivity of coal macerals and lithotypes Fuel 67 (6) 781-785 (lun 1988) Cumming J W (1980) The electrical resistance of coal ash at elevated temperatures Journal of the Institute of Energy 53 (416) 153-154 (Sep 1980) Cumming J W Livingston W R Hesselmann G J (1987) Coal reactivity assessment for boiler design In Coaltech 87 - Coaltrade 87 - conference papers London UK 9-11 Jun 1987 Schiedam the Netherlands Industrial Presentations pp 11-30 (1987) Cunliffe F (1990) Thornton UK Shell Research Limited Personal communication (1990) Dacey P W Cope D R (1986) Process development In Flue gas desulphurisation - system performance ICEASIB4 London UK IEA Coal Research pp 44-48 (Dec 1986) Daniel M (1991a) Power station coal use prospects to 2000 IEACR4l London UK IEA Coal Research 61 pp (Oct 1991)
Daniel P L (1991b) The effect of coal chlorides on furnace wall corrosion In First international conference on chlorine in coal Chicago IL USA 9-11 Oct 1989 Amsterdam the Netherlands Elsevier Science Publishers pp 207-224 (1991) Darby K (1983) Commercial precipitator design In Second CSIRO conference on electrostatic precipitation Bowral NSW Australia 17-19 Aug 1983 North Ryde NSW Australia Commonwealth Scientific Industrial Research Organisation pp L41-L431 (1983) Davidson R (1990) Effects on coal behaviour In Natural oxidation of coal IEACR29 London UK IEA Coal Research pp 55-65 (Sep 1990) Davis A (1984) Coal petrography and petrographic analysis In Coal geology and coal technology Ward C R (ed) Melbourne Vic Australia Blackwell Scientific Publications pp 74-112 (1984) Deiuliis N J Fink C E Abbott M F (1991) The impact of ash quantity and quality on boiler performance and power cost In Eighth annual international Pittsburgh coal conference Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greenburg PA USA Pittsburgh Coal Conference pp 975-980 (1991) Deutsch W (1922) Bewegung und Ladung der Elektrizitatstrager im Zylinderkondensator (Velocity and loading of charged particles in cyclinder capacitors) Annales der Physik 68 335-344 (1922) Diessel C F K Bailey J G (1989) The application of petrographic techniques to carbonisation and combustion research at the University of Newcastle In MINPET 89shyMineralogy-petrology symposium Sydney NSW Australia 6-8 Feb 1989 Sydney NSW Australia The Australasian Institute of Mining and Metallurgy pp 117-121 (Feb 1989) Donais R T Tyler A L Bakker W T (1988) Effects of coal properties on pulverizer abrasion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 21-217 (1988) Dooley B (1992) Boiler tube failures - a perspective and a vision In International conference on boiler tube failures in fossil plants San Diego CA USA 5-7 Nov 1991 EPRI-TR-100493 Palo Alto CA USA EPRI Distribution Centre pp 11-129 (Apr 1992) Doyle G (1989) Price premiums and inter-coal competition In CoalTrans 89 sixth international coal trade and transportation conference London UK 16-18 Oct 1989 Worcester Park UK CoalTrans Conferences Ltd pp 177-180 (1989) Dusak V (1986) Brown coal and its safe storage Energetika 36 (1011) 471-474 (Oct 1986) Eck G A (1987) Perfectblend coal blending computer program Journal of Coal Quality 6 (3) 100-101 (lui 1987) Electrical World (1987) Utilities report boiler failure chief culprit in forced outages Electrical World 201 (8) 50-52 (Aug 1987) Elliott M A (ed) (1981) Chemistry of coal utilizationshysecond supplementary volume New York NY USA John Wiley and Sons 2274 pp (1981) Elliott T C (1991) Monitoring powerplant performance Power 135 (9) 11-26 (Sep 1991) Elliott T C (1992) Coal handling and preparation Power 136 (1) 17-33 (Jan 1992) ERM Consultants Pty Ltd (1983) Australian case studies
107
References
which relate to coal quality andor consistency to efficiency and economy ofpower production Brisbane Qld Australia ERM Consultants Pty Ltd vp (Mar 1983) Essenhigh R H (1981) Fundamentals of coal combustion In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley and Sons pp 1153-1312 (1981) Evans R J (1991) A computer expert system to reduce power plant emissions PErC Review (4) 24-28 (1991) Falcon L M Falcon R M S (1987) The petrographic composition of Southern African coals in relation to friability hardness and abrasive indices Journal of South African Institute ofMining and Metallurgy 87 (10) 323-336 (Oct 1987) Falcon R M S Snyman C P (1986) An introduction to coal petrography atlas ofpetrographic constituents in the bituminous coals of South Africa Johannesburg South Africa Geological Society of South Africa 27 pp (1986) Falcon R Ham A J (1988) The characteristics of Southern African coals Journal of South African Institute ofMining and Metallurgy 88 (5) 145-161 (May 1988) Fiveland W A Wessel R A (1988) Numerical model for predicting perfonnance of three-dimensional pulverized-fuel fired furnaces Journal ofEngineering for Gas Turbines and Power 110 117-129 (1988) Flatley T Latham E P Morris C W (1981) Co-extruded tubes improve resistance to fuel ash corrosion in UK boilers Material Performance 20 (5) 12-17 (May 1981) Folsom B A Heap M P PoW J H (1986a) Effect of coal quality on power plant performance and costs - Volume 1 State-of-the-art review summary and program plan EPRl-CS-4283-Vol1 Palo Alto CA USA EPRl Technical Infonnation Services 262 pp (Feb 1986) Folsom B A Heap M P PoW J H Smith J L Corio M R (1986b) Effect of coal quality on power plant performance and costs - Volume 2 Review of coal quality impact evaluation procedures EPRl-CS-4283-Vo12 Palo Alto CA USA EPRl Technical Infonnation Services 387 pp (Feb 1986) Folsom B A Heap M P PoW J H Smith J L (1986c) Effect of coal quality on power plant performance and costs - Volume 3 Review of coal quality and power plant performance diagnostics EPRl-CS-4283-Vo13 Palo Alto CA USA EPRI Technical Infonnation Services 176 pp (Feb 1986) Fortune D B (1990) London UK Shell Coal International Ltd Personal communication (1990) Galluzzo N G Stallard G S Boushka M E Mehta A K (1987) Model predicts as-fired costs of changing coal sources Power 131 (6) 53-56 (Jun 1987) Gebel K Madlsperger G Hein K Bokenbrink D (1989) Entwicklung eines Kombinations DeNOx-Verfahrens unter Verwendung von feuerungstechnischen Minderungsrnassnahmen und Hamstoff-SNCR-Technik (Development of a combined DeNOx process using staged combustion and urea-SNCR technology) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Gennany 26-27 Apr 1989 Essen Federal Republic of Gennany VGB Kraftswerkstechnik GmbH pp 173-180 (Apr 1989) Gibb W H (1983) The nature of chlorine in coal and its
behaviour during combustion In Corrosion resistant materials for coal conversion systems Meadowcroft D B Manning M S (eds) London UK Applied Science Publishers pp 25-45 (1983) Gibb W H (1992) Nottingham UK PowerGen Ratcliffe Technology Centre Personal communication (Sep 1992) Gibbs L A Hallett W L H Hughes P M (1989) Coal devolatilization in an entrained flow reactor In The Combustion 1nstitute Canadian Section 1989 spring technical meeting Toronto Ontario Canada 31 May-2 Jun 1989 Ontario Canada The Combustion Institute pp 91-93 (1989) Giovanni D V Afonso R F Dyas B E Mehta A K (1991) Coal quality field test at New England power companys Salem Harbour Unit Three In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRl-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 379-398 (Jul 1991) Given P H (1984) An essay on the organic geochemistry of coal In Coal science volume 3 Gorbaty M L Larsen J Wender I (eds) Orlando FL USA Academic Press pp 63-252 (1984) Given P H Yarzab R F (1978) Coal analysis and mineral matter In Analytical methods for coal and coal products shyVolume II Karr C Jr (ed) New York NY USA Academic Press pp 3-42 (1978) Gluskoter H J Shimp N F Ruch R R (1981) Coal analyses trace elements and mineral matter In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley amp Sons pp 369-424 (1981) Goddard C W Duzy A F (1967) Measuring abrasiveness of solid fuels and other materials by a radiochemical method ASME paper no 67-WAIFU-l New York NY USA American Society of Mechanical Engineers vp (1967) Goetz G J Nsakala N Y Borio R W (1978) Development of methods for determining emissintives and adsorptivities of coal ash deposits In 1987 winter annual ASME meeting Boston MA USA 13 Dec 1978 New York NY USA American Society of Mechanical Engineers vp (1978) Gomer K (1988) Prediction of the turbulent flow heat release and heat transfer in utility boiler furnaces In Coal combustion Science and technology of industrial and utility applications Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 273-282 (1988) Gutberlet H (1988) Einfluss der Feuerungsart auf die Vergiftung von DeNOx-Katalysatoren durch Arsen (The effect of furnace type on the poisoning of DeNOx catalysts by arsenic) VGB Kraftwerkstechnik 68 (3) 287-293 (Mar 1988) Hainley D C Yavuzkurt S Scaroni A W (1986) Effect of coal properties on fluidized bed combustor perfonnance In Energy-sources technology conference and exhibition New Orleans LA USA 23 Feb 1986 New York NY USA American Society of Mechanical Engineers pp 43-54 (1986) Hampartsoumian E Murdoch M Pourkashanian M Williams A (1991) The reactivity of coal chars produced under various pyrolysing conditions In 1991 international conference on coal science - proceedings Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 271-274 (Sep 1991) Harb J N Smith E E (1990) Fireside corrosion in PC-fired
108
References
boilers Progress in Energy and Combustion Science 16 (3) 169-190 (1990) Hardgrove R M (1938) ASME technical paper Paper presented at ASME spring meeting Chicago IL USA 27 Jun 1938 Harrington R C Kaltenback R P Stratton H L (1988) Burner improvement program on a 650 MW supercritical steam generator - a case study In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 541-549 (Sep 1988) Harrison C Zera C (1990) A new way of doing business in coal-fired power generation Power Engineering 94 (4) 33-36 (Apr 1990) Hatt R M (1990) Fireside deposits in coal-fired utility boilers Progress in Energy and Combustion Science 16 (4) 235-241 (1990) Hatt R M (1991) Coal mining and preparation practices shyimpacts on power plant perfonnance In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 365-377 (Jul 1991) Heap M P Kramlich J C Pershing D W Pohl J H Richter W F Seeker W R (1986) Effect of coal quality on power plant performance and costs - Volume 4 Review of coal science fundamentals EPRI-CS-4283-Vo14 Palo Alto CA USA EPRI Technical Infonnation Services 574 pp (Feb 1986) Heap M P Pohl A S Folsom A S Mehta A K (1984) The effects of coal quality and the resulting ash deposition on the costs of power station operation (Die Bedeutung der Kohlqualitiit und der daraus resultierenden Aschelagerungen fur die Kostan des Kraftwerksbetriebes) In Internationale VGB-Konferenz Verschlackungen Verschmutzungen und Korrosionen in Wriimekraftwerken - Vortriige Essen Federal Republic of Gennany 29 Feb-2 Mar 1984 Essen Federal Republic of Gennany VGB Technische Vereinigung der Grosskraftwerksbetreiber eV pp 493-507 (1984) Heble J J Srinivaschar S Boni A A (1991) The behaviour of clay minerals under combustion conditions American Chemical Society Division of Fuel Chemistry Preprints 36 (1) 173-180 (Apr 1991) Heitmiiller W Schuster H (1991) Low-NOx pulverized coal firing systems and their components Infonnation No 189 Hausdruckerei Gennany Deutsche Babcock Energie- und Umwelttechnik AG 17 pp (Mar 1991) Hervol J D Mehta A K Levasseur A A Miemiec L S Lexa G F (1988) Benefits of coal cleaning on the capital and operating costs of a 550 MW boiler In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 81-824 (May 1988) Hewing A N Harvey M R (1981) Evaluating freeze conditioning agents for coal Power Engineering 85 (7) 74-75 (JuI1981) Hjalmarsson A-K (1990) NOx control technologies for coal combustion IEACRl24 London UK lEA Coal Research 102 pp (Jun 1990) Hjalmarsson A-K (1992) Interactions in emissions control for coal-fired plant IEACRl47 London UK lEA Coal Research 81 pp (Mar 1992) Hjalmarsson A-K Soud H N (1990) Systems for controlling
NOxfrom coal combustion IEACRl30 London UK lEA Coal Research 240 pp (Dec 1990) Hobbs M L Smith P J (1990) Algebraic multi-zoned radiation model for a two-zoned zero-dimensional cylindrical furnace Fuel 69 (11) 1420-1427 (Nov 1990) Hodde J A (1988) Least cost fuel system used to plan fuel purchases In 1988 joint power generation conference Philadelphia PA USA 25-29 Sep 1988 New York NY USA American Society of Mechanical Engineers pp 43-51 (Sep 1988) Holstein R A (1981) Coal fired power plant capital cost estimates EPRI-PE-1865 Palo Alto CA USA EPRI Technical Infonnation Services vp (1981) Horsfall D W Zitron Z (1982) High density beneficiation of coal In Proceedings sixth international conference on coal research London UK 4-8 Oct 1982 London UK National Coal Board pp 319-337 (1982) lEA Coal Industry Advisory Board (1985) Coal quality and ash characteristics Paris France OECDIIEA 63 pp (Jan 1985) IEEE (1984) IEEE standard criteria and guidelines for the laboratory measurement and reporting offly ash resistivity IEEE Standard 548-1984 New York NY USA Institute of Electrical and Electronics Engineers 30 pp (21 Dec 1984) ICCP International Committee for Coal Petrology (1963) International handbook of coal petrology - second edition Paris France Centre National de la Recherche Scientifique vp (1963) ICCP International Committee for Coal Petrology (1975) International handbook of coal petrology - supplement to the second edition Paris France Centre National de la Recherche Scientifique vp (1975) ICCP International Committee for Coal Petrology (1985) International handbook of coal petrology - edited reprint of 1975 supplement to the second edition Murchison D G Smith A H V (eds) Newcastle upon Tyne UK University of Newcastle upon Tyne vp (1985) International Energy Agency (1992) Coal information 1992 Paris France OECDIIEA 541 pp (1992) Iskhakov Kh A (1990) The role of sorbed moisture in coal oxidation Solid Fuel Chemistry (English translation) 24 (2) 17-21 (1990) Jacobs J P (1992) Essen Gennany VGB Technical Association of Large Power Plant Operators Personal communication (Sep 1992) Jamaluddin A S Fiveland W A (1990) Practical model for predicting unburned carbon and temperatures in large-scale boilers Paper presented at 1990 spring meeting combustion fundamentals and applications Cincinnati OH USA 20-22 May 1990 Jenson P T (1992) Fredericia Denmark ELSAM Personal communication (Sep 1992) Johanson J R (1989) Evaluating coal handling characteristics In 1989 joint power generation conference Dallas TX USA 22-26 Oct 1989 New York NY USA American Society of Mechanical Engineers pp 1-5 (Oct 1989) Johanson J R (1991) Identify hard-to-handle coal early Power Engineering 95 (11) 35-38 (Nov 1991) Johnson R P Plangemann R Rehm M (1991) Coal quality effects on boiler perfonnance an Eastern utility perspective In Effects of coal quality on power plants St Louis MI
109
References
USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 11-113 (Jul 1991) Jones A R Gibb W Johnston J (1992) Nottingham UK PowerGen Ratcliffe Technology Centre Personal communication (Mar 1992) Jones M L Benson S A (1988) An overview of slagginglfouling with Western coals In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 125-147 (1988) Jones R B McCourt C B Morley C King K (1985) Maceral and rank influences on the morphology of coal char Fuel 64 (10) 1460-1467 (Oct 1985) Juniper L Pohl J (1991) Techniques to control NOx
emissions from coal-fIred boilers Australian Combustion Technology Centre Combustion News 1-4 (May 1991) Jiintgen H (1987a) Coal characterization in relation to coal combustion Part I structural aspects and combustion Erdol Kohle Erdgas Petrochemie vereinigt mit Brennstoff-Chemie 40 (4) 153-165 (Apr 1987) Jiintgen H (1987b) Coal characterization in relation to coal combustion Part II environmental problems of combustion ErdOl Kohle Erdgas Petrochemie vereinigt mit Brennstoff-Chemie 40 (5) 204-208 (May 1987) Kalmanovitch D P (1991) A practical approach to predicting ash deposition In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 591-5102 (Jul 1991) Kapteijn F Bruinsma D Mol J Moolijn J A (1990) The characterisation of fly-chars from combustion the effect of temperature and rank on reactivity texture and composition Fuel Processing Technology 24 (113) 391-398 (1990) Kautz K (1982) Importance of maceral content in regard to the properties of coals of worldwide origin and its effects on combustion chamber design of large dry furnaces VGB Kraftwerkstechnik - English Issue 62 (3) 1-12 (Mar 1982) Kehoe D B Hervol J D Evans R J Levasseur A A (1990) Evaluating the effects of cleaned coals in utility boilers In Eleventh international coal preparation congress Tokyo Japan 22-25 Oct 1990 Tokyo Japan Mining and Materials Processing Institute of Japan pp 247-252 (1990) Kemeny P (1988) Coal quality impact on electric power generation costs case study Fusina unit 3 In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 631-655 (1988) King J G Maries M B Crossley H E (1936) Fonnulae for the calculation of coal analysis to a basis of coal substance free of mineral matter Journal for the Society of Chemistry and Industry 55 277-281 (1936) Kirchner A T (1991) On-line analysis of coal IEACR40 London UK lEA Coal Research 79 pp (Sep 1991) Kiss L T King TN (1979) Reporting of low-rank coal analysis - the distinction between minerals and inorganics Fuel 58 (7) 547-549 (Jul 1979) Klingspor J S Vernon J L (1988) Particulate control for coal combustion IEACR05 London UK lEA Coal Research 70 pp (Feb 1988) Klitgaard J (1988) Utility coal quality work at a cross-road Journal of Coal Quality 7 (2) 36-37 (Jun 1988) Knill K J (1987) A review offuel staging in pulverised coal
combustion systems IFRF-G-13a3 IJmuiden Netherlands International Flame Research Foundation 54 pp (Sep 1987) Kok A (1988) The effect of coal type on carbon burnout and NOx fonnation in pulverized coal combustion In Coaltech 88 - Coaltrade 88 seventh international conference on coal technology and coal trade Amsterdam the Netherlands 21-23 Nov 1988 Amsterdam the Netherlands Industrial Presentations (Europe) BV pp 1-14 B3 (1988) Kosvic T C Breen B P Yingling J C Mazumdar M Carpenter M Stothart B Plangemann R Maurer W (1988) A combined mechanisticstatistical approach to relating coal properties and boiler operating characteristics to the perfonnance of coal fIred boilers In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 71-717 (Sep 1988) Kremer H Grigoleit H Jacobs J (1990) Tendency of power station coals to fonn NOx - Results of VGB Research Project 89 VGB Kraftwerkstechnik - English Issue 70 (7) 478-484 (Jul 1990) Latham C E Fiveland W A La Rue A D (1991a) Numerical models as combustion system design tools In Eighth annual international Pittsburgh coal conference proceedings Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greenburg PA USA Pittsburgh Coal Conference pp 34-39 (1991) Latham E Meadowcroft D B Pinder L (1991b) The effects of coal chlorine on fireside corrosion In First international conference on chlorine in coal Chicago IL USA 9-11 Oct 1989 Amsterdam the Netherlands Elsevier Science Publishers pp 225-250 (1991) Laurendeau N M (1978) Heterogeneous kinetics of coal char gasification and combustion Progress in Energy and Combustion Science 4 (4) 221-270 (1978) Lee G K Thambimuthu K V Hill J M (1991) Assessment of ash sintering potential by conductance and dilatometry In Eight annual international Pittsburgh coal conference proceedings Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greensburg PA USA Pittsburgh Coal Conference pp 6-11 (1991) Llewellyn W (1991) A practical study of coal handleability In Proceedings of the fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Association of New Zealand vol 1 pp 115-126 (1991) Llinares V Caron M B Schmidt E J Szela F J (1982) The C-E availability data program 1982 further developments on MTTR and MTBF analysis Paper presented at Ninth annual engineering conference on reliability for the electric power industry Hershey PA USA 16-19 Jun 1982 Llinares V Lutz A B (1985) Long range forecast and availability improvement program In Proceedings of the 1985 joint ASMEIEEE power generation conference Milwaukee WI USA 20 Oct 1985 New York NY USA American Society of Mechanical Engineers vp (1985) Lockwood F C Mahmud T (1989) The prediction of swirl burner pulverized coal flames In Twenty-second symposium (international) on combustion Seattle WA USA 14-19 Aug 1988 Pittsburgh PA USA The Combustion Institute pp 165-173 (1989) Lowe A (1987) Important coal properties for power
110
References
generation In Geology and coal mining conference Sydney NSW Australia 13-15 Oct 1987 Sydney NSW Australia Geological Society of Australia Coal Geology Group pp 188-196 (Oct 1987) Lowe A (1988a) Effect of ash levels on large pulverised coal fired furnace performance In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 523-540 (Sep 1988) Lowe A (1988b) Effect of ash in coal on power plant availability In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 733-744 (1988) Luckie P T and others (1980) Coal grinding technology A manual for process engineers ERDA FE-2475-25 USA US Government Printing Office No 1980-640-258-2090 vp (1980) Luo X-L Boyd R K Kent J H (1991) Computational investigation of burnout in a furnace firing pulverised coal Journal of the Institute of Energy 64 (461) 230-238 (Dec 1991) Mackowsky M Th (1982) Minerals and trace elements occurring in coal In Stachs textbook of coal petrology Stach E Mackowsky M Th Teichrnller M Taylor G H Chandra D Teichrnller R (eds) Berlin Federal Republic of Germany Gebriider Borntraeger pp 153-171 (1982) Maher T P Smith MY (1990) A user-friendly coal value model for thermal coals In 1990 international coal engineering conference Sydney NSW Australia 19-21 lun 1990 Barton ACT Australia Institution of Engineers pp 259-263 (lun 1990) Mahr D (1988) Blending coal for quality control In 1988 joint power generation conference - coal quality control fundamentals and applications Philadelphia PA USA 25-29 Sep 1988 New York NY USA American Society of Mechanical Engineers pp 1-8 (Sep 1988) Makanski J (1989) Coal analyzers provide critical link for plant control functions Power 133 (2) 23-25 (Feb 1989) Malhotra V M Crelling J C (1987) Spontaneous combustion of coal and maceral enriched fractions under storage pneumatic transport conditions Final report DOEIPC79863-T13 Carbondale IL USA Coal Extraction and Utilization Research Center 97 pp (Mar 1987) Mancini R A Hopkins B W Hodde J A (1987) Coal quality engineering aids purchasing Power Engineering 91 (6) 16-20 (lun 1987) Mancini R A Hopkins B W Hodde J A (1988) Coal quality engineering analysis used to evaluate coal purchases In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 Palo Alto CA USA EPRI Research Reports Center pp 51-515 (May 1988) Mason D M Gandhi K (1980) Formulas for calculating the heating value of coal and char development tests and uses American Chemical Society Division of Fuel Chemistry Preprints 25 (3) 235-245 (1980) Matsuura S Uchida S (1988) Spontaneous combustion susceptibility of coals Saiko to Hoan 34 (10) 2-14 (25 Oct 1988) Matts S A Ohnfeldt P 0 (1973) Efficient gas cleaning with SF electrostatic precipitators Vaxjo Sweden Flakt Industri AB vp (1973)
McCartney R H Whittaker P S Planner J H (1990) A comparison of United States and Australian practices for power station coal handling facilities In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 lun 1990 Sydney NSW Australia Institution of Engineers pp 174-183 (lun 1990) Mehta A (1989) Coal quality impact model EPRl Journal 14 (8) 49-52 (Dec 1989) Mellanby-Lee H (1986) Effects of coal quality on the costs of electricity generation In Physical coal beneficiation and electricity costs ICEASC3 London UK lEA Coal Research pp 18-30 (Feb 1986) Meyers A D Atkinson B W (1991) Using techno-economic computer modelling to assess the utilisation value of New Zealand coal on the world market In Fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Association of New Zealand pp 160-171 (1991) Mikula R J Parsons I S (1991) Coal dustiness characterisation and control Coal Preparation 9 (314) 199-212 (1991) Misra M K Essenhigh R H (1990) Modelling of one-dimensional pulverised coal flames Paper presented at 1990 spring technical meeting combustion fundamentals and applications Cincinnati OH USA 20-22 May 1990 Mitas D Stallard S Anderson-Higgs A OConnor D (1991) Coal quality analysis linked to power plant control Power Engineering 95 (5) 29-32 (May 1991) Mittelbach G (1989) NOx- Minderung an Kohle-und Mtillkesseln mit dem TermoNOx Verfahren Vergleich von Untersuchungsergebnissen (NOx reduction at coal-fired plants and refuse incinerators with the ThermoNOx process a comparison of test results) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Germany 26-27 Apr 1989 Essen Federal Republic of Germany VGB Kraftswerkstechnik GmbH pp 194-200 (Apr 1989) Morgan M E (1987) Characterisation of coals for use in pulverised coal combustion In International conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 823-826 (1987) Morgan ME (1990) Effect of coal quality on the performance of low-NOx burners Journal of the Institute of Energy 66 (454) 3-8 (Mar 1990) Morgan P A Robertson S D Unsworth J F (1987) Combustion studies by thermogravimetric analysis Fuel 66 (2) 210-215 (Feb 1987) Morrison G F (1982) Control of sulphur oxides from coal combustion ICTISITR21 London UK lEA Coal Research 104 pp (Nov 1982) Morrison G F (1986) Understanding pulverised coal combustion ICTISITR34 London UK lEA Coal Research 46 pp (Dec 1986) Murtha M J (1982) Minerals extraction from ash state of the art In Proceedings of resources from coal coal wastes and ash workshop Reston VA USA 9 lun 1982 BNL-51679 DE83017775 Springfield VA USA National Technical Information Service pp 91-103 (1982) Muter R B Lawrence W F (1986) Mineral matter analysis a technique to improve bituminous coal ACS Symposium Series 301 443-448 (1986)
111
References
Myllynen H (1987) Which thermal coal In Coal Power 87 Neuss Dusseldorf Federal Republic of Germany 27-29 Oct 1987 Worcester Park UK CS Publications Ltd pp 37-42 (1987) Nadgauda S S Hathaway A J (1990) Coal utilization cost model for fuel procurement Journal of Coal Quality 9 (1) 17-21 (Mar 1990) Nakabayashi Y (1988) NOx removal from flue gas In The coal in Sweden conference on the role of coal in the Swedish energy system possibilities and limitation SOdertiilje Sweden 26-27 Oct 1988 Sdertlje Sweden Telge Energe AB pp 1-39 (Oct 1988) Nakata T Sato M Makino H (1988) Methods ofpredicting NOx emissions in coal combustion and unburned carbon in fly ash - effects of coal propenies CRIEPI-W-87003 Tokyo Japan Central Research Institute of the Electrical Power Industry 30 pp (Feb 1988) Nandi B N Brown T D Lee G K (1977) Inert coal macerals in combustion Fuel 56 (4) 125-130 (Apr 1977) Nayak R V Bauer F W Tonden T P (1987) Mineral matter in coal - origin identification and boiler erosion Journal of Coal Quality 6 (2) 37-43 (1987) Neavel R C (1981) Origin petrography and classification of coal In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley and Sons pp 91-158 (1981) Neavel R C Smith S E Hippo E J Miller R N (1986) Interrelationships between coal compositional parameters Fuel 65 (3) 312-320 (Mar 1986) Nemec J Dobal V (1988) Contribution to problem of coal spontaneous combustion Acta Montana Zpravy Hornickeho Ustavu CSAV (Ceskoslovenske Akademie Ved) (76) 9-20 (1988) Nicol S K Smitham J B (1990) Coal stockpile dust control In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 Jun 1990 Sydney NSW Australia Institution of Engineers pp 154-158 (Jun 1990) Noskievic P Kolat P Cech B (1987) Operational tests of burners for ignition and stabilization of pulverised coal Energetika 37 (5) 233-236 (May 1987) Nurick W (1988) An engineering approach to prediction of fuel impacts on utility boiler systems In Reducing electricity generation costs by improving coal quality Indiana PA USA 5-6 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 71-760 (May 1988) Oka N Murayama T Masuoka H Yamada S Yamada T Shinozaki S Shibaoka M Thomas C G (1987) The influence of rank and maceral composition on ignition and char burnout of pulverized coal Fuel Processing Technology 15 213-224 (Jan 1987) Osborn G A (1992) Review of sulphur and chlorine retention in coal-fIred boiler deposits Fuel 71 (2) 131-142 (Feb 1992) OKeefe W Hart R M Hopkins B W McIntire D C Harrison C D (1987) Do we need highly detailed coal specs Power 131 (10) 121-123 (Oct 1987) Parish B M (1970) Wear ofpulverisers Research report 363 Cheltenham UK National Coal Board Research Establishment vp (20 Mar 1970) Pasini S Trebbi G (1989) Evolutions of design and operation criteria for ENEL boilers Paper presented at Tenth international conference on power stations Liege Belgium 25-29 Sep 1989
Pavlikova H Machovic V Sebestova E (1989) Study of low-temperature coal oxidation by means of nuclear magnetic resonance spectrometers infrared spectrometers and electron spin resonance In 2 celostatni konference Samovolne vmecovani uhli v teorii a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSAV pp 1-14 (1989) Penninger A (1989) Effect of working parameters on flame stability for coal dust combustion In Tagung iiber Verbrennung und Feuerung14 Deutscher Flammentag (Meeting on combustion and furnaces 14 Gennan flame day) Stuttgart Federal Republic of Germany 5-6 Oct 1989 Dusseldorf Federal Republic of Germany Verein Deutscher Ingenieure (VDI) - Gesellschaft Energietechnik pp 669-679 (1989) Platfoot R (1990) Erosion life of tube banks in coal fired boilers In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 237-241 (Iun 1990) Pohl J S (1990) Procedure for evaluating the performance of low-grade fuels In Low-grade fuels Helsinki Finland 12-16 Jun 1989 Espoo Finland Valtion Teknillinen Tutkimuskeskus vol 1 pp 247-260 (1990) Potter E (1988) Correlations of ash chemistry with pilot-scale electrostatic precipitation experiments In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp N33-N34 (1988) PowerGen (1991) POSTMAN steady state plant modelling system Information sheet no 34 Nottingham UK PowerGen pic Power Technology Centre 2 pp (1991) Pronobis M (1989) Further fmdings concerning the effect of ash deposits upon the exchange of heat in convection boiler surfaces VGB Kraftwerkstechnik - English Issue 69 (11) 931-938 (Nov 1989) Raask E (1985) Mineral impurities in coal combustion shybehaviour problems and remedial measures London UK Hemisphere Publishing 506 pp (1985) Rademacher F J C (1990) Coal handling developments focusing on The Netherlands In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 282-288 (Jun 1990) Rees 0 W (1966) Chemistry uses and limitations of coal analysis Report of Investigations 220 Urbana IL USA lllinois State Geological Survey 50 pp (1966) Reinschmidt K F (1991) Neural networks next step for simulation and control Power Engineering 95 (11) 41-45 (Nov 1991) Repic B Radulovic P Sikmanovic S Grubor B (1988) Boilers start-up with pulverized coal Paper presented at 20 Kraftwerkstechnisches Kolloquium 1988 (20 power plant technical colloquium) Dresden Federal Republic of Germany 11-12 Oct 1988 Richter W Payne R Heap M P (1986) Influence of thermal properties of wall deposits on performance of pulverised fuel fired boiler combustion chambers ACS Symposium Series (301) 375-393 (1986) Richwine R R Quinn A D Mills J B Lowe S D (1989)
112
References
Results of the availability improvement program in the southern electric system Paper presented at Tenth international conference on power stations Liege Belgium 25-29 Sep 1989 Riley J T Gilleland S R Forsythe R F Graham H D Jr Hayes F J (1989) Nonadditive analytical values for coal blends In Proceedings of the seventh international coal testing conference Ashland KY USA 1989 Ashland KY USA Coal Testing Conference pp 32-38 (1989) Rittenhouse R C (1991) Fighting corrosion in air pollution control systems Power Engineering 95 (6) 23-29 (Jun 1991) Rittenhouse R C (1992) New fuel choices change coal handling and storage rules Power Engineering 96 (1) 17-21 (Jan 1992) Robinson G F (1985) A three-dimensional analytical model of a large tangentially fired furnace Journal of the Institute of Energy 116 226-150 (1985) Roy W R Griffin R A Dickerson D R Schuller R M (1984) illinois basin coal fly ashes 1 Chemical characterisation and solubility Environmental Science and Technology 18 (10) 734-739 (1984) Sadowski R S Hunt P J (1978) Consequences of specifying a boiler design fuel before source commitments are firm In Proceedings of the American power conference Vol 40 Chicago IL USA Apr 1978 Chicago IL USA illinois Institute of Technology pp 394-402 (1978) Sanyal A Livingston W R Marsh H Skorupska N M Field D J Edwards 1 AS (1991) Petrography of lignitic and bituminous coals application to assess coal combustibility for power generation In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 51-520 (JuI1991) Saxena S C (1990) Devolatilization and combustion characteristics of coal particles Progress in Energy and Combustion Science 16 (1) 55-94 (1990) Schaeffer J J (1988) Review of coal quality characteristics of potential utility fuel supply sources Journal of Coal Quality 7 (1) 19-22 (Jan 1988) Scieszka S F (1985) New concept for determining pulverizing properties of coal Fuel 64 (8) 1132-1142 (Aug 1985) Sebesta P Vodickova A (1989) Self-ignition of coal according to its reactivity to oxygen In Symposium on coal utilization trends and challenges Dhanbad India 13-14 Dec 1989 Dhanbad India Central Fuel Research Institute vp (1989) Sherman R A Pilcher J M (1938) An experimental investigation of the use of oil in the treatment of coal Transactions ofAmerican Society of Chemical Engineers 60 97-109 (1938) Shibaoka M Thomas C S Heng S Mackay G H (1987) Significance of morphological features of macerals in coal utilization research In 1987 international conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 107-110 (1987) Shida H Adacchi T Karagasaki M Kuminoto T Hisatome M Kobayashi Y (1984) Development of three-dimensional numerical analysis method of boiler furnace characteristics - part 1 flow analysis Technical Review 18-23 (1984)
Shigeta J-I Hamao Y Aoki H Kajigaya 1 (1987) Development of a coal ash corrosivity index for high temperature corrosion Journal of Engineering Materials and Technology 109 (4) 299-305 (Oct 1987) Shimada S Aumiiller A Klemm F (1991) Measurement of property change of coals stored in stockpile for a long time In 1991 international conference on coal science Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 925-928 (Sep 1991) Shonhardt J A (1990) Evaluation of spontaneous combustion characteristics of some Australian coals Coal Journal (Australia) (29) 21-31 (1990) Singer J G (1989a) Steam fundamentals In Standard handbook ofpower-plant engineering New York NY USA McGraw Hill pp 13-19 (1989) Singer J G (1989b) Pulverizers In Standard handbook of power-plant engineering New York NY USA McGraw Hill pp 1157-1182 (1989) Singer J G (1991) Combustion fossil power - a reference book on fuel burning and steam generation Windsor CN USA Combustion Engineering 1010 pp (1991) Skinner M S A (1988) The costs of burning coal In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Specialists pp 719-731 (1988) Skorupska N M Marsh H (1989) The importance of petrographic characterization of coal for combustion processes In Institute of Energy conference on applied energy research Swansea UK 5-7 Sep 1989 Bristol UK Adam Hilger pp 161-181 (1989) Skorupska N M Sanyal A Hesselman G J Crelling J C Edwards 1 A S Marsh H (1987) The use of an entrained flow reactor to assess the reactivity of coals of high inertinite content In 1987 intemational conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 827-831 (1987) Sligar J (1985) Coal pulverising mill section In Course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 101-1023 (May 1985) Sligar J (1992) Sydney NSW Australia Pacific Power Services Personal communication (Oct 1992) Smith D J (1991) Integrated control systems The next stop Power Engineering 95 (9) 17-21 (Sep 1991) Smith G (1985) Laboratory studies to support the marketing of Australian coals In Proceedings Coal research conference Wellington New Zealand 15-17 Oct 1985 Wellington New Zealand Coal Research Association of New Zealand vol 2 Paper 342 15 pp (1985) Smith 1 W (1982) The combustion rates of coal chars In Nineteenth symposium (international) on combustion Haifa Israel 8-13 Aug 1982 Pittsburgh PA USA The Combustion Institute pp 1045-1065 (1982) Smith 1 W Wall T F Stanmore B R Harris D J Chen J Y Zhang D K (1991a) Coal combustion testing optimum laboratory procedure NERDDP-EG-91-993 Canberra ACT Australia National Energy Research Development and Demonstration Council 89 pp (Feb 1991) Smith P J Davies P R Jamaluddin A S (1991b) Coupling fireside deposition with computational combustion predictions In Effects of coal quality on power plants St
113
References
Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 2119-2140 (Jul 1991) Smith P J Smoot L D (1987) Detailed model for practical pulverized coal furnaces and gasifiers In Proceedings of the AR and TD (Advanced Research and Technology Development) direct utilization and instrumentation and diagnostics contractors review meeting Morgantown WV USA 13 Oct 1987 DOEIMETC-886084-vol 1 Morgantown WV USA Morgantown Energy Technology Center pp 62-71 (Oct 1987) Smith S R (1988) Tennessee Valley Authoritys experience with switching to improved quality coal In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 Palo Alto CA USA EPRI Technical Infonnation Services pp 31-323 (May 1988) Smoot L D (1984) Modeling of coal-combustion processes Progress in Energy and Combustion Science 10 (2) 229-272 (1984) Smoot L D Smith P J (1985) Coal combustion and gasification New York NY USA Plenum Press 459 pp (1985) Sorter J G Folsom B A Richter W (1986) Application of pilot-scale coal evaluation to utility boilers In Joint ASMElIEEE Power generation conference Portland OR USA 19-23 Oct 1986 New York NY USA American Society of Mechanical Engineers pp 1-8 (Oct 1986) St Baker T C (1983) Technology of coal utilisation for electric power generation In Coal technology and coal utilisation Brisbane Qld Australia 29-31 Aug 1983 Brisbane Qld Australia Australian Mineral Foundation Inc pp 1-42 (Aug 1983) Stach E Mackowsky M Th Teichmiiller M and others (eds) (1982) Stachs textbook ofcoal petrology Berlin Federal Republic of Germany Gebriider Borntraeger 535 pp (1982) Stallard G S Galluzzo N G Brown R E Pavlish J H (1988) Implementing EPRIs state-of-the-art coal quality impact model into fuel procurement practices In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 677-693 (1988) Stallard G S Mehta A (1991) Using EPRI CQIM to evaluate acid rain strategies In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 257-275 (Jul 1991) Stallard S Galluzzo N G Mehta A K (1989) Demonstration coal quality impact model In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Alto CA USA EPRI Technical Infonnation Services pp 91-919 (Oct 1989) Stanmore B R (1990) Ash hopper explosions in coal-fired boilers In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 274-276 (Jun 1990) Strein D L (1989) Effects of changing coal quality on precipitator perfonnance In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Alto CA USA EPRI Technical Infonnation Services pp 41-417 (Oct 1989)
Swaine D J (1990) Methods of analysis In Trace elements in coal London UK Butterworths amp Co Ltd pp 50-76 (1990) Swanson A R Taggart I J Wood D L (1982) The economic value of coal for coal fired power stations In Coal Phoenix of the 80s - Proceedings 64th CIC coal symposium Halifax NS Canada 31 May-3 Jun 1981 Ottawa ON Canada Canadian Society for Chemical Engineering pp 324-329 (1982) Swithenbank J Garbett E S Boysan F Ayers W H (1988) Advance of research on coal combustion system modelling In International symposium on coal combustion Science and technology of industrial and utility applications Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 39-63 (1988) Tams D E (1990) Atmospheric fluidized beds - problems and solutions in practice In International conference on steam plant for the 1990s London UK 4-6 Apr 1990 Bury St Edmunds UK Mechanical Engineering Publications pp 117-124 (1990) Taraba B (1989) Effects of grain size and moisture on heat released during oxidation In 2 celostatni konference Samovolne vznecovani uhli v teorii a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSAV pp 1-9 (1989) Taubert U (1991) New developments in the waste disposal of coal-fired power plants VGB Kraftwerkstechnik - English Issue 2 (91) 86-91 (1991) Teichmillier M (1982) Origin of the petrographic constituents In Stachs textbook of coal petrology Stach E Mackowsky M Th Teichmller M and others (eds) Berlin Federal Republic of Germany Gebriider Borntraeger pp 219-294 (1982) Teyssler J (1988) Dependence of operating cost of a steam generator on inert content of the fuel Paper presented at Twentieth power plant technical colloquium Dresden Federal Republic of Germany 11-12 Oct 1988 Thielen W Odenthal H P Richter W (1987) Investigation of the influence of furnace geometry and coal properties on furnace perfonnance with the help of radiation transfer model In Fundamentals of the physical-chemistry of pulverised coal combustion Les Arcs France 28 Jul-1 Aug 1986 Dordrecht the Netherlands Martinus Nijhoff Publishers pp 424-436 (1987) Thompson A W Gibb W H (1988) Coal ash viscosity measurements on selected British coals as an aid to slagging propensity assessment In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 315-351 (1988) Tisch C Mancini R Sutton J Rini M (1990) Optimize p-c combustion to reduce carbon in fly ash Power 134 (12) 31-33 (Dec 1990) Tominaga H Sato M (1989) Development of a simulation for pulverised coal-fired boiler operation (part 4) evaluation of the FLUENT model Idemitsu Sekiyu Gijutsu 32 (1) 29-37 (1 Jan 1989) Truelove J (1985) Burners and flame stability In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle
114
References
NSW Australia University of Newcastle Institute of Coal Research pp 41-419 (May 1985) Tsai CoY Scaroni A W (1987) Reactivity ofbiturninous coal chars during the initial stage of pulverized-coal combustion Fuel 66 (10) 1400-1406 (Oct 1987) Ugursal V I AI Taweel A M (1990) A method for calculating the area requirement for power plant ash and FGD sludge disposal Journal of Coal Quality 9 (3) 87-90 (1990) Ugursal V I AI Taweel A M Mackay G D M (1990) Impact of coal quality on the cost of electrical power generation a technoeconomic model International Journal of Energy Research 14 (6) 683-699 (Aug 1990) Unsworth J F Barrett D J Roberts P T (1991) Coal quality and combustion performance an international perspective Amsterdam the Netherlands Elsevier Science Publishers 648 pp (1991) Vaninetti G E (1987) The importance of coal quality in marketing Journal of Coal Quality 6 (I) 5-7 (Jan 1987) Vernon J L (1989) Market impacts of sulphur control the consequences for coal lEACRlI8 London UK lEA Coal Research III pp (Oct 1989) Vernon J Soud H (1990) FGD installations on coal-fired plants lEACRl22 London UK lEA Coal Research 84 pp (Apr 1990) Vissar M Boysan F Weber R (1987) Computations of isothermal swirling vortices in the near burner zone Report on the MMF 1-1 investigation IFRF-F-336a9 Umiuden the Netherlands International Flame Research Foundation 179 pp (Iun 1987) Vitta P K Lowe S D Gallaspy D T Afonso R F Molino N M (1991) Application and validation of the coal quality impact model as part of the EPRI coal quality monitoring project In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 295-2117 (luI 1991) van Bush P Snyder T R Chang R L (1989) Determination of baghouse performance from coal and ash properties part II JAPCA Journal of the Air and Waste Management Association 39 (3) 361-372 (Mar 1989) Wagoner C L (1988) New opportunity to predict and verify effects of coal quality on the operation of heat exchangers through generic engineering In Reducing electricity generation costs by improving coal quality Indiana PA USA 5-6 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Information Services pp 61-626 (May 1988) Wain S E Livingston W R Sanyal A Williamson J (1992) Thermal and mechanical properties of boiler slags of relevance to sootblowing In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 459-470 (1992) Wall T F (1985a) Coal characterisation for combustion In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 11-119 (May 1985) Wall T F (1985b) Combustion of coal chars In An intensive course on the characterisation of steaming coals Newcastle
NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 51-529 (May 1985) Wall T F Wibberley L J McCol Stewart I (1985) The characterisation of steaming coals - limitations of the standard laboratory and pilot scale tests In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 111-1126 (May 1985) Walsh P M Beer J M Sarofun A F (1988) Estimation of aerodynamic effects on erosion of a tube by ash In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 219-234 (1988) Ward C P Pech J W Woodson H S (1988) Analytical model for coal combustion optimizing boiler operation through combustion control In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 Palo Alto CA USA EPRI Technical Information Services pp 621-629 (1988) Ward C R (1984) Chemical analysis and classification of coal In Coal geology and coal technology C R Ward (ed) Melbourne Vic Australia Blackwell Scientific Publications pp 40-73 (1984) Waters A G (1987) Implications of coal properties for thermal coal exports In Geology and coal mining conference Proceedings Sydney NSW Australia 13-15 Oct 1987 Sydney NSW Australia Geological Society of Australia Coal Geology Group pp AGWOI-AGW08 (1987) Wibberley L J (1985a) Effect of coal composition on deposit formation in PP fired boilers In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 91-918 (May 1985) Wibberley L J (1985b) Characterisation of coals for flyash and sulphur oxide emissions In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 71-715 (May 1985) Wibberley L J Wall T F (1986) An investigation of factors affecting the physical characteristics of fly ash formed in a laboratory scale combustor Combustion Science and Technology 48 177-190 (1986) Wigley F Williamson J Jones A R (1989) Slagging indices for UK coal and their relationship with mineral matter Fuel Processing Technology 24 (13) 383-389 (1989) Wollmann H-J (1990) Danger from residual coal content in hot fly ash VGB Krafiwerkstechnik - English Issue 70 (6) 404-408 (Iun 1990) Wright I G Williams D N Mehta A K (1988) Techniques to reduce fireside corrosion and fly ash erosion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 255-274 (1988) Wu E J Chen K Y (1987) Chemical form and leachability of inorganic trace elements in coal ash EPRI-EA-5115 Palo Alto CA USA EPRI Technical Information Services 202 pp (Iun 1987) Wu K T Payne R Li B Sheldon M (1990) Application of
115
References
engineering computer models and modeling techniques for evaluating boiler thermal performance and emissions control processes In Combustion modeling and burner replacement strategies ASMFIEEE joint power generation conference Boston MA USA 21-25 Oct 1990 New York NY USA American Society of Mechanical Engineers pp 1-8 (1990) Yancey H F Geer M R Price J D (1951) An investigation of the abrasiveness of coal and its associated impurities Mining Engineering 3 262-268 (1951) Yarkin E V Novikova I V (1988) Price as an incentive for improving quality of power fuel Eleckricheskie Stantsii (3) 8-11 (Mar 1988) Yavorskii I A Alaev G P Pugach L I Talankin L P (1968) Influence of the petrographic composition of coals on the efficiency of a pf fired boiler furnace Thermal Engineering (English translation of Teploenergetika) 15 (9) 108-113 (1968) Young R P DuBard J L Hovis L S (1989) Resistivity of fly ashlsorbent mixtures In Seventh symposium on the transfer and utilization ofparticulate control technology Nashville lN USA 22-25 Mar 1988 EPRI-GS-6208 Palo Alto CA USA EPRI Technical Information Services pp 11-115 (1989)
Zehner P (1989) Erfahrungen mit NOx-mindemden Massnahmen an Feuerungen grosser Dampferzeuger (Experience with combustion measures for NOx reduction at large steam generators) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Germany 26-27 Apr 1989 Essen Federal Republic of Germany VGB Kraftwerkstechnik GmbH pp 121-136 (1989) Zelkowski J Riepe W (1987) Generation of ash by hard coal power stations and problems of its utilization in the Federal Republic of Germany In Ash - a valuable resource Pretoria South Africa 1987 Pretoria South Africa Council for Scientific and Industrial Research vol 1 pp Bl-5 (1987) Ziesmer B C Barna L J Bull D L (1991) A utility perspective on western coals - operating experience and methods for screening potential fuel supplies In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 437-456 (Jul 1991) Zygarlicke C J Steadman E N Benoon S A (1990) Studies of transformations of inorganic constituents in a Texas lignite during combustion Progress in Energy and Combustion Science 16 (4) 195-204 (1990)
116
Appendix List of standards referred to in the report
American Society for Testing and Materials 1916 Race Street Philadelphia PA 19103 USA
D197-1987 Sampling and fineness test of pulverized coal
D291-1986 Cubic foot weight of crushed bituminous coal
D3172-1989
D3173-1987
D3174-1989
Proximate analysis of coal and coke
Moisture in the analysis sample of coal and coke
Ash in the analysis sample of coal and coke from coal
0409-1992 Grindability of coal by the Hardgrove-machine method
D3175-1989 Volatile matter in the analysis sample of coal and coke
D440-1986 Drop shatter test for coal D3176-1989 Ultimate analysis of coal and coke
D441-1986
D547-1941
D720-1991
Tumbler test for coal
Index of dustiness of coal and coke
Free-swelling index of coal
D3177-1989
D3178-1989
Total sulfur in the analysis sample of coal and coke
Carbon and hydrogen in the analysis sample of coal and coke
D1412-1989
D1756-1989
Equilibrium moisture of coal at 96 to 97 per cent relative humidity and 30D C
Carbon dioxide in coal
D3179-1989
D3286-1991
Nitrogen in the analysis sample of coal and coke
Gross CalOrifIC value of coal and coke by the isoperibol bomb calorimeter
D1857-1987 Fusibility of coal and coke ash D3302-1991 Total moisture in coal
D2015-1991 Gross calorific value of coal and coke by the adiabatic bomb calorimeter
D3682-1991 Major and minor elements in coal and coke ash by atomic absorption
D2361-1991
D2492-1990
D2795-1986
Chlorine in coal
Forms of sulfur in coal
Analysis of coal and coke ash
D3683-1978
D4326-1992
Trace elements in coal and coke ash by atomic absorption
Major and minor elements in coal and coke ash by X-ray fluorescence
D2798-1991 Microscopical determination of the reflectance of intrinite in a polished specimen of coal
D4749-1987 Performing the sieve analysis of coal and designating coal size
D2799-1992 Microscopical determination of volume per cent of physical components of coal
D5142-1990 Proximate analysis of the analysis sample of coal and coke by instrumental procedures
117
List of standards referred to in the report
Standards Association of Australia BS 1016 Part 6-1977 Ultimate analysis of coal 80-86 Arthur Street North Sydney NSW 2060 Australia
BS 1016 Part 8-1980 Chlorine in coal and coke
BS 1016 Part 11-1982 Forms of sulphur in coal
BS 1016 Part 12-1984 Caking and swelling properties of coal
BS 1016 Part 14-1979 Analysis of coal ash and coke ash
BS 1016 Part 15-1979 Fusibility of coal ash and coke ash
BS 1016 Part 17-1987 Size analysis of coal
BS 1016 Part 11-1990 Determination of the index of abrasion of coal
BS 1016 Part 20-1987 Determination of the Hardgrove grindability index of hard coal
BS 1016 Part 111-1990 Determination of abrasion index of coal
BS 6127 Part 3-1981 Petrographic analysis of bituminous coal and anthracite Part 3 Method of determining maceral group composition of bituminous coal and anthracite
BS 6127 Part 5-1981 Petrographic analysis of bituminous coal and anthracite Part 5 Method of determining microscopically the reflectance of vitrinite
Deutsches Institut rDr Normung eV Postfach 1107 1000 Berlin 30 Germany
DIN 22020 Part 3-1981 Mikroskopische Untersuchungen an Steinkohle Koks und Briketts Maceralanalyse an Komerschliffen (Microscopic method of analysing coal coke and briquettes maceral group analysis)
DIN 22020 Part 5-1981 Mikroskopische Untersuchungen an Steinkohle Koks und Briketts Reflexionsmessungen an Vitriniten (Microscopic method of analysing coal coke and briquettes measurement of the reflectance of vitrinite)
DIN 51 700-1967 Allgemeines und Ubersicht tiber Untersuchungsverfahren (General and overview of methods of analysis)
DIN 51 705-1979 Bestimmung der Schtittdichte (Determination of bulk density)
AS 1038 Parts 1-11
AS 1038 Part 1-1980
AS 1038 Part 3-1989
AS 1038 Part 5-1989
AS 1038 Part 6-1986
AS 1038 Part 8-1980
AS 1038 Part 11-1982
AS 1038 Part 121-1984
AS 1038 Part 141-1981
AS 1038 Part 15-1972
AS 1038 Part 17shy
AS 1038 Part 20-1981
AS 1038 Part 22-1983
AS 2486-1981
AS 2515-1981
AS 3381-1991
AS 3899-1991
Methods for the analysis and testing of coal and coke (metric units)
Total moisture in hard coal
Proximate analysis of hard coal
Gross specific energy of coal and coke
Ultimate analysis of coal
Chlorine in coal and coke
Forms of sulphur in coal
Determination of crucible swelling number of coal
Analysis of coal ash coke ash and mineral matter (borate fusion-flame atomic absorption method)
Fusibility of coal ash and coke ash
Size analysis of hard coal
Determination of Hardgrove Grindability Index of hard coal
Determination of mineral matter and water of hydration of minerals in coal
Microscopical determination of the reflectance of coal macerals
Determination of the maceral group composition of bituminous coal and anthracite (hard coal)
Size analysis of hard coal
Higher rank coals and coke - bulk density
British Standards Institution Sales Office Linford Wood Milton Keynes MK14 6LE UK
BS 1016 Parts 1-20
BS 1016 Part 1-1989
BS 1016 Part 3-1973
BS 1016 Part 5-1977
Methods for the analysis and testing of coal and coke
Total moisture of coal
Proximate of analysis coal
Gross calorific value of coal and coke
118
Appendix
DIN 51 717-1967
DIN 51 718-1978
DIN 51 719-1978
DIN 51 720-1978
DIN 51 721-1950
DIN 51 722shy
DIN 51 724-1975
DIN 51 726-1980
DIN 51 727-1976
DIN 51 729shy
DIN 51 730-1976
DIN 51 741-1974
DIN 51900shy
Bestimmung der Trommelfestigkeit und des Abriebs von Steinkohlenkoks (Detennination of abrasion indexdrum strength and abrasion of hard coal coke)
Bestimmung des Wassergehaltes (Detennination of water content)
Bestimmung des Aschegehaltes (Detennination of ash content)
Bestimmung des Gehaltes an Fliichtigen Bestandteilen (Detennination of volatile matter content)
Bestimmung des Gehaltes an Kohlenstoff und Wasserstoff (Detennination of content of carbon and hydrogen)
Bestimmung des Stickstoff-Gehaltes (gilt nur fur Kohlen) (Detennination of nitrogen (for coal only)
Bestimmung des Schwefelgehaltes Gesamtschwefel (Part 1 Detennination of sulphur content and total sulphur)
Bestimmung des Gehaltes an Carbonat-Kohlenstoff-dioxid (Detennination of content of carbonate carbon dioxide)
Bestimmung des Chlorgehaltes (Detennination of chlorine content)
Bestimmung der chemischen Zusammensetzung von Brennstoffasche (Detennination of chemical composition of fuel ash)
Bestimmung des Asche-Schmelzverhaltens (Detennination of ash melting behaviour)
Bestimmung der BHihzahl von Steinkohle (Determination of swelling capacityindex)
Priifung fester und fliissiger Brennstoffe Bestimmung des Brennwertes mit dem Bomben-Kalorimeter und Berechnung des Heizwertes (Testing of solid and liquid fuels detenninationlanalysis of the
heating value by bomb-calorimeter and calculation of the heating value)
Teil 2 - 1977 Verfahren mit isothermem Wassermantel (Part 2 Methods with isothermal water jacket)
Teil 3 - 1977 Verfahren mit adiabatischem Mantel (Part 3 Methods with adiabatic jacket)
International Organization for Standardization Casa Postale 56 CH 1211 Geneva 20 Switzerland
ISO 157-1975
ISO 331-1983
ISO 332-1981
ISO 334-1975
ISO 352- 1981
ISO 501-1981
ISO 540-1981
ISO 562-1981
ISO 589-1981
ISO 602-1983
ISO 625-1975
ISO 925
ISO 1018-1975
ISO 1171-1981
Hard coal - Detennination of forms of sulphur
Coal - Detennination of moisture in the analysis sample - Direct gravimetric method
Coal - Detennination of nitrogen shyMacro Kjeldahl method
Coal and coke - Detennination of total sulphur - Eschka method
Solid mineral fuels shyDetennination of chlorine - High temperature combustion method
Coal - Detennination of the crucible swelling number
Solid mineral fuels shyDetennination of fusibility of ash shyHigh temperature tube method
Hard coal and coke shyDetennination of volatile matter content
Hard coal - Detennination of total moisture
Coal - Detennination of mineral matter
Coal and coke - Detennination of carbon and hydrogen - Liebig method
Coal - Determination of carbon dioxide
Hard coal - Detennination of moisture-holding capacity
Solid mineral fuels shyDetennination of ash
119
List of standards referred to in the report
ISO 1921-1976
ISO 1953-1972
ISO 1994-1976
ISO 5074-1980
Solid mineral fuels shyDetermination of gross calorific value by the calorimeter bomb method and calculation of net calorific value
Hard coals - Size analysis
Hard coal - Determination of oxygen content
Hard coal - Determination of Hardgrove grindability index
ISO 7404 Part 3-1984
ISO 7404 Part 5-1984
Methods for the petrographic analysis of bituminous coal and anthracite Part 3 Method of determining maceral group composition
Methods for the petrographic analysis of bituminous coal and anthracite Part 5 Method of determining microscopically the reflectance of vitrinite
120
Related publications
Further lEA Coal Research publications on coal utilisation are listed below
Advanced coal cleaning technology G R Couch IEACRl44 ISBN 92-9029-197-4 95 pp December 1991
Power station refurbishment opportunities for coal D H Scott IEACRl42 ISBN 92-9029-195-8 58 pp October 1991
On-line analysis of coal A T Kirchner IEACR140 ISBN 92-9029-193-1 79 pp September 1991
Coal gasification for IGCC power generation Toshiishi Takematsu Chris Maude IEACR137 ISBN 92-9029-190-7 80 pp March 1991
Lignite upgrading G R Couch IEACRl23 ISBN 92-9029-176-172 pp May 1990
Power generation from lignite G R Couch IEACRl19 ISBN 92-9029-170-2 67 pp December 1989
Lignite resources and characteristics G R Couch IEACRl13 ISBN 92-9029-163-X 100 pp December 1988
Coal-fired MHD G F Morrison IEACRl06 ISBN 92-9029-151-6 32 pp April 1988
Biotechnology and coal G R Couch ICTISfTR38 ISBN 92-9029-147-8 56 pp March 1987
Understanding pulverised coal combustion G F Morrison ICTISfTR34 ISBN 92-9029-138-9 46 pp December 1986
Atmospheric f1uidised bed boilers for industry I F Thomas ICTISfTR35 ISBN 92-9029-136-2 69 pp November 1986
All reports are priced at pound60pound180 (membernon-member countries)
Other lEA Coal Research pUblications Details of lEA Coal Research publications are available from
Reviews assessments and analyses of supply transport and markets lEA Coal Research coal science Gemini House coal utilisation 10-18 Putney Hill coal and the environment London SW15 6AA
United Kingdom Coal abstracts Coal calendar Tel (0)81-7802111 Coal research projects Fax (0)81-7801746
lEA Coal Research
lEA Coal Research was established in 1975 under the auspices of the International Energy Agency (lEA) and is currently supported by fourteen countries (Australia Austria Belgium Canada Denmark Finland Germany Italy Japan the Netherlands Spain Sweden the UK and the USA) and the Commission of the European Communities
lEA Coal Research provides information and analysis of all aspects of coal production and use including
supply transport and markets coal science coal utilisation coal and the environment
lEA Coal Research produces
periodicals including Coal abstracts a monthly current awareness journal giving details of the most recent and relevant items from the worlds literature on coal and Coal calendar a comprehensive descriptive calendar of recently-held and forthcoming meetings of interest to the coal industry technical assessments and economic reports on specific topics throughout the coal chain bibliographic databases on coal technology coal research projects and forthcoming events and numerical databanks on reserves and resources coal ports and coal-fired power stations
General enquiries about lEA Coal Research should be addressed to
Mr John Trubshaw Head of Service lEA Coal Research Gemini House 10-18 Putney Hill London SW 15 6AA United Kingdom
Telephone (0)81-780 2111 Fax (0)81-7801746
3
Abstract
This report examines the impacts of coal properties on power station perfonnance As most of the coal used to generate electricity is consumed as pulverised fuel the focus of the report is on performance in pulverised fuel (PF) power station units The properties that are currently employed as specifications for coal selection are reviewed together with their influence on power station performance Major coal-related items in a power station are considered in relation to those properties which affect their performance There is a review of tools being used for coal selection and prediction of station performance which includes an overview of the types of computer models that are available and those that are being developed
The principal coal properties that were found to cause greatest concern to operators included the ash sulphur moisture and volatile matter contents heating value and grindability Little has changed over the years in the way that coal is assessed and selected for combustion Operators continue to use tests as specifications that were mostly developed for coal uses other than combustion Because the procurement specifications are based on tests which do not relate well to actual practice there is still a need for expensive large scale test burns to confIrm suitability With the advances that have been made in computer technology there is a growing number of utilities that are adopting expert unit or integrated models that aid in the planning and operation of generating units Others have shown scepticism over the capability of devising a truly representative model of a coal combustion plant using the coal data produced from current testing procedures
Specific requirements that have been identified include the need to develop internationally acceptable methods of defining coal characteristics so that combustion plant perfonnance can be predicted more effectively There is also a need to establish economic parameters which can serve to measure the effects of coals on plant performance and hence on the cost of electricity
4
Contents
List of figures 7
List of tables 9
Acronyms and abbreviations 11
1 Introduction 13 11 Background 13
2 Coal specifications 15 21 Proximate analysis 17 22 Ultimate analysis of coal 20 23 Ash analysis and minerals 21 24 Forms of sulphur chlorine and trace elements 23 25 Coal mechanical and physical properties 23 26 Calculated indices 28 27 Comments 28
3 Pre-combustion performance 29 31 Coal handling and storage 29
311 Plugging and flowability 32 312 Freezing 34 313 Dusting 35 314 Oxidationspontaneous combustion 36
32 Mills 37 321 Drying 37 322 Grinding 38 323 Size classification and transport 42
33 Fans 42 34 Comments 45
4 Combustion performance 46 41 Burners 46 42 Steam generator 47
421 Combustion characteristics 47 422 Ash deposition 49
43 Comments 56
5
5 Post-combustion performance 57 51 Ash transport 57 52 Environmental control 58
521 Coal cleaning 59 522 Fly ash collection 60 523 Technologies for controlling gaseous emissions 63 524 Solid residue disposal 65
53 Comments 67
6 Coal-related effects on overall power station performance and costs 68 61 Capital costs 68 62 Cost of coal 68 63 Power station perfonnance and costs 69
631 Capacity 69 632 Heat rate 69 633 Maintenance 74 634 Availability 76
64 Comments 77
7 Computer models 79 71 Least cost coalcoal blend models 80 72 Component evaluation models 81 73 Unit models 82
731 Statistically-derived regression models 82 732 Systems engineering analysis 88 733 Integrated site models 97
74 Comments 99
8 Conclusions 101
9 References 104
Appendix List of standards referred to in the report 117
6
Figures
Schematic diagram of the coal-to-electricity chain 14
8 Three-day consolidation critical arching diameter (CAD)
18 Influence of ash characteristics of US coals on
23 Resistivity results for both power station fly ash and
2 Comparison of different coal classification systems 18
3 Mill throughput as a function of Hardgrove grindability index 24
4 Critical temperature points of the ash fusion test 25
5 Typical power station components 29
6 Typical flow patterns in bunkers 32
7 Surface moisture versus critical arching diameter (CAD) determined from shear tests 33
versus per cent fines in coal as a function of moisture content 33
9 Dewatering efficiency versus temperature 34
10 Size distributions of Australian export coal 35
11 Coal lift-off from a stockpile as a function of total moisture content 35
12 Influence of storage time on swelling index 37
13 Primary air temperature requirements depending on moisture content and coal type 39
14 Variation in capacity factor with HGI for different fineness grinds 40
15 HGI for several coals as a function of rank 41
16 Typical utility boiler fan arrangement 43
17 Fuel ratio as an indicator of coal reactivity 48
furnace size of 600 MW pulverised coal fired boilers 49
19 Mechanisms for fly ash formation 50
20 Heat flux recovery for different coals and soot blowing cycles 52
21 Effect of CaO and MgO on corrosivity deposit 53
22 Typical ash distribution 58
laboratory ash from Tallawarra power station feed coal 62
7
24 Laboratory resistivity curves of ash from a South African coal and from a blend of South African and Polish coals against temperature 62
25 Effects of grindability on vertical spindle pulveriser performance 72
26 Example of cost impact of a coal change on heat rate for a 1000 MW boiler 74
27 Adjusted maintenance cost accounts for TVAs Cumberland plant 75
28 Causes of coal-related outages 76
29 Boiler and boiler tubes equivalent availability factor (EAF) record 77
30 Mill engineering model analysis approach 82
31 Comparison of TVA and EPRI availability correlations to a 1000 MW boiler 85
32 Comparison of ash and H20 effects on boiler efficiency and gross heat rate 86
33 Outline of CIVEC model operation 87
34 CQEA evaluation of the impact of different coals on overall production costs of one unit 92
35 Equipment types modelled by CQIM 92
36 Major components of the CQE system 94
37 Correlations of forced outage hours against ash throughput using the CQI model 95
38 Schematic showing the structure of the C-QUEL system 97
39 Comparison of the operations with and without the use of the C-QUEL 98
8
5
10
15
20
25
Tables
1 Summary of coal quality requirements for power generation 16
2 Coal composition parameters standard measurements 17
3 Analysis of a given coal calculated to different bases 18
4 Rank and coal properties 19
Minerals in coal 22
6 Coal mechanical and physical parameters standard measurements 24
7 A summary of the major characteristics of the three maceral groups in hard coals 25
8 Summary of coal ash indices 26
9 lllustrative example of USA coal storage requirements 30
Conveyor Equipment Manufacturers Association (CEMA) material classification chart 31
11 CEMA codes for various coals 32
12 Analysis of ash and clay distribution in a coal by mesh size 33
13 Effect of coal properties on critical lift-off moisture content 35
14 Preferred range of coal properties 37
Maximum mill outlet temperatures for vertical spindle mills 38
16 Comparison of fineness recommendations 38
17 Summary of the effects of coal properties on power station component performance - I 44
18 Enrichment of iron in boiler wall deposits shycomparison of composition of ash deposits and as-fired coal ashes 52
19 Hardness of fly ash constituents 54
Properties of some coal ash components 54
21 Summary of the effects of coal properties on power station component performance - II 56
22 Summary of coal cleaning effects on boiler operation 59
23 Effect of coal type on total concentrations of selected elements from fly ash samples 65
24 Summary of the effects of coal properties on power station component performance - III 66
The effect of coal quality on the costs of a new power station 68
9
26 Ash contents of traded coals 69
31 Examples of boiler frreside variables station and cost
33 Comparison of coal energy costs based on gross heating
27 Calculation of boiler heat losses 70
28 Typical boiler losses for four Australian Queensland steaming coals 71
29 Total fuel costs for power stations of the Southern Company USA 75
30 Comparison of reduced boiler availability on the basis of hours in operation and type of fuel 76
components which may be affected by those variables when coal quality is changed 78
32 Model input output data - International Coal Value Model (ICVM) 80
value (at power station pulverisers) - in order of increasing cost 80
34 Boiler groupings in TVA study 83
35 TVA study - maintenance costs plant correlations for all coal-related equipment 84
36 NERA study - gross heat rate correlation 85
37 ClVEC coal specifications input 88
38 ClVEC power station operational parameters 89
39 ClVEC factors contribution to utilisation value 89
40 Model input output data - COALBUY 90
41 Model input output data - Coal Quality Advisor (CQA) 90
42 Model input output data - Coal Quality Engineering Analysis (CQEA) 91
43 Model input output data - Coal Quality Impact Model (CQIM) 93
44 Ranges of selected coal-ash combustibility parameter that predict approximate classification of CF values 94
45 Model input output data - IMPACT 95
46 Assessment of four coals for Fusina unit 3 using the CQI model 96
47 Summary of model types and capabilities 99
48 Summary of the impacts of coal quality on power station performance 102
10
Acronyms and abbreviations
ad AP ARA ASTM BSl Btu CAD CCSEM CEMA CGI cif CPampL CQA CQEA CQE CQIM CSIRO daf DIN dmmf DTF EEl EFR EPRl ESP FD FEGT FFV FGD FGET FGR fob FTIR GADS GHR GP HGI HLampP HR
air-dried auxiliary power Acid Rain Advisor American Society for Testing and Materials British Standards Institution British thermal unit critical arching diameter computer controlled scanning electron microscopy Conveyor Equipment Manufacturers Association continuous grindability index cost insurance freight Carolina Power and Light Company Coal Quality Advisor Coal Quality Engineering Analysis Coal Quality Expert Coal Quality Impact Model Commonwealth Scientific and Industrial Research Organisation (Australia) dry ash-free Deutsches Institut rur Normung (Germany) dry mineral matter-free drop tube furnace Edison Electric Institute (USA) entrained flow reactor Electric Power Research Institute (USA) electrostatic precipitator forced draft furnace exit gas temperature flow factor value flue gas desulphurisation flue gas exit temperature flue gas recirculation free on board Fourier transform infrared Generating Availability Data System (USA) gross heat rate gross power Hardgrove grindability index Houston Lighting amp Power Company (USA) heat rate
11
ICVM ill IEEE IFRF ISO LCFS kWh MCR MJlkg MWe MWh NERA NERC NHR nm NOx
NYSEG OGampE OampM PA PF PGNAA PN PP ppm ROM SCR SNCR TGA THR TVA UDI UK USA US DOE
International Coal Value Model induced draft Institute of Electronic and Electrical Engineers (UK) International Flame Research Foundation (The Netherlands) International Organization for Standardization Least cost fuel system kilowatt hour maximum continuous rating megajoule per kilogram megawatt (electrical) megawatt hours National Economic Research Associate (USA) North American Electric Reliability Council (USA) net heat rate nanometres nitrogen oxides New York State Electric amp Gas Company (USA) Oklahoma Gas amp Electric Company (USA) operation and maintenance primary air pulverised fuel Prompt Gamma Neutron Activation Analysis Polish Standards Committee Pacific Power parts per million run-of-mine selective catalytic reduction selective non-catalytic reduction thermal gravimetric analysis turbine heat rate Tennessee Valley Authority (USA) Utility Data Institute (USA) United Kingdom United States of America United States Department of Energy
12
1 Introduction
This report examines the impacts of coal properties on power stations buming pulverised fuels (PF) The properties that are currently examined when defining specifications for coal selection are reviewed together with their influence on power station performance The main power station components are considered in relation to those coal properties which affect their performance There is a review of tools being used for coal selection and prediction of station performance which includes an overview of the types of computer models that are both available and under development
In support of the study lEA Coal Research conducted a survey by questionnaire of power stations in 12 countries to obtain additional information about utility practice and experience of the effects of coal quality on power station performance The responses of station operators and research specialists to the questionnaire were of considerable value and much appreciated
11 Background Utilities are continually striving to produce power at the lowest possible cost This means that power stations must operate at optimal availability and rated output while maintaining efficient operation and maintenance schedules At the same time they must also meet relevant emission requirements
Operators of coal-frred stations have long known that coal composition and characteristics signifIcantly affect operation on a broad front Because a power station is a complex interrelated system a change in one area such as coal quality can reverberate throughout the whole system Figure 1 shows a schematic diagram of the coal-to-electricity chain To generate electricity to the busbar at minimum cost it is necessary to evaluate the total cost associated with each coal This includes the cost of any coal-related effects on the performance and availability of
power station components as indicated by Sections 4-7 in Figure 1 in addition to the delivered cost of the coal It is estimated that coal quality factors can contribute up to 60 of all unscheduled outages of coal-fired stations (Mancini and others 1988)
In some cases utilities have the opportunity to fire a range of coals in their power stations In general power stations have a design coal analysis with which initial performance guarantees are met It is also usual to have an allowable range for the most important coal properties within which it is expected that full load may be produced although possibly at reduced efficiencies Substantial deviations in one or more of the properties may result in impaired plant performance or even serious operating and maintenance problems
The quality of coal supplied to a power station may vary for many reasons including
typical day-to-day seam variations in individual coals longer term variations in coal quality due to seam depletion andor change of mining method inconsistencies due to inadequate preparation or poor quality control at the mine site variation in proportions of coals supplied from several traditional supply sources replacement of traditional supplies with sources with different properties due to changing availability or price switchinglblending requirements to meet changing emissions regulations intentional change of fuel quality to solve existing performance problems heavy reliance on recoveries from old stockpiles effects of weather
In order to select a coal supply utilities must try to predict the impacts of alternative coals on power station performance and overall power generation costs Since the type and design of boiler and auxiliary equipment are fixed the coal is
13
6
Introduction
PREPARATION PLANT TRANSPORTMINE
2 3
Figure 1 Schematic diagram of the coal-ta-electricity chain
usually selected to match these rather than the reverse There are numerous methods employed to help select an appropriate coal These can range from selecting coals on the basis of a limited number of design specifications based on proximate analysis through use of sophisticated computer models describing overall performance to expensive full
4 5
HANDLING AND MILLING
STORAGE
PARTICULATES REMOVAL - COMBUSTION~ bull
6B FGD
6C
WASTE DISPOSAL
9
ADDITIONAL UNIT
GENERATION CAPACITY
STEAM 7TURBINE
ELECTRICITY TO 8BUSBAR
scale test firing of sample loads over a limited time period It is recognised that a wide range of complex physical and chemical processes occur during preparation and combustion and so it is not surprising that these methods may still prove to be inadequate in providing a quantitative understanding of the impacts of coal quality
14
2 Coal specifications
The criteria for including particular properties of a coal in a specification used for a particular power station are varied Basic coal contracts can include as few as three or four base quality guarantees - stipulating a range of values for heating value ash content moisture and more recently sulphur More typical purchasing specifications incorporate additional properties such as volatile matter fixed carbon ash fusion temperatures grindability along with the base level specifications of heating value ash moisture and sulphur (Schaeffer 1988) More recently these have been expanded by some utilities to include trace element details and the petrographic composition of the coal Table 1 summarises the typical coal quality requirements for power generation The specification values indicated are derived from both the literature and analysis of the results obtained from the survey of boiler operators
Most of the properties described in Table 1 are measured using relatively simple standard tests More recently some coal specifications have emerged which appear even more complex and restrictive In addition to the standard characterisation tests they may include non-standard characterisation and combustion tests such as the use of thermal gravimetric analysers drop-tube furnaces and pilot-plant tests (see Section 42) It has been argued that such detailed specifications are not necessary (OKeefe and others 1987) may be excessively restrictive and could lead to increasing fuel cost as specific sources are no longer available (Mahr 1988 Harrison and Zera 1990) The advocates for detailed specifications argue that to use only a basic fuel specification for selection will leave the market open for many coals which may not perform as well as the design-specification coal (Vaninetti 1987 Myllynen 1987) They will most likely be attractively priced (Corder 1983 OKeefe and others 1987) but there is no assurance that the saving will necessarily minimise the overall cost of power generation In many cases buying the coal of lowest price can be false economy (see Chapter 6) for example if the coal adversely affects heat rate additional coal will be
needed If the selected coal cannot sustain full unit capacity or causes additional outages (availability loss) alternative units must be operated to make up the lost power possibly at considerable additional cost Also increased maintenance costs add directly to the total cost of power generation (Folsom and others 1986a Sotter and others 1986 Yarkin and Novikova 1988 Ziesmer and others 1991 Bretz 1991a)
Blending to meet quality specifications is gaining acceptance In most cases power stations do not fire only coal from a single seam in their boilers As coal occurs in heterogeneous deposits the supply from any mine is already a blend of material from different seams to meet the required specification This principle may be extended such that coals supplied to power stations can be blends from several different sources prepared at handling centres such as at Rotterdam The Netherlands (Rademacher 1990) Power stations themselves may have facilities for blending two or more coals on site Separately the coals may not meet specification but a homogeneous mix does (Ratt 1991) Most countries which depend solely on imported coals have commercial strategies stipulating that no single source should account for more than 40 of supply (Klitgaard 1988) Blending which extends the range of acceptable coals increases the number of supply opportunities It should be noted that the non-additive nature of some of the standard tests such as ash fusion tests and use of HGI values (see Section 25) makes blend evaluation for power station use inherently complex (Riley and others 1989)
The following sections examine the coal properties used in coal specifications and evaluate their significance in power station operation
Table 2 lists eighteen standard methods of measuring coal composition together with an indication of the relevance of the results to the utility industry As illustrated in Table 2 the key measurement methods are proximate analysis
15
Coal specifications
Table 1 Summary of coal quality requirements for power generation
Parameter Desired Typicallimits
Heating value (ar) MJkg high min 24-25 (23) Proximate analysis - Total moisture (ar) 4-8 max 12
- Ash (mt) low max 15-20 (max 30) - Volatile matter (rot) 20-35 min 20 (23) - side-fIred furnaces
15-20 max 20 - down-fIred pf furnaces Total sulphur (mt) low max 05-10 - dependent on local pollution regulations
Hardgrove grindability index (HGI) high
Maximum size mm 130-40 Fines less than 05 mm (15 max)
Proximate analysis Ultimate analysis
Chlorine (rot)
Ash analysis weight of ash
Ash fusion temperatures degC
Swelling index Ash resistivity Handleability
Trace elements
Vitrinite reflectogram
Maceral analysis
- Fixed carbon (rot) - Carbon (daf)
- Hydrogen (daf)
- Nitrogen (dat) low - Sulphur (dat)
- Oxygen (by diff daf) low
Silicon dioxide (Si02) Aluminium oxide (Ah03) Titanium oxide (Ti02) Ferric oxide (Fe203) Calcium oxide (CaO) Magnesium oxide (MgO) Sodium oxide (Na20) Potassium oxide (K20) Sulphite (SOn Phosphorus pentoxide (P20 S)
- initial deformation high - softening (H = W) high - hemispherical (H =lizW) high - fluid high
low ohmem at 120degC
As Cd Co Cr Cu
Hg Ni Pb Sb Se Tl Zn
Vitrinite Exinite Inertinite Mineral
min 50-55 (min 39) 50 limited by size accepted by pulveriser
limited for handling characteristics
(08-11)
max 01--03 (max 05)
(45-75) (15-35) (04-22) (1-12) (01-23) (02-14) (01--09) (08-26) (01-16) (01-15)
(gt1075) in reducing conditions (gt1150) for dry bottom furnaces (gt1180) Values are much lower for wet bottom (gt1225) furnaces
(max 5) if available if available
Declaration of presence
if available
55-80 5-15 10-25 to declare
Typical limits refer to those commonly quoted those in brackets indicate outer limits acceptable in some cases
Measurement basis ar shy as received mf - moisture free daf - dry ash-free
16
Coal specifications
Table 2 Coal composition parameters standard measurements (after Folsom and others 1986c)
Measurement Method Standards procedure
ASTM AS BS DIN ISO
Parameters measured
Relationship to power station performance
Proximate analysis 03172-89 Moisture D3173-87 Volatile matter D3175-89 Ash D3174-89 Fixed carbon
Ultimate analysis 03176-89 Oxygen Carbon 03178-89 Hydrogen 03178-89 Nitrogen 03179-89 Total sulphur 03177-83
10383-89 10383-89 10383-89 10383-89 10388-89
10386-86
103861-86 103861-86 103862-86 103863-86
10163-73 10163-73 10163-73 10163-73 10163-73
10166-77 10166-77 10166-77 10166-77 10166-77 10166-77
51700-67 51718-78 51720-78 51719-78
51700-67
51721-50 51721-50 51722 517241-75
331-83 562-81 1171-81
1994-76 625-75 625-75 332-81 334-75
H20 Ash VM FC
Part of proximate analysis
C H 0 N S Ash H2O
) Pm of 1_ analysis
These parameters affect all power station systems since they are the principal constituents of coal
Ash analysis D2795-89 AA-Elemental ash analysis Major 03682-87 AA-Elemental ash
1038141-81
1038141-81
101614-79
101614-79
51729-80
analysis Trace 03683-78 Mineral matter C02 in coal D1756-89 Forms of sulphur D2492-90 Chlorine D2361-91 Total moisture D3302-89 Equil moisture D1412-89
1038104-86 103822-83 103823-84 103811-82 10388-80 10381-80 103817-89
10166-77 101611-87 10168-84 10161-89 101621-87
51726 517242 51727-76 51718
602-83 925-80 157-75 352-81 589-81 1018-75 Surface moisture
Corrosion slagging fouling
Handling amp pulverisation
Proximate analysis by instrumental procedures D5142-90
AA Atomic Adsorption ASTM American Society for Testing and Materials AS Australian Standards
BS British Standards Institution DIN Deutsches Institut fur Normung ISO International Organization for Standardization
ultimate analysis and ash analysis Additionally other early 1800s at a time when carbonisation was the most chemical analyses are often carried out on coal samples important use of coal It was a means of broadly assessing Some of these tests are used to enable correction of the bulk distribution of products obtainable from a coal by proximate and ultimate analysis data to allow for mineral destructive distillation (Elliott 1981) It is widely accepted matter constituents while others are used to evaluate the by the utility industry and forms the basis of many coal coals suitability for specific purposes In most coal qualitypower station performance correlations The great producing and consuming countries national or international advantage of the tests required for proximate analysis is that standard techniques are used The titles of the standards they are all quite simple and can be performed with basic reported in this chapter and the addresses of the standards laboratory equipment So much so that they have been fully organisations are given in the Appendix automated in recent years The results of proximate analysis
although endorsed with long history and extensive Common causes of confusion in the comparison of coal and experience are empirical and only applicable if the tests are interpretation of analytical data as reviewed by Carpenter carried out under strict standardised conditions The five (1988) are characteristics obtainable from the procedure are
the different domestic and international coal total moisture classification schemes used (see Figure 2) air-dried moisture the wide range of analytical bases on which the coal data volatile matter may be reported and the failure of many workers to ash identify clearly the basis for their results Table 3 fixed carbon illustrates how results will vary for a single coal depending on the base used Proximate analysis reports moisture in only two categories
as total and air-dried although it actually occurs in coals in different forms Air-dried moisture is also referred to as21 Proximate analysis inherent moisture The total moisture of coal consists of
The proximate analysis of coal is the simplest and most surface and inherent moisture Surface moisture is the common form of coal evaluation It was introduced in the extraneous water held as films on the surface of the coal and
17
----- ---
---
01
Coal specifications
Volatile Australia
301a
302
303
301b 302 303
401-901 high volatile A bituminous
402-702 coal402 class 7 Ihigh volatile B bituminous
coal 902 high volatile
class ~inouscoal
I subbituminousclass subbituminous
B coal 11 A coal subbituminous
class ~
approximate C coal 12 volatile matter
f-- shy dmmf lignite A class class 6 32-40
13 class 7 32-43 class 8 34-49
class ~
class 9 41-49
-14 lignite B
class
-15
matter dmmf
2 6 8 9
10 115 135
14 15 17
195 20 22 24
275 28 31 32 33
36
44J
47J
Great Britain NCB
101 anthracite
102
201a dry Ol ~~ 201b I~~~I~ COcgt
202 ~EgE- co co ~co203 -OlO 02 -en8en t)204
FRG
meta-anthracite
anthracite
lean (non-caking)
coal
forge coal
fat (coking) coal
hard coals
gas coal
tgas flame coal
flame coal
shiny hard
brown coal
matt
soft brown coal
MJkg class 6 326
class 7
302 class 8
class 9 -256
- 221 soft
193 brown coals
147
Heating value MJkg
N S
173 131
179 136
198 151
gross net
3168 3067
3279 3175
3635 3520
-
medium volatile coals
30shy
40shy
50shy
60shy
70shy
International hard coals
class 0
class 1A
class 1B
class 2
class 3
class 4
hardclass 5 coals
class 6 moi sture
high ~ f 0Yo
brown coals
volatile I coals
and I
I~ class 8
-1Q class 9- - 20shy
North America ASTM
Imeta-anthraciteI
anthracite
semi-anthracite
low volatile bituminous
coal
medium volatile
bituminous coal
Calorific value mmmf
hard coals
class 1
class 2
class 3
class 4A
class 4B
hardclass 5 coals
Figure 2 Comparison of different coal classification systems (Couch 1988)
Table 3 Analysis of a given coal calculated to different bases
Condition or basis
Proximate analysis
H2O VM FC Ash
Ultimate analysis
C H 0
As received 339 2061 6653 947 7729 459 561
Dry 2133 6887 980 8000 436 269
Dry ash-free 2365 7635 8869 483 299
Analysis of US Pennsylvania Somerset County Upper Kittaning Bed No 3 Mine
In the ultimate analysis moisture on an as received basis is included in the hydrogen and oxygen Net heating value is calculated from the gross value using the relationship in ISO 1928
its content can vary in a coal over time The moisture present water is difficult to control separate assessment of inherent in other forms is regarded as the inherent moisture it is or air-dried moisture is also necessary as most other more or less constant for coals of a given rank (Ward 1984) analyses are carried out on air-dried material
A coal that is sold commercially usually contains a certain Surface moisture is important to the handleability of coal amount of surface moisture which forms part of the total (see also Section 31) With a content greater than 12 of weight of coal delivered Knowledge of the total moisture the coal weight problems such as bridging in bunkers and content of the coal is therefore essential to assess the value of blocking of feeders can be expected in the transport system any consignment However because the amount of surface (Cortsen 1983) In cold climates the excess surface moisture
I
18
Coal specifications
may freeze and act as a binder so incurring coal handling problems (Raask 1985)
Extremely low surface moisture content can cause environmental problems due to dust and enhanced risks of fire due to coal oxidation which causes heating and may lead to spontaneous combustion especially in low rank coals (see
also Sections 313 and 314)
Surface moisture and part of the inherent moisture of a coal can be released in the mills during grinding This means that the mill inlet or primary air temperature prior to milling must be increased for coals with a high total moisture content The surface moisture of the coal is converted to vapour during milling and forms part of the coal-air mixture in direct feed systems The vapour enters the furnace where it can cause a delay in coal ignition and increase flame length The effect however is small for coals with moisture contents not exceeding 10
The inherent moisture has a more direct influence on coal ignition and combustion Significant gasification of the coal particle to release combustible gases cannot start prior to the evaporation of the moisture from within the particle When firing a coal with a high inherent moisture content conditions can also be improved by increasing mill air inlet temperature
Total moisture in the coal contributes to the overall gas flow in the form of vapour (Cortsen 1983) This can influence the operation of fans that move the air flue gas and pulverised coal through the unit An increase in coal moisture will increase the flue gas volume flow rate thus necessitating an increased power requirement for the fans (see Section 33)
During the combustion process coal releases volatiles which include various amounts of hydrogen carbon oxides methane other low mOlecular weight hydrocarbons and water vapour Volatile yield of a coal is an important property providing a rough indication of the reactivity or combustibility of a coal and ease of ignition and hence flame stability The amount of volatiles actually released in practice is a function of both the coal and its combustion conditions including sample size particle size time rate of heating and maximum temperature reached In order to obtain a method for comparing coals a simple test was devised to obtain a value for the volatile matter content of a coal The volatile matter content as determined by proximate analysis represents the loss of weight corrected for moisture when the coal sample is heated to 900degC in specified apparatus under standardised conditions
Typical values of volatile matter content associated with different ranks of coal as determined by proximate analysis are given in Table 4 (Cunliffe 1990) It should be noted that some of the volatile matter may originate from the mineral matter present
The volatile matter content of a coal is used to assess the stability of the flame after ignition Under the same combustion conditions that is same burner configuration and amount of excess air a coal with a high volatile matter content will usually give stable ignition and a more intensive
Table 4 Rank and coal properties (Cunliffe 1990)
Type C H 0 Volatile Heating
(composition ) matter value daf MJkg
Wood 500 60 430 800 146
Peat 575 55 350 684 159
Lignite 700 50 230 526 216
Bituminous High volatile 770 55 150 421 258
Medium volatile 860 50 45 263 335
Low volatile 905 45 30 188 348
Semi-anthracite 905 45 30 188 348
Anthracite 940 30 15 41 346
daf dry ash-free basis
flame compared with a coal with a low volatile matter content Maintaining stable ignition is one of the most crucial aspects of pulverised coal firing since instability necessitates the use of pilot fuel and in extreme cases may incur the risk of furnace explosion (Cortsen 1983) Low laquo20) volatile matter coals can produce high-carbon residue ash In order to combat this adverse effect the coal would require extra-fine milling and combustion in boilers with a long flame path (Raask 1985) A high volatile matter content (gt30) can cause mill safety problems This is due to the increased possibility of mill fires resulting from spontaneous combustion of the coal (see Section 32) Volatile matter content values are often used to calculate combustibility indices which are used as an indication of the reactivity of a coal They are also included in formulae for the prediction of NOli release during coal combustion (Kok 1988)
Ash is the residue remaining following the complete combustion of all coal organic material and oxidation of the mineral matter present in the coal Ash is commonly used as an indication of the grade or quality of a coal since it provides a measure of the incombustible material present in the coal A higher ash content means a lower heating value of the coal as ash does not contribute any energy to the system It represents a dead weight during coal transport to and through a power station (Lowe 1988a) In order to maintain boiler output when switching from a low ash coal to another with similar specification but a higher ash content an increased throughput of material would be required to achieve the same loading Alternatively power station output may be constrained by the lack of capacity in the ash handling system
Ash content and its distribution within the coal influences ignition stability The transformation of mineral matter to ash is an endothermic reaction - requiring energy Thus some coal particles containing a high proportion of mineral matter may not ignite satisfactorily In some cases stack and unburnt carbon losses have been shown to increase as the heating value of the coal decreases with increased ash content A high-ash content may lower the accessibility of the carbon to combustion within the particle (Kapteijn and others 1990) In contrast to these situations Australian power stations have been known to combust coals with a
19
Coal specifications
high ash (gt25) content without support fuel satisfactorily (Sligar 1992)
High ash coals (gt20) can cause abrasion and particle impaction erosion wear of fuel handling plant mills burners boiler tubes and ash pipes if the plant is not designed for this (Raask 1985) Utilisation of a high ash coal may impair the performance of particulate control devices by ash overloading There may also be problems of accommodating higher ash levels for disposal (Bretz 1991b)
Possibly the most serious effects that ash constituents have upon the boiler performance are those connected with fouling slagging and corrosion of the heating surfaces These problems are discussed in Section 422
The fixed carbon content of coal is not measured directly but represents the difference in an air-dried coal between 100 and the sum of the moisture volatile matter and ash contents It still contains appreciable amounts of nitrogen sulphur hydrogen and possibly oxygen as absorbed or chemically combined material (Rees 1966)
The fixed carbon content of coal is used by the ASTM to classify coal according to rank (Carpenter 1988) It is also used as an estimate of the quantity of char (intermediate combustion product) that can be produced and to indicate the amount of unburnt carbon that might be found in the fly ash
In any assessment of data it should be noted that the final temperatures heating rates and residence times utilised in proximate analysis tests differ significantly from conditions experienced in power station boilers In proximate analysis depending upon the set of country standards used
moisture content is determined in a nitrogen atmosphere at around 100degC for 10 minutes volatile matter of a coal is determined under restricted conditions at 900degC after a residence time of up to seven minutes ash content is determined by combusting the organic component of the coal in air up to around 800dege
Conditions in a power station boiler have been reported to produce temperatures greater than 1700degC (3120degF) heating rates of 1O000-100OOOdegCs and particle residence times within the system of seconds rather than minutes Ideally the suitability of a coal for combustion use should take into account the operational conditions and aim to identify relationships between critical process requirements and specific properties of the coal on a more rational basis However proximate analysis is still widely used in the utility industry
There are also problems with interpreting the results from a proximate analysis Ideally the moisture fraction should contain only water the volatiles fraction should consist only of volatile hydrocarbons released during the initial stages of heating the fixed carbon would be the char after complete devolatilisation and ash only the oxidised remains of the mineral matter after combustion This is not always the case Many coals contain light hydrocarbons which are driven off from the coal at temperatures low enough to cause them to
appear in the moisture determination Consequently the moisture measurement is too high and corresponding volatiles measurement too low This can be a significant problem with lower rank coals (Folsom and others 1986c)
A similar problem occurs between volatiles and fixed carbon The mechanisms involved in thermal decomposition of coal are complex and variations in the particle size treatment times temperatures and heating rates may affect the results Volatile matter content usually includes a loss in weight due also to the decomposition of inorganic material especially carbonates which are known to decompose at temperatures in excess of 250degC (see Section 23) Since fIxed carbon is not a direct measurement but obtained by difference it will include any errors bias and scatter involved in the related determinations of moisture volatile matter and ash Thus the concept of well defmed quantities of fixed carbon and volatile matter for specific coals is subject to qualification
Ash as produced during proximate analysis is often used as the material for conducting chemical analysis and other tests for assessing ash behaviour in a power station The problems associated with this approach are discussed in Section 23
22 Ultimate analysis of coal Ultimate analysis involves the determination of the elemental composition ofthe organic fraction of coal (Ward 1984 Gluskoter and others 1981) Table 2 describes the standard measurement methods for ultimate analysis techniques for ASTM AS BS DIN and ISO In addition to ash and moisture element weight per cents of carbon hydrogen nitrogen sulphur and oxygen (which is determined by difference) are reported Ash and moisture are determined by the same method as in the proximate analysis and suffer from the same shortcomings The detection of the above elements are usually performed with classic oxidation decomposition andor reduction methods (Berkowitz 1985)
Carbon and hydrogen occur mainly as complex hydrocarbon compounds Carbon may also be present in inorganic carbonates The nitrogen found in coals appears to be confmed mainly to the organic compounds present (Ward 1984) The nitrogen content of coal has become an important issue with the increased awareness of air pollution by nitrogen oxides (NOx) Unfortunately there is no simple correlation between coal nitrogen content and nitrogen oxide emissions as unlike sulphur dioxide not all nitrogen oxide produced during combustion comes from the coal itself In combustion theory there are three different formation mechanisms for NOx thermal prompt and formation ofNOx from fuel-bound nitrogen although the reactions are not fully understood (Juniper and Pohl 1991) Only the third mechanism relates to oxidation of the nitrogen contained in coal (Hjalmarsson 1990) The nitrogen content in coal varies between 05 and 25 and is contained mostly in aromatic structures (Burchill 1987 Zehner 1989) Some of the fuel nitrogen is released during devolatilisation and in highly turbulent unstaged burners is rapidly oxidised The remainder of the fuel nitrogen remains in the char and is released at a similar rate to that of char combustion The effIciency of coal-bound nitrogen conversion to NOx has
20
Coal specifications
been estimated at 20-25 for the char and up to 60 for the volatile matter (Morgan 1990) NOx formation from fuel-bound nitrogen can be minimised by promoting devolatilisation in zones of high temperature under reducing conditions for example air staging This principle is exploited in low NOx burners However less can be done to mitigate NOx formation due to the combustion of post-devolatilisation char-bound nitrogen (Kremer and others 1990 Hjalmarsson 1990)
Sulphur is present in nearly all coals from trace amounts up to about 6 although higher levels are not unknown The presence of sulphur compounds in the coal and ash can have many deleterious effects on the operation of boilers for example
during combustion the sulphur is oxidised to S02 A small percentage generally not more than 2 is converted into S03 of which a substantial percentage may then be reabsorbed to form sulphates with the alkali metals in the ash Alkaline sulphates are undesirable in that they increase the tendency of fouling and corrosion of heat transfer surfaces (see Section 422) if the dew point of the combustion gases is reached the S03 present combines with condensing water vapour to produce sulphuric acid which can then cause severe corrosion in cool sections of the power station particularly flue gas ducts and treatment systems (see Section 422)
The main problem however is S02 which is emitted through the stack and constitutes an environmental problem due to the resulting formation of acid rain
The oxygen content of coal is traditionally determined by difference subtracting the sum of the measured elements (C + H + N + S) from 100 although there are procedures available for the direct determination of oxygen (Gluskoter and others 1981 Ward 1984) It is an important property as it can be used as an indicator of rank and the basic nature of the coal Coals tend to oxidise in air to form what is commonly known as weathered coal The oxygen content of a coal has also been used as a measure of the extent of oxidation
Whilst the procedures for elemental analysis described by national standards often differ in minutiae they generally yield closely similar results This can only be achieved by the rigorous adherence to test specifications as laid down by the standards careful sampling and sample preparation
Similar to proximate analysis corrections to the analysis data are necessary For example
contributions to the hydrogen content from residual coal moisture and dehydration of mineral matter because the hydrogen content in coal is determined by the conversion of all the hydrogen present to H20 contributions to the carbon and sulphur contents which are determined by conversion to C02 and S02 respectively because both C02 and S02 are released from any carbonates and sulphides or sulphates that may be contained in the mineral matter
The major limitation of ultimate analysis is the labour cost
and time required to conduct the analyses Several techniques and instruments have been developed to reduce these limitations Some utilise automated gas chromatographic or spectroscopic equipment attached to high temperature combustion furnaces to reduce the time and labour required for the analysis Others utilise a range of measurement techniques including nucleonic methods to provide a quasi-continuous analysis for example on-line analysers (Folsom and others 1986a Kirchner 1991)
23 Ash analysis and minerals Coal ash consists almost entirely of the decomposed residues of silicates carbonates sulphides and other minerals Originating for the most part from clays it consists mainly of alumino silicates so that its chemical composition can usually be expressed in terms of similar oxides to those found in clay minerals The composition of the ash may be used as a guide to the types of minerals originally present in the coal (Given and Yarzab 1978 Ward 1984)
Certain generalisations can be made on the influence of the ash composition on the fusion characteristics as determined by the ash fusion test
the nearer the composition approaches that of alumina silicate Al2032Si02 (Al203 =458 Si02 =542) the more refractory (infusible) it will be CaO MgO and Fe203 act as mild fluxes lowering the fusion temperatures especially in the presence of excess Si02 FeO and Na20 act as strong fluxes in lowering the fusion temperatures high sulphur contents lower the initial deformation temperature and widen the range of fusion temperatures
In practice power station operators are primarily interested in knowing how closely the laboratory-prepared ash content of coal represents the quantity and behaviour of ash produced in large boilers Therefore when interpreting the results of the ash analysis it is important to recognise that the analysis is conducted on a sample of ash produced by the procedures specified in the proximate analysis (for example ASTM D3172 - see Appendix) It does not therefore correspond to the mineral matter present in the parent coal or necessarily to the individual ash particles formed when fired in a utility boiler For example it would be incorrect to assume that the iron measured in the ash sample is necessarily present in the coal as Fe203 or that the aluminium is present as Ah03 (Folsom and others 1986c) The principal chemical reactions that affect the ash yield at different temperatures are
High temperature Low temperature combustion oxidation
(Na K Ca)0Si02xAL203 + S03~ (Na K Ca)S04 + Si02xA1203 2 FeO + 1z 02 ~ Fe203
The boiler ash cools rapidly at a rate of about 200degCs through the temperature range from 900degC to 250degC and
21
Coal specifications
during this short time interval there is only a limited degree of sulphation and oxidation taking place Thus the ash prepared in a laboratory furnace at 815degC has higher weight than that formed in the boiler furnace due to the absorption of S03 in sulphate and additional oxygen in the ferric oxide (Raask 1985) For many years ash analysis in this form has been the only method available for assessing fly ash and deposit composition These in turn would be used to assess a coals slagging fouling and corrosive propensities which are of concern for the efficient operation of the power station More recently investigators have recognised the importance of actual mineral matter composition and
Table 5 Minerals in coal (Mackowsky 1982)
Mineral group First stage of coalification
distribution within the parent coal particles as a better indicator of a coals slagging and fouling behaviour (Nayak and others 1987 Heble and others 1991 Zygarlicke and others 1990) (see also Section 422)
Mineral matter determination is carried out far less frequently than the relatively fast and inexpensive ash determination (Brown 1985) Table 5 describes the minerals found in coal and their method of deposition
Although the ash as measured by proximate analysis is often equated with the coal mineral matter there are significant
Second stage of coalification Occurrence
Syngenetic fonnation synsedimentary-early diagenetic Epigenetic formation (intimately intergrown)
Transported Newly fonned Deposited in Transfonnation by water or fissures cleats of syngenetic wind and cavaties minerals
(coarsely (intimately intergrown) intergrown)
Clay minerals Kaolinite common-very common Illite-Sericite Illite dominant-abundant Minerals with a layered structure Chlorite rare Montmorillonite rare-common Tonstein
Carbonates Siderite Ankerite Ankerite common-very common Dolomite Dolomite rare-common Calcite Calcite common-very common
Sulphides Pyrite Pyrite Pyrite rare-common Melnikovite rare Marcasite Marcasite rare
Galena rare Chalcopyrite rare
Oxides
Quartz
Phosphates
Heavy minerals and accessory
Hematite Goethite
Quartz grains Quartz Quartz
Apatite Apatite Phosphorite
Zircon Tounnaline Orthoclase Biotite
Chlorides Sulphates Nitrates
rare rare
rare-common
rare rare
rare very rare very rare very rare rare rare rare
dominant gt60 abundant 30-60 very common 10-30 of the total mineral matter common 5-10 content in the coal rare 5-1 very rare lt1
22
Coal specifications
differences For example dehydration decomposition and oxidation of mineral matter which may occur during the laboratory process can affect the composition of the ash as follows
FeS04nHzO FeS04 + nHZO dehydration reduces the weight of CaC03 CaO + COZ decomposition ash and adds to
volatile matter
FeS + 20z FeS04 oxidation adds to weight of ash
Similarly partial loss of volatile constituents in particular mercury (Hg) potassium (K) sodium (Na) chlorine (CI) phosphorus (P) and sulphur (S) means that the ash is qualitatively and quantitatively quite different from the mineral matter that gave rise to it Its behaviour which is ultimately determined by its composition is also different If the ash sample is used for subsequent composition analysis the concentration of sodium and other volatile inorganic elements may be significantly lower than in the original mineral matter
Carbonate minerals are common constituents of many coals (see Table 5) These minerals liberate carbon dioxide (C02) on heating and therefore can contribute to the total carbon content of the coal as determined by ultimate analysis Whilst the COz content of the mineral matter is important for the correction of other specifications it is not normally included on coal specification sheets for combustion
24 Forms of SUlphur chlorine and trace elements
Procedures for determining these properties are described in various national and international standards (see Table 2)
Sulphur in coal is generally recognised as existing in three forms inorganic sulphates iron pyrites (FeS2) and organic sulphur compounds known respectively as sulphate sulphur pyritic sulphur and organic sulphur Although the total sulphur content provides sufficient data for most commercial applications a knowledge of the relative amounts of the forms of sulphur present is useful for assessing the level to which the total sulphur content of a particular coal might be reduced by preparation processes Commercial preparation plants can generally remove much of the pyritic sulphur but have little effect on the organic sulphur content
Pyrite is one of the substances which enhance the risk of spontaneous combustion by promoting oxidation and consequent heating of the coal (Bretz 1991a) Pyrite is also a hard and heavy substance which adds to the abrasion of coal mills (Cortsen 1983) (see Section 322)
It appears that in many cases some of the sulphur in the coal is retained in the ash as sulphate Thus the sulphate in the ash is invariably greater than the sulphate in the original coal when both parameters are expressed as fractions of the weight of original coal This effect is so large with the lower rank lignites that the ash yield may actually be greater than
the mineral matter content Kiss and King (1979) showed that between 0 and 99 of the organic sulphur in Australian brown coals may be retained in the ash as sulphate The thermal decomposition of carboxylate salts is particularly efficient in trapping organic sulphur as sulphate in ash With higher rank coals that do not contain carboxyl groups it is carbonates or the oxides formed from pyrolysis that tend to fix sulphur as sulphate It is evident that the amount of sulphate in ash depends on both the sulphur content of the coal and the concentration and nature of the materials capable of fixing it during ashing Various national and international standards specify procedures for determining sulphate in ash
Although not strictly part of the usual ultimate analysis procedure determination of chlorine which may be present in the organic fraction of the coal as distinct from the mineral analysis of the ash is often included Chlorine can enter the coal in the form of mineral chlorides in saline strata waters but this accounts for less than 50 of the total amount The bulk of the chlorine is present as CIshyassociated with organic matter probably as hydrochlorides of pyridine bases (Gibb 1983) In general chlorine content in most coals is quite low though there are exceptions For example some British coals can contain up to 1 chlorine (Given 1984)
In combustion chlorine from both alkali chlorides and the organic fraction of coal can combine with other mineral elements and contribute to deposition and corrosion Chlorine content is also used as an indication of potential fouling tendencies as the majority of the alkali metals responsible for fouling problems are present in the original coal associated with chlorine Chlorine can also affect the control of the pH (aciditylbasicity) in FGD plants (Jacobs 1992)
Apart from the major impurities in coal which are measured in the normal analysis there are a wide variety of trace elements which can also occur Clarke and Sloss (1992) have reviewed the typical concentrations of trace elements in coals There is a growing interest in the emission of trace elements from stacks as atmospheric pollutants and one can expect more attention to be given to this over the coming years (Swaine 1990) There has also been increased anxiety over the possible leaching of trace elements from ash or flue gas desulphurisation waste which may be deposited on the ground as means of disposal or use (Clarke and Sloss 1992) (see also Section 524)
25 Coal mechanical and physical properties
The commercial evaluation of a coal also involves assessments of physical properties A variety of tests have been developed to quantify physical properties of coal but each one is usually related to a particular end use requirement Table 6 lists standard measurements for coal physical tests which are considered relevant for handling and combustion
23
ASTM American Society for Testing and Materials AS Australian Standards BS British Standards Institution DIN Deutsches Institut fUr Norrnung ISO International Organization for Standardization
Bulk density flow properties fineness friability and dustiness all affect the handleability of coal
bulk density measurements are designed to evaluate the density of the coal as it might lie in a pile or on a conveyor belt (Folsom and others 1986c) the size distribution test is used to evaluate the size distribution of coal prior to pulverisation This measurement is important as it can be used to determine the suitability of a coal for a particular mill type and is used to assess the efficiency of the mill system Particle size distribution is also determined for the coal sample after air drying and pulverisation Pulverised coal fineness and size distribution is particularly important for burner performance (see Section 41) there are several tests to evaluate coal friability They are designed to determine the extent of coal size degradation and dusting caused by handling stockpiling and grinding
Most modem coal-burning equipment requires the coal to be ground to a fine powder (pulverised) before it is fed into the boiler The Hardgrove grindability index (HGI) is designed to provide a measure of the relative grindability or ease of pulverisation of a coal The test has changed little over the years Traditionally the HGI is used to predict the capacity performance and energy requirement of milling equipment as well as determining the particle size of the grind produced (Wall 1985a) Coals with high HGI are relatively soft and easy to grind Those with a low value (less than 50) are hard and more difficult to make into pulverised fuel (Wall and others 1985 Ward 1984) The grindability of coals is important in the design and operation of milling equipment A fall in HGI of 15 units can cause up to 25 reduction in the mill capacity for a given PF product as shown by the
10--1-----shyOJ sect 5 Cl r
eOl
09 pound
middotE 0 OJ ~
~ 08
lt5 z
constant PF size distribution
50 48 46 44 42
Hardgrove grindability index (HGI)
Figure 3 Mill throughput as a function of Hardgrove grindabaility index (Fortune 1990)
graph in Figure 3 Coals with high HGI values in general cause few milling problems
The abrasion index is a measure of the abrasiveness of a particular coal and is used in the estimation of mill wear during grinding (Yancey and others 1951) The abrasion index is expressed in milligrams of metal as lost from the blades of the test mill per kilogram of coal
The free swelling index (FSI) also called the crucible swelling number is used to indicate the agglomerating characteristics of a coal when heated Although primarily intended as a quick guide to carbonisation characteristics it can be used as an indicator of char behaviour during combustion A high swelling number suggests that the coal
24
Coal specifications
particle may expand to fonn lightweight porous particles that ash residue at high temperatures can be a critical factor in fly in the air stream and could contribute to a high carbon selection of coals for combustion applications Ash fusion content in the fly ash The extent of swelling is a function of temperatures are often used to predict the relative slagging the rate of heating final temperature and ambient gas and fouling propensities of coal temperature (Essenhigh 1981) so that the actual effects in practice are greatly dependent on combustion conditions The The test involves observing the profiles of specifically swelling number is also significantly affected by the particle size distribution of the sample (Ward 1984) Knowledge of the swelling properties of a coal can be used to avoid agglomeration problems in fuel feed systems (Hainley and others 1986 Tarns 1990) The size of the char particle after devolatilisation and swelling has been found to have an important influence on the kinetics of the combustion process 2 3 4 (Morrison 1986 Jiintgen 1987b) IT 5T HT
1 Cone before heating
The FSI can also provide a broad indication of the degree of 2 IT (or ID) Initial deformation temperature 3 ST Softening temperature (H=W) oxidation of a given coal when compared with a fresh 4 HT Hemispherical temperature (H=12W)
unoxidised sample or against a background history of 5FT Fluid temperature
measurement for a particular coal (ASTM DnO Shimada and others 1991)
Figure 4 Critical temperature points of the ash fusion The ash fusion test (AFT) measures the softening and test (Singer 1991 ASTM D1857) melting behaviour of coal ash The behaviour ofthe coals
Table 7 A summary of the major characteristics of the three maceral groups in hard coals (Falcon and Snyman 1986)
Maceral group Reflectance Chemical properties Combustion properties plant origin
Description Rank Reflected Characteristic Typical products on Ignition Burnout light element heating
Vitrinite woody trunks Dark to Low rank to 05-11 intermediate light intermediate ill ill branches stems medium grey medium rank hydrogen hydrocarbons volatiles jj jj stalks bark leaf bituminous 11-16 content decreasing j j tissue shoots and rank j j detrital organic Pale grey High rank 16--20 j j matter gelified bituminous vitrinised in White anthracite 20-100 acquatic reducing conditions
Exinite cuticles spores Black- Low rank -00-05 early methane volatile- jjjj jjjj resin bodies algae brown gas rich accumulating in sub- Dark grey Bituminous -05--09 hydrogen- oil decreasing jjj jjj acquatic conditions -09-11 rich with rank
Pale grey Medium rank -11-16 condensates bituminous wet gases (j) (j)
Pale grey High rank (decreasing) (=vitrinite) bituminous to white to shadows anthracite -16--100
Inertinite as for vitrinite but Medium Low rank 07-16 hydrogen- low fusinitised in aerobic grey bituminous poor volatiles oxiding conditions Pale grey Medium rank -16--18 in all ranks
to white bituminous and yellow to anthracite -18-100 (j) (j) - white
Capacity or rate j = slow Capacity or rate shown in parenthesis refers to vitrinite jj = medium jjj = fast jjjj = very fast
5 FT
25
Coal specifications
Table 8 Summary of coal ash indices (Anson 1988 Folsom and others 1986c Wibberley and Wall 1986 Wigley and others
Index Factors
Ash descriptor Base-acid ratio (BfA)
Ash viscosity T250 of ash degC (OF) Silica ratio
Siagging propensity Base-acid ratio (BfA) (for Iignitic ash CaO + MgO gtFe203) Siagging factor (for bituminous ash CaO + MgO lt Fe203) Iron-calcium ratio Silica-alumina ratio
Slagging factor degC (OF)
Viscosity slagging factor
Fouling propensity Sodium content
Fouling factor
Total alkaline metal content in ash (expressed in equivalent Na203)
chlorine in dry coal
Strength of sintered fly ash Psi
Temperature ash viscosity = 250 poise SiOl(Si02 +Fe203 + CaO + MgO)
(BfA)(S dry)
Fe20 3fCaO SiOlAh03 Maximum hemispherical temperature + 4(minimum initial deformation temperature)
5 T25o(oxid-TlOooO(red)
975 Fs
(Fs ranges from 10-110 for temperature range 1037-1593degC (1900-2900degFraquo
Na203 (for Iignitic ash CaO + MgO gtFe203) (for bituminous ash CaO + MgO ltFe203)
BfA(Na20 in ash) (for bituminous ash CaO + MgO ltFe203) BfA(Na20 water solublellow temperature ash) Na20 + K20 (for bituminous ash CaO + MgO ltFe203)
oxid oxidising conditions red reducing conditions
shaped cones made from ash prepared by the proximate analysis method with a suitable binder The cones are gradually heated in a furnace under either an oxidising or reducing atmosphere until the ash softens and melts Temperatures corresponding to four characteristic cone profile conditions are noted These conditions are shown in Figure 4 The four cone shapes are defined as follows
initial deformation - the initial rounding of the cone tip softening temperature - height equal to width hemispherical temperature - height equal to one-half width fluid temperature - height equal to one-sixteenth width
Under reducing conditions AFTs are lower due to the greater fluxing action (basicity) of the ferrous ion (FeO) compared with the ferric ion which is present under oxidising conditions
The heating value or calorific value is the single most important coal index or quality value for use in steam power stations since it provides a direct measure of the heat released during combustion The energy liberated by a coal on combustion is due to the exothermic reactions of its
hydrocarbon content with oxygen Other materials in the coal such as nitrogen sulphur and the mineral matter also undergo chemical changes in the combustion process but many of these reactions are endothermic and act to reduce the total energy otherwise available
The standard laboratory test measures the gross heating value that is the total amount of energy given off by the coal including latent heat of condensation of vapour formed in the process Under practical conditions water vapour and other compounds (acid forming gases) can escape directly to the atmosphere without condensation and the recoverable heat given off under these conditions is known as the net heating value It can differ most significantly from the gross heating value in coals that have a high moisture content such as brown coals or lignites as the main difference between the two values is the latent heat of evaporation of water The net heating value can be calculated from the standard laboratory-determined gross value based on factors such as the moisture sulphur and chlorine contents of the coal concerned An example of a conversion formula which relates gross and net heating value reads (ISO 1928)
Qn = Qg - 0212 H - 00008 0 - 00245 M MJkg
26
Coal specifications
1989)
Tendenciesvalues
Low Medium Iligh Severe
gt1302 (2375) 1399-1149 (2550-2100) 1246-1121 (2275-2050) lt1204 (2200)
Viscosity proportional to silica ratio
lt05 05-10 10-175
lt06 06-20 20-26 gt26
lt031 or gt300 031-30 Low ~ High
gt1343 (2450) 1232-1343 (2250-2450) 1149-1232 (2100-2250) lt1149 (2100)
05-099 10-199 gt200
lt20 20-60 60-80 gt80 lt05 05-10 10-25 gt25 lt02 02-05 05-10 gt10 lt01 01-024 025-07 gt07
lt03 03-04 04-05 gt05
lt03 03-05 gt05
lt1000 1000-5000 5000-16000 gt16000
where Qn = net heating value Qg = gross heating value H = hydrogen (percentage fuel weight) 0 = oxygen content (percentage fuel weight) M = moisture content (percentage fuel weight)
In North America boiler thennal efficiency is usually quoted on the basis of the gross heating value whereas most European countries use net heating value
Various fonnulae for predicting the heating value of coal from ultimate analysis have been developed On a dry mineral matter-free basis the heating value relates directly to the composition of the coal substance Some of these fonnulae are reviewed by Mason and Gandhi (1980) and Raask (1985)
Petrographic analysis of coals is increasingly being used to add to the information necessary to assess the suitability of coal for combustion in a particular power station Coal petrology describes coal in tenns of its maceral and mineral matter composition (see Table 7) These components can be recognised and measured quantitatively with the aid of a microscope A comprehensive review of the features that
characterise the various members of the maceral groups and rules for their microscopic identification can be found in the Intemational Handbook of Coal Petrography (ICCP 1963 1975 1985) Stach and others (1982) gives an overview of the macerals and their physical and chemical properties and Teichmiiller (1982) Given (1984) Davis (1984) Falcon and Snyman (1986) and Carpenter (1988) provide a good description of the origin of macerals
Maceral composition can be linked to properties of significance for describing combustion perfonnance Relatively little attention has been given to assessing maceral effects on grindability The literature that is available provides a confusing and somewhat contradictory picture This could be a consequence of the relative grindabilities of vitrinite and inertinite reversing as the rank of coal increases (Unsworth and others 1991) The preferential population of macerals within particular size ranges has been reported by several investigators (Falcon and Snyman 1986 Skorupska and Marsh 1989) For example an investigation involving a medium rank bituminous coal revealed a difference between the grindability of vitrinite and inertinite of approximately 15 units with inertinite displaying a HGI value averaging
27
Coal specifications
55 Such differences can significantly influence mill throughput (Unsworth and others 1991)
In certain circumstances it has been reported that a petrographic assessment of coal rank has advantages over the other techniques used as standards (Neavel 1981 Unsworth and others 1991) Parameters such as volatile matter content fixed carbon heating value swelling indices are average properties of a coal sample As such they reflect coal rank but they are also affected by variations in maceral composition Measurement of vitrinite reflectance is widely used as an index of coal rank
Earlier investigators recognised that the carbonaceous materials present in fly ash were predominantly forms of inertinite (Yavorskii and others 1968 Nandi and others 1977 Kautz 1982) Since that time the influence of maceral composition on coal reactivity during combustion has been the subject of considerable study (Jones and others 1985 Falcon and Falcon 1987 Oka and others 1987 Shibaoka and others 1987 Bend 1989 Diessel and Bailey 1989 Skorupska and Marsh 1989 Sanyal and others 1991) It has now been applied in many cases to explain problems that occur during combustion when other traditional tests such as proximate analysis have failed (Sanyal and others 1991)
The application of petrographic assessment as a predictive tool is still believed to be some way off Two reasons for this are
the subjective identification and different criteria being applied by the different countries to distinguish macerals has led to unsatisfactory reproducibility in results This has been illustrated in international exchange exercises conducted by the ICCP in the past It has been clear for some time that there is a need to reduce subjectivity to a minimum This may be achieved by using automated assessment techniques limited validation on a power station boiler scale of the influence of macerals on boiler performance Present operational procedure at boiler scale does not lend itself well to simultaneously monitor performance and allow for full petrographic assessment of the feedstock coal
26 Calculated indices In an effort to extend the use of laboratory results a number of empirical indices have been developed based on the
measurements discussed in the previous subsections These indices have been used to relate coal composition to the performance of power station components While the indices are not measurements as such in many cases they are utilised in the same manner as coal properties The accuracy reproducibility and applicability of these indices depend directly on the specific measurement procedures employed Indices have been developed for
rank reactivity ash descriptor ash viscosity slagging propensity fouling propensity
Rank relationships with coal properties as used nationally and internationally are summarised earlier in Figure 2
Some combustion reactivity indices use a relationship of the proximate volatile matter and fixed carbon of a coal known as the fuel ratio lllustrations of the relationship are given in Section 421
The indices used to describe ash behaviour are summarised in Table 8 The indices can be included in coal specification sheets to help assess the suitability of a coal for combustion How they are used and their relationship to performance are discussed in Section 422 of this report
27 Comments Most coal evaluation testing for combustion relies on empirical procedures which were developed primarily for the carbonisation industry town gas and blast furnace coke manufacture using simple laboratory equipment under conditions which were intended to represent those found in that type of process Despite the shortcomings the techniques required to perform the tests such as for proximate analysis are so simple that they lend themselves to automation This removes much of the risk of operator error and produces repeatable results
As operating requirements become more stringent the weaknesses of some of these techniques are becoming increasingly apparent There is a growing need to develop tests and specifications which reflect more closely the conditions found in power station boilers
28
3
steam generator
burners
mills
environmental control
I
Pre-combustion performance
environmental controlcoal handling
and storage
ash transport fans
The following three chapters describe the effect of coal quality parameters on the performance of various component parts of coal-frred steam generator systems Figure 5 illustrates the components of a typical power station The main power station components include
coal handling and storage mills fans burners boiler ash transport technologies for controlling emissions
This chapter focuses on effects of coal quality on the pre-combustion components of a power station
31 Coal handling and storage The coal handling equipment includes all components which process coal from its delivery on site to the mills This includes a large amount of equipment which (depending on power station design) may include unloading facilities hoppers screens conveyors outside storage bulldozers reclaimers bunkers etc and of course the coal feeders to the mills (Folsom and others 1986b) A high level of automation and remote control is often incorporated in
Figure 5 Typical power station components
29
Pre-combustion performance
Table 9 Illustrative example of USA coal storage requirements (Folsom amp others 1986b)
Coal
Lignite Subbituminous Bituminous
midwest eastern
Heat to turbine 106 kJh 4591 4591 4591 4591 Boiler efficiency 835 862 885 905 Coal heat input 106 kJh 5499 5326 5185 5073 Coal HHV MJkg 14135 19771 26284 33285 Coal flowrate th 429 297 217 168
Design storage requirements t Bunkers 12 hours 5148 3564 2604 2016 Live 10 days 102960 71280 52080 40320 Dead 90 days 926640 641520 468720 362880
Storage time for eastern bituminous plant design t Bunkers hours 47 68 93 120 Live days 39 57 77 100 Dead days 35 51 69 902
equivalent storage time for a plant designed for eastern bituminous coal but fired with the coals listed
modern coal handling facilities including sophisticated stacking-out and reclaim facilities to achieve some degree of coal blending capability Slot bunker systems with bulldozer operated stacking and reclaimers are still preferred by many utilities because of capital cost savings and greater flexibility of stockpile management
Coal storage can be divided into two categories according to the purpose live (active) storage with short residence time which supplies fIring equipment directly and dead or reserve storage which may remain undisturbed for many months to guard against delays in shipments etc Live storage is usually under cover and reserve storage outdoors
When outdoor storage serves only as a reserve the normal practice is to take part of an incoming shipment and transfer it directly to live storage within the station while diverting the remainder to the outdoor pile
The coal storage components are generally sized to provide capacity equivalent to a fIxed time period of fIring at full load (McCartney and others 1990) Typical values are 12 hours for inplant storage in bunkers ten days for live storage and more than 90 days for reserve storage Capacity of the reserve pile can be for example a minimum 60-day supply at 75 of the maximum burn rate These time periods are specifIed by the architectengineer based on the utilitys desired operating procedures and other constraints such as political legislation for strategic stocking The key parameters for assessing the quantity of coal required are
power station capacity heat rate coal heating value
Steam generators of a given capacity operating at steady load
require a fIxed heat input per unit of time regardless of coal heating value (Carmichael 1987) Therefore if the actual heating value of the coal is reduced then the storage capacity and quantities that must be delivered to the utility via the transport system must be increased For example Folsom and others (l986b) compared the storage requirements for four coals of differing rank supplying a 500 MW steam-electric unit (see Table 9) For all performance parameters to remain constant over a wide range of coal heating values substantial variations in coal flow rate at full load are required with factors of as much as 21 in some cases The coal storage requirements for specifIc time periods reflect this same range of variation Also shown are the storage times required for fIring alternate coals in a unit designed to fIre a high heating value fuel an Eastern USA bituminous coal These changes may not affect the ability to operate the unit at high capacity for short time periods However the equipment which transports the coal may need to operate more frequently and this could limit the ability to fIre at full station capacity over an extended period Also normal power station operating procedures may need to be modifIed to permit fIlling the bunkers more than once per day etc
Most of the equipment which transports the coal operates intermittently Thus coal quality changes which result in coal flow rate changes will vary the duty cycle for the transport equipment An increase in flow rate requirements caused by a decrease in coal heating value or an increase in boiler heat rate will increase the duty cycle and may affect unit capacity Provided that these changes in flow rate are small or of limited duration most power stations will be able to tolerate them with no equipment modifIcations Large increases in flow rate for example those that may occur due to a shift from a bituminous coal to a lignite as described in Table 9 may require such long duty cycles that the normal operating procedures of the power stations and maintenance intervals
30
Pre-combustion performance
Table 10 Conveyor Equipment Manufacturers Association (CEMA) material classification chart (Colijn 1988a)
Major class Material characteristics included Code designation
Density
Size
Flowability
Abrasiveness
Miscellaneous properties or hazards
Bulk density loose
Very fine 200 mesh sieve (0075 mm) and under 100 mesh sieve (0150 mm) and under 40 mesh sieve (0406 mm) and under
Fine 6 mesh sieve (335 mm) and under
Granular 127 mm and under
Lumpy 76 mm and under 178 mm and under 406 mm and under
Irregular stringy fibrous cylindrical slabs etc
Very free flowing - flow functiongt 10 Free flowing - flow function gt4 but lt10 Average flowability - flow function gt2 but lt4 Sluggish - flow function lt2
Mildly abrasive - Index 1 - 17 Moderately abrasive - Index 18 - 67 Extremely abrasive - Index 68 - 416
Builds up and hardens Generates static electricity Decomposes - deteriorates in storage Flammability Becomes plastic or tends to soften Very dusty Aerates and becomes fluid Explosiveness Stickiness - adhesion Contaminable affecting use Degradable affecting use Gives off harmful or toxic gas or fumes Highly corrosive Mildly corrosive Hygroscopic Interlocks mats of agglomerates Oils present Packs under pressure Very light and fluffy - may be windswept Elevated temperature
Actual kgcoal flow
Azoo AIOO
~
C~
E
1 2 3 4
5 6 7
F G H J K L M N o P Q R S T U V W X Y Z
may be inadequate In such extreme cases the capacity of the transfer equipment may be insufficient even with continuous operation such that modifications will be required In some power stations it may be possible to increase the capacity of the transport equipment For example conveyor belt speeds may be increased However this can also lead to dust problems and increased spillage especially with friable coal
Unlike the other coal transport equipment the coal feeders operate continuously Thus any change in coal flow rate requirements must be met with an immediate change in feeder speed Coal feeders are usually designed with excess capacity so that minor changes in coal flow rate requirements can be tolerated easily The major changes required by significant changes in coal heating value such as switching
from a bituminous coal to a lignite would be beyond the capacity of most coal feed systems Another factor to consider is the feeder turndown Many feeders have a minimum operating speed beneath which problems such as uneven flow can occur
In addition to changes in the required coal flow rates coal characteristics can produce other detrimental effects on handling and storage systems
In a survey carried out at a coal handleability workshop (Arnold 1988) attendees from utilities and the mining community were asked to rank the problems from one (1 - worst) to ten (10 -least) The ratings are indicated next to each problem
31
Pre-combustion performance
plugging in bins (1) feeders (2) arching and caving in storage (10) flowability hang-up in bins (3) sticky coal on belts (4) freezing in transport (5) storage (8) dusting on conveyors (6) in stockpiles (7) oxidationspontaneous combustion (9)
Other concerns mentioned included abrasiveness of coal causing chute wear wet fuel hang-up in transfer towers sticky fuel in downcomers spillage and sliding from belts due to wetness hang-up in breakers excessive surface moisture and coal sticking in bottom-dumped rail cars Whilst relationships between coal properties and handleability have been established these are not the same as those needed for combustion purposes In fact some coal specifications do not usually include parameters which reflect the handling and storage properties of coal Colijn (1988a) reported that the Conveyor Equipment Manufacturers Association (CEMA) have made an effort to establish a listing of material properties and characteristics which influence the handling and storage of granular bulk materials including coal as shown in Table 10 The coding system has been developed to describe particular material properties such as density size flowability and abrasiveness Where material handling characteristics are in general not easily quantifiable they are listed as hazards - watch out Table II shows typical CEMA codes for various coal
Table 11 CEMA codes for various coals (Calijn 1988a)
Material description CEMA material code
Coal anthracite (River amp Culm) 6OB635TY Coal anthracite sized - 127 mm 58C-225 Coal bituminous mined 50 m amp under 52A4035 Coal bituminous mined 50D335LNXY Coal bituminous mined sized 50D335QV Coal bituminous mined run-of-mine 50Dx35 Coal bituminous mined slack 47C-245T Coal bituminous stripping not cleaned 55Dx46 Coal lignite 43D335T Coal char 24Cl35Q
x refers to a range of particle sizes
311 Plugging and flowability
The economic impact of plugging of coal transport facilities can be significant resulting in added manpower costs for clearance partial unit deratings or in some cases total shutdowns For example at 15 $MWh a typical 575 MW unit could lose over 1000 $h income as a result of partial deratings for each plugged silo (Bennett and others 1988)
No flow or limited flow problems are often due to the formation of stable arches andor increases in wall friction (Arnold 1990) Binsilo blockages occur when the coal has become sufficiently adhesive to form a stable arch which supports the weight of the coal above it Increases in wall friction which is a measure of the sliding resistance of the coal against the bin wall will result in coal adjacent to the wall moving slower than that in the centre zone This gives
mass flow funnel flow expanded flow
Figure 6 Typical flow patterns in bunkers (Colijn 1988a)
rise to different flow patterns in various parts of the bin (see Figure 6) For most coals three to four days outdoor storage increases the chances of one or both of the above problems occurring Coal flowability is directly related to various coal characteristics depending on the coal rank Some of the major contributing properties are (Llewellyn 1991)
surface moisture particle size distribution clay content changes in bulk density
Surface moisture is considered the most critical factor There is a level below which regardless of other factors coal flow problems do not occur There is also a critical surface moisture at which maximum adhesion and bulk coal strength will occur Above this level additional water flows away rises to the surface or in the extreme decreases strength due to slurry formation Adding moisture to dry coal first creates a lubricating effect and allows particles to slide against each other more easily and pack into a denser stronger material Surface tension develops as a form of physico-chemical bonding (known as hydrogen bonding) increases between water and coal particles
Particle size distribution contributes to flowability problems because it determines the available surface area and hence adhesion characteristics The proportion and size of the smallest particles in bulk coal have a great effect on its handleability In some coals the ash and clay content which is inherent in the coal concentrates in the fines fraction (see Table 12) This also influences coal flowability characteristics Average particle size can be affected by coal handling procedures and equipment or by natural causes A major factor influencing the size composition of a coal product is its friability Friability is a combination of the impact strength and fracture cleavage characteristics of the coal and its susceptibility to degradation due to a rubbing action during handling A high fines content if combined with a critical moisture level can result in a coal with very poor handling properties (Llewellyn 1991) In low rank coals large pieces may fall apart and produce excess fines in dry air If the coal is subsequently rewetted the combination
32
Pre-combustion performance
Table 12 Analysis of ash and clay distribution in a coal by mesh size (Bennett and others 1988)
Property Base fuel +6 Mesh (+335 mm)
6-50 Mesh (036-030 mm)
50-100 Mesh (030-015 mm)
-100 Mesh (-015 mm)
Weight Ash (Dry) Silica
10000 2277 6740
4514 1702 5850
4512 2320 6490
765 3596 7790
209 4153 8380
of increased surface area and moisture can have a substantial impact on flow characteristics
The clay content of coal affects its cohesive characteristics Increased clay content in strip mined subbituminous coal and lignites has been shown significantly to increase wall friction and shear strength at a given moisture content (Bennett and others 1988)
If all of the above factors increase simultaneously that is high surface moisture high clay high fmes percentage and coal is stored in a bin for several days drastic increases in coal bulk shear strength lead to significant adhesion bridging and consequent coal flowability problems
There are no coal specifications which relate to coal bulk shear strength although tests have been developed which provide bulk shear strength values for coals They are used as a measure of the cohesive strength or stickiness and have been used as a quantifying factor for problem coals Shear strength can be measured using either a rotational or a linear translational instrument Results from the rotational shear test can be obtained within an hour and may be used on-site to provide real time analyses (Bennett and others 1988 Colijn 1988a) The principle of the rotational shear tester is to provide an equally distributed shearing force across a horizontal plane in the coal sample This is done while the sample is placed under varied loads The bulk shear strength determined for a particular fuel handling situation can be represented as a value in applied pressure or as an arbitrary relative flow factor value (FFV) The FFV can be plotted relative to moisture and clay values A critical arching diameter (CAD) can be extracted by combining results from a shear tester with the bulk density of the coal Calculations can then be made for the geometric configuration of each type of coal container for particular types of coal thus negating possible problems of archingplugging in a binsilo Figure 7 shows the data derived from shear tests for more than twenty coals conducted by Colijn (1988b) The CAD was plotted against the surface moisture content for the coals and while a clear relationship between increasing moisture content and increasing CAD exists there is significant data scatter As discussed earlier other investigators (Blondin and others 1988 Arnold 1991) have shown that the amount of clay and fines also influence the CAD
As many coals have a tendency to increase their strength after a few days of consolidation it is often necessary to test the coals under these conditions For these cases a coal sample would be kept inside the shear cell under pressure for a number of days to simulate the time period during which the coal may be contained within a bin or silo Arnold (1991) reported a study conducted to define further the relationship
mass flow - instantaneous
2 E ~
til Q) E til 0 0) c
c ()
ro (ij ()
8
0
0
Figure 7
3 E
~ Q) E til 2 0 0)
~ c ()
ro (ij ()
8
0
0 0 0
o
0
6 o 00 oo0
o D cPo DO
0 CI o~ 0_o
--tJ 0 0 0 _ - shy
9 - Data for a variety of coal samples
2 4 6 8 10 12 14 16
Surface moisture
Surface moisture versus critical arching diameter (CAD) determined from shear tests (Coljjn 1988b)
3-day consolidation
10 moisture
+ 8 moisture
6 moisture
+ +
0
0 2 4 6 8 10 12 14
Fines -44 ~m (-325 mesh)
Figure 8 Three-day consolidation critical arching diameter (CAD) versus per cent fines in coal as a function of moisture content (Arnold 1991)
of coals and their handling behaviour Six coals that were combusted at an Eastern USA power station were selected The coals had very similar chemical analyses and all met the power station coal specification but exhibited a range of handling characteristics As an illustration of some of the preliminary results of the study Figure 8 shows the influence of the percentage fines (particles less than 44 lm in diameter) moisture content and consolidation time on the CAD calculated from shear tests conducted on one of the coals The instantaneous CAD values are not shown in Figure 8 but were in fact 30 lower in value than the three-day consolidation values Generally for all the coals studied the maximum value occurred at the highest moisture
33
Pre-combustion performance
contents and there was a tendency to increase with increasing fines content and increases in consolidation time
More recently Rittenhouse (1992) reported the development of a series of simplified empirical tests that can be run by power station staff members that make it possible to identify potential problem coals The results of the tests are indices that characterise the flowability of coal The individual indices are
arching index ratholing index hopper index chute index flow rate index density index
These can also be used to indicate when hopper modifications may extend the operating range of the system so that coals that are less than free flowing can be handled The tests are reviewed in greater detail by Johanson (1989 1991) Arnold and OConnor (1992) have recently reported the development of another simplified test that can be used more easily on-site and has been validated against the tri-axial shear tester
Coal flowability can be modified by the use of chemicals which specifically enhance the flow of wet coal Additive selection and performance depend greatly on fuel quality (Bennett and others 1988) The effectiveness of particular additives on problem coals is assessed by measurement of shear strength values produced
312 Freezing
Although it is difficult to assess the cost related specifically to coal moisture freezing during cold weather some of the potential problems are as follows
production losses at the mine beneficiation plant and the utilities increased labour costs associated with frozen coal removal less safe working conditions costs related to operation of thawing and mechanical removal equipment transport equipment damage due to mechanical or thermal means of removing frozen coal from ships rail cars or trucks demurrage costs on rail cars accelerated rail wear andor derailment
Work done in the mid-1970s showed that surface moisture of a coal caused the problems For freezing to occur the coal being handled must be exposed to sub-freezing temperatures for a sufficient period of time It is generally accepted however that no problems with handling should be expected unless the surface moisture exceeds approximately five per cent Total moisture content of the coal is inadequate as a sole indicator since coal that has a high inherent moisture may not freeze at 20 or more total moisture while coal with a low inherent moisture
may freeze and cause severe problems at seven per cent or below
Each coal type has a characteristic inherent moisture content defined here as the moisture contained in the fine pore structure itself Depending upon rank porosity and hydrophilicity of the coal inherent moisture ranges from less than one per cent to greater than 20 of the coal mass While surface moisture is undoubtedly the primary cause of coal freezing and the consequent handling problems other factors also influence the situation For example Connelly (1988) reported that at lower temperatures the increased viscosity of water renders the dewatering of coal processes less efficient Total moisture content of dewatered coals can be expected to increase at lower temperatures as shown in Figure 9
90
86 bull
t-O)
s 82 bull
iiimiddot0 E 78
Cii l 0V 0)
cr 74
72 bull
66
4 10 20 30 40 50 Temperature degC
Figure 9 Dewatering efficiency versus temperature (Connelly 1988)
Particle size is also important If the coal particle size were consistently large that is 127 cm (h inch) or larger it would be unlikely that the particles would pack together sufficiently to freeze and cause a serious problem Current mining methods use continuous longwall techniques to extract coal with consequent breakage and fines production For this reason it is impractical for beneficiation plants to furnish a product with a minimum particle size of 127 cm or greater for all shipments unless some form of agglomeration process is used Typically coal being shipped contains a wide range particle size distribution and a substantial amount of material less than 016 cm in diameter Because of this particle size distribution the fine particles of coal can pack between the larger ones and form a more continuous solid mass The finer particle size coal also tends to hold a larger percentage of surface moisture With the finer particle size and increased surface water more particle-to-particle contact occurs accentuating the freezing problems
The freezing process can be offset by the use of additives such as urea calcium chloride solution or polyhydroxy alcohols (Hewing and Harvey 1981 Boley 1984 Connelly 1988)
34
Pre-combustion performance
313 Dusting
Most bulk solid materials have the potential to generate dust during handling Dust can be generated while the coal is in motion such as during transfer from transport to storage and even as wind borne dust from stockpiles This creates safety as well as environmental problems The extent of dust problems may be related empirically to particle size distribution (the amount of fines) moisture content moisture holding capacity and the wind speed (Mikula and Parsons 1991) Nicol and Smitham (1990) reported that in the case of Australian export coals they are sold with a nominal top size of 5 cm but as was discussed earlier there is a wide range of size distributions covered by this specification Figure 10 shows the broad range of coal sizes that are exported This implies that the potential dustiness of coal is a variable with coal source Sherman and Pilcher (1938) have done considerable work in the area of dust control and have tested the size of dust particles in the ASTM D547 dust cabinet test and found that the diameters of particles range from 11 to 55 11m Devised in the 1930s the test is perceived to be somewhat dated as it was originally designed to simulate coal delivery into a bin
Nicol and Smitham (1990) investigated the effects of moisture on the lift-off potential of different coals over a range of wind velocities using a laboratory wind tunnel facility They found that depending on the coal size fraction the velocity to remove wet particles was between 25 and 75 greater than the dry particle removal velocity Alternatively the amount of coal removed at a given velocity is reduced as the moisture content increases Figure 11
99
80
E 60 -E 7 40
if ro 0
20 0
N middotw 10 m 0 c 5J
shaded area encompasses 90 of export coals with coarsest (lower) and finest (upper) size disributions also shown
0125 025 05 2 4 8 16 315 63 Particle Size mm
Figure 10 Size distributions of Australian export coal (Nicol and Smitham 1990)
illustrates the effect and shows that a critical moisture content of about 9 in the coal can be reached at which coal removal can be largely prevented The effects of different coals show up most clearly in the moisture content to prevent any dust emission that is the intercept on the moisture axis in Figure 10 Table 13 summarises the results for the three coals of different properties Rank and chemical properties such as volatile matter content are poor indicators of the propensity for different coals to dust Porosity as reflected in the moisture holding capacity does provide a useful indicator of the potential dustiness of coal Coals with a low moisture holding capacity that is a low equilibrium moisture have little internal porosity so that once this internal volume is filled the excess water remains at the particle surface where it is available to form bridges of water between adjacent particles preventing their removal in an air stream High moisture capacity coals require a greater amount of water to fill the internal volume before water is available at the surface to be an effective dust control agent Jensen (1992)
2000
o
N
E Oi ui Cf)
g Cii 0 ()
Q) gt ~ S E J u
1500
1000
500
0
0
0 0
0 0
amp0
0 ~ 0
0 0
0
0
o 2 4 6 8 10 12
Total moisture
Figure 11 Coal lift-off from a stockpile as a function of total moisture content (Nicol and Smitham 1990)
Table 13 Effect of coal properties on critical lift-off moisture content (Nicol amp Smitham 1990)
Coal Critical moisture Reflectance Australian coal Moisture holding content Ro max rank nomenclature capacity
1 100 094 high volatile bituminous A 25 2 115 120 medium volatile bituminous 40 3 210 073 high volatile bituminous A 120
66
35
Pre-combustion performance
reported that work carried out by ELSAM Denmark has shown that coals with a sUlface nwisture content of 2-3 was sufficient to prevent dusting of some coals
314 Oxidationspontaneous combustion
All coals when stored tend to combine to some extent with oxygen from the air in a process known as weathering (Davidson 1990) This causes some loss of heating value generally less than 1 in the first year of storage for most coals but may be up to 3 for low rank coals - and can change firing characteristics (Singer 1989a) Weathering also tends to promote reduction in size or crumbling (Llewellyn 1991)
Llewellyn (1991) also reported that grindability tests carried out on both fresh coal supplies and the coal stored on the surface of a stockpile indicated a clear separation in behaviour Surface samples were reported as being significantly harder (average 43 HGI) to grind than the fresh coal supply samples (average 52 HGI) The hardness increased with the age of the stockpiled coal A similar clear separation was found between the surface and the interior of the stockpile
Oxidation releases heat and if conditions in the stockpile are such that it occurs at a sufficiently rapid rate enough heat can be generated to cause spontaneous combustion (Sebesta and Vodickova 1989)
In brief the coal properties that have been found to influence oxidation and spontaneous combustion are
rank (heating value or volatile matter) moisture content ash content particle size
Malhotra and Crelling (1987) reported that as the rank of coals decreases the susceptibility for spontaneous combustion increases Cacka and others (1989) suggested that this phenomenon may be related to the increasing content of aliphatic structures which have a higher propensity to react with oxygen than aromatic structures present in coal However there are many anomalies to this straight rank order susceptibility Chamberlain and Hall (1973) have in fact pointed out that some higher rank coals may be more susceptible to spontaneous combustion
The mechanism of water adsorption into the pores of coal also releases heat so that heating in a stockpile will be dependent to some extent upon the inherent moisture (Matsuura and Uchida 1988 Iskhakov 1990) In most cases excess moisture can suppress the heating process (Taraba 1989) although cases have been reported where addition of water to an overheating stockpile can exacerbate the problem and these have been discussed in greater detail in a review by Chen (1991)
The mineral matter composition of coals can influence their susceptibility to oxidation Dusak (1986) reported incidents where mineral matter can play the role of oxidation
promoters by increasing oxidation rate and heat emission due possibly to exothermic reactions of the mineral matter itself with oxygen Work by Cacka and others (1989) determined that iron and titanium were particularly active in the coals under investigation Nemec and Dobal (1988) reported the influence of pyritic sulphur The magnitude of the influence on the oxidation process depends upon mineral matter size and its dissemination within the coal along with the rank moisture content and size of the coal
Particle size influences the surface area available for oxidation Several workers have reported that the smaller the particle size the greater the heat build up within coal stockpiles (Brooks and Glasser 1986 Nemec and Dobal 1988 Llewellyn 1991)
A number of tests have been devised to assess the extent of oxidation of a coal and its susceptibility to spontaneous combustion These include
crossing point test This measures the ignition temperature of a coal sample when it is heated at a constant temperature rate in a small cylindrical furnace The ignition temperature is measured as that at which the coal temperature crosses or becomes greater than the furnace temperature (Brown 1985) This can also be known as the runaway temperature (Gibb 1992) Differential thermal gravimetric analysers and calorimeters are also used to carry out a similar form of test (Clemens and others 1990 Shonhardt 1990) free swelling index test (see also Section 25) Shimada and others (1991) used free swelling index to monitor the extent of weathering of coals in a stockpile The swelling index of a Polish coal (K11) was seen to decrease significantly after a short storage time of three months (see Figure 12) It could also be used to distinguish between coal samples taken from the body (K11) of the coal stockpile and those from the slope (K11 slope) The test can only be applied to coals that exhibit a high initial swelling index as some coals with low initial swelling index (such as Kl in Figure 12) do not give any perceptible change after storage spectroscopic techniques Berkowitz (1989) has reviewed the spectroscopic methods utilised to detect oxidation of coal These can include Fourier transform shyinfra red (FTIR) spectroscopy electron spin resonance (ESR) nuclear magnetic resonance (NMR) and fluorescence microscopy (pavlikova and others 1989 Bend 1989)
Most of the above tests are not standardised With the exception of FSI which is generally used as an indicator of the caking nature of coals they usually are not included in a typical coal specification
At present none of the above effects can be quantified accurately The overall impact on operation and any required modifications must be based primarily on experience The influence of coal quality on the spontaneous combustion of the coal can be minimised by careful layout and construction of the stockpiles
36
Pre-combustion performance
bull 6
--- K1
0 K11
x L K11 slope 5 0
(]) 0 4 0 ~
0OJ sect 3CD ~ 0
(f)
2
L ~ - - - - - - - - - - - - 1f - - - - - - - - - - -- - - - - - shy II I
o 3 5 7 9 11 13 15 17 30 40 50 60 70
Storage time months
Figure 12 Influence of storage time on swelling index (Shimada and others 1991)
The special requirements for low rank coal storage are reviewed in an lEA Coal Research report entitled Power generation from lignite (Couch 1989)
32 Mills Most large steam-electric units are direct fIred that is the coal is supplied to the mills and is pulverised continuously with direct pneumatic transport of the pulverised coaVair mixture to the burners Thus the performance of the mills has a direct effect on the performance of the unit In modern practice a single mill can supply several burners In tangentially fIred systems all four bumers on a single elevation are typically supplied by a single mill In wall fIred systems a single mill may supply a complete row or another symmetrical array of burners A common design practice is to size systems to achieve full load with one or more mills out of service This allows time for maintenance and allows the spare mill to be brought on-line in the event that a failure occurs in one of the other mills
Because of their heterogeneous nature coals used for combustion can exhibit a wide range of grindabilities and require different milling actions to produce a suitably sized product Fine grinding of coal - generally 70 or more passing 75 11m (200 mesh) - is the standard commonly adopted to assure complete combustion of coal particles and to minimise deposits of ash and carbon on heat absorbing surfaces (Carmichael 1987) The different mill designs can be classified according to speed
low-speed mills are of the balVtube design with a large rotating steel cylinder and a charge of hardened balls Coal grinding occurs as the coal is crushed and abraded between the balls medium-speed mills are typically vertical spindle designs and grind the coal between rollers or balls and a bowl or face There are a number of designs in service differing in the specific design of the equipment which rotates size and shape of the grinding elements etc high-speed mills have a high-speed rotor which impacts and breaks the coal
Table 14 Preferred range of coal properties (Sligar 1985)
Mill type Low speed
Maximum capacity tJh 100 Turndown 41 Coalfeed top size mm 25 Coal moisture 0-10 Coal mineral matter 1-50 Coal quartz content 0-10 Coal fibre content 0-1 Hardgrove grindability
Medium High speed speed
100 30 41 51 35 32 0-20 0-15 1-30 1-15 0-3 0-1 0-10 (0-15)
index 30-5080 40-60 60-100 Coal reactivity low medium medium
The range of properties listed above is a preferred range and operation outside these limits is possible
Numerical values for the preferred range of coal properties appropriate for each mill type are given in Table 14 Most large steam-electric units use balVtube or vertical spindle mills
Coal mills integrate four separate processes all of which can be influenced by coal characteristics
drying grinding classifIcation transport
321 Drying
Earlier mills used external dryers before the coal was fed to the mills placing an economic disadvantage on the system Internal drying was developed to overcome this The surface moisture of the coal must be evaporated in the mill to avoid agglomeration of the particles (Sadowski and Hunt 1978) As the primary air is used for conveying the coal the only variable for drying is the temperature of this air The primary air temperature is adjusted to achieve a mill discharge temperature high enough to ensure complete drying in the
37
Pre-combustion performance
Table 15 Maximum mill outlet temperatures for vertical spindle mills (Babcock amp Wilcox 1978 Singer 1991)
Maximum temperature degC (OF)
Coal Babcock amp Wilcox Combustion Engineering
High volatile 66 (150) 71-77 (160-170) bituminous
Low volatile 66-79 (150-175) 82 (180) bituminous
Lignite 49-60 (120-140) 43-60 (110-140)
grinding zone For example Table 15 lists the maximum mill discharge temperatures recommended by Babcock amp Wilcox and Combustion Engineering The discharge temperatures are fixed for safety reasons and are dependent on coal type For bituminous coals the value is usually between 65degC and 90degC with the lower value for fuels of high volatility to reduce the potential for mill fires Higher temperatures of over 100degC have been reported to be used in some cases (Jones and others 1992) Standard proximate analysis volatile matter tests have been used to provide some indication of the likelihood of spontaneous combustion High volatile matter coals are more reactive and more susceptible to spontaneous combustion under these conditions
The primary air temperature required to dry the coal depends on several factors including its moisture (or ice) content temperature and specific heat together with airfuel ratio and mill design The required air temperature may be calculated via a simple energy balance (Folsom and others 1986b)
Figure 13 shows the effect of coal moisture on primary air temperature requirements for vertical spindle mills manufactured by Babcock amp Wilcox and Combustion Engineering As the moisture content of the coal increases so the inlet air temperature must increase to compensate Increases in the coal moisture content can impact unit capacity if the primary air supply system cannot provide air at a high enough temperature It should be noted that to
provide more heat to the drying process the aircoal ratio can be increased However the aircoal ratio affects classifier performance and other downstream operations such as burner performance pulverised coal transport and wear in the coal supply system These effects must be considered Increasing the air temperature increases the potential for mill fires since dry coal particles especially those recycled from the classifier may come into contact with the high temperature air entering the mill
Low-speed mills are most sensitive to coal surface moisture content The capacity of these mills falls in an approximately linear manner with increase in moisture content The decrease in mill capacity is of the order of 3 for each 1 increase in coal surface moisture This effect is present because of the use of a lower airfuel ratio with these mills lower primary air temperature and less efficient mixing within the mill body Medium- and high-speed mills are not nearly as sensitive to high moisture coal
322 Grinding
The size consistency of the coal feed has a direct effect on the power requirements of the mill (see Section 632) All three types of mill are affected by coal feed top size Table 14 gives the critical feed top size for all three types of mill Low-speed mills are particularly sensitive to coal top size Mill capacity falls in a regular manner with increase in coal feed top size In addition to the top size the overall particle size distribution is also of significance In all cases the presence of excessive proportions of fines in the feed to the mill acts to the detriment of the full output
The fineness required is usually related to the rank of a coal the higher the rank of the coal the fmer the particle size distribution needed to achieve satisfactory combustion that is an increase in fmeness with decreasing volatile matter content The approximate size ranges which are acceptable for coals of different rank to ensure complete combustion are shown in Table 16 Analysis of the combustion process shows that burnout is a function of the proportion of particles over 100 1JlIl rather than the amount less than 75 -Lm It is to be expected that increasing the 200 IJlIl oversize from 1 to
Table 16 Comparison of fineness recommendations ( passing 200 mesh -75 11m) (Babcock amp Wilcox 1978 Cortsen 1983)
Babcock amp Wilcox specification ASTM classification of coals by rank
Fixed carbon Fixed carbon below 69
Type of furnace 979-86 (petroleum coke)
859-78 779-69 BtuI1b gt13000 (gt303 MJkg)
BtuI1b 12900-11 000 (300-256 MJkg)
BtuI1b lt11 000 (lt256 MJkg)
Water-cooled 80 75 70 70 65 60
ELSAM Denmark specification
Volatile matter content dry ash-free () lt10 10-20 20-25 gt25
Water-cooled 85 80 75 70
38
Pre-combustion performance
Eastern USA coals (Combustion Engineering)
80a C leaving mixture temperature
H 2 0 entering-leaving
300 14-20
o 12-20 a
10-20
8-20
6-15
4-15
2-10
Babcock amp Wilcox
3000 a
(i100 CIl ~
gt 3
3 4 5 Cl
9 (1)kg of air leaving millkg of coal a 200 lt1l Cii Cl E
Midwestern USA coals (Combustion Engineering) 2 ill
nac leaving mixture temperature ~
laquo 100
JI 24-70 entering-leaving
22-65
26-75 H 0
~ 2
20-60
18-60300 shy16-55
o 2 4 6 8 1014-50 12-50 kg of coalkg of air
10-45 8-40
6-40
100
2
~
OJshysect
pound 0 ~
ES
2 3 4 5
kg of air leaving millkg of coal
Figure 13 Primary air temperature requirements depending on moisture content and coal type (Babcock amp Wilcox 1978 Singer 1991)
39
ie curve is unreliable in this area
60 lt75 ~m
lt75~m
lt75~m
90 lt75 ~m----shy
25 50 75 100
Pre-combustion performance
2 would have a much more significant increase on bumout than decreasing the under 75 lm from 70 to 65 Oversize particles are believed to contribute to slagging problems in boilers although there are no adequate correlations to relate particle size distribution to the incidence of slagging (Babcock amp Wilcox 1978 Singer 1991) The use of low NOx combustion strategies has required a policy of finer grinding for some coals in order to offset the increased unbumt carbon found in the fly ash (Heitmiiller and Schuster 1991)
The ease by which a coal can be ground within a particular type of apparatus is termed its grindability The most common measurement is the Hardgrove grindability index (HGI) (see Section 25) The HGI is widely accepted as the industry standard for evaluating the effects of coal quality on mill performance for high rank coals (Babcock amp Wilcox 1978 Singer 1991) The rated capacity of a mill is defined as the amount of coal (tlh) that can be ground to a fineness of 70 through a 75 lm sieve using a coal with HGI of 50 or 55 Mill manufacturers tend to be divided on how mill capacity is determined for a particular coal Some provide correlations relating the HGI of the coal to mill output for each standard mill size Other manufacturers depend on assessments made in proprietary small test mills or full size mill tests with large samples to give more confidence to anticipated performance of mills with the specification coal(s) With the multitude of mill designs available there is no reason to expect that the capacity of each type should be related to HGI according to any universal relationship
The Hardgrove test is limited in its application as it is a batch operation which is then related to a continuous process Mills
are air swept so that as comminution proceeds fine particles are quickly removed from the grinding elements whereas they remain in the grinding zone in the Hardgrove machine (Hardgrove 1938)
Values of HGI for coal lie in the range 25-11 O Within the range of 42-65 HGI is probably a good indicator of grindability providing the other properties (moisture specific energy etc) are considered Outside this range confidence in HGI is not so good (see Figure 14) Many attempts have been made to correlate HGI with coal composition (Singer 1991) but whilst there is a general trend with coal rank as seen in Figure 15 the scatter is enormous For example the HGI for high volatile bituminous A coals range from 30 to 75 a factor of 25 The scatter could be accounted for by the distribution of macerals in the coal (Fortune 1990) The milling properties of the different maceral types can give rise to segregation of macerals within particular size ranges For example vitrinite tends to be more brittle than exinite or inertinite and is usually concentrated in the finer fraction of the milled coal (Falcon and Falcon 1987 Conroy 1991) In addition vitrinite and exinite are more reactive than inertinite so that a greater concentration of inertinite will generally be found in the unbumt fuel than in the parent coal Inertinite also tends to concentrate in the larger particle size ranges where its lower reactivity has a noticeable effect on bumout It should be noted that this will depend on the different forms of inertinite as some types are more reactive than others (Bailey and others 1990) These observations are dependent greatly on maceral distribution within the coal Macerals in some coals occur in discrete layers whereas in others (for example South African coals) they can occur as intimate associations (Falcon and Ham 1988) The distribution as
20
16
ist5 12 2 2shy0 ro g- 08 ()
04
o
curves extrapolated to zero capacity usefull range for
(HGI =13) curves
range in which bituminous coals are found
Hardgrove grindability index (HGI)
Figure 14 Variation in capacity factor with HGI for different fineness grinds (Fortune 1990)
40
Pre-combustion performance
o
o o
bull Ball mill indexes
Hardgrove tests converted to equivalent Ball mill indexes
bull bull 0
ltlOl 0
etgtz l 2 2
100 - o o o
90
o80
a 70S xOl U ~ 60 pound 0 ro 50 U sect 01 Ol 40 gt e -e01 bull ro 30 I U 0 m
en enJ J Jroen middot0 middot020 Olen Olen ~ 0 0 degoJ _J _J ro ro c c 0 oen len~ gt 0 0 J c cmiddotE middotE EJ~ roc roc gtJ
C middot02 CEo
3 omiddotE omiddotE o~ ro10 3 0 _
Eg cp ro eO2 ~~~ gtJ gtJ middot~middotE gtEmiddotc 0 0 J c~ middotE c
0 0 uJ 3J Q)ouo 010 010 Ol- C01 J J Jc 0middot Ol =i Cf) Cf) Cf)roU Im Iltl ~o -10 Cf) ltl ~
0 9 10 11 12 13 14 15 16 70 80 90 100
Moist mineral-matter-free MJ Dry mineral-maller-free fixed carbon
Figure 15 HGI for several coals as a function of rank (Elliott 1981)
described will effect the particle composition and other coal to 77 and mainly in the 60 to 70 range In general such coals physical properties These effects cannot be predicted from would not be expected to cause difficulty with grinding proximate analysis and so could account for discrepancies in the anticipated performance of coals having similar The abrasive properties of a coal and especially its associated proximate analysis values but with different petrographic minerals cause wear of the grinding elements and other compositions surfaces in the mill The extent of this wear determines the
intervals between planned maintenance periods and the Grinding of coal blends in which the components have possibility of shutdowns It is therefore of great importance widely different HGI values have shown that care is required for an operator to have an idea of how long these periods are in the interpretation of the results Byrne and Juniper (1987) likely to be and how unplanned outages caused by excessive observed that in such cases the harder material tended to mill wear can be avoided concentrate in the coarser fractions of the pulverised fuel and the softer coal in the finer fractions It was believed that this Wear is caused by one of four mechanisms (Fortune 1990) was a consequence of the softer coal blanketing the harder coal and so preventing full grinding of all the fuel adhesion
surface fatigue One difficulty with HGI is reproducibility BS ISO and AS1M abrasion standards all state that a spread of three units is acceptable This corrosion is equivalent to a 4 change in mill capacity Comparisons from different laboratories have given a reproducibility of Adhesion and surface fatigue effects in milling are negligible around eight to nine (Fortune 1990) This is equivalent to a mill compared with abrasion and corrosion capacity variation spread of 12 which is clearly unacceptable as an indication of grinding performance The rate of abrasive wear in mills will depend in general on
the following factors Attempts have been made to develop alternative grindability indices but so far none of these has attained widespread use the type of coal used especially the amount and Typical of these is the continuous grindability index (CGI) composition of the incombustible minerals associated which relates mill performance to power input It was with the coal developed for low rank coal applications A new method has the material used for the mill rolls and bowls also been proposed for determining coal grindability and the design of the mill abrasivity properties using a single machine by Scieszka (1985) although it should be noted that this work was based The most widely used abrasion test is the Yancey Geer and on a limited range of coals with HGI values ranging from 39 Price (YGP) test (Yancey and others 1951) although its
41
Pre-combustion performance
repeatability varies with coal characteristics For abrasive coals the repeatability is about 3 However for coals with low abrasiveness repeatability may be as low as 18 Babcock Energy Scotland use a similar test but with a smaller coal sample (Cortsen 1983) Babcock amp Wilcox in the USA has developed an abrasion test using a radioactive tracer technique (Goddard and Duzy 1967) This test produces a measurement of mill wear albeit at a laboratory scale
Literature data indicate that coal itself is not very abrasive (Parish 1970) Of the associated minerals usually present in coal only quartz (SiOz) and pyrite (FeSz) are considered to be hard enough to cause significant wear Other minerals mainly clays are generally quite soft and friable and do not contribute much to mill wear The earlier studies have shown some correlation between wear and quartz or pyrite content of the coal but the correlations obtained were generally not widely applicable (Parish 1970) In investigations carried out by Donais and others (1988) it was found that as well as the total amount the size of the quartz and pyrite grains significantly affected the wear rate The study was carried out on eight different US coals using NIHARD rolls in both Babcock amp Wilcox and Combustion Engineering mills In general the data indicated that the coarser fractions of quartz and pyrite contribute more to mill wear than the finer size fractions The best correlation between the data was as described in the following expression
Abrasion (radial wear per tons of throughput) =F (3 Q+ P)
where F = constant
Q = ( Quartzgt100 Ilm) P = ( Pyrite gt300 Ilm)
Donais and others (1988) found that the intercept of the curve from the above relationship on the Y axis (mill wear) was well above zero indicating that the effect of the finer fractions of the quartz and pyrite are not negligible and that the coal itself or other minerals may also contribute to wear It should be noted that the size distribution of pyrite and quartz are not normally measured and are not usually included in coal specifications
Other experimental techniques for abrasion testing are summarised in an early report by Parish (1970)
Erosion by mineral particles picked up in the air stream carrying pulverised coal through the mill classifier and ducting is a recognised problem The following parameters affect erosion rates
stream velocity - erosion rate increases exponentially with velocity For ductile materials the exponent is about 23 for brittle materials the exponent ranges between 14 and 5 impingement angle on mill surfaces - maximum erosion rates occur at 30deg for ductile materials and at 90deg for brittle materials particle size - erosion rates increase with particle size up to a critical size above which no increase is observed
323 Size classification and transport
Reduction in oversize particles after initial milling is achieved by separation and recycling of particles through the mill to be reground until they are sufficiently small to pass through a classifier The classifIer can be adjusted to vary the final fineness of the coal Coal fineness affects essentially all processes occurring downstream of the mill including ignition flame stability flame shape ash deposition char burnout etc However if the classifier is adjusted for greater fineness to accommodate for example the firing of a lower volatile coal (see Section 41) the amount of material recycled back to the grinding zone increases This alters the grinding process and if the coal mass in the grinding zone increases too much the grinding elements may begin to skid or excessive spillage can occur The initial coal particle size and grindability can affect the fine tuning of the classifier
The primary air flow rate to the mill is based on the requirements of the burner mill and pulverised coal transport At full load the air flow rate usually corresponds to an aircoal mass ratio of about 20 For a given size of pipes the air flow rate can be adjusted over a narrow range only without causing de-entrainment of PF or increasing pipeline wear for lower or higher rates respectively For a given mill for example ring ball type roller mills supplied with design coal and having 20 of total air as primary air at full load the calculated coalair ratio changes from about 05 kgkg to about 036 kgkg by reducing load from 100 to 50
The relationship between primary air flow rate and coal flow rate is established by the mill manufacturer Moisture content of the coal determines the necessary primary air temperatures as discussed earlier in Section 321 Moisture content of the coal may therefore influence effective and accurate transport of the coal through the mill
33 Fans Coal fired steam-electric units use a number of fans to move air flue gas and pulverised coal The major type of fans include
forced draft (FD) fans - supply air to the wind box under positive pressure induced draft (ID) fans - withdraw flue gas from the furnace and balance furnace pressure primary air (PA) fans - supply air to the mills flue gas recirculation (FGR) fans - recirculate flue gas from the economiser outlet to the burners or the wind box
The performance of the fans can be impacted by changes in coal quality
A typical arrangement of the major fans at a steam-electric unit is illustrated in Figure 16 The major path flow involves the FD and ID fans It should be noted that the fan arrangement shown in Figure 16 is not fully representative of all coal fired steam-electric units The number and arrangement of the fans and other components can vary substantially Also the pressures and temperatures of the air
42
Pre-combustion performance
air FD forced draft exhaust to FGR flue gas recirculation stack - - - - - - flue gas 10 induced draft
-----_ _-- coalair PA primary air I
1_1I __ Tempertures are approximate and may vary with plant design and operating parameters ambient air I EMISSION I
PA HEATER (air side)
PULVERISERS
-
I PA 1 FAN
-
I CONTROL I I EQUIPMENT
--T-shyt 150degC
AIR HEATER (air side)
( V
I
EMISSION CONTROL
EQUIPMENT
air heater leakage
--------+--------shy
AIR HEATER (gas side)
I
r------ -----jI
I 3700C 1 I
CONVECTIVE COLLECTOR
FGR OUST
_PA__S_ __ 2DC
1 370degC
FGR FAN FUR~ACE
g
__roaka 0I 3700C
- - - - - -+ - - - - ~ - - - -~ - - shy
wind box
burners~bullbullbullbull ------------- bullbullbull ----------- ---- bullbull ------ bullbullbull -------------- bullbull - --- bullbull --shy
Figure 16 Typical utility boiler fan arrangement (Folsom and others 1986c Sligar 1992)
43
Pre-combustion performance
entering the fans depend on the overall plant design Thus to change in flow rate required evaluate the impact of coal quality on fan capacity it is change in system resistance necessary to specify the details of the fan design and change in fan inlet conditions operating characteristics as well as the power station change in rate of fan erosion arrangement To evaluate fan capacity only the characteristics at maximum performance settings need be The flow rate through the fan could be changed in a number considered of ways by changes in coal quality For example an increase
in coal moisture will increase the flue gas volume flow rate Changes in coal characteristics can impact fan performance Changes in heating value of the coal would require a change in four ways to the airfuel ratio and hence the firing rate The excess air
Table 17 Summary of the effects of coal properties on power station component performance - I (after Lowe 1987)
Property Contributing properties Effect
Coal handling and storage Heating value
Coal flow properties
Freezing
Dustiness
Combustibility (spontaneous combustion)
Mills
Drying
Mill throughput
Wear
Fans Flow rate
moisture ash ultimate analysis
moisture coal size distribution mineral matter analysis bulk density
types of moisture
moisture size analysis mineral matter analysis porosity
coal rank moisture size distribution sulphur
moisture
volatile matter
total moisture
Hardgrove grindability index (HGI)
raw coal top size
pulverised fuel size
distribution
mineral matter analysis (quartz amp pyrite) mineral matter size distribution
moisture slagging propensity fixed carbon
A 1 decrease in heating value increases required mass throughput of coal by 1
As flow properties degrade coal throughput remains relatively constant until catastrophic blockages occur at a critical flow property value This value is highly site specific
Surface moisture at low temperatures is the primary cause of freezing
Increased operating and maintenance costs with dusty coals Potential for increased loss of availability
Heating value of stockpiled coal decreases due to spontaneous combustion Plant layout and procedures are dictated by spontaneous combustion
MiD type
Low speed Medium speed Influences primary air requirements and power consumption for both types of mill Mfects the susceptibility of both mill types to mill fires
-3 throughput for 1 moisture -15 throughput for 1 increase moisture increase above
approx 12 moisture -1 throughput for 1 unit -1 throughput for 1 reduction in HGI unit reduction in HGI Caution when using HGI for interpreting coal blend behaviour -3 throughput for 5 mm increase No loss in throughput below in top size 60 mm top size Reduction in fraction passing Reduction in fraction passing
lt75 JlII1 mesh screen by 035 for lt75 Ilm screen by 09 for 1 increase in throughput 1 increase in throughput Influences the component operation and maintenance rate for both types of mill
An increase in moisture increases the flue gas volume flow rate Influences the excess air requirements
44
Pre-combustion performance
required for a specific coal depends on the slagging propensity of the coal carbon burnout and boiler steam temperature considerations These effects are difficult to predict and the actual value of excess air used is determined by the operators to achieve the best balance
The system resistance can also be affected in a number of ways For example fouling of the convective pass increases ID fan resistance on units with induced or balanced draft (Folsom and others 1986b) Fly ash loading in the flue gas can influence the performance for example increased fan blade erosion can occur with increased quantities of fly ash (Sligar 1992)
34 Comments Table 17 summarises the effects of coal properties on the performance of the power station components discussed in this chapter It has been shown that whilst many empirical
relationships have been developed and used to describe the problems that are encountered in the power station there are some signifIcant uncertainties related to many assumptions made These can include for the components described in Chapter 3 the following
coal handling and storage - oxidation dusting flowability and freezing cannot be predicted from coal composition measurements mills - there is no way to evaluate the fineness requirements accurately Mill capacity for blends of coals and for lower rank coals are difficult to evaluate using existing HGI correlations fans - air and gas flow rates depend on excess air Excess air depends on flame stability carbon burnout and slaggingfouling considerations There is no satisfactory method of predicting the effect of these relationships for specific coals Twenty per cent excess is often assumed
45
4 Combustion performance
41 Burners For ignition to take place four elements must be present
fuel air sufficiently high temperature ignition energy availability
A pulverised fuel burner solves this task by blowing a mixture of pulverised coal and air into a part of the furnace where there is a high temperature When lighting up the burner this high temperature is secured locally with an ignition system The burner itself however must be designed in such a way that a stable flame is achieved after the ignition flame is extinguished and it must be able to keep the flame stable and provide optimum combustion The loss of a flame on tum-down even within normal control ranges constitutes a serious dust explosion hazard (Cortsen 1983) Sustained combustion without support fuel also requires consistent coal quality Pockets of high ash can cause momentary extinction and subsequent risk of explosion when fuel returns
A number of physical and chemical processes occur extremely rapidly within the flame It is difficult to describe the number of interactions and complexity of the reactions occurring In spite of many years of theoretical flame research burner design is still based on practical experience though in more recent years this has been supplemented with pilot- and full-scale experiments (Knill 1987 Noskievic and others 1987 Harrington and others 1988 Kosvic and others 1988 Repic and others 1988 Penninger 1989)
Ignition stability is strongly influenced by the characteristics of the coal The conventional method of evaluating the impact of coal characteristics has been to consider the volatile content of the coal and the presence of inert material (moisture and ash) However even if two
coals have the same proximate analysis their ignition characteristics may still be very different due to differences in chemical structure
There are three distinct groups of coal with respect to ignition according to Truelove (1985)
lignites and subbituminous coals with high inherent moisture and high volatile matter content greater than 50 bituminous coals with proximate volatile matter content between 20 and 50 anthracite and semi-anthracite with volatile matter content less than 20
Notwithstanding the high volatile matter content low rank coals can still be difficult to ignite because the high moisture lowers the flame temperature and dilutes the volatilesair mixture The energy required to evaporate 15 moisture and superheat it is equal to the energy required to heat the coal material to 500degC When the moisture content exceeds 40 the coal can be dried using hot flue gas with the result that the primary coaVair stream is heavily loaded with inert water vapour and products of combustion In contrast to the difficulties associated with the ignition of low rank coals the char resulting from high-moisture high volatile matter coals is generally highly reactive
Low volatile coals are much more difficult to ignite In these cases the heat released during the combustion of volatiles is usually insufficient to raise the temperature of the char to ignition and hence sustain combustion It may be necessary to provide continuous support fuel to maintain combustion Ignition stability with low volatile coals can be enhanced by grinding the coal finer and using high preheat for the combustion air Table 16 shows recommendations for pulverised coal fineness based on the volatile matter content (Cortsen 1983) Bituminous coals with volatile contents above 25 should present few problems with ignition
46
Combustion performance
Modem independent burners all use strongly swirling air flows to achieve flame stability and control flame length and width and combustion intensity The application of swirl produces short and intense flames Although excess swirl especially in the primary stream may delay ignition due to rapid mixing of the primary coaVair stream with the relatively cool combustion secondary air
The effect of ash on flame stability has been studied at the International Flame Research Foundation (IFRF) in the Netherlands No significant differences in ignition and flame stability were found when firing 6 ash and 30 ash high volatile coals provided that the fuel was well mixed and delivered to the burner at consistent quality
In the efforts to cut NOx emissions virtually all the combustion-equipment manufacturers are involved in the development of low NOx coal burners Many utilities already utilise the technology Intensive research has focused on the formation of NOx which is influenced greatly by combustion conditions This is discussed further in Section 523
42 Steam generator The ability of the steam turbine to generate power at full capacity depends on an adequate supply of steam at the correct temperature and pressure The steam supply and quality is dependent on the heat release occurring in the furnace and the heat transfer from the resulting gases to the various boiler surfaces located in radiant and convective banks
The effects of coal characteristics on boiler heat transfer and ultimately steam conditions are complex and closely related to the arrangement of large steam generators Factors such as the layout of radiative and convective heat transfer surfaces in the gas side and location of boiling and non-boiling regions on the steam side are critical This section considers how coal characteristics can affect both heat release and heat transfer processes via the mechanisms of fuel combustion and ash deposition
421 Combustion characteristics
Insight into the influence of coal properties on pulverised coal combustion can be gained by examining the factors affecting combustion There is an extensive amount of literature which reviews the work carried out in the field of pulverised coal combustion An lEA Coal Research report Understanding pulverised coal combustion by Morrison (1986) reviews the literature mainly post 1980 on the fundamental processes and mechanisms of pulverised coal combustion Others include reviews by Laurendeau (1978) Essenhigh (1981) Smoot (1984) Smoot and Smith (1985) Heap and others (1986) and Singer (1991) Only a brief description will be given here
The combustion of individual coal particles comprises the following sequence of processes which are partly overlapping and are all dependent on both physical conditions and coal properties
heating of the particle
release of volatile matter combustion of volatile matter combustion of the char
Heating of the particles occurs very quickly The temperature gradient is 105_106degCs depending on the size of the particle Thus a 60 lm particle may achieve furnace temperature within 005-01 s
Release of volatiles occurs within the similar time span but varies with coal quality and particle size The initial gases released ignite and bum momentarily consuming the oxygen present in the air surrounding the particle At this stage the volatiles bum independently of the char particle The devolatilisation of coal at high heating rates is an important stage because it may control
the rate at which combustion proceeds the rate at which oxygen is consumed the rate and form of evolution of nitrogen sulphur and other species together with the mechanisms governing the fate of these species
Depending on temperature and coal quality char combustion may be initiated before combustion of all volatile constituents is completed For successful combustion the heat release associated with the gas-phase reaction must raise the bulk gas temperature sufficiently to ignite the char The rate of char combustion is dependent upon several factors
initial coal structure variations diffusion of reactants reaction by various species (02 H20 C02 H2) particle size effects developed pore diffusion char mineral content (catalysis) changes in surface area as the reaction proceeds char fracturing variations with temperature and pressure
The time required for consumption of a char particle represent a significant portion of the overall time required in the coal reaction process and can range from 03 s to over 1 s (Smoot 1984)
The watersteam temperature balance in a boiler is influenced greatly by the burning profile of the coal that is the rate at which coal passes through the different stages of combustion the heat release associated with them and take-up by watersteam (Singer 1991) During combustion gas temperatures are near 1800degC but the gases must cool to the design point temperatures (usually around 1200degC) of the convective sections of the boiler so that they may be maintained in a satisfactory condition of cleanliness (see Section 422) If the coal bums too quickly
too much heat may be absorbed in the radiant section of the boiler When the gases subsequently reach the superheater tubes they may be too cool to raise steam temperature to the levels necessary for efficient turbine operation and full capacity utilisation temperatures at the radiant section can rise too high and
47
Combustion performance
cause circulation problems or increased boiler slagging (see Section 422) thus raising the incidence of forced outages
If the coal bums too slowly temperatures in the radiant section do not reach design levels and gases reaching the superheater tubes may be hotter than l200dege Thus there can be a decrease in boiler efficiency through
decreased steam production fouling of superheater tubes (see Section 422) increased carbon loss loss of superheater temperature control increased risk of fires in the economiser hopper air heater and particulate control system higher than desired exit temperature of exhaust gases
Many attempts have been made to establish empirical correlations between combustion behaviour and coal properties The volatile matter content is most commonly used as an indicator for ignition behaviour of a particular fuel Similarly heating value and ash content provide a guide to flame stability
The heating value of the coal is important as it constitutes the amount of energy that can be imparted to the system Moisture and total ash content act as negative influences to the energy supply by affecting the adiabatic flame temperature and firing density
The combustibility or reactivity of a coal can be characterised by two factors (Wall 1985a)
volatile matter yield and composition (Jiintgen 1987a Morrison 1986 Saxena 1990) reactivity of char - char reactivity generally increases with decreasing rank in PF combustion (Smith 1982 Morgan and others 1987) so that the rate of combustion is similarly dependent on rank (Shibaoka and others 1987 Jiintgen 1987b Oka and others 1987) However Cumming and others (1987) and Bend (1989) found that rank was not an accurate guide for high volatile bituminous coals from different origins The amount of char produced has been shown to be related to the proximate analysis fixed carbon content petrographic composition and initial coal particle size
An index that relates both of the parameters above is the fuel ratio that is fixed carbon divided by volatile matter as determined by proximate analysis can be used as a measure of coal reactivity The fuel ratio provides an indication of the relative proportion of char to volatiles Although correlations between the fuel ratio and carbon burnout have been found (for example Baker and others 1987) there are exceptions (Oka and others 1987) A higher fuel ratio does not necessarily indicate a coal of lower reactivity and high carbon burnout (Figure 17) This is not surprising since both volatile matter and fixed carbon determinations relate to laboratory test conditions which do not represent the conditions encountered in PF boiler As was discussed in Section 21 proximate volatile yield is generally lower than the true volatile yield as it is sensitive to test conditions
20
C----------) indicates trend reversal
These comparisons 10 contradict the rule that a higher fuel ratio necessarily means higher unburnt carbon and lower reactivity
Coal sized to +125-150 Ilm 5
Peak temperature 1300degC
2
10
c o 0 CB U
c 05s
0 c J
02
01 -t----------+-------------
05
Fuel ratio fixed carbonvolatile matter
Figure 17 Fuel ratio as an indicator of coal reactivity (Smith 1985)
(Morgan 1987) Similarly proximate fixed carbon makes no allowance for the differing reactivity of chars formed from different coals (Oka and others 1987 Smith 1982) Fuel ratio has also been found to be unsuitable for assessing low rank coals
Many utilities have found that volatile matter content information alone is a poor indicator of coal furnace performance they are tuming to the use of advanced test methods Further test procedures have been developed by boiler manufacturers and utilities which give a better insight into the influence of coal properties on combustion characteristics For example thermal gravimetric analysis (TGA) may be used to evaluate the characteristics of coal with respect to particle coal heating and volatiles ignition It should be noted however that TGA test conditions can also differ largely from the conditions present in a PF boiler An example of a TGA test requires a coal sample to be heated at
10 20 40
48
Combustion performance
a controlled rate in a controlled environment The weight loss of the sample is recorded continuously as a function of time (or temperature) The burning profiles determined in TGA are often used as a characteristic fingerprint for a coal These will be compared to a standard coal with an established boiler performance (Cumming and others 1987 Morgan and others 1987) The TGA can also be used to determine the reactivity of coal chars prepared in situ or in other test apparatus such as drop tube furnaces (DTF) or entrained flow reactors (EFR) (Jones and others 1985 Morgan and others 1987 Crelling and others 1988 Hampartsoumian and others 1991)
The DTF or EFR apparatus can also be used to determine the reactivity of coalschars under a range of conditions The apparatus can be utilised under conditions similar to those experienced in a boiler In these tests a consistently higher extent of volatile release is measured than in the volatile matter test of the proximate analysis (Morrison 1986 Knill 1987 Gibbs and others 1989) Carbon burnout can be determined along with the reaction rates for the different stages of combustion (Wall 1985b Skorupska and others 1987 Tsai and Scaroni 1987 Diessel and Bailey 1989 Smith and others 1991a Chen and others 1991) This topic has also been reviewed by Unsworth and others (1991)
Other apparatus used for volatile matter release rates and coalchar reactivity determinations include the heated wire grid apparatus flat flame burners pyroprobe and pilot scale furnaces
All these tests provide data on the devolatilisation and combustion characteristics of coal in considerably more detail than the data provided by standard proximate analysis The boiler manufacturers have developed methods of utilising the test data to predict boiler performance However it should be recognised that these tests are used subject to individual choice and interpretation They are not widely accepted in the utility industry as standards Currently the tests results are meaningful only in the context of a background database for a particular installation which includes accumulated measurements on fuels in the specific test facilities as well as field operating systems The most direct method of utilising the tests would be to compare the performance of specific coals to a base coal whose performance in the subject boiler is well documented In cases where such an approach is not practical it is necessary to rely on laboratory data and modelling to extrapolate the results to full scale However the test procedures particularly in the case of DTF apparatus are complex and since the test facilities have been used primarily as research tools there are no accepted standards
422 Ash deposition
Ash deposition is one of the most important operational problems associated with the efficient utilisation of coal (lEA Coal Industry Advisory Board 1985 Jones and Benson 1988) Since deep cleaning of coal is expensive (Couch 1991) ash is present in all coal-fired furnaces and must be carefully controlled
Equipment manufacturers have used several approaches for
108wx 106d 126 w x 124 d
D D D L wxd 116wx108d
r130 h
U Eastern Western Lignite
bituminous subbituminous coal coal
Siagging propensity low-medium high severe high Fouling propensity low-medium high high high
Midwest (Illinois)
bituminous coal
Furnace size is also affected by coal heating value - moisture - volatile matter
Figure 18 Influence of ash characteristics of US coals on furnace size of 600 MW pulverised coal fired boilers (Babcock amp Wilcox 1978)
ash management to accommodate effective collection and disposal of the deposit Dry and wet bottom furnaces utilise very different operational conditions to achieve this goal (Hatt 1990) Most pulverised coal units that are offered today are of the dry bottom type although wet bottom or slagging bottom furnaces may still be offered for special applications
Since the presence of ash is unavoidable coal-fired power stations are designed to tolerate some deposit on tube surfaces without undue interference of unit operation Knowledge of ash deposition tendencies of coals is important for boiler manufacturers as boiler design features can be varied to accommodate difficult coals Figure 18 describes how one manufacturer accommodates various ash characteristics by adjustment of furnace dimensions and the number of deposition removal systems such as wall blowers The criteria of several utility boiler manufacturers for designing boilers to avoid deposition have been reported by Barrett and Tuckfield (1988) It was observed that each manufacturer applied a different set of criteria and placed different emphasis on the coal analyses details used for prediction of ash depositional behaviour
The occurrence of extensive ash deposits can create the following problems in a boiler
reduced heat transfer - due to a reduction in boiler surface absorptivity and thermal resistance of the deposit impedance ofgas flow - due to partial blockage of the gas path in the convective section of the boiler
49
Combustion performance
physical damage to pressure parts - due to excessive loading of the structures andor impact damage when pieces of the deposit break off and fall down through the furnace corrosion ofpressure parts - due to chemical attack of metal surfaces by constituents of ash erosion ofpressure parts - resulting from abrasive components of fly ash
If the deposits cannot be removed by wall blower or soot blower operation the load on the boiler may have to be reduced to lower furnace temperatures to the point where ash softening is controlled and wall andor soot blowers become effective It is not unusual to observe power stations that must drop loads to about one-third of capacity at night to shed slag accumulated during high-load day time operation (Barrett and Tuckfield 1988) In extreme cases the boiler
Extraneous minerals
must be shutdown and the deposit removed by hand Frequent maintenance and unscheduled shutdowns for removing these deposits and the repair of the effects of corrosion and erosion add substantially to the cost of power generation These problems can result in reduced generating capacities and in some cases costly modifications (Bull 1992)
Deposit problems within a boiler are classified as either slagging or fouling Different definitions of slagging or fouling are used by different people Some people refer to the nature of the deposit - defining molten deposits as slagging and dry deposits as fouling Others define slagging and fouling by the section of the boiler on which the deposit occurs (Borio and Levasseur 1986) For the purposes of this report slagging refers to deposits within the furnace and on widely spaced pendant superheaters in those areas of the unit
bull pyrite 1100degC --------- fusion clays 1300degC
quartz 1550degC
~ expansion
~
Inherent minerals
bull M cenospheres
Y
Na K Heterogeneous 8 ~ condensation Mg ~
80 Homogeneous I __ nucleation
MgO coalescence
surface enrichment
coalesce~--------------I~~ euroY-----~ bull 30~m
p~QD~--- quench ---1~~ ~Qi) 10-90 ~m
disintegration
~
Figure 19 Mechanisms for fly ash formation (Wibberley 1985b Jones and Benson 1988)
50
Combustion performance
which are directly exposed to flame radiation Fouling refers to deposits on the more closely spaced convection tubes in those areas of the unit not directly exposed to flame radiation
Ash slagging and fouling give rise to the first four problems listed above The fifth problem erosion is the result of the impingement of abrasive ash on pressure parts Often coal ash deposit effects are inter-related For example the build up of ash deposit layers on tube walls and superheaters does not only reduce furnace and overall boiler efficiency but can also increase the temperature level in furnace and convective passages and aggravate existing deposit problems The characteristics of the deposit layer change so as to reduce the heat transfer to the surface locally the gas temperature in the furnace will rise partially ameliorating the impact However the net effect is that furnace deposits (slagging) decrease the heat transfer in the radiant furnace and increase the furnace exit gas temperature This can lead to enhanced fouling problems in the convective pass if the ash particles enter the convective tube bundles in a sticky state Ash deposits accumulated on convection tubes can reduce the cross-sectional flow area increasing fan requirements and also creating higher local gas velocities which accelerate fly ash erosion In situ deposit reactions can produce liquid phase components which are instrumental in tube corrosion
The coal ash deposition process involves numerous aspects of coal combustion and mineral matter transformations reactions The importance of the furnace operating conditions on the combined results of the above areas must also be stressed For a given coal composition furnace temperatures combustion kinetics heat transfer to and from the deposit and residence times generally dictate the physical and chemical transformations which occur (Barrett 1990) The ash formation process is therefore dependent on the timetemperature history of the coal particle and the heterogeneous nature of the mineral matter in coal Each pulverised fuel particle may behave uniquely as a result of its composition Figure 19 summarises the mechanisms for fly ash formation
The ash transported through the combustion system only becomes a problem if it is first transported to the heat transfer surface and subsequently sticks to that surface Particle size particle density and shape affect transport behaviour (Borio and Levasseur 1986)
In addition to transport phenomena the three requirements for the formation of deposits from a gas stream containing inorganic vapour and fly ash are (Wibberley 1985b)
the vapours and fly ash penetrate the boundary layer of the tube and contact the metal surface the material adheres to the tube surface sufficient cohesion occurs in the deposit to allow continued growth without periodic shedding under the influence of its own weight vibration soot blowing temperature cycling in the furnace etc
The initial deposit layer is significant as it represents the boundary between the tube metal or rather oxide and the remainder of the deposit Adhesion between the tube and the
first deposit forming material from the fumace gases may involve several factors
surface attraction between the fine ashcharged ash and the tube inherent roughness of the tube which is increased by oxide whisker growth or growths of desublimed alkalis liquid phases on the tube surface formed by supercooling of condensing alkalis reactions involving desublimed alkalis or alkalis pyrrhotite fly ash sulphur compounds and the tube metal to form low melting point complex salts such as Na3Fe(S04)3 Tm = 627degC sticky fly ash particles with either supercooled sodium silicates or condensed alkalis on the surface of the ash and species migration through the deposit
As the deposit thickens the temperature at its outer surface increases at the rate of 30-100degCmm depending on the thermal conductivity of the deposit and the local heat flux to the deposit (Wibberley 1985a) The increasing temperature decreases the viscosity of any liquid phases present which in tum increases the retention of larger fly ash particles impinging on the tube and also the rate of deposit consolidation by sintering and sUlphation
As the size of the fly ash retained at the deposit surface increases its surface becomes increasingly irregular (secondary deposit layer) The rate of deposition is highest where the deposit extends furthest into the oncoming gas stream This causes projections to form Continued growth of the deposit depends on simultaneous growth and consolidation Consolidation involves sintering and sulphation which are enhanced by the increasing temperature in the outer regions of the growing deposit
Siagging Slagging deposits typically form on the water wall section of boilers near the burner region In this region the water wall tubes surfaces are typically in the region of 200degC to 425degC (400degF to 800degF) a temperature too low for mineral matter to form molten deposits The fireside layer of a slagging deposit may consist of a running fluid in which all the fly ash has dissolved or it may consist of a glassy phase impregnated with particles of fly ash (Bryers 1992) Formation of slagging deposits is a time dependent phenomenon Situations are commonly encountered within a boiler where initiation of slag deposits in one region of the boiler will propagate to other regions of the boiler as the heat transfer through the water wall tubes is continually reduced and the temperature of the flame and the deposit increases This influence on heat absorption has been demonstrated using pilot combustor facilities to monitor the effect and rate of deposit build up on heat flux on panels designed to simulate boiler water wall surfaces (Abbott and Bilonick 1992) Figure 20 shows the average per cent heat flux recovery for soot blowing cycles at two different coal firing rates for a range of US coals The work demonstrated that the ash deposits from different coals prove to have a range of tenacities as demonstrated by the different values of heat flux recovery
Determination of the elemental composition of slagging deposits in comparison with equivalent compositions of fly ash have
51
Combustion performance
1 washed Pittsburgh seam - medium sulphur 2 run-at-mine Pittsburgh seam - medium sulphur 3 Pittsburgh seam - low sulphur 4 Pittsburgh seam - high sulphur 5 Illinois No 6 seam - low sulphur 6 Roland seam 7 60 Roland40 Illinois No 6 - low sulphur blend
Figure 20 Heat flux recovery for different coals and soot blowing cycles (Abbott and Bilonick 1992)
shown that there is enrichment of some elements in the deposit (Borio and Levasseur 1986) The results of such an analysis are shown in Table 18 This analysis shows some depletion of silica (Si02) alumina (Ah03) and lime (CaO) in the deposit and an increase in hematite (Fe203) In some cases direct impaction of unspent pyrite on hanger tubes and the leading edge of the first row of convection bank tubes can cause an iron-rich deposit to form that is 75-90 Fe203 in the deposited ash The deposit is semi-fused as pyrrhotite and is further oxidised to hematite or magnetite While bulk analysis of deposits on water wall tubes can give an insight into the formation of the deposits still more information can be gained from chemical analysis of different layers within the deposits which are seldom homogeneous and vary with time
Wain and others (1992) have also illustrated that slag
deposits from different UK coals can exhibit a range of chemical and physical properties At one extreme the slag may be highly porous and friable having little mechanical strength while at the other extreme the slag deposit may be dense and fused with great strength Susceptibility to removal processes was shown to be related to the porosity of the slag formed which in tum is dependent upon ash composition and operating conditions Earlier work indicated that the physical state of the deposit can have a significant effect on the radiative properties In particular molten deposits show higher emissivitiesabsorptivities than sintered or powdery deposits (Goetz and others 1978) Thin molten deposits are less troublesome from a heat transfer aspect than thick sintered deposits However molten deposits are usually more difficult to remove and cause frozen deposits to collect in the lower reaches of the furnace where physical removal can no longer be carried out with wall blowers
Fouling In all coal-fired units ash deposits build up on the convective pass tube bundles due to the flow of the particulate laden flue gas over the tubes The boiler manufacturers attempt to design their units to avoid the uncontrollable build up of deposits in this region Fouling problems occur when the strength of the deposits is high and the action of soot blowers is unable to remove the deposits It should be noted that with fouling there is no analogue to the wet bottom approach to slagging that is units cannot be designed to accommodate fouling problems by ensuring that the ash deposits are removed from the convective pass tubes as liquids
As with slagging the bonding of ash particles to the tube surface depends on the physical state of the particles approaching the tubes and wetting action of the ash on the tube surface However in the convective pass the temperature difference between the particles (and gas) and the tube surface is much less than in the radiant furnace so that the quenching action of the particles impacting the tube surface is greatly reduced
Organically-bound sodium and sodium chloride are most frequently the cause of convective bank fouling in low rank coals and bituminous coals respectively (Osborn 1992) As discussed earlier many of the alkali metal compounds in coal
Table 18 Enrichment of iron in boiler wall deposits - comparison of composition of ash deposits and as-fired coal ashes (Borio and Levasseur 1986)
Unit sample Power station 1 Power station 2 Power station 3
As-fired Waterwal1 As-fued Waterwal1 As-fired Waterwal1 coal ash deposit coal ash deposit coal ash deposit
Ash composition Si02 470 333 502 551 497 418 Ah03 267 180 169 146 165 158 Fe203 146 435 59 183 120 285 CaO 22 12 128 72 65 90 MgO 07 05 35 20 09 09 Na20 04 02 06 05 11 06 K20 23 16 08 06 15 09 Ti02 13 08 09 08 11 07 S03 11 05 120 01 20 02
52
Combustion performance
vaporise readily at typical furnace temperatures They form hydroxides or oxides that react with S03 in the gas phase at the tube surface to form sodium sulphate They can react with ash particles to form low melting point eutectics or can nucleate on the surface of ash particles or tubes Thus alkali metal compounds can lead to sticky deposits on the tube surfaces Generally sodium and calcium sulphate dominate the initial layer of deposits As the deposits build up in thickness they can sinter into a strong fused mass They may include other ash particles completely encapsulated with calcium and sodium sulphate crystals The sintering process may be related to diffusion of materials through the deposits and solid phase reactions
As in the case of slagging fouling deposits also are not uniform but are built in layers of material which can differ in particle size and chemical composition
Corrosion Corrosion of the furnace wall tubes has resulted in metal depletion rates of 600 nmh or more compared to normal oxidation rates of about 8 nmh (Brooks and others 1983) Such severe corrosion drastically reduces the lifetime of the tubes and may lead to unexpected failure Fumace wall corrosion of steel tubes has been observed in virtually all types of pulverised coal boilers In extreme cases the result is tube failure and large scale requirements for replacement (Clarke and Morris 1983 Blough and others 1988) Currently corrosion is no longer the primary cause of forced boiler shutdowns owing to control strategies and regular maintenance However remedial measures are quite costly and current efforts seek to reduce this cost by substantially extending maintenance intervals (Flatley and others 1981)
The mechanisms which govern the corrosion of the furnace wall tubes are not well understood (Harb and Smith 1990) Corrosion behaviour is closely linked to conditions in the furnace Fireside corrosion can occur on both water walls and superheater tube surfaces Water wall corrosion results essentially from regions of persistent local substoichiometric combustion near the walls which may be due to coal devolatilisation andor inadequate coalair mixing The resulting low partial pressure of oxygen and a high partial pressure of sulphur (as H2S and S02) cause the formation of scales containing iron sulphides Sulphide scales grow more rapidly than the corresponding oxides They are less protective and can lead to increased stress when formed in an existing oxide scale This promotes rapid spalling of the tube surface (Wright and others 1988) Other species believed to participate in corrosion reactions include HCI This is formed on volatilisation in the flame Flatley and others (1981) postulated that HCl reacts with the outer scales of the previously formed protective oxide to create gaseous microchannels through which HCl gains access to the metal surface Once at the surface the HCI reacts with the iron to form a volatile iron chloride which is then transported back toward the bulk furnace gases The reducing environment is also known to lower ash fusion temperatures and increase mineral deposition which in turn can affect corrosion behaviour
Corrosion often occurs in definite patterns associated with the direction of the flame and has been linked to flame impingement (Borio and others 1978) Flame impingement
again creates severely reducing conditions high heat fluxes and leads to the generation of corrosive species Evidence exists that severe furnace wall corrosion of carbon steel is a consequence of poor local combustion associated with flame impingement and the delivery of unburnt coal particles to the tube surface (Flatley and others 1981) Strategies to limit NOx formation in some boilers can increase the likelihood of corrosion owing to the presence of reducing environments and enlargement of the flame zone (Chou and others 1986)
On higher temperature metal surfaces such as superheaters and reheaters two main causes of corrosion are
overheating which leads to accelerated oxidation of both fireside and steam side deposit related molten-salt attack
The latter form of corrosion can be related directly to the chemistry of the coal being burned and the steam (wall) temperature Molten salt attack concerns the development of conditions beneath a surface deposit which are conducive to the formation of a low melting salt ofthe type (NaK)3Fe(S04)3 These alkali-iron trisulphates form by reaction of alkali sulphates deposited from the flue gas with iron oxide on the tubes or from the fly ash in the presence of S03 (Shigeta and others 1987) The minimum melting point for these salts occurs at 552degC (1026degF) This type of corrosion has been associated with the presence of alkali metals sulphur and iron in coal
Chlorine can also be a contributing factor towards superheater metal corrosion if sulphate content is low While exact mechanisms can be argued there have been both liquid phase and gas phase corrosion when chlorides have been present (Latham and others 1991b Daniel 1991)
Calcium and magnesium which may also be found in coal mineral matter are known to be anticorrosive elements which inhibit the formation of alkali-iron trisulphates This is particularly true for acid-soluble calcium and magnesium contents which have an inhibiting ability for liquid-phase corrosion by forming a solid sulphate in the deposit for example calcium sulphate (Blough and others 1988) Work by Shigeta and others (1987) showed from corrosion tests that the corrosion rates were influenced by anti-corrosive elements (see Figure 21)
c 4 co E 0
-0 3E ( ()
Q 2 1 OJ
Qj
5
o 4 8 12 16
Contents of CaO and MgO
Figure 21 Effect of CaO and MgO on corrosivity deposit (Shigeta and others 1987)
20
53
Combustion performance
Erosion Erosion due to fly ash is recognised as the second most important cause of boiler tube failure (Dooley 1992) Considerable effort is being spent to understand the mechanism of fly ash erosion and to acquire the capability to predict erosion rates due to fly ash in boilers Fly ash is more erosive compared to the coal from which it originates one reason being the absence of the soft organic fraction
Table 19 Hardness of fly ash constituents (Nayak and others 1987)
Constituent Mohs Vickers Hardness kgmrnz
Mullite Vitreous material Free silica (quartz) Hematite Magnetite Coke particles with inherent and surface ash
Fume sulphate particles Anhydrite (CaS04)
5 550-600 7 1200-1500 5-6 500-1100 5-6 500-1100
3-5 100-500 (non-abrasive)
Erosion occurs at the outlet of the furnace section where the flue gas is made to tum over the top of the boiler while traversing pendant tube banks and in the rear pass especially on the sections of horizontal tube banks adjacent to the back wall of the rear pass (Wright and others 1988) Fly ash size and shape ash particle composition hardness and concentration and local gas velocities play important roles concerning the erosion phenomenon Table 19 lists the available data on hardness values of fly ash particles (Nayak and others 1987) The hardness characteristics of the major mineral contents in fly ash have not been studied extensively Work by Raask (1985) and Bauver and others (1984) has shown that quartz particles above a certain particle size are very influential in the erosion process and that furnace temperature history plays an important role in determining erosive characteristics of the particles
Many of the above phenomena discussed under the headings of Slagging Fouling Corrosion and Erosion have standard tests such as ash fusibility (see Section 25) as the basis for predicting their occurrence These bench-scale tests provide relative information on a coal which is used in a comparative
fashion with similar data on fuels of known behaviour Unfortunately although commonly used they do not always provide sufficient information to permit accurate comparison
The fusibility temperature measurement technique attempts to recognise the fact that mineral matter is made up of a mixture of compounds each having their own melting point (see Table 20) As a cone of ash is heated some of the compounds melt before the others and a mixture of melted and unmelted material results The structural integrity or deformation of the traditional ash cone changes with increasing temperature as more of the minerals melt However use of ash fusion data can be misleading Ash fusion tests typically are run in both a reducing and oxidising environment This means there is either sufficient oxygen in the atmosphere surrounding the ash particles to oxidise various minerals or there is not Generally an oxidising environment pertains throughout the combustion chamber of the boiler For a number of reasons there may be moments when as the coal and mineral particles pass through the combustion chamber there is not enough oxygen for oxidation to occur This is known as a reducing environment It is important to be aware of these conditions since if a reducing environment develops the ash fusion temperatures are lower than those occurring in oxidising conditions and can become low enough to cause slagging and fouling
The problems with ash fusion measurement is that recent results indicate that significant meltingsintering can occur before initial deformation is observed The fact that the timetemperature history of the laboratory ash is quite different from the conditions experienced in the boiler can result in differences in melting behaviour In addition the ash used in this technique may not represent the composition of the ash deposits that actually stick to the tube surfaces Often there is a major discrepancy between the composition of as-fired ash and that which is found in the deposits The discrepancies between fusion temperature results and actual slagging performance are usually greater on ashes that may look reasonably good in the laboratory One can usually assume with reasonable confidence that the melting temperature of the water wall deposits will be no higher than measured fusion temperatures although they can be and often are lower This is because deposition of lower melting constituents can and does occur with a resulting enrichment of lower melting material in the deposit Bearing all of these points in mind it is difficult to show confidence in this test as a predictor of performance
Table 20 Properties of some coal ash components (Singer 1991)
Element Oxide Melting temperature degC
Si SiOz 1716 Al Ah0 3 2043 Ti TiOz 1838 Fe Fez03 1566 Ca CaO 2521 Mg MgO 2799 Na NazO sublimes at 1276 K KzO decomposes at 348
54
Chemical Compound Melting property temperature degC
acidic NazSi03 877 acidic KzSi03 977 acidic Ah03NazO6SiOz 1099 basic Alz03KzO6SiOz 1149 basic FeSi03 1143 basic CaOFez03 1249 basic CaOMgO2SiOz 1391 basic CaSi03 1540
Other tests such as ash viscosity measurements suffer from shortcomings These tests are conducted on laboratory ash and on a composite ash sample Viscosity measurements are less subjective and more definitive than fluid temperature determination for the assessment of ash flow characteristics The usual procedure for assessing slag viscosity for wet bottom furnaces is to correlate the temperature at which the viscosity of coal ash slag is 250 poise This is defined as T250 Viscosities for dry bottom furnaces are usually conducted at higher temperatures These values can also be calculated from ash analysis Thompson and Gibb (1988) reported that in a study of nine UK coal ashes with a high iron content the slagging propensities as determined by ash viscosity tests was broadly in keeping with expectations though four of the samples showed contradictory behaviour During pulverised coal firing a severe problem may already exist before slag deposits reach the fluidrunning state Generally only a small quantity of liquid phase material exists in deposits and it is the particle-to-particle surface bonding which is most important
Tests utilising the electrical resistance properties of ash have also been developed and these are perceived as being superior to the standard ash fusibility test for providing an indicator of the onset of ash sintering (Cumming 1980 Lee and others 1991)
Much use is also made of the ash composition which is normally a compilation of the major elements in coal ash expressed as the oxide form Coal ash can be classified as one oftwo types viz
bituminous-type Fe203 in ash is greater than the sum of CaO + MgO in ash lignitic-type Fe203 in ash is less than the sum of CaO + MgO in ash
From the compilation of elements expressed as oxides from the ash analyses judgements are often made based on the quantity of key constituents like iron silicon aluminium and sodium
Using the results obtained from a standard ash analysis the measured oxides can be separated into basic and acidic components (see Table 8 and Table 20) The acidic components are those materials which will react with basic oxides They include Si02 Ab03 and Ti02 The basic ash constituents are those materials which will react with acidic oxides They include Fe203 CaO MgO Na20 and K20 The base to acid ratio is the ratio of the sum of the basic components to the sum of the acidic components Baseacid ratios are used as indicators of ash behaviour normally lower melting ashes fall in the 04 to 06 range It has been shown that baseacid ratios generally correlate well with ash softening temperatures so although baseacid ratios have helped explain why ash softening temperatures varied it has not improved the predictive capabilities (Borio and Levasseur 1986) Other ratios such as FeCa and SiAI have been used as indicators of ash deposit behaviour Ratios like these have helped to explain deposit characteristics but their
Combustion performance
use as a prime predictive tool is questionable especially since these ratios do not take into account selective deposition nor do they consider the total quantities of the constituents present An FeCa ratio of two could result from weight per cent ratios of 63 or 3015 the latter numbers would generally indicate a far worse situation than the former but the ratio does not show this
Many of the slagging and fouling indices described earlier in Table 8 are based upon certain ash constituent ratios and corrected using such factors as geographical area sulphur content sodium content etc One commonly used slagging index uses both BaseAcid ratio and sulphur content Factoring in sulphur content is likely to improve the sensitivity of this index to the influence of pyrite on slagging (As previously discussed iron-rich minerals often play an important role in slagging) However the use of such correction factors is often a crude substitute for more detailed knowledge of the fundamental ash properties Another example of this is the use of chlorine content in a coal as a fouling index This can be valid as a general rule if the chlorine is present as NaCI (thereby indicating the concentration of sodium which is an active form) and that the sodium will in fact cause the fouling Chlorine present in other forms mayor may not adversely affect fouling
Sintering strength tests have been used as an indication of fouling potential Assuming that correct ash compositions have been represented (which is less of a problem in the convection section than in the radiant section) worthwhile information may be obtained relative to a timetemperature versus bonding strength relationship Again in order for sintering tests to accurately predict actual behaviour it is necessary that tests be conducted with ash produced under representative furnace conditions (timetemperature history) (Kalmanovitch 1991)
The conventional analyses and developed indices may provide indications for limited parts of the coal spectrum but they share a flaw in that they take their point of departure in the end composition of the ash without taking account of the original minerals and intermediate products formed and transformed in the combustion zone (Cortsen 1983)
Information concerning the mineral forms present in the coals and the distribution of inorganic species within the coal matrix can be extremely important in extrapolating previous experience since the nature of the inorganic constituents contained in the coal can be the determining factor in their behaviour during the ash deposition process (Borio and Levasseur 1986) Generally speaking newer bench-scale techniques can be more sensitive to the conditions that exist in commercial furnaces than the older predictive methods Selective deposition for example has been recognised as a phenomenon which cannot be ignored More attention is being paid to fundamentals of the ash formation and deposition processes The use of new analytical techniques could give results that allow mineral matter to be identified according to composition mineral form distribution within the coal matrix and grain size Techniques such as computer-controlled scanning electron microscopy (CCSEM) scanning transmission electron microscopy
55
Combustion performance
Table 21 Summary of the effects of coal properties on power station component performance - II (after Lowe 1987)
Property Contributing properties Effect
Burners and steam generator Volatile matter
Ultimate analysis
Fuel ratio
Moisture
Slagging propensity
Furnace wall emissivity
Fouling propensity
carbon hydrogen nitrogen
fixed carbon volatile matter
ash elemental analysis ash fusion temperatures coal particle mineral analysis
ash elemental analysis wall deposit physical state
ash elemental analysis active alkalis (sodium amp potassium) ash fusion temperatures
Special burner design for flame stabilisation required below a dry ash-free volatile content of 25
Air requirements are affected by ultimate analysis unit increase of CIH ratio increases air requirements per unit heat release by 08
A 006 increase in efficiency loss due to unburnt carbon for 10 increase in fuel ratio at ratio of 16
A 1 increase in moisture decreases boiler efficiency by 025 requiring a proportional increase in firing rate
Slagging propensity generally ranked as low intermediate high or severe Response to slagging propensity is a function of unit thermal rating
Furnace wall emissivity is typically 08 a decrease of 1 will increase furnace outlet gas temperature by 16degC
Fouling propensity ranked low to severe Response to slagging propensity and is highly unit specific
(STEM) and X-ray diffraction can be used to characterise these properties on an individual particle basis New spectroscopies such as extended X-ray absorption fine structure spectroscopy (EXAFS) and electron energy loss spectroscopy (EELS) are capable of determining the electronic bonding structure and local atomic environment for organically associated forms of calcium sodium and sulphur Other new techniques such as Fourier transform infrared spectroscopy (FTIR) electron microprobe electron spectroscopy for chemical analysis (ESCA) all provide methods of improving present capabilities Thermal gravimetric analyses (TGA) and drop tube furnaces (DTF) have been used to characterise mineral matter decomposition and prepare ash samplesdeposits under near-boiler conditions respectively For example Benson and others (1988) have used a laminar flow DTF to study the formation of alkali and alkaline earth alumino silicates during coal combustion
A cautionary note though should be added here as many of the new techniques are still primarily focused on small fragments of the overall deposition process in order to permit manageable controlled studies in the laboratory Unfortunately the results are all too often not re-integrated in order to understand the total process But it cannot be doubted that a knowledge of the effects of the
aforementioned coal qualities is essential to avoid expensive delay in any changes to operational conditions in order to rectify deposition problems once they arise Information of performance in test reactors could also help to implement counter strategies to prevent the occurrence of deleterious incidents forewarned is forearmed
43 Comments Table 21 summarises the effects of coal properties on the performance of the power station components discussed in this chapter Whilst many empirical relationships have been developed and used to describe the problems that are encountered in the burner and boiler region of the power station it has been shown that significant uncertainties relate to many of the assumptions involved Flame shape and stability and char burnout cannot be predicted with certainty on the basis of coal composition data Correlations for slagging fouling erosion and corrosion have been shown to be inadequate
Power station operators still consider the problems of slagging fouling corrosion and erosion to be of greatest concern In view of this these subjects are the attention of a number of studies and have been reviewed extensively It is recognised that this topic merits a more extensive review than could be incorporated in this study
56
5 Post-combustion performance
51 Ash transport
The mineral matter entering with the coal exits the power station in the following five streams
mill rejects bottom ash economiser ash particulate collection system flue gas
The distribution between these streams depends on the power station design and operation as well as the coal composition Figure 22 shows a typical distribution However as described below this distribution may vary substantially
Most direct-fired mills have provision to reject pyrite extraneous material and excess coal introduced into the mill Under normal operating conditions the mass of the material rejected is a negligibly small fraction of the total coal flow rate However as the flow rate of coal into the mill is increased toward maximum capacity the amount of rejects increases Thus there is no effective way of estimating the effect of coal composition on mill rejects The mill reject system is typically oversized and would not be expected to limit mill operation except under unusual circumstances or where mill capacity is exceeded
The amount of ash removed at the bottom of the furnace is typically about 20 of the total ash content of the coal However the mass of bottom ash is difficult to measure accurately It may be estimated by measuring the mass of ash exiting with the flue gas and subtracting this from the ash entering the boiler with the coal However the errors of such an analysis procedure are considerable and the calculated mass of bottom ash may even be negative The factors which are probably the most important for determining the fraction of ash in the bottom ash are the design of the firing system the coal fineness bulk
velocities in the furnace and slagging Coal qualities that would directly influence these factors are
ash in the coal grindability of the coal slagging propensity of the fly ash
Due to the uncertainty in the mass of the bottom ash the handling system for the material is typically designed with considerable excess capacity Most systems operate intermittently so that an increase in bottom ash may be accommodated by an increase in duty cycle
The composition of the coal ash has an impact on the characteristics of the material captured as bottom ash Dry bottom furnaces are designed to maintain the ash in the hopper in a powdery non-sticky state The powdery ash slides down the hopper walls into the collection tank at the bottom of the furnace IT the ash has a low fusion temperature it may stick to the hopper or build up to running slag This material can accumulate at the bottom of the hopper and plug the hopper exit Solid slag deposits may fall from water walls higher in the fumace causing similar problems Wet bottom furnaces are designed to operate with running slag The slag must have a viscosity low enough to flow into the collection tank where it is quenched in water and shatters into small particles Typically the slag viscosity should be in the range of 250 poise at 1426degC (2600degF) for adequate fluidity (Babcock amp Wilcox 1978) If the viscosity increases plugging of the hopper bottom can occur similar to dry bottom furnaces
The strength of the ash can affect bottom ash system operation Many bottom ash systems are equipped with clinker grinders to reduce the size of the slag particles IT the slag particles are sufficiently large or strong they can disable the clinker grinder All the problems described above are related to the coal ash chemistry that is whether a fluid slag is formed and operating conditions
57
1-----++---------shy--
Post-combustion performance
Based on coal 10 ash 2791 MJkg
Unit 500 MW 1055 MJkWh
Mass kgkJ
Mass
Flow rate th
Coal ash
Mill rejects
Bottom ash
Economiser ash
Cyclone ESP
baghouse
Stack emissions
358
1000
1905
003
10
019
072
200
381
018
50
095
261
734
1398
002
06
012
Figure 22 Typical ash distribution (Folsom and others 1986c)
Occurrences of ash hopper explosions have been reported (Stanmore 1990) The exact mechanism for the explosions has not been elucidated Hypotheses of the cause include
chemical explosions involving iron-rich ash thermal explosions resulting from rapid quenching of falling hot deposits inducing a pressure wave within the water thermal explosion within the ash hopper causing entrainment of unburnt coal which then ignites to produce a secondary blast
Stanmore (1990) reports that work so far in this field has failed to uncover any boiler feature hopper type or coal composition which was common to all explosions investigated Corner-fired and wall-fired units experience the problem with both bituminous and subbituminous coals Both low and high ash content coals were involved with both high and low ash fusion temperatures
Ash-related explosions involving residual carbon in the ash can result from unfavourable furnace conditions which can occur during a cold start of a boiler Moreover variation in initial coal size can lead to poor grinding efficiencies giving rise to a wide pulverised coal size distribution and hence incomplete coal combustion (Stanmore 1990 Wol1mann 1990)
Most of the ash particles captured in the economiser hopper
are large because they are shed from the convective pass tube bundle deposits by the action of gravity flue gas flow rate or soot blowing The amount of ash varies with the fouling characteristics of the coal and cannot be predicted easily Economiser ash disposal systems are typically designed to handle about five per cent of the coal ash The presence of unburnt carbon in economiser ash can impact the operation of the collection system Poor coal reactivity can lead to high carbon content in the ash The carbon can continue to burn in the hopper and fuse the powdery material into a large mass which cannot flow from the hopper easily
Most of the ash exits the boiler as fly ash and is captured in particulate control equipment which may include cyclones ESPs fabric filters (baghouses) or scrubbers
52 Environmental control Since the early 1970s mandatory control of power station emissions has significantly increased the cost of generating electricity (CoalTrans International 1991) Initial concerns were focused on particulate emissions and have led to the development of efficient particulate removal systems Environmental concern about the use of coal is particularly tuned to the problem of emissions of SOx NOx and C02 to the atmosphere Trace elements are receiving increasing attention from the scientific and electric power communities who are attempting to evaluate the potential impact of trace
58
elements on the environment (Clarke and Sloss 1992) There is also the problem of disposal of the solid residues which are obtained from power stations
The capital and operating costs of emission control hardware can account for up to 40 of a power stations operating expenses (Cichanowicz and Harrison 1989) Increasingly coal-fired utilities are realising that in order to comply with ever tightening emission regulations their environmental control strategies must include adequate control of coal quality Emission control strategies related to coal quality can include
coal switching coal blending coal cleaning control of emissions during combustion post-combustion emission control
The impact of coal quality on emission control hardware has not been studied extensively Additional constraints in some cases are applied to coal quality during coal selection as a result of the implementation of emission controls
The following sections briefly review the emission control technologies available and attempts to highlight the coal characteristics and other considerations that affect the selection or efficient use of emission control systems
521 Coal cleaning
Historically coal has been cleaned to maintain specifications for delivered fuel quality and to reduce transport costs Coal cleaning benefits are usually greatest for coals which have to be transported over long distances to the point of use Conventional coal preparation plant mainly uses methods developed at least forty years ago Nevertheless in recent years there have been major advances in instrumentation and control which have resulted in reduced costs and greater consistency in the cleaned product
Utilities also have the option to incorporate coal cleaning strategies on site High mineral matter high sulphur coals could be purchased at lower prices and cleaned on site to boiler-related specifications The decision to implement this type of strategy is dependent essentially upon three factors
cost savings achieved by coal cleaning feasibility of residue disposal
Coal cleaning costs depend upon the initial cleaning plant capital costs cleaning plant operations and maintenance and the value of lesser-quality coal discarded in the cleaning process In general coal cleaning capital costs average about five per cent of the cost of the power station using the coal Direct operating costs are determined by labour consumables and power Discarded coal can account for as much as 50 of total cleaning costs (Cichanowicz and Harrison 1989)
Savings achieved by coal cleaning depend upon the depth of
Post-combustion performance
cleaning instigated (Elliott 1992) A review by Couch (1991) entitled Advanced coal cleaning technology provides a technical overview of recent developments in coal cleaning methods The fuel characteristics most significantly changed by cleaning are
mineral matter content and distribution sulphur content and form heating value
Reducing the mineral matter impurities and sulphur in the coal can have a signifIcant affect on a coals abrasiveness reduce ash loadings by up to 93 and potential S02 emissions by as much as 70 (Hervol and others 1988) Moreover coal cleaning can reduce environmental control costs by lowering the quantity of fly ash and S02 that must be removed after combustion Coal cleaning permits smaller and therefore less expensive flue gas processing equipment reduces reagent quantity and decreases the amount of solid waste requiring disposal Cleaned coal can improve station heat rate by reducing auxiliary power for flue gas handling systems and allowing lower air heater exit temperature thus increasing boiler efficiency Pilot scale combustion tests conducted by Cichanowicz and Harrison (1989) showed that boiler efficiency was greatly improved by coal cleaning as shown in Table 22
Table 22 Summary of coal cleaning effects on boiler operation (Cichanowicz and Harrison 1989)
Characteristics Run-of-mine Medium Deep coal cleaned cleaned
coal coal
Moisture 17 17 16 Sulphur 38 37 20 Ash 235 71 35 Heating value MJkg 2338 3103 3266 Flue gas S03 7 4 3
concentration ppm Air heater exit 136 120
temperature degC Boiler efficiency 884 901 Flue gas volume 6
reductionsect
dried sect includes flue gas temperature reduction and efficiency
improvement
Although the total ash content is reduced it must be noted that all ash constituents may not be removed equally Unfortunately those constituents which are primarily responsible for slagging and fouling are least affected so that problems in this area can be induced as a result of cleaning
As overall S02 emissions will be lowered by coal cleaning the benefits of this form of pollution reduction must be considered in the light of the ESP problems that might result from the use of low sulphur coal (see Section 522) and with regard to its adverse effects on collection efficiency (Strein
59
Post-combustion performance
1989) Coal cleaning has only peripheral implications for NOx and C02 emissions
An additional benefit of cleaning coals is the substantial removal of many trace elements especially heavy metals with the mineral components (Swaine 1990) Efficiencies for trace element extraction have been reported for various physical cleaning processes including density separation oil agglomeration float-sink separation and combinations of heavy-media cyclones froth flotation and hydraulic classifiers (Gluskoter and others 1981 Couch 1991)
The adoption of coal cleaning strategies on a power station site would require a knowledge of quality characteristics that affect cleaning These include
the amount nature and the size of the mineral matter If they are finely divided and dispersed they are difficult to liberate and to separate the size distribution of the coal affected by inherent friability and by mining and handling procedures All of the properties which affect coal handling have an influence here the relative proportions of pyritic and organic sulphur coal oxidation affecting surface properties the porosity of the particles
A number of tests have been developed specifically to assess the cleanability of a coal These have been reviewed in an lEA Coal Research report by Couch (1991) and will not be discussed here
522 Fly ash collection
Fly ash collection systems are required on virtually all coal-fired power stations to meet particulate emissions or opacity regulations The acceptable dust loading from collection equipment is usually about 01 gm3 A coal containing 20 ash typically provides an uncontrolled dust loading of about 30 gm2 so that a collection efficiency of 997 is required to meet acceptable emission standards For very fine particles such as fly ash such a high collection efficiency can only be achieved using electrostatic precipitators (ESP) or fabric filters
Electrostatic precipitators (ESP) ESPs have been studied extensively and a number of comprehensive texts are available that describe the process (Babcock amp Wilcox 1978 Singer 1991 Klingspor and Vernon 1988) The ESP process involves fly ash particle charging collection and removal
The perfonnance or collection efficiency of an ESP is defined as the mass of particulate matter collected divided by the mass of such material entering the ESP over a period of time One of the earliest and simplest equations for predicting the particulate collection efficiency of an ESP was that proposed by Anderson in 1919 and subsequently developed by Deutsch in 1922 The Deutsch-Anderson equation enables the collection efficiency to be predicted from the gas flow the precipitator size and the precipitation rate (or migration
velocity) ofthe particles It may be presented as follows (Deutsch1922)
where e = fractional precipitator collection efficiency (dimensionless)
a = total collecting electrode surface area (m2) v = gas flow rate (m3s) w = migration velocity of the particles (ms)
The ratio av is often referred to as the specific collecting area (SCA) and has dimensions slm When determined empirically the migration velocity w accounts for ash properties such as ash particle size distributions as well as for rapping losses and gas flow distribution The Deutsch-Anderson equation was recognised as having several limitations and so gives only approximate results for some operating regimes For this reason alternative equations have been developed often as modifications of the original Deutsch-Anderson equation For example Matts and Ohnfeldt (1973) introduced a semi-empirical factor and a constant based on particle size distribution and other ash properties which gives a more realistic approximation of actual precipitator behaviour
The equations discussed above describe how perfonnance is a function of ESP design flue gas flow conditions and the characteristics of the fly ash The impact of coal quality on ESP perfonnance is primarily via the influence of the chemical and physical properties of the fly ash on the migration velocity of the particles These include
ash resistivity ash quantity ash particle size and size distribution
Ash resistivity influences ESP power input Resistivity is critical for fly ash ESPs because it directly influences operational voltages and currents As the ash resistivity increases the flow of corona current decreases Generally speaking as the corona current decreases so does the precipitator efficiency Low resistivity ash (l08 ohm-cm and below) is also a problem because the ash easily loses its charge after being collected on the plates The uncharged particles are recharged and redeposited several times and some are eventually re-entrained into the flue gas and escape from the precipitator A limit on maximum gas velocity and special collector profiles are needed to overcome this problem
High resistivity ash (above 1011 ohm-cm) is considerably more difficult to precipitate with a risk of back corona discharge An explanation for this phenomenon is that the ash particles do not readily lose their charge when they reach the electrodes This results in difficulties when trying to remove the agglomerated ash When a deep enough deposit collects on the plate back corona may develop on the ash surface and the precipitator no longer operates efficiently Back corona is extremely detrimental to precipitator performance and occurs when particles migrate to the collecting surface but fail to dissipate their charge This
60
Post-combustion performance
causes a high potential gradient in the dust layer on the surface of the electrode and results in current conduction of opposed polarity to that of the discharge electrode
The range of dust resistivity is primarily affected by
chemistry of fly ash levels of sulphur trioxide and moisture content of the flue gas flue gas temperature
Key ash constituents which affect resistivity are ferric oxide Fez03 potassium oxide (KzO) and sodium oxide NazOshywhere a substantial reduction in either or both of these will cause an increase in fly ash resistivity Conversely a substantial increase in calcium oxide (CaO) magnesium oxide (MgO) aluminium oxide (Alz03) and silicon dioxide (SiOz) will cause ash resistivity to increase (Singer 1991) Strein (1989) describes the impact of coal cleaning in particular the removal of sulphur from coals and switching to low sulphur coals on ESP performance It was determined that coal cleaning was not always beneficial to good precipitator operation Although precipitators can be designed for low sulphur coals the use of low sulphur coals in other cases can lead to a reduction in precipitator collection efficiency and possible non compliance with stack opacity limits Precipitators constructed many years ago were likely to encounter problems if any change to a lower sulphur coal was encountered It was concluded that before a change in fuel was made a careful review should be made of the precipitator design data predicted precipitator performance and the coal and ash chemistry of the new fuel If the problem of high fly ash resistivity was encountered after a fuel switch of this nature flue gas conditioning must be considered in particular a S03 injection system The purpose of this is to supplement the naturally occurring S03 in the boiler flue gas stream to the extent necessary to reduce fly ash resistivity to an acceptable level
A number of electrostatic precipitator manufacturers have developed regression equations which make first order predictions of fly ash precipitation performance based on the elemental analysis of the ash in coal These equations are generally regarded as proprietary and are not published
CSIRO Australia have published details of correlations of ash chemistry with pilot-scale electrostatic precipitators Whilst many correlations used in the past have proved inadequate for precise prediction the most promising correlation was obtained when consideration was given to the elements that would contribute to the refractoriness of fly ash The best precision was obtained from the sum of the elemental analyses for silicon aluminium and iron calculated assuming (on an ash basis) Si+Al+Fe+Ti+Mn+Ca+Mg+Na+K+P+S = 100
The formula given for a precipitator outlet concentration of 01 gm3 and for coal at 15 ash content is in two parts (Potter 1988)
for Si+Al+Fe = a lt82 am = 1886 + 0565a for 82 lta lt90 am = -2864 + 428a
where am = required specific collecting area in mass units mZ(kgs) This value can also be represented as a percentage of the ash content (A) by multiplying by the factor f given by f = 1364 - 048810glO[(100A)-I]
Cortsen (1983) reports of the use of alkaline sulphate index (ASI) by utility operators to assess the ease of fly ash precipitation The ASI is calculated from a series of equations which relate S03 content of the flue gas and the corresponding chemical equivalent of the oxides of silicon aluminium calcium magnesium phosphorus sodium and potassium Coal ashes with ASI values between two and three are perceived difficult to collect while an ASI of six or above indicates easy precipitation The index was not considered as accurate in ESP evaluation as measurement of ash resistivity nor measurement of actual precipitator efficiency (Cortsen 1983)
Sulphur content of the coal can also influence ash resistivity Sulphur trioxide (S03) formed from the combustion of the sulphur reacts with water vapour to produce sulphuric acid (HZS04) at temperatures of approximately 500degC (950degF) In the cool part of the flue gas system there may be some deposition of HZS04 which depends on flue gas temperature and vapour pressure The HzS04 can be absorbed onto the fly ash particles and reduce their resistivity It has been shown that H2S04 can alter the fly ash resistivity either by completely absorbing on the dust particles or by chemically reacting to form sulphates Others have suggested that the formation of binary acid water aerosol is the primary mechanism by which HzS04 can affect fly ash resistivity Although the mechanism which accounts for the presence of absorbed H2S04 on fly ash particles is not clearly understood the net effect is reduction in fly ash resistivity
Increases in moisture content can adversely affect precipitator performance through impacts upstream of the ESPs The moisture content of the coal in conjunction with coal particle size and volatility can affect flame stability and combustion within the boiler furnace area If this causes excessive carbon content in the fly ash at the ESP inlet ESP performance will suffer because of the decreased resistivity of the fly ash
Flue gas temperature can also influence ash resistivity Peak resistivities occur between about 120degC and 230degC depending upon coal ash characteristics Above 230degC to 288degC the ash resistivity is inversely proportional to the absolute temperature while below 120degC to 149degC the resistivity is directly proportional to the absolute temperature (Singer 1991)
The quantity of fly ash produced from a particular coal can vary as discussed in Section 51 It is important to ensure that the total electrode collection surface area and rapping frequency is adequate to handle the quantity of fly ash produced so as to prevent re-entrainment of the material back into the gas stream after initial entrapment at the collecting plates (Strein 1989)
Migration velocity and therefore particle collection rates
61
Post-combustion performance
decrease in proportion to the size of the particle (Darby 1983 Wibberley 1985b) lithe coal is pulverised too finely before entering the boiler ESP perfonnance can be adversely affected due to reduction in particle size distribution of the fly ash at the precipitator inlet The fonnation of fine fly ash may be increased also by higher combustion temperatures and from coals that have a high Free swelling index Disintegration of swollen char particles precludes agglomeration of the mineral inclusions thus ensuring the production of finer ash particles (Wibberley 1985b)
Bench-scale tests that are nonnally perfonned on new coal samples include
preparation of ash samples in a test furnace fly ash resistivity measurement of drift velocity in an electric field
Ideally the ash analysed for the purpose of investigating ESP perfonnance should be taken from the boiler to which the ESP system under assessment is attached Baker and Holcombe (I988b) have demonstrated that the fly ash produced in a specially developed laboratory furnace could show similarities to fly ash resulting from combustion of the coal in approximately eight different power stations It was possible to reproduce the properties of the power station fly ash in tenns of electrical properties and elemental analysis
14 shyelectric stress 400 kVm
bull
13
10 - - ltgt power station fly ash
- simulated fly ash
Mass H2 0r fIgures Indicated = d fl r mass ry ue gas
015 9
80 100 150 200
TemperatureOC
Figure 23 Resistivity results for both power station fly ash and laboratory ash from Tallawarra power station feed coal (Baker and Holcombe 1988b)
and general shape although the material was coarser than nonnal power station fly ashes A comparison of the resistivities of boiler and laboratory ashes is illustrated in Figure 23
Measurement of ash resistivity must ideally be measured under the same gas and temperature conditions as those at which the precipitator will operate The packing density should also be the same as that of the dust layer deposited on the precipitator collectors Dust resistivity measurements do not correlate very well with experience in ash precipitation efficiency
Laboratory resistivity tests are not standardised by ASTM BS AS nor ISO The Institute of Electronic and Electrical Engineers in the UK standard IEEE 548-1984 describe a resistivity test designed for testing compressed fly ash at 96 water vapour by volume (IEEE 1984) Measurements of resistivity are usually taken during both heating and cooling of the sample (Young and others 1989) Figure 24 illustrates the resistivity curves against temperature for ashes from a South African coal and Polish and South African coal blend respectively It can be seen that there is a degree of hysteresis as a result of the effect of moisture in the ash
5
3
2
103
E Eo 5 c 0 4
2 323shy
s ~
200 Q)
a
102
5 4 South African coal 3 50 Polish50 South African coal
2
100 120 140 160 180 200
Temperature degC
Figure 24 Laboratory resistivity curves of ash from a South African coal and from a blend of South African and Polish coals against temperature (Cortsen 1983)
62
Post-combustion performance
which gives a lower resistivity and which disappears after the heating process (Cortsen 1983)
The drift or migration velocity in a particular electric field can be estimated by examining the dielectric constant and particle size distribution as well as the aerodynamic factors for the fly ash A technique has been developed for determining particle dielectric constant from resistivity cell tests and other measurements (Baker and Holcombe 1988a) Particle size analysis of simulated ash is not reliable because of the difference in severity of the combustion process between full scale and test combustor Optical and scanning electron microscopes can be used to assess the shape characteristics of the fly ash
Prediction of fly ash precipitation characteristics remains an inexact science so that both pilot plant testing and electrical simulation studies remain extremely important in determining the precipitability of fly ash in practice
Fabric filters Although the use of fabric filters has become more widespread in recent years with the continued preference for low sulphur coals and to reduce stack emissions further there are no coal quality tests which relate to their performance directly
As described in Section 523 in cases where sorbent injection into the flue gas is used to control sulphur emissions collection of the fine sorbent in the bag can confer a high surface area to the gas and enhance the sulphur collection performance
While the efficiency of fabric filters is very high it is important to note that problems may occur with the presence of fine ash and acid condensation derived from coal causing
retention of filter cake on the filter fabric after the cleaning cycle due to agglomeration of the cake improving its mechanical strength blinding of the apertures of the fabric by very fine particles clogging of the filter by condensation promoting filter cake agglomeration bag rotting due to acid condensation
523 Technologies for controlling gaseous emissions
A range of methods is available for control of gaseous emissions in particular for SOx and NOx Options include
emissions control in the combustor post-combustion control technologies
lEA Coal Research have produced several reports that review these technologies SOx control technologies are reported in Flue gas desulphurisation - system performance (Dacey and Cope 1986) FGD installations on coal-fired plants (Vernon and Soud 1990) Market impacts of sulphur control the consequences for coal (Vernon 1989) Technologies for
controlling NOx emissions are described in detail in the reports NOx control technologies for coal combustion (Hjalmarsson 1990) and Systems for controlling NOxfrom coal combustion (Hjalmarsson and Soud 1990)
Emissions control in the combustor In-furnace desulphurisation by injection of calcium-based sorbents is not a widely-used sulphur control technology at present mainly because of its inability to achieve as high sulphur removal rates in commercial use as wet or spray-dry scrubbers Promising results are being obtained with sorbent injection followed by enhanced collection in a fabric filter in New South Wales Australia (Boyd and Lowe 1992)
There are several potential problems that may arise from the injection of calcium-based sorbents such as limestone (CaC03) into pulverised coal flames
the additional calcium may interact with the coal ash to reduce the ash melting point with consequent risk of increased slagging and fouling it is necessary to handle increased quantities of solid residue the possible adverse effects of calcium addition on downstream equipment such as electrostatic precipitators and solid residue disposal (see Sections 522 and 524 respectively) the possible influence of sorbent injection on the radiative properties of the flame (Morrison 1982)
To date sorbent injection into the furnace has only been utilised in smaller power stations with low sulphur coal where its low capital costs are particularly favoured Sorbent utilisation rates are generally low although it still results in a significant volume of mixed fly ash and calcium sulphitesulphate residue requiring disposal (Vernon 1989)
The formation of NOx depends mainly on oxygen partial pressure temperature and coal properties such as the content of nitrogen and volatile matter Measures can also be taken to modify the combustion conditions so that they are less favourable for NOx formation (Hjalmarsson 1990) This is usually achieved by some form of air staging Combustion air is admitted in stages in such a way as to limit flame temperature
The implementation of low NOx combustion techniques is much easier and more effective in a new installation compared with a retrofIt Low NOx measures on existing boilers can affect the combustion the boiler and other parts of the power station Combustion measures especially on existing boilers are specific to each boiler Consequently it is difficult to transfer experience of the impact of coal qualities directly
Most NOx abatement investigations have concentrated on determining the coal properties that influence NOx formation such as total nitrogen content volatile matter content and particle size distribution and developing technologies for reducing NOx emissions (Nakata and others 1988) There is limited information available concerning the impact of coal properties on power station performance under low NOx
63
Post-combustion performance
combustion conditions Discussions with power station operators have revealed that coals which previously produced a satisfactory performance prior to low NOx modifications have caused increased carbon in fly ash andor fouling slagging and corrosion along with other problems under low NOx combustion conditions Some possible explanations for this behaviour are presented briefly below
combustion efficiency can be reduced combustion conditions that reduce NOx formation such as low combustion temperature and low excess air are not favourable for accomplishing complete combustion As a result of this the level of unburnt carbon in the fly ash tends to increase If this is not counteracted the high content of unburnt carbon can cause changed conditions in an electrostatic precipitator (Klingspor and Vernon 1988) and make the fly ash unsaleable (see
Section 524) changes may also occur in the characteristics of the fly ash due to the reduced combustion temperature This will make the fly ash less glassy changing its properties and making the fly ash less attractive for use in cement and concrete production the thermal conditions in both the water and the steam parts of the boiler may change through low NOx combustion leading to changes in the temperature profile of heat exchangers Combustion modifications can also lead to an increased furnace exit gas temperature (FEGT) Deposits on heat exchange surfaces can affect heat absorption The reducing atmospheres reduce the ash melting point and can aggravate the problem of causing heat surface slagging Low excess air and staged combustion can produce areas with a reducing atmosphere which cause corrosion to boiler tubes (Coal Research Establishment 1991) the higher pressure drop over burners requires a higher fan capacity This in addition to other measures such as increased mill energy to obtain the required fineness and flue gas recirculation leads to higher power consumption low NOx burners may give longer flames that can cause deposits by impingement Flame stability may also be influenced Decrease in flame stability is usually found at reduced load causing limitations to boiler load turn down
Low NOx combustion was in many cases expected to give a higher degree of slagging and fouling in the boiler The opposite however has also been found Either result causes changes in soot blowing operations (Hjalrnarsson 1990)
Post-combustion control technologies SOx emission is minimised mainly with low sulphur coal Beyond this control is carried out with flue gas desulphurisation (FGD) systems The vast majority of FGD systems use an alkaline sorbent to absorb the flue gas sulphur dioxide chemically There are a number of different types of FGD and the effects of coal changes on their performance depends on the specific design details - no generalisation can be made For example flue gas temperature and SOz level impact the performance of wet limelimestone scrubbers These same variables affect spray dry FGD systems differently (Hjalmarsson 1990)
In wet FGD systems the effects of chloride from coal are generally all negative Chloride concentrations can build to high levels in the wet scrubbing loop causing corrosion problems and greatly reducing scrubber liquid-phase alkalinity (Rittenhouse 1991) However the removal of HCl in spray-dry scrubbers can have both positive and negative effects The HCl in the system can improve SOz removal capabilities resulting in lower reagent costs This effect was noted during a full-scale test conducted by Northern States Power Company in 1983 The addition of an amount of calcium chloride equivalent to a 02-03 increase in chlorine content reduced lime consumption by 25 Pilot tests carried out by EPRI confmn this effect (Collins 1990) The savings in lime consumption usually outweigh the cost of any negative effects including
incomplete droplet drying corrosion of stainless steel components in the system increased pressure drop downstream of fabric filters degraded ESP performance
Reference manuals have been published at IEA Coal Research that evaluate the wide range of FGD systems (Vernon and Soud 1990 Dacey and Cope 1986)
Where power station limits for NOx emissions cannot be met by combustion control flue gas treatment has to be installed The dominant method in use is selective catalytic reduction (SCR) In the SCR method the NOx concentration in the flue gas is reduced through injection of ammonia in the presence of a catalyst The role of the catalyst catalyst types and the reaction mechanism are described extensively by Hjalmarsson (1990) The efficiency of NOx reduction is primarily dependent upon condition of the catalyst which in tum is dependent upon the type of catalyst its susceptibility to poisoning and its location in the flue gas flow
The positions that are used for catalyst location are high dust low dust and tail end In the high dust location between the economiser and the air preheater the flue gases passing through the catalyst contain all the fly ash gaseous contaminants and sulphur oxides from combustion This can cause degradation of the catalyst leading to a decrease in NOx reduction efficiency The main types of degradation that are coal quality related are
deposition of fly ash causing clogging of the pores of the catalyst (Balling and Hein 1989) poisoning of the active sites of the catalyst by compounds such as alkali ions (sodium potassium calcium and magnesium) especially in sulphated form and some trace elements such as arsenic (Gutbertlet 1988 Balling and Hein 1989) erosion of the catalyst A high fly ash content in addition to an uneven particulate concentration and size distribution are most likely to cause erosion problems
The lifetime of a catalyst in this position is considerably shorter than in other positions Nakabayashi (1988) reported from a comparison of the impact of position on catalyst characteristics that catalyst life can range from 2-3 years in
64
Post-combustion performance
Table 23 Effect of coal type on total concentrations of selected elements from fly ash samples (Ainsworth and Rai 1987)
Mean and range of concentrations in fly ashes (Ilglg solid) from
Element Bituminous Subbituminous Lignite
Arsenic 219 (11-1385) 191 (8-34) 544 (21-96)
Cadmium 117 laquo5-169) lt5 lt5
Chromium 245 (37-609) 73 (41-108) 284 laquo40-651)
Molybdenum 56 (7-236) 165 laquo4--55) 141 (8-197)
Selenium 123 laquo5-435) 142 laquo5-281) 184 laquo5-469)
Vanadium 290 (99-652) 133 laquo25-292) 209 (lt25-268)
Zinc 607 (65-2880) 148 (27-658) 647 (25-127)
mean value is followed by range in parenthesis for 26 8 and 5 fly ashes from bituminous subbituminous and lignite coals respectively
a high dust location compared to 3-5 years in the tail end position
A low dust location means that the catalyst is situated after a hot gas electrostatic precipitator and before the preheater The flue gas reaching the catalyst is almost dust free but still contains sulphur dioxide which may result in poisoning of the catalyst
Tail end systems have the catalyst situated in the end of the chain of flue gas purification equipment after the desulphurisation plant The flue gases reaching the catalyst therefore contain only small amounts of sulphur oxides and particulates
NOx can also be controlled through thermal reactions by using appropriate reducing chemicals The process is called selective non catalytic reduction (SNCR) It has been found that different conditions in the flue gases influence the reactions and the temperature window (Mittelbach 1989 Gebel and others 1989) High CO content (gt1000 ppm) reduces the removal efficiency High S02 content increases the reaction temperature (Hjarlmarsson 1990)
Numerous processes have been developed for combined desulphurisation and denitrification of gases Most processes are still at the laboratory scale and there are a few stations operating at full commercial scale Coal quality effects on combined removal processes have not been studied extensively The problems encountered during the implementation of the individual abatement technologies may also be exacerbated for the dual systems An lEA Coal Research report Interactions in emissions control for coal-fired plants (Hjarlmarsson 1992) examines the interactions between control of S02 NOx and particulate emissions with different combustion methods and also the production of solid and liquid residues An understanding of the impact of coal quality on emission control technologies must be achieved for future efficient implementation of control systems
Trace elements emissions during combustion can also become associated with fly ash andor bottom ash Because of vaporisation-condensation mechanisms most of the trace elements in fly ash are often higher in total concentrations than those found in the corresponding bottom ash (WU and Chen 1987) In addition the levels of many trace elements including Cr Mn Pb n and Zn are often concentrated on the surfaces of the fly ash particles Typical median concentrations of selected trace elements in fly ash from different coal types are shown in Table 23 In power stations equipped with wet FGD systems the sludge from the scrubbers is a combination of spent solvent calcium sulphate and sulphite precipitates and fly ash The quantity and distribution of trace elements occurring in sludge are essentially determined by the coal ash composition and may influence the disposal cost of the material (Akers and others 1989)
524 Solid residue disposal
A typical pulverised coal fired power station employing ESPs or baghouses for particulate control and FGD for SOx control can produce three types of residue bottom ash (including slag) fly ash and FGD sludge Although under favourable conditions increasingly large amounts of these residues are utilised for various purposes at a net profit to the utility (Murtha 1982 Taubert 1991) it is anticipated that utilisation will not eliminate the need for disposal at a net cost in the foreseeable future
Changing coal characteristics can impact both the quantity and characteristics of the residue Power stations with limited resources for residue disposal have to transport the ash to alternative locations Ash for disposal may be conveyed to the disposal site as a dilute slurry Cerkanowicz and others (1991) reported that physical and rheological properties of fly ashes vary from different power stations This can impact the flow properties of fly ashwater mixtures significantly
The major factors that affect the amount of residue produced
65
Post-combustion performance
Table 24 Summary of the effects of coal properties on power station component performance - III (after Lowe 1987)
Property Contributing properties
Ash and dust plant
Ash quantity per unit heat release
Slagging propensity
Ash solubility
Erosiveness
Clinker reactivity
Environmental control
Coal cleaning
Particulate control ESP Dust burden (Ash per unit gas volume) Gas flow per unit heat
Ash resistivity
Sulphur
Fabric filters Dust burden
Gas flow per unit heat
Combustion measures
Post combustion
Residue disposal
ash level heating value grindability
ash elemental analysis ash fusion temperature coal particle mineral matter
ash elemental analysis ash mineral composition
mineral matter elemental analysis coal size distribution trace element
ash heating value ultimate analysis CIH ratio moisture level
ash heating value ultimate analysis CIH ratio moisture level
sulphur nitrogen volatile matter
cWorine fly ash size trace elemental analysis
ash ash elemental analysis sulphur heating value trace elemental analysis chlorine content
Effect
A I increase in ash quantity per unit heat release increases the ash and dust plant duty by 1
High slagging propensity increases the duty on ash extraction plant Formation of large clinkers may cause blockages in hopper doors and contribute to ash crusher problems
For wet hopper systems with recirculated water formation of scale pipelines may cause problems
Increased erosiveness will increase wear in pipelines and sluiceways
Some coals produce clinker in the furnace which is prone to explosive release of energy on quenching in the ash hopper
Different techniques are required depending upon the type and size distribution of the mineral matter Coal particle size influences the efficiency of the cleaning process and overall organic coal recovery
A 1 increase in dust burden will increase emissions by 1
A 1 increase in gas flow per unit heat release will increase emissions by 15 A resistivity change of 1 order of magnitude would suggest an increase in emissions by a factor of 2 General trend for reducing resistivity as sulphur increases possibly one order of magnitude per 1 sulphur change Below 1 sulphur resistivity is dominated by other factors
Differential pressure will increase with dust burden
A 1 increase in gas flow per unit heat release will increase unit heat differential pressure over the filter bags by 1
Influences the amount of sorbent used and dust collecting efficiencies Use of low NO burners can influence the combustion conditions and promote slaggingfouling due to reducing conditions present
Can have a positive and negative influence on SO removal efficiencies Can cause a reduction in catalyst efficiency in the removal of NObull
Quantity and quality influenced by the properties Saleable byshyproducts can be contaminated by carbon carry-over and trace elements
Quality of FGD waste can be influenced by cWorine and trace elements content
66
Post-combustion performance
annually by a pulverised coal fIred power station are the following
coal consumption ash content of the coal sulphur content bottom ashfly ash ratio fly ash collection efficiency SOx removal efficiency
These in turn influence the land requirement for residue disposal Ugursal and Al Taweel (1990) use the parameters listed above for calculating the area requirement for power station ash and FGD sludge disposal
The characteristics of the solid residue are particularly important where the residue materials must meet specifIcations to be sold (Cerkanowicz and others 1991 Bretz 1991b) For example the key requirement for the use of fly ash in cement production is the carbon content (Tisch and others 1990) A typical specifIcation is less than 5 carbon A coal change which degrades mill performance affects flame stability or reduces the rate of char oxidation such as in the case of low NOx combustion measures may increase the carbon content enough to exceed this carbon specifIcation (Zelkowski and Riepe 1987) Such a change would result in a considerable net cost to the utility since the fly ash would need to be disposed in a landfill at some cost instead of being sold for cement production at a profIt (Folsom and others 1986b) Similar problems can occur with FGD solid residue use for gypsum production The chlorine content of the coal is becoming an increasingly important consideration for power stations that have an established market for the gypsum produced from FGD residue as the chlorine impacts the quality of the gypsum for sale
The trace element content of combustion residues is an important consideration for both disposal and utilisation purposes (Clarke and Sloss 1992) The concentrations in power station residues may vary signifIcantly depending primarily on the coal used and on the cleaning techniques and combustion methods employed Therefore if the residue disposal strategy of the power station includes residue utilisation then a detailed knowledge of trace element content of the coal being fired is essential An lEA Coal Research report Trace elements emissions from coal combustion and gasification examines the behaviour of trace elements within these systems in more detail than can be discussed here (Clarke and Sloss 1992)
53 Comments The properties of coal affect the performance of the post combustion components of the power station These impacts are summarised in Table 24 As has also been highlighted in Chapters 3 and 4 many empirical relationships have been developed and used to describe the problems that are encountered in these systems but there are some signifIcant uncertainties related to many assumptions made For the post-combustion components these can include
fly ash collection - there is considerable disagreement as to the best method of measuring fly ash resistivity There is no correlation between coal composition and fly ash fIneness technologies for controlling gaseous emissions - there is no adequate means to predict NOx emissions
Whenever a change in coal supply is considered it is important to pay attention to the downstream effects
67
6 Coal-related effects on overall power station performance and costs
The production of electricity at the lowest busbar cost at a coal-fired power station depends on
the capital costs of the power station the delivered cost of the coal consumed overall power station performance the way in which the capital costs are financed during the construction and operating life of the station (interest depreciation profits taxes etc) the cost of decommissioning the power station at the end of its life
Coal quality can affect each of the above factors except for the last two components The main aim of this chapter is to look at coal-related effects on overall power station performance and costs
61 Capital costs The capital costs in most cases are affected by the range of coal qualities envisaged at the design stage (Mellanby-Lee 1986) In a study done by Ebasco Services Inc (Cagnetta and Zelensky 1983) the capital costs of a new power station are estimated for a wide range coal and a dedicated coal specification The wide range coal characteristics encompass about 90 of the recoverable reserves east of the Mississippi in the USA while the dedicated coal characteristics vary over a much narrower range Table 25 gives details of coal quality values for both types of coal and the costs with respect to the design for the wide range coal type It can be seen that the cost of a power station to bum a wide range of coals is $54 million more expensive than the design for a dedicated coal supply
A decision to bum high sulphur coal in a power station may necessitate the installation of an FGD or other emission control technologies FGD the best established technology to control emissions can be costly typically adding up to 20 or more to the total capital cost for new capacity and around
Table 25 The effect of coal quality on the costs of a new power station (Cagnetta and Zelensky 1983)
Coal Wide range Dedicated
Heating value GIlt 2442-3315 2949-3282 Moisture 10-150 10-65 Ash 60-180 64-146 Sulphur 05-40 17-32 HGI 40-64 45-60
Power station capital costs $ million coal handling +03 base steam generators +66 base ash handling +10 base ESP +417 base FGD +46 base total 1086 1032
Figures are for a 2 x 600 MW net power station they exclude coal costs
30 to power station capital costs when retrofitted to existing power stations (Vernon 1989) Control costs for NOx an additional environmental consideration are lower adding some 6-10 to the total capital costs of large new plants but as with FGD costing more when retrofitted (Hjalmarsson 1990 Daniel 1991)
62 Cost of coal The cost of internationally traded coal varies considerably For the third quarter of 1991 the lEA reported that the average cif coal import prices in Europe Japan and the USA were 4927 4998 and 3425 US$lMt respectively The range of prices to the two major importing areas that is the EC and Japan were 4320-5068 US$lMt and 4451-5180 US$lMt respectively The variation in prices is influenced by geographic location transport costs and coal quality The lEA reported that countries describe thermal coal using different average coal quality values for example the lower
68
Coal-related effects on overall power station performance and costs
heating value of a steam coal as detennined by the EC is 2617 MJkg (6251 kcalkg) compared with Japan at 2466 MJkg (5890 kcalkg) (International Energy Agency 1992)
Ash contents of traded coal vary substantially from under 5 for Colombias Cerrej6n coal for example to over 20 for typical South African thermal coals (see Table 26) Most of the traded coals have an ash content below 15 with the average being around 12-13 Given the associated costs of ash handling and disposal (see Section 63) coals with high ash contents will attract a lower price than those with lower ash even when corrected for heat content because of the application of penalties Many utilities and traders have a formula for calculating price penalties in relation to ash content Estimates of penalties vary depending upon the equipment in place It is probable given the increasing concern about the disposal of combustion residues that these ash penalties may increase during the next decade and a half
Table 26 Ash contents of traded coals (Doyle 1989)
Low Medium High lt8 8-15 gt15
Colombia Canada South Africa Venezuela China Indonesia Australia
Poland USA South Africa
While ash characteristics have traditionally most worried boiler managers sulphur content has become more significant in recent years because it is the primary determinant of the cleanliness of a coal in relation to S02 emission standards Most traded coal is low sulphur Only a small volume has a sulphur content above 15 However as S02 emission standards have tightened there has been a noticeable downward shift in what is considered low sulphur coal The defmition of low sulphur is now perceived to be below 09-10 and an increasing amount of traded materials now below 06 Various studies have deduced that low sulphur coal could command a premium price of up to one third greater than high sulphur coal (Doyle 1989 Calarco and Bennett 1989) Doyle (1989) also reported that at the most general level the low sulphur premium must be less than or equal to the smaller of either FGD costs or coal cleaning costs Otherwise buyers would take higher sulphur coals In practice the situation is more complicated For some users regulations may make the use of low sulphur coal or FGD equipment compulsory An excessive premium on low sulphur coal may also bring gas frring inter-fuel competition into consideration
63 Power station performance and costs
Several investigations of coal qualitypower station performance relationships have been conducted by utilities and other organisations These have been reviewed by
Folsom and others (1986a) In general the manner in which station performance evaluation of the impacts of coal quality have been assessed was by considering the following four performance categories
capacity - the capability of the unit to produce design load
heat rate - a measure of the net energy conversion efficiency
maintenance - the cost of maintaining all components in suitable working order
availability - a measure of the degree to which the unit can be operated when required
A summary of coal quality effects on these categories is presented under these headings
631 Capacity
The utility industry uses a number of definitions for station capacity In this discussion the term capacity will refer to the maximum rate of power generation for a specific unit under given operating conditions It should be noted that changes in this definition of capacity mayor may not be of economic consequence to a utility The need to operate a specific unit depends on
utilitys power demand available capacity system-wide relative costs of operating the specific unit compared to other available units
Fuel quality can affect unit capacity in a number of ways An analysis of the way fuel quality affects the capacity of each component of a generating station can reveal the total impact This analysis must start with the component most critical in detennining power station capacity The next step is to estimate the effects on less critical components The effects of successively less critical components may be interactive with the impacts on more critical components In some cases a change in fuel quality may affect one component to such an extent that it becomes the most critical item
Since a coal-fired steam-electric unit has a large number of components detailed analysis can be quite complex In Chapters 3-5 the effects of coal characteristics on the seven major components of a power station were described The capacity of the component was often influenced by these effects In many cases these effects could be evaluated with reasonable accuracy using existing straight forward engineering procedures In other cases assumptions on coal behaviour had to be made to facilitate the calculations As was summarised in Sections 34 43 and 53 there are some significant uncertainties related to many assumptions made
632 Heat rate
Heat rate (HR) is an index of the overall efficiency of a power station expressed as the heat input in the form of coal (Qin (MJIhr or BtuIhr)) required to produce one unit of electrical energy It may be expressed on a gross or net basis Gross heat rate (GHR) is based on the total or gross power
69
Coal-related effects on overall power station performance and costs
(GP) produced by the turbine generator while the net heat rate (NHR) is based on the GP reduced by the auxiliary power (AP) NHR depends on the turbine heat rate (THR) boiler efficiency (BE) GP and AP and it may be calculated as follows
NHR= THR x GP BE (GP-AP)
The coal changes which affect heat rate are associated primarily with boiler thermal efficiency auxiliary power consumption and turbine cycle efficiency (via changes in steam conditions) The following three sections describe how coal characteristics can affect boiler efficiency auxiliary power consumption and turbine heat rate respectively
Boiler efficiency The most widely used method of evaluating the impacts of coal characteristics on boiler efficiency is to assess the heat losses from the boiler and to assume that the remainder of the heat is absorbed to produce superheated or reheated steam This approach has the advantage of eliminating direct measurement or calculation of heat transfer rates in each section of the boiler which are quite complex but can only be carried out with suitable probes on fully instrumented boilers
The procedure involves the calculation of around six types of heat losses (Corson 1988) These can be
dry flue gas loss heat losses due to fuel moisture heat loss due to moisture produced from the combustion of hydrogen in the fuel heat loss due to combustibles and sensible heat in the ash
heat loss due to radiation unaccounted heat losses
Dry flue gas loss which is usually the largest factor affecting boiler efficiency increases with higher exit gas temperatures or excess air values Every 35degC to 40degC increment in exit gas temperature is reported to reduce boiler efficiency by 1 A 1 increase in excess air by itself decreases boiler efficiency by 005 ill most boilers however increased excess air leads to higher flue gas exit temperatures (FGET) Consequently increases in excess air can have a twofold effect on unit efficiency (Singer 1991) Calculations of excess air requirements depend on
flame stability carbon burnout slagging and furnaceconvective pass heat transfer considerations
These are difficult to predict with existing correlations
Losses due to moisture and fuel hydrogen are calculated easily from the coal analysis data using straight forward chemical and physical relationships
illcomplete combustion is manifest primarily by carbon in the bottom and fly ash The carbon content of the ash is difficult to predict and is affected by the slagging and fouling characteristics of the coal If the furnace is large enough to avoid slagging and fouling problems the carbon content of the ash is often less than about 5 For any furnace the carbon content of the ash tends to increase as the excess air decreases Also carbon loss may vary with char reactivity which depends on coal characteristics such as particle size
Table 27 Calculation of boiler heat losses (Folsom and others 1986a)
Loss
Dry gas
Fuel moisture
Fuel hydrogen
Combustibles
Radiation
Data required
Coal ultimate analysis Excess air Exhaust temperature Product specific heat
Coal moisture content Exhaust temperature H20 latent and specific heat
Coal hydrogen content Exhaust temperature H20 latent and specific heat
Carbon content of ash Coal carbon and ash content Heating value of carbon
Total heat output Maximum continuous rating
Assumption Comments
Complete combustion based Carbon corrected for on ultimate analysis carbon lost to ash shy
usually the largest loss
Complete combustion of fuel hydrogen to H20
Neglects CO and HxCy emissions which are usually negligible
External surface temperature Usually less than 05 Ambient air velocity over surfaces Independent of coal characteristics Calculated using ABMA chart
Unaccounted None Allowance for Usually estimated as about 05 bottom ash quenching Independent of coal characteristics CO and HxCy emissions Miscellaneous
70
Coal-related effects on overall power station performance and costs
rank and petrographic composition and combustion as the heat absorption pattern in the boiler changes Also if conditions At present there is no satisfactory method of the acid dew point of the flue gases changes the operators predicting the carbon content of the fly ash andor may need to adjust furnace exit gas temperature (FEGT) so combustibles loss based on standard coal analysis alone as to maintain the minimum air heater metal temperature Most coal quality analyses merely assume that the carbon above the acid dew point to avoid air heater corrosion loss guarantee provided by a boiler manufacturer will not be Whilst largely empirical procedures are used the actual exceeded This is usually in the range of 5 since fly ash amount of available data are insufficient to determine the with higher carbon content has less value for subsequent use accuracy of this approach Thus improved procedures need such as feed stock for cement manufacture (see to be developed and evaluated for assessing excess air flue Section 524) For coals with 10 ash and 60 carbon as gas exhaust temperature and combustible loss as a function fired 5 in the fly ash corresponds to a carbon utilisation of coal characteristics for a given furnace efficiency of 9912 (Folsom and others 1986a)
A summary of the data required for calculating heat losses is Procedures have been developed to predict combustibles loss given in Table 27 Combustion handbooks published by the based on furnace models An example of this is a boiler manufacturers include detailed descriptions of 3-dimensional model developed by the Energy and procedures for evaluating these losses (Babcock amp Wilcox Environmental Research Corporation USA (EER) This 1978 Singer 1991) These calculations are complex but includes a char combustion sub-model which evaluates the nevertheless straightforward and can be automated via a combustion process as a function of the micro-environment computer program easily An illustration of typical boiler surrounding individual char particles (WU and others 1990) losses for four Australian Queensland steaming coals is given Several more simplified approaches to carbon loss prediction in Table 28 have been developed All involve burning the coal under controlled laboratory conditions measuring the carbon loss Auxiliary power consumption and then scaling these data to full-scale units (see Power station auxiliaries consume power for Section 421)
coal handling In the calculation of boiler efficiency the flue gas exit mills temperature (FGET) is usually assumed constant However a feedwater pumps detailed evaluation should consider that the FGET may vary soot blowing
Table 28 Typical boiler losses for four Australian Queensland steaming coals (St Baker 1983)
Coal type A B C D
As-burnt - Total moisture 70 160 100 110 -Ash 214 143 100 280 -Carbon 581 535 676 487 - Nitrogen 11 09 15 09 - Hydrogen 39 34 38 32 - Sulphur 04 03 02 02 -Oxygen 76 111 64 75 Unburnt carbon 05 05 05 05
Gross heating value GJt 2412 2120 2738 1998 Latent heat of evaporation 102 112 106 096 of H20 from coal OJt Net heat value GJt 2310 2008 2632 1902 Unburnt carbon loss GJt 017 017 017 017 Radiation amp other losses OJt 013 012 015 011 Total dry air per tonne of coal tit 9130 8180 10433 7556 Sensible heat in combustion air OJt 221 196 252 183 Total heat available OJt 2501 2175 2852 2057 Overall total combustion products t 10130 9108 11433 8556 Exit flue gases (at 130degC) OJt 0108 0110 0108 0110 Flue gas exit loss GJt 110 100 123 094
Heat balance Heat input in coal 1000 1000 1000 1000 - Flue gas exit loss 46 47 45 47 - Heat loss due to H20 42 52 39 48 - Loss to unburnt carbon 07 08 06 09 - Loss to radiation etc 05 05 05 05
Net heat to watersteam 900 888 905 891
71
----
-----------
Coal-related effects on overall power station performance and costs
fans 200 shyparticulate control
flue gas desulphurisation shy-~ 0
Auxiliary power is typically in the range of 50 to 100 of gross power and is highly dependent on the specific power station design However coal characteristics also affect power consumption for most of these components although the impacts in many cases are not large and can be evaluated by considering trends
The primary factors impacting the power requirements for coal handling are the design of the systems and the desired coal flow rate The design of coal handling systems varies substantially and power requirements can be determined accurately by considering the details of the specific designs Since coal handling equipment normally operates intermittently any change in coal flow rate will change the duty cycle of the equipment and the power consumption will be approximately proportional to the coal flow rate This assumes that no modifications to the coal handling equipment are made to increase capacity In some analyses the coal flow rate is assumed to be inversely proportional to the coal heating rate on the assumption that the total heat input remains constant However as discussed earlier any change in heating value may change the performance of several other power station components and impact overall heat rate This compounding effect means that changes in coal flow rate are often greater than would be expected based on heating value alone
The power required for coal grinding depends on mill design characteristics of the coal feed including its grindability and size distribution and the mill operating conditions including the coal flow rate and pulverised coal size distribution The manufacturers have developed power consumption correlations based primarily on Hardgrove grindability index (HGI) Cortsen (1983) reported that the power consumption of the mills at a Danish utility was mainly dependent on the grindability of coal In evaluating mill performance it must be recognised that for a given design the operating parameters are linked It is not possible to vary the coal flow rate HGI and pulverised coal size distribution independently This is illustrated in Figure 25 which shows the effects of an independent change of coal grindability on the performance of a pilot vertical spindle mill (Luckie and others 1980) However Folsom and others (1986a) put forward the theory that reasonably accurate evaluation of coal changes have been made by assuming that the power consumption varies linearly with the coal flow rate independent of coal grindability in cases where variations in HGI are small St Baker (1983) reported that the power consumption of mills increases with increases in moisture content
There are few data that can be used to determine the number of soot blowers and frequency of operation for a specific coal The usual procedure is to select the wall blower array based on experience with similar coals and to set the wall blower operating schedule during normal boiler operation to minimise slagging and fouling problems The actual frequency of soot blowing will depend on the severity of
a5 sect 5 0
Cii 0 ()
100 ---shy--constant coal flow rate ---
0
40 50 60 70
Hardgrove grindability index (HGI)
80
100 -
o 40 50 60 70 80
Hardgrove grindability index (HGI)
10 shy
5
o 40 50 60 70 80
Hardgrove grindability index (HGI)
Figure 25 Effects of grindability on vertical spindle pulveriser performance (Luckie and others 1980)
slagging and fouling In some cases certain boiler stages may be blown unnecessarily and incur a heat rate penalty Excessive blowing can result in erosion of the tube surfaces which leads to premature tube failure and subsequent forced outages Proper blowing schemes are critical in achieving target steam and flue gas exit temperatures Wall blowers can utilise steam or air as the blowing medium The steam consumption can be treated as auxiliary steam use and can be evaluated in terms of its impact on heat rate Compressed air is generated in motor driven air compressors and the compressor power consumption can be evaluated as part of the auxiliary power load which has a greater impact on overall heat rate
The power consumption of fans in a power station is based
72
Coal-related effects on overall power station performance and costs
on the required flow rate and pressure rise fan design and the method of fan control Given these parameters the power requirements may be calculated easily based on standard fan analysis procedures In general a coal change that causes an increase in flow rate or pressure rise for example as a result of a reduction of cross-sectional flow area due to ash deposit bridges will increase fan power requirements (Borio and Levasseur 1986)
Essentially all the power consumed by an electrostatic precipitator for particulate control is used to generate the corona The power consumed to charge and deposit particulates is negligible while collection efficiency increases with corona power (Folsom and others 1986b)
The auxiliary power requirements of the flue gas desulphurisation (FGD) systems depend on the equipment designs which vary substantially among operational systems employed internationally A number of reference manuals have been published which provide procedures for evaluating the impacts of coal quality on flue gas desulphurisation systems These manuals should be consulted to conduct a detailed evaluation of the impact of coal characteristics on flue gas desulphurisation system auxiliary power (Dacey and Cope 1986) Generally the FGD facility will require more auxiliary power when operating with a high sulphur coal
Turbine heat rate Turbine heat rate is an index of the efficiency of the steam cycle and generator set in converting heat supplied to the turbine in the form of superheated or reheated steam to electrical power The turbine heat rate depends on the specific design of the turbine cycle as well as the operating conditions principally the steam supply and the discharge conditions
Since the coal does not come into contact with the steam coal quality impacts on turbine heat rate are neglected in many analyses However coal quality can impact the steam supply characteristics by changing the distribution of heat absorption among the various heat transfer surfaces in the boiler as discussed earlier in this section It should be noted that this is distinct from the total quantity of heat absorbed which is related to the boiler efficiency Changes in the heat distribution may result in an inability to achieve the required superheat or reheat temperatures or necessitate excessive attemperation to moderate steam temperature Both effects can degrade turbine cycle efficiency significantly
Evaluation of the effects of coal characteristics on steam temperature and hence turbine heat rate requires analysis of the radiative and convective heat transfer occurring in the various boiler sections and consideration of the options available to boiler operators to vary steam conditions (see also Section 42) A wide range of heat transfer models of varying complexity for the furnace and convective surfaces have been created (Shida and others 1984 Robinson 1985 Boyd and Kent 1986 Fiveland and Wessel 1988 Pronobis 1989) (see also Section 72)
The effects of coal characteristics on heat transfer evaluated by these methods can be grouped into three categories
gas flow rate changes through the furnace and the tube bank due to the volume of combustion products which mainly affects convective heat transfer radiative heat transfer changes due to varying coal composition combustion conditions and particle deposition heat transfer change due to deposits resulting from slagging and fouling
The volume of combustion products from a coal of arbitrary composition can be evaluated easily by simple combustion principles given the firing rate and excess air The impact of volumetric air flow rate on radiant and convective pass heat transfer can be evaluated using the models The effects of coal composition on radiative heat transfer are more difficult to evaluate As coal composition changes the radiative characteristics of the reacting gases and particles change along with the characteristics of the wall deposits The emissivity and thermal resistance of the ash deposits have the greatest impacts Similarly the effects of fouling deposits on convective pass heat transfer are difficult to evaluate However tests of slagging in pilot-scale furnaces indicate that potassium sodium sulphur ash fusion temperature ash particle size and total ash might be important (Wagoner 1988 Pohl 1990) In contrast Wain and others (1992) have shown in a study of slags from UK power stations that the thermal conductivity of wall deposits is primarily influenced by the physical properties of the slag such as its porosity rather than by its chemical composition
Deposits are formed over the perimeter of the tube quite irregularly so that the effective shapes of the tubes immersed in the flow of flue gases are completely changed This not only impairs the efficiency of the heat exchanger because of the necessity to overcome the thermal resistance layer but leads also to changes of the heat transfer coefficient brought about by the changed flow pattern and the effective shape of the tube cross-sections In the course of time the properties of the deposits also change resulting in further changes of thermal resistance (Pronobis 1989) The ability to remove the deposit by soot blowing and recovery of lost heat transfer is also important and is determined by the thickness strength and phase of the deposit and the available soot blowing power (Wagoner 1988)
If the effects of these changes on heat transfer can be determined or assumed the turbine heat rate can be evaluated via thermodynamic analysis Several computer programs have been developed to analyse complex thermodynamic cycles The limiting factor of the models is the specification of the input parameters
In general the heat rate correlations are perceived to be adequate providing that certain key parameters such as excess air carbon loss and mineral matter impacts can be specified In many analyses these are assumed since coal quality impact data are usually not available An example of the cost implications of a coal change on heat rate for a 1000 MW boiler was compiled by Folsom and others (1986a) Figure 26 illustrates this effect based on various assumptions conceming the unit characteristics The relatively large change in coal quality is shown to result in a
73
Coal-related effects on overall power station performance and costs
Change in coal characteristics
Coal ash increase 10
Coal moisture increase 5
Coal heating value decrease 15
Char reactivity decrease
- carbon in ash increase 2
- excess air increase 0
Ash deposition
- superheat decrease 50degC
- reheat at temperature increase 5
- exhaust temperature increase 10
Loss component Cost impact
ESP
Coal handling
Carbon loss
Dry flue gas
Moisture loss
Fans
Turbine efficiency
070
010
055
079
048
066
118
65 capacity factor base line heat rate 10000 Btu kWh thermal efficiency 89 coal heating value 279 MJkg (12000 Btulb) coal ash 10 coal moisture 5 coal carbon 77 and coal cost 35 Sit
Figure 26 Example of cost impact of a coal change on heat rate for a 1000 MW boiler (Folsom and others 1986a)
cost impact in heat rate of $446 millioniy (1986 prices) which is equivalent to an availability loss of about 5
As an alternative to these fairly complex calculations some attempts have been made to correlate coal quality with heat rate and boiler efficiency statistically (Barrett and others 1983 Kemeny 1988)
Several organisations have developed methods to facilitate the calculation of coal quality impacts on heat rate Some of these methods use computer programs to calculate economic effects directly from coal quality data power station design information and economic assumptions Others make use of manual calculations and rely more on engineering judgement and experience with similar coals
The use of both statistical techniques and computer models is discussed in greater detail in Chapter 7
633 Maintenance
While it is widely accepted in the utility industry that coal characteristics can affect maintenance costs primarily via wear by abrasion and erosion and by corrosion of power station components there is at present no effective method for predicting the effects of a coal change on maintenance Utilities use a range of procedures to account for maintenance costs in coal-fired units Whilst these procedures generally meet utility needs they often make it difficult to evaluate actual coal quality impacts For example while the maintenance cost due to a tube failure may be identifiable it may not be possible to determine whether tube failures relate to coal quality water quality structural problems or other effects (Heap and others 1984) Another significant problem is that maintenance costs are due in part to phenomena which should be predictable and form part of scheduled
maintenance routine for example replacement of expendable components (such as worn mill rollers and balls) Unfortunately they are also due to unscheduled failures which may cause partial or full outages It has been demonstrated that both routine maintenance requirements and unscheduled outages can be affected by coal characteristics
The mechanisms involved in wear of components are discussed in more detail in Sections 32 and 422 For many components the major factor affecting wear rates and hence maintenance costs is the mass of material processed This will be directly related to the heating value of the coal and the heat rate of the power station However as discussed in Sections 32 and 422 certain coal minerals are identified as strongly influencing the rate of wear by abrasion in handling equipment and mills In some instances erosion rate depend on power station design and aerodynamic considerations (Walsh and others 1988 Platfoot 1990)
Increases in unscheduled maintenance costs and consequent reduced availability (see Section 634) even involving reduced boiler life which result from excessive boiler flue gas erosion and corrosion can be considerable In a review of the state-of-the-art methods of reducing fireside corrosion and fly ash erosion as factors responsible for tube failures in boilers Wright and others (1988) reported that both of the effects are considered to be major problems only on units burning coal that is rated as very aggressive (high sulphur alkalis and chlorine) or that contains a high percentage of erosive materials such as quartz and ash Fly ash erosion of primary superheater reheater and economiser tubes were considered to be more serious problems than fireside corrosion An interesting observation from the study was that although there were proven permanent solutions for most of the problems encountered such as coal and hardware modifications these were not widely accepted Evidently the
74
Coal-related effects on overall power station performance and costs
costs of these solutions were perceived to compare unfavourably with continued maintenance activities in spite of the inconvenience of several unscheduled outages annually for emergency maintenance
St Baker (1983) reported that a typical 20-day unscheduled outage on a single 350 MW generating unit to repair boiler erosion damage could cost more than A$2 million in 1983 in replacement power costs alone This would amount to more than A$33 million (US$25 million) at 1991 prices
In a study of the use of declining fuel quality in 110 and 200 MW Czechoslovak power stations Teyssler (1988) showed increased maintenance costs due to higher equipment wear Examples of costs were given as Czech crowns 15-25t ash output in 1988 (US$04-07 (1991raquo for the cost of repair and replacement of heating surfaces damaged by erosion a 1 increase in ash content was found to result in at least a 10 higher cost in mill component replacement
Smith (1988) in a paper describing Tennessee Valley Authority s (TVA) experience with switching to improved quality coal presents a comparison of performance variations at the Cumberland power station (2 x 1300 MW) and Paradise power station (2 x 704 MW 1 x 1150 MW) with coal quality over the period 1977-86 The results show that maintenance costs for the boilers burning equipment and ash handling equipment were reduced with improved quality coal Costs dropped by about US$15 millionyon average between 1980 and 1984 at the Cumberland power station In this case the improvement in quality was achieved by cleaning the coal supply Prior to coal washing the units exhibited extensive slagging fouling corrosion and tube leakages Figure 27 shows the effect of a coal quality change that occurred at Cumberland in 1982 The largest change after washing was a reduction in ash content from about 152 to 92 Sulphur was reduced from 35 to 28 and which heating value went up from 249 MJkg (10712 Btulb) to 271 MJkg (11635 Btulb) In contrast
10 o boilers
A burning equipment 9
LD ash handling equipment co en 8~
c Q 7E $ (j) 6 =gt t5 50 u (l) u 4c ro c 2 3c iii ~ 2
I 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986
Figure 27 Adjusted maintenance cost accounts for TVAs Cumberland plant (Smith 1988)
operation and maintenance costs for the Paradise power station do not show dramatic cost improvements on utilisation of washed coals because major modifications and maintenance improvements necessitating significant investment were also made to the station over the same time period TVA believe that damage done to the Cumberland boiler by years of operating with poor quality coal was still causing problems long after the change to washed coal (Smith 1988) This example illustrates the difficulty of obtaining valid information of coal quality effects on maintenance and other power station performance factors independently from the influence of other modifications and changes in operating procedure
Hodde (1988) in an investigation of work conducted by Blake and Robin (1982) which considered the contribution of coal quality effects to total fuel-related operating costs of the Southern Company USA (see Table 29) concluded that whilst the dominant portion of the total fuel-related bill is the delivered cost of fuel comprising about 80 the remaining costs are associated with problems due to coal quality It was shown that approximately three quarters of the quality-related costs are in maintenance and residue disposal From this assessment Hodde (1988) suggested that maintenance costs relate linearly with coal quality in particular ash and could be calculated in advance This figure together with the price of the coal would account for almost 90 of the total costs associated with the coal This simplified approach is adopted in a number of computer models (see Section 72) However the approach has been challenged by a number of other sources (Folsom and others 1986b Mancini and others 1987 Galluzzo and others 1987 Lowe 1988b) who report that maintenance costs are not linearly related to the mass of ash processed by a power station Additionally there is usually a substantial lag between the initial variation in ash content of the fuel and the first experience of its effect on maintenance costs Consequently care should be taken in the use of linearised maintenance cost assessments to allow for the effects of lead times and incubation
In general the relationships between maintenance costs and coal quality are difficult to assess due to four factors the inadequacies of records maintained by utilities the impact of non-coal-related factors power station design variations and delayed effects of coal quality impacts
Table 29 Total fuel costs for power stations of the Southern Company USA (Hodde 1988)
Costs of total For coals with ash content of
15 20
Delivered fuel cost 83 77
Waste disposal cost 5 6 Maintenance cost 7 9 Ash related unavailability 3 4 Other operating costs 2 4 Slagging and fouling -0 -0
Total 100 100
75
r ~ 250 lt9 c o t3 200 J 0 2 a 0 150 3 o a
Ui3 100
50
o 2 (ij 3
~
0 ro Q)r 0 a J
(fJ
0 ~ 0 gt
5 0
(ij 0 c Q)
3 ~ is
CD
~ 2 ro Q)r Q)
a
0 ltJ)
E 0 c 0 U w
c ~
-0 0 Q) u J 0
Ol c 6l Ol ro iii
Coal-related effects on overall power station performance and costs
Table 30 Comparison of reduced boiler availability on the basis of hours in operation and type of fuel (Pasini and Trebbi 1989)
Mean annual All boilers Hours in operation Type of fuel reduced availability lt105 gt105 oil-gas coal
Furnace wall 220 203 270 184 309 Secondary SH 054 032 113 045 075 Reheater 032 032 032 015 075 Primary SH 019 008 051 005 054 Economiser 013 005 036 012 014
Unheated 020 017 029 025 008 Casing 030 025 043 039 009 Others 045 075 048 045 045
Total 433 365 622 370 588
634 Availability
The availability of a power station is important to both system reliability and generating-company profit Improving availability only slightly can save considerably on reserve generating capacity and the cost of replacement power Availability can be defined as the percentage of time that a unit is available for operating regardless of whether electricity is actually generated The total electricity sent out from a power station is affected by the planned shutdowns for maintenance forced down-ratings forced outages and other reductions in its availability (Mellanby-Lee 1986)
While it is clear that availability can be affected by coal quality the nature of the relationship is not well understood Statistical data-gathering studies such as the programme conducted by the North American Electric Reliability Council (NERC) utilising the Generating Availability Data System (GADS) supplied data relating to the component cause of outages and load reduction but were not able to provide information as to why particular components failed (Electrical World 1987) A study conducted by Combustion Engineering USA has gathered information from coal-fired units of 390 MW and larger on the causes of outages and load reductions in nine major equipment categories related to steam generators Included were
water walls superheaters and reheaters economisers furnace soot blowingbottom ash removal equipment convection-section soot blowing and fly ash removal equipment boiler controls fans mills boiler circulating pumps
The study indicated that water wall superheater reheater and economiser tube leaks account for 80-90 of all forced outages whereas coal milling systems accounted for 50 of equivalent down-time hours in load reductions (Llinares and others 1982 Llinares and Lutz 1985) Pasini and Trebbi (1989) reported similar trends of reduced power station availability for ENEL Italy (see Table 30) Mancini and
others (1988) reported that in a study of the top eighteen causes of full and partial outages at coal-fired stations in the USA for the decade from 1971 through 1980 60 of these causes were related to coal-quality (see Figure 28)
A record of boiler tube erosion at two Australian power stations Munmorah (4 x 350 MW) and Liddell (4 x 500 MW) illustrates the considerable costs that can result from excessive flue gas dust burdens in boilers supplied with off-specification coals particularly ash content above the design level They have experience of
up to 7 per annum additional reduced availability due to outages for the repair of boiler tube leaks reduced boiler life before major refurbishment affecting the economic life and gross power station output over
350
300 Coal related outages represent 60 of total power station outages
E
Figure 28 Causes of coal-related outages (Mancini and others 1988)
76
Coal-related effects on overall power station performance and costs
Southern Electric System USA 10 ] D US Industry average
8
7
6
J lLshy 5 ltt w
4 9339
3
2
90
Early units Early units Later units 1975-77 1985-87
Figure 29 Boiler and boiler tubes equivalent availability factor (EAF) record (Richwine and others 1989)
which the power stations initial capital costs could be recovered the necessity to be complemented by a greater level of standby generating capacity in order to ensure adequate reliability of electricity supply to consumers (St Baker 1983)
Richwine and others (1989) reported the results of an availability improvement programme in the Southern Electric System (SES) USA coal-fired units Due to a decline in availability between 1970-76 increased attention was given to this factor such that from 1977 to 1988 an improvement of over 22 percentage points was achieved This turnaround was accomplished by recognising the problems implementing appropriate solutions and adopting new power station practices The problems included coal-related cases such as boiler tube superheater reheater and economiser tube failures arising from fly ash erosion and slagging Figure 29 shows the increase in equivalent availability factor (EAF) achieved when coal quality upgrades were adopted along with tube maintenance during planned outages and the design improvements of later units to incorporate a wider range of coals while maintaining high reliability Problems encountered with mill operation were recognised as being a result of coal characteristics Many units experienced outages due to fires and flow problems due to high moisture coal
It has been suggested that a 5 increased outage rate for a power station designed for a 30 ash coal compared for one designed for 15 ash is a reasonable allowance for possible loss of availability (ERM Consultants 1983)
Due to the undefinable relationship between availability loss and coal characteristics engineering correlations cannot be used directly to evaluate the impacts of coal quality on availability At present the only way to calculate availability loss due to particular coal parameters seems to be to correlate
performance observations in the operating boiler with coal quality data Illustrations of these type of observations have been given above On a larger scale than single power station observations the statistical studies conducted by TVA (Barrett and others 1982) EPRI (Heap and others 1984) and the National Economic Research Associates (NERA) (Corio 1982) (see also Section 731) provided correlations for availability parameters of boilers with
ash sulphur and the age of the boiler (TVA study) actual ash sulphur and moisture content utilised and differences between actual and design values a complex relationship involving 13 independent variables
Most of the methodologies above resulted in equivalent availability values increasing with ash and sulphur contents which is contrary to expectation The correlation utilising the difference between actual and design coal quality values with availability agreed with expectation in that the availability of a power station should be degraded by deviation from the design coal specification A more detailed account of statistical studies is given in Section 731
64 Comments In any final analysis the economic trade offs which take into account system availability cost of coal (at various quality levels) maintenance costs substitute fuel and capacity costs station replacement costs etc must be analysed for each operating situation Only then can any meaningful and specific conclusions about the cost impact of coal quality on the cost of electricity be made Final judgements are often required to compare these costs with other factors such as diversity of supply reliability control of emissions for environmental reasons balance of trade and currency availabilities in order to make final coal selection decisions
Whichever judgement is made it is widely accepted that the capacity availability and cost of operation of each individual boiler are materially affected by the quality of coal fed to it It is generally believed that availability does not depend on the quality of the design coal and will only be affected if the actual coal burnt is outside the design range (Cagnetta and Zelensky 1983) However experience at some stations have shown that substantial losses in availability or down ratings can occur when the quality of the coal used is not outside the design range A summary of these effects is shown in Table 31 The missing links though in coal quality evaluations are the lack of information concerning power station performance and the ability to attach a price to a change in performance as a result of a change in coal quality
There is also the problem that some affects of a change in coal quality require time to show themselves Proper allowance must also be made for this incubation period
Hitherto the accounting systems of many utilities have not been designed to identify easily the costs associated with coal quality impacts (Skinner 1988) These systems need to
77
Coal-related effects on overall power station performance and costs
Table 31 Examples of boiler fireside variables station and cost components which may be affected by those variables when coal quality is changed (Sotter and others 1986)
Variable type Boiler design Operating conditions cost component
affected Coal quality
Capacity Ash size distribution - organic associations - separate species Moisture content Hardgrove grindability index Sulphur content
Heat rate illtimate analysis Moisture content Slow burning macerals Slagging fouling indices (Steam temperature control)
Maintenance Ash content Ash composition (abrasiveness slagging tendency)
Availability Ash Na 0 CaO Fez03 SiOz etc
be updated and improved if utilities wish to take full advantage of new tools that are becoming available In particular improved data are required to support the
Number of mills Precipitator collecting area
Burner type Furnace size
Number and placement of soot blowers
Heat releasefurnace area Convective tube spacing
Excess air
Excess air Coal particle sizes Burner settings
Load history
Load history Soot blowing interval
increasingly sophisticated computer models which can be used to predict the effect of fuel quality on station performance
78
7 Computer models
The decision to buy particular quality coals from either local interstate or from international sources must include a quantitative evaluation of the impact of coal quality on performance of the power station and ultimately the cost of electric power generation As has been demonstrated in Chapter 6 and illustrated further in this chapter the cheapest coal to buy does not necessarily produce the cheapest electricity Because of the large number of processes involved in the coal-to-electricity chain and the complicated nature of coal-power station interactions engineering and economic evaluation studies are usually both time consuming and costly The methodologies adopted can range from manual calculations and a reliance on practical experience with similar coals through to elaborate computer models which calculate performance and resulting economic impacts directly from coal quality data power station design information and economic factors Use of a computer based model to quantify the impact of coal and system parameters on the cost of electrical generation could substantially reduce the time and cost of these studies In theory such a model would be used to evaluate various approaches and the most economic action could be selected with relative ease (Ugursal and others 1990) However it should be noted that the results from the models are only as good as the data used in particular the coal properties measured to predict combustion performance
For the purpose of this report the types of models available for the evaluation of part or all of the coal-to-electricity chain (see Figure 1) have been identified as belonging to one of four categories described below
least cost coalcoal blend models that assess the cost of coals and their associated transport costs They can calculate suitable coal blends according to power station design specifications to provide the lowest cost purchasing plan They may also include allowances for some maintenance and disposal factors
component evaluation models that predict the performanceefficiency of the subsystems of the power station such as mills boiler ESPs unit models that offer coal quality impact evaluation of an entire power station and in some cases attempt to supply costs of the impacts on generation Two methods most commonly put forward as evaluation techniques include
statistically-derived regression analyses leading to overall power station inputoutput models developed for specifying general utility power station requirements These models however do not usually contain detailed predictions of system operation or design requirements
systems engineering analysis for defining relative impacts of fuel properties on each systems performance These types of models are being developed by both equipment manufacturers and research contractors and utilise in addition to fuel property data (that is proximate and ultimate analyses and slagging and fouling indices) special bench-scale measurements of key parameters and pilot-scale data These data combined with the proprietary models can allow for the determination of operating limits for specific units
integrated site models that bring together the information from unit models systems performance and other models and are integrated directly into the control room data system
In this chapter brief examples of the above methodologies are described with particular emphasis given to unit models which are known to include coal quality impact assessments Although particular attention is given to coal specification details used by the models the overall intention is to provide a cross-section of the procedures and the capabilities of the various methodologies
79
Computer models
71 Least cost coalcoal blend models
Least cost models in most cases use linear relationships for the evaluation and purchasing of fuels for power stations The technique is used to find the lowest cost purchasing plan for a utility fuel buyer from among a large number of fuel supplies available and will meet the constraints imposed by the fuel supplies and by the utilityS system The programs are usually designed to run on personal computers and to be user-friendly (Allman 1987 Bek 1987 Hodde 1988 Maher and Smith 1990)
Examples of this type of model include the International Coal Value Model (ICVM) (Maher and Smith 1990) Least Cost Fuel System (LCFS) (Hodde 1988) and Perfectblend (Bck 1987) and Steam coal blending plan (Allman 1987 1991) for blending coals
Least cost coalcoal blend models are reported to have the ability to conduct an economic evaluation of thermal coals as traded on the world market The main users of the models are identified as power companies buying coals of various properties and costs from a number of sources In many cases
blending of coals would also be employed The coals would be selected by the model in accordance with the coal specification requirements of the power stations based on their design and operating experience They are designed as a tool to determine the real cost of coal and energy at the inlet of the power station being considered (see Figure 1 Sections 1-4 of the coal-to-electricity chain) They permit comparison of all coal properties within allowable power station coal specifications including other coals and blends It allows for the blending of a large number of coals in any desired proportions (Maher and Smith 1990) Examples of the types of input data required and the items included in the results for a Least cost model are given in Tables 32 and 33
This type of model does not apply merits or demerits in value for particular properties for example sulphur The reason given by the developers is that the effect of such properties is very site-specific being dependent on the design of the power station and accessories for example flue-gas desulphurisation environmental regulations applying residue disposal costs etc
Hodde (1988) illustrated the use of the Least Cost Fuel System model by considering a utility system with three
Table 32 Model input output data -International Coal Value Model (ICVM) (Maher amp Smith 1990)
Developer Coal input Generating unit input Key output
Joint Coal Board CSIRO Australia
Gross specific energy Total moisture Proximate analysis Elemental analysis Chlorine Phosphorus Free swelling index Hardgrove index Ash fusion temperatures degC Top size mm Fines ltlmm Sulphur form Ash analysis Cost fob cif Currencies amp
exchange rates Ocean freight costs Insurance costs Handling costs
Power station power output MW Generated thermal efficiency Capacity factor
Gross and net specific energy and other properties calculated to different bases and units
Slagging and fouling tendencies Average blend properties with non-linearity warnings CoalconsumptionUy Ash production Uy Cost of coal at pulverisers in various currencies on a
tonne per consignment and per energy unit basis Thermal coal database
Table 33 Comparison of coal energy costs based on gross heating value (at power station pulverisers) - in order of increasing cost (Maher and Smith 1990)
Coal Cost US$GJ Total Specifications moisture
ash VM gross specific energy MJlkg
BBB 206 90 1193 330 2953 AAA 212 95 1238 316 2909 Blend 2 220 84 1434 288 2903 Blend 1 222 86 1406 291 2901 CCC 229 80 1596 260 2869
80
Computer models
coal-fired power stations evaluating the purchase of coal from eleven coal sources supplying contract and spot deliveries Like the ICVM model the objective function to be minimised includes the sum of the fob mine coal cost transport cost and coal quality costs for all three stations on the system But unlike the ICVM the LCFS includes additional costs related to coal quality that are net of the following
maintenance costs assumed to be linearly proportional to the tons of ash processed by each power station ash disposal costs also assumed to be linearly proportional to the tons of coal burned at each station fuel handling costs assumed to be linearly proportional to the tons of coal burned at each station FGD operation and maintenance cost and FGD residue disposal costs assumed to be linearly proportional to the tons of sulphur removed from the flue gas revenue from the sale of ash for construction material assumed to be linearly proportional to the ash content of the fuel
These factors are calculated separately and fed into the LCFS model Additional constraints can be added for utility application For example some utilities are located in regions which have legislated that a certain fraction of the coal burned for power production must be sourced from the region
These programs make only limited provision for coal quality because most of the effects on costs are non-linear so that they cannot be accommodated by these models Warnings are issued by some models of the non-linear behaviour of coal blend properties for example Hardgrove grindability index ash fusion temperatures and ash analysis
Coal quality impacts that are not assessed by the simple models include
slagging and fouling costs cost of reduced boiler availability impacts of coal quality on gross power station heat rate and boiler efficiency impacts of coal quality on the capacity of various station systems including mills fans and ash handling systems
72 Component evaluation models Since the mid-1970s boiler manufacturers utilities and other research centres have been developing advanced numerical system models that can be used to optimise performance of power station components and hence improve overall system performance Most of the development effort has been directed to modelling the boiler With the increasing availability of substantial computing power numerical simulation of combustion systems is now feasible and provides a new engineering tool for evaluating designs and the complex interactions in the flow and combustion processes More recently the techniques have been applied to improve understanding of NOx formation and control in increasingly complex combustion systems For boilers the intricacy of the models range from single zoned one-dimensional (I-D) models
that predict combustion and thermal efficiency for boilers with staged or unstaged combustion systems (Smith and Smoot 1987 Hobbs and Smith 1990 Misra and Essenhigh 1990) to models attempting to solve the fully elliptic multi-zoned three-dimensional systems with finite difference approximations of the conservation equations for mass momentum turbulence combustion and heat transfer (Thielen and others 1987 Boyd and Lowe 1988 Gomer 1988 Jarnaluddin and Fiveland 1990 Luo and others 1991) A widely used boiler computer code known as FLUENT has also been applied to model PF boilers (Tominaga and Sato 1989 Swithenbank and others 1988 Vissar and others 1987 Lockwood and Mahmud 1989) Other examples are documented in literature and a review of the application of these types of models to addressing both NOx formation and unburned carbon has been presented recently by Latham and others (1991a)
The output from these models includes coal particle trajectories within the boiler predictions of unburned carbon involving coal devolatilisation and char burnout models furnace exit gas temperatures (FEGT) species concentrations heat release and heat absorption (Latham and others 1991a)
The coal characteristics that have been found to have the greatest influence in these boiler models are
ultimate analysis carbon hydrogen nitrogen sulphur oxygen
moisture content volatile matter content ash content heating value particle size distribution
Most of the models do not include provision for the effects of fouling and slagging propensity of a particular coal on heat transfer Work on developing computer models that describes the transformation of mineral matter during combustion the mechanism of ash deposition on surfaces as well as the physical properties of the ash deposit after deposition has been initiated (Hobbs and Smith 1990 Smith and others 1991b Beer and others 1992) Baxter (1992) has recently reported the development of a model that considers ash deposit local viscosity index of refraction and ash composition (ADLVIC) in coal-fIred power stations In contrast to other ash deposition predictor models which are based on the elemental composition of ash ADLVIC is based on the mineralogical description of a coals inorganic matter and can be used to predict changes in these mineral properties with time and their effect on ash deposition as the particles flow through the boiler It has received some validation during a three week test burn in a 600 MW boiler operated by Centrallllinois Public Services The approach of using mineralogical descriptions of a coals inorganic matter has also been utilised in a model called the Slagging Advisor developed by PSI Technologies (Heble and others 1991)
81
Computer models
I
Performance factors
MAXIMUM MILL CAPACITY
INLET AIR TEMPERATURE
GRIND CHARACTERISTICS
POWER ~
I
I
I I
Indicescorrelations
Fineness bull passing 200 mesh bull gt50 mesh
Grindability bull
bull HGI Wear
bull abrasion index bull ash burden bull wear index bull equal life
moisture
Pulverised coal distribution bull Rosin - Rammler distribution
function perameter
Mass throughputMMBtu
HGI
moisture
i
Engineering analysis model
COMPOSITE MILL MODEL
- Maximum capacity bull base capacity (as new - of MCR) bull 10ssMMBtu throughput
- Inlet air temperature bull minimum inlet temperature
- Mill power
I
U)0 ttl
~ 0 Q5
~ 0 0 E
Q Level 1 predictions
Q Level 2 predictions
Figure 3D Mill engineering model analysis approach (Nurick 1988)
Nurick (1988) describes an engineering model for the detennination of performance factors for each major system component as impacted by coal quality The modelling approach for each component is described For example Figure 30 illustrates the analysis approach for the mill engineering model The figure also highlights two levels of prediction capability The first level is based on the manual assessment of indicescorrelations of the coal properties and the second level refers to predictions from correlations obtained from application of the mill model The latter predictions can be included into an overall power station model In this particular case the overall performance model does not include any cost evaluations These models can form part of larger more comprehensive systems engineering unit models as described in Section 73
73 Unit models The development of models to assess the impact of coal quality on overall power station performance was initiated in the 1970s when statistical methods were used to compare historical power station performance and cost data (such as forced outage hours or maintenance costs) with coal use and coal quality data in order to fmd working relationships
More recently engineering-based methods have been employed to predict power station performance directly from coal characteristics by using individual component models as modules in an overall power station model In some of the unit models both statistical assessments and operating experience are employed to produce an overall assessment
731 Statistically-derived regression models
Most statistical studies of coal quality impacts on power station performance have been conducted by utilities and research organisations in the US A notable and extensively publicised statistical study has been performed by Battelle Columbus Laboratories and Hoffman-Hold Incorporated on Tennessee Valley Authoritys (TVA) coal-fired power stations (Barrett and others 1982)
The TVA study was aimed at evaluation of how coal quality impacts on boiler operation and costs Information was collected from nine TVA power stations for the period 1962 to 1980 based on monthly proximate analyses of the coal used power station outages maintenance costs boiler
82
Computer models
Table 34 Boiler groupings in TVA study (Barrett and others 1982)
Plant and unit Size Manufac- Firing Stearn Year put Capacity Coal Firing configuration MWlUnit turer methodsect temperature into
degC COF) commercial gt500 MW lt500 MW Midshy
operation Large Small Eastern Western Wall Tangential
Bull Run 1 950 CE PF-DB 538538degC 1967 j j
(10001OOOdegF) Colbert 1-4 200 BampW PF-DB 566566degC 1955 j j
(l0501050degF) Colbert 5 550 BampW PF-DB 566538degC 1965 j j
(10501OOOdegF) Gallatin 1-2 300 CE PF-DB 566566degC 1956 j j j
(l0501050degF) Gallatin 3-4 328 CE PF-DB 566566degC 1959 j j j
(l0501050degF) John Sevier 1-4 200 CE PF-DB 566566degC 1955-6 j j
(l0501050degF) Johnsonville 1-6 125 CE PF-DB 538538degC 1951-3 j j j
(l 0001 OOOdegF) Johnsonville 7-10 173 FW PF-DB 566538degC 1958-9 j j j
(l 0501OOOdegF) Kingston 1-4 175 CE PF-DB 538538degC 1954 j j j
(l0001OOOdegF) Kingston 5-9 200 CE PF-DB 566566degC 1955 j j j
(l0501050degF) Paradise 1-2 704 BampW Cyc 566538degC 1963 j j
(l 0501OOOdegF) Paradise 3 1150 BampW Cyc 538538degC 1970 j j
(l 0001 OOOdegF) Shawnee 1-10 175 BampW PF-DB 538538degC 1953-6 j j j
(l0001 OOOdegF) Widows Creek 1-6 141 BampW PF-DB 538538degCj[ 1952-4 j j
(l 0001ooodegF) Widows Creek 7-8 550 CE PF-DB 566538degC 1961-5
(l 0501 OOOdegF)
BampW = Babcock amp Wilcox CE = Combustion Engineering FW = Foster Wheeler PF = pulverised fuel Cyc= cyclone fired DB = dry bottom
II Units 1-4 do not have reheat
efficiency and where available griruklbility data The data were organised into 15 groups of similar boilers (see Table 34) In addition six aggregates of these 15 groups were assembled based on the capacity of the boilers (greater or less than 500 MW) coal characteristics (Eastern or Western US coal) and firing configuration (wall or tangential)
A variety of statistical techniques including linear and non-linear multiple regression techniques were used to look for meaningful relationships Power station boiler capacity was considered for inclusion in the analysis but dropped due to lack of precise historical data Operating costs other than maintenance costs as determined by TVA were not deemed dependent on coal quality so that analysis in this area was also discontinued (Barrett and others 1983)
In spite of the fact that considerable quantities of data were available within the TVA system it was recognised at the time that the data were not designed to support this study Hence the preferred data such as data on boiler capacity and detailed coal analyses were not always available The investigators sometimes found themselves under severe
limitations They persisted because they believed that the results from what was originally conceived as a limited study might provide utilities with additional useful information for making decisions conceming coal purchase and use
The study identified some quantitative relationships between certain coal quality properties and power station performance and cost However the statistical analyses suffered from the difficulty of co-linearity (or correlated variables) as it was found that the impact of ash and sulphur also generally increased with boiler age due to unavoidable changes in the quality of the coal supplies over time Analysis of data from most TVA units showed that the ash and moisture contents of the coal together with boiler age had the greatest effect on boiler efficiency (see later Figure 32 on page 86)
Availability on the other hand was found to be influenced mainly by ash and sulphur content of the coal although boiler age was still relevant Only outages attributed to equipment that were exposed to coal flue gas or ash were considered in the analysis Over the range of ash fired at TVA power stations (generally 12 to 14) the statistical relationship indicated that for a typical power station the outage hours
83
Computer models
may vary by 360 hy because of changes in ash content alone Likewise over the range of sulphur values for TVA power stations (generally 10 to 50) outage hours at a typical power station may vary by as much as 870 hy due to sulphur alone
Only maintenance costs for coal-related equipment were considered relevant for evaluating the operating cost variations when fIring different coals It was found that ash sulphur content of the coal and power station boiler age were the independent variables although it was determined eventually that age was not a signifIcant factor affecting maintenance costs so that was dropped from further consideration This is somewhat surprising since it is commonly accepted that maintenance costs for most types of equipment increase with equipment age However the effects of age may have been overshadowed by the effects of changes in coal quality with time especially increasing ash
It was reasoned that maintenance costs were not an instantaneous effect of coal quality but rather a result of firing the coal over a period of time To account for delayed or integrated effects over time (for example erosion) the ash and sulphur mass variables were allocated a lag coefficient of several months in the correlations It was reasoned that correlations which suggested that maintenance costs decreased as ash and sulphur mass increased could be regarded as unreasonable because they did not agree with practical experience Consequently these correlations were dropped from further consideration independent of their statistical significance The final correlations were selected as those which produced the highest correlation coefficient value The correlations for the nine separate TVA power stations are listed in Table 35 There appears to be no relationship between the correlation coefficient and the number of units at a power station In addition to these separate power station correlations an overall correlation was developed The optimum correlations were obtained when the lag coefficient for ash and sulphur were set at six and ten months respectively
The reports and reviews of the study stress that the correlations developed for TVA are not necessarily applicable to other power stations because of some significant limitations of the study (Barrett and others 1982 Heap and others 1984 Folsom and others 1986b) First the correlations are based on only one utility - TVA This utility
has its own design philosophy for selecting units its own maintenance and operation strategy and for some units studied there is only one design fuel a bituminous coal Also over the 19 years of data evaluated the TVA units fired only Eastern and mid-Western US coals Thus the range was limited Furthermore TVAs coal purchasing strategy changed such that the coal quality deteriorated to provide higher levels of ash and sulphur as time progressed Thus it was to be expected that the range in ash and sulphur coefficients in the resulting correlations may be at least partially attributable to age effects Overall the study was viewed as an advance in coal quality impact assessment as it had attempted to address the problem of performance prediction and highlighted the inadequacies of coal quality and performance data records
Other studies have been carried out in an attempt to improve and extend the TVA analytical approach Heap and others (1984) reported that EPRI conducted a statistical study to determine whether the TVA methodology could be applied to a more diverse and larger data set that is 25 utilities The study focused on equivalent availability only No attempt was made to separate coal related and other outages Instead a wide range of boiler design parameters were included in the correlation The analysis also utilised the same coal variables as the TVA study ash sulphur and nwisture
As discussed earlier in Section 634 EPRI used an alternative approach to analyse the data In addition to using the log of equivalent availability as the dependent variable and linear ash and sulphur terms based on the as-fired coal data EPRI also used the equivalent availability directly as the dependent variable and the difference between the actual and power station design values of the ash sulphur and moisture content of the fuel as the independent variables This approach makes the effects of coal changes additive terms rather than multiplicative terms as in the TVA approach and the correlation exhibits a relationship that reflected engineering judgement such that the availability of a power station is degraded by deviation from the design coal specification Heap and others (1984) compared the correlations developed by the TVA and EPRI studies by using them to evaluate the effects on a 1000 MWe unit (see Figure 31) The base availability loss due to coal related effects was taken as 97 Base case coal was the design coal and the effects of increasing ash and sulphur content by
Computer models
Correlation predicts maximum 55465 h
100
lt 806
vi Q) OJ co 605 0 -0 Q) range for 6 ro correlations of ~ 40 large unit groups Cii 0 u 0 Ul 200 0
97
0
Base 5 ash increase
8760 (full year)
8000
CfJ
6000 ~ c Q) OJ CIl 5
4000 ~ Q)
ro ~ Cii
2000 8
o
2 sulphur increase
Decreasing coal quality ---
Figure 31 Comparison of TVA and EPRI availability correlations to a 1000 MW boiler (Heap and others 1984)
5 and 2 respectively were calculated The cost of availability loss was taken as $1000000 The ranges of predictions for the TVA correlations based on the 15 groups of similar boilers the six larger groups and the entire database are shown in Figure 31 The correlations based on similar units cover a wide range Note that the large change in coal quality as represented by the changes in ash and sulphur contents in each case evaluated resulted in some of
the correlations predicting greater outage hours than are contained in a year At the other extreme some of the correlations predict that performance would improve with a decrease in coal quality The range of correlations for the larger groups of units was smaller and shows an increase in cost with decrease in coal quality as does the overall correlation The EPRI correlation predicts a greater cost due to coal degradation than the TVA study by a factor of two
A statistical study conducted by the National Economic Research Associates (NERA) USA and reported by Corio (1982) evaluated the impacts of coal quality on gross heat rate and availability based on the performance of 171 coal-fired boilers with capacities greater than 200 MW included in the Edison Electric Institute (EEl) database Only those units which had burned coal exclusively for three or more years were included in the study As with the TVA and EPRI study the coal quality data were limited to the ash sulphur and mnisture contents
The NERA study developed a single correlation with parameters to account for the differences in unit design Table 36 lists the specific variables and coefficients determined in the regression analysis
Both the TVA and NERA coefficients for the correlations are positive indicating that an increase in ash and moisture will increase gross heat rate (GHR) These trends cannot be compared with the TVA boiler efficiency trends exactly as the dependent variables are different Folsom and others (1986b) in a review of the two studies made an approximate comparison by examining the relative changes in the dependent variables (percentage) as ash and moisture content vary This is equivalent to neglecting the NERA GHR correlation The
Table 36 NERA study - gross heat rate correlation (Corio 1982)
Class Variable
Coal quality
Unit designoperation
Ash H2O
Vintage
Age
Output factor
Firing configuration
Stearn conditions
Feedwater pump
Oil firing
Constant
Type
Linear Linear
Linear
Linear
Linear
Switch
Switch
Switch
Switch
Independent
Year - woo
Years
Reciprocal
Cyclone = 1 Other = 0
Supercritical =1 Subcritical = 0
Shaft = 1 Other = 0 Stearn = 11565 Other = 0
Oil = 1
Coefficient
1107 1326
6770
4884
11517640
18485
-11953
7255
31563
273500
Output factor = capacity factor(service hoursperiod hours) expressed as
85
Computer models
150 150
125 125
gf2 0
(l) (l)10 1015 0
co~ sectco gt gt C C (l) ~1lJ (l)
7gtlJ lJ a5 075 ~ a5 07500Q Q (l) (l)~ lJ ~O lJ
lt0~ ~ (l) 0- (l)
OJ OJ~0c 05 c 05 co co
r r U U
025 025
O-JL------------------------------o o 2 4 6 8 10 o 2 4 6 8 10
Ash
Figure 32 Comparison of ash and H20 effects on boiler efficiency and gross heat rate (Folsom and others 1986b)
comparison made is shown in Figure 32 where the selected trends of the overall TVA correlation are plotted against the trends of the NERA correlation The trends for moisture were shown to be similar but the effect of ash was shown to be a factor of about 45 greater for the NERA GHR correlation
More recently the Illinois Power Company (Behnam-Giulani and others 1991) conducted a statistical study based on a database containing NERC and Utility Data Institute (UDI) USA data of 5600 unit-years for coal-frred units from 1982-88 They developed four statistical models to describe heat rate equivalent forced-outage rate operation and maintenance costs and capital addition costs In terms of coal quality impacts the models indicated that
heat rate increased by 127 and 74 kJlkWh for each percentage point increase in ash and moisture content respectively OampM costs increase by 005 with each percentage point increase in ash capital addition costs including costs due to wear and tear increased by 010 $kW of installed capacity with each percentage point increase in ash Capital addition costs were shown to decrease with increasing percentage sulphur content This is contrary to actual experience and is believed to be an erroneous result caused by inaccuracies in the database
Some of the models for example the heat rate model were reported to display good accuracy while some others for example the equivalent forced-outage model proved to be less accurate It was believed that further refinement to the data and methodologies was necessary and for this reason the
study results were recommended for secondary (not primary) computations
It should also be noted that as in the earlier statistical studies only the coal qualities ash moisture and sulphur content were considered in the correlations This highlights the difficulty of obtaining relevant and reliable coal data and corresponding power station data to form such correlations
To summarise statistical methodologies have been shown to have several disadvantages
engineering data are required The TVA study evaluated boiler efficiency only and the NERA study evaluated gross heat rate only The statistical correlations provide only a portion of the information required to evaluate net heat rate the full range of designs cannot be correlated If separate correlations are developed for each unit or group of similar units the accuracies of the correlations are reduced due to the smaller number of data points Increasing the number of independent variables included in the correlation also reduces the statistical importance of each variable concurrent variation If two variables change in sympathy it is difficult to determine the effects of each variable independently coal quality variables are incomplete All the studies primarily correlated performance with the coal ash sulphur and moisture contents only due to the limited availability of coal quality data However several other coal quality parameters can have significant impacts on heat rate These effects cannot be evaluated statistically based on the existing databases
86
Computer models
database accuracies The accuracies of the statistical correlations are limited in part by the accuracies of the input data It is difficult to obtain coal samples that are representative of a full year or even a month of firing database representativeness Statistical correlations are based on limited databases poor accuracy The statistical correlations have fairly wide error bands
multitude of results For example for any given unit in the TVA system boiler efficiency can be evaluated by the individual correlation capacity correlation fuel type correlation and overall correlation Each of these correlations predicts a different effect of ash and moisture content Also the trends of ash and moisture content effects on boiler efficiency and gross heat rate predicted by the four studies are somewhat different particularly for ash
COAL PROPERTIES POWER STATION DATA
Total moisture Unit size Proximate analysis Transport Ultimate analysis Pulverisation
Sulphur Fly ash collection Calorific value Emission limits
HGI Ash disposal Ash fusion temperature
Ash resistivity
HEAT amp MASS BALANCE
(Combustion drying steam production flue gas loss FGD reheat)
STREAM FLOW RATES ampCOMPOSITION
(coal flue gas fly ash)
COAL TRANSPORT HANDLING STOCKPILING
POWER STATION OPERATIONS
(pulverisation electrostatic precipitation flue gas desulphurisation ash disposal)
NET POWER PRODUCTION
OPERATING COSTS
(centskWh as a function of fob coal price)
Figure 33 Outline of CIVEC model operation (Meyers and Atkinson 1991)
87
Computer models
732 Systems engineering analysis CCI Valuation of Energy Coals (CIVEC) Meyers and Atkinson (1991) have reported on the
Several advanced systems engineering-based models have development of ClVEC a techno-economic model by been developed in Australia Canada and the USA in the last Carbon Consulting International Australia to evaluate coals decade The models can be used to predict the overall on the basis of their cost effectiveness in terms of net power coal-related generation cost and become ultimately the generated when applied to a specific generating system The singular basis of comparison for all coals being considered valuation is based on a reference coal whose properties and taking into account the coals effect on availability power fob price are well established station capacity operating costs maintenance costs and power station performance as well as the unit price of the Details of the coals to be studied and specific power station coal In general the method used by systems engineering parameters are entered into the model Heat and mass models is to apply values to coals being considered with balances are determined using these parameters so that the respect to reference coals whose properties fob prices and annual coal requirement may be established The cost effect performance are well established of the coal properties are determined for different sections of
the power station (see Figure 33) The fob price of the study Many models are now available to run on personal coal is subsequently adjusted to give a power production cost computers whereas in the past large main frame systems equivalent to that obtained with the reference coal This were required to carry out the necessary computations model assumes that the overall power station design will be
suitable for the coals studied in terms of parameters such as Several illustrations that use these techniques based on fouling slagging and NOx emissions predictive calculations and comparison with the performance of reference coals and others that utilise a combination of An illustration of the use of ClVEC to assess a suite of these and statistical techniques are presented below In each typical steaming coals from New Zealand Australia and case the coal qualities used and assumptions made in the USA relative to a reference coal was reported by Meyers and model are highlighted Atkinson (1991) The reference coal used in the study was
Table 37 CIVEC coal specifications input (Meyers and Atkinson 1991)
Base Coal A Coal B Coal C CoalD
Total moisture as 80 140 150 100 90
Total ballast as 224 178 228 220 211
Proximate analysis ad Moisture 22 90 70 25 60 Ash 153 40 85 130 125 Volatile matter 258 370 280 315 335 Fixed carbon 567 500 565 530 480
Total sulphur ad 035 025 035 080 110
Heating value MJkg (gross ad) 280 276 281 289 285 MJkg (gross ar) 264 261 256 267 256
Ultimate analysis daf Carbon 839 800 835 840 830 Hydrogen 50 55 45 50 60 Nitrogen 16 20 20 20 15 Oxygen 91 125 96 82 84 Sulphur 04 00 04 08 11
Hardgrove grindability index 49 50 60 50
Freight rate U5$t 1000 1000 1000 1000 1000
total moisture (as) + Ash (as)
Coal quality data were obtained by averaging numerous coal qualities from various mines Coal A Typical New Zealand steaming Coal B Typical low ash low sulphur Australian steaming Coal C Typical high ash high sulphur Australian steaming Coa1D Typical high ash high sulphur US steaming
88
Computer models
Table 38 CIVEC power station operational parameters (Meyers and Atkinson 1991)
Reference coal Coal A Coal B Coal C Coal D
Quantity Mtly 1453 1483 1503 1448 1409 Boiler efficiency 889 880 885 884 878 Mill-capacity factor 093 127 120 108 105 - Power drawn MW 289 216 222 268 268 SOz in flue gas (ppm) 531 363 528 1168 1636
(gGJ) 231 153 214 498 703 Required ESP efficiency 998 993 996 998 998 Residue Mtly 0228 0068 0134 0219 0235
see Table 37 for coal types
Table 39 CIVEC factors contribution to utilisation value (Meyers and Atkinson 1991)
Basis Base coal at 4085 US$t fob standard plant 90 capacity
Coal type Cost variations US$1t
2 3 4 5 6 Utilisation value US$t fob
A -080 -025 180 270 250 070 4750 B -135 -040 100 150 040 030 4230 C 015 005 000 005 -395 -235 3480 D 135 040 -025 -035 -585 -300 3315
1 Variation in coal tonnage to provide same energy input 2 Difference in transport and handling costs 3 Maintenance costs (induding overheads) 4 Disposal costs (including overheads) 25 US$1t waste 5 FOD costs (including overheads and limestone 20 US$t)
6 Power consumption difference - mainly pulverisers and FOD
also an Australian Hunter Valley thennal coal which was well established with Japanese power utilities Table 37 summarises the properties for each coal used in the study The power station modelled was a 500 MW unit with a capacity factor of 90 Ash collection was implemented with a cold side ESP Each coal type was valued under these base conditions and also for a range of residue disposal costs (0-50 US$t) and 100 flue gas scrubbing with limestone costs set at 20 US$t Table 38 summarises the power station operational parameters for each coal studied Table 39 shows the utilisation value resulting from the model together with the component contributions to coal value It should be noted that highest utilisation value implies the best coal for the system For example coal A whilst requiring a small additional annual tonnage as a result of a slightly lower heating value with respect to the reference coal (see Table 39 - minor penalties indicated under factors 1 and 2) actually compares favourably with the base coal case due to its very low ash level (low residue disposal costs) and lower than reference sulphur level (low FGD costs) The authors of the report pointed out that unit availability and the handleability characteristics of each coal have not been taken into account and that the costs of domestic transport were not included in the study In this respect the model does not take into account 100 of available coal quality impacts on power station perfonnance but can be considered as an improved least cost type model as described in Section 71
COALBUY In 1976 Carolina Power And Light Company (CPampL) developed a program called COALBUY which they use to calculate the operating expense incurred by utilising coal of a given quality at a selected generating unit The program essentially evaluates a series of six potential penalties
boiler efficiency auxiliary power requirements coal handling equipment maintenance ash handling equipment maintenance ash storage cost replacement power due to load limitations
The program contains an extensive database for each CPampL coal-fired generating unit together with detailed specifications for a reference coal Each offered coal is compared with the reference when calculating potential operating penalties Any penalties are added to the offer price of the coal to obtain a total cost of burning it The program is also used to predict the extent to which a unit might be load-limited when burning off-specification coal Details utilised for each unit are given in Table 40 The operating data listed are taken from actual performance tests at a series of load levels
COALBUY is in fact a sub-routine of CPampL s EVAL
89
Computer models
Table 40 Model input output data - COALBUY (Corson 1988)
Developer Coal input Generating unit input Key output
Carolina Higher heating value Net unit heat rate Operating penalties Power amp Light Grindability Base boiler efficiency Total cost of coal ($IMBtu) USA Proximate analysis Estimated boiler radiation losses Load limitation on generating unit capacity
Total sulphur content Ambient air temperature Identification of system causing the load limitation Purchase price including Ambient air humidity ratio Operating characteristics of boiler fans with
transport Stack gas temperature reference to coal and purchased coal Standard deviation of the Unburned carbon in fly ash Boiler efficiency losses and related parameters
variation in higher Unburned carbon in bottom ash - boiler efficiency heating value Carbon dioxide and oxygen in the - auxiliary power requirement
boiler gases entering and leaving the - coal handling equipment maintenance air heater - ash handling equipment maintenance
Monthly unit demand profiles - ash storage cost - replacement power
The operating data listed above are taken from actual boiler tests at a series of load levels
Also includes escalation factors for database cost factors
program which was developed to maintain files on quotations a coal buyer in making a detailed assessment of cost and and purchase orders to select suppliers of spot-market coal performance impacts of using a candidate coal in his power and to plan the distribution of long-term and spot-market station Model input and output parameters are summarised purchases throughout CPampLs generating system each month in Table 41 (Corson 1988)
The system establishes the coal rank (based on ASTM D388 Coal Quality Advisor (CQA) guidelines) ash type and determines ash fouling and The CQA expert system was developed by a joint utility slagging characteristics based on empirical slagging and (Houston Lighting amp Power Company (lllampP)) and fouling indexes It compares the provided analysis values architectengineering company (Stone and Webster) team against those expected for the reference of coal and coal ash (Arora and others 1989) Its intended application is to assist Arora and others (1989) describe the specific functions in
Table 41 Model input output data - Coal Quality Advisor (CQA) (Arora and others 1989)
Developer Coal input Generating unit input Key output
Houston Lighting amp Power Stone amp Webster Engineering Corporation USA
Proximate analysis Higher heating value Ultimate analysis Sulphur forms Ash mineral analysis Ash fusion temperature Trace elements Equilibrium moisture Quartz content Coal size Coal cost (fob)
Pulveriser horse power input Number of mills in service Plant capacity factor PA temperature (OF) amp pressure (lbft2mill) Primary air to fuel ratio (lbairnbfue1 )
Plan area heat release rate actual (Btuh ft2 x 106)
Boiler efficiency () Approximate net heat rate (BtukWh) Limestone cost Total change in OampM costs ($y) Annual fuel flow (ty) Differential power costs at equivalent coal flow (ty)
Intermediate output variables Maximum mill capacity (th) Required coal flow (Pph) Coal flow per mill (th) Percent base mill Super heater gas velocity (ftsec) Reheater gas velocity (ftlsec) Air flow (lbh) Excess air () Fuel flow (Pph) from boiler calculations Annual fuel flow 075 capacity factor Gas temperature - out CF) Bottom ash flow (Pph) Fly ash flow (Pph) Volumetric heat release (Btuh x 106)
Furnace exit gas temperature (OF) Limestone usage rate (th) Unburned carbon (lbslOO lbs coal)
90
Computer models
greater detail than can be discussed here It should be noted that due to the lack of a suitable database the basis of OampM cost methods was a percentage of equipment capital costs for each major power station component
The model has been validated for HLampP use It has been reported to have been used for (Arora and others 1989)
blending of up to five coals to a specific mix or to achieve a specified quality for the blend (that is sulphur ash heating value) classifying the coal (blend) to permit assessment in various components of the power station determination of empirical slagging and fouling indices evaluating the required performance against the given limits for the major components of the power station determination of OampM costs and the net heat rate change for a candidate coal relative to a given base coal unit No 8 at HLampP Parish power station but it can be configured to enable evaluation of other coal-fired units in the HLampP system with minor changes
The impact assessment for each of the systems is classified by severity level and displayed to the user with appropriate recommendations
Coal Quality Engineering Analysis Model (CQEA) From 1963 to the mid-1970s NYSEG have used a coal evaluation program to determine bonuses and penalties on each parameter of the coal offered by suppliers (Mancini and
others 1988) In 1975 the company commenced a two-year coal quality study to develop a method of fitting the existing program to each of the five NYSEG generating stations The model approach was changed to combine generating station engineering data with coal analysis data in a workable package for fuel evaluation engineering and economic analyses The result is the CQEA which has been used by NYSEG since 1977
Table 42 summarises the coal input data generating unit data required and the key and intermediate output variables The CQEA is calibrated to each units characteristics The generating unit input data are reported to be recalibrated annually
An illustration of the capability of the CQEA is shown in Figure 34 It compares the overall production cost for five different coals burned in one unit (unit 5 of Figure 34) as calculated by CQEA If only delivered cost is used as a measure to purchase coal then coal 3 would be the lowest cost However the overall cost of coal 1 is about 80 ckWh lower than the overall cost of coal 3 Similarly it is shown that paying the highest cost for high-quality coal 2 compared to coal 1 is not overall economically beneficial Also if the choice were among coals 2 4 and 5 - which are almost equal - the best quality would be chosen knowing the results of the CQEA These results have been verified by actual experience of the above coals in the units discussed
The CQEA system is used by two different groups within
Table 42 Model input output data - Coal Quality Engineering Analysis (CQEA) (Mancini and others 1988)
Developer Coal input Generating unit input Key output
NYSEG Delivered price USA Heat content
Proximate analysis Sulphur Ash softening temperature Grindability
Maximum gross capacity Hours operating at peak and average power Station service power Turbine heat rate Forced draft fan inlet temperature Stack exit gas temperature Carbon in ash and ash as fly ash versus
bottom ash moisture added to ash for dust-free disposal
Excess combustion air Base pulveriser capacity Pulveriser capacity correction factors for
fineness and grindability Radiation amp unaccounted boiler loss Fuel oil rate for low volume coal Minimum volatiles in coal without ignition oil
Average gross generation Ash collection capacities fly ash
and bottom ash Ash and scrubber sludge disposal cost Flue gas desulphuriser removal
efficiency and OampM costs
Cost of coal and oil burned Ash disposal costs Maintenance costs for coal and ash handling equipment Scrubber OampM and waste disposal costs Replacement power cost Net output MWh Replacement power MWh
Intermediate output variables Boiler efficiency () Total station service power () Net station heat rate (B tukWh) Percent utilisation of capacity Total Btu fired in coal and oil
Additional system data Maintenance wage rate Replacement power demand and energy charge Fuel oil heating value and price
91
Computer models
D coal quality - related costs 16shy D delivered coal cost
14 c 3 ~ 12ifgt U5 0 100
u c 0
OJ 8 D 2 0shyD 6 (j)
iii ~ 4 a OJ
u 2
0 Coal 1
MJkg 256 ash 210 moisture 70 sulphur 21
Coal 2 Coal 3 Coal 4 CoalS
302 263 284 270 120 203 127 177 40 53 72 70 27 12 26 20
Figure 34 CQEA evaluation of the impact of different coals on overall production costs of one unit (Mancini and others 1987)
NYSEG These are the Perfonnance and Fuel Engineering group which maintains the CQEA calibration factors for each unit and the Fossil Fuel Supply group which uses the
BOILER bull subcritical PC bull supercritical PC bull parallelseries backpass bull flue gas recirculation
COAL PREPARATION bull 41 mill offerings bull vertical spindle mills bull exhauster mills bull other
r
BOnOM ASH SYSTEM bull wet system
- jet pumps - centrifugal pumps
COAL HANDLING bull rail truck bargeship conveyor unloading bull emergency and normal stockout bull stacker reclaimers lowering wells
other reclaim systems bull ring granulator hammermill crushers
CQEA as a tool for evaluating coal purchase offers from coal producers (Mancini and others 1987)
Coal Quality Impact Model (CQIM) In 1985 Black amp Veatch a US architect-engineering group and EPRI worked together to develop a comprehensive computer program for predicting coal quality impacts The result was the Coal Quality Impact Model (CQIM) As of the end of 1991 112 copies had been distributed to 72 different utilities and six different companies or agencies Black amp Veatch has also sold the program to eight companies including four outside of the US Four additional sales to non-EPRI member companies are in their last stages of negotiations This is the most widely used systemsshyengineering model in the world
The role of CQIM is to quantify both perfonnance and cost impacts associated with changes in coal quality (Evans 1991 Stallard and Mehta 1991) The equipment types modelled by CQIM are summarised in Figure 35 As described earlier for other models CQIM evaluates alternative coals by comparing them with a reference or current coal supply It is also designed to consider station-specific design and operation characteristics on a component-by-component basis as well as the unit as a whole This allows the CQIM to identify potential system limitations (sources of derate)
The effort required to collect CQIM input data varies according to the background of the user the availability of data and the purpose of the evaluation CQIM contains a
AIR HEATERS bull bisectors bull trisectors
PARTICULATE REMOVAL bull hot ESP bull cold ESP bull fabric filter
1 FLY ASH HANDLING bull pressurisedbull vacuum
FD FANS bull axial bull centrifugal
~
~ PA FANS bull axial bull centrifugal bull coldhot bull exhuasters
Figure 35 Equipment types modelled by CQIM (Galluzzo and others 1987)
ID FANS bull axial bull centrifugal
SRUBBER ADDITIVE bull limestone bull lime bull none
to stack
t GAS REHEAT bull 5 alternatives
f---shy FGD SYSTEM bull wet limestone bull spray dryer --- bull none
WASTE DISPOSAL bull stabilised waste bull fixated waste bull evaporation ponds bull other
92
Computer models
Table 43 Model input output data - Coal Quality Impact Model (CQIM) (Stallard and others 1988 Stallard and Mehta 1991)
Developer Coal input Generating unit input Key output
EPRI amp Heating value Black amp Veach Ultimate analysis USA Moisture content
Ash content Chlorine content Sodium content in ash HOI Ash fusion temperatures Ash analysis Fuel cost Transport cost
Unit size (MW net) Capacity factor () Net power level Auxiliary power requirements Auxiliary equipment specifications
and capacities Hours of operation Net turbine heat rate (BtukWh) Excess air level () Boiler losses Boiler dimensions Soot blowing details Tube bank configurations Maximum heat input per plan area (MBtuJhft2)
Design FEGT Maximum allowable flue gas velocity Economiser
Economic data Replacement energy cost ($millkWh) Limestone cost ($ton) Salarymaintenance rate ($person-year)
Discount rate Replacement power cost Limestonellime cost Total annual fuel related costs Transport costs Escalation rates Overall unit performance data - slagging fouling and erosion potentials - equipment performance and derate info - maintenance availability data - calculated derate by system - generation cost summary page Sensitivity analysis Comparison tables Error warnings
feature for supplementing data provided by the user This default information is based on the data entered by the user the overall power station configuration the characteristics of the design coal and established equipment design practices Since default data can be substituted for most missing data the program can be run with limited input Of course the more actual data used the more comprehensive the predictions
Table 43 illustrates the type of data required for conducting an initial screening evaluation of coal quality CQIM contains programs for translating each major performance impact into a discrete cost component
During the course of the development of the CQIM model validation was carried out by means of a host utility program Initially 12 utilities worked with EPRI to develop case studies to validate the CQIM equipment performance models The CQIM performance and cost predictions were compared with historical data and actual utility operating experience Any discrepancies were used to modify the program modules and improve the overall predictive capability of the CQIM The case studies covered a wide range of US unit designs and US coals With the sale of the CQIM to international utilities this has prompted the development of CQIM International which will have facilities to convert input data utilising SI units
There are several examples of literature describing the application and validation of the CQIM (Galluzzo and others 1987 Boushka 1988 Stallard and others 1989 Cox and others 1990 Kehoe and others 1990 Afonso and Molino 1991 Giovanni and others 1991 Vitta and others 1991)
Coal Quality Expert (CQE) The US Department of Energy (DOE) selected the
development of the CQE in Round 1 of the Clean Coal Technology program The project initiated in 1990 and scheduled for completion in August 1994 will cost $217 million
The CQE computer system is designed to give utilities a tool that will predict the total cost of impact of coal quality on boiler performance maintenance operational costs and emissions
Figure 36 shows the major components of the CQE system The foundation for the CQE is EPRIs CQIM (see section on CQIM) More than 20 software models and databases including the CQIM a flue gas desulphurisation model a coal cleaning model a transport model and a new power station construction model will be integrated into a single tool to enable planners and engineers to examine the cost and effects of coal quality on each facet of power generation from the mine to the stack The expert system is intended to evaluate numerous options including various qualities of coal available transport methods and alternative emissions control strategies to determine the least expensive emission control strategy for a given power station
It is intended that the CQE will include cost estimating models for new and retrofit coal cleaning processes power production equipment and emissions control systems Individual models are to be made available as they are developed The first of these models the Acid Rain Advisor (ARA) has already been released (CQ Inc 1992) The ARA developed primarily to assist users in managing US Clean Air Act compliance evaluations can be used to quantify costs and emissions allowance needs for potential utility compliance strategies
A core part of the CQE program is extensive data gathering
93
Computer models
ENGINEERING AND ECONOMIC MODELS
bull Coal Quality Impact Model
bull coal cleaning cost model
bull flue gas desulphurisation
bull NOx emissions
ADVANCED USER INTERFACE
Integrated report and graphic capabilities
CQE ASSISTANCE Integrated applications
bull strategic planning
bull plant engineering
bull fuel procurement
bull environmental strategies
bull acid rain advisor
Figure 36 Major components of the CQE system (Evans 1991)
and analysis to validate the models and it is one of the largest efforts ever attempted to link pre-combustion combustion and post-combustion technologies to solve power station emission problems (Evans 1991) Samples of the various coals identified for the project are being collected at mines commercial cleaning plants and the six host power stations Extensive measurements of the performance of all ancillary equipment are taken during the field tests Moreover the project will generate considerable data from laboratory bench- and pilot-scale combustion tests using the same coals All the data will be used to develop and validate the CQE models including those that predict mill wear slagging and fouling precipitator performance flue gas particulate removal NOx formation and the flue gas desulphurisation performance
IMPACT Ugursal and others (1990) reported the development of a computer-based techno-economic model that can predict the impact of coal quality and other key variables on the busbar cost of electricity generated by new power stations The IMPACT model has been structured to focus on four major cost sectors of the coal-to-electricity chain (see Figure 1) This includes transport power station post-combustion particulate and SOz emission controls and residue disposal
Table 44 Ranges of selected coal-ash combustibility parameter that predict approximate classification of CF values (Ugursal and others 1990)
Incombustibility index RI1 Classification of CF values
lt21 21--43 43-75 gt75
94
low laquo017) medium (017-D34) high (034-D47) severe (gt047)
INFORMATION AND DATA BANKS
bull fLe1 sources
bull plant specifications
bull transport rates
bull waste handling
bull coal quality information systems
The impact of coal characteristics on power station performance is quantified in IMPACT as follows
steam cycle heat rate calculation assumes that the boiler is designed for the given coal and operates at design load boiler efficiency is evaluated using the heat loss method (see Section 632) A notable additional approach adopted to evaluate unburnt combustible losses in the calculation of efficiency includes an incombustible parameter Rh which is inversely proportional to the base-to-acid ratio of coal ash Rh is directly proportional to the amount of unburnt combustibles in the fly ash The amount of unburnt combustibles is expressed by CF and can be defined as
CF = [(flyash combustible$ (lb of fly ash formed)] (lb of coal feed)
The approximate ranges of CF values that corresponds to the incombustibility parameter ranges are given in Table 44 Once CF is determined from Table 44 the percentage of combustibles in the coal feed that is lost in the flue gas can be determined from
CFx 100 coal feed combustIbles = n1 1 d b tmiddotbl70coa lee com us 1 es
where the percentage of coal feed combustibles = 100 - ash - moisture with the ash and moisture content determined from proximate analysis of the coal
IMPACT utilises empirical correlations (developed by regression of data published by Bechtel Power Corporation (Holstein 1981)) between auxiliary power consumption and the sum of the ash and moisture contents of the coal for both subcritical and supercritical units (Ugursal and others 1990) availability values of 80 are assumed to apply to new
Computer models
Table 45 Model input output data - IMPACT (Ugursal and others 1990)
Developer Coal input Generating unit input Key output
University of Ultimate analysis () Plant capacity (MW) Levalised busbar cost of electricity Nova Scotia Ash content Unit type Annual operational cost Canada Ash composition () Steam generator efficiency () Capital costs
Heating value Steam cycle heat rate (BtulkWh) Annual coal consumption Cost of coal Flue gas exit temperature
Average load Equivalent availability Auxiliary equipment specifications Cost of limestone
power stations This assumption is adopted due to the lack of information available quantifying the impact of coal quality on the availability of power stations coal consumption and coal bum rate of a given power station are calculated using an energy balance based on the results obtained from the parameters above and the specified annual generation capacity annual ash and S02 generation are determined by a mass balance on the annual coal consumption rate and the ash and sulphur contents of the coal
Although this model has yet to be fully validated the authors carried out sensitivity analyses for a number of coals with various levels of ash and sulphur (Ugursal and others 1990) on a representative power station with two 500 MW units The input and output parameters of the coals and power station for the model are summarised in Table 45 Overall from the study it was concluded that the capital and operating costs of most of the sectors of the coal-to-electricity chain increase with increasing ash content of the coal fIred The authors emphasised that the findings apply for the particular conditions of the case the results might be quite different under other site specific conditions
Coal quality impact study model (CQI) Kemeny (1988) reported on work performed to develop a method of analysis using a combination of statistical and engineering methods which could be applied to any power station operating system The method adopted also developed a model that computes a power stations total coal-related generation cost on a specific coal It was developed initially for an Italian power station Fusina 3 to determine the economics of burning four different coals at the station
The method adopted for the calculation of availability assumed that planned outages were unaffected by coal quality whereas their effects on forced outages was the sole influence on availability Because of the random nature of equipment failures an analysis of forced outage rates was carried out statistically Historical coal usage data were correlated against historical outage data to see if there was a coal quality relationship For Fusina 3 power station the coal type was changed so frequently that data from a single unit were considered suffIcient for such a study The results of the availability analysis are shown graphically in Figure 37 A low correlation coefficient of 0447 was observed for the relationship indicating that there was a fairly high probability
that the apparent correlation between forced outages and ash was due to random scatter of data points and not to any cause-and-effect relationship In addition the large negative y-axis indicated that the regression equation may not have been accurate across the full range of ash values In light of the results demonstrated by this study it would appear that it would be more prudent not to include the results of the availability analysis in the coal quality impact model However the investigators believed that the regression analysis conformed to engineering expectations and because of the probabilistic nature of forced outages it was quite unlikely that with the amount of data available outages would correlate very strongly with coal quality Therefore the results of the availability analysis were included in this coal quality impact model
Coal-related operating costs accounted for in the model cover any cost not specifically covered by fuel costs At Fusina 3 for example these areas included the cost of sulphur for S03 conditioning and the cost of ash disposal Other areas might include the cost of fuel additives scrubber related costs cost of additional equipment The effects of coal quality on the cost of routine and emergency maintenance at the power station is most easily measured statistically in a similar way in which forced outages were correlated
01000
~ L 800 (j)
~
L0 600 81 Q) 0 OJ co 5 400 -0 Q)
0 0
~4() 82 00 200 u
83 o
40 60 80 100
Ash throughput kty
o not included in regression
Figure 37 Correlations of forced outage hours against ash throughput using the cal model (Kemeny 1988)
95
Computer models
Table 46 Assessment of four coals for Fusina unit 3 using the CQI model (Kemeny 1988)
Coals
South Africa Polish American
Low ash High ash
Coal characteristics High heating value MJkg [Btulb] Ash content Sulphur Moisture content Carbon content Ash resistivity ohmcm x E13
Coal cost $GJ [$MMBtu]
Results from model Boiler efficiency Availability US$y Capacity - ESP limit - Auxiliary power
Fuel costs - coal - supplementary
OampM costs - maintenance - flue gas conditioning - ash disposal
Totals
2625 [11291] 1339 038 830
6474 375
153 [161]
8890 3905122
1764549 3765822
25565882 3450848
2806626 24916
458876
4172640
2707 [11639] 1226 063 780
6796 500
163 [172]
8889 3204389
1514442 3817118
27980093 3059766
2538408 9051
330618
424453886
3012 [12950] 742 081 720
7433 500
177 [187]
8931 336355
357460 4033183
33180022 1625800
1440618 o
175209
40798228
2830 [12173] 1152 075 710
7033 500
177 [187]
8886
2459658
2325523 o
228820
44008125
Without going into power station details as this is described elsewhere (Kemeny 1988) an illustration of the type of results produced by the model of the comparison of four coals from Poland South Africa and the USA is given in Table 46
As in the case of other similar models the value of the total coal-related production cost in the cost summary is just an indicator it is neither a calculation nor a prediction of the actual generating cost The number in this model does not include costs such as maintenance costs for non-coal-related systems However it can be used for comparative purposes Quite simply the coal which gives the lowest production cost is the most economical
More briefly other models that have been reported in the literature include
Waters (1987) reported the development of a computerised mathematical model known as ECUMEC Data taken from the model subroutines are used to calculate the power cost for example at the busbar including the cost of coal Once again the method used to assign an economic value to a coal is to select a base coal or yardstick coal to which a coal price (fob) can be ascribed The equivalent value of another coal is that price (fob) which gives the same power production cost as the base coal Waters (1987) demonstrated the
capability of the model by considering the effect of some coal properties such as sulphur ash and moisture content on the equivalent coal value in a 500 MW power station The base coal was a 15 ash Australian Hunter Valley coal The coal price (fob) was shown to be very dependent upon ash with a 5 ash coal worth approximately US$745 more per tonne than a 15 ash coal (based on 1987 prices) The effect of moisture on equivalent coal price is similar to ash but not as marked It was shown using the model that a 05 increase in sulphur content had a much greater effect on coal value than a 5 increase in ash content This was because the capital and operating costs associated with FGD to meet air quality requirements were very high a program developed by Southern Company Services USA to help estimate the benefits from cleaning coals The constituents of coal that were found to affect the cost factors were primarily ash moisture sulphur and carbon content (Blake 1988) the Consol Coal QualityPower Cost model which was used by Deiuliis and others (1991) to evaluate the performance of six US regional coals in a typical 500 MW pulverised coal-fired unit The study was focused on developing a cleanliness factor for model relating to heat flux and soot blower effectiveness data obtained from pilot combustion tests the Coal Utilisation Cost Model which utilises a three-step modelling approach-statistical analysis of
96
Computer models
historical data (source NERC) development of an engineering algorithms and evaluated cost calculations based on the algorithm results (Nadgauda and Hathaway 1990)
733 Integrated site models
With further advancements in computer and sensor technology in the last ten years integrated site models are being developed that allow the integration of information from unit models systems perfonnance and other models directly into the control room data system These programs allow the continuous monitoring of for example selected coal properties such as ash moisture and sulphur furnace and convective pass deposits and can define overall heat rates based on these continuous measurements taken from the unit (Elliott 1991) The diagnostics packages can also include a routine for predicting the implementation and impact of operating practices on heat rate (Nurick 1988 Alder and others 1992)
Smith (1991) and Reinschmidt (1991) have reviewed the wider application of integrated control systems from individual component control to full automation of the power
Coal quality COAL MANAGEMENT
as a function MODULEof time at mills
Coal quality collection and assessment
station and the new computer technologies that are being applied such as neural network approaches that processes input data without identification of particular algorithms connecting the output results with the input data and fuzzy logic An example of this application is the C-QUEL system
Coal quality evaluation system (C-QUEL) Mitas and others (1991) have reported on the current development of a comprehensive software system C-QUEL that will allow utilities to use on-line analysers to try to solve or mitigate existing coal-related problems This will be accomplished by the C-QUEL system by providing information about coal quality before it is burned predict potential effects on operation and provide recommendations of control actions which can be taken to adjust coal quality andor improve power station response to quality changes The use of on-line coal analysers has been reviewed by Makansi (1989) and Kirchner (1991)
C-QUEL is a suite of computer programs which can be used as a basis for control of various processes in a power station Figure 38 shows a schematic of the structure of the system Appropriate control actions will be determined based on a wide variety of information gathered by the operator on-line
ON-LINE PERFORMANCE MONITORING SYSTEM
Equipment status Current performance
Load demand
ON-LINE COAL ANALYSER
SUPERVISORY CONTROL MODULE
COAL QUALITY CONTROLACTION
RELATIONSHIP MODULES
Coal data logging
Monitor CQ and equipment modify operation to
meet goals
DATA ARCHIVE AND TRENDING
USER INTERFACE
EPRI COAL QUALITY IMPACT MODEL
Annunciation Predicted performance Interactive dialogue Information retrieval
Figure 38 Schematic showing the structure of the e-aUEL system (Mitas and others 1991)
97
Computer models
coal analyser real-time station data on-line performance calculations equipment performance predictions and coal flow models The EPRI Coal Quality Impact Model (CQIM) will be incorporated into C-QUEL to provide the prediction capability for the performance of all major power station systems directly impacted by coal quality Operational strategies as a result of expected unit performance will be evaluated by C-QUEL and provided to the operator These strategies will take into account the current and future unit generating requirements as well as cost information associated with each possible action Specific control recommendations and supporting information are presented to the power station operators
Figure 39 shows a simplified case as an example of the use of C-QUEL in which the primary goal is to maximise electrical generation from a base load power station Figure 39a depicts the sequence of events that can be expected at a particular point in time The operator is unaware that a change in coal quality has occurred until a
a) Without C-QUEL
Ash and moisture content have
increased
drop in load is detected In the second scenario Figure 39b the goal of maximising electrical production has been fed into the C-QUEL supervisory module Since decreased mill capacity will have a direct effect on generation this information together with a recommended course of action is given to the operator and allows him enough time to make the proposed adjustments before load production is affected Because of detection of the higher moisture and ash content of the coal supply by the on-line coal analyser a decrease in mill capacity was predicted To prevent any load reduction the operator would be instructed by the system to bring another mill into operation
The project team for development of the C-QUEL system consists of two host US utilities - Oklahoma Gas and Electric (OGampE) and Pennsylvania Electric (penelec) two engineering contractors - Black amp Veatch and Praxis Engineers and EPRI Demonstration of the system will take place at OGampEs Muskogee power station and the Penelec-operated Conemaugh plant OGampEs Muskogee
I I
Only two pulverisers are on-line consistent with the requirements
of the previous coal quality
I I I L_
On
Electrical production has
dropped
Operator determines decreased pulveriser capacity has caused the load drop and brings another pulveriser on-line
b) With C-QUEL Pulveriser module predicts Other controlaction modules decreased pulveriser capacity
Analyser detects Iincrease in coal ash and moisture conten t I
III I +0bull
Goalmaximise output
-
1 Supervisory module evaluates this information relative to operational
t--- goals and constraints and information from other modules
I
A message notifies the
Pulveriser 2
operator of potential generation loss and the need for an additional pulveriser
1-~e~C 1
I I L_
Operator brings another pulveriser on-line before the high ashhigh moisture coal is fed to the fuel preparation system Maximum electrical production is successfully maintained
Figure 39 Comparison of the operations with and without the use of e-aUEL (Mitas and others 1991)
98
power station fires primarily western low-sulphur coal that is currently blended with more expensive higher sulphur Oklahoma coal which also has a higher heating value on a 10 by heating value basis The station must also meet a strict SOz emission limit OGampE has installed an on-line analyser - PGNAA elemental analyser - that will provide data to assist in blending and feeding An elemental analyser has also been installed at the Conemaugh power station Initial data gathering will focus on the Muskogee power station (Mitas and others 1991)
Couch (1991) has also reviewed the influence of integrated computer control and modelling on coal preparation plant
74 Comments The studies described above demonstrate the feasibility of developing various quantitative relationships which are essential for optimum planning and operation of generating units Table 47 summarises the capabilities of the models described in this chapter Many of the results are based on data and methodologies which still require further refinement
When considering the two major techniques for assessing power station performance that is statistical and engineering analysis modelling a weak link with both approaches is within the coal specification parameters used in the correlations
Table 47 Summary of model types and capabilities
Computer models
For the purpose of selecting an economically attractive coal it is important to determine heat rate effects due to coal quality as accurately as possible In their review of statistical and engineering based relationships Folsom and others (1986b) did not believe that the correlations from statistical studies were close enough to be useful for this purpose Consequently the use of engineering correlations and experience to evaluate heat rate impacts was highlighted as the preferred procedure
Engineering based models have their critics also Many utilities apply least cost models for purchasing coals and component models and some acknowledge the benefits of expert unit or integrated models Others remain sceptical over the capability of devising a truly representative model of the coal combustion process Some of the reasons given for this scepticism include
the present methods that describe coal properties require substantial refinement for use in the models as they are not adequate for predictingaccounting for unit performance a belief that coal blending solutions based on pragmatism and simple empirical methods are more appropriate providing a here-and-now solution a belief that processes such as fouling and slagging and mill performance cannot be accurately modelled whilst the basic mechanisms are not clearly understood
Model type Modelling capabilities Developed by Application Comments Model name Assessmentcountry
Heat Capacity Avail- Maintenance Other of origin
rate costs ability costs
Least cost coal coal blend model
Least cost fuel system total fuel cost architectengineer buyer manualAustralia ICVM total fuel cost research organisation buyer manualAustralia Steam coal blending plan - total fuel cost supplier buyer manuallUSA Perfectblend total fuel cost research organisation buyer manuallUSA
Single component model Boiler models --I --I research organisation operator computerintershyand others utilityequip manufacturer national
Unit model Statistical
TVA study --I --I --I research organisationutility operator manualUSA EPR study --I --I --I research organisationutility operator manuallUSA NERA srudy --I --I research organisation operator manuallUSA PC study --I --I --I capital costs utility operator manuallUSA
Engineering ClVEC --I --I estimated total fuel costs research organisation buyer computerAustralia COALBUY --I --I --I --I total fuel costs utility buyer computerlUSA CQA --I --I --I estimated total fuel costs architect engineerutility buyeroperator computerlUSA CQEA --I --I --I coalash handling total fuel costs utility buyeroperator manuallUSA CQIM --I --I --I --I total fuel costs architect engineerutility supplierlbuyer computerlUSAUK
operator CQE --I --I --I --I total fuel costs architect engineerutility buyeroperator computerlUSA IMPACT --I --I --I --I total fuel costs research organisation buyeroperator computerCanada CQI --I --I --I statistical evaluation total fuel costs research organisationutility buyersoperator computerlUSA
Site model C-QUEL --I --I --I --I total fuel costs architect engineerutility operator computerlUSA
total fuel costs for engineering models refers to the total fuel-related production costs in terms of the price of electricity at the busbar
99
Computer models
new advanced boiler configurations such as low NOx
combustion regimes increase the complexity of boiler models many of the models have not been applied to a wide range of international coals and therefore have not received adequate validation
The analysis approach adopted by many of the unit models available can vary in complexity such that a form of quantitative predictability can be produced to a reasonable or to what may be deemed as a high level The lower level of prediction capability has been perceived by critics to produce too general a fmding In contrast the higher level may require more detailed unit specific information than a utility may have readily available such that special provisions would have to be made in order to collect the necessary data (Johnson and others 1991) This is known to be time consuming and is perceived by some operators to detract from the main utility priority that is to produce electricity Others believe that the models incorporate performance measurement errors that may compound to reduce the effectiveness of the model and make it only useful for comparing coals that show a wide range of coal property values
Many of the model descriptions have cited the beneficial role of the model in fuels purchasing It is considered that when models are used in such a manner they could become an improved means of communication between supplier buyer and user as they can ultimately aid the purchase of an economical coal of adequate quality for a particular power station The advantages of having the ability to assign an overall cost to a coal particularly in terms of its impact on component and overall power station performance could prove to be of technical and financial benefit to the utility in helping to justify supplier buyer or operator policies such as coal cleaning blending power station retrofitting or purchase of replacement energy to the advantage of the utility
In general however operators remain reluctant to move toward a predictive approach to coal quality impacts in preference to reliance on post mortem type remedies In the future integrated computer models such as C-QUEL may prove more acceptable when they can provide real time cause and effect information and advice on how to remedy problem situations as soon as they occur and can be seen to rely on dependable input data
100
8 Conclusions
Fuels purchasing and management presents an important opportunity for utilities to control costs It is also recognised that final judgements on coal selection often require a trade-off between these costs and qualitative factors such as diversity of supply reliability control of emissions for environmental reasons balance of trade and currency availabilities The contribution of coal to the cost of electricity extends far beyond the purchase price of the fuel Over the last fifteen years it has become generally accepted by coal-fired power station operators that the capacity availability and cost of operation of each individual component of the power station are materially affected by the quality of coal fed to it To generate power at least cost it is important to evaluate the overall total cost associated with each coal for a particular power station
The principal coal properties that were found to cause greatest concern to operators include
ash content and composition heating value sulphur content moisture content grindability volatile matter content
Enforcement of environmental legislation has resulted in the elevation of total sulphur content to a key position in the specification of coal along with total ash moisture and heating value Table 48 summarises the effects of these properties and other coal characteristics that are used as coal specifications for combustion on component and overall power station performance
Little has changed over the years in the way that coal is assessed and selected for combustion Operators continue to use quality parameters in their specifications that were mostly developed for coal using processes other than direct combustion Whilst many empirical relationships have been
established between coal specifications and certain component and plant performance indicators the coal characterisation tests themselves have been shown to have serious shortcomings and in some cases do not adequately reflect the process conditions For example
coal composition measurements cannot be used to explain the problems of dusting flowability freezing and oxidation that can occur during coal handling mill capacities for lower rank coals or coal blends are difficult to evaluate using existing grindability correlations combustion characteristics including flame shape stability and char burnout cannot be evaluated accurately based on standard coal composition tests the correlations that have been developed for slagging and fouling are inadequate there is considerable disagreement as to the best method of measuring fly ash resistivity there is no correlation between coal composition and fly ash fineness there is no adequate means to predict NOx emissions
Because the procurement specifications are based on tests which do not relate well to actual practice there is still a need for expensive large scale test burns to confirm suitability
Coal quality affects a wide variety of plant components and ultimately the overall station performance that is total system capacity availability maintenance costs substitute fuel costs plant replacement costs and the final cost of electricity There is a growing awareness that coal suppliers should take more responsibility with respect to determining the quality of coal made available on the market Suppliers that best understand the consumers fuel quality concerns prove to be the most successful in securing contracts and maintaining market share
Plant operators and other organisations are working to
101
Conclusions
Table 48 Summarymiddot of the impacts of coal quality on power station performance
Coal specification Power station component performance Overall power station performance
Environmental control
l u l
tl a
B
amp ~ o(l co S c r
~
~
E l
aI
0
~ C
co
~ B en
c= E co c E c ~
c= E 5 0 co c ~
U - 0 U
c au
~ u
lt5i if
c= ~ ~ amp 0 j c a u
6 en
c= sect l 0 0 1sect a u gtlt
0 Z
1(j at
4-lt a
E c
l 0
tl sect 0 ~ l
QI
0 ~
U
B ~ lta r
c= E S 0
U
sect c B c
ca ~
~ ~ ca gtlt
Ash content increase decrease
Heating value increase decrease
Sulphur content increase decrease
Moisture increase decrease
Hardgrove grindability index increase decrease
Volatile matter increase decrease
Ash fusion temperature increase decrease
Ash resistivity increase decrease
Sodium content increase decrease
Chlorine content increase decrease
Fuel ratio increase decrease
Free swelling index increase decrease
Size consist increase decrease
compiled from observations from literature and the lEA Coal Research survey worsened (or decreased for components marked ) improved (or increased for components marked )
102
improve their understanding of how their equipment or systems respond to particular coals and coal blends but the lack of data for appropriate direct correlations of plant performance and coal behaviour has hindered the development of true prediction capability Until these relationships have been developed and proven respecting differences in boiler design coal buyers will continue to operate at a disadvantage when selecting new sources of coal
With the advances that have been made in computer technology there has been some success in the development of computer models that demonstrate the feasibility of developing various quantitative relationships for optimum planning and operation of generating units Many utilities use least cost models for purchasing coals that have no performance prediction capability Many use component models that supply fundamental data of plant component performance There is a growing number of utilities that are adopting expert unit or integrated models that are being developed Others have shown scepticism over the capability of devising a truly representative model of a coal combustion plant for reasons that include the following
a belief that coal blending solutions based on pragmatism and simple empirical methods are more appropriate providing a here-and-now solution a belief that many of the coal quality impacts cannot be accurately modelled as the basic mechanisms are still not fully understood new advanced boiler configurations such as low NOx
combustion regimes increase the complexity of boiler models many of the models have not been applied to a wide range of international coals and therefore have not received adequate validation the present methods that describe coal properties require substantial refinement as used in the models as they have been found to be inadequate in many cases for predictingaccounting for unit performance
Many of the shortcomings in the traditional coal characterisation tests that form the basis for specifications for
Conclusions
combustion have been exposed by the efforts to develop computer models and their improved data processing Prior to their application manual comparisons provided only limited indications of coal behaviour and in many cases precluded the ability to attach a price to a change in performance as a result of a change in coal quality Development of the models has also initiated extensive validation exercises to acquire the necessary performance data In addition coal characterisation tests are being reassessed It is recognised that an overly conservative approach to the development and adoption of new techniques as characterisation tests which may more realistically reflect the conditions extant to coal combustion has also hindered progress into acquiring true predictive capability
Specific needs that have been identified during the course of this review include
the need to develop an internationally acceptable method(s) of defining coal characteristics so plant performance can be predicted more effectively specific relationships between boiler performance in particular for advanced boiler configurations such as low NOx combustion regimes and coal quality need to be developed For example the specific impact of sulphur chlorine sodium overall ash content and coal rank (or reactivity) on carbon burnout slagging fouling corrosion and abrasion all need to be established economic parameters to measure the impact of plant performance on the cost of electricity need to be established and agreed upon in the electric utility industry The accounting systems of many utilities are not designed to easily identify the costs associated with coal quality impacts These organisations need to review their methods particularly if they intend to take advantage of new developing tools that are available such as expert computer models
Successful resolution of these issues is fundamental to achieving optimum use of coal as pulverised fuel in utility power stations
103
9 References
Abbott M F Bilonick R A (1992) Applied heat flux and soot blower effectiveness measurements in the CONSOL pilot and research combustors In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast R USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 471-497 (1992) Afonso R F Molino N M (1991) Compliance coal and low volatile bituminous coal testing at New England power In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 421-436 (JulI991) Ainsworth C C Rai D (1987) Chemical characterization of fossil fuel combustion wastes EPRI-EA-5321 Palo Alto CA USA EPRI Technical Information Services 136 pp (Sep 1987) Akers D J Norton G A Buttermore W H Markuszewski R (1989) Trace elements in coal In Trace elements in coal and coal wastes EPRI-GS-6575 Palo Alto CA USA EPRI Technical Information Services pp 21-28 (Dec 1989) Alder G Klein K Rettberg L (1992) Optimization of automated sootblowing through on-line boiler heat balance modeling In Power-Gen 91 Tampa R USA 4-6 Dec 1991 Houston TX USA PennWell Conferences and Exhibitions pp 1863-1881 (1992) Allman W P (1987) Steam coal blending planning and economic analysis facilitated by computer-generated tables Journal of Coal Quality 6 (1) 19-22 (Jan 1987) Allman W P (1991) A cost-minimization planning model for the coal sourcingtransport network problem emphasizing environmental emission restrictions Energy Systems and Policy 15 (1) 65-73 (Jan-Mar 1991) Anson D (1988) Interpretation and use of empirical slagging criteria In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 181-1101 (1988) Arnold B J (1988) Workshop on defining coal handleability
its cost impact and control Palo Alto CA USA EPRI Technical Information Services 128 pp (Nov 1988) Arnold B J (1991) Effect of chemical and physical coal properties on handling behaviour Mining Engineering 43 (2) 228-231 (Feb 1991) Arnold B J OConnor D C (1992) The effect of coal quality on coal handling Paper presented at Impact of coal quality on power plant peljormance La Jolla CA USA 25-27 Aug 1992 Arnold P C (1990) Storage systems for coal the requirement for implementation of modern design techniques In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 40-46 (Jun 1990) Arora B R Racine J P Sirois R H Finn G A Hanna R S Kern E E Buffinton A L (1989) Coal quality advisor for coal buyer Paper presented at Expert systems applications for the electric power industry Orlando R USA 5-8 Jun 1989 Babcock amp Wilcox (1978) Steam its generation and use (39th edition) New York NY USA Babcock amp Wilcox Company vp (1978) Bailey J G Tate A Diessel C F K Wall T F (1990) A char morphology system with applications to coal combustion Fuel 69 (2) 225-239 (Feb 1990) Baker J W Bennett P Conroy A Naylor P Smith G B (1987) Utilization characteristics of Australian steaming coals in overseas power stations In Coal Power 87 The AUSIMM annual conference in association with the Mining and Metallurgical Institute ofJapan (MMlJ) Newcastle NSW Australia May 1987 Parkville Vic Australia The Australasian Institute of Mining and Metallurgy pp 303-311 (May 1987) Baker J W Holcombe D (1988a) Use of the drift velocity apparatus to determine electrostatic precipitation performance In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp N13-NI6 (1988)
104
References
Baker J W Holcombe D (1988b) Electrostatic precipitations and fabric collection In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp L121-L1239 (1988) Balling L Hein D (1989) DeNOx catalytic converters for various types of furnaces and fuels - development testing operation In 1989 Symposium on stationary combustion nitrogen oxide control San Francisco CA USA 6-9 Mar 1989 EPRI-GS-6423-vol 2 Palo Alto CA USA EPRI Technical Infonnation Services vol 2 pp 7A27-7A40 (JuI1989) Barrett R E (1990) Designing boilers to avoid slagging fouling Power 134 (2) 41-45 (Feb 1990) Barrett R E Holt E C Jr Mack G A Frank R L (1983) Power plant perfonnance Assessing the impact of coal quality In SME-AIME annual meeting Atlanta GA USA 6-10 Mar 1983 Littleton CO USA Society of Mining Engineers of AIME pp 1-12 (Mar 1983) Barrett R E Mack G A Holt E C Jr (1982) Examining relationships between coal characteristics and the perfonnance of IVA power plants TVA10PIEDT-8312 Columbus OH USA Batelle-Columbus 254 pp (Sep 1982) Barrett R E Tuckfield R C (1988) Correlation of slaggingfouling from utility operating data In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 163-180 (1988) Bauver W P Bianca J D Fishburn J D (1984) Characterization of erosion of heat transfer tubes in coal fired power plants ASME Paper 84-JPGC-F4-3 New York NY USA American Society of Mechanical Engineers vp (1984) Baxter L L (1992) Combustion model predicts properties of coal ash deposits Sandia Science News 27 (6) 4 (Jun 1992) Beer J M SarorllD A F Barta L E (1992) From properties of coal mineral matter to deposition tendencies of fly ash - a modelling route Journal of the Institute of Energy 65 (462) 55-62 (Mar 1992) Behnam-Guilani K Hickey G L Hipple M J (1991) Statistical models for predicting coal-fired generating unit costs and performance Proceedings of the American Power Conference 53 888-892 (1991) Bend S L (1989) Coal characterisation and combustion PhD Thesis Newcastle upon Tyne UK University of Newcastle upon Tyne 189 pp (Nov 1989) Bennett R Fogel W Aloia P (1988) Wet fuel handling A program to minimize plugging In Defining coal handleability Its cost impact and control Lexington KY USA 30 Apr-l May 1987 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Information Services pp 41-410 (Nov 1988) Benson S A Steadman E N Kalmanovitch D P (1988) Studies of the fonnation of alkali and alkaline earth aluminosilicates during coal combustion using a laboratory scale furnace In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 31-312 (1988) Berkowitz N (1985) The methods of coal chemistry In The chemistry of coal Amsterdam the Netherlands Elsevier Science Publishers pp 33-102 (1985)
Berkowitz N (1989) Atmospheric oxidation of coal In Sample selection aging and reactivity of coal New York NY USA John Wiley and Sons pp 217-253 (1989) Blake M W (1988) Estimating benefits from cleaning coals In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 667-676 (1988) Blake M W Robin T T (1982) Coal quality influence on operating plant cost Paper presented at Ninth annual engineering conference on reliability for the electric power industry Hershey PA USA 16-19 Jun 1982 Blondin J Girardeau M Nomine M (1988) Two simple tests for the assessment of wet fine coal handleability In Industrial practice offine coal processing KIimpel R R Luckie P T (eds) Littleton CO USA SME-AIME pp 253-255 (1988) Blough J L Kihara S Wolowodiuk W (1988) Effects of coal properties on superheater corrosion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 235-253 (1988) Boley D G (1984) Calcium chloride A new solution for frozen coal Power 128 (1) 67-69 (Jan 1984) Borio R W Levasseur A A (1986) Coal ash deposition in boilers ACS Symposium Series 103 288-302 (1986) Borio R W Levasseur A A Chow 0 K Miemiec L S (1992) Ash deposition a boiler manufacturers perspective In Engineering Foundation conference on inorganic transfonnations and ash deposition during combustion Palm Coast FL USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 95-120 (1992) Borio R W Plumley A L Sylvester W R (1978) Improved thennal efficiency by controlling of factors affecting metal wastage in pulverized coal-fired steam generators In Ash deposits and corrosion due to impurities in combustion gases Bryers R W (ed) Washington DC USA Hemisphere Publishing pp 163-183 (1978) Boushka M (1988) Application of EPRIs coal quality impact model In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Infonnation Services pp AI-A20 (May 1988) Boyd R K Kent J H (1986) Three-dimensional furnace computer modelling In Twentyjirst symposium (international) on combustion Munich Federal Republic of Gennany 3 Aug 1986 Pittsburgh PA USA The Combustion Institute pp 265-274 (1986) Boyd R K Lowe A (1988) Three-dimensional modeling of a pulverised-coal fired utility furnace In Coal combustion science and technology of industrial and utility application Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 165-172 (1988) Boyd R K Lowe A (1992) Sydney NSW Australia Pacific Power Services Personal communication (Sep 1992) Bretz E A (1991a) Specifying powerplant fuels and combustion systems Electrical World 205 (2) 40-45 (Feb 1991) Bretz E A (1991b) Innovation key to finding unusual ash-disposal options Electrical World 205 (7) 56-57 (Jul 1991) Brooks K Glasser D (1986) A simplified model of
105
References
spontaneous combustion in coal stockpiles Fuel 65 (8) 1035-1041 (Jug 1986) Brooks S Meadowcroft DB Morris C W Flatley T A (1983) J laboratory evaluation of alloys potentially resistant to furnace wall corrosion In Corrosion resistant materials in coal conversion systems Meadowcroft D B Manning M S (eds) London UK Jpplied Science Publishers pp 121-135 (1983) Brown K (1985) Sampling testing and analysis of coals In An intensive course on the characterisation of steaming coals Newcastle NSW Justralia 20-22 May 1985 Newcastle NSW Justralia University of Newcastle Institute of Coal Research pp 21-239 (May 1985) Bryers R W (1992) Fireside behaviour of mineral impurities in fuels from Marchwood 1963 to the Sheraton Palm Coast 1992 In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USJ 10-15 Mar 1991 New York NY USJ Jmerican Society of Mechanical Engineers pp 3-70 (1992) Bull D L (1992) Jsh deposition a utility perspective In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USJ 10-15 Mar 1991 New York NY USJ Jmerican Society of Mechanical Engineers pp 121-132 (1992) Burchill P (1987) Some observations on the variation of nitrogen content and functionality with coal rank In 1987 International conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Jmsterdam the Netherlands Elsevier Science Publishing Company pp 5-8 (1987) Byrne G J Juniper L A (1987) Utilization characteristics of Justralian steaming coals in overseas power stations In Coal Power 87 The AUSIMM annual conference in association with the Mining and Metallurgical Institute of Japan (MMIJ) Newcastle NSW Justralia May 1987 Parkville Vic Justralia The Justralasian Institute of Mining and Metallurgy pp 293-301 (May 1987) Cacka H Lang I Fabianova D (1989) Vliv prvkoveho slozeni uhli HDBS a jejich THF extraktu na nizkoteplotni oxidaci uhli (Effects of elementary composition of coal from the Sokolov brown coal basin and its tetrahydrofuran extracts on low-temperature oxidation) In 2 celostatni konference Samovolne vmecovani uhli v teoril a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSJV pp 1-14 (1989) Cagnetta A C Zelensky G (1983) Coal qualitydesigning a power plant for a wide range or dedicated coal supply In Fifth international coal utilization exhibition and conference Houston TX USJ 7-9 Dec 1982 Houston TX US1 EBJSCO Services Inc pp 3-14 (Dec 1983) Calarco V Bennett D (1989) United States acid rain legislation implications for the international coal markets In CoalTrans 89 sixth international coal trade and transportation conference London UK 16-18 Oct 1989 Worcester Park UK CoalTrans Conferences Ltd vp (1989) Carmichael R L (1987) Factors influencing selection of coals for existing power plants In International symposium on mining technology and science Xuzhou China 18 Sep 1985 Beijing China China Coal Industry Publishing House pp 1365-1371 (1987)
Carpenter A (1988) Coal classification IEJCR12 London UK IEJ Coal Research 104 pp (Oct 1988) Cerkanowicz A E Liskowitz J W Wecharatana M (1991) Potential model of the energy manufacturing process to predict properties of fly-ash as it relates to utilization In Eighth annual international Pittsburgh coal conference Coal - energy and the environment Pittsburgh PJ USJ 14-18 Oct 1991 Greenburg PA USJ Pittsburgh Coal Conference pp 839-842 (1991) Chamberlain R A C Hall D A (1973) The liability of coals to spontaneous combustion Colliery Guardian 221 (2) 65 (Feb 1973) Chen J Y Harris D J Smith I W Zhang D K Wall T F Stanmore B R (1991) Combustion reactivity of coals shyevaluation of laboratory techniques In 1991 international conference on coal science - proceedings Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 303-306 (Sep 1991) Chen X D (1991) The effect of moisture content on the spontaneous ignition process - a review In Proceedings of the fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Jssociation of New Zealand vol 2 pp 327-337 (1991) Chou SF Daniels P L Rodgers L W Theus G J Eskinazi D (1986) Fire-side corrosion in 10w-NOx
combustion systems In Proceedings Symposium on stationary combustion NOx control Boston MJ US1 6-9 May 1985 EPRI-CS-4360 Palo Jlto C1 US1 EPRI Technicallnfonnation Services pp 191-1922 (Jan 1986) Cichanowicz J E Harrison C D (1989) The role of coal cleaning in integrated environmental control In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Jlto C1 USA EPRI Technical Information Services pp 711-724 (Oct 1989) Clarke F Morris C W (1983) Combustion aspects of furnace wall corrosion In Corrosion resistant materials in coal conversion systems Meadowcroft D B Manning M I (eds) London UK Jpplied Science Publishers pp 47-61 (1983) Clarke L Sloss L (1992) Trace elements emissions from coal combustion and gasification IEJCR49 London UK IEJ Coal Research 111 pp (1992) Clemens A H Matheson T W Rogers D E (1990) DTJ studies of the low temperature oxidation of low rank coals Fuel 69 (2) 255-256 (Feb 1990) Coal Research Establishment British Coal Corporation (1991) Studies of the production ofnitrogen oxides and ash deposition from pulverised coal in relation to utilisation in low NOx burners EUR 13443 EN Luxembourg Commission of the European Communities 46 pp (1991) CoaiTrans International (1991) Coal in the environmentshysupplement CoalTrans International 6 (2) VI-XIII (MarlJpr 1991) Colijn H (1988a) Coal properties handleability and bin design In Defining coal handleability Its cost impact and control Lexington KY USJ 30 Jpr-1 May 1987 EPRI-CS-6015 Palo Jlto CJ USA EPRI Research Reports Center pp 21-219 (Nov 1988) Colijn H (1988b) Coal handleability as part of coal quality control In 1988 joint power generation conference
106
References
Philadelphia PA USA 25-29 Sep 1988 New York NY USA The American Society of Mechanical Engineers pp 25-41 (Sep 1988) Collins S (1990) Can problems arising from chlorine in coal be solved generically Power 134 (12) 59-60 (Dec 1990) Connelly L J (1988) Freeze condition agents and their use in the coal industry In Defining coal handleability Its cost impact and control Lexington KY USA 30 Apr-l May 1987 EPRI-CS-6015 Palo Alto CA USA EPRI Research Reports Center pp 31-327 (Nov 1988) Conroy A (1991) Grinding behaviour of hard coals Combustion News 1-4 (Nov 1991) Corder W C (1983) For lower power costs use high quality coal In Third European coal utilisation conference Amsterdam The Netherlands 11-13 Oct 1983 Rotterdam The Netherlands Industrial Presentations pp 221-240 (1983) Corio M R (1982) Heat rates and availability the use of econometric analysis in comparing electric generating unit performance New York NY USA National Economic Research Associates vp (1982) Corson P B (1988) Carolina Power and Light purchasing model (COALBUY) In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 41-410 (May 1988) Cortsen C E (1983) An evaluation of coal properties and their influence on the utilisation in power stations Report No2 2nd ed Fredericia Denmark ELSAM Coal Quality Committee 161 pp (Nov 1983) Couch G R (1988) Lignite resources and characteristics IEACR13 London UK IEA Coal Research 102 pp (Dec 1988) Couch G R (1989) Power generationfrom lignite IEACR19 London UK IEA Coal Research 67 pp (Dec 1989) Couch G R (1991) Advanced coal cleaning technology IEACR44 London UK IEA Coal Research 95 pp (1991) Cox J N Smith S R Metha A (1990) Field evaluation of EPRI coal quality impact model In Proceedings 1989 EPRl heat-rate improvement conference Knoxville TN USA 26-28 Sep 1989 EPRI-GS-6985 Palo Alto CA USA EPRI Research Reports Center pp 4B61-4B68 (Sep 1990) CQ Inc (1992) The Acid Rain Advisor Homer City PA USA CQ Inc 2 pp (1992) Crelling J C Skorupska N M Marsh H (1988) Reactivity of coal macerals and lithotypes Fuel 67 (6) 781-785 (lun 1988) Cumming J W (1980) The electrical resistance of coal ash at elevated temperatures Journal of the Institute of Energy 53 (416) 153-154 (Sep 1980) Cumming J W Livingston W R Hesselmann G J (1987) Coal reactivity assessment for boiler design In Coaltech 87 - Coaltrade 87 - conference papers London UK 9-11 Jun 1987 Schiedam the Netherlands Industrial Presentations pp 11-30 (1987) Cunliffe F (1990) Thornton UK Shell Research Limited Personal communication (1990) Dacey P W Cope D R (1986) Process development In Flue gas desulphurisation - system performance ICEASIB4 London UK IEA Coal Research pp 44-48 (Dec 1986) Daniel M (1991a) Power station coal use prospects to 2000 IEACR4l London UK IEA Coal Research 61 pp (Oct 1991)
Daniel P L (1991b) The effect of coal chlorides on furnace wall corrosion In First international conference on chlorine in coal Chicago IL USA 9-11 Oct 1989 Amsterdam the Netherlands Elsevier Science Publishers pp 207-224 (1991) Darby K (1983) Commercial precipitator design In Second CSIRO conference on electrostatic precipitation Bowral NSW Australia 17-19 Aug 1983 North Ryde NSW Australia Commonwealth Scientific Industrial Research Organisation pp L41-L431 (1983) Davidson R (1990) Effects on coal behaviour In Natural oxidation of coal IEACR29 London UK IEA Coal Research pp 55-65 (Sep 1990) Davis A (1984) Coal petrography and petrographic analysis In Coal geology and coal technology Ward C R (ed) Melbourne Vic Australia Blackwell Scientific Publications pp 74-112 (1984) Deiuliis N J Fink C E Abbott M F (1991) The impact of ash quantity and quality on boiler performance and power cost In Eighth annual international Pittsburgh coal conference Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greenburg PA USA Pittsburgh Coal Conference pp 975-980 (1991) Deutsch W (1922) Bewegung und Ladung der Elektrizitatstrager im Zylinderkondensator (Velocity and loading of charged particles in cyclinder capacitors) Annales der Physik 68 335-344 (1922) Diessel C F K Bailey J G (1989) The application of petrographic techniques to carbonisation and combustion research at the University of Newcastle In MINPET 89shyMineralogy-petrology symposium Sydney NSW Australia 6-8 Feb 1989 Sydney NSW Australia The Australasian Institute of Mining and Metallurgy pp 117-121 (Feb 1989) Donais R T Tyler A L Bakker W T (1988) Effects of coal properties on pulverizer abrasion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 21-217 (1988) Dooley B (1992) Boiler tube failures - a perspective and a vision In International conference on boiler tube failures in fossil plants San Diego CA USA 5-7 Nov 1991 EPRI-TR-100493 Palo Alto CA USA EPRI Distribution Centre pp 11-129 (Apr 1992) Doyle G (1989) Price premiums and inter-coal competition In CoalTrans 89 sixth international coal trade and transportation conference London UK 16-18 Oct 1989 Worcester Park UK CoalTrans Conferences Ltd pp 177-180 (1989) Dusak V (1986) Brown coal and its safe storage Energetika 36 (1011) 471-474 (Oct 1986) Eck G A (1987) Perfectblend coal blending computer program Journal of Coal Quality 6 (3) 100-101 (lui 1987) Electrical World (1987) Utilities report boiler failure chief culprit in forced outages Electrical World 201 (8) 50-52 (Aug 1987) Elliott M A (ed) (1981) Chemistry of coal utilizationshysecond supplementary volume New York NY USA John Wiley and Sons 2274 pp (1981) Elliott T C (1991) Monitoring powerplant performance Power 135 (9) 11-26 (Sep 1991) Elliott T C (1992) Coal handling and preparation Power 136 (1) 17-33 (Jan 1992) ERM Consultants Pty Ltd (1983) Australian case studies
107
References
which relate to coal quality andor consistency to efficiency and economy ofpower production Brisbane Qld Australia ERM Consultants Pty Ltd vp (Mar 1983) Essenhigh R H (1981) Fundamentals of coal combustion In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley and Sons pp 1153-1312 (1981) Evans R J (1991) A computer expert system to reduce power plant emissions PErC Review (4) 24-28 (1991) Falcon L M Falcon R M S (1987) The petrographic composition of Southern African coals in relation to friability hardness and abrasive indices Journal of South African Institute ofMining and Metallurgy 87 (10) 323-336 (Oct 1987) Falcon R M S Snyman C P (1986) An introduction to coal petrography atlas ofpetrographic constituents in the bituminous coals of South Africa Johannesburg South Africa Geological Society of South Africa 27 pp (1986) Falcon R Ham A J (1988) The characteristics of Southern African coals Journal of South African Institute ofMining and Metallurgy 88 (5) 145-161 (May 1988) Fiveland W A Wessel R A (1988) Numerical model for predicting perfonnance of three-dimensional pulverized-fuel fired furnaces Journal ofEngineering for Gas Turbines and Power 110 117-129 (1988) Flatley T Latham E P Morris C W (1981) Co-extruded tubes improve resistance to fuel ash corrosion in UK boilers Material Performance 20 (5) 12-17 (May 1981) Folsom B A Heap M P PoW J H (1986a) Effect of coal quality on power plant performance and costs - Volume 1 State-of-the-art review summary and program plan EPRl-CS-4283-Vol1 Palo Alto CA USA EPRl Technical Infonnation Services 262 pp (Feb 1986) Folsom B A Heap M P PoW J H Smith J L Corio M R (1986b) Effect of coal quality on power plant performance and costs - Volume 2 Review of coal quality impact evaluation procedures EPRl-CS-4283-Vo12 Palo Alto CA USA EPRl Technical Infonnation Services 387 pp (Feb 1986) Folsom B A Heap M P PoW J H Smith J L (1986c) Effect of coal quality on power plant performance and costs - Volume 3 Review of coal quality and power plant performance diagnostics EPRl-CS-4283-Vo13 Palo Alto CA USA EPRI Technical Infonnation Services 176 pp (Feb 1986) Fortune D B (1990) London UK Shell Coal International Ltd Personal communication (1990) Galluzzo N G Stallard G S Boushka M E Mehta A K (1987) Model predicts as-fired costs of changing coal sources Power 131 (6) 53-56 (Jun 1987) Gebel K Madlsperger G Hein K Bokenbrink D (1989) Entwicklung eines Kombinations DeNOx-Verfahrens unter Verwendung von feuerungstechnischen Minderungsrnassnahmen und Hamstoff-SNCR-Technik (Development of a combined DeNOx process using staged combustion and urea-SNCR technology) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Gennany 26-27 Apr 1989 Essen Federal Republic of Gennany VGB Kraftswerkstechnik GmbH pp 173-180 (Apr 1989) Gibb W H (1983) The nature of chlorine in coal and its
behaviour during combustion In Corrosion resistant materials for coal conversion systems Meadowcroft D B Manning M S (eds) London UK Applied Science Publishers pp 25-45 (1983) Gibb W H (1992) Nottingham UK PowerGen Ratcliffe Technology Centre Personal communication (Sep 1992) Gibbs L A Hallett W L H Hughes P M (1989) Coal devolatilization in an entrained flow reactor In The Combustion 1nstitute Canadian Section 1989 spring technical meeting Toronto Ontario Canada 31 May-2 Jun 1989 Ontario Canada The Combustion Institute pp 91-93 (1989) Giovanni D V Afonso R F Dyas B E Mehta A K (1991) Coal quality field test at New England power companys Salem Harbour Unit Three In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRl-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 379-398 (Jul 1991) Given P H (1984) An essay on the organic geochemistry of coal In Coal science volume 3 Gorbaty M L Larsen J Wender I (eds) Orlando FL USA Academic Press pp 63-252 (1984) Given P H Yarzab R F (1978) Coal analysis and mineral matter In Analytical methods for coal and coal products shyVolume II Karr C Jr (ed) New York NY USA Academic Press pp 3-42 (1978) Gluskoter H J Shimp N F Ruch R R (1981) Coal analyses trace elements and mineral matter In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley amp Sons pp 369-424 (1981) Goddard C W Duzy A F (1967) Measuring abrasiveness of solid fuels and other materials by a radiochemical method ASME paper no 67-WAIFU-l New York NY USA American Society of Mechanical Engineers vp (1967) Goetz G J Nsakala N Y Borio R W (1978) Development of methods for determining emissintives and adsorptivities of coal ash deposits In 1987 winter annual ASME meeting Boston MA USA 13 Dec 1978 New York NY USA American Society of Mechanical Engineers vp (1978) Gomer K (1988) Prediction of the turbulent flow heat release and heat transfer in utility boiler furnaces In Coal combustion Science and technology of industrial and utility applications Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 273-282 (1988) Gutberlet H (1988) Einfluss der Feuerungsart auf die Vergiftung von DeNOx-Katalysatoren durch Arsen (The effect of furnace type on the poisoning of DeNOx catalysts by arsenic) VGB Kraftwerkstechnik 68 (3) 287-293 (Mar 1988) Hainley D C Yavuzkurt S Scaroni A W (1986) Effect of coal properties on fluidized bed combustor perfonnance In Energy-sources technology conference and exhibition New Orleans LA USA 23 Feb 1986 New York NY USA American Society of Mechanical Engineers pp 43-54 (1986) Hampartsoumian E Murdoch M Pourkashanian M Williams A (1991) The reactivity of coal chars produced under various pyrolysing conditions In 1991 international conference on coal science - proceedings Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 271-274 (Sep 1991) Harb J N Smith E E (1990) Fireside corrosion in PC-fired
108
References
boilers Progress in Energy and Combustion Science 16 (3) 169-190 (1990) Hardgrove R M (1938) ASME technical paper Paper presented at ASME spring meeting Chicago IL USA 27 Jun 1938 Harrington R C Kaltenback R P Stratton H L (1988) Burner improvement program on a 650 MW supercritical steam generator - a case study In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 541-549 (Sep 1988) Harrison C Zera C (1990) A new way of doing business in coal-fired power generation Power Engineering 94 (4) 33-36 (Apr 1990) Hatt R M (1990) Fireside deposits in coal-fired utility boilers Progress in Energy and Combustion Science 16 (4) 235-241 (1990) Hatt R M (1991) Coal mining and preparation practices shyimpacts on power plant perfonnance In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 365-377 (Jul 1991) Heap M P Kramlich J C Pershing D W Pohl J H Richter W F Seeker W R (1986) Effect of coal quality on power plant performance and costs - Volume 4 Review of coal science fundamentals EPRI-CS-4283-Vo14 Palo Alto CA USA EPRI Technical Infonnation Services 574 pp (Feb 1986) Heap M P Pohl A S Folsom A S Mehta A K (1984) The effects of coal quality and the resulting ash deposition on the costs of power station operation (Die Bedeutung der Kohlqualitiit und der daraus resultierenden Aschelagerungen fur die Kostan des Kraftwerksbetriebes) In Internationale VGB-Konferenz Verschlackungen Verschmutzungen und Korrosionen in Wriimekraftwerken - Vortriige Essen Federal Republic of Gennany 29 Feb-2 Mar 1984 Essen Federal Republic of Gennany VGB Technische Vereinigung der Grosskraftwerksbetreiber eV pp 493-507 (1984) Heble J J Srinivaschar S Boni A A (1991) The behaviour of clay minerals under combustion conditions American Chemical Society Division of Fuel Chemistry Preprints 36 (1) 173-180 (Apr 1991) Heitmiiller W Schuster H (1991) Low-NOx pulverized coal firing systems and their components Infonnation No 189 Hausdruckerei Gennany Deutsche Babcock Energie- und Umwelttechnik AG 17 pp (Mar 1991) Hervol J D Mehta A K Levasseur A A Miemiec L S Lexa G F (1988) Benefits of coal cleaning on the capital and operating costs of a 550 MW boiler In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 81-824 (May 1988) Hewing A N Harvey M R (1981) Evaluating freeze conditioning agents for coal Power Engineering 85 (7) 74-75 (JuI1981) Hjalmarsson A-K (1990) NOx control technologies for coal combustion IEACRl24 London UK lEA Coal Research 102 pp (Jun 1990) Hjalmarsson A-K (1992) Interactions in emissions control for coal-fired plant IEACRl47 London UK lEA Coal Research 81 pp (Mar 1992) Hjalmarsson A-K Soud H N (1990) Systems for controlling
NOxfrom coal combustion IEACRl30 London UK lEA Coal Research 240 pp (Dec 1990) Hobbs M L Smith P J (1990) Algebraic multi-zoned radiation model for a two-zoned zero-dimensional cylindrical furnace Fuel 69 (11) 1420-1427 (Nov 1990) Hodde J A (1988) Least cost fuel system used to plan fuel purchases In 1988 joint power generation conference Philadelphia PA USA 25-29 Sep 1988 New York NY USA American Society of Mechanical Engineers pp 43-51 (Sep 1988) Holstein R A (1981) Coal fired power plant capital cost estimates EPRI-PE-1865 Palo Alto CA USA EPRI Technical Infonnation Services vp (1981) Horsfall D W Zitron Z (1982) High density beneficiation of coal In Proceedings sixth international conference on coal research London UK 4-8 Oct 1982 London UK National Coal Board pp 319-337 (1982) lEA Coal Industry Advisory Board (1985) Coal quality and ash characteristics Paris France OECDIIEA 63 pp (Jan 1985) IEEE (1984) IEEE standard criteria and guidelines for the laboratory measurement and reporting offly ash resistivity IEEE Standard 548-1984 New York NY USA Institute of Electrical and Electronics Engineers 30 pp (21 Dec 1984) ICCP International Committee for Coal Petrology (1963) International handbook of coal petrology - second edition Paris France Centre National de la Recherche Scientifique vp (1963) ICCP International Committee for Coal Petrology (1975) International handbook of coal petrology - supplement to the second edition Paris France Centre National de la Recherche Scientifique vp (1975) ICCP International Committee for Coal Petrology (1985) International handbook of coal petrology - edited reprint of 1975 supplement to the second edition Murchison D G Smith A H V (eds) Newcastle upon Tyne UK University of Newcastle upon Tyne vp (1985) International Energy Agency (1992) Coal information 1992 Paris France OECDIIEA 541 pp (1992) Iskhakov Kh A (1990) The role of sorbed moisture in coal oxidation Solid Fuel Chemistry (English translation) 24 (2) 17-21 (1990) Jacobs J P (1992) Essen Gennany VGB Technical Association of Large Power Plant Operators Personal communication (Sep 1992) Jamaluddin A S Fiveland W A (1990) Practical model for predicting unburned carbon and temperatures in large-scale boilers Paper presented at 1990 spring meeting combustion fundamentals and applications Cincinnati OH USA 20-22 May 1990 Jenson P T (1992) Fredericia Denmark ELSAM Personal communication (Sep 1992) Johanson J R (1989) Evaluating coal handling characteristics In 1989 joint power generation conference Dallas TX USA 22-26 Oct 1989 New York NY USA American Society of Mechanical Engineers pp 1-5 (Oct 1989) Johanson J R (1991) Identify hard-to-handle coal early Power Engineering 95 (11) 35-38 (Nov 1991) Johnson R P Plangemann R Rehm M (1991) Coal quality effects on boiler perfonnance an Eastern utility perspective In Effects of coal quality on power plants St Louis MI
109
References
USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 11-113 (Jul 1991) Jones A R Gibb W Johnston J (1992) Nottingham UK PowerGen Ratcliffe Technology Centre Personal communication (Mar 1992) Jones M L Benson S A (1988) An overview of slagginglfouling with Western coals In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 125-147 (1988) Jones R B McCourt C B Morley C King K (1985) Maceral and rank influences on the morphology of coal char Fuel 64 (10) 1460-1467 (Oct 1985) Juniper L Pohl J (1991) Techniques to control NOx
emissions from coal-fIred boilers Australian Combustion Technology Centre Combustion News 1-4 (May 1991) Jiintgen H (1987a) Coal characterization in relation to coal combustion Part I structural aspects and combustion Erdol Kohle Erdgas Petrochemie vereinigt mit Brennstoff-Chemie 40 (4) 153-165 (Apr 1987) Jiintgen H (1987b) Coal characterization in relation to coal combustion Part II environmental problems of combustion ErdOl Kohle Erdgas Petrochemie vereinigt mit Brennstoff-Chemie 40 (5) 204-208 (May 1987) Kalmanovitch D P (1991) A practical approach to predicting ash deposition In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 591-5102 (Jul 1991) Kapteijn F Bruinsma D Mol J Moolijn J A (1990) The characterisation of fly-chars from combustion the effect of temperature and rank on reactivity texture and composition Fuel Processing Technology 24 (113) 391-398 (1990) Kautz K (1982) Importance of maceral content in regard to the properties of coals of worldwide origin and its effects on combustion chamber design of large dry furnaces VGB Kraftwerkstechnik - English Issue 62 (3) 1-12 (Mar 1982) Kehoe D B Hervol J D Evans R J Levasseur A A (1990) Evaluating the effects of cleaned coals in utility boilers In Eleventh international coal preparation congress Tokyo Japan 22-25 Oct 1990 Tokyo Japan Mining and Materials Processing Institute of Japan pp 247-252 (1990) Kemeny P (1988) Coal quality impact on electric power generation costs case study Fusina unit 3 In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 631-655 (1988) King J G Maries M B Crossley H E (1936) Fonnulae for the calculation of coal analysis to a basis of coal substance free of mineral matter Journal for the Society of Chemistry and Industry 55 277-281 (1936) Kirchner A T (1991) On-line analysis of coal IEACR40 London UK lEA Coal Research 79 pp (Sep 1991) Kiss L T King TN (1979) Reporting of low-rank coal analysis - the distinction between minerals and inorganics Fuel 58 (7) 547-549 (Jul 1979) Klingspor J S Vernon J L (1988) Particulate control for coal combustion IEACR05 London UK lEA Coal Research 70 pp (Feb 1988) Klitgaard J (1988) Utility coal quality work at a cross-road Journal of Coal Quality 7 (2) 36-37 (Jun 1988) Knill K J (1987) A review offuel staging in pulverised coal
combustion systems IFRF-G-13a3 IJmuiden Netherlands International Flame Research Foundation 54 pp (Sep 1987) Kok A (1988) The effect of coal type on carbon burnout and NOx fonnation in pulverized coal combustion In Coaltech 88 - Coaltrade 88 seventh international conference on coal technology and coal trade Amsterdam the Netherlands 21-23 Nov 1988 Amsterdam the Netherlands Industrial Presentations (Europe) BV pp 1-14 B3 (1988) Kosvic T C Breen B P Yingling J C Mazumdar M Carpenter M Stothart B Plangemann R Maurer W (1988) A combined mechanisticstatistical approach to relating coal properties and boiler operating characteristics to the perfonnance of coal fIred boilers In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 71-717 (Sep 1988) Kremer H Grigoleit H Jacobs J (1990) Tendency of power station coals to fonn NOx - Results of VGB Research Project 89 VGB Kraftwerkstechnik - English Issue 70 (7) 478-484 (Jul 1990) Latham C E Fiveland W A La Rue A D (1991a) Numerical models as combustion system design tools In Eighth annual international Pittsburgh coal conference proceedings Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greenburg PA USA Pittsburgh Coal Conference pp 34-39 (1991) Latham E Meadowcroft D B Pinder L (1991b) The effects of coal chlorine on fireside corrosion In First international conference on chlorine in coal Chicago IL USA 9-11 Oct 1989 Amsterdam the Netherlands Elsevier Science Publishers pp 225-250 (1991) Laurendeau N M (1978) Heterogeneous kinetics of coal char gasification and combustion Progress in Energy and Combustion Science 4 (4) 221-270 (1978) Lee G K Thambimuthu K V Hill J M (1991) Assessment of ash sintering potential by conductance and dilatometry In Eight annual international Pittsburgh coal conference proceedings Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greensburg PA USA Pittsburgh Coal Conference pp 6-11 (1991) Llewellyn W (1991) A practical study of coal handleability In Proceedings of the fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Association of New Zealand vol 1 pp 115-126 (1991) Llinares V Caron M B Schmidt E J Szela F J (1982) The C-E availability data program 1982 further developments on MTTR and MTBF analysis Paper presented at Ninth annual engineering conference on reliability for the electric power industry Hershey PA USA 16-19 Jun 1982 Llinares V Lutz A B (1985) Long range forecast and availability improvement program In Proceedings of the 1985 joint ASMEIEEE power generation conference Milwaukee WI USA 20 Oct 1985 New York NY USA American Society of Mechanical Engineers vp (1985) Lockwood F C Mahmud T (1989) The prediction of swirl burner pulverized coal flames In Twenty-second symposium (international) on combustion Seattle WA USA 14-19 Aug 1988 Pittsburgh PA USA The Combustion Institute pp 165-173 (1989) Lowe A (1987) Important coal properties for power
110
References
generation In Geology and coal mining conference Sydney NSW Australia 13-15 Oct 1987 Sydney NSW Australia Geological Society of Australia Coal Geology Group pp 188-196 (Oct 1987) Lowe A (1988a) Effect of ash levels on large pulverised coal fired furnace performance In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 523-540 (Sep 1988) Lowe A (1988b) Effect of ash in coal on power plant availability In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 733-744 (1988) Luckie P T and others (1980) Coal grinding technology A manual for process engineers ERDA FE-2475-25 USA US Government Printing Office No 1980-640-258-2090 vp (1980) Luo X-L Boyd R K Kent J H (1991) Computational investigation of burnout in a furnace firing pulverised coal Journal of the Institute of Energy 64 (461) 230-238 (Dec 1991) Mackowsky M Th (1982) Minerals and trace elements occurring in coal In Stachs textbook of coal petrology Stach E Mackowsky M Th Teichrnller M Taylor G H Chandra D Teichrnller R (eds) Berlin Federal Republic of Germany Gebriider Borntraeger pp 153-171 (1982) Maher T P Smith MY (1990) A user-friendly coal value model for thermal coals In 1990 international coal engineering conference Sydney NSW Australia 19-21 lun 1990 Barton ACT Australia Institution of Engineers pp 259-263 (lun 1990) Mahr D (1988) Blending coal for quality control In 1988 joint power generation conference - coal quality control fundamentals and applications Philadelphia PA USA 25-29 Sep 1988 New York NY USA American Society of Mechanical Engineers pp 1-8 (Sep 1988) Makanski J (1989) Coal analyzers provide critical link for plant control functions Power 133 (2) 23-25 (Feb 1989) Malhotra V M Crelling J C (1987) Spontaneous combustion of coal and maceral enriched fractions under storage pneumatic transport conditions Final report DOEIPC79863-T13 Carbondale IL USA Coal Extraction and Utilization Research Center 97 pp (Mar 1987) Mancini R A Hopkins B W Hodde J A (1987) Coal quality engineering aids purchasing Power Engineering 91 (6) 16-20 (lun 1987) Mancini R A Hopkins B W Hodde J A (1988) Coal quality engineering analysis used to evaluate coal purchases In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 Palo Alto CA USA EPRI Research Reports Center pp 51-515 (May 1988) Mason D M Gandhi K (1980) Formulas for calculating the heating value of coal and char development tests and uses American Chemical Society Division of Fuel Chemistry Preprints 25 (3) 235-245 (1980) Matsuura S Uchida S (1988) Spontaneous combustion susceptibility of coals Saiko to Hoan 34 (10) 2-14 (25 Oct 1988) Matts S A Ohnfeldt P 0 (1973) Efficient gas cleaning with SF electrostatic precipitators Vaxjo Sweden Flakt Industri AB vp (1973)
McCartney R H Whittaker P S Planner J H (1990) A comparison of United States and Australian practices for power station coal handling facilities In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 lun 1990 Sydney NSW Australia Institution of Engineers pp 174-183 (lun 1990) Mehta A (1989) Coal quality impact model EPRl Journal 14 (8) 49-52 (Dec 1989) Mellanby-Lee H (1986) Effects of coal quality on the costs of electricity generation In Physical coal beneficiation and electricity costs ICEASC3 London UK lEA Coal Research pp 18-30 (Feb 1986) Meyers A D Atkinson B W (1991) Using techno-economic computer modelling to assess the utilisation value of New Zealand coal on the world market In Fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Association of New Zealand pp 160-171 (1991) Mikula R J Parsons I S (1991) Coal dustiness characterisation and control Coal Preparation 9 (314) 199-212 (1991) Misra M K Essenhigh R H (1990) Modelling of one-dimensional pulverised coal flames Paper presented at 1990 spring technical meeting combustion fundamentals and applications Cincinnati OH USA 20-22 May 1990 Mitas D Stallard S Anderson-Higgs A OConnor D (1991) Coal quality analysis linked to power plant control Power Engineering 95 (5) 29-32 (May 1991) Mittelbach G (1989) NOx- Minderung an Kohle-und Mtillkesseln mit dem TermoNOx Verfahren Vergleich von Untersuchungsergebnissen (NOx reduction at coal-fired plants and refuse incinerators with the ThermoNOx process a comparison of test results) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Germany 26-27 Apr 1989 Essen Federal Republic of Germany VGB Kraftswerkstechnik GmbH pp 194-200 (Apr 1989) Morgan M E (1987) Characterisation of coals for use in pulverised coal combustion In International conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 823-826 (1987) Morgan ME (1990) Effect of coal quality on the performance of low-NOx burners Journal of the Institute of Energy 66 (454) 3-8 (Mar 1990) Morgan P A Robertson S D Unsworth J F (1987) Combustion studies by thermogravimetric analysis Fuel 66 (2) 210-215 (Feb 1987) Morrison G F (1982) Control of sulphur oxides from coal combustion ICTISITR21 London UK lEA Coal Research 104 pp (Nov 1982) Morrison G F (1986) Understanding pulverised coal combustion ICTISITR34 London UK lEA Coal Research 46 pp (Dec 1986) Murtha M J (1982) Minerals extraction from ash state of the art In Proceedings of resources from coal coal wastes and ash workshop Reston VA USA 9 lun 1982 BNL-51679 DE83017775 Springfield VA USA National Technical Information Service pp 91-103 (1982) Muter R B Lawrence W F (1986) Mineral matter analysis a technique to improve bituminous coal ACS Symposium Series 301 443-448 (1986)
111
References
Myllynen H (1987) Which thermal coal In Coal Power 87 Neuss Dusseldorf Federal Republic of Germany 27-29 Oct 1987 Worcester Park UK CS Publications Ltd pp 37-42 (1987) Nadgauda S S Hathaway A J (1990) Coal utilization cost model for fuel procurement Journal of Coal Quality 9 (1) 17-21 (Mar 1990) Nakabayashi Y (1988) NOx removal from flue gas In The coal in Sweden conference on the role of coal in the Swedish energy system possibilities and limitation SOdertiilje Sweden 26-27 Oct 1988 Sdertlje Sweden Telge Energe AB pp 1-39 (Oct 1988) Nakata T Sato M Makino H (1988) Methods ofpredicting NOx emissions in coal combustion and unburned carbon in fly ash - effects of coal propenies CRIEPI-W-87003 Tokyo Japan Central Research Institute of the Electrical Power Industry 30 pp (Feb 1988) Nandi B N Brown T D Lee G K (1977) Inert coal macerals in combustion Fuel 56 (4) 125-130 (Apr 1977) Nayak R V Bauer F W Tonden T P (1987) Mineral matter in coal - origin identification and boiler erosion Journal of Coal Quality 6 (2) 37-43 (1987) Neavel R C (1981) Origin petrography and classification of coal In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley and Sons pp 91-158 (1981) Neavel R C Smith S E Hippo E J Miller R N (1986) Interrelationships between coal compositional parameters Fuel 65 (3) 312-320 (Mar 1986) Nemec J Dobal V (1988) Contribution to problem of coal spontaneous combustion Acta Montana Zpravy Hornickeho Ustavu CSAV (Ceskoslovenske Akademie Ved) (76) 9-20 (1988) Nicol S K Smitham J B (1990) Coal stockpile dust control In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 Jun 1990 Sydney NSW Australia Institution of Engineers pp 154-158 (Jun 1990) Noskievic P Kolat P Cech B (1987) Operational tests of burners for ignition and stabilization of pulverised coal Energetika 37 (5) 233-236 (May 1987) Nurick W (1988) An engineering approach to prediction of fuel impacts on utility boiler systems In Reducing electricity generation costs by improving coal quality Indiana PA USA 5-6 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 71-760 (May 1988) Oka N Murayama T Masuoka H Yamada S Yamada T Shinozaki S Shibaoka M Thomas C G (1987) The influence of rank and maceral composition on ignition and char burnout of pulverized coal Fuel Processing Technology 15 213-224 (Jan 1987) Osborn G A (1992) Review of sulphur and chlorine retention in coal-fIred boiler deposits Fuel 71 (2) 131-142 (Feb 1992) OKeefe W Hart R M Hopkins B W McIntire D C Harrison C D (1987) Do we need highly detailed coal specs Power 131 (10) 121-123 (Oct 1987) Parish B M (1970) Wear ofpulverisers Research report 363 Cheltenham UK National Coal Board Research Establishment vp (20 Mar 1970) Pasini S Trebbi G (1989) Evolutions of design and operation criteria for ENEL boilers Paper presented at Tenth international conference on power stations Liege Belgium 25-29 Sep 1989
Pavlikova H Machovic V Sebestova E (1989) Study of low-temperature coal oxidation by means of nuclear magnetic resonance spectrometers infrared spectrometers and electron spin resonance In 2 celostatni konference Samovolne vmecovani uhli v teorii a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSAV pp 1-14 (1989) Penninger A (1989) Effect of working parameters on flame stability for coal dust combustion In Tagung iiber Verbrennung und Feuerung14 Deutscher Flammentag (Meeting on combustion and furnaces 14 Gennan flame day) Stuttgart Federal Republic of Germany 5-6 Oct 1989 Dusseldorf Federal Republic of Germany Verein Deutscher Ingenieure (VDI) - Gesellschaft Energietechnik pp 669-679 (1989) Platfoot R (1990) Erosion life of tube banks in coal fired boilers In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 237-241 (Iun 1990) Pohl J S (1990) Procedure for evaluating the performance of low-grade fuels In Low-grade fuels Helsinki Finland 12-16 Jun 1989 Espoo Finland Valtion Teknillinen Tutkimuskeskus vol 1 pp 247-260 (1990) Potter E (1988) Correlations of ash chemistry with pilot-scale electrostatic precipitation experiments In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp N33-N34 (1988) PowerGen (1991) POSTMAN steady state plant modelling system Information sheet no 34 Nottingham UK PowerGen pic Power Technology Centre 2 pp (1991) Pronobis M (1989) Further fmdings concerning the effect of ash deposits upon the exchange of heat in convection boiler surfaces VGB Kraftwerkstechnik - English Issue 69 (11) 931-938 (Nov 1989) Raask E (1985) Mineral impurities in coal combustion shybehaviour problems and remedial measures London UK Hemisphere Publishing 506 pp (1985) Rademacher F J C (1990) Coal handling developments focusing on The Netherlands In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 282-288 (Jun 1990) Rees 0 W (1966) Chemistry uses and limitations of coal analysis Report of Investigations 220 Urbana IL USA lllinois State Geological Survey 50 pp (1966) Reinschmidt K F (1991) Neural networks next step for simulation and control Power Engineering 95 (11) 41-45 (Nov 1991) Repic B Radulovic P Sikmanovic S Grubor B (1988) Boilers start-up with pulverized coal Paper presented at 20 Kraftwerkstechnisches Kolloquium 1988 (20 power plant technical colloquium) Dresden Federal Republic of Germany 11-12 Oct 1988 Richter W Payne R Heap M P (1986) Influence of thermal properties of wall deposits on performance of pulverised fuel fired boiler combustion chambers ACS Symposium Series (301) 375-393 (1986) Richwine R R Quinn A D Mills J B Lowe S D (1989)
112
References
Results of the availability improvement program in the southern electric system Paper presented at Tenth international conference on power stations Liege Belgium 25-29 Sep 1989 Riley J T Gilleland S R Forsythe R F Graham H D Jr Hayes F J (1989) Nonadditive analytical values for coal blends In Proceedings of the seventh international coal testing conference Ashland KY USA 1989 Ashland KY USA Coal Testing Conference pp 32-38 (1989) Rittenhouse R C (1991) Fighting corrosion in air pollution control systems Power Engineering 95 (6) 23-29 (Jun 1991) Rittenhouse R C (1992) New fuel choices change coal handling and storage rules Power Engineering 96 (1) 17-21 (Jan 1992) Robinson G F (1985) A three-dimensional analytical model of a large tangentially fired furnace Journal of the Institute of Energy 116 226-150 (1985) Roy W R Griffin R A Dickerson D R Schuller R M (1984) illinois basin coal fly ashes 1 Chemical characterisation and solubility Environmental Science and Technology 18 (10) 734-739 (1984) Sadowski R S Hunt P J (1978) Consequences of specifying a boiler design fuel before source commitments are firm In Proceedings of the American power conference Vol 40 Chicago IL USA Apr 1978 Chicago IL USA illinois Institute of Technology pp 394-402 (1978) Sanyal A Livingston W R Marsh H Skorupska N M Field D J Edwards 1 AS (1991) Petrography of lignitic and bituminous coals application to assess coal combustibility for power generation In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 51-520 (JuI1991) Saxena S C (1990) Devolatilization and combustion characteristics of coal particles Progress in Energy and Combustion Science 16 (1) 55-94 (1990) Schaeffer J J (1988) Review of coal quality characteristics of potential utility fuel supply sources Journal of Coal Quality 7 (1) 19-22 (Jan 1988) Scieszka S F (1985) New concept for determining pulverizing properties of coal Fuel 64 (8) 1132-1142 (Aug 1985) Sebesta P Vodickova A (1989) Self-ignition of coal according to its reactivity to oxygen In Symposium on coal utilization trends and challenges Dhanbad India 13-14 Dec 1989 Dhanbad India Central Fuel Research Institute vp (1989) Sherman R A Pilcher J M (1938) An experimental investigation of the use of oil in the treatment of coal Transactions ofAmerican Society of Chemical Engineers 60 97-109 (1938) Shibaoka M Thomas C S Heng S Mackay G H (1987) Significance of morphological features of macerals in coal utilization research In 1987 international conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 107-110 (1987) Shida H Adacchi T Karagasaki M Kuminoto T Hisatome M Kobayashi Y (1984) Development of three-dimensional numerical analysis method of boiler furnace characteristics - part 1 flow analysis Technical Review 18-23 (1984)
Shigeta J-I Hamao Y Aoki H Kajigaya 1 (1987) Development of a coal ash corrosivity index for high temperature corrosion Journal of Engineering Materials and Technology 109 (4) 299-305 (Oct 1987) Shimada S Aumiiller A Klemm F (1991) Measurement of property change of coals stored in stockpile for a long time In 1991 international conference on coal science Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 925-928 (Sep 1991) Shonhardt J A (1990) Evaluation of spontaneous combustion characteristics of some Australian coals Coal Journal (Australia) (29) 21-31 (1990) Singer J G (1989a) Steam fundamentals In Standard handbook ofpower-plant engineering New York NY USA McGraw Hill pp 13-19 (1989) Singer J G (1989b) Pulverizers In Standard handbook of power-plant engineering New York NY USA McGraw Hill pp 1157-1182 (1989) Singer J G (1991) Combustion fossil power - a reference book on fuel burning and steam generation Windsor CN USA Combustion Engineering 1010 pp (1991) Skinner M S A (1988) The costs of burning coal In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Specialists pp 719-731 (1988) Skorupska N M Marsh H (1989) The importance of petrographic characterization of coal for combustion processes In Institute of Energy conference on applied energy research Swansea UK 5-7 Sep 1989 Bristol UK Adam Hilger pp 161-181 (1989) Skorupska N M Sanyal A Hesselman G J Crelling J C Edwards 1 A S Marsh H (1987) The use of an entrained flow reactor to assess the reactivity of coals of high inertinite content In 1987 intemational conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 827-831 (1987) Sligar J (1985) Coal pulverising mill section In Course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 101-1023 (May 1985) Sligar J (1992) Sydney NSW Australia Pacific Power Services Personal communication (Oct 1992) Smith D J (1991) Integrated control systems The next stop Power Engineering 95 (9) 17-21 (Sep 1991) Smith G (1985) Laboratory studies to support the marketing of Australian coals In Proceedings Coal research conference Wellington New Zealand 15-17 Oct 1985 Wellington New Zealand Coal Research Association of New Zealand vol 2 Paper 342 15 pp (1985) Smith 1 W (1982) The combustion rates of coal chars In Nineteenth symposium (international) on combustion Haifa Israel 8-13 Aug 1982 Pittsburgh PA USA The Combustion Institute pp 1045-1065 (1982) Smith 1 W Wall T F Stanmore B R Harris D J Chen J Y Zhang D K (1991a) Coal combustion testing optimum laboratory procedure NERDDP-EG-91-993 Canberra ACT Australia National Energy Research Development and Demonstration Council 89 pp (Feb 1991) Smith P J Davies P R Jamaluddin A S (1991b) Coupling fireside deposition with computational combustion predictions In Effects of coal quality on power plants St
113
References
Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 2119-2140 (Jul 1991) Smith P J Smoot L D (1987) Detailed model for practical pulverized coal furnaces and gasifiers In Proceedings of the AR and TD (Advanced Research and Technology Development) direct utilization and instrumentation and diagnostics contractors review meeting Morgantown WV USA 13 Oct 1987 DOEIMETC-886084-vol 1 Morgantown WV USA Morgantown Energy Technology Center pp 62-71 (Oct 1987) Smith S R (1988) Tennessee Valley Authoritys experience with switching to improved quality coal In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 Palo Alto CA USA EPRI Technical Infonnation Services pp 31-323 (May 1988) Smoot L D (1984) Modeling of coal-combustion processes Progress in Energy and Combustion Science 10 (2) 229-272 (1984) Smoot L D Smith P J (1985) Coal combustion and gasification New York NY USA Plenum Press 459 pp (1985) Sorter J G Folsom B A Richter W (1986) Application of pilot-scale coal evaluation to utility boilers In Joint ASMElIEEE Power generation conference Portland OR USA 19-23 Oct 1986 New York NY USA American Society of Mechanical Engineers pp 1-8 (Oct 1986) St Baker T C (1983) Technology of coal utilisation for electric power generation In Coal technology and coal utilisation Brisbane Qld Australia 29-31 Aug 1983 Brisbane Qld Australia Australian Mineral Foundation Inc pp 1-42 (Aug 1983) Stach E Mackowsky M Th Teichmiiller M and others (eds) (1982) Stachs textbook ofcoal petrology Berlin Federal Republic of Germany Gebriider Borntraeger 535 pp (1982) Stallard G S Galluzzo N G Brown R E Pavlish J H (1988) Implementing EPRIs state-of-the-art coal quality impact model into fuel procurement practices In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 677-693 (1988) Stallard G S Mehta A (1991) Using EPRI CQIM to evaluate acid rain strategies In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 257-275 (Jul 1991) Stallard S Galluzzo N G Mehta A K (1989) Demonstration coal quality impact model In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Alto CA USA EPRI Technical Infonnation Services pp 91-919 (Oct 1989) Stanmore B R (1990) Ash hopper explosions in coal-fired boilers In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 274-276 (Jun 1990) Strein D L (1989) Effects of changing coal quality on precipitator perfonnance In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Alto CA USA EPRI Technical Infonnation Services pp 41-417 (Oct 1989)
Swaine D J (1990) Methods of analysis In Trace elements in coal London UK Butterworths amp Co Ltd pp 50-76 (1990) Swanson A R Taggart I J Wood D L (1982) The economic value of coal for coal fired power stations In Coal Phoenix of the 80s - Proceedings 64th CIC coal symposium Halifax NS Canada 31 May-3 Jun 1981 Ottawa ON Canada Canadian Society for Chemical Engineering pp 324-329 (1982) Swithenbank J Garbett E S Boysan F Ayers W H (1988) Advance of research on coal combustion system modelling In International symposium on coal combustion Science and technology of industrial and utility applications Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 39-63 (1988) Tams D E (1990) Atmospheric fluidized beds - problems and solutions in practice In International conference on steam plant for the 1990s London UK 4-6 Apr 1990 Bury St Edmunds UK Mechanical Engineering Publications pp 117-124 (1990) Taraba B (1989) Effects of grain size and moisture on heat released during oxidation In 2 celostatni konference Samovolne vznecovani uhli v teorii a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSAV pp 1-9 (1989) Taubert U (1991) New developments in the waste disposal of coal-fired power plants VGB Kraftwerkstechnik - English Issue 2 (91) 86-91 (1991) Teichmillier M (1982) Origin of the petrographic constituents In Stachs textbook of coal petrology Stach E Mackowsky M Th Teichmller M and others (eds) Berlin Federal Republic of Germany Gebriider Borntraeger pp 219-294 (1982) Teyssler J (1988) Dependence of operating cost of a steam generator on inert content of the fuel Paper presented at Twentieth power plant technical colloquium Dresden Federal Republic of Germany 11-12 Oct 1988 Thielen W Odenthal H P Richter W (1987) Investigation of the influence of furnace geometry and coal properties on furnace perfonnance with the help of radiation transfer model In Fundamentals of the physical-chemistry of pulverised coal combustion Les Arcs France 28 Jul-1 Aug 1986 Dordrecht the Netherlands Martinus Nijhoff Publishers pp 424-436 (1987) Thompson A W Gibb W H (1988) Coal ash viscosity measurements on selected British coals as an aid to slagging propensity assessment In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 315-351 (1988) Tisch C Mancini R Sutton J Rini M (1990) Optimize p-c combustion to reduce carbon in fly ash Power 134 (12) 31-33 (Dec 1990) Tominaga H Sato M (1989) Development of a simulation for pulverised coal-fired boiler operation (part 4) evaluation of the FLUENT model Idemitsu Sekiyu Gijutsu 32 (1) 29-37 (1 Jan 1989) Truelove J (1985) Burners and flame stability In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle
114
References
NSW Australia University of Newcastle Institute of Coal Research pp 41-419 (May 1985) Tsai CoY Scaroni A W (1987) Reactivity ofbiturninous coal chars during the initial stage of pulverized-coal combustion Fuel 66 (10) 1400-1406 (Oct 1987) Ugursal V I AI Taweel A M (1990) A method for calculating the area requirement for power plant ash and FGD sludge disposal Journal of Coal Quality 9 (3) 87-90 (1990) Ugursal V I AI Taweel A M Mackay G D M (1990) Impact of coal quality on the cost of electrical power generation a technoeconomic model International Journal of Energy Research 14 (6) 683-699 (Aug 1990) Unsworth J F Barrett D J Roberts P T (1991) Coal quality and combustion performance an international perspective Amsterdam the Netherlands Elsevier Science Publishers 648 pp (1991) Vaninetti G E (1987) The importance of coal quality in marketing Journal of Coal Quality 6 (I) 5-7 (Jan 1987) Vernon J L (1989) Market impacts of sulphur control the consequences for coal lEACRlI8 London UK lEA Coal Research III pp (Oct 1989) Vernon J Soud H (1990) FGD installations on coal-fired plants lEACRl22 London UK lEA Coal Research 84 pp (Apr 1990) Vissar M Boysan F Weber R (1987) Computations of isothermal swirling vortices in the near burner zone Report on the MMF 1-1 investigation IFRF-F-336a9 Umiuden the Netherlands International Flame Research Foundation 179 pp (Iun 1987) Vitta P K Lowe S D Gallaspy D T Afonso R F Molino N M (1991) Application and validation of the coal quality impact model as part of the EPRI coal quality monitoring project In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 295-2117 (luI 1991) van Bush P Snyder T R Chang R L (1989) Determination of baghouse performance from coal and ash properties part II JAPCA Journal of the Air and Waste Management Association 39 (3) 361-372 (Mar 1989) Wagoner C L (1988) New opportunity to predict and verify effects of coal quality on the operation of heat exchangers through generic engineering In Reducing electricity generation costs by improving coal quality Indiana PA USA 5-6 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Information Services pp 61-626 (May 1988) Wain S E Livingston W R Sanyal A Williamson J (1992) Thermal and mechanical properties of boiler slags of relevance to sootblowing In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 459-470 (1992) Wall T F (1985a) Coal characterisation for combustion In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 11-119 (May 1985) Wall T F (1985b) Combustion of coal chars In An intensive course on the characterisation of steaming coals Newcastle
NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 51-529 (May 1985) Wall T F Wibberley L J McCol Stewart I (1985) The characterisation of steaming coals - limitations of the standard laboratory and pilot scale tests In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 111-1126 (May 1985) Walsh P M Beer J M Sarofun A F (1988) Estimation of aerodynamic effects on erosion of a tube by ash In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 219-234 (1988) Ward C P Pech J W Woodson H S (1988) Analytical model for coal combustion optimizing boiler operation through combustion control In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 Palo Alto CA USA EPRI Technical Information Services pp 621-629 (1988) Ward C R (1984) Chemical analysis and classification of coal In Coal geology and coal technology C R Ward (ed) Melbourne Vic Australia Blackwell Scientific Publications pp 40-73 (1984) Waters A G (1987) Implications of coal properties for thermal coal exports In Geology and coal mining conference Proceedings Sydney NSW Australia 13-15 Oct 1987 Sydney NSW Australia Geological Society of Australia Coal Geology Group pp AGWOI-AGW08 (1987) Wibberley L J (1985a) Effect of coal composition on deposit formation in PP fired boilers In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 91-918 (May 1985) Wibberley L J (1985b) Characterisation of coals for flyash and sulphur oxide emissions In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 71-715 (May 1985) Wibberley L J Wall T F (1986) An investigation of factors affecting the physical characteristics of fly ash formed in a laboratory scale combustor Combustion Science and Technology 48 177-190 (1986) Wigley F Williamson J Jones A R (1989) Slagging indices for UK coal and their relationship with mineral matter Fuel Processing Technology 24 (13) 383-389 (1989) Wollmann H-J (1990) Danger from residual coal content in hot fly ash VGB Krafiwerkstechnik - English Issue 70 (6) 404-408 (Iun 1990) Wright I G Williams D N Mehta A K (1988) Techniques to reduce fireside corrosion and fly ash erosion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 255-274 (1988) Wu E J Chen K Y (1987) Chemical form and leachability of inorganic trace elements in coal ash EPRI-EA-5115 Palo Alto CA USA EPRI Technical Information Services 202 pp (Iun 1987) Wu K T Payne R Li B Sheldon M (1990) Application of
115
References
engineering computer models and modeling techniques for evaluating boiler thermal performance and emissions control processes In Combustion modeling and burner replacement strategies ASMFIEEE joint power generation conference Boston MA USA 21-25 Oct 1990 New York NY USA American Society of Mechanical Engineers pp 1-8 (1990) Yancey H F Geer M R Price J D (1951) An investigation of the abrasiveness of coal and its associated impurities Mining Engineering 3 262-268 (1951) Yarkin E V Novikova I V (1988) Price as an incentive for improving quality of power fuel Eleckricheskie Stantsii (3) 8-11 (Mar 1988) Yavorskii I A Alaev G P Pugach L I Talankin L P (1968) Influence of the petrographic composition of coals on the efficiency of a pf fired boiler furnace Thermal Engineering (English translation of Teploenergetika) 15 (9) 108-113 (1968) Young R P DuBard J L Hovis L S (1989) Resistivity of fly ashlsorbent mixtures In Seventh symposium on the transfer and utilization ofparticulate control technology Nashville lN USA 22-25 Mar 1988 EPRI-GS-6208 Palo Alto CA USA EPRI Technical Information Services pp 11-115 (1989)
Zehner P (1989) Erfahrungen mit NOx-mindemden Massnahmen an Feuerungen grosser Dampferzeuger (Experience with combustion measures for NOx reduction at large steam generators) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Germany 26-27 Apr 1989 Essen Federal Republic of Germany VGB Kraftwerkstechnik GmbH pp 121-136 (1989) Zelkowski J Riepe W (1987) Generation of ash by hard coal power stations and problems of its utilization in the Federal Republic of Germany In Ash - a valuable resource Pretoria South Africa 1987 Pretoria South Africa Council for Scientific and Industrial Research vol 1 pp Bl-5 (1987) Ziesmer B C Barna L J Bull D L (1991) A utility perspective on western coals - operating experience and methods for screening potential fuel supplies In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 437-456 (Jul 1991) Zygarlicke C J Steadman E N Benoon S A (1990) Studies of transformations of inorganic constituents in a Texas lignite during combustion Progress in Energy and Combustion Science 16 (4) 195-204 (1990)
116
Appendix List of standards referred to in the report
American Society for Testing and Materials 1916 Race Street Philadelphia PA 19103 USA
D197-1987 Sampling and fineness test of pulverized coal
D291-1986 Cubic foot weight of crushed bituminous coal
D3172-1989
D3173-1987
D3174-1989
Proximate analysis of coal and coke
Moisture in the analysis sample of coal and coke
Ash in the analysis sample of coal and coke from coal
0409-1992 Grindability of coal by the Hardgrove-machine method
D3175-1989 Volatile matter in the analysis sample of coal and coke
D440-1986 Drop shatter test for coal D3176-1989 Ultimate analysis of coal and coke
D441-1986
D547-1941
D720-1991
Tumbler test for coal
Index of dustiness of coal and coke
Free-swelling index of coal
D3177-1989
D3178-1989
Total sulfur in the analysis sample of coal and coke
Carbon and hydrogen in the analysis sample of coal and coke
D1412-1989
D1756-1989
Equilibrium moisture of coal at 96 to 97 per cent relative humidity and 30D C
Carbon dioxide in coal
D3179-1989
D3286-1991
Nitrogen in the analysis sample of coal and coke
Gross CalOrifIC value of coal and coke by the isoperibol bomb calorimeter
D1857-1987 Fusibility of coal and coke ash D3302-1991 Total moisture in coal
D2015-1991 Gross calorific value of coal and coke by the adiabatic bomb calorimeter
D3682-1991 Major and minor elements in coal and coke ash by atomic absorption
D2361-1991
D2492-1990
D2795-1986
Chlorine in coal
Forms of sulfur in coal
Analysis of coal and coke ash
D3683-1978
D4326-1992
Trace elements in coal and coke ash by atomic absorption
Major and minor elements in coal and coke ash by X-ray fluorescence
D2798-1991 Microscopical determination of the reflectance of intrinite in a polished specimen of coal
D4749-1987 Performing the sieve analysis of coal and designating coal size
D2799-1992 Microscopical determination of volume per cent of physical components of coal
D5142-1990 Proximate analysis of the analysis sample of coal and coke by instrumental procedures
117
List of standards referred to in the report
Standards Association of Australia BS 1016 Part 6-1977 Ultimate analysis of coal 80-86 Arthur Street North Sydney NSW 2060 Australia
BS 1016 Part 8-1980 Chlorine in coal and coke
BS 1016 Part 11-1982 Forms of sulphur in coal
BS 1016 Part 12-1984 Caking and swelling properties of coal
BS 1016 Part 14-1979 Analysis of coal ash and coke ash
BS 1016 Part 15-1979 Fusibility of coal ash and coke ash
BS 1016 Part 17-1987 Size analysis of coal
BS 1016 Part 11-1990 Determination of the index of abrasion of coal
BS 1016 Part 20-1987 Determination of the Hardgrove grindability index of hard coal
BS 1016 Part 111-1990 Determination of abrasion index of coal
BS 6127 Part 3-1981 Petrographic analysis of bituminous coal and anthracite Part 3 Method of determining maceral group composition of bituminous coal and anthracite
BS 6127 Part 5-1981 Petrographic analysis of bituminous coal and anthracite Part 5 Method of determining microscopically the reflectance of vitrinite
Deutsches Institut rDr Normung eV Postfach 1107 1000 Berlin 30 Germany
DIN 22020 Part 3-1981 Mikroskopische Untersuchungen an Steinkohle Koks und Briketts Maceralanalyse an Komerschliffen (Microscopic method of analysing coal coke and briquettes maceral group analysis)
DIN 22020 Part 5-1981 Mikroskopische Untersuchungen an Steinkohle Koks und Briketts Reflexionsmessungen an Vitriniten (Microscopic method of analysing coal coke and briquettes measurement of the reflectance of vitrinite)
DIN 51 700-1967 Allgemeines und Ubersicht tiber Untersuchungsverfahren (General and overview of methods of analysis)
DIN 51 705-1979 Bestimmung der Schtittdichte (Determination of bulk density)
AS 1038 Parts 1-11
AS 1038 Part 1-1980
AS 1038 Part 3-1989
AS 1038 Part 5-1989
AS 1038 Part 6-1986
AS 1038 Part 8-1980
AS 1038 Part 11-1982
AS 1038 Part 121-1984
AS 1038 Part 141-1981
AS 1038 Part 15-1972
AS 1038 Part 17shy
AS 1038 Part 20-1981
AS 1038 Part 22-1983
AS 2486-1981
AS 2515-1981
AS 3381-1991
AS 3899-1991
Methods for the analysis and testing of coal and coke (metric units)
Total moisture in hard coal
Proximate analysis of hard coal
Gross specific energy of coal and coke
Ultimate analysis of coal
Chlorine in coal and coke
Forms of sulphur in coal
Determination of crucible swelling number of coal
Analysis of coal ash coke ash and mineral matter (borate fusion-flame atomic absorption method)
Fusibility of coal ash and coke ash
Size analysis of hard coal
Determination of Hardgrove Grindability Index of hard coal
Determination of mineral matter and water of hydration of minerals in coal
Microscopical determination of the reflectance of coal macerals
Determination of the maceral group composition of bituminous coal and anthracite (hard coal)
Size analysis of hard coal
Higher rank coals and coke - bulk density
British Standards Institution Sales Office Linford Wood Milton Keynes MK14 6LE UK
BS 1016 Parts 1-20
BS 1016 Part 1-1989
BS 1016 Part 3-1973
BS 1016 Part 5-1977
Methods for the analysis and testing of coal and coke
Total moisture of coal
Proximate of analysis coal
Gross calorific value of coal and coke
118
Appendix
DIN 51 717-1967
DIN 51 718-1978
DIN 51 719-1978
DIN 51 720-1978
DIN 51 721-1950
DIN 51 722shy
DIN 51 724-1975
DIN 51 726-1980
DIN 51 727-1976
DIN 51 729shy
DIN 51 730-1976
DIN 51 741-1974
DIN 51900shy
Bestimmung der Trommelfestigkeit und des Abriebs von Steinkohlenkoks (Detennination of abrasion indexdrum strength and abrasion of hard coal coke)
Bestimmung des Wassergehaltes (Detennination of water content)
Bestimmung des Aschegehaltes (Detennination of ash content)
Bestimmung des Gehaltes an Fliichtigen Bestandteilen (Detennination of volatile matter content)
Bestimmung des Gehaltes an Kohlenstoff und Wasserstoff (Detennination of content of carbon and hydrogen)
Bestimmung des Stickstoff-Gehaltes (gilt nur fur Kohlen) (Detennination of nitrogen (for coal only)
Bestimmung des Schwefelgehaltes Gesamtschwefel (Part 1 Detennination of sulphur content and total sulphur)
Bestimmung des Gehaltes an Carbonat-Kohlenstoff-dioxid (Detennination of content of carbonate carbon dioxide)
Bestimmung des Chlorgehaltes (Detennination of chlorine content)
Bestimmung der chemischen Zusammensetzung von Brennstoffasche (Detennination of chemical composition of fuel ash)
Bestimmung des Asche-Schmelzverhaltens (Detennination of ash melting behaviour)
Bestimmung der BHihzahl von Steinkohle (Determination of swelling capacityindex)
Priifung fester und fliissiger Brennstoffe Bestimmung des Brennwertes mit dem Bomben-Kalorimeter und Berechnung des Heizwertes (Testing of solid and liquid fuels detenninationlanalysis of the
heating value by bomb-calorimeter and calculation of the heating value)
Teil 2 - 1977 Verfahren mit isothermem Wassermantel (Part 2 Methods with isothermal water jacket)
Teil 3 - 1977 Verfahren mit adiabatischem Mantel (Part 3 Methods with adiabatic jacket)
International Organization for Standardization Casa Postale 56 CH 1211 Geneva 20 Switzerland
ISO 157-1975
ISO 331-1983
ISO 332-1981
ISO 334-1975
ISO 352- 1981
ISO 501-1981
ISO 540-1981
ISO 562-1981
ISO 589-1981
ISO 602-1983
ISO 625-1975
ISO 925
ISO 1018-1975
ISO 1171-1981
Hard coal - Detennination of forms of sulphur
Coal - Detennination of moisture in the analysis sample - Direct gravimetric method
Coal - Detennination of nitrogen shyMacro Kjeldahl method
Coal and coke - Detennination of total sulphur - Eschka method
Solid mineral fuels shyDetennination of chlorine - High temperature combustion method
Coal - Detennination of the crucible swelling number
Solid mineral fuels shyDetennination of fusibility of ash shyHigh temperature tube method
Hard coal and coke shyDetennination of volatile matter content
Hard coal - Detennination of total moisture
Coal - Detennination of mineral matter
Coal and coke - Detennination of carbon and hydrogen - Liebig method
Coal - Determination of carbon dioxide
Hard coal - Detennination of moisture-holding capacity
Solid mineral fuels shyDetennination of ash
119
List of standards referred to in the report
ISO 1921-1976
ISO 1953-1972
ISO 1994-1976
ISO 5074-1980
Solid mineral fuels shyDetermination of gross calorific value by the calorimeter bomb method and calculation of net calorific value
Hard coals - Size analysis
Hard coal - Determination of oxygen content
Hard coal - Determination of Hardgrove grindability index
ISO 7404 Part 3-1984
ISO 7404 Part 5-1984
Methods for the petrographic analysis of bituminous coal and anthracite Part 3 Method of determining maceral group composition
Methods for the petrographic analysis of bituminous coal and anthracite Part 5 Method of determining microscopically the reflectance of vitrinite
120
Related publications
Further lEA Coal Research publications on coal utilisation are listed below
Advanced coal cleaning technology G R Couch IEACRl44 ISBN 92-9029-197-4 95 pp December 1991
Power station refurbishment opportunities for coal D H Scott IEACRl42 ISBN 92-9029-195-8 58 pp October 1991
On-line analysis of coal A T Kirchner IEACR140 ISBN 92-9029-193-1 79 pp September 1991
Coal gasification for IGCC power generation Toshiishi Takematsu Chris Maude IEACR137 ISBN 92-9029-190-7 80 pp March 1991
Lignite upgrading G R Couch IEACRl23 ISBN 92-9029-176-172 pp May 1990
Power generation from lignite G R Couch IEACRl19 ISBN 92-9029-170-2 67 pp December 1989
Lignite resources and characteristics G R Couch IEACRl13 ISBN 92-9029-163-X 100 pp December 1988
Coal-fired MHD G F Morrison IEACRl06 ISBN 92-9029-151-6 32 pp April 1988
Biotechnology and coal G R Couch ICTISfTR38 ISBN 92-9029-147-8 56 pp March 1987
Understanding pulverised coal combustion G F Morrison ICTISfTR34 ISBN 92-9029-138-9 46 pp December 1986
Atmospheric f1uidised bed boilers for industry I F Thomas ICTISfTR35 ISBN 92-9029-136-2 69 pp November 1986
All reports are priced at pound60pound180 (membernon-member countries)
Other lEA Coal Research pUblications Details of lEA Coal Research publications are available from
Reviews assessments and analyses of supply transport and markets lEA Coal Research coal science Gemini House coal utilisation 10-18 Putney Hill coal and the environment London SW15 6AA
United Kingdom Coal abstracts Coal calendar Tel (0)81-7802111 Coal research projects Fax (0)81-7801746
Abstract
This report examines the impacts of coal properties on power station perfonnance As most of the coal used to generate electricity is consumed as pulverised fuel the focus of the report is on performance in pulverised fuel (PF) power station units The properties that are currently employed as specifications for coal selection are reviewed together with their influence on power station performance Major coal-related items in a power station are considered in relation to those properties which affect their performance There is a review of tools being used for coal selection and prediction of station performance which includes an overview of the types of computer models that are available and those that are being developed
The principal coal properties that were found to cause greatest concern to operators included the ash sulphur moisture and volatile matter contents heating value and grindability Little has changed over the years in the way that coal is assessed and selected for combustion Operators continue to use tests as specifications that were mostly developed for coal uses other than combustion Because the procurement specifications are based on tests which do not relate well to actual practice there is still a need for expensive large scale test burns to confIrm suitability With the advances that have been made in computer technology there is a growing number of utilities that are adopting expert unit or integrated models that aid in the planning and operation of generating units Others have shown scepticism over the capability of devising a truly representative model of a coal combustion plant using the coal data produced from current testing procedures
Specific requirements that have been identified include the need to develop internationally acceptable methods of defining coal characteristics so that combustion plant perfonnance can be predicted more effectively There is also a need to establish economic parameters which can serve to measure the effects of coals on plant performance and hence on the cost of electricity
4
Contents
List of figures 7
List of tables 9
Acronyms and abbreviations 11
1 Introduction 13 11 Background 13
2 Coal specifications 15 21 Proximate analysis 17 22 Ultimate analysis of coal 20 23 Ash analysis and minerals 21 24 Forms of sulphur chlorine and trace elements 23 25 Coal mechanical and physical properties 23 26 Calculated indices 28 27 Comments 28
3 Pre-combustion performance 29 31 Coal handling and storage 29
311 Plugging and flowability 32 312 Freezing 34 313 Dusting 35 314 Oxidationspontaneous combustion 36
32 Mills 37 321 Drying 37 322 Grinding 38 323 Size classification and transport 42
33 Fans 42 34 Comments 45
4 Combustion performance 46 41 Burners 46 42 Steam generator 47
421 Combustion characteristics 47 422 Ash deposition 49
43 Comments 56
5
5 Post-combustion performance 57 51 Ash transport 57 52 Environmental control 58
521 Coal cleaning 59 522 Fly ash collection 60 523 Technologies for controlling gaseous emissions 63 524 Solid residue disposal 65
53 Comments 67
6 Coal-related effects on overall power station performance and costs 68 61 Capital costs 68 62 Cost of coal 68 63 Power station perfonnance and costs 69
631 Capacity 69 632 Heat rate 69 633 Maintenance 74 634 Availability 76
64 Comments 77
7 Computer models 79 71 Least cost coalcoal blend models 80 72 Component evaluation models 81 73 Unit models 82
731 Statistically-derived regression models 82 732 Systems engineering analysis 88 733 Integrated site models 97
74 Comments 99
8 Conclusions 101
9 References 104
Appendix List of standards referred to in the report 117
6
Figures
Schematic diagram of the coal-to-electricity chain 14
8 Three-day consolidation critical arching diameter (CAD)
18 Influence of ash characteristics of US coals on
23 Resistivity results for both power station fly ash and
2 Comparison of different coal classification systems 18
3 Mill throughput as a function of Hardgrove grindability index 24
4 Critical temperature points of the ash fusion test 25
5 Typical power station components 29
6 Typical flow patterns in bunkers 32
7 Surface moisture versus critical arching diameter (CAD) determined from shear tests 33
versus per cent fines in coal as a function of moisture content 33
9 Dewatering efficiency versus temperature 34
10 Size distributions of Australian export coal 35
11 Coal lift-off from a stockpile as a function of total moisture content 35
12 Influence of storage time on swelling index 37
13 Primary air temperature requirements depending on moisture content and coal type 39
14 Variation in capacity factor with HGI for different fineness grinds 40
15 HGI for several coals as a function of rank 41
16 Typical utility boiler fan arrangement 43
17 Fuel ratio as an indicator of coal reactivity 48
furnace size of 600 MW pulverised coal fired boilers 49
19 Mechanisms for fly ash formation 50
20 Heat flux recovery for different coals and soot blowing cycles 52
21 Effect of CaO and MgO on corrosivity deposit 53
22 Typical ash distribution 58
laboratory ash from Tallawarra power station feed coal 62
7
24 Laboratory resistivity curves of ash from a South African coal and from a blend of South African and Polish coals against temperature 62
25 Effects of grindability on vertical spindle pulveriser performance 72
26 Example of cost impact of a coal change on heat rate for a 1000 MW boiler 74
27 Adjusted maintenance cost accounts for TVAs Cumberland plant 75
28 Causes of coal-related outages 76
29 Boiler and boiler tubes equivalent availability factor (EAF) record 77
30 Mill engineering model analysis approach 82
31 Comparison of TVA and EPRI availability correlations to a 1000 MW boiler 85
32 Comparison of ash and H20 effects on boiler efficiency and gross heat rate 86
33 Outline of CIVEC model operation 87
34 CQEA evaluation of the impact of different coals on overall production costs of one unit 92
35 Equipment types modelled by CQIM 92
36 Major components of the CQE system 94
37 Correlations of forced outage hours against ash throughput using the CQI model 95
38 Schematic showing the structure of the C-QUEL system 97
39 Comparison of the operations with and without the use of the C-QUEL 98
8
5
10
15
20
25
Tables
1 Summary of coal quality requirements for power generation 16
2 Coal composition parameters standard measurements 17
3 Analysis of a given coal calculated to different bases 18
4 Rank and coal properties 19
Minerals in coal 22
6 Coal mechanical and physical parameters standard measurements 24
7 A summary of the major characteristics of the three maceral groups in hard coals 25
8 Summary of coal ash indices 26
9 lllustrative example of USA coal storage requirements 30
Conveyor Equipment Manufacturers Association (CEMA) material classification chart 31
11 CEMA codes for various coals 32
12 Analysis of ash and clay distribution in a coal by mesh size 33
13 Effect of coal properties on critical lift-off moisture content 35
14 Preferred range of coal properties 37
Maximum mill outlet temperatures for vertical spindle mills 38
16 Comparison of fineness recommendations 38
17 Summary of the effects of coal properties on power station component performance - I 44
18 Enrichment of iron in boiler wall deposits shycomparison of composition of ash deposits and as-fired coal ashes 52
19 Hardness of fly ash constituents 54
Properties of some coal ash components 54
21 Summary of the effects of coal properties on power station component performance - II 56
22 Summary of coal cleaning effects on boiler operation 59
23 Effect of coal type on total concentrations of selected elements from fly ash samples 65
24 Summary of the effects of coal properties on power station component performance - III 66
The effect of coal quality on the costs of a new power station 68
9
26 Ash contents of traded coals 69
31 Examples of boiler frreside variables station and cost
33 Comparison of coal energy costs based on gross heating
27 Calculation of boiler heat losses 70
28 Typical boiler losses for four Australian Queensland steaming coals 71
29 Total fuel costs for power stations of the Southern Company USA 75
30 Comparison of reduced boiler availability on the basis of hours in operation and type of fuel 76
components which may be affected by those variables when coal quality is changed 78
32 Model input output data - International Coal Value Model (ICVM) 80
value (at power station pulverisers) - in order of increasing cost 80
34 Boiler groupings in TVA study 83
35 TVA study - maintenance costs plant correlations for all coal-related equipment 84
36 NERA study - gross heat rate correlation 85
37 ClVEC coal specifications input 88
38 ClVEC power station operational parameters 89
39 ClVEC factors contribution to utilisation value 89
40 Model input output data - COALBUY 90
41 Model input output data - Coal Quality Advisor (CQA) 90
42 Model input output data - Coal Quality Engineering Analysis (CQEA) 91
43 Model input output data - Coal Quality Impact Model (CQIM) 93
44 Ranges of selected coal-ash combustibility parameter that predict approximate classification of CF values 94
45 Model input output data - IMPACT 95
46 Assessment of four coals for Fusina unit 3 using the CQI model 96
47 Summary of model types and capabilities 99
48 Summary of the impacts of coal quality on power station performance 102
10
Acronyms and abbreviations
ad AP ARA ASTM BSl Btu CAD CCSEM CEMA CGI cif CPampL CQA CQEA CQE CQIM CSIRO daf DIN dmmf DTF EEl EFR EPRl ESP FD FEGT FFV FGD FGET FGR fob FTIR GADS GHR GP HGI HLampP HR
air-dried auxiliary power Acid Rain Advisor American Society for Testing and Materials British Standards Institution British thermal unit critical arching diameter computer controlled scanning electron microscopy Conveyor Equipment Manufacturers Association continuous grindability index cost insurance freight Carolina Power and Light Company Coal Quality Advisor Coal Quality Engineering Analysis Coal Quality Expert Coal Quality Impact Model Commonwealth Scientific and Industrial Research Organisation (Australia) dry ash-free Deutsches Institut rur Normung (Germany) dry mineral matter-free drop tube furnace Edison Electric Institute (USA) entrained flow reactor Electric Power Research Institute (USA) electrostatic precipitator forced draft furnace exit gas temperature flow factor value flue gas desulphurisation flue gas exit temperature flue gas recirculation free on board Fourier transform infrared Generating Availability Data System (USA) gross heat rate gross power Hardgrove grindability index Houston Lighting amp Power Company (USA) heat rate
11
ICVM ill IEEE IFRF ISO LCFS kWh MCR MJlkg MWe MWh NERA NERC NHR nm NOx
NYSEG OGampE OampM PA PF PGNAA PN PP ppm ROM SCR SNCR TGA THR TVA UDI UK USA US DOE
International Coal Value Model induced draft Institute of Electronic and Electrical Engineers (UK) International Flame Research Foundation (The Netherlands) International Organization for Standardization Least cost fuel system kilowatt hour maximum continuous rating megajoule per kilogram megawatt (electrical) megawatt hours National Economic Research Associate (USA) North American Electric Reliability Council (USA) net heat rate nanometres nitrogen oxides New York State Electric amp Gas Company (USA) Oklahoma Gas amp Electric Company (USA) operation and maintenance primary air pulverised fuel Prompt Gamma Neutron Activation Analysis Polish Standards Committee Pacific Power parts per million run-of-mine selective catalytic reduction selective non-catalytic reduction thermal gravimetric analysis turbine heat rate Tennessee Valley Authority (USA) Utility Data Institute (USA) United Kingdom United States of America United States Department of Energy
12
1 Introduction
This report examines the impacts of coal properties on power stations buming pulverised fuels (PF) The properties that are currently examined when defining specifications for coal selection are reviewed together with their influence on power station performance The main power station components are considered in relation to those coal properties which affect their performance There is a review of tools being used for coal selection and prediction of station performance which includes an overview of the types of computer models that are both available and under development
In support of the study lEA Coal Research conducted a survey by questionnaire of power stations in 12 countries to obtain additional information about utility practice and experience of the effects of coal quality on power station performance The responses of station operators and research specialists to the questionnaire were of considerable value and much appreciated
11 Background Utilities are continually striving to produce power at the lowest possible cost This means that power stations must operate at optimal availability and rated output while maintaining efficient operation and maintenance schedules At the same time they must also meet relevant emission requirements
Operators of coal-frred stations have long known that coal composition and characteristics signifIcantly affect operation on a broad front Because a power station is a complex interrelated system a change in one area such as coal quality can reverberate throughout the whole system Figure 1 shows a schematic diagram of the coal-to-electricity chain To generate electricity to the busbar at minimum cost it is necessary to evaluate the total cost associated with each coal This includes the cost of any coal-related effects on the performance and availability of
power station components as indicated by Sections 4-7 in Figure 1 in addition to the delivered cost of the coal It is estimated that coal quality factors can contribute up to 60 of all unscheduled outages of coal-fired stations (Mancini and others 1988)
In some cases utilities have the opportunity to fire a range of coals in their power stations In general power stations have a design coal analysis with which initial performance guarantees are met It is also usual to have an allowable range for the most important coal properties within which it is expected that full load may be produced although possibly at reduced efficiencies Substantial deviations in one or more of the properties may result in impaired plant performance or even serious operating and maintenance problems
The quality of coal supplied to a power station may vary for many reasons including
typical day-to-day seam variations in individual coals longer term variations in coal quality due to seam depletion andor change of mining method inconsistencies due to inadequate preparation or poor quality control at the mine site variation in proportions of coals supplied from several traditional supply sources replacement of traditional supplies with sources with different properties due to changing availability or price switchinglblending requirements to meet changing emissions regulations intentional change of fuel quality to solve existing performance problems heavy reliance on recoveries from old stockpiles effects of weather
In order to select a coal supply utilities must try to predict the impacts of alternative coals on power station performance and overall power generation costs Since the type and design of boiler and auxiliary equipment are fixed the coal is
13
6
Introduction
PREPARATION PLANT TRANSPORTMINE
2 3
Figure 1 Schematic diagram of the coal-ta-electricity chain
usually selected to match these rather than the reverse There are numerous methods employed to help select an appropriate coal These can range from selecting coals on the basis of a limited number of design specifications based on proximate analysis through use of sophisticated computer models describing overall performance to expensive full
4 5
HANDLING AND MILLING
STORAGE
PARTICULATES REMOVAL - COMBUSTION~ bull
6B FGD
6C
WASTE DISPOSAL
9
ADDITIONAL UNIT
GENERATION CAPACITY
STEAM 7TURBINE
ELECTRICITY TO 8BUSBAR
scale test firing of sample loads over a limited time period It is recognised that a wide range of complex physical and chemical processes occur during preparation and combustion and so it is not surprising that these methods may still prove to be inadequate in providing a quantitative understanding of the impacts of coal quality
14
2 Coal specifications
The criteria for including particular properties of a coal in a specification used for a particular power station are varied Basic coal contracts can include as few as three or four base quality guarantees - stipulating a range of values for heating value ash content moisture and more recently sulphur More typical purchasing specifications incorporate additional properties such as volatile matter fixed carbon ash fusion temperatures grindability along with the base level specifications of heating value ash moisture and sulphur (Schaeffer 1988) More recently these have been expanded by some utilities to include trace element details and the petrographic composition of the coal Table 1 summarises the typical coal quality requirements for power generation The specification values indicated are derived from both the literature and analysis of the results obtained from the survey of boiler operators
Most of the properties described in Table 1 are measured using relatively simple standard tests More recently some coal specifications have emerged which appear even more complex and restrictive In addition to the standard characterisation tests they may include non-standard characterisation and combustion tests such as the use of thermal gravimetric analysers drop-tube furnaces and pilot-plant tests (see Section 42) It has been argued that such detailed specifications are not necessary (OKeefe and others 1987) may be excessively restrictive and could lead to increasing fuel cost as specific sources are no longer available (Mahr 1988 Harrison and Zera 1990) The advocates for detailed specifications argue that to use only a basic fuel specification for selection will leave the market open for many coals which may not perform as well as the design-specification coal (Vaninetti 1987 Myllynen 1987) They will most likely be attractively priced (Corder 1983 OKeefe and others 1987) but there is no assurance that the saving will necessarily minimise the overall cost of power generation In many cases buying the coal of lowest price can be false economy (see Chapter 6) for example if the coal adversely affects heat rate additional coal will be
needed If the selected coal cannot sustain full unit capacity or causes additional outages (availability loss) alternative units must be operated to make up the lost power possibly at considerable additional cost Also increased maintenance costs add directly to the total cost of power generation (Folsom and others 1986a Sotter and others 1986 Yarkin and Novikova 1988 Ziesmer and others 1991 Bretz 1991a)
Blending to meet quality specifications is gaining acceptance In most cases power stations do not fire only coal from a single seam in their boilers As coal occurs in heterogeneous deposits the supply from any mine is already a blend of material from different seams to meet the required specification This principle may be extended such that coals supplied to power stations can be blends from several different sources prepared at handling centres such as at Rotterdam The Netherlands (Rademacher 1990) Power stations themselves may have facilities for blending two or more coals on site Separately the coals may not meet specification but a homogeneous mix does (Ratt 1991) Most countries which depend solely on imported coals have commercial strategies stipulating that no single source should account for more than 40 of supply (Klitgaard 1988) Blending which extends the range of acceptable coals increases the number of supply opportunities It should be noted that the non-additive nature of some of the standard tests such as ash fusion tests and use of HGI values (see Section 25) makes blend evaluation for power station use inherently complex (Riley and others 1989)
The following sections examine the coal properties used in coal specifications and evaluate their significance in power station operation
Table 2 lists eighteen standard methods of measuring coal composition together with an indication of the relevance of the results to the utility industry As illustrated in Table 2 the key measurement methods are proximate analysis
15
Coal specifications
Table 1 Summary of coal quality requirements for power generation
Parameter Desired Typicallimits
Heating value (ar) MJkg high min 24-25 (23) Proximate analysis - Total moisture (ar) 4-8 max 12
- Ash (mt) low max 15-20 (max 30) - Volatile matter (rot) 20-35 min 20 (23) - side-fIred furnaces
15-20 max 20 - down-fIred pf furnaces Total sulphur (mt) low max 05-10 - dependent on local pollution regulations
Hardgrove grindability index (HGI) high
Maximum size mm 130-40 Fines less than 05 mm (15 max)
Proximate analysis Ultimate analysis
Chlorine (rot)
Ash analysis weight of ash
Ash fusion temperatures degC
Swelling index Ash resistivity Handleability
Trace elements
Vitrinite reflectogram
Maceral analysis
- Fixed carbon (rot) - Carbon (daf)
- Hydrogen (daf)
- Nitrogen (dat) low - Sulphur (dat)
- Oxygen (by diff daf) low
Silicon dioxide (Si02) Aluminium oxide (Ah03) Titanium oxide (Ti02) Ferric oxide (Fe203) Calcium oxide (CaO) Magnesium oxide (MgO) Sodium oxide (Na20) Potassium oxide (K20) Sulphite (SOn Phosphorus pentoxide (P20 S)
- initial deformation high - softening (H = W) high - hemispherical (H =lizW) high - fluid high
low ohmem at 120degC
As Cd Co Cr Cu
Hg Ni Pb Sb Se Tl Zn
Vitrinite Exinite Inertinite Mineral
min 50-55 (min 39) 50 limited by size accepted by pulveriser
limited for handling characteristics
(08-11)
max 01--03 (max 05)
(45-75) (15-35) (04-22) (1-12) (01-23) (02-14) (01--09) (08-26) (01-16) (01-15)
(gt1075) in reducing conditions (gt1150) for dry bottom furnaces (gt1180) Values are much lower for wet bottom (gt1225) furnaces
(max 5) if available if available
Declaration of presence
if available
55-80 5-15 10-25 to declare
Typical limits refer to those commonly quoted those in brackets indicate outer limits acceptable in some cases
Measurement basis ar shy as received mf - moisture free daf - dry ash-free
16
Coal specifications
Table 2 Coal composition parameters standard measurements (after Folsom and others 1986c)
Measurement Method Standards procedure
ASTM AS BS DIN ISO
Parameters measured
Relationship to power station performance
Proximate analysis 03172-89 Moisture D3173-87 Volatile matter D3175-89 Ash D3174-89 Fixed carbon
Ultimate analysis 03176-89 Oxygen Carbon 03178-89 Hydrogen 03178-89 Nitrogen 03179-89 Total sulphur 03177-83
10383-89 10383-89 10383-89 10383-89 10388-89
10386-86
103861-86 103861-86 103862-86 103863-86
10163-73 10163-73 10163-73 10163-73 10163-73
10166-77 10166-77 10166-77 10166-77 10166-77 10166-77
51700-67 51718-78 51720-78 51719-78
51700-67
51721-50 51721-50 51722 517241-75
331-83 562-81 1171-81
1994-76 625-75 625-75 332-81 334-75
H20 Ash VM FC
Part of proximate analysis
C H 0 N S Ash H2O
) Pm of 1_ analysis
These parameters affect all power station systems since they are the principal constituents of coal
Ash analysis D2795-89 AA-Elemental ash analysis Major 03682-87 AA-Elemental ash
1038141-81
1038141-81
101614-79
101614-79
51729-80
analysis Trace 03683-78 Mineral matter C02 in coal D1756-89 Forms of sulphur D2492-90 Chlorine D2361-91 Total moisture D3302-89 Equil moisture D1412-89
1038104-86 103822-83 103823-84 103811-82 10388-80 10381-80 103817-89
10166-77 101611-87 10168-84 10161-89 101621-87
51726 517242 51727-76 51718
602-83 925-80 157-75 352-81 589-81 1018-75 Surface moisture
Corrosion slagging fouling
Handling amp pulverisation
Proximate analysis by instrumental procedures D5142-90
AA Atomic Adsorption ASTM American Society for Testing and Materials AS Australian Standards
BS British Standards Institution DIN Deutsches Institut fur Normung ISO International Organization for Standardization
ultimate analysis and ash analysis Additionally other early 1800s at a time when carbonisation was the most chemical analyses are often carried out on coal samples important use of coal It was a means of broadly assessing Some of these tests are used to enable correction of the bulk distribution of products obtainable from a coal by proximate and ultimate analysis data to allow for mineral destructive distillation (Elliott 1981) It is widely accepted matter constituents while others are used to evaluate the by the utility industry and forms the basis of many coal coals suitability for specific purposes In most coal qualitypower station performance correlations The great producing and consuming countries national or international advantage of the tests required for proximate analysis is that standard techniques are used The titles of the standards they are all quite simple and can be performed with basic reported in this chapter and the addresses of the standards laboratory equipment So much so that they have been fully organisations are given in the Appendix automated in recent years The results of proximate analysis
although endorsed with long history and extensive Common causes of confusion in the comparison of coal and experience are empirical and only applicable if the tests are interpretation of analytical data as reviewed by Carpenter carried out under strict standardised conditions The five (1988) are characteristics obtainable from the procedure are
the different domestic and international coal total moisture classification schemes used (see Figure 2) air-dried moisture the wide range of analytical bases on which the coal data volatile matter may be reported and the failure of many workers to ash identify clearly the basis for their results Table 3 fixed carbon illustrates how results will vary for a single coal depending on the base used Proximate analysis reports moisture in only two categories
as total and air-dried although it actually occurs in coals in different forms Air-dried moisture is also referred to as21 Proximate analysis inherent moisture The total moisture of coal consists of
The proximate analysis of coal is the simplest and most surface and inherent moisture Surface moisture is the common form of coal evaluation It was introduced in the extraneous water held as films on the surface of the coal and
17
----- ---
---
01
Coal specifications
Volatile Australia
301a
302
303
301b 302 303
401-901 high volatile A bituminous
402-702 coal402 class 7 Ihigh volatile B bituminous
coal 902 high volatile
class ~inouscoal
I subbituminousclass subbituminous
B coal 11 A coal subbituminous
class ~
approximate C coal 12 volatile matter
f-- shy dmmf lignite A class class 6 32-40
13 class 7 32-43 class 8 34-49
class ~
class 9 41-49
-14 lignite B
class
-15
matter dmmf
2 6 8 9
10 115 135
14 15 17
195 20 22 24
275 28 31 32 33
36
44J
47J
Great Britain NCB
101 anthracite
102
201a dry Ol ~~ 201b I~~~I~ COcgt
202 ~EgE- co co ~co203 -OlO 02 -en8en t)204
FRG
meta-anthracite
anthracite
lean (non-caking)
coal
forge coal
fat (coking) coal
hard coals
gas coal
tgas flame coal
flame coal
shiny hard
brown coal
matt
soft brown coal
MJkg class 6 326
class 7
302 class 8
class 9 -256
- 221 soft
193 brown coals
147
Heating value MJkg
N S
173 131
179 136
198 151
gross net
3168 3067
3279 3175
3635 3520
-
medium volatile coals
30shy
40shy
50shy
60shy
70shy
International hard coals
class 0
class 1A
class 1B
class 2
class 3
class 4
hardclass 5 coals
class 6 moi sture
high ~ f 0Yo
brown coals
volatile I coals
and I
I~ class 8
-1Q class 9- - 20shy
North America ASTM
Imeta-anthraciteI
anthracite
semi-anthracite
low volatile bituminous
coal
medium volatile
bituminous coal
Calorific value mmmf
hard coals
class 1
class 2
class 3
class 4A
class 4B
hardclass 5 coals
Figure 2 Comparison of different coal classification systems (Couch 1988)
Table 3 Analysis of a given coal calculated to different bases
Condition or basis
Proximate analysis
H2O VM FC Ash
Ultimate analysis
C H 0
As received 339 2061 6653 947 7729 459 561
Dry 2133 6887 980 8000 436 269
Dry ash-free 2365 7635 8869 483 299
Analysis of US Pennsylvania Somerset County Upper Kittaning Bed No 3 Mine
In the ultimate analysis moisture on an as received basis is included in the hydrogen and oxygen Net heating value is calculated from the gross value using the relationship in ISO 1928
its content can vary in a coal over time The moisture present water is difficult to control separate assessment of inherent in other forms is regarded as the inherent moisture it is or air-dried moisture is also necessary as most other more or less constant for coals of a given rank (Ward 1984) analyses are carried out on air-dried material
A coal that is sold commercially usually contains a certain Surface moisture is important to the handleability of coal amount of surface moisture which forms part of the total (see also Section 31) With a content greater than 12 of weight of coal delivered Knowledge of the total moisture the coal weight problems such as bridging in bunkers and content of the coal is therefore essential to assess the value of blocking of feeders can be expected in the transport system any consignment However because the amount of surface (Cortsen 1983) In cold climates the excess surface moisture
I
18
Coal specifications
may freeze and act as a binder so incurring coal handling problems (Raask 1985)
Extremely low surface moisture content can cause environmental problems due to dust and enhanced risks of fire due to coal oxidation which causes heating and may lead to spontaneous combustion especially in low rank coals (see
also Sections 313 and 314)
Surface moisture and part of the inherent moisture of a coal can be released in the mills during grinding This means that the mill inlet or primary air temperature prior to milling must be increased for coals with a high total moisture content The surface moisture of the coal is converted to vapour during milling and forms part of the coal-air mixture in direct feed systems The vapour enters the furnace where it can cause a delay in coal ignition and increase flame length The effect however is small for coals with moisture contents not exceeding 10
The inherent moisture has a more direct influence on coal ignition and combustion Significant gasification of the coal particle to release combustible gases cannot start prior to the evaporation of the moisture from within the particle When firing a coal with a high inherent moisture content conditions can also be improved by increasing mill air inlet temperature
Total moisture in the coal contributes to the overall gas flow in the form of vapour (Cortsen 1983) This can influence the operation of fans that move the air flue gas and pulverised coal through the unit An increase in coal moisture will increase the flue gas volume flow rate thus necessitating an increased power requirement for the fans (see Section 33)
During the combustion process coal releases volatiles which include various amounts of hydrogen carbon oxides methane other low mOlecular weight hydrocarbons and water vapour Volatile yield of a coal is an important property providing a rough indication of the reactivity or combustibility of a coal and ease of ignition and hence flame stability The amount of volatiles actually released in practice is a function of both the coal and its combustion conditions including sample size particle size time rate of heating and maximum temperature reached In order to obtain a method for comparing coals a simple test was devised to obtain a value for the volatile matter content of a coal The volatile matter content as determined by proximate analysis represents the loss of weight corrected for moisture when the coal sample is heated to 900degC in specified apparatus under standardised conditions
Typical values of volatile matter content associated with different ranks of coal as determined by proximate analysis are given in Table 4 (Cunliffe 1990) It should be noted that some of the volatile matter may originate from the mineral matter present
The volatile matter content of a coal is used to assess the stability of the flame after ignition Under the same combustion conditions that is same burner configuration and amount of excess air a coal with a high volatile matter content will usually give stable ignition and a more intensive
Table 4 Rank and coal properties (Cunliffe 1990)
Type C H 0 Volatile Heating
(composition ) matter value daf MJkg
Wood 500 60 430 800 146
Peat 575 55 350 684 159
Lignite 700 50 230 526 216
Bituminous High volatile 770 55 150 421 258
Medium volatile 860 50 45 263 335
Low volatile 905 45 30 188 348
Semi-anthracite 905 45 30 188 348
Anthracite 940 30 15 41 346
daf dry ash-free basis
flame compared with a coal with a low volatile matter content Maintaining stable ignition is one of the most crucial aspects of pulverised coal firing since instability necessitates the use of pilot fuel and in extreme cases may incur the risk of furnace explosion (Cortsen 1983) Low laquo20) volatile matter coals can produce high-carbon residue ash In order to combat this adverse effect the coal would require extra-fine milling and combustion in boilers with a long flame path (Raask 1985) A high volatile matter content (gt30) can cause mill safety problems This is due to the increased possibility of mill fires resulting from spontaneous combustion of the coal (see Section 32) Volatile matter content values are often used to calculate combustibility indices which are used as an indication of the reactivity of a coal They are also included in formulae for the prediction of NOli release during coal combustion (Kok 1988)
Ash is the residue remaining following the complete combustion of all coal organic material and oxidation of the mineral matter present in the coal Ash is commonly used as an indication of the grade or quality of a coal since it provides a measure of the incombustible material present in the coal A higher ash content means a lower heating value of the coal as ash does not contribute any energy to the system It represents a dead weight during coal transport to and through a power station (Lowe 1988a) In order to maintain boiler output when switching from a low ash coal to another with similar specification but a higher ash content an increased throughput of material would be required to achieve the same loading Alternatively power station output may be constrained by the lack of capacity in the ash handling system
Ash content and its distribution within the coal influences ignition stability The transformation of mineral matter to ash is an endothermic reaction - requiring energy Thus some coal particles containing a high proportion of mineral matter may not ignite satisfactorily In some cases stack and unburnt carbon losses have been shown to increase as the heating value of the coal decreases with increased ash content A high-ash content may lower the accessibility of the carbon to combustion within the particle (Kapteijn and others 1990) In contrast to these situations Australian power stations have been known to combust coals with a
19
Coal specifications
high ash (gt25) content without support fuel satisfactorily (Sligar 1992)
High ash coals (gt20) can cause abrasion and particle impaction erosion wear of fuel handling plant mills burners boiler tubes and ash pipes if the plant is not designed for this (Raask 1985) Utilisation of a high ash coal may impair the performance of particulate control devices by ash overloading There may also be problems of accommodating higher ash levels for disposal (Bretz 1991b)
Possibly the most serious effects that ash constituents have upon the boiler performance are those connected with fouling slagging and corrosion of the heating surfaces These problems are discussed in Section 422
The fixed carbon content of coal is not measured directly but represents the difference in an air-dried coal between 100 and the sum of the moisture volatile matter and ash contents It still contains appreciable amounts of nitrogen sulphur hydrogen and possibly oxygen as absorbed or chemically combined material (Rees 1966)
The fixed carbon content of coal is used by the ASTM to classify coal according to rank (Carpenter 1988) It is also used as an estimate of the quantity of char (intermediate combustion product) that can be produced and to indicate the amount of unburnt carbon that might be found in the fly ash
In any assessment of data it should be noted that the final temperatures heating rates and residence times utilised in proximate analysis tests differ significantly from conditions experienced in power station boilers In proximate analysis depending upon the set of country standards used
moisture content is determined in a nitrogen atmosphere at around 100degC for 10 minutes volatile matter of a coal is determined under restricted conditions at 900degC after a residence time of up to seven minutes ash content is determined by combusting the organic component of the coal in air up to around 800dege
Conditions in a power station boiler have been reported to produce temperatures greater than 1700degC (3120degF) heating rates of 1O000-100OOOdegCs and particle residence times within the system of seconds rather than minutes Ideally the suitability of a coal for combustion use should take into account the operational conditions and aim to identify relationships between critical process requirements and specific properties of the coal on a more rational basis However proximate analysis is still widely used in the utility industry
There are also problems with interpreting the results from a proximate analysis Ideally the moisture fraction should contain only water the volatiles fraction should consist only of volatile hydrocarbons released during the initial stages of heating the fixed carbon would be the char after complete devolatilisation and ash only the oxidised remains of the mineral matter after combustion This is not always the case Many coals contain light hydrocarbons which are driven off from the coal at temperatures low enough to cause them to
appear in the moisture determination Consequently the moisture measurement is too high and corresponding volatiles measurement too low This can be a significant problem with lower rank coals (Folsom and others 1986c)
A similar problem occurs between volatiles and fixed carbon The mechanisms involved in thermal decomposition of coal are complex and variations in the particle size treatment times temperatures and heating rates may affect the results Volatile matter content usually includes a loss in weight due also to the decomposition of inorganic material especially carbonates which are known to decompose at temperatures in excess of 250degC (see Section 23) Since fIxed carbon is not a direct measurement but obtained by difference it will include any errors bias and scatter involved in the related determinations of moisture volatile matter and ash Thus the concept of well defmed quantities of fixed carbon and volatile matter for specific coals is subject to qualification
Ash as produced during proximate analysis is often used as the material for conducting chemical analysis and other tests for assessing ash behaviour in a power station The problems associated with this approach are discussed in Section 23
22 Ultimate analysis of coal Ultimate analysis involves the determination of the elemental composition ofthe organic fraction of coal (Ward 1984 Gluskoter and others 1981) Table 2 describes the standard measurement methods for ultimate analysis techniques for ASTM AS BS DIN and ISO In addition to ash and moisture element weight per cents of carbon hydrogen nitrogen sulphur and oxygen (which is determined by difference) are reported Ash and moisture are determined by the same method as in the proximate analysis and suffer from the same shortcomings The detection of the above elements are usually performed with classic oxidation decomposition andor reduction methods (Berkowitz 1985)
Carbon and hydrogen occur mainly as complex hydrocarbon compounds Carbon may also be present in inorganic carbonates The nitrogen found in coals appears to be confmed mainly to the organic compounds present (Ward 1984) The nitrogen content of coal has become an important issue with the increased awareness of air pollution by nitrogen oxides (NOx) Unfortunately there is no simple correlation between coal nitrogen content and nitrogen oxide emissions as unlike sulphur dioxide not all nitrogen oxide produced during combustion comes from the coal itself In combustion theory there are three different formation mechanisms for NOx thermal prompt and formation ofNOx from fuel-bound nitrogen although the reactions are not fully understood (Juniper and Pohl 1991) Only the third mechanism relates to oxidation of the nitrogen contained in coal (Hjalmarsson 1990) The nitrogen content in coal varies between 05 and 25 and is contained mostly in aromatic structures (Burchill 1987 Zehner 1989) Some of the fuel nitrogen is released during devolatilisation and in highly turbulent unstaged burners is rapidly oxidised The remainder of the fuel nitrogen remains in the char and is released at a similar rate to that of char combustion The effIciency of coal-bound nitrogen conversion to NOx has
20
Coal specifications
been estimated at 20-25 for the char and up to 60 for the volatile matter (Morgan 1990) NOx formation from fuel-bound nitrogen can be minimised by promoting devolatilisation in zones of high temperature under reducing conditions for example air staging This principle is exploited in low NOx burners However less can be done to mitigate NOx formation due to the combustion of post-devolatilisation char-bound nitrogen (Kremer and others 1990 Hjalmarsson 1990)
Sulphur is present in nearly all coals from trace amounts up to about 6 although higher levels are not unknown The presence of sulphur compounds in the coal and ash can have many deleterious effects on the operation of boilers for example
during combustion the sulphur is oxidised to S02 A small percentage generally not more than 2 is converted into S03 of which a substantial percentage may then be reabsorbed to form sulphates with the alkali metals in the ash Alkaline sulphates are undesirable in that they increase the tendency of fouling and corrosion of heat transfer surfaces (see Section 422) if the dew point of the combustion gases is reached the S03 present combines with condensing water vapour to produce sulphuric acid which can then cause severe corrosion in cool sections of the power station particularly flue gas ducts and treatment systems (see Section 422)
The main problem however is S02 which is emitted through the stack and constitutes an environmental problem due to the resulting formation of acid rain
The oxygen content of coal is traditionally determined by difference subtracting the sum of the measured elements (C + H + N + S) from 100 although there are procedures available for the direct determination of oxygen (Gluskoter and others 1981 Ward 1984) It is an important property as it can be used as an indicator of rank and the basic nature of the coal Coals tend to oxidise in air to form what is commonly known as weathered coal The oxygen content of a coal has also been used as a measure of the extent of oxidation
Whilst the procedures for elemental analysis described by national standards often differ in minutiae they generally yield closely similar results This can only be achieved by the rigorous adherence to test specifications as laid down by the standards careful sampling and sample preparation
Similar to proximate analysis corrections to the analysis data are necessary For example
contributions to the hydrogen content from residual coal moisture and dehydration of mineral matter because the hydrogen content in coal is determined by the conversion of all the hydrogen present to H20 contributions to the carbon and sulphur contents which are determined by conversion to C02 and S02 respectively because both C02 and S02 are released from any carbonates and sulphides or sulphates that may be contained in the mineral matter
The major limitation of ultimate analysis is the labour cost
and time required to conduct the analyses Several techniques and instruments have been developed to reduce these limitations Some utilise automated gas chromatographic or spectroscopic equipment attached to high temperature combustion furnaces to reduce the time and labour required for the analysis Others utilise a range of measurement techniques including nucleonic methods to provide a quasi-continuous analysis for example on-line analysers (Folsom and others 1986a Kirchner 1991)
23 Ash analysis and minerals Coal ash consists almost entirely of the decomposed residues of silicates carbonates sulphides and other minerals Originating for the most part from clays it consists mainly of alumino silicates so that its chemical composition can usually be expressed in terms of similar oxides to those found in clay minerals The composition of the ash may be used as a guide to the types of minerals originally present in the coal (Given and Yarzab 1978 Ward 1984)
Certain generalisations can be made on the influence of the ash composition on the fusion characteristics as determined by the ash fusion test
the nearer the composition approaches that of alumina silicate Al2032Si02 (Al203 =458 Si02 =542) the more refractory (infusible) it will be CaO MgO and Fe203 act as mild fluxes lowering the fusion temperatures especially in the presence of excess Si02 FeO and Na20 act as strong fluxes in lowering the fusion temperatures high sulphur contents lower the initial deformation temperature and widen the range of fusion temperatures
In practice power station operators are primarily interested in knowing how closely the laboratory-prepared ash content of coal represents the quantity and behaviour of ash produced in large boilers Therefore when interpreting the results of the ash analysis it is important to recognise that the analysis is conducted on a sample of ash produced by the procedures specified in the proximate analysis (for example ASTM D3172 - see Appendix) It does not therefore correspond to the mineral matter present in the parent coal or necessarily to the individual ash particles formed when fired in a utility boiler For example it would be incorrect to assume that the iron measured in the ash sample is necessarily present in the coal as Fe203 or that the aluminium is present as Ah03 (Folsom and others 1986c) The principal chemical reactions that affect the ash yield at different temperatures are
High temperature Low temperature combustion oxidation
(Na K Ca)0Si02xAL203 + S03~ (Na K Ca)S04 + Si02xA1203 2 FeO + 1z 02 ~ Fe203
The boiler ash cools rapidly at a rate of about 200degCs through the temperature range from 900degC to 250degC and
21
Coal specifications
during this short time interval there is only a limited degree of sulphation and oxidation taking place Thus the ash prepared in a laboratory furnace at 815degC has higher weight than that formed in the boiler furnace due to the absorption of S03 in sulphate and additional oxygen in the ferric oxide (Raask 1985) For many years ash analysis in this form has been the only method available for assessing fly ash and deposit composition These in turn would be used to assess a coals slagging fouling and corrosive propensities which are of concern for the efficient operation of the power station More recently investigators have recognised the importance of actual mineral matter composition and
Table 5 Minerals in coal (Mackowsky 1982)
Mineral group First stage of coalification
distribution within the parent coal particles as a better indicator of a coals slagging and fouling behaviour (Nayak and others 1987 Heble and others 1991 Zygarlicke and others 1990) (see also Section 422)
Mineral matter determination is carried out far less frequently than the relatively fast and inexpensive ash determination (Brown 1985) Table 5 describes the minerals found in coal and their method of deposition
Although the ash as measured by proximate analysis is often equated with the coal mineral matter there are significant
Second stage of coalification Occurrence
Syngenetic fonnation synsedimentary-early diagenetic Epigenetic formation (intimately intergrown)
Transported Newly fonned Deposited in Transfonnation by water or fissures cleats of syngenetic wind and cavaties minerals
(coarsely (intimately intergrown) intergrown)
Clay minerals Kaolinite common-very common Illite-Sericite Illite dominant-abundant Minerals with a layered structure Chlorite rare Montmorillonite rare-common Tonstein
Carbonates Siderite Ankerite Ankerite common-very common Dolomite Dolomite rare-common Calcite Calcite common-very common
Sulphides Pyrite Pyrite Pyrite rare-common Melnikovite rare Marcasite Marcasite rare
Galena rare Chalcopyrite rare
Oxides
Quartz
Phosphates
Heavy minerals and accessory
Hematite Goethite
Quartz grains Quartz Quartz
Apatite Apatite Phosphorite
Zircon Tounnaline Orthoclase Biotite
Chlorides Sulphates Nitrates
rare rare
rare-common
rare rare
rare very rare very rare very rare rare rare rare
dominant gt60 abundant 30-60 very common 10-30 of the total mineral matter common 5-10 content in the coal rare 5-1 very rare lt1
22
Coal specifications
differences For example dehydration decomposition and oxidation of mineral matter which may occur during the laboratory process can affect the composition of the ash as follows
FeS04nHzO FeS04 + nHZO dehydration reduces the weight of CaC03 CaO + COZ decomposition ash and adds to
volatile matter
FeS + 20z FeS04 oxidation adds to weight of ash
Similarly partial loss of volatile constituents in particular mercury (Hg) potassium (K) sodium (Na) chlorine (CI) phosphorus (P) and sulphur (S) means that the ash is qualitatively and quantitatively quite different from the mineral matter that gave rise to it Its behaviour which is ultimately determined by its composition is also different If the ash sample is used for subsequent composition analysis the concentration of sodium and other volatile inorganic elements may be significantly lower than in the original mineral matter
Carbonate minerals are common constituents of many coals (see Table 5) These minerals liberate carbon dioxide (C02) on heating and therefore can contribute to the total carbon content of the coal as determined by ultimate analysis Whilst the COz content of the mineral matter is important for the correction of other specifications it is not normally included on coal specification sheets for combustion
24 Forms of SUlphur chlorine and trace elements
Procedures for determining these properties are described in various national and international standards (see Table 2)
Sulphur in coal is generally recognised as existing in three forms inorganic sulphates iron pyrites (FeS2) and organic sulphur compounds known respectively as sulphate sulphur pyritic sulphur and organic sulphur Although the total sulphur content provides sufficient data for most commercial applications a knowledge of the relative amounts of the forms of sulphur present is useful for assessing the level to which the total sulphur content of a particular coal might be reduced by preparation processes Commercial preparation plants can generally remove much of the pyritic sulphur but have little effect on the organic sulphur content
Pyrite is one of the substances which enhance the risk of spontaneous combustion by promoting oxidation and consequent heating of the coal (Bretz 1991a) Pyrite is also a hard and heavy substance which adds to the abrasion of coal mills (Cortsen 1983) (see Section 322)
It appears that in many cases some of the sulphur in the coal is retained in the ash as sulphate Thus the sulphate in the ash is invariably greater than the sulphate in the original coal when both parameters are expressed as fractions of the weight of original coal This effect is so large with the lower rank lignites that the ash yield may actually be greater than
the mineral matter content Kiss and King (1979) showed that between 0 and 99 of the organic sulphur in Australian brown coals may be retained in the ash as sulphate The thermal decomposition of carboxylate salts is particularly efficient in trapping organic sulphur as sulphate in ash With higher rank coals that do not contain carboxyl groups it is carbonates or the oxides formed from pyrolysis that tend to fix sulphur as sulphate It is evident that the amount of sulphate in ash depends on both the sulphur content of the coal and the concentration and nature of the materials capable of fixing it during ashing Various national and international standards specify procedures for determining sulphate in ash
Although not strictly part of the usual ultimate analysis procedure determination of chlorine which may be present in the organic fraction of the coal as distinct from the mineral analysis of the ash is often included Chlorine can enter the coal in the form of mineral chlorides in saline strata waters but this accounts for less than 50 of the total amount The bulk of the chlorine is present as CIshyassociated with organic matter probably as hydrochlorides of pyridine bases (Gibb 1983) In general chlorine content in most coals is quite low though there are exceptions For example some British coals can contain up to 1 chlorine (Given 1984)
In combustion chlorine from both alkali chlorides and the organic fraction of coal can combine with other mineral elements and contribute to deposition and corrosion Chlorine content is also used as an indication of potential fouling tendencies as the majority of the alkali metals responsible for fouling problems are present in the original coal associated with chlorine Chlorine can also affect the control of the pH (aciditylbasicity) in FGD plants (Jacobs 1992)
Apart from the major impurities in coal which are measured in the normal analysis there are a wide variety of trace elements which can also occur Clarke and Sloss (1992) have reviewed the typical concentrations of trace elements in coals There is a growing interest in the emission of trace elements from stacks as atmospheric pollutants and one can expect more attention to be given to this over the coming years (Swaine 1990) There has also been increased anxiety over the possible leaching of trace elements from ash or flue gas desulphurisation waste which may be deposited on the ground as means of disposal or use (Clarke and Sloss 1992) (see also Section 524)
25 Coal mechanical and physical properties
The commercial evaluation of a coal also involves assessments of physical properties A variety of tests have been developed to quantify physical properties of coal but each one is usually related to a particular end use requirement Table 6 lists standard measurements for coal physical tests which are considered relevant for handling and combustion
23
ASTM American Society for Testing and Materials AS Australian Standards BS British Standards Institution DIN Deutsches Institut fUr Norrnung ISO International Organization for Standardization
Bulk density flow properties fineness friability and dustiness all affect the handleability of coal
bulk density measurements are designed to evaluate the density of the coal as it might lie in a pile or on a conveyor belt (Folsom and others 1986c) the size distribution test is used to evaluate the size distribution of coal prior to pulverisation This measurement is important as it can be used to determine the suitability of a coal for a particular mill type and is used to assess the efficiency of the mill system Particle size distribution is also determined for the coal sample after air drying and pulverisation Pulverised coal fineness and size distribution is particularly important for burner performance (see Section 41) there are several tests to evaluate coal friability They are designed to determine the extent of coal size degradation and dusting caused by handling stockpiling and grinding
Most modem coal-burning equipment requires the coal to be ground to a fine powder (pulverised) before it is fed into the boiler The Hardgrove grindability index (HGI) is designed to provide a measure of the relative grindability or ease of pulverisation of a coal The test has changed little over the years Traditionally the HGI is used to predict the capacity performance and energy requirement of milling equipment as well as determining the particle size of the grind produced (Wall 1985a) Coals with high HGI are relatively soft and easy to grind Those with a low value (less than 50) are hard and more difficult to make into pulverised fuel (Wall and others 1985 Ward 1984) The grindability of coals is important in the design and operation of milling equipment A fall in HGI of 15 units can cause up to 25 reduction in the mill capacity for a given PF product as shown by the
10--1-----shyOJ sect 5 Cl r
eOl
09 pound
middotE 0 OJ ~
~ 08
lt5 z
constant PF size distribution
50 48 46 44 42
Hardgrove grindability index (HGI)
Figure 3 Mill throughput as a function of Hardgrove grindabaility index (Fortune 1990)
graph in Figure 3 Coals with high HGI values in general cause few milling problems
The abrasion index is a measure of the abrasiveness of a particular coal and is used in the estimation of mill wear during grinding (Yancey and others 1951) The abrasion index is expressed in milligrams of metal as lost from the blades of the test mill per kilogram of coal
The free swelling index (FSI) also called the crucible swelling number is used to indicate the agglomerating characteristics of a coal when heated Although primarily intended as a quick guide to carbonisation characteristics it can be used as an indicator of char behaviour during combustion A high swelling number suggests that the coal
24
Coal specifications
particle may expand to fonn lightweight porous particles that ash residue at high temperatures can be a critical factor in fly in the air stream and could contribute to a high carbon selection of coals for combustion applications Ash fusion content in the fly ash The extent of swelling is a function of temperatures are often used to predict the relative slagging the rate of heating final temperature and ambient gas and fouling propensities of coal temperature (Essenhigh 1981) so that the actual effects in practice are greatly dependent on combustion conditions The The test involves observing the profiles of specifically swelling number is also significantly affected by the particle size distribution of the sample (Ward 1984) Knowledge of the swelling properties of a coal can be used to avoid agglomeration problems in fuel feed systems (Hainley and others 1986 Tarns 1990) The size of the char particle after devolatilisation and swelling has been found to have an important influence on the kinetics of the combustion process 2 3 4 (Morrison 1986 Jiintgen 1987b) IT 5T HT
1 Cone before heating
The FSI can also provide a broad indication of the degree of 2 IT (or ID) Initial deformation temperature 3 ST Softening temperature (H=W) oxidation of a given coal when compared with a fresh 4 HT Hemispherical temperature (H=12W)
unoxidised sample or against a background history of 5FT Fluid temperature
measurement for a particular coal (ASTM DnO Shimada and others 1991)
Figure 4 Critical temperature points of the ash fusion The ash fusion test (AFT) measures the softening and test (Singer 1991 ASTM D1857) melting behaviour of coal ash The behaviour ofthe coals
Table 7 A summary of the major characteristics of the three maceral groups in hard coals (Falcon and Snyman 1986)
Maceral group Reflectance Chemical properties Combustion properties plant origin
Description Rank Reflected Characteristic Typical products on Ignition Burnout light element heating
Vitrinite woody trunks Dark to Low rank to 05-11 intermediate light intermediate ill ill branches stems medium grey medium rank hydrogen hydrocarbons volatiles jj jj stalks bark leaf bituminous 11-16 content decreasing j j tissue shoots and rank j j detrital organic Pale grey High rank 16--20 j j matter gelified bituminous vitrinised in White anthracite 20-100 acquatic reducing conditions
Exinite cuticles spores Black- Low rank -00-05 early methane volatile- jjjj jjjj resin bodies algae brown gas rich accumulating in sub- Dark grey Bituminous -05--09 hydrogen- oil decreasing jjj jjj acquatic conditions -09-11 rich with rank
Pale grey Medium rank -11-16 condensates bituminous wet gases (j) (j)
Pale grey High rank (decreasing) (=vitrinite) bituminous to white to shadows anthracite -16--100
Inertinite as for vitrinite but Medium Low rank 07-16 hydrogen- low fusinitised in aerobic grey bituminous poor volatiles oxiding conditions Pale grey Medium rank -16--18 in all ranks
to white bituminous and yellow to anthracite -18-100 (j) (j) - white
Capacity or rate j = slow Capacity or rate shown in parenthesis refers to vitrinite jj = medium jjj = fast jjjj = very fast
5 FT
25
Coal specifications
Table 8 Summary of coal ash indices (Anson 1988 Folsom and others 1986c Wibberley and Wall 1986 Wigley and others
Index Factors
Ash descriptor Base-acid ratio (BfA)
Ash viscosity T250 of ash degC (OF) Silica ratio
Siagging propensity Base-acid ratio (BfA) (for Iignitic ash CaO + MgO gtFe203) Siagging factor (for bituminous ash CaO + MgO lt Fe203) Iron-calcium ratio Silica-alumina ratio
Slagging factor degC (OF)
Viscosity slagging factor
Fouling propensity Sodium content
Fouling factor
Total alkaline metal content in ash (expressed in equivalent Na203)
chlorine in dry coal
Strength of sintered fly ash Psi
Temperature ash viscosity = 250 poise SiOl(Si02 +Fe203 + CaO + MgO)
(BfA)(S dry)
Fe20 3fCaO SiOlAh03 Maximum hemispherical temperature + 4(minimum initial deformation temperature)
5 T25o(oxid-TlOooO(red)
975 Fs
(Fs ranges from 10-110 for temperature range 1037-1593degC (1900-2900degFraquo
Na203 (for Iignitic ash CaO + MgO gtFe203) (for bituminous ash CaO + MgO ltFe203)
BfA(Na20 in ash) (for bituminous ash CaO + MgO ltFe203) BfA(Na20 water solublellow temperature ash) Na20 + K20 (for bituminous ash CaO + MgO ltFe203)
oxid oxidising conditions red reducing conditions
shaped cones made from ash prepared by the proximate analysis method with a suitable binder The cones are gradually heated in a furnace under either an oxidising or reducing atmosphere until the ash softens and melts Temperatures corresponding to four characteristic cone profile conditions are noted These conditions are shown in Figure 4 The four cone shapes are defined as follows
initial deformation - the initial rounding of the cone tip softening temperature - height equal to width hemispherical temperature - height equal to one-half width fluid temperature - height equal to one-sixteenth width
Under reducing conditions AFTs are lower due to the greater fluxing action (basicity) of the ferrous ion (FeO) compared with the ferric ion which is present under oxidising conditions
The heating value or calorific value is the single most important coal index or quality value for use in steam power stations since it provides a direct measure of the heat released during combustion The energy liberated by a coal on combustion is due to the exothermic reactions of its
hydrocarbon content with oxygen Other materials in the coal such as nitrogen sulphur and the mineral matter also undergo chemical changes in the combustion process but many of these reactions are endothermic and act to reduce the total energy otherwise available
The standard laboratory test measures the gross heating value that is the total amount of energy given off by the coal including latent heat of condensation of vapour formed in the process Under practical conditions water vapour and other compounds (acid forming gases) can escape directly to the atmosphere without condensation and the recoverable heat given off under these conditions is known as the net heating value It can differ most significantly from the gross heating value in coals that have a high moisture content such as brown coals or lignites as the main difference between the two values is the latent heat of evaporation of water The net heating value can be calculated from the standard laboratory-determined gross value based on factors such as the moisture sulphur and chlorine contents of the coal concerned An example of a conversion formula which relates gross and net heating value reads (ISO 1928)
Qn = Qg - 0212 H - 00008 0 - 00245 M MJkg
26
Coal specifications
1989)
Tendenciesvalues
Low Medium Iligh Severe
gt1302 (2375) 1399-1149 (2550-2100) 1246-1121 (2275-2050) lt1204 (2200)
Viscosity proportional to silica ratio
lt05 05-10 10-175
lt06 06-20 20-26 gt26
lt031 or gt300 031-30 Low ~ High
gt1343 (2450) 1232-1343 (2250-2450) 1149-1232 (2100-2250) lt1149 (2100)
05-099 10-199 gt200
lt20 20-60 60-80 gt80 lt05 05-10 10-25 gt25 lt02 02-05 05-10 gt10 lt01 01-024 025-07 gt07
lt03 03-04 04-05 gt05
lt03 03-05 gt05
lt1000 1000-5000 5000-16000 gt16000
where Qn = net heating value Qg = gross heating value H = hydrogen (percentage fuel weight) 0 = oxygen content (percentage fuel weight) M = moisture content (percentage fuel weight)
In North America boiler thennal efficiency is usually quoted on the basis of the gross heating value whereas most European countries use net heating value
Various fonnulae for predicting the heating value of coal from ultimate analysis have been developed On a dry mineral matter-free basis the heating value relates directly to the composition of the coal substance Some of these fonnulae are reviewed by Mason and Gandhi (1980) and Raask (1985)
Petrographic analysis of coals is increasingly being used to add to the information necessary to assess the suitability of coal for combustion in a particular power station Coal petrology describes coal in tenns of its maceral and mineral matter composition (see Table 7) These components can be recognised and measured quantitatively with the aid of a microscope A comprehensive review of the features that
characterise the various members of the maceral groups and rules for their microscopic identification can be found in the Intemational Handbook of Coal Petrography (ICCP 1963 1975 1985) Stach and others (1982) gives an overview of the macerals and their physical and chemical properties and Teichmiiller (1982) Given (1984) Davis (1984) Falcon and Snyman (1986) and Carpenter (1988) provide a good description of the origin of macerals
Maceral composition can be linked to properties of significance for describing combustion perfonnance Relatively little attention has been given to assessing maceral effects on grindability The literature that is available provides a confusing and somewhat contradictory picture This could be a consequence of the relative grindabilities of vitrinite and inertinite reversing as the rank of coal increases (Unsworth and others 1991) The preferential population of macerals within particular size ranges has been reported by several investigators (Falcon and Snyman 1986 Skorupska and Marsh 1989) For example an investigation involving a medium rank bituminous coal revealed a difference between the grindability of vitrinite and inertinite of approximately 15 units with inertinite displaying a HGI value averaging
27
Coal specifications
55 Such differences can significantly influence mill throughput (Unsworth and others 1991)
In certain circumstances it has been reported that a petrographic assessment of coal rank has advantages over the other techniques used as standards (Neavel 1981 Unsworth and others 1991) Parameters such as volatile matter content fixed carbon heating value swelling indices are average properties of a coal sample As such they reflect coal rank but they are also affected by variations in maceral composition Measurement of vitrinite reflectance is widely used as an index of coal rank
Earlier investigators recognised that the carbonaceous materials present in fly ash were predominantly forms of inertinite (Yavorskii and others 1968 Nandi and others 1977 Kautz 1982) Since that time the influence of maceral composition on coal reactivity during combustion has been the subject of considerable study (Jones and others 1985 Falcon and Falcon 1987 Oka and others 1987 Shibaoka and others 1987 Bend 1989 Diessel and Bailey 1989 Skorupska and Marsh 1989 Sanyal and others 1991) It has now been applied in many cases to explain problems that occur during combustion when other traditional tests such as proximate analysis have failed (Sanyal and others 1991)
The application of petrographic assessment as a predictive tool is still believed to be some way off Two reasons for this are
the subjective identification and different criteria being applied by the different countries to distinguish macerals has led to unsatisfactory reproducibility in results This has been illustrated in international exchange exercises conducted by the ICCP in the past It has been clear for some time that there is a need to reduce subjectivity to a minimum This may be achieved by using automated assessment techniques limited validation on a power station boiler scale of the influence of macerals on boiler performance Present operational procedure at boiler scale does not lend itself well to simultaneously monitor performance and allow for full petrographic assessment of the feedstock coal
26 Calculated indices In an effort to extend the use of laboratory results a number of empirical indices have been developed based on the
measurements discussed in the previous subsections These indices have been used to relate coal composition to the performance of power station components While the indices are not measurements as such in many cases they are utilised in the same manner as coal properties The accuracy reproducibility and applicability of these indices depend directly on the specific measurement procedures employed Indices have been developed for
rank reactivity ash descriptor ash viscosity slagging propensity fouling propensity
Rank relationships with coal properties as used nationally and internationally are summarised earlier in Figure 2
Some combustion reactivity indices use a relationship of the proximate volatile matter and fixed carbon of a coal known as the fuel ratio lllustrations of the relationship are given in Section 421
The indices used to describe ash behaviour are summarised in Table 8 The indices can be included in coal specification sheets to help assess the suitability of a coal for combustion How they are used and their relationship to performance are discussed in Section 422 of this report
27 Comments Most coal evaluation testing for combustion relies on empirical procedures which were developed primarily for the carbonisation industry town gas and blast furnace coke manufacture using simple laboratory equipment under conditions which were intended to represent those found in that type of process Despite the shortcomings the techniques required to perform the tests such as for proximate analysis are so simple that they lend themselves to automation This removes much of the risk of operator error and produces repeatable results
As operating requirements become more stringent the weaknesses of some of these techniques are becoming increasingly apparent There is a growing need to develop tests and specifications which reflect more closely the conditions found in power station boilers
28
3
steam generator
burners
mills
environmental control
I
Pre-combustion performance
environmental controlcoal handling
and storage
ash transport fans
The following three chapters describe the effect of coal quality parameters on the performance of various component parts of coal-frred steam generator systems Figure 5 illustrates the components of a typical power station The main power station components include
coal handling and storage mills fans burners boiler ash transport technologies for controlling emissions
This chapter focuses on effects of coal quality on the pre-combustion components of a power station
31 Coal handling and storage The coal handling equipment includes all components which process coal from its delivery on site to the mills This includes a large amount of equipment which (depending on power station design) may include unloading facilities hoppers screens conveyors outside storage bulldozers reclaimers bunkers etc and of course the coal feeders to the mills (Folsom and others 1986b) A high level of automation and remote control is often incorporated in
Figure 5 Typical power station components
29
Pre-combustion performance
Table 9 Illustrative example of USA coal storage requirements (Folsom amp others 1986b)
Coal
Lignite Subbituminous Bituminous
midwest eastern
Heat to turbine 106 kJh 4591 4591 4591 4591 Boiler efficiency 835 862 885 905 Coal heat input 106 kJh 5499 5326 5185 5073 Coal HHV MJkg 14135 19771 26284 33285 Coal flowrate th 429 297 217 168
Design storage requirements t Bunkers 12 hours 5148 3564 2604 2016 Live 10 days 102960 71280 52080 40320 Dead 90 days 926640 641520 468720 362880
Storage time for eastern bituminous plant design t Bunkers hours 47 68 93 120 Live days 39 57 77 100 Dead days 35 51 69 902
equivalent storage time for a plant designed for eastern bituminous coal but fired with the coals listed
modern coal handling facilities including sophisticated stacking-out and reclaim facilities to achieve some degree of coal blending capability Slot bunker systems with bulldozer operated stacking and reclaimers are still preferred by many utilities because of capital cost savings and greater flexibility of stockpile management
Coal storage can be divided into two categories according to the purpose live (active) storage with short residence time which supplies fIring equipment directly and dead or reserve storage which may remain undisturbed for many months to guard against delays in shipments etc Live storage is usually under cover and reserve storage outdoors
When outdoor storage serves only as a reserve the normal practice is to take part of an incoming shipment and transfer it directly to live storage within the station while diverting the remainder to the outdoor pile
The coal storage components are generally sized to provide capacity equivalent to a fIxed time period of fIring at full load (McCartney and others 1990) Typical values are 12 hours for inplant storage in bunkers ten days for live storage and more than 90 days for reserve storage Capacity of the reserve pile can be for example a minimum 60-day supply at 75 of the maximum burn rate These time periods are specifIed by the architectengineer based on the utilitys desired operating procedures and other constraints such as political legislation for strategic stocking The key parameters for assessing the quantity of coal required are
power station capacity heat rate coal heating value
Steam generators of a given capacity operating at steady load
require a fIxed heat input per unit of time regardless of coal heating value (Carmichael 1987) Therefore if the actual heating value of the coal is reduced then the storage capacity and quantities that must be delivered to the utility via the transport system must be increased For example Folsom and others (l986b) compared the storage requirements for four coals of differing rank supplying a 500 MW steam-electric unit (see Table 9) For all performance parameters to remain constant over a wide range of coal heating values substantial variations in coal flow rate at full load are required with factors of as much as 21 in some cases The coal storage requirements for specifIc time periods reflect this same range of variation Also shown are the storage times required for fIring alternate coals in a unit designed to fIre a high heating value fuel an Eastern USA bituminous coal These changes may not affect the ability to operate the unit at high capacity for short time periods However the equipment which transports the coal may need to operate more frequently and this could limit the ability to fIre at full station capacity over an extended period Also normal power station operating procedures may need to be modifIed to permit fIlling the bunkers more than once per day etc
Most of the equipment which transports the coal operates intermittently Thus coal quality changes which result in coal flow rate changes will vary the duty cycle for the transport equipment An increase in flow rate requirements caused by a decrease in coal heating value or an increase in boiler heat rate will increase the duty cycle and may affect unit capacity Provided that these changes in flow rate are small or of limited duration most power stations will be able to tolerate them with no equipment modifIcations Large increases in flow rate for example those that may occur due to a shift from a bituminous coal to a lignite as described in Table 9 may require such long duty cycles that the normal operating procedures of the power stations and maintenance intervals
30
Pre-combustion performance
Table 10 Conveyor Equipment Manufacturers Association (CEMA) material classification chart (Colijn 1988a)
Major class Material characteristics included Code designation
Density
Size
Flowability
Abrasiveness
Miscellaneous properties or hazards
Bulk density loose
Very fine 200 mesh sieve (0075 mm) and under 100 mesh sieve (0150 mm) and under 40 mesh sieve (0406 mm) and under
Fine 6 mesh sieve (335 mm) and under
Granular 127 mm and under
Lumpy 76 mm and under 178 mm and under 406 mm and under
Irregular stringy fibrous cylindrical slabs etc
Very free flowing - flow functiongt 10 Free flowing - flow function gt4 but lt10 Average flowability - flow function gt2 but lt4 Sluggish - flow function lt2
Mildly abrasive - Index 1 - 17 Moderately abrasive - Index 18 - 67 Extremely abrasive - Index 68 - 416
Builds up and hardens Generates static electricity Decomposes - deteriorates in storage Flammability Becomes plastic or tends to soften Very dusty Aerates and becomes fluid Explosiveness Stickiness - adhesion Contaminable affecting use Degradable affecting use Gives off harmful or toxic gas or fumes Highly corrosive Mildly corrosive Hygroscopic Interlocks mats of agglomerates Oils present Packs under pressure Very light and fluffy - may be windswept Elevated temperature
Actual kgcoal flow
Azoo AIOO
~
C~
E
1 2 3 4
5 6 7
F G H J K L M N o P Q R S T U V W X Y Z
may be inadequate In such extreme cases the capacity of the transfer equipment may be insufficient even with continuous operation such that modifications will be required In some power stations it may be possible to increase the capacity of the transport equipment For example conveyor belt speeds may be increased However this can also lead to dust problems and increased spillage especially with friable coal
Unlike the other coal transport equipment the coal feeders operate continuously Thus any change in coal flow rate requirements must be met with an immediate change in feeder speed Coal feeders are usually designed with excess capacity so that minor changes in coal flow rate requirements can be tolerated easily The major changes required by significant changes in coal heating value such as switching
from a bituminous coal to a lignite would be beyond the capacity of most coal feed systems Another factor to consider is the feeder turndown Many feeders have a minimum operating speed beneath which problems such as uneven flow can occur
In addition to changes in the required coal flow rates coal characteristics can produce other detrimental effects on handling and storage systems
In a survey carried out at a coal handleability workshop (Arnold 1988) attendees from utilities and the mining community were asked to rank the problems from one (1 - worst) to ten (10 -least) The ratings are indicated next to each problem
31
Pre-combustion performance
plugging in bins (1) feeders (2) arching and caving in storage (10) flowability hang-up in bins (3) sticky coal on belts (4) freezing in transport (5) storage (8) dusting on conveyors (6) in stockpiles (7) oxidationspontaneous combustion (9)
Other concerns mentioned included abrasiveness of coal causing chute wear wet fuel hang-up in transfer towers sticky fuel in downcomers spillage and sliding from belts due to wetness hang-up in breakers excessive surface moisture and coal sticking in bottom-dumped rail cars Whilst relationships between coal properties and handleability have been established these are not the same as those needed for combustion purposes In fact some coal specifications do not usually include parameters which reflect the handling and storage properties of coal Colijn (1988a) reported that the Conveyor Equipment Manufacturers Association (CEMA) have made an effort to establish a listing of material properties and characteristics which influence the handling and storage of granular bulk materials including coal as shown in Table 10 The coding system has been developed to describe particular material properties such as density size flowability and abrasiveness Where material handling characteristics are in general not easily quantifiable they are listed as hazards - watch out Table II shows typical CEMA codes for various coal
Table 11 CEMA codes for various coals (Calijn 1988a)
Material description CEMA material code
Coal anthracite (River amp Culm) 6OB635TY Coal anthracite sized - 127 mm 58C-225 Coal bituminous mined 50 m amp under 52A4035 Coal bituminous mined 50D335LNXY Coal bituminous mined sized 50D335QV Coal bituminous mined run-of-mine 50Dx35 Coal bituminous mined slack 47C-245T Coal bituminous stripping not cleaned 55Dx46 Coal lignite 43D335T Coal char 24Cl35Q
x refers to a range of particle sizes
311 Plugging and flowability
The economic impact of plugging of coal transport facilities can be significant resulting in added manpower costs for clearance partial unit deratings or in some cases total shutdowns For example at 15 $MWh a typical 575 MW unit could lose over 1000 $h income as a result of partial deratings for each plugged silo (Bennett and others 1988)
No flow or limited flow problems are often due to the formation of stable arches andor increases in wall friction (Arnold 1990) Binsilo blockages occur when the coal has become sufficiently adhesive to form a stable arch which supports the weight of the coal above it Increases in wall friction which is a measure of the sliding resistance of the coal against the bin wall will result in coal adjacent to the wall moving slower than that in the centre zone This gives
mass flow funnel flow expanded flow
Figure 6 Typical flow patterns in bunkers (Colijn 1988a)
rise to different flow patterns in various parts of the bin (see Figure 6) For most coals three to four days outdoor storage increases the chances of one or both of the above problems occurring Coal flowability is directly related to various coal characteristics depending on the coal rank Some of the major contributing properties are (Llewellyn 1991)
surface moisture particle size distribution clay content changes in bulk density
Surface moisture is considered the most critical factor There is a level below which regardless of other factors coal flow problems do not occur There is also a critical surface moisture at which maximum adhesion and bulk coal strength will occur Above this level additional water flows away rises to the surface or in the extreme decreases strength due to slurry formation Adding moisture to dry coal first creates a lubricating effect and allows particles to slide against each other more easily and pack into a denser stronger material Surface tension develops as a form of physico-chemical bonding (known as hydrogen bonding) increases between water and coal particles
Particle size distribution contributes to flowability problems because it determines the available surface area and hence adhesion characteristics The proportion and size of the smallest particles in bulk coal have a great effect on its handleability In some coals the ash and clay content which is inherent in the coal concentrates in the fines fraction (see Table 12) This also influences coal flowability characteristics Average particle size can be affected by coal handling procedures and equipment or by natural causes A major factor influencing the size composition of a coal product is its friability Friability is a combination of the impact strength and fracture cleavage characteristics of the coal and its susceptibility to degradation due to a rubbing action during handling A high fines content if combined with a critical moisture level can result in a coal with very poor handling properties (Llewellyn 1991) In low rank coals large pieces may fall apart and produce excess fines in dry air If the coal is subsequently rewetted the combination
32
Pre-combustion performance
Table 12 Analysis of ash and clay distribution in a coal by mesh size (Bennett and others 1988)
Property Base fuel +6 Mesh (+335 mm)
6-50 Mesh (036-030 mm)
50-100 Mesh (030-015 mm)
-100 Mesh (-015 mm)
Weight Ash (Dry) Silica
10000 2277 6740
4514 1702 5850
4512 2320 6490
765 3596 7790
209 4153 8380
of increased surface area and moisture can have a substantial impact on flow characteristics
The clay content of coal affects its cohesive characteristics Increased clay content in strip mined subbituminous coal and lignites has been shown significantly to increase wall friction and shear strength at a given moisture content (Bennett and others 1988)
If all of the above factors increase simultaneously that is high surface moisture high clay high fmes percentage and coal is stored in a bin for several days drastic increases in coal bulk shear strength lead to significant adhesion bridging and consequent coal flowability problems
There are no coal specifications which relate to coal bulk shear strength although tests have been developed which provide bulk shear strength values for coals They are used as a measure of the cohesive strength or stickiness and have been used as a quantifying factor for problem coals Shear strength can be measured using either a rotational or a linear translational instrument Results from the rotational shear test can be obtained within an hour and may be used on-site to provide real time analyses (Bennett and others 1988 Colijn 1988a) The principle of the rotational shear tester is to provide an equally distributed shearing force across a horizontal plane in the coal sample This is done while the sample is placed under varied loads The bulk shear strength determined for a particular fuel handling situation can be represented as a value in applied pressure or as an arbitrary relative flow factor value (FFV) The FFV can be plotted relative to moisture and clay values A critical arching diameter (CAD) can be extracted by combining results from a shear tester with the bulk density of the coal Calculations can then be made for the geometric configuration of each type of coal container for particular types of coal thus negating possible problems of archingplugging in a binsilo Figure 7 shows the data derived from shear tests for more than twenty coals conducted by Colijn (1988b) The CAD was plotted against the surface moisture content for the coals and while a clear relationship between increasing moisture content and increasing CAD exists there is significant data scatter As discussed earlier other investigators (Blondin and others 1988 Arnold 1991) have shown that the amount of clay and fines also influence the CAD
As many coals have a tendency to increase their strength after a few days of consolidation it is often necessary to test the coals under these conditions For these cases a coal sample would be kept inside the shear cell under pressure for a number of days to simulate the time period during which the coal may be contained within a bin or silo Arnold (1991) reported a study conducted to define further the relationship
mass flow - instantaneous
2 E ~
til Q) E til 0 0) c
c ()
ro (ij ()
8
0
0
Figure 7
3 E
~ Q) E til 2 0 0)
~ c ()
ro (ij ()
8
0
0 0 0
o
0
6 o 00 oo0
o D cPo DO
0 CI o~ 0_o
--tJ 0 0 0 _ - shy
9 - Data for a variety of coal samples
2 4 6 8 10 12 14 16
Surface moisture
Surface moisture versus critical arching diameter (CAD) determined from shear tests (Coljjn 1988b)
3-day consolidation
10 moisture
+ 8 moisture
6 moisture
+ +
0
0 2 4 6 8 10 12 14
Fines -44 ~m (-325 mesh)
Figure 8 Three-day consolidation critical arching diameter (CAD) versus per cent fines in coal as a function of moisture content (Arnold 1991)
of coals and their handling behaviour Six coals that were combusted at an Eastern USA power station were selected The coals had very similar chemical analyses and all met the power station coal specification but exhibited a range of handling characteristics As an illustration of some of the preliminary results of the study Figure 8 shows the influence of the percentage fines (particles less than 44 lm in diameter) moisture content and consolidation time on the CAD calculated from shear tests conducted on one of the coals The instantaneous CAD values are not shown in Figure 8 but were in fact 30 lower in value than the three-day consolidation values Generally for all the coals studied the maximum value occurred at the highest moisture
33
Pre-combustion performance
contents and there was a tendency to increase with increasing fines content and increases in consolidation time
More recently Rittenhouse (1992) reported the development of a series of simplified empirical tests that can be run by power station staff members that make it possible to identify potential problem coals The results of the tests are indices that characterise the flowability of coal The individual indices are
arching index ratholing index hopper index chute index flow rate index density index
These can also be used to indicate when hopper modifications may extend the operating range of the system so that coals that are less than free flowing can be handled The tests are reviewed in greater detail by Johanson (1989 1991) Arnold and OConnor (1992) have recently reported the development of another simplified test that can be used more easily on-site and has been validated against the tri-axial shear tester
Coal flowability can be modified by the use of chemicals which specifically enhance the flow of wet coal Additive selection and performance depend greatly on fuel quality (Bennett and others 1988) The effectiveness of particular additives on problem coals is assessed by measurement of shear strength values produced
312 Freezing
Although it is difficult to assess the cost related specifically to coal moisture freezing during cold weather some of the potential problems are as follows
production losses at the mine beneficiation plant and the utilities increased labour costs associated with frozen coal removal less safe working conditions costs related to operation of thawing and mechanical removal equipment transport equipment damage due to mechanical or thermal means of removing frozen coal from ships rail cars or trucks demurrage costs on rail cars accelerated rail wear andor derailment
Work done in the mid-1970s showed that surface moisture of a coal caused the problems For freezing to occur the coal being handled must be exposed to sub-freezing temperatures for a sufficient period of time It is generally accepted however that no problems with handling should be expected unless the surface moisture exceeds approximately five per cent Total moisture content of the coal is inadequate as a sole indicator since coal that has a high inherent moisture may not freeze at 20 or more total moisture while coal with a low inherent moisture
may freeze and cause severe problems at seven per cent or below
Each coal type has a characteristic inherent moisture content defined here as the moisture contained in the fine pore structure itself Depending upon rank porosity and hydrophilicity of the coal inherent moisture ranges from less than one per cent to greater than 20 of the coal mass While surface moisture is undoubtedly the primary cause of coal freezing and the consequent handling problems other factors also influence the situation For example Connelly (1988) reported that at lower temperatures the increased viscosity of water renders the dewatering of coal processes less efficient Total moisture content of dewatered coals can be expected to increase at lower temperatures as shown in Figure 9
90
86 bull
t-O)
s 82 bull
iiimiddot0 E 78
Cii l 0V 0)
cr 74
72 bull
66
4 10 20 30 40 50 Temperature degC
Figure 9 Dewatering efficiency versus temperature (Connelly 1988)
Particle size is also important If the coal particle size were consistently large that is 127 cm (h inch) or larger it would be unlikely that the particles would pack together sufficiently to freeze and cause a serious problem Current mining methods use continuous longwall techniques to extract coal with consequent breakage and fines production For this reason it is impractical for beneficiation plants to furnish a product with a minimum particle size of 127 cm or greater for all shipments unless some form of agglomeration process is used Typically coal being shipped contains a wide range particle size distribution and a substantial amount of material less than 016 cm in diameter Because of this particle size distribution the fine particles of coal can pack between the larger ones and form a more continuous solid mass The finer particle size coal also tends to hold a larger percentage of surface moisture With the finer particle size and increased surface water more particle-to-particle contact occurs accentuating the freezing problems
The freezing process can be offset by the use of additives such as urea calcium chloride solution or polyhydroxy alcohols (Hewing and Harvey 1981 Boley 1984 Connelly 1988)
34
Pre-combustion performance
313 Dusting
Most bulk solid materials have the potential to generate dust during handling Dust can be generated while the coal is in motion such as during transfer from transport to storage and even as wind borne dust from stockpiles This creates safety as well as environmental problems The extent of dust problems may be related empirically to particle size distribution (the amount of fines) moisture content moisture holding capacity and the wind speed (Mikula and Parsons 1991) Nicol and Smitham (1990) reported that in the case of Australian export coals they are sold with a nominal top size of 5 cm but as was discussed earlier there is a wide range of size distributions covered by this specification Figure 10 shows the broad range of coal sizes that are exported This implies that the potential dustiness of coal is a variable with coal source Sherman and Pilcher (1938) have done considerable work in the area of dust control and have tested the size of dust particles in the ASTM D547 dust cabinet test and found that the diameters of particles range from 11 to 55 11m Devised in the 1930s the test is perceived to be somewhat dated as it was originally designed to simulate coal delivery into a bin
Nicol and Smitham (1990) investigated the effects of moisture on the lift-off potential of different coals over a range of wind velocities using a laboratory wind tunnel facility They found that depending on the coal size fraction the velocity to remove wet particles was between 25 and 75 greater than the dry particle removal velocity Alternatively the amount of coal removed at a given velocity is reduced as the moisture content increases Figure 11
99
80
E 60 -E 7 40
if ro 0
20 0
N middotw 10 m 0 c 5J
shaded area encompasses 90 of export coals with coarsest (lower) and finest (upper) size disributions also shown
0125 025 05 2 4 8 16 315 63 Particle Size mm
Figure 10 Size distributions of Australian export coal (Nicol and Smitham 1990)
illustrates the effect and shows that a critical moisture content of about 9 in the coal can be reached at which coal removal can be largely prevented The effects of different coals show up most clearly in the moisture content to prevent any dust emission that is the intercept on the moisture axis in Figure 10 Table 13 summarises the results for the three coals of different properties Rank and chemical properties such as volatile matter content are poor indicators of the propensity for different coals to dust Porosity as reflected in the moisture holding capacity does provide a useful indicator of the potential dustiness of coal Coals with a low moisture holding capacity that is a low equilibrium moisture have little internal porosity so that once this internal volume is filled the excess water remains at the particle surface where it is available to form bridges of water between adjacent particles preventing their removal in an air stream High moisture capacity coals require a greater amount of water to fill the internal volume before water is available at the surface to be an effective dust control agent Jensen (1992)
2000
o
N
E Oi ui Cf)
g Cii 0 ()
Q) gt ~ S E J u
1500
1000
500
0
0
0 0
0 0
amp0
0 ~ 0
0 0
0
0
o 2 4 6 8 10 12
Total moisture
Figure 11 Coal lift-off from a stockpile as a function of total moisture content (Nicol and Smitham 1990)
Table 13 Effect of coal properties on critical lift-off moisture content (Nicol amp Smitham 1990)
Coal Critical moisture Reflectance Australian coal Moisture holding content Ro max rank nomenclature capacity
1 100 094 high volatile bituminous A 25 2 115 120 medium volatile bituminous 40 3 210 073 high volatile bituminous A 120
66
35
Pre-combustion performance
reported that work carried out by ELSAM Denmark has shown that coals with a sUlface nwisture content of 2-3 was sufficient to prevent dusting of some coals
314 Oxidationspontaneous combustion
All coals when stored tend to combine to some extent with oxygen from the air in a process known as weathering (Davidson 1990) This causes some loss of heating value generally less than 1 in the first year of storage for most coals but may be up to 3 for low rank coals - and can change firing characteristics (Singer 1989a) Weathering also tends to promote reduction in size or crumbling (Llewellyn 1991)
Llewellyn (1991) also reported that grindability tests carried out on both fresh coal supplies and the coal stored on the surface of a stockpile indicated a clear separation in behaviour Surface samples were reported as being significantly harder (average 43 HGI) to grind than the fresh coal supply samples (average 52 HGI) The hardness increased with the age of the stockpiled coal A similar clear separation was found between the surface and the interior of the stockpile
Oxidation releases heat and if conditions in the stockpile are such that it occurs at a sufficiently rapid rate enough heat can be generated to cause spontaneous combustion (Sebesta and Vodickova 1989)
In brief the coal properties that have been found to influence oxidation and spontaneous combustion are
rank (heating value or volatile matter) moisture content ash content particle size
Malhotra and Crelling (1987) reported that as the rank of coals decreases the susceptibility for spontaneous combustion increases Cacka and others (1989) suggested that this phenomenon may be related to the increasing content of aliphatic structures which have a higher propensity to react with oxygen than aromatic structures present in coal However there are many anomalies to this straight rank order susceptibility Chamberlain and Hall (1973) have in fact pointed out that some higher rank coals may be more susceptible to spontaneous combustion
The mechanism of water adsorption into the pores of coal also releases heat so that heating in a stockpile will be dependent to some extent upon the inherent moisture (Matsuura and Uchida 1988 Iskhakov 1990) In most cases excess moisture can suppress the heating process (Taraba 1989) although cases have been reported where addition of water to an overheating stockpile can exacerbate the problem and these have been discussed in greater detail in a review by Chen (1991)
The mineral matter composition of coals can influence their susceptibility to oxidation Dusak (1986) reported incidents where mineral matter can play the role of oxidation
promoters by increasing oxidation rate and heat emission due possibly to exothermic reactions of the mineral matter itself with oxygen Work by Cacka and others (1989) determined that iron and titanium were particularly active in the coals under investigation Nemec and Dobal (1988) reported the influence of pyritic sulphur The magnitude of the influence on the oxidation process depends upon mineral matter size and its dissemination within the coal along with the rank moisture content and size of the coal
Particle size influences the surface area available for oxidation Several workers have reported that the smaller the particle size the greater the heat build up within coal stockpiles (Brooks and Glasser 1986 Nemec and Dobal 1988 Llewellyn 1991)
A number of tests have been devised to assess the extent of oxidation of a coal and its susceptibility to spontaneous combustion These include
crossing point test This measures the ignition temperature of a coal sample when it is heated at a constant temperature rate in a small cylindrical furnace The ignition temperature is measured as that at which the coal temperature crosses or becomes greater than the furnace temperature (Brown 1985) This can also be known as the runaway temperature (Gibb 1992) Differential thermal gravimetric analysers and calorimeters are also used to carry out a similar form of test (Clemens and others 1990 Shonhardt 1990) free swelling index test (see also Section 25) Shimada and others (1991) used free swelling index to monitor the extent of weathering of coals in a stockpile The swelling index of a Polish coal (K11) was seen to decrease significantly after a short storage time of three months (see Figure 12) It could also be used to distinguish between coal samples taken from the body (K11) of the coal stockpile and those from the slope (K11 slope) The test can only be applied to coals that exhibit a high initial swelling index as some coals with low initial swelling index (such as Kl in Figure 12) do not give any perceptible change after storage spectroscopic techniques Berkowitz (1989) has reviewed the spectroscopic methods utilised to detect oxidation of coal These can include Fourier transform shyinfra red (FTIR) spectroscopy electron spin resonance (ESR) nuclear magnetic resonance (NMR) and fluorescence microscopy (pavlikova and others 1989 Bend 1989)
Most of the above tests are not standardised With the exception of FSI which is generally used as an indicator of the caking nature of coals they usually are not included in a typical coal specification
At present none of the above effects can be quantified accurately The overall impact on operation and any required modifications must be based primarily on experience The influence of coal quality on the spontaneous combustion of the coal can be minimised by careful layout and construction of the stockpiles
36
Pre-combustion performance
bull 6
--- K1
0 K11
x L K11 slope 5 0
(]) 0 4 0 ~
0OJ sect 3CD ~ 0
(f)
2
L ~ - - - - - - - - - - - - 1f - - - - - - - - - - -- - - - - - shy II I
o 3 5 7 9 11 13 15 17 30 40 50 60 70
Storage time months
Figure 12 Influence of storage time on swelling index (Shimada and others 1991)
The special requirements for low rank coal storage are reviewed in an lEA Coal Research report entitled Power generation from lignite (Couch 1989)
32 Mills Most large steam-electric units are direct fIred that is the coal is supplied to the mills and is pulverised continuously with direct pneumatic transport of the pulverised coaVair mixture to the burners Thus the performance of the mills has a direct effect on the performance of the unit In modern practice a single mill can supply several burners In tangentially fIred systems all four bumers on a single elevation are typically supplied by a single mill In wall fIred systems a single mill may supply a complete row or another symmetrical array of burners A common design practice is to size systems to achieve full load with one or more mills out of service This allows time for maintenance and allows the spare mill to be brought on-line in the event that a failure occurs in one of the other mills
Because of their heterogeneous nature coals used for combustion can exhibit a wide range of grindabilities and require different milling actions to produce a suitably sized product Fine grinding of coal - generally 70 or more passing 75 11m (200 mesh) - is the standard commonly adopted to assure complete combustion of coal particles and to minimise deposits of ash and carbon on heat absorbing surfaces (Carmichael 1987) The different mill designs can be classified according to speed
low-speed mills are of the balVtube design with a large rotating steel cylinder and a charge of hardened balls Coal grinding occurs as the coal is crushed and abraded between the balls medium-speed mills are typically vertical spindle designs and grind the coal between rollers or balls and a bowl or face There are a number of designs in service differing in the specific design of the equipment which rotates size and shape of the grinding elements etc high-speed mills have a high-speed rotor which impacts and breaks the coal
Table 14 Preferred range of coal properties (Sligar 1985)
Mill type Low speed
Maximum capacity tJh 100 Turndown 41 Coalfeed top size mm 25 Coal moisture 0-10 Coal mineral matter 1-50 Coal quartz content 0-10 Coal fibre content 0-1 Hardgrove grindability
Medium High speed speed
100 30 41 51 35 32 0-20 0-15 1-30 1-15 0-3 0-1 0-10 (0-15)
index 30-5080 40-60 60-100 Coal reactivity low medium medium
The range of properties listed above is a preferred range and operation outside these limits is possible
Numerical values for the preferred range of coal properties appropriate for each mill type are given in Table 14 Most large steam-electric units use balVtube or vertical spindle mills
Coal mills integrate four separate processes all of which can be influenced by coal characteristics
drying grinding classifIcation transport
321 Drying
Earlier mills used external dryers before the coal was fed to the mills placing an economic disadvantage on the system Internal drying was developed to overcome this The surface moisture of the coal must be evaporated in the mill to avoid agglomeration of the particles (Sadowski and Hunt 1978) As the primary air is used for conveying the coal the only variable for drying is the temperature of this air The primary air temperature is adjusted to achieve a mill discharge temperature high enough to ensure complete drying in the
37
Pre-combustion performance
Table 15 Maximum mill outlet temperatures for vertical spindle mills (Babcock amp Wilcox 1978 Singer 1991)
Maximum temperature degC (OF)
Coal Babcock amp Wilcox Combustion Engineering
High volatile 66 (150) 71-77 (160-170) bituminous
Low volatile 66-79 (150-175) 82 (180) bituminous
Lignite 49-60 (120-140) 43-60 (110-140)
grinding zone For example Table 15 lists the maximum mill discharge temperatures recommended by Babcock amp Wilcox and Combustion Engineering The discharge temperatures are fixed for safety reasons and are dependent on coal type For bituminous coals the value is usually between 65degC and 90degC with the lower value for fuels of high volatility to reduce the potential for mill fires Higher temperatures of over 100degC have been reported to be used in some cases (Jones and others 1992) Standard proximate analysis volatile matter tests have been used to provide some indication of the likelihood of spontaneous combustion High volatile matter coals are more reactive and more susceptible to spontaneous combustion under these conditions
The primary air temperature required to dry the coal depends on several factors including its moisture (or ice) content temperature and specific heat together with airfuel ratio and mill design The required air temperature may be calculated via a simple energy balance (Folsom and others 1986b)
Figure 13 shows the effect of coal moisture on primary air temperature requirements for vertical spindle mills manufactured by Babcock amp Wilcox and Combustion Engineering As the moisture content of the coal increases so the inlet air temperature must increase to compensate Increases in the coal moisture content can impact unit capacity if the primary air supply system cannot provide air at a high enough temperature It should be noted that to
provide more heat to the drying process the aircoal ratio can be increased However the aircoal ratio affects classifier performance and other downstream operations such as burner performance pulverised coal transport and wear in the coal supply system These effects must be considered Increasing the air temperature increases the potential for mill fires since dry coal particles especially those recycled from the classifier may come into contact with the high temperature air entering the mill
Low-speed mills are most sensitive to coal surface moisture content The capacity of these mills falls in an approximately linear manner with increase in moisture content The decrease in mill capacity is of the order of 3 for each 1 increase in coal surface moisture This effect is present because of the use of a lower airfuel ratio with these mills lower primary air temperature and less efficient mixing within the mill body Medium- and high-speed mills are not nearly as sensitive to high moisture coal
322 Grinding
The size consistency of the coal feed has a direct effect on the power requirements of the mill (see Section 632) All three types of mill are affected by coal feed top size Table 14 gives the critical feed top size for all three types of mill Low-speed mills are particularly sensitive to coal top size Mill capacity falls in a regular manner with increase in coal feed top size In addition to the top size the overall particle size distribution is also of significance In all cases the presence of excessive proportions of fines in the feed to the mill acts to the detriment of the full output
The fineness required is usually related to the rank of a coal the higher the rank of the coal the fmer the particle size distribution needed to achieve satisfactory combustion that is an increase in fmeness with decreasing volatile matter content The approximate size ranges which are acceptable for coals of different rank to ensure complete combustion are shown in Table 16 Analysis of the combustion process shows that burnout is a function of the proportion of particles over 100 1JlIl rather than the amount less than 75 -Lm It is to be expected that increasing the 200 IJlIl oversize from 1 to
Table 16 Comparison of fineness recommendations ( passing 200 mesh -75 11m) (Babcock amp Wilcox 1978 Cortsen 1983)
Babcock amp Wilcox specification ASTM classification of coals by rank
Fixed carbon Fixed carbon below 69
Type of furnace 979-86 (petroleum coke)
859-78 779-69 BtuI1b gt13000 (gt303 MJkg)
BtuI1b 12900-11 000 (300-256 MJkg)
BtuI1b lt11 000 (lt256 MJkg)
Water-cooled 80 75 70 70 65 60
ELSAM Denmark specification
Volatile matter content dry ash-free () lt10 10-20 20-25 gt25
Water-cooled 85 80 75 70
38
Pre-combustion performance
Eastern USA coals (Combustion Engineering)
80a C leaving mixture temperature
H 2 0 entering-leaving
300 14-20
o 12-20 a
10-20
8-20
6-15
4-15
2-10
Babcock amp Wilcox
3000 a
(i100 CIl ~
gt 3
3 4 5 Cl
9 (1)kg of air leaving millkg of coal a 200 lt1l Cii Cl E
Midwestern USA coals (Combustion Engineering) 2 ill
nac leaving mixture temperature ~
laquo 100
JI 24-70 entering-leaving
22-65
26-75 H 0
~ 2
20-60
18-60300 shy16-55
o 2 4 6 8 1014-50 12-50 kg of coalkg of air
10-45 8-40
6-40
100
2
~
OJshysect
pound 0 ~
ES
2 3 4 5
kg of air leaving millkg of coal
Figure 13 Primary air temperature requirements depending on moisture content and coal type (Babcock amp Wilcox 1978 Singer 1991)
39
ie curve is unreliable in this area
60 lt75 ~m
lt75~m
lt75~m
90 lt75 ~m----shy
25 50 75 100
Pre-combustion performance
2 would have a much more significant increase on bumout than decreasing the under 75 lm from 70 to 65 Oversize particles are believed to contribute to slagging problems in boilers although there are no adequate correlations to relate particle size distribution to the incidence of slagging (Babcock amp Wilcox 1978 Singer 1991) The use of low NOx combustion strategies has required a policy of finer grinding for some coals in order to offset the increased unbumt carbon found in the fly ash (Heitmiiller and Schuster 1991)
The ease by which a coal can be ground within a particular type of apparatus is termed its grindability The most common measurement is the Hardgrove grindability index (HGI) (see Section 25) The HGI is widely accepted as the industry standard for evaluating the effects of coal quality on mill performance for high rank coals (Babcock amp Wilcox 1978 Singer 1991) The rated capacity of a mill is defined as the amount of coal (tlh) that can be ground to a fineness of 70 through a 75 lm sieve using a coal with HGI of 50 or 55 Mill manufacturers tend to be divided on how mill capacity is determined for a particular coal Some provide correlations relating the HGI of the coal to mill output for each standard mill size Other manufacturers depend on assessments made in proprietary small test mills or full size mill tests with large samples to give more confidence to anticipated performance of mills with the specification coal(s) With the multitude of mill designs available there is no reason to expect that the capacity of each type should be related to HGI according to any universal relationship
The Hardgrove test is limited in its application as it is a batch operation which is then related to a continuous process Mills
are air swept so that as comminution proceeds fine particles are quickly removed from the grinding elements whereas they remain in the grinding zone in the Hardgrove machine (Hardgrove 1938)
Values of HGI for coal lie in the range 25-11 O Within the range of 42-65 HGI is probably a good indicator of grindability providing the other properties (moisture specific energy etc) are considered Outside this range confidence in HGI is not so good (see Figure 14) Many attempts have been made to correlate HGI with coal composition (Singer 1991) but whilst there is a general trend with coal rank as seen in Figure 15 the scatter is enormous For example the HGI for high volatile bituminous A coals range from 30 to 75 a factor of 25 The scatter could be accounted for by the distribution of macerals in the coal (Fortune 1990) The milling properties of the different maceral types can give rise to segregation of macerals within particular size ranges For example vitrinite tends to be more brittle than exinite or inertinite and is usually concentrated in the finer fraction of the milled coal (Falcon and Falcon 1987 Conroy 1991) In addition vitrinite and exinite are more reactive than inertinite so that a greater concentration of inertinite will generally be found in the unbumt fuel than in the parent coal Inertinite also tends to concentrate in the larger particle size ranges where its lower reactivity has a noticeable effect on bumout It should be noted that this will depend on the different forms of inertinite as some types are more reactive than others (Bailey and others 1990) These observations are dependent greatly on maceral distribution within the coal Macerals in some coals occur in discrete layers whereas in others (for example South African coals) they can occur as intimate associations (Falcon and Ham 1988) The distribution as
20
16
ist5 12 2 2shy0 ro g- 08 ()
04
o
curves extrapolated to zero capacity usefull range for
(HGI =13) curves
range in which bituminous coals are found
Hardgrove grindability index (HGI)
Figure 14 Variation in capacity factor with HGI for different fineness grinds (Fortune 1990)
40
Pre-combustion performance
o
o o
bull Ball mill indexes
Hardgrove tests converted to equivalent Ball mill indexes
bull bull 0
ltlOl 0
etgtz l 2 2
100 - o o o
90
o80
a 70S xOl U ~ 60 pound 0 ro 50 U sect 01 Ol 40 gt e -e01 bull ro 30 I U 0 m
en enJ J Jroen middot0 middot020 Olen Olen ~ 0 0 degoJ _J _J ro ro c c 0 oen len~ gt 0 0 J c cmiddotE middotE EJ~ roc roc gtJ
C middot02 CEo
3 omiddotE omiddotE o~ ro10 3 0 _
Eg cp ro eO2 ~~~ gtJ gtJ middot~middotE gtEmiddotc 0 0 J c~ middotE c
0 0 uJ 3J Q)ouo 010 010 Ol- C01 J J Jc 0middot Ol =i Cf) Cf) Cf)roU Im Iltl ~o -10 Cf) ltl ~
0 9 10 11 12 13 14 15 16 70 80 90 100
Moist mineral-matter-free MJ Dry mineral-maller-free fixed carbon
Figure 15 HGI for several coals as a function of rank (Elliott 1981)
described will effect the particle composition and other coal to 77 and mainly in the 60 to 70 range In general such coals physical properties These effects cannot be predicted from would not be expected to cause difficulty with grinding proximate analysis and so could account for discrepancies in the anticipated performance of coals having similar The abrasive properties of a coal and especially its associated proximate analysis values but with different petrographic minerals cause wear of the grinding elements and other compositions surfaces in the mill The extent of this wear determines the
intervals between planned maintenance periods and the Grinding of coal blends in which the components have possibility of shutdowns It is therefore of great importance widely different HGI values have shown that care is required for an operator to have an idea of how long these periods are in the interpretation of the results Byrne and Juniper (1987) likely to be and how unplanned outages caused by excessive observed that in such cases the harder material tended to mill wear can be avoided concentrate in the coarser fractions of the pulverised fuel and the softer coal in the finer fractions It was believed that this Wear is caused by one of four mechanisms (Fortune 1990) was a consequence of the softer coal blanketing the harder coal and so preventing full grinding of all the fuel adhesion
surface fatigue One difficulty with HGI is reproducibility BS ISO and AS1M abrasion standards all state that a spread of three units is acceptable This corrosion is equivalent to a 4 change in mill capacity Comparisons from different laboratories have given a reproducibility of Adhesion and surface fatigue effects in milling are negligible around eight to nine (Fortune 1990) This is equivalent to a mill compared with abrasion and corrosion capacity variation spread of 12 which is clearly unacceptable as an indication of grinding performance The rate of abrasive wear in mills will depend in general on
the following factors Attempts have been made to develop alternative grindability indices but so far none of these has attained widespread use the type of coal used especially the amount and Typical of these is the continuous grindability index (CGI) composition of the incombustible minerals associated which relates mill performance to power input It was with the coal developed for low rank coal applications A new method has the material used for the mill rolls and bowls also been proposed for determining coal grindability and the design of the mill abrasivity properties using a single machine by Scieszka (1985) although it should be noted that this work was based The most widely used abrasion test is the Yancey Geer and on a limited range of coals with HGI values ranging from 39 Price (YGP) test (Yancey and others 1951) although its
41
Pre-combustion performance
repeatability varies with coal characteristics For abrasive coals the repeatability is about 3 However for coals with low abrasiveness repeatability may be as low as 18 Babcock Energy Scotland use a similar test but with a smaller coal sample (Cortsen 1983) Babcock amp Wilcox in the USA has developed an abrasion test using a radioactive tracer technique (Goddard and Duzy 1967) This test produces a measurement of mill wear albeit at a laboratory scale
Literature data indicate that coal itself is not very abrasive (Parish 1970) Of the associated minerals usually present in coal only quartz (SiOz) and pyrite (FeSz) are considered to be hard enough to cause significant wear Other minerals mainly clays are generally quite soft and friable and do not contribute much to mill wear The earlier studies have shown some correlation between wear and quartz or pyrite content of the coal but the correlations obtained were generally not widely applicable (Parish 1970) In investigations carried out by Donais and others (1988) it was found that as well as the total amount the size of the quartz and pyrite grains significantly affected the wear rate The study was carried out on eight different US coals using NIHARD rolls in both Babcock amp Wilcox and Combustion Engineering mills In general the data indicated that the coarser fractions of quartz and pyrite contribute more to mill wear than the finer size fractions The best correlation between the data was as described in the following expression
Abrasion (radial wear per tons of throughput) =F (3 Q+ P)
where F = constant
Q = ( Quartzgt100 Ilm) P = ( Pyrite gt300 Ilm)
Donais and others (1988) found that the intercept of the curve from the above relationship on the Y axis (mill wear) was well above zero indicating that the effect of the finer fractions of the quartz and pyrite are not negligible and that the coal itself or other minerals may also contribute to wear It should be noted that the size distribution of pyrite and quartz are not normally measured and are not usually included in coal specifications
Other experimental techniques for abrasion testing are summarised in an early report by Parish (1970)
Erosion by mineral particles picked up in the air stream carrying pulverised coal through the mill classifier and ducting is a recognised problem The following parameters affect erosion rates
stream velocity - erosion rate increases exponentially with velocity For ductile materials the exponent is about 23 for brittle materials the exponent ranges between 14 and 5 impingement angle on mill surfaces - maximum erosion rates occur at 30deg for ductile materials and at 90deg for brittle materials particle size - erosion rates increase with particle size up to a critical size above which no increase is observed
323 Size classification and transport
Reduction in oversize particles after initial milling is achieved by separation and recycling of particles through the mill to be reground until they are sufficiently small to pass through a classifier The classifIer can be adjusted to vary the final fineness of the coal Coal fineness affects essentially all processes occurring downstream of the mill including ignition flame stability flame shape ash deposition char burnout etc However if the classifier is adjusted for greater fineness to accommodate for example the firing of a lower volatile coal (see Section 41) the amount of material recycled back to the grinding zone increases This alters the grinding process and if the coal mass in the grinding zone increases too much the grinding elements may begin to skid or excessive spillage can occur The initial coal particle size and grindability can affect the fine tuning of the classifier
The primary air flow rate to the mill is based on the requirements of the burner mill and pulverised coal transport At full load the air flow rate usually corresponds to an aircoal mass ratio of about 20 For a given size of pipes the air flow rate can be adjusted over a narrow range only without causing de-entrainment of PF or increasing pipeline wear for lower or higher rates respectively For a given mill for example ring ball type roller mills supplied with design coal and having 20 of total air as primary air at full load the calculated coalair ratio changes from about 05 kgkg to about 036 kgkg by reducing load from 100 to 50
The relationship between primary air flow rate and coal flow rate is established by the mill manufacturer Moisture content of the coal determines the necessary primary air temperatures as discussed earlier in Section 321 Moisture content of the coal may therefore influence effective and accurate transport of the coal through the mill
33 Fans Coal fired steam-electric units use a number of fans to move air flue gas and pulverised coal The major type of fans include
forced draft (FD) fans - supply air to the wind box under positive pressure induced draft (ID) fans - withdraw flue gas from the furnace and balance furnace pressure primary air (PA) fans - supply air to the mills flue gas recirculation (FGR) fans - recirculate flue gas from the economiser outlet to the burners or the wind box
The performance of the fans can be impacted by changes in coal quality
A typical arrangement of the major fans at a steam-electric unit is illustrated in Figure 16 The major path flow involves the FD and ID fans It should be noted that the fan arrangement shown in Figure 16 is not fully representative of all coal fired steam-electric units The number and arrangement of the fans and other components can vary substantially Also the pressures and temperatures of the air
42
Pre-combustion performance
air FD forced draft exhaust to FGR flue gas recirculation stack - - - - - - flue gas 10 induced draft
-----_ _-- coalair PA primary air I
1_1I __ Tempertures are approximate and may vary with plant design and operating parameters ambient air I EMISSION I
PA HEATER (air side)
PULVERISERS
-
I PA 1 FAN
-
I CONTROL I I EQUIPMENT
--T-shyt 150degC
AIR HEATER (air side)
( V
I
EMISSION CONTROL
EQUIPMENT
air heater leakage
--------+--------shy
AIR HEATER (gas side)
I
r------ -----jI
I 3700C 1 I
CONVECTIVE COLLECTOR
FGR OUST
_PA__S_ __ 2DC
1 370degC
FGR FAN FUR~ACE
g
__roaka 0I 3700C
- - - - - -+ - - - - ~ - - - -~ - - shy
wind box
burners~bullbullbullbull ------------- bullbullbull ----------- ---- bullbull ------ bullbullbull -------------- bullbull - --- bullbull --shy
Figure 16 Typical utility boiler fan arrangement (Folsom and others 1986c Sligar 1992)
43
Pre-combustion performance
entering the fans depend on the overall plant design Thus to change in flow rate required evaluate the impact of coal quality on fan capacity it is change in system resistance necessary to specify the details of the fan design and change in fan inlet conditions operating characteristics as well as the power station change in rate of fan erosion arrangement To evaluate fan capacity only the characteristics at maximum performance settings need be The flow rate through the fan could be changed in a number considered of ways by changes in coal quality For example an increase
in coal moisture will increase the flue gas volume flow rate Changes in coal characteristics can impact fan performance Changes in heating value of the coal would require a change in four ways to the airfuel ratio and hence the firing rate The excess air
Table 17 Summary of the effects of coal properties on power station component performance - I (after Lowe 1987)
Property Contributing properties Effect
Coal handling and storage Heating value
Coal flow properties
Freezing
Dustiness
Combustibility (spontaneous combustion)
Mills
Drying
Mill throughput
Wear
Fans Flow rate
moisture ash ultimate analysis
moisture coal size distribution mineral matter analysis bulk density
types of moisture
moisture size analysis mineral matter analysis porosity
coal rank moisture size distribution sulphur
moisture
volatile matter
total moisture
Hardgrove grindability index (HGI)
raw coal top size
pulverised fuel size
distribution
mineral matter analysis (quartz amp pyrite) mineral matter size distribution
moisture slagging propensity fixed carbon
A 1 decrease in heating value increases required mass throughput of coal by 1
As flow properties degrade coal throughput remains relatively constant until catastrophic blockages occur at a critical flow property value This value is highly site specific
Surface moisture at low temperatures is the primary cause of freezing
Increased operating and maintenance costs with dusty coals Potential for increased loss of availability
Heating value of stockpiled coal decreases due to spontaneous combustion Plant layout and procedures are dictated by spontaneous combustion
MiD type
Low speed Medium speed Influences primary air requirements and power consumption for both types of mill Mfects the susceptibility of both mill types to mill fires
-3 throughput for 1 moisture -15 throughput for 1 increase moisture increase above
approx 12 moisture -1 throughput for 1 unit -1 throughput for 1 reduction in HGI unit reduction in HGI Caution when using HGI for interpreting coal blend behaviour -3 throughput for 5 mm increase No loss in throughput below in top size 60 mm top size Reduction in fraction passing Reduction in fraction passing
lt75 JlII1 mesh screen by 035 for lt75 Ilm screen by 09 for 1 increase in throughput 1 increase in throughput Influences the component operation and maintenance rate for both types of mill
An increase in moisture increases the flue gas volume flow rate Influences the excess air requirements
44
Pre-combustion performance
required for a specific coal depends on the slagging propensity of the coal carbon burnout and boiler steam temperature considerations These effects are difficult to predict and the actual value of excess air used is determined by the operators to achieve the best balance
The system resistance can also be affected in a number of ways For example fouling of the convective pass increases ID fan resistance on units with induced or balanced draft (Folsom and others 1986b) Fly ash loading in the flue gas can influence the performance for example increased fan blade erosion can occur with increased quantities of fly ash (Sligar 1992)
34 Comments Table 17 summarises the effects of coal properties on the performance of the power station components discussed in this chapter It has been shown that whilst many empirical
relationships have been developed and used to describe the problems that are encountered in the power station there are some signifIcant uncertainties related to many assumptions made These can include for the components described in Chapter 3 the following
coal handling and storage - oxidation dusting flowability and freezing cannot be predicted from coal composition measurements mills - there is no way to evaluate the fineness requirements accurately Mill capacity for blends of coals and for lower rank coals are difficult to evaluate using existing HGI correlations fans - air and gas flow rates depend on excess air Excess air depends on flame stability carbon burnout and slaggingfouling considerations There is no satisfactory method of predicting the effect of these relationships for specific coals Twenty per cent excess is often assumed
45
4 Combustion performance
41 Burners For ignition to take place four elements must be present
fuel air sufficiently high temperature ignition energy availability
A pulverised fuel burner solves this task by blowing a mixture of pulverised coal and air into a part of the furnace where there is a high temperature When lighting up the burner this high temperature is secured locally with an ignition system The burner itself however must be designed in such a way that a stable flame is achieved after the ignition flame is extinguished and it must be able to keep the flame stable and provide optimum combustion The loss of a flame on tum-down even within normal control ranges constitutes a serious dust explosion hazard (Cortsen 1983) Sustained combustion without support fuel also requires consistent coal quality Pockets of high ash can cause momentary extinction and subsequent risk of explosion when fuel returns
A number of physical and chemical processes occur extremely rapidly within the flame It is difficult to describe the number of interactions and complexity of the reactions occurring In spite of many years of theoretical flame research burner design is still based on practical experience though in more recent years this has been supplemented with pilot- and full-scale experiments (Knill 1987 Noskievic and others 1987 Harrington and others 1988 Kosvic and others 1988 Repic and others 1988 Penninger 1989)
Ignition stability is strongly influenced by the characteristics of the coal The conventional method of evaluating the impact of coal characteristics has been to consider the volatile content of the coal and the presence of inert material (moisture and ash) However even if two
coals have the same proximate analysis their ignition characteristics may still be very different due to differences in chemical structure
There are three distinct groups of coal with respect to ignition according to Truelove (1985)
lignites and subbituminous coals with high inherent moisture and high volatile matter content greater than 50 bituminous coals with proximate volatile matter content between 20 and 50 anthracite and semi-anthracite with volatile matter content less than 20
Notwithstanding the high volatile matter content low rank coals can still be difficult to ignite because the high moisture lowers the flame temperature and dilutes the volatilesair mixture The energy required to evaporate 15 moisture and superheat it is equal to the energy required to heat the coal material to 500degC When the moisture content exceeds 40 the coal can be dried using hot flue gas with the result that the primary coaVair stream is heavily loaded with inert water vapour and products of combustion In contrast to the difficulties associated with the ignition of low rank coals the char resulting from high-moisture high volatile matter coals is generally highly reactive
Low volatile coals are much more difficult to ignite In these cases the heat released during the combustion of volatiles is usually insufficient to raise the temperature of the char to ignition and hence sustain combustion It may be necessary to provide continuous support fuel to maintain combustion Ignition stability with low volatile coals can be enhanced by grinding the coal finer and using high preheat for the combustion air Table 16 shows recommendations for pulverised coal fineness based on the volatile matter content (Cortsen 1983) Bituminous coals with volatile contents above 25 should present few problems with ignition
46
Combustion performance
Modem independent burners all use strongly swirling air flows to achieve flame stability and control flame length and width and combustion intensity The application of swirl produces short and intense flames Although excess swirl especially in the primary stream may delay ignition due to rapid mixing of the primary coaVair stream with the relatively cool combustion secondary air
The effect of ash on flame stability has been studied at the International Flame Research Foundation (IFRF) in the Netherlands No significant differences in ignition and flame stability were found when firing 6 ash and 30 ash high volatile coals provided that the fuel was well mixed and delivered to the burner at consistent quality
In the efforts to cut NOx emissions virtually all the combustion-equipment manufacturers are involved in the development of low NOx coal burners Many utilities already utilise the technology Intensive research has focused on the formation of NOx which is influenced greatly by combustion conditions This is discussed further in Section 523
42 Steam generator The ability of the steam turbine to generate power at full capacity depends on an adequate supply of steam at the correct temperature and pressure The steam supply and quality is dependent on the heat release occurring in the furnace and the heat transfer from the resulting gases to the various boiler surfaces located in radiant and convective banks
The effects of coal characteristics on boiler heat transfer and ultimately steam conditions are complex and closely related to the arrangement of large steam generators Factors such as the layout of radiative and convective heat transfer surfaces in the gas side and location of boiling and non-boiling regions on the steam side are critical This section considers how coal characteristics can affect both heat release and heat transfer processes via the mechanisms of fuel combustion and ash deposition
421 Combustion characteristics
Insight into the influence of coal properties on pulverised coal combustion can be gained by examining the factors affecting combustion There is an extensive amount of literature which reviews the work carried out in the field of pulverised coal combustion An lEA Coal Research report Understanding pulverised coal combustion by Morrison (1986) reviews the literature mainly post 1980 on the fundamental processes and mechanisms of pulverised coal combustion Others include reviews by Laurendeau (1978) Essenhigh (1981) Smoot (1984) Smoot and Smith (1985) Heap and others (1986) and Singer (1991) Only a brief description will be given here
The combustion of individual coal particles comprises the following sequence of processes which are partly overlapping and are all dependent on both physical conditions and coal properties
heating of the particle
release of volatile matter combustion of volatile matter combustion of the char
Heating of the particles occurs very quickly The temperature gradient is 105_106degCs depending on the size of the particle Thus a 60 lm particle may achieve furnace temperature within 005-01 s
Release of volatiles occurs within the similar time span but varies with coal quality and particle size The initial gases released ignite and bum momentarily consuming the oxygen present in the air surrounding the particle At this stage the volatiles bum independently of the char particle The devolatilisation of coal at high heating rates is an important stage because it may control
the rate at which combustion proceeds the rate at which oxygen is consumed the rate and form of evolution of nitrogen sulphur and other species together with the mechanisms governing the fate of these species
Depending on temperature and coal quality char combustion may be initiated before combustion of all volatile constituents is completed For successful combustion the heat release associated with the gas-phase reaction must raise the bulk gas temperature sufficiently to ignite the char The rate of char combustion is dependent upon several factors
initial coal structure variations diffusion of reactants reaction by various species (02 H20 C02 H2) particle size effects developed pore diffusion char mineral content (catalysis) changes in surface area as the reaction proceeds char fracturing variations with temperature and pressure
The time required for consumption of a char particle represent a significant portion of the overall time required in the coal reaction process and can range from 03 s to over 1 s (Smoot 1984)
The watersteam temperature balance in a boiler is influenced greatly by the burning profile of the coal that is the rate at which coal passes through the different stages of combustion the heat release associated with them and take-up by watersteam (Singer 1991) During combustion gas temperatures are near 1800degC but the gases must cool to the design point temperatures (usually around 1200degC) of the convective sections of the boiler so that they may be maintained in a satisfactory condition of cleanliness (see Section 422) If the coal bums too quickly
too much heat may be absorbed in the radiant section of the boiler When the gases subsequently reach the superheater tubes they may be too cool to raise steam temperature to the levels necessary for efficient turbine operation and full capacity utilisation temperatures at the radiant section can rise too high and
47
Combustion performance
cause circulation problems or increased boiler slagging (see Section 422) thus raising the incidence of forced outages
If the coal bums too slowly temperatures in the radiant section do not reach design levels and gases reaching the superheater tubes may be hotter than l200dege Thus there can be a decrease in boiler efficiency through
decreased steam production fouling of superheater tubes (see Section 422) increased carbon loss loss of superheater temperature control increased risk of fires in the economiser hopper air heater and particulate control system higher than desired exit temperature of exhaust gases
Many attempts have been made to establish empirical correlations between combustion behaviour and coal properties The volatile matter content is most commonly used as an indicator for ignition behaviour of a particular fuel Similarly heating value and ash content provide a guide to flame stability
The heating value of the coal is important as it constitutes the amount of energy that can be imparted to the system Moisture and total ash content act as negative influences to the energy supply by affecting the adiabatic flame temperature and firing density
The combustibility or reactivity of a coal can be characterised by two factors (Wall 1985a)
volatile matter yield and composition (Jiintgen 1987a Morrison 1986 Saxena 1990) reactivity of char - char reactivity generally increases with decreasing rank in PF combustion (Smith 1982 Morgan and others 1987) so that the rate of combustion is similarly dependent on rank (Shibaoka and others 1987 Jiintgen 1987b Oka and others 1987) However Cumming and others (1987) and Bend (1989) found that rank was not an accurate guide for high volatile bituminous coals from different origins The amount of char produced has been shown to be related to the proximate analysis fixed carbon content petrographic composition and initial coal particle size
An index that relates both of the parameters above is the fuel ratio that is fixed carbon divided by volatile matter as determined by proximate analysis can be used as a measure of coal reactivity The fuel ratio provides an indication of the relative proportion of char to volatiles Although correlations between the fuel ratio and carbon burnout have been found (for example Baker and others 1987) there are exceptions (Oka and others 1987) A higher fuel ratio does not necessarily indicate a coal of lower reactivity and high carbon burnout (Figure 17) This is not surprising since both volatile matter and fixed carbon determinations relate to laboratory test conditions which do not represent the conditions encountered in PF boiler As was discussed in Section 21 proximate volatile yield is generally lower than the true volatile yield as it is sensitive to test conditions
20
C----------) indicates trend reversal
These comparisons 10 contradict the rule that a higher fuel ratio necessarily means higher unburnt carbon and lower reactivity
Coal sized to +125-150 Ilm 5
Peak temperature 1300degC
2
10
c o 0 CB U
c 05s
0 c J
02
01 -t----------+-------------
05
Fuel ratio fixed carbonvolatile matter
Figure 17 Fuel ratio as an indicator of coal reactivity (Smith 1985)
(Morgan 1987) Similarly proximate fixed carbon makes no allowance for the differing reactivity of chars formed from different coals (Oka and others 1987 Smith 1982) Fuel ratio has also been found to be unsuitable for assessing low rank coals
Many utilities have found that volatile matter content information alone is a poor indicator of coal furnace performance they are tuming to the use of advanced test methods Further test procedures have been developed by boiler manufacturers and utilities which give a better insight into the influence of coal properties on combustion characteristics For example thermal gravimetric analysis (TGA) may be used to evaluate the characteristics of coal with respect to particle coal heating and volatiles ignition It should be noted however that TGA test conditions can also differ largely from the conditions present in a PF boiler An example of a TGA test requires a coal sample to be heated at
10 20 40
48
Combustion performance
a controlled rate in a controlled environment The weight loss of the sample is recorded continuously as a function of time (or temperature) The burning profiles determined in TGA are often used as a characteristic fingerprint for a coal These will be compared to a standard coal with an established boiler performance (Cumming and others 1987 Morgan and others 1987) The TGA can also be used to determine the reactivity of coal chars prepared in situ or in other test apparatus such as drop tube furnaces (DTF) or entrained flow reactors (EFR) (Jones and others 1985 Morgan and others 1987 Crelling and others 1988 Hampartsoumian and others 1991)
The DTF or EFR apparatus can also be used to determine the reactivity of coalschars under a range of conditions The apparatus can be utilised under conditions similar to those experienced in a boiler In these tests a consistently higher extent of volatile release is measured than in the volatile matter test of the proximate analysis (Morrison 1986 Knill 1987 Gibbs and others 1989) Carbon burnout can be determined along with the reaction rates for the different stages of combustion (Wall 1985b Skorupska and others 1987 Tsai and Scaroni 1987 Diessel and Bailey 1989 Smith and others 1991a Chen and others 1991) This topic has also been reviewed by Unsworth and others (1991)
Other apparatus used for volatile matter release rates and coalchar reactivity determinations include the heated wire grid apparatus flat flame burners pyroprobe and pilot scale furnaces
All these tests provide data on the devolatilisation and combustion characteristics of coal in considerably more detail than the data provided by standard proximate analysis The boiler manufacturers have developed methods of utilising the test data to predict boiler performance However it should be recognised that these tests are used subject to individual choice and interpretation They are not widely accepted in the utility industry as standards Currently the tests results are meaningful only in the context of a background database for a particular installation which includes accumulated measurements on fuels in the specific test facilities as well as field operating systems The most direct method of utilising the tests would be to compare the performance of specific coals to a base coal whose performance in the subject boiler is well documented In cases where such an approach is not practical it is necessary to rely on laboratory data and modelling to extrapolate the results to full scale However the test procedures particularly in the case of DTF apparatus are complex and since the test facilities have been used primarily as research tools there are no accepted standards
422 Ash deposition
Ash deposition is one of the most important operational problems associated with the efficient utilisation of coal (lEA Coal Industry Advisory Board 1985 Jones and Benson 1988) Since deep cleaning of coal is expensive (Couch 1991) ash is present in all coal-fired furnaces and must be carefully controlled
Equipment manufacturers have used several approaches for
108wx 106d 126 w x 124 d
D D D L wxd 116wx108d
r130 h
U Eastern Western Lignite
bituminous subbituminous coal coal
Siagging propensity low-medium high severe high Fouling propensity low-medium high high high
Midwest (Illinois)
bituminous coal
Furnace size is also affected by coal heating value - moisture - volatile matter
Figure 18 Influence of ash characteristics of US coals on furnace size of 600 MW pulverised coal fired boilers (Babcock amp Wilcox 1978)
ash management to accommodate effective collection and disposal of the deposit Dry and wet bottom furnaces utilise very different operational conditions to achieve this goal (Hatt 1990) Most pulverised coal units that are offered today are of the dry bottom type although wet bottom or slagging bottom furnaces may still be offered for special applications
Since the presence of ash is unavoidable coal-fired power stations are designed to tolerate some deposit on tube surfaces without undue interference of unit operation Knowledge of ash deposition tendencies of coals is important for boiler manufacturers as boiler design features can be varied to accommodate difficult coals Figure 18 describes how one manufacturer accommodates various ash characteristics by adjustment of furnace dimensions and the number of deposition removal systems such as wall blowers The criteria of several utility boiler manufacturers for designing boilers to avoid deposition have been reported by Barrett and Tuckfield (1988) It was observed that each manufacturer applied a different set of criteria and placed different emphasis on the coal analyses details used for prediction of ash depositional behaviour
The occurrence of extensive ash deposits can create the following problems in a boiler
reduced heat transfer - due to a reduction in boiler surface absorptivity and thermal resistance of the deposit impedance ofgas flow - due to partial blockage of the gas path in the convective section of the boiler
49
Combustion performance
physical damage to pressure parts - due to excessive loading of the structures andor impact damage when pieces of the deposit break off and fall down through the furnace corrosion ofpressure parts - due to chemical attack of metal surfaces by constituents of ash erosion ofpressure parts - resulting from abrasive components of fly ash
If the deposits cannot be removed by wall blower or soot blower operation the load on the boiler may have to be reduced to lower furnace temperatures to the point where ash softening is controlled and wall andor soot blowers become effective It is not unusual to observe power stations that must drop loads to about one-third of capacity at night to shed slag accumulated during high-load day time operation (Barrett and Tuckfield 1988) In extreme cases the boiler
Extraneous minerals
must be shutdown and the deposit removed by hand Frequent maintenance and unscheduled shutdowns for removing these deposits and the repair of the effects of corrosion and erosion add substantially to the cost of power generation These problems can result in reduced generating capacities and in some cases costly modifications (Bull 1992)
Deposit problems within a boiler are classified as either slagging or fouling Different definitions of slagging or fouling are used by different people Some people refer to the nature of the deposit - defining molten deposits as slagging and dry deposits as fouling Others define slagging and fouling by the section of the boiler on which the deposit occurs (Borio and Levasseur 1986) For the purposes of this report slagging refers to deposits within the furnace and on widely spaced pendant superheaters in those areas of the unit
bull pyrite 1100degC --------- fusion clays 1300degC
quartz 1550degC
~ expansion
~
Inherent minerals
bull M cenospheres
Y
Na K Heterogeneous 8 ~ condensation Mg ~
80 Homogeneous I __ nucleation
MgO coalescence
surface enrichment
coalesce~--------------I~~ euroY-----~ bull 30~m
p~QD~--- quench ---1~~ ~Qi) 10-90 ~m
disintegration
~
Figure 19 Mechanisms for fly ash formation (Wibberley 1985b Jones and Benson 1988)
50
Combustion performance
which are directly exposed to flame radiation Fouling refers to deposits on the more closely spaced convection tubes in those areas of the unit not directly exposed to flame radiation
Ash slagging and fouling give rise to the first four problems listed above The fifth problem erosion is the result of the impingement of abrasive ash on pressure parts Often coal ash deposit effects are inter-related For example the build up of ash deposit layers on tube walls and superheaters does not only reduce furnace and overall boiler efficiency but can also increase the temperature level in furnace and convective passages and aggravate existing deposit problems The characteristics of the deposit layer change so as to reduce the heat transfer to the surface locally the gas temperature in the furnace will rise partially ameliorating the impact However the net effect is that furnace deposits (slagging) decrease the heat transfer in the radiant furnace and increase the furnace exit gas temperature This can lead to enhanced fouling problems in the convective pass if the ash particles enter the convective tube bundles in a sticky state Ash deposits accumulated on convection tubes can reduce the cross-sectional flow area increasing fan requirements and also creating higher local gas velocities which accelerate fly ash erosion In situ deposit reactions can produce liquid phase components which are instrumental in tube corrosion
The coal ash deposition process involves numerous aspects of coal combustion and mineral matter transformations reactions The importance of the furnace operating conditions on the combined results of the above areas must also be stressed For a given coal composition furnace temperatures combustion kinetics heat transfer to and from the deposit and residence times generally dictate the physical and chemical transformations which occur (Barrett 1990) The ash formation process is therefore dependent on the timetemperature history of the coal particle and the heterogeneous nature of the mineral matter in coal Each pulverised fuel particle may behave uniquely as a result of its composition Figure 19 summarises the mechanisms for fly ash formation
The ash transported through the combustion system only becomes a problem if it is first transported to the heat transfer surface and subsequently sticks to that surface Particle size particle density and shape affect transport behaviour (Borio and Levasseur 1986)
In addition to transport phenomena the three requirements for the formation of deposits from a gas stream containing inorganic vapour and fly ash are (Wibberley 1985b)
the vapours and fly ash penetrate the boundary layer of the tube and contact the metal surface the material adheres to the tube surface sufficient cohesion occurs in the deposit to allow continued growth without periodic shedding under the influence of its own weight vibration soot blowing temperature cycling in the furnace etc
The initial deposit layer is significant as it represents the boundary between the tube metal or rather oxide and the remainder of the deposit Adhesion between the tube and the
first deposit forming material from the fumace gases may involve several factors
surface attraction between the fine ashcharged ash and the tube inherent roughness of the tube which is increased by oxide whisker growth or growths of desublimed alkalis liquid phases on the tube surface formed by supercooling of condensing alkalis reactions involving desublimed alkalis or alkalis pyrrhotite fly ash sulphur compounds and the tube metal to form low melting point complex salts such as Na3Fe(S04)3 Tm = 627degC sticky fly ash particles with either supercooled sodium silicates or condensed alkalis on the surface of the ash and species migration through the deposit
As the deposit thickens the temperature at its outer surface increases at the rate of 30-100degCmm depending on the thermal conductivity of the deposit and the local heat flux to the deposit (Wibberley 1985a) The increasing temperature decreases the viscosity of any liquid phases present which in tum increases the retention of larger fly ash particles impinging on the tube and also the rate of deposit consolidation by sintering and sUlphation
As the size of the fly ash retained at the deposit surface increases its surface becomes increasingly irregular (secondary deposit layer) The rate of deposition is highest where the deposit extends furthest into the oncoming gas stream This causes projections to form Continued growth of the deposit depends on simultaneous growth and consolidation Consolidation involves sintering and sulphation which are enhanced by the increasing temperature in the outer regions of the growing deposit
Siagging Slagging deposits typically form on the water wall section of boilers near the burner region In this region the water wall tubes surfaces are typically in the region of 200degC to 425degC (400degF to 800degF) a temperature too low for mineral matter to form molten deposits The fireside layer of a slagging deposit may consist of a running fluid in which all the fly ash has dissolved or it may consist of a glassy phase impregnated with particles of fly ash (Bryers 1992) Formation of slagging deposits is a time dependent phenomenon Situations are commonly encountered within a boiler where initiation of slag deposits in one region of the boiler will propagate to other regions of the boiler as the heat transfer through the water wall tubes is continually reduced and the temperature of the flame and the deposit increases This influence on heat absorption has been demonstrated using pilot combustor facilities to monitor the effect and rate of deposit build up on heat flux on panels designed to simulate boiler water wall surfaces (Abbott and Bilonick 1992) Figure 20 shows the average per cent heat flux recovery for soot blowing cycles at two different coal firing rates for a range of US coals The work demonstrated that the ash deposits from different coals prove to have a range of tenacities as demonstrated by the different values of heat flux recovery
Determination of the elemental composition of slagging deposits in comparison with equivalent compositions of fly ash have
51
Combustion performance
1 washed Pittsburgh seam - medium sulphur 2 run-at-mine Pittsburgh seam - medium sulphur 3 Pittsburgh seam - low sulphur 4 Pittsburgh seam - high sulphur 5 Illinois No 6 seam - low sulphur 6 Roland seam 7 60 Roland40 Illinois No 6 - low sulphur blend
Figure 20 Heat flux recovery for different coals and soot blowing cycles (Abbott and Bilonick 1992)
shown that there is enrichment of some elements in the deposit (Borio and Levasseur 1986) The results of such an analysis are shown in Table 18 This analysis shows some depletion of silica (Si02) alumina (Ah03) and lime (CaO) in the deposit and an increase in hematite (Fe203) In some cases direct impaction of unspent pyrite on hanger tubes and the leading edge of the first row of convection bank tubes can cause an iron-rich deposit to form that is 75-90 Fe203 in the deposited ash The deposit is semi-fused as pyrrhotite and is further oxidised to hematite or magnetite While bulk analysis of deposits on water wall tubes can give an insight into the formation of the deposits still more information can be gained from chemical analysis of different layers within the deposits which are seldom homogeneous and vary with time
Wain and others (1992) have also illustrated that slag
deposits from different UK coals can exhibit a range of chemical and physical properties At one extreme the slag may be highly porous and friable having little mechanical strength while at the other extreme the slag deposit may be dense and fused with great strength Susceptibility to removal processes was shown to be related to the porosity of the slag formed which in tum is dependent upon ash composition and operating conditions Earlier work indicated that the physical state of the deposit can have a significant effect on the radiative properties In particular molten deposits show higher emissivitiesabsorptivities than sintered or powdery deposits (Goetz and others 1978) Thin molten deposits are less troublesome from a heat transfer aspect than thick sintered deposits However molten deposits are usually more difficult to remove and cause frozen deposits to collect in the lower reaches of the furnace where physical removal can no longer be carried out with wall blowers
Fouling In all coal-fired units ash deposits build up on the convective pass tube bundles due to the flow of the particulate laden flue gas over the tubes The boiler manufacturers attempt to design their units to avoid the uncontrollable build up of deposits in this region Fouling problems occur when the strength of the deposits is high and the action of soot blowers is unable to remove the deposits It should be noted that with fouling there is no analogue to the wet bottom approach to slagging that is units cannot be designed to accommodate fouling problems by ensuring that the ash deposits are removed from the convective pass tubes as liquids
As with slagging the bonding of ash particles to the tube surface depends on the physical state of the particles approaching the tubes and wetting action of the ash on the tube surface However in the convective pass the temperature difference between the particles (and gas) and the tube surface is much less than in the radiant furnace so that the quenching action of the particles impacting the tube surface is greatly reduced
Organically-bound sodium and sodium chloride are most frequently the cause of convective bank fouling in low rank coals and bituminous coals respectively (Osborn 1992) As discussed earlier many of the alkali metal compounds in coal
Table 18 Enrichment of iron in boiler wall deposits - comparison of composition of ash deposits and as-fired coal ashes (Borio and Levasseur 1986)
Unit sample Power station 1 Power station 2 Power station 3
As-fired Waterwal1 As-fued Waterwal1 As-fired Waterwal1 coal ash deposit coal ash deposit coal ash deposit
Ash composition Si02 470 333 502 551 497 418 Ah03 267 180 169 146 165 158 Fe203 146 435 59 183 120 285 CaO 22 12 128 72 65 90 MgO 07 05 35 20 09 09 Na20 04 02 06 05 11 06 K20 23 16 08 06 15 09 Ti02 13 08 09 08 11 07 S03 11 05 120 01 20 02
52
Combustion performance
vaporise readily at typical furnace temperatures They form hydroxides or oxides that react with S03 in the gas phase at the tube surface to form sodium sulphate They can react with ash particles to form low melting point eutectics or can nucleate on the surface of ash particles or tubes Thus alkali metal compounds can lead to sticky deposits on the tube surfaces Generally sodium and calcium sulphate dominate the initial layer of deposits As the deposits build up in thickness they can sinter into a strong fused mass They may include other ash particles completely encapsulated with calcium and sodium sulphate crystals The sintering process may be related to diffusion of materials through the deposits and solid phase reactions
As in the case of slagging fouling deposits also are not uniform but are built in layers of material which can differ in particle size and chemical composition
Corrosion Corrosion of the furnace wall tubes has resulted in metal depletion rates of 600 nmh or more compared to normal oxidation rates of about 8 nmh (Brooks and others 1983) Such severe corrosion drastically reduces the lifetime of the tubes and may lead to unexpected failure Fumace wall corrosion of steel tubes has been observed in virtually all types of pulverised coal boilers In extreme cases the result is tube failure and large scale requirements for replacement (Clarke and Morris 1983 Blough and others 1988) Currently corrosion is no longer the primary cause of forced boiler shutdowns owing to control strategies and regular maintenance However remedial measures are quite costly and current efforts seek to reduce this cost by substantially extending maintenance intervals (Flatley and others 1981)
The mechanisms which govern the corrosion of the furnace wall tubes are not well understood (Harb and Smith 1990) Corrosion behaviour is closely linked to conditions in the furnace Fireside corrosion can occur on both water walls and superheater tube surfaces Water wall corrosion results essentially from regions of persistent local substoichiometric combustion near the walls which may be due to coal devolatilisation andor inadequate coalair mixing The resulting low partial pressure of oxygen and a high partial pressure of sulphur (as H2S and S02) cause the formation of scales containing iron sulphides Sulphide scales grow more rapidly than the corresponding oxides They are less protective and can lead to increased stress when formed in an existing oxide scale This promotes rapid spalling of the tube surface (Wright and others 1988) Other species believed to participate in corrosion reactions include HCI This is formed on volatilisation in the flame Flatley and others (1981) postulated that HCl reacts with the outer scales of the previously formed protective oxide to create gaseous microchannels through which HCl gains access to the metal surface Once at the surface the HCI reacts with the iron to form a volatile iron chloride which is then transported back toward the bulk furnace gases The reducing environment is also known to lower ash fusion temperatures and increase mineral deposition which in turn can affect corrosion behaviour
Corrosion often occurs in definite patterns associated with the direction of the flame and has been linked to flame impingement (Borio and others 1978) Flame impingement
again creates severely reducing conditions high heat fluxes and leads to the generation of corrosive species Evidence exists that severe furnace wall corrosion of carbon steel is a consequence of poor local combustion associated with flame impingement and the delivery of unburnt coal particles to the tube surface (Flatley and others 1981) Strategies to limit NOx formation in some boilers can increase the likelihood of corrosion owing to the presence of reducing environments and enlargement of the flame zone (Chou and others 1986)
On higher temperature metal surfaces such as superheaters and reheaters two main causes of corrosion are
overheating which leads to accelerated oxidation of both fireside and steam side deposit related molten-salt attack
The latter form of corrosion can be related directly to the chemistry of the coal being burned and the steam (wall) temperature Molten salt attack concerns the development of conditions beneath a surface deposit which are conducive to the formation of a low melting salt ofthe type (NaK)3Fe(S04)3 These alkali-iron trisulphates form by reaction of alkali sulphates deposited from the flue gas with iron oxide on the tubes or from the fly ash in the presence of S03 (Shigeta and others 1987) The minimum melting point for these salts occurs at 552degC (1026degF) This type of corrosion has been associated with the presence of alkali metals sulphur and iron in coal
Chlorine can also be a contributing factor towards superheater metal corrosion if sulphate content is low While exact mechanisms can be argued there have been both liquid phase and gas phase corrosion when chlorides have been present (Latham and others 1991b Daniel 1991)
Calcium and magnesium which may also be found in coal mineral matter are known to be anticorrosive elements which inhibit the formation of alkali-iron trisulphates This is particularly true for acid-soluble calcium and magnesium contents which have an inhibiting ability for liquid-phase corrosion by forming a solid sulphate in the deposit for example calcium sulphate (Blough and others 1988) Work by Shigeta and others (1987) showed from corrosion tests that the corrosion rates were influenced by anti-corrosive elements (see Figure 21)
c 4 co E 0
-0 3E ( ()
Q 2 1 OJ
Qj
5
o 4 8 12 16
Contents of CaO and MgO
Figure 21 Effect of CaO and MgO on corrosivity deposit (Shigeta and others 1987)
20
53
Combustion performance
Erosion Erosion due to fly ash is recognised as the second most important cause of boiler tube failure (Dooley 1992) Considerable effort is being spent to understand the mechanism of fly ash erosion and to acquire the capability to predict erosion rates due to fly ash in boilers Fly ash is more erosive compared to the coal from which it originates one reason being the absence of the soft organic fraction
Table 19 Hardness of fly ash constituents (Nayak and others 1987)
Constituent Mohs Vickers Hardness kgmrnz
Mullite Vitreous material Free silica (quartz) Hematite Magnetite Coke particles with inherent and surface ash
Fume sulphate particles Anhydrite (CaS04)
5 550-600 7 1200-1500 5-6 500-1100 5-6 500-1100
3-5 100-500 (non-abrasive)
Erosion occurs at the outlet of the furnace section where the flue gas is made to tum over the top of the boiler while traversing pendant tube banks and in the rear pass especially on the sections of horizontal tube banks adjacent to the back wall of the rear pass (Wright and others 1988) Fly ash size and shape ash particle composition hardness and concentration and local gas velocities play important roles concerning the erosion phenomenon Table 19 lists the available data on hardness values of fly ash particles (Nayak and others 1987) The hardness characteristics of the major mineral contents in fly ash have not been studied extensively Work by Raask (1985) and Bauver and others (1984) has shown that quartz particles above a certain particle size are very influential in the erosion process and that furnace temperature history plays an important role in determining erosive characteristics of the particles
Many of the above phenomena discussed under the headings of Slagging Fouling Corrosion and Erosion have standard tests such as ash fusibility (see Section 25) as the basis for predicting their occurrence These bench-scale tests provide relative information on a coal which is used in a comparative
fashion with similar data on fuels of known behaviour Unfortunately although commonly used they do not always provide sufficient information to permit accurate comparison
The fusibility temperature measurement technique attempts to recognise the fact that mineral matter is made up of a mixture of compounds each having their own melting point (see Table 20) As a cone of ash is heated some of the compounds melt before the others and a mixture of melted and unmelted material results The structural integrity or deformation of the traditional ash cone changes with increasing temperature as more of the minerals melt However use of ash fusion data can be misleading Ash fusion tests typically are run in both a reducing and oxidising environment This means there is either sufficient oxygen in the atmosphere surrounding the ash particles to oxidise various minerals or there is not Generally an oxidising environment pertains throughout the combustion chamber of the boiler For a number of reasons there may be moments when as the coal and mineral particles pass through the combustion chamber there is not enough oxygen for oxidation to occur This is known as a reducing environment It is important to be aware of these conditions since if a reducing environment develops the ash fusion temperatures are lower than those occurring in oxidising conditions and can become low enough to cause slagging and fouling
The problems with ash fusion measurement is that recent results indicate that significant meltingsintering can occur before initial deformation is observed The fact that the timetemperature history of the laboratory ash is quite different from the conditions experienced in the boiler can result in differences in melting behaviour In addition the ash used in this technique may not represent the composition of the ash deposits that actually stick to the tube surfaces Often there is a major discrepancy between the composition of as-fired ash and that which is found in the deposits The discrepancies between fusion temperature results and actual slagging performance are usually greater on ashes that may look reasonably good in the laboratory One can usually assume with reasonable confidence that the melting temperature of the water wall deposits will be no higher than measured fusion temperatures although they can be and often are lower This is because deposition of lower melting constituents can and does occur with a resulting enrichment of lower melting material in the deposit Bearing all of these points in mind it is difficult to show confidence in this test as a predictor of performance
Table 20 Properties of some coal ash components (Singer 1991)
Element Oxide Melting temperature degC
Si SiOz 1716 Al Ah0 3 2043 Ti TiOz 1838 Fe Fez03 1566 Ca CaO 2521 Mg MgO 2799 Na NazO sublimes at 1276 K KzO decomposes at 348
54
Chemical Compound Melting property temperature degC
acidic NazSi03 877 acidic KzSi03 977 acidic Ah03NazO6SiOz 1099 basic Alz03KzO6SiOz 1149 basic FeSi03 1143 basic CaOFez03 1249 basic CaOMgO2SiOz 1391 basic CaSi03 1540
Other tests such as ash viscosity measurements suffer from shortcomings These tests are conducted on laboratory ash and on a composite ash sample Viscosity measurements are less subjective and more definitive than fluid temperature determination for the assessment of ash flow characteristics The usual procedure for assessing slag viscosity for wet bottom furnaces is to correlate the temperature at which the viscosity of coal ash slag is 250 poise This is defined as T250 Viscosities for dry bottom furnaces are usually conducted at higher temperatures These values can also be calculated from ash analysis Thompson and Gibb (1988) reported that in a study of nine UK coal ashes with a high iron content the slagging propensities as determined by ash viscosity tests was broadly in keeping with expectations though four of the samples showed contradictory behaviour During pulverised coal firing a severe problem may already exist before slag deposits reach the fluidrunning state Generally only a small quantity of liquid phase material exists in deposits and it is the particle-to-particle surface bonding which is most important
Tests utilising the electrical resistance properties of ash have also been developed and these are perceived as being superior to the standard ash fusibility test for providing an indicator of the onset of ash sintering (Cumming 1980 Lee and others 1991)
Much use is also made of the ash composition which is normally a compilation of the major elements in coal ash expressed as the oxide form Coal ash can be classified as one oftwo types viz
bituminous-type Fe203 in ash is greater than the sum of CaO + MgO in ash lignitic-type Fe203 in ash is less than the sum of CaO + MgO in ash
From the compilation of elements expressed as oxides from the ash analyses judgements are often made based on the quantity of key constituents like iron silicon aluminium and sodium
Using the results obtained from a standard ash analysis the measured oxides can be separated into basic and acidic components (see Table 8 and Table 20) The acidic components are those materials which will react with basic oxides They include Si02 Ab03 and Ti02 The basic ash constituents are those materials which will react with acidic oxides They include Fe203 CaO MgO Na20 and K20 The base to acid ratio is the ratio of the sum of the basic components to the sum of the acidic components Baseacid ratios are used as indicators of ash behaviour normally lower melting ashes fall in the 04 to 06 range It has been shown that baseacid ratios generally correlate well with ash softening temperatures so although baseacid ratios have helped explain why ash softening temperatures varied it has not improved the predictive capabilities (Borio and Levasseur 1986) Other ratios such as FeCa and SiAI have been used as indicators of ash deposit behaviour Ratios like these have helped to explain deposit characteristics but their
Combustion performance
use as a prime predictive tool is questionable especially since these ratios do not take into account selective deposition nor do they consider the total quantities of the constituents present An FeCa ratio of two could result from weight per cent ratios of 63 or 3015 the latter numbers would generally indicate a far worse situation than the former but the ratio does not show this
Many of the slagging and fouling indices described earlier in Table 8 are based upon certain ash constituent ratios and corrected using such factors as geographical area sulphur content sodium content etc One commonly used slagging index uses both BaseAcid ratio and sulphur content Factoring in sulphur content is likely to improve the sensitivity of this index to the influence of pyrite on slagging (As previously discussed iron-rich minerals often play an important role in slagging) However the use of such correction factors is often a crude substitute for more detailed knowledge of the fundamental ash properties Another example of this is the use of chlorine content in a coal as a fouling index This can be valid as a general rule if the chlorine is present as NaCI (thereby indicating the concentration of sodium which is an active form) and that the sodium will in fact cause the fouling Chlorine present in other forms mayor may not adversely affect fouling
Sintering strength tests have been used as an indication of fouling potential Assuming that correct ash compositions have been represented (which is less of a problem in the convection section than in the radiant section) worthwhile information may be obtained relative to a timetemperature versus bonding strength relationship Again in order for sintering tests to accurately predict actual behaviour it is necessary that tests be conducted with ash produced under representative furnace conditions (timetemperature history) (Kalmanovitch 1991)
The conventional analyses and developed indices may provide indications for limited parts of the coal spectrum but they share a flaw in that they take their point of departure in the end composition of the ash without taking account of the original minerals and intermediate products formed and transformed in the combustion zone (Cortsen 1983)
Information concerning the mineral forms present in the coals and the distribution of inorganic species within the coal matrix can be extremely important in extrapolating previous experience since the nature of the inorganic constituents contained in the coal can be the determining factor in their behaviour during the ash deposition process (Borio and Levasseur 1986) Generally speaking newer bench-scale techniques can be more sensitive to the conditions that exist in commercial furnaces than the older predictive methods Selective deposition for example has been recognised as a phenomenon which cannot be ignored More attention is being paid to fundamentals of the ash formation and deposition processes The use of new analytical techniques could give results that allow mineral matter to be identified according to composition mineral form distribution within the coal matrix and grain size Techniques such as computer-controlled scanning electron microscopy (CCSEM) scanning transmission electron microscopy
55
Combustion performance
Table 21 Summary of the effects of coal properties on power station component performance - II (after Lowe 1987)
Property Contributing properties Effect
Burners and steam generator Volatile matter
Ultimate analysis
Fuel ratio
Moisture
Slagging propensity
Furnace wall emissivity
Fouling propensity
carbon hydrogen nitrogen
fixed carbon volatile matter
ash elemental analysis ash fusion temperatures coal particle mineral analysis
ash elemental analysis wall deposit physical state
ash elemental analysis active alkalis (sodium amp potassium) ash fusion temperatures
Special burner design for flame stabilisation required below a dry ash-free volatile content of 25
Air requirements are affected by ultimate analysis unit increase of CIH ratio increases air requirements per unit heat release by 08
A 006 increase in efficiency loss due to unburnt carbon for 10 increase in fuel ratio at ratio of 16
A 1 increase in moisture decreases boiler efficiency by 025 requiring a proportional increase in firing rate
Slagging propensity generally ranked as low intermediate high or severe Response to slagging propensity is a function of unit thermal rating
Furnace wall emissivity is typically 08 a decrease of 1 will increase furnace outlet gas temperature by 16degC
Fouling propensity ranked low to severe Response to slagging propensity and is highly unit specific
(STEM) and X-ray diffraction can be used to characterise these properties on an individual particle basis New spectroscopies such as extended X-ray absorption fine structure spectroscopy (EXAFS) and electron energy loss spectroscopy (EELS) are capable of determining the electronic bonding structure and local atomic environment for organically associated forms of calcium sodium and sulphur Other new techniques such as Fourier transform infrared spectroscopy (FTIR) electron microprobe electron spectroscopy for chemical analysis (ESCA) all provide methods of improving present capabilities Thermal gravimetric analyses (TGA) and drop tube furnaces (DTF) have been used to characterise mineral matter decomposition and prepare ash samplesdeposits under near-boiler conditions respectively For example Benson and others (1988) have used a laminar flow DTF to study the formation of alkali and alkaline earth alumino silicates during coal combustion
A cautionary note though should be added here as many of the new techniques are still primarily focused on small fragments of the overall deposition process in order to permit manageable controlled studies in the laboratory Unfortunately the results are all too often not re-integrated in order to understand the total process But it cannot be doubted that a knowledge of the effects of the
aforementioned coal qualities is essential to avoid expensive delay in any changes to operational conditions in order to rectify deposition problems once they arise Information of performance in test reactors could also help to implement counter strategies to prevent the occurrence of deleterious incidents forewarned is forearmed
43 Comments Table 21 summarises the effects of coal properties on the performance of the power station components discussed in this chapter Whilst many empirical relationships have been developed and used to describe the problems that are encountered in the burner and boiler region of the power station it has been shown that significant uncertainties relate to many of the assumptions involved Flame shape and stability and char burnout cannot be predicted with certainty on the basis of coal composition data Correlations for slagging fouling erosion and corrosion have been shown to be inadequate
Power station operators still consider the problems of slagging fouling corrosion and erosion to be of greatest concern In view of this these subjects are the attention of a number of studies and have been reviewed extensively It is recognised that this topic merits a more extensive review than could be incorporated in this study
56
5 Post-combustion performance
51 Ash transport
The mineral matter entering with the coal exits the power station in the following five streams
mill rejects bottom ash economiser ash particulate collection system flue gas
The distribution between these streams depends on the power station design and operation as well as the coal composition Figure 22 shows a typical distribution However as described below this distribution may vary substantially
Most direct-fired mills have provision to reject pyrite extraneous material and excess coal introduced into the mill Under normal operating conditions the mass of the material rejected is a negligibly small fraction of the total coal flow rate However as the flow rate of coal into the mill is increased toward maximum capacity the amount of rejects increases Thus there is no effective way of estimating the effect of coal composition on mill rejects The mill reject system is typically oversized and would not be expected to limit mill operation except under unusual circumstances or where mill capacity is exceeded
The amount of ash removed at the bottom of the furnace is typically about 20 of the total ash content of the coal However the mass of bottom ash is difficult to measure accurately It may be estimated by measuring the mass of ash exiting with the flue gas and subtracting this from the ash entering the boiler with the coal However the errors of such an analysis procedure are considerable and the calculated mass of bottom ash may even be negative The factors which are probably the most important for determining the fraction of ash in the bottom ash are the design of the firing system the coal fineness bulk
velocities in the furnace and slagging Coal qualities that would directly influence these factors are
ash in the coal grindability of the coal slagging propensity of the fly ash
Due to the uncertainty in the mass of the bottom ash the handling system for the material is typically designed with considerable excess capacity Most systems operate intermittently so that an increase in bottom ash may be accommodated by an increase in duty cycle
The composition of the coal ash has an impact on the characteristics of the material captured as bottom ash Dry bottom furnaces are designed to maintain the ash in the hopper in a powdery non-sticky state The powdery ash slides down the hopper walls into the collection tank at the bottom of the furnace IT the ash has a low fusion temperature it may stick to the hopper or build up to running slag This material can accumulate at the bottom of the hopper and plug the hopper exit Solid slag deposits may fall from water walls higher in the fumace causing similar problems Wet bottom furnaces are designed to operate with running slag The slag must have a viscosity low enough to flow into the collection tank where it is quenched in water and shatters into small particles Typically the slag viscosity should be in the range of 250 poise at 1426degC (2600degF) for adequate fluidity (Babcock amp Wilcox 1978) If the viscosity increases plugging of the hopper bottom can occur similar to dry bottom furnaces
The strength of the ash can affect bottom ash system operation Many bottom ash systems are equipped with clinker grinders to reduce the size of the slag particles IT the slag particles are sufficiently large or strong they can disable the clinker grinder All the problems described above are related to the coal ash chemistry that is whether a fluid slag is formed and operating conditions
57
1-----++---------shy--
Post-combustion performance
Based on coal 10 ash 2791 MJkg
Unit 500 MW 1055 MJkWh
Mass kgkJ
Mass
Flow rate th
Coal ash
Mill rejects
Bottom ash
Economiser ash
Cyclone ESP
baghouse
Stack emissions
358
1000
1905
003
10
019
072
200
381
018
50
095
261
734
1398
002
06
012
Figure 22 Typical ash distribution (Folsom and others 1986c)
Occurrences of ash hopper explosions have been reported (Stanmore 1990) The exact mechanism for the explosions has not been elucidated Hypotheses of the cause include
chemical explosions involving iron-rich ash thermal explosions resulting from rapid quenching of falling hot deposits inducing a pressure wave within the water thermal explosion within the ash hopper causing entrainment of unburnt coal which then ignites to produce a secondary blast
Stanmore (1990) reports that work so far in this field has failed to uncover any boiler feature hopper type or coal composition which was common to all explosions investigated Corner-fired and wall-fired units experience the problem with both bituminous and subbituminous coals Both low and high ash content coals were involved with both high and low ash fusion temperatures
Ash-related explosions involving residual carbon in the ash can result from unfavourable furnace conditions which can occur during a cold start of a boiler Moreover variation in initial coal size can lead to poor grinding efficiencies giving rise to a wide pulverised coal size distribution and hence incomplete coal combustion (Stanmore 1990 Wol1mann 1990)
Most of the ash particles captured in the economiser hopper
are large because they are shed from the convective pass tube bundle deposits by the action of gravity flue gas flow rate or soot blowing The amount of ash varies with the fouling characteristics of the coal and cannot be predicted easily Economiser ash disposal systems are typically designed to handle about five per cent of the coal ash The presence of unburnt carbon in economiser ash can impact the operation of the collection system Poor coal reactivity can lead to high carbon content in the ash The carbon can continue to burn in the hopper and fuse the powdery material into a large mass which cannot flow from the hopper easily
Most of the ash exits the boiler as fly ash and is captured in particulate control equipment which may include cyclones ESPs fabric filters (baghouses) or scrubbers
52 Environmental control Since the early 1970s mandatory control of power station emissions has significantly increased the cost of generating electricity (CoalTrans International 1991) Initial concerns were focused on particulate emissions and have led to the development of efficient particulate removal systems Environmental concern about the use of coal is particularly tuned to the problem of emissions of SOx NOx and C02 to the atmosphere Trace elements are receiving increasing attention from the scientific and electric power communities who are attempting to evaluate the potential impact of trace
58
elements on the environment (Clarke and Sloss 1992) There is also the problem of disposal of the solid residues which are obtained from power stations
The capital and operating costs of emission control hardware can account for up to 40 of a power stations operating expenses (Cichanowicz and Harrison 1989) Increasingly coal-fired utilities are realising that in order to comply with ever tightening emission regulations their environmental control strategies must include adequate control of coal quality Emission control strategies related to coal quality can include
coal switching coal blending coal cleaning control of emissions during combustion post-combustion emission control
The impact of coal quality on emission control hardware has not been studied extensively Additional constraints in some cases are applied to coal quality during coal selection as a result of the implementation of emission controls
The following sections briefly review the emission control technologies available and attempts to highlight the coal characteristics and other considerations that affect the selection or efficient use of emission control systems
521 Coal cleaning
Historically coal has been cleaned to maintain specifications for delivered fuel quality and to reduce transport costs Coal cleaning benefits are usually greatest for coals which have to be transported over long distances to the point of use Conventional coal preparation plant mainly uses methods developed at least forty years ago Nevertheless in recent years there have been major advances in instrumentation and control which have resulted in reduced costs and greater consistency in the cleaned product
Utilities also have the option to incorporate coal cleaning strategies on site High mineral matter high sulphur coals could be purchased at lower prices and cleaned on site to boiler-related specifications The decision to implement this type of strategy is dependent essentially upon three factors
cost savings achieved by coal cleaning feasibility of residue disposal
Coal cleaning costs depend upon the initial cleaning plant capital costs cleaning plant operations and maintenance and the value of lesser-quality coal discarded in the cleaning process In general coal cleaning capital costs average about five per cent of the cost of the power station using the coal Direct operating costs are determined by labour consumables and power Discarded coal can account for as much as 50 of total cleaning costs (Cichanowicz and Harrison 1989)
Savings achieved by coal cleaning depend upon the depth of
Post-combustion performance
cleaning instigated (Elliott 1992) A review by Couch (1991) entitled Advanced coal cleaning technology provides a technical overview of recent developments in coal cleaning methods The fuel characteristics most significantly changed by cleaning are
mineral matter content and distribution sulphur content and form heating value
Reducing the mineral matter impurities and sulphur in the coal can have a signifIcant affect on a coals abrasiveness reduce ash loadings by up to 93 and potential S02 emissions by as much as 70 (Hervol and others 1988) Moreover coal cleaning can reduce environmental control costs by lowering the quantity of fly ash and S02 that must be removed after combustion Coal cleaning permits smaller and therefore less expensive flue gas processing equipment reduces reagent quantity and decreases the amount of solid waste requiring disposal Cleaned coal can improve station heat rate by reducing auxiliary power for flue gas handling systems and allowing lower air heater exit temperature thus increasing boiler efficiency Pilot scale combustion tests conducted by Cichanowicz and Harrison (1989) showed that boiler efficiency was greatly improved by coal cleaning as shown in Table 22
Table 22 Summary of coal cleaning effects on boiler operation (Cichanowicz and Harrison 1989)
Characteristics Run-of-mine Medium Deep coal cleaned cleaned
coal coal
Moisture 17 17 16 Sulphur 38 37 20 Ash 235 71 35 Heating value MJkg 2338 3103 3266 Flue gas S03 7 4 3
concentration ppm Air heater exit 136 120
temperature degC Boiler efficiency 884 901 Flue gas volume 6
reductionsect
dried sect includes flue gas temperature reduction and efficiency
improvement
Although the total ash content is reduced it must be noted that all ash constituents may not be removed equally Unfortunately those constituents which are primarily responsible for slagging and fouling are least affected so that problems in this area can be induced as a result of cleaning
As overall S02 emissions will be lowered by coal cleaning the benefits of this form of pollution reduction must be considered in the light of the ESP problems that might result from the use of low sulphur coal (see Section 522) and with regard to its adverse effects on collection efficiency (Strein
59
Post-combustion performance
1989) Coal cleaning has only peripheral implications for NOx and C02 emissions
An additional benefit of cleaning coals is the substantial removal of many trace elements especially heavy metals with the mineral components (Swaine 1990) Efficiencies for trace element extraction have been reported for various physical cleaning processes including density separation oil agglomeration float-sink separation and combinations of heavy-media cyclones froth flotation and hydraulic classifiers (Gluskoter and others 1981 Couch 1991)
The adoption of coal cleaning strategies on a power station site would require a knowledge of quality characteristics that affect cleaning These include
the amount nature and the size of the mineral matter If they are finely divided and dispersed they are difficult to liberate and to separate the size distribution of the coal affected by inherent friability and by mining and handling procedures All of the properties which affect coal handling have an influence here the relative proportions of pyritic and organic sulphur coal oxidation affecting surface properties the porosity of the particles
A number of tests have been developed specifically to assess the cleanability of a coal These have been reviewed in an lEA Coal Research report by Couch (1991) and will not be discussed here
522 Fly ash collection
Fly ash collection systems are required on virtually all coal-fired power stations to meet particulate emissions or opacity regulations The acceptable dust loading from collection equipment is usually about 01 gm3 A coal containing 20 ash typically provides an uncontrolled dust loading of about 30 gm2 so that a collection efficiency of 997 is required to meet acceptable emission standards For very fine particles such as fly ash such a high collection efficiency can only be achieved using electrostatic precipitators (ESP) or fabric filters
Electrostatic precipitators (ESP) ESPs have been studied extensively and a number of comprehensive texts are available that describe the process (Babcock amp Wilcox 1978 Singer 1991 Klingspor and Vernon 1988) The ESP process involves fly ash particle charging collection and removal
The perfonnance or collection efficiency of an ESP is defined as the mass of particulate matter collected divided by the mass of such material entering the ESP over a period of time One of the earliest and simplest equations for predicting the particulate collection efficiency of an ESP was that proposed by Anderson in 1919 and subsequently developed by Deutsch in 1922 The Deutsch-Anderson equation enables the collection efficiency to be predicted from the gas flow the precipitator size and the precipitation rate (or migration
velocity) ofthe particles It may be presented as follows (Deutsch1922)
where e = fractional precipitator collection efficiency (dimensionless)
a = total collecting electrode surface area (m2) v = gas flow rate (m3s) w = migration velocity of the particles (ms)
The ratio av is often referred to as the specific collecting area (SCA) and has dimensions slm When determined empirically the migration velocity w accounts for ash properties such as ash particle size distributions as well as for rapping losses and gas flow distribution The Deutsch-Anderson equation was recognised as having several limitations and so gives only approximate results for some operating regimes For this reason alternative equations have been developed often as modifications of the original Deutsch-Anderson equation For example Matts and Ohnfeldt (1973) introduced a semi-empirical factor and a constant based on particle size distribution and other ash properties which gives a more realistic approximation of actual precipitator behaviour
The equations discussed above describe how perfonnance is a function of ESP design flue gas flow conditions and the characteristics of the fly ash The impact of coal quality on ESP perfonnance is primarily via the influence of the chemical and physical properties of the fly ash on the migration velocity of the particles These include
ash resistivity ash quantity ash particle size and size distribution
Ash resistivity influences ESP power input Resistivity is critical for fly ash ESPs because it directly influences operational voltages and currents As the ash resistivity increases the flow of corona current decreases Generally speaking as the corona current decreases so does the precipitator efficiency Low resistivity ash (l08 ohm-cm and below) is also a problem because the ash easily loses its charge after being collected on the plates The uncharged particles are recharged and redeposited several times and some are eventually re-entrained into the flue gas and escape from the precipitator A limit on maximum gas velocity and special collector profiles are needed to overcome this problem
High resistivity ash (above 1011 ohm-cm) is considerably more difficult to precipitate with a risk of back corona discharge An explanation for this phenomenon is that the ash particles do not readily lose their charge when they reach the electrodes This results in difficulties when trying to remove the agglomerated ash When a deep enough deposit collects on the plate back corona may develop on the ash surface and the precipitator no longer operates efficiently Back corona is extremely detrimental to precipitator performance and occurs when particles migrate to the collecting surface but fail to dissipate their charge This
60
Post-combustion performance
causes a high potential gradient in the dust layer on the surface of the electrode and results in current conduction of opposed polarity to that of the discharge electrode
The range of dust resistivity is primarily affected by
chemistry of fly ash levels of sulphur trioxide and moisture content of the flue gas flue gas temperature
Key ash constituents which affect resistivity are ferric oxide Fez03 potassium oxide (KzO) and sodium oxide NazOshywhere a substantial reduction in either or both of these will cause an increase in fly ash resistivity Conversely a substantial increase in calcium oxide (CaO) magnesium oxide (MgO) aluminium oxide (Alz03) and silicon dioxide (SiOz) will cause ash resistivity to increase (Singer 1991) Strein (1989) describes the impact of coal cleaning in particular the removal of sulphur from coals and switching to low sulphur coals on ESP performance It was determined that coal cleaning was not always beneficial to good precipitator operation Although precipitators can be designed for low sulphur coals the use of low sulphur coals in other cases can lead to a reduction in precipitator collection efficiency and possible non compliance with stack opacity limits Precipitators constructed many years ago were likely to encounter problems if any change to a lower sulphur coal was encountered It was concluded that before a change in fuel was made a careful review should be made of the precipitator design data predicted precipitator performance and the coal and ash chemistry of the new fuel If the problem of high fly ash resistivity was encountered after a fuel switch of this nature flue gas conditioning must be considered in particular a S03 injection system The purpose of this is to supplement the naturally occurring S03 in the boiler flue gas stream to the extent necessary to reduce fly ash resistivity to an acceptable level
A number of electrostatic precipitator manufacturers have developed regression equations which make first order predictions of fly ash precipitation performance based on the elemental analysis of the ash in coal These equations are generally regarded as proprietary and are not published
CSIRO Australia have published details of correlations of ash chemistry with pilot-scale electrostatic precipitators Whilst many correlations used in the past have proved inadequate for precise prediction the most promising correlation was obtained when consideration was given to the elements that would contribute to the refractoriness of fly ash The best precision was obtained from the sum of the elemental analyses for silicon aluminium and iron calculated assuming (on an ash basis) Si+Al+Fe+Ti+Mn+Ca+Mg+Na+K+P+S = 100
The formula given for a precipitator outlet concentration of 01 gm3 and for coal at 15 ash content is in two parts (Potter 1988)
for Si+Al+Fe = a lt82 am = 1886 + 0565a for 82 lta lt90 am = -2864 + 428a
where am = required specific collecting area in mass units mZ(kgs) This value can also be represented as a percentage of the ash content (A) by multiplying by the factor f given by f = 1364 - 048810glO[(100A)-I]
Cortsen (1983) reports of the use of alkaline sulphate index (ASI) by utility operators to assess the ease of fly ash precipitation The ASI is calculated from a series of equations which relate S03 content of the flue gas and the corresponding chemical equivalent of the oxides of silicon aluminium calcium magnesium phosphorus sodium and potassium Coal ashes with ASI values between two and three are perceived difficult to collect while an ASI of six or above indicates easy precipitation The index was not considered as accurate in ESP evaluation as measurement of ash resistivity nor measurement of actual precipitator efficiency (Cortsen 1983)
Sulphur content of the coal can also influence ash resistivity Sulphur trioxide (S03) formed from the combustion of the sulphur reacts with water vapour to produce sulphuric acid (HZS04) at temperatures of approximately 500degC (950degF) In the cool part of the flue gas system there may be some deposition of HZS04 which depends on flue gas temperature and vapour pressure The HzS04 can be absorbed onto the fly ash particles and reduce their resistivity It has been shown that H2S04 can alter the fly ash resistivity either by completely absorbing on the dust particles or by chemically reacting to form sulphates Others have suggested that the formation of binary acid water aerosol is the primary mechanism by which HzS04 can affect fly ash resistivity Although the mechanism which accounts for the presence of absorbed H2S04 on fly ash particles is not clearly understood the net effect is reduction in fly ash resistivity
Increases in moisture content can adversely affect precipitator performance through impacts upstream of the ESPs The moisture content of the coal in conjunction with coal particle size and volatility can affect flame stability and combustion within the boiler furnace area If this causes excessive carbon content in the fly ash at the ESP inlet ESP performance will suffer because of the decreased resistivity of the fly ash
Flue gas temperature can also influence ash resistivity Peak resistivities occur between about 120degC and 230degC depending upon coal ash characteristics Above 230degC to 288degC the ash resistivity is inversely proportional to the absolute temperature while below 120degC to 149degC the resistivity is directly proportional to the absolute temperature (Singer 1991)
The quantity of fly ash produced from a particular coal can vary as discussed in Section 51 It is important to ensure that the total electrode collection surface area and rapping frequency is adequate to handle the quantity of fly ash produced so as to prevent re-entrainment of the material back into the gas stream after initial entrapment at the collecting plates (Strein 1989)
Migration velocity and therefore particle collection rates
61
Post-combustion performance
decrease in proportion to the size of the particle (Darby 1983 Wibberley 1985b) lithe coal is pulverised too finely before entering the boiler ESP perfonnance can be adversely affected due to reduction in particle size distribution of the fly ash at the precipitator inlet The fonnation of fine fly ash may be increased also by higher combustion temperatures and from coals that have a high Free swelling index Disintegration of swollen char particles precludes agglomeration of the mineral inclusions thus ensuring the production of finer ash particles (Wibberley 1985b)
Bench-scale tests that are nonnally perfonned on new coal samples include
preparation of ash samples in a test furnace fly ash resistivity measurement of drift velocity in an electric field
Ideally the ash analysed for the purpose of investigating ESP perfonnance should be taken from the boiler to which the ESP system under assessment is attached Baker and Holcombe (I988b) have demonstrated that the fly ash produced in a specially developed laboratory furnace could show similarities to fly ash resulting from combustion of the coal in approximately eight different power stations It was possible to reproduce the properties of the power station fly ash in tenns of electrical properties and elemental analysis
14 shyelectric stress 400 kVm
bull
13
10 - - ltgt power station fly ash
- simulated fly ash
Mass H2 0r fIgures Indicated = d fl r mass ry ue gas
015 9
80 100 150 200
TemperatureOC
Figure 23 Resistivity results for both power station fly ash and laboratory ash from Tallawarra power station feed coal (Baker and Holcombe 1988b)
and general shape although the material was coarser than nonnal power station fly ashes A comparison of the resistivities of boiler and laboratory ashes is illustrated in Figure 23
Measurement of ash resistivity must ideally be measured under the same gas and temperature conditions as those at which the precipitator will operate The packing density should also be the same as that of the dust layer deposited on the precipitator collectors Dust resistivity measurements do not correlate very well with experience in ash precipitation efficiency
Laboratory resistivity tests are not standardised by ASTM BS AS nor ISO The Institute of Electronic and Electrical Engineers in the UK standard IEEE 548-1984 describe a resistivity test designed for testing compressed fly ash at 96 water vapour by volume (IEEE 1984) Measurements of resistivity are usually taken during both heating and cooling of the sample (Young and others 1989) Figure 24 illustrates the resistivity curves against temperature for ashes from a South African coal and Polish and South African coal blend respectively It can be seen that there is a degree of hysteresis as a result of the effect of moisture in the ash
5
3
2
103
E Eo 5 c 0 4
2 323shy
s ~
200 Q)
a
102
5 4 South African coal 3 50 Polish50 South African coal
2
100 120 140 160 180 200
Temperature degC
Figure 24 Laboratory resistivity curves of ash from a South African coal and from a blend of South African and Polish coals against temperature (Cortsen 1983)
62
Post-combustion performance
which gives a lower resistivity and which disappears after the heating process (Cortsen 1983)
The drift or migration velocity in a particular electric field can be estimated by examining the dielectric constant and particle size distribution as well as the aerodynamic factors for the fly ash A technique has been developed for determining particle dielectric constant from resistivity cell tests and other measurements (Baker and Holcombe 1988a) Particle size analysis of simulated ash is not reliable because of the difference in severity of the combustion process between full scale and test combustor Optical and scanning electron microscopes can be used to assess the shape characteristics of the fly ash
Prediction of fly ash precipitation characteristics remains an inexact science so that both pilot plant testing and electrical simulation studies remain extremely important in determining the precipitability of fly ash in practice
Fabric filters Although the use of fabric filters has become more widespread in recent years with the continued preference for low sulphur coals and to reduce stack emissions further there are no coal quality tests which relate to their performance directly
As described in Section 523 in cases where sorbent injection into the flue gas is used to control sulphur emissions collection of the fine sorbent in the bag can confer a high surface area to the gas and enhance the sulphur collection performance
While the efficiency of fabric filters is very high it is important to note that problems may occur with the presence of fine ash and acid condensation derived from coal causing
retention of filter cake on the filter fabric after the cleaning cycle due to agglomeration of the cake improving its mechanical strength blinding of the apertures of the fabric by very fine particles clogging of the filter by condensation promoting filter cake agglomeration bag rotting due to acid condensation
523 Technologies for controlling gaseous emissions
A range of methods is available for control of gaseous emissions in particular for SOx and NOx Options include
emissions control in the combustor post-combustion control technologies
lEA Coal Research have produced several reports that review these technologies SOx control technologies are reported in Flue gas desulphurisation - system performance (Dacey and Cope 1986) FGD installations on coal-fired plants (Vernon and Soud 1990) Market impacts of sulphur control the consequences for coal (Vernon 1989) Technologies for
controlling NOx emissions are described in detail in the reports NOx control technologies for coal combustion (Hjalmarsson 1990) and Systems for controlling NOxfrom coal combustion (Hjalmarsson and Soud 1990)
Emissions control in the combustor In-furnace desulphurisation by injection of calcium-based sorbents is not a widely-used sulphur control technology at present mainly because of its inability to achieve as high sulphur removal rates in commercial use as wet or spray-dry scrubbers Promising results are being obtained with sorbent injection followed by enhanced collection in a fabric filter in New South Wales Australia (Boyd and Lowe 1992)
There are several potential problems that may arise from the injection of calcium-based sorbents such as limestone (CaC03) into pulverised coal flames
the additional calcium may interact with the coal ash to reduce the ash melting point with consequent risk of increased slagging and fouling it is necessary to handle increased quantities of solid residue the possible adverse effects of calcium addition on downstream equipment such as electrostatic precipitators and solid residue disposal (see Sections 522 and 524 respectively) the possible influence of sorbent injection on the radiative properties of the flame (Morrison 1982)
To date sorbent injection into the furnace has only been utilised in smaller power stations with low sulphur coal where its low capital costs are particularly favoured Sorbent utilisation rates are generally low although it still results in a significant volume of mixed fly ash and calcium sulphitesulphate residue requiring disposal (Vernon 1989)
The formation of NOx depends mainly on oxygen partial pressure temperature and coal properties such as the content of nitrogen and volatile matter Measures can also be taken to modify the combustion conditions so that they are less favourable for NOx formation (Hjalmarsson 1990) This is usually achieved by some form of air staging Combustion air is admitted in stages in such a way as to limit flame temperature
The implementation of low NOx combustion techniques is much easier and more effective in a new installation compared with a retrofIt Low NOx measures on existing boilers can affect the combustion the boiler and other parts of the power station Combustion measures especially on existing boilers are specific to each boiler Consequently it is difficult to transfer experience of the impact of coal qualities directly
Most NOx abatement investigations have concentrated on determining the coal properties that influence NOx formation such as total nitrogen content volatile matter content and particle size distribution and developing technologies for reducing NOx emissions (Nakata and others 1988) There is limited information available concerning the impact of coal properties on power station performance under low NOx
63
Post-combustion performance
combustion conditions Discussions with power station operators have revealed that coals which previously produced a satisfactory performance prior to low NOx modifications have caused increased carbon in fly ash andor fouling slagging and corrosion along with other problems under low NOx combustion conditions Some possible explanations for this behaviour are presented briefly below
combustion efficiency can be reduced combustion conditions that reduce NOx formation such as low combustion temperature and low excess air are not favourable for accomplishing complete combustion As a result of this the level of unburnt carbon in the fly ash tends to increase If this is not counteracted the high content of unburnt carbon can cause changed conditions in an electrostatic precipitator (Klingspor and Vernon 1988) and make the fly ash unsaleable (see
Section 524) changes may also occur in the characteristics of the fly ash due to the reduced combustion temperature This will make the fly ash less glassy changing its properties and making the fly ash less attractive for use in cement and concrete production the thermal conditions in both the water and the steam parts of the boiler may change through low NOx combustion leading to changes in the temperature profile of heat exchangers Combustion modifications can also lead to an increased furnace exit gas temperature (FEGT) Deposits on heat exchange surfaces can affect heat absorption The reducing atmospheres reduce the ash melting point and can aggravate the problem of causing heat surface slagging Low excess air and staged combustion can produce areas with a reducing atmosphere which cause corrosion to boiler tubes (Coal Research Establishment 1991) the higher pressure drop over burners requires a higher fan capacity This in addition to other measures such as increased mill energy to obtain the required fineness and flue gas recirculation leads to higher power consumption low NOx burners may give longer flames that can cause deposits by impingement Flame stability may also be influenced Decrease in flame stability is usually found at reduced load causing limitations to boiler load turn down
Low NOx combustion was in many cases expected to give a higher degree of slagging and fouling in the boiler The opposite however has also been found Either result causes changes in soot blowing operations (Hjalrnarsson 1990)
Post-combustion control technologies SOx emission is minimised mainly with low sulphur coal Beyond this control is carried out with flue gas desulphurisation (FGD) systems The vast majority of FGD systems use an alkaline sorbent to absorb the flue gas sulphur dioxide chemically There are a number of different types of FGD and the effects of coal changes on their performance depends on the specific design details - no generalisation can be made For example flue gas temperature and SOz level impact the performance of wet limelimestone scrubbers These same variables affect spray dry FGD systems differently (Hjalmarsson 1990)
In wet FGD systems the effects of chloride from coal are generally all negative Chloride concentrations can build to high levels in the wet scrubbing loop causing corrosion problems and greatly reducing scrubber liquid-phase alkalinity (Rittenhouse 1991) However the removal of HCl in spray-dry scrubbers can have both positive and negative effects The HCl in the system can improve SOz removal capabilities resulting in lower reagent costs This effect was noted during a full-scale test conducted by Northern States Power Company in 1983 The addition of an amount of calcium chloride equivalent to a 02-03 increase in chlorine content reduced lime consumption by 25 Pilot tests carried out by EPRI confmn this effect (Collins 1990) The savings in lime consumption usually outweigh the cost of any negative effects including
incomplete droplet drying corrosion of stainless steel components in the system increased pressure drop downstream of fabric filters degraded ESP performance
Reference manuals have been published at IEA Coal Research that evaluate the wide range of FGD systems (Vernon and Soud 1990 Dacey and Cope 1986)
Where power station limits for NOx emissions cannot be met by combustion control flue gas treatment has to be installed The dominant method in use is selective catalytic reduction (SCR) In the SCR method the NOx concentration in the flue gas is reduced through injection of ammonia in the presence of a catalyst The role of the catalyst catalyst types and the reaction mechanism are described extensively by Hjalmarsson (1990) The efficiency of NOx reduction is primarily dependent upon condition of the catalyst which in tum is dependent upon the type of catalyst its susceptibility to poisoning and its location in the flue gas flow
The positions that are used for catalyst location are high dust low dust and tail end In the high dust location between the economiser and the air preheater the flue gases passing through the catalyst contain all the fly ash gaseous contaminants and sulphur oxides from combustion This can cause degradation of the catalyst leading to a decrease in NOx reduction efficiency The main types of degradation that are coal quality related are
deposition of fly ash causing clogging of the pores of the catalyst (Balling and Hein 1989) poisoning of the active sites of the catalyst by compounds such as alkali ions (sodium potassium calcium and magnesium) especially in sulphated form and some trace elements such as arsenic (Gutbertlet 1988 Balling and Hein 1989) erosion of the catalyst A high fly ash content in addition to an uneven particulate concentration and size distribution are most likely to cause erosion problems
The lifetime of a catalyst in this position is considerably shorter than in other positions Nakabayashi (1988) reported from a comparison of the impact of position on catalyst characteristics that catalyst life can range from 2-3 years in
64
Post-combustion performance
Table 23 Effect of coal type on total concentrations of selected elements from fly ash samples (Ainsworth and Rai 1987)
Mean and range of concentrations in fly ashes (Ilglg solid) from
Element Bituminous Subbituminous Lignite
Arsenic 219 (11-1385) 191 (8-34) 544 (21-96)
Cadmium 117 laquo5-169) lt5 lt5
Chromium 245 (37-609) 73 (41-108) 284 laquo40-651)
Molybdenum 56 (7-236) 165 laquo4--55) 141 (8-197)
Selenium 123 laquo5-435) 142 laquo5-281) 184 laquo5-469)
Vanadium 290 (99-652) 133 laquo25-292) 209 (lt25-268)
Zinc 607 (65-2880) 148 (27-658) 647 (25-127)
mean value is followed by range in parenthesis for 26 8 and 5 fly ashes from bituminous subbituminous and lignite coals respectively
a high dust location compared to 3-5 years in the tail end position
A low dust location means that the catalyst is situated after a hot gas electrostatic precipitator and before the preheater The flue gas reaching the catalyst is almost dust free but still contains sulphur dioxide which may result in poisoning of the catalyst
Tail end systems have the catalyst situated in the end of the chain of flue gas purification equipment after the desulphurisation plant The flue gases reaching the catalyst therefore contain only small amounts of sulphur oxides and particulates
NOx can also be controlled through thermal reactions by using appropriate reducing chemicals The process is called selective non catalytic reduction (SNCR) It has been found that different conditions in the flue gases influence the reactions and the temperature window (Mittelbach 1989 Gebel and others 1989) High CO content (gt1000 ppm) reduces the removal efficiency High S02 content increases the reaction temperature (Hjarlmarsson 1990)
Numerous processes have been developed for combined desulphurisation and denitrification of gases Most processes are still at the laboratory scale and there are a few stations operating at full commercial scale Coal quality effects on combined removal processes have not been studied extensively The problems encountered during the implementation of the individual abatement technologies may also be exacerbated for the dual systems An lEA Coal Research report Interactions in emissions control for coal-fired plants (Hjarlmarsson 1992) examines the interactions between control of S02 NOx and particulate emissions with different combustion methods and also the production of solid and liquid residues An understanding of the impact of coal quality on emission control technologies must be achieved for future efficient implementation of control systems
Trace elements emissions during combustion can also become associated with fly ash andor bottom ash Because of vaporisation-condensation mechanisms most of the trace elements in fly ash are often higher in total concentrations than those found in the corresponding bottom ash (WU and Chen 1987) In addition the levels of many trace elements including Cr Mn Pb n and Zn are often concentrated on the surfaces of the fly ash particles Typical median concentrations of selected trace elements in fly ash from different coal types are shown in Table 23 In power stations equipped with wet FGD systems the sludge from the scrubbers is a combination of spent solvent calcium sulphate and sulphite precipitates and fly ash The quantity and distribution of trace elements occurring in sludge are essentially determined by the coal ash composition and may influence the disposal cost of the material (Akers and others 1989)
524 Solid residue disposal
A typical pulverised coal fired power station employing ESPs or baghouses for particulate control and FGD for SOx control can produce three types of residue bottom ash (including slag) fly ash and FGD sludge Although under favourable conditions increasingly large amounts of these residues are utilised for various purposes at a net profit to the utility (Murtha 1982 Taubert 1991) it is anticipated that utilisation will not eliminate the need for disposal at a net cost in the foreseeable future
Changing coal characteristics can impact both the quantity and characteristics of the residue Power stations with limited resources for residue disposal have to transport the ash to alternative locations Ash for disposal may be conveyed to the disposal site as a dilute slurry Cerkanowicz and others (1991) reported that physical and rheological properties of fly ashes vary from different power stations This can impact the flow properties of fly ashwater mixtures significantly
The major factors that affect the amount of residue produced
65
Post-combustion performance
Table 24 Summary of the effects of coal properties on power station component performance - III (after Lowe 1987)
Property Contributing properties
Ash and dust plant
Ash quantity per unit heat release
Slagging propensity
Ash solubility
Erosiveness
Clinker reactivity
Environmental control
Coal cleaning
Particulate control ESP Dust burden (Ash per unit gas volume) Gas flow per unit heat
Ash resistivity
Sulphur
Fabric filters Dust burden
Gas flow per unit heat
Combustion measures
Post combustion
Residue disposal
ash level heating value grindability
ash elemental analysis ash fusion temperature coal particle mineral matter
ash elemental analysis ash mineral composition
mineral matter elemental analysis coal size distribution trace element
ash heating value ultimate analysis CIH ratio moisture level
ash heating value ultimate analysis CIH ratio moisture level
sulphur nitrogen volatile matter
cWorine fly ash size trace elemental analysis
ash ash elemental analysis sulphur heating value trace elemental analysis chlorine content
Effect
A I increase in ash quantity per unit heat release increases the ash and dust plant duty by 1
High slagging propensity increases the duty on ash extraction plant Formation of large clinkers may cause blockages in hopper doors and contribute to ash crusher problems
For wet hopper systems with recirculated water formation of scale pipelines may cause problems
Increased erosiveness will increase wear in pipelines and sluiceways
Some coals produce clinker in the furnace which is prone to explosive release of energy on quenching in the ash hopper
Different techniques are required depending upon the type and size distribution of the mineral matter Coal particle size influences the efficiency of the cleaning process and overall organic coal recovery
A 1 increase in dust burden will increase emissions by 1
A 1 increase in gas flow per unit heat release will increase emissions by 15 A resistivity change of 1 order of magnitude would suggest an increase in emissions by a factor of 2 General trend for reducing resistivity as sulphur increases possibly one order of magnitude per 1 sulphur change Below 1 sulphur resistivity is dominated by other factors
Differential pressure will increase with dust burden
A 1 increase in gas flow per unit heat release will increase unit heat differential pressure over the filter bags by 1
Influences the amount of sorbent used and dust collecting efficiencies Use of low NO burners can influence the combustion conditions and promote slaggingfouling due to reducing conditions present
Can have a positive and negative influence on SO removal efficiencies Can cause a reduction in catalyst efficiency in the removal of NObull
Quantity and quality influenced by the properties Saleable byshyproducts can be contaminated by carbon carry-over and trace elements
Quality of FGD waste can be influenced by cWorine and trace elements content
66
Post-combustion performance
annually by a pulverised coal fIred power station are the following
coal consumption ash content of the coal sulphur content bottom ashfly ash ratio fly ash collection efficiency SOx removal efficiency
These in turn influence the land requirement for residue disposal Ugursal and Al Taweel (1990) use the parameters listed above for calculating the area requirement for power station ash and FGD sludge disposal
The characteristics of the solid residue are particularly important where the residue materials must meet specifIcations to be sold (Cerkanowicz and others 1991 Bretz 1991b) For example the key requirement for the use of fly ash in cement production is the carbon content (Tisch and others 1990) A typical specifIcation is less than 5 carbon A coal change which degrades mill performance affects flame stability or reduces the rate of char oxidation such as in the case of low NOx combustion measures may increase the carbon content enough to exceed this carbon specifIcation (Zelkowski and Riepe 1987) Such a change would result in a considerable net cost to the utility since the fly ash would need to be disposed in a landfill at some cost instead of being sold for cement production at a profIt (Folsom and others 1986b) Similar problems can occur with FGD solid residue use for gypsum production The chlorine content of the coal is becoming an increasingly important consideration for power stations that have an established market for the gypsum produced from FGD residue as the chlorine impacts the quality of the gypsum for sale
The trace element content of combustion residues is an important consideration for both disposal and utilisation purposes (Clarke and Sloss 1992) The concentrations in power station residues may vary signifIcantly depending primarily on the coal used and on the cleaning techniques and combustion methods employed Therefore if the residue disposal strategy of the power station includes residue utilisation then a detailed knowledge of trace element content of the coal being fired is essential An lEA Coal Research report Trace elements emissions from coal combustion and gasification examines the behaviour of trace elements within these systems in more detail than can be discussed here (Clarke and Sloss 1992)
53 Comments The properties of coal affect the performance of the post combustion components of the power station These impacts are summarised in Table 24 As has also been highlighted in Chapters 3 and 4 many empirical relationships have been developed and used to describe the problems that are encountered in these systems but there are some signifIcant uncertainties related to many assumptions made For the post-combustion components these can include
fly ash collection - there is considerable disagreement as to the best method of measuring fly ash resistivity There is no correlation between coal composition and fly ash fIneness technologies for controlling gaseous emissions - there is no adequate means to predict NOx emissions
Whenever a change in coal supply is considered it is important to pay attention to the downstream effects
67
6 Coal-related effects on overall power station performance and costs
The production of electricity at the lowest busbar cost at a coal-fired power station depends on
the capital costs of the power station the delivered cost of the coal consumed overall power station performance the way in which the capital costs are financed during the construction and operating life of the station (interest depreciation profits taxes etc) the cost of decommissioning the power station at the end of its life
Coal quality can affect each of the above factors except for the last two components The main aim of this chapter is to look at coal-related effects on overall power station performance and costs
61 Capital costs The capital costs in most cases are affected by the range of coal qualities envisaged at the design stage (Mellanby-Lee 1986) In a study done by Ebasco Services Inc (Cagnetta and Zelensky 1983) the capital costs of a new power station are estimated for a wide range coal and a dedicated coal specification The wide range coal characteristics encompass about 90 of the recoverable reserves east of the Mississippi in the USA while the dedicated coal characteristics vary over a much narrower range Table 25 gives details of coal quality values for both types of coal and the costs with respect to the design for the wide range coal type It can be seen that the cost of a power station to bum a wide range of coals is $54 million more expensive than the design for a dedicated coal supply
A decision to bum high sulphur coal in a power station may necessitate the installation of an FGD or other emission control technologies FGD the best established technology to control emissions can be costly typically adding up to 20 or more to the total capital cost for new capacity and around
Table 25 The effect of coal quality on the costs of a new power station (Cagnetta and Zelensky 1983)
Coal Wide range Dedicated
Heating value GIlt 2442-3315 2949-3282 Moisture 10-150 10-65 Ash 60-180 64-146 Sulphur 05-40 17-32 HGI 40-64 45-60
Power station capital costs $ million coal handling +03 base steam generators +66 base ash handling +10 base ESP +417 base FGD +46 base total 1086 1032
Figures are for a 2 x 600 MW net power station they exclude coal costs
30 to power station capital costs when retrofitted to existing power stations (Vernon 1989) Control costs for NOx an additional environmental consideration are lower adding some 6-10 to the total capital costs of large new plants but as with FGD costing more when retrofitted (Hjalmarsson 1990 Daniel 1991)
62 Cost of coal The cost of internationally traded coal varies considerably For the third quarter of 1991 the lEA reported that the average cif coal import prices in Europe Japan and the USA were 4927 4998 and 3425 US$lMt respectively The range of prices to the two major importing areas that is the EC and Japan were 4320-5068 US$lMt and 4451-5180 US$lMt respectively The variation in prices is influenced by geographic location transport costs and coal quality The lEA reported that countries describe thermal coal using different average coal quality values for example the lower
68
Coal-related effects on overall power station performance and costs
heating value of a steam coal as detennined by the EC is 2617 MJkg (6251 kcalkg) compared with Japan at 2466 MJkg (5890 kcalkg) (International Energy Agency 1992)
Ash contents of traded coal vary substantially from under 5 for Colombias Cerrej6n coal for example to over 20 for typical South African thermal coals (see Table 26) Most of the traded coals have an ash content below 15 with the average being around 12-13 Given the associated costs of ash handling and disposal (see Section 63) coals with high ash contents will attract a lower price than those with lower ash even when corrected for heat content because of the application of penalties Many utilities and traders have a formula for calculating price penalties in relation to ash content Estimates of penalties vary depending upon the equipment in place It is probable given the increasing concern about the disposal of combustion residues that these ash penalties may increase during the next decade and a half
Table 26 Ash contents of traded coals (Doyle 1989)
Low Medium High lt8 8-15 gt15
Colombia Canada South Africa Venezuela China Indonesia Australia
Poland USA South Africa
While ash characteristics have traditionally most worried boiler managers sulphur content has become more significant in recent years because it is the primary determinant of the cleanliness of a coal in relation to S02 emission standards Most traded coal is low sulphur Only a small volume has a sulphur content above 15 However as S02 emission standards have tightened there has been a noticeable downward shift in what is considered low sulphur coal The defmition of low sulphur is now perceived to be below 09-10 and an increasing amount of traded materials now below 06 Various studies have deduced that low sulphur coal could command a premium price of up to one third greater than high sulphur coal (Doyle 1989 Calarco and Bennett 1989) Doyle (1989) also reported that at the most general level the low sulphur premium must be less than or equal to the smaller of either FGD costs or coal cleaning costs Otherwise buyers would take higher sulphur coals In practice the situation is more complicated For some users regulations may make the use of low sulphur coal or FGD equipment compulsory An excessive premium on low sulphur coal may also bring gas frring inter-fuel competition into consideration
63 Power station performance and costs
Several investigations of coal qualitypower station performance relationships have been conducted by utilities and other organisations These have been reviewed by
Folsom and others (1986a) In general the manner in which station performance evaluation of the impacts of coal quality have been assessed was by considering the following four performance categories
capacity - the capability of the unit to produce design load
heat rate - a measure of the net energy conversion efficiency
maintenance - the cost of maintaining all components in suitable working order
availability - a measure of the degree to which the unit can be operated when required
A summary of coal quality effects on these categories is presented under these headings
631 Capacity
The utility industry uses a number of definitions for station capacity In this discussion the term capacity will refer to the maximum rate of power generation for a specific unit under given operating conditions It should be noted that changes in this definition of capacity mayor may not be of economic consequence to a utility The need to operate a specific unit depends on
utilitys power demand available capacity system-wide relative costs of operating the specific unit compared to other available units
Fuel quality can affect unit capacity in a number of ways An analysis of the way fuel quality affects the capacity of each component of a generating station can reveal the total impact This analysis must start with the component most critical in detennining power station capacity The next step is to estimate the effects on less critical components The effects of successively less critical components may be interactive with the impacts on more critical components In some cases a change in fuel quality may affect one component to such an extent that it becomes the most critical item
Since a coal-fired steam-electric unit has a large number of components detailed analysis can be quite complex In Chapters 3-5 the effects of coal characteristics on the seven major components of a power station were described The capacity of the component was often influenced by these effects In many cases these effects could be evaluated with reasonable accuracy using existing straight forward engineering procedures In other cases assumptions on coal behaviour had to be made to facilitate the calculations As was summarised in Sections 34 43 and 53 there are some significant uncertainties related to many assumptions made
632 Heat rate
Heat rate (HR) is an index of the overall efficiency of a power station expressed as the heat input in the form of coal (Qin (MJIhr or BtuIhr)) required to produce one unit of electrical energy It may be expressed on a gross or net basis Gross heat rate (GHR) is based on the total or gross power
69
Coal-related effects on overall power station performance and costs
(GP) produced by the turbine generator while the net heat rate (NHR) is based on the GP reduced by the auxiliary power (AP) NHR depends on the turbine heat rate (THR) boiler efficiency (BE) GP and AP and it may be calculated as follows
NHR= THR x GP BE (GP-AP)
The coal changes which affect heat rate are associated primarily with boiler thermal efficiency auxiliary power consumption and turbine cycle efficiency (via changes in steam conditions) The following three sections describe how coal characteristics can affect boiler efficiency auxiliary power consumption and turbine heat rate respectively
Boiler efficiency The most widely used method of evaluating the impacts of coal characteristics on boiler efficiency is to assess the heat losses from the boiler and to assume that the remainder of the heat is absorbed to produce superheated or reheated steam This approach has the advantage of eliminating direct measurement or calculation of heat transfer rates in each section of the boiler which are quite complex but can only be carried out with suitable probes on fully instrumented boilers
The procedure involves the calculation of around six types of heat losses (Corson 1988) These can be
dry flue gas loss heat losses due to fuel moisture heat loss due to moisture produced from the combustion of hydrogen in the fuel heat loss due to combustibles and sensible heat in the ash
heat loss due to radiation unaccounted heat losses
Dry flue gas loss which is usually the largest factor affecting boiler efficiency increases with higher exit gas temperatures or excess air values Every 35degC to 40degC increment in exit gas temperature is reported to reduce boiler efficiency by 1 A 1 increase in excess air by itself decreases boiler efficiency by 005 ill most boilers however increased excess air leads to higher flue gas exit temperatures (FGET) Consequently increases in excess air can have a twofold effect on unit efficiency (Singer 1991) Calculations of excess air requirements depend on
flame stability carbon burnout slagging and furnaceconvective pass heat transfer considerations
These are difficult to predict with existing correlations
Losses due to moisture and fuel hydrogen are calculated easily from the coal analysis data using straight forward chemical and physical relationships
illcomplete combustion is manifest primarily by carbon in the bottom and fly ash The carbon content of the ash is difficult to predict and is affected by the slagging and fouling characteristics of the coal If the furnace is large enough to avoid slagging and fouling problems the carbon content of the ash is often less than about 5 For any furnace the carbon content of the ash tends to increase as the excess air decreases Also carbon loss may vary with char reactivity which depends on coal characteristics such as particle size
Table 27 Calculation of boiler heat losses (Folsom and others 1986a)
Loss
Dry gas
Fuel moisture
Fuel hydrogen
Combustibles
Radiation
Data required
Coal ultimate analysis Excess air Exhaust temperature Product specific heat
Coal moisture content Exhaust temperature H20 latent and specific heat
Coal hydrogen content Exhaust temperature H20 latent and specific heat
Carbon content of ash Coal carbon and ash content Heating value of carbon
Total heat output Maximum continuous rating
Assumption Comments
Complete combustion based Carbon corrected for on ultimate analysis carbon lost to ash shy
usually the largest loss
Complete combustion of fuel hydrogen to H20
Neglects CO and HxCy emissions which are usually negligible
External surface temperature Usually less than 05 Ambient air velocity over surfaces Independent of coal characteristics Calculated using ABMA chart
Unaccounted None Allowance for Usually estimated as about 05 bottom ash quenching Independent of coal characteristics CO and HxCy emissions Miscellaneous
70
Coal-related effects on overall power station performance and costs
rank and petrographic composition and combustion as the heat absorption pattern in the boiler changes Also if conditions At present there is no satisfactory method of the acid dew point of the flue gases changes the operators predicting the carbon content of the fly ash andor may need to adjust furnace exit gas temperature (FEGT) so combustibles loss based on standard coal analysis alone as to maintain the minimum air heater metal temperature Most coal quality analyses merely assume that the carbon above the acid dew point to avoid air heater corrosion loss guarantee provided by a boiler manufacturer will not be Whilst largely empirical procedures are used the actual exceeded This is usually in the range of 5 since fly ash amount of available data are insufficient to determine the with higher carbon content has less value for subsequent use accuracy of this approach Thus improved procedures need such as feed stock for cement manufacture (see to be developed and evaluated for assessing excess air flue Section 524) For coals with 10 ash and 60 carbon as gas exhaust temperature and combustible loss as a function fired 5 in the fly ash corresponds to a carbon utilisation of coal characteristics for a given furnace efficiency of 9912 (Folsom and others 1986a)
A summary of the data required for calculating heat losses is Procedures have been developed to predict combustibles loss given in Table 27 Combustion handbooks published by the based on furnace models An example of this is a boiler manufacturers include detailed descriptions of 3-dimensional model developed by the Energy and procedures for evaluating these losses (Babcock amp Wilcox Environmental Research Corporation USA (EER) This 1978 Singer 1991) These calculations are complex but includes a char combustion sub-model which evaluates the nevertheless straightforward and can be automated via a combustion process as a function of the micro-environment computer program easily An illustration of typical boiler surrounding individual char particles (WU and others 1990) losses for four Australian Queensland steaming coals is given Several more simplified approaches to carbon loss prediction in Table 28 have been developed All involve burning the coal under controlled laboratory conditions measuring the carbon loss Auxiliary power consumption and then scaling these data to full-scale units (see Power station auxiliaries consume power for Section 421)
coal handling In the calculation of boiler efficiency the flue gas exit mills temperature (FGET) is usually assumed constant However a feedwater pumps detailed evaluation should consider that the FGET may vary soot blowing
Table 28 Typical boiler losses for four Australian Queensland steaming coals (St Baker 1983)
Coal type A B C D
As-burnt - Total moisture 70 160 100 110 -Ash 214 143 100 280 -Carbon 581 535 676 487 - Nitrogen 11 09 15 09 - Hydrogen 39 34 38 32 - Sulphur 04 03 02 02 -Oxygen 76 111 64 75 Unburnt carbon 05 05 05 05
Gross heating value GJt 2412 2120 2738 1998 Latent heat of evaporation 102 112 106 096 of H20 from coal OJt Net heat value GJt 2310 2008 2632 1902 Unburnt carbon loss GJt 017 017 017 017 Radiation amp other losses OJt 013 012 015 011 Total dry air per tonne of coal tit 9130 8180 10433 7556 Sensible heat in combustion air OJt 221 196 252 183 Total heat available OJt 2501 2175 2852 2057 Overall total combustion products t 10130 9108 11433 8556 Exit flue gases (at 130degC) OJt 0108 0110 0108 0110 Flue gas exit loss GJt 110 100 123 094
Heat balance Heat input in coal 1000 1000 1000 1000 - Flue gas exit loss 46 47 45 47 - Heat loss due to H20 42 52 39 48 - Loss to unburnt carbon 07 08 06 09 - Loss to radiation etc 05 05 05 05
Net heat to watersteam 900 888 905 891
71
----
-----------
Coal-related effects on overall power station performance and costs
fans 200 shyparticulate control
flue gas desulphurisation shy-~ 0
Auxiliary power is typically in the range of 50 to 100 of gross power and is highly dependent on the specific power station design However coal characteristics also affect power consumption for most of these components although the impacts in many cases are not large and can be evaluated by considering trends
The primary factors impacting the power requirements for coal handling are the design of the systems and the desired coal flow rate The design of coal handling systems varies substantially and power requirements can be determined accurately by considering the details of the specific designs Since coal handling equipment normally operates intermittently any change in coal flow rate will change the duty cycle of the equipment and the power consumption will be approximately proportional to the coal flow rate This assumes that no modifications to the coal handling equipment are made to increase capacity In some analyses the coal flow rate is assumed to be inversely proportional to the coal heating rate on the assumption that the total heat input remains constant However as discussed earlier any change in heating value may change the performance of several other power station components and impact overall heat rate This compounding effect means that changes in coal flow rate are often greater than would be expected based on heating value alone
The power required for coal grinding depends on mill design characteristics of the coal feed including its grindability and size distribution and the mill operating conditions including the coal flow rate and pulverised coal size distribution The manufacturers have developed power consumption correlations based primarily on Hardgrove grindability index (HGI) Cortsen (1983) reported that the power consumption of the mills at a Danish utility was mainly dependent on the grindability of coal In evaluating mill performance it must be recognised that for a given design the operating parameters are linked It is not possible to vary the coal flow rate HGI and pulverised coal size distribution independently This is illustrated in Figure 25 which shows the effects of an independent change of coal grindability on the performance of a pilot vertical spindle mill (Luckie and others 1980) However Folsom and others (1986a) put forward the theory that reasonably accurate evaluation of coal changes have been made by assuming that the power consumption varies linearly with the coal flow rate independent of coal grindability in cases where variations in HGI are small St Baker (1983) reported that the power consumption of mills increases with increases in moisture content
There are few data that can be used to determine the number of soot blowers and frequency of operation for a specific coal The usual procedure is to select the wall blower array based on experience with similar coals and to set the wall blower operating schedule during normal boiler operation to minimise slagging and fouling problems The actual frequency of soot blowing will depend on the severity of
a5 sect 5 0
Cii 0 ()
100 ---shy--constant coal flow rate ---
0
40 50 60 70
Hardgrove grindability index (HGI)
80
100 -
o 40 50 60 70 80
Hardgrove grindability index (HGI)
10 shy
5
o 40 50 60 70 80
Hardgrove grindability index (HGI)
Figure 25 Effects of grindability on vertical spindle pulveriser performance (Luckie and others 1980)
slagging and fouling In some cases certain boiler stages may be blown unnecessarily and incur a heat rate penalty Excessive blowing can result in erosion of the tube surfaces which leads to premature tube failure and subsequent forced outages Proper blowing schemes are critical in achieving target steam and flue gas exit temperatures Wall blowers can utilise steam or air as the blowing medium The steam consumption can be treated as auxiliary steam use and can be evaluated in terms of its impact on heat rate Compressed air is generated in motor driven air compressors and the compressor power consumption can be evaluated as part of the auxiliary power load which has a greater impact on overall heat rate
The power consumption of fans in a power station is based
72
Coal-related effects on overall power station performance and costs
on the required flow rate and pressure rise fan design and the method of fan control Given these parameters the power requirements may be calculated easily based on standard fan analysis procedures In general a coal change that causes an increase in flow rate or pressure rise for example as a result of a reduction of cross-sectional flow area due to ash deposit bridges will increase fan power requirements (Borio and Levasseur 1986)
Essentially all the power consumed by an electrostatic precipitator for particulate control is used to generate the corona The power consumed to charge and deposit particulates is negligible while collection efficiency increases with corona power (Folsom and others 1986b)
The auxiliary power requirements of the flue gas desulphurisation (FGD) systems depend on the equipment designs which vary substantially among operational systems employed internationally A number of reference manuals have been published which provide procedures for evaluating the impacts of coal quality on flue gas desulphurisation systems These manuals should be consulted to conduct a detailed evaluation of the impact of coal characteristics on flue gas desulphurisation system auxiliary power (Dacey and Cope 1986) Generally the FGD facility will require more auxiliary power when operating with a high sulphur coal
Turbine heat rate Turbine heat rate is an index of the efficiency of the steam cycle and generator set in converting heat supplied to the turbine in the form of superheated or reheated steam to electrical power The turbine heat rate depends on the specific design of the turbine cycle as well as the operating conditions principally the steam supply and the discharge conditions
Since the coal does not come into contact with the steam coal quality impacts on turbine heat rate are neglected in many analyses However coal quality can impact the steam supply characteristics by changing the distribution of heat absorption among the various heat transfer surfaces in the boiler as discussed earlier in this section It should be noted that this is distinct from the total quantity of heat absorbed which is related to the boiler efficiency Changes in the heat distribution may result in an inability to achieve the required superheat or reheat temperatures or necessitate excessive attemperation to moderate steam temperature Both effects can degrade turbine cycle efficiency significantly
Evaluation of the effects of coal characteristics on steam temperature and hence turbine heat rate requires analysis of the radiative and convective heat transfer occurring in the various boiler sections and consideration of the options available to boiler operators to vary steam conditions (see also Section 42) A wide range of heat transfer models of varying complexity for the furnace and convective surfaces have been created (Shida and others 1984 Robinson 1985 Boyd and Kent 1986 Fiveland and Wessel 1988 Pronobis 1989) (see also Section 72)
The effects of coal characteristics on heat transfer evaluated by these methods can be grouped into three categories
gas flow rate changes through the furnace and the tube bank due to the volume of combustion products which mainly affects convective heat transfer radiative heat transfer changes due to varying coal composition combustion conditions and particle deposition heat transfer change due to deposits resulting from slagging and fouling
The volume of combustion products from a coal of arbitrary composition can be evaluated easily by simple combustion principles given the firing rate and excess air The impact of volumetric air flow rate on radiant and convective pass heat transfer can be evaluated using the models The effects of coal composition on radiative heat transfer are more difficult to evaluate As coal composition changes the radiative characteristics of the reacting gases and particles change along with the characteristics of the wall deposits The emissivity and thermal resistance of the ash deposits have the greatest impacts Similarly the effects of fouling deposits on convective pass heat transfer are difficult to evaluate However tests of slagging in pilot-scale furnaces indicate that potassium sodium sulphur ash fusion temperature ash particle size and total ash might be important (Wagoner 1988 Pohl 1990) In contrast Wain and others (1992) have shown in a study of slags from UK power stations that the thermal conductivity of wall deposits is primarily influenced by the physical properties of the slag such as its porosity rather than by its chemical composition
Deposits are formed over the perimeter of the tube quite irregularly so that the effective shapes of the tubes immersed in the flow of flue gases are completely changed This not only impairs the efficiency of the heat exchanger because of the necessity to overcome the thermal resistance layer but leads also to changes of the heat transfer coefficient brought about by the changed flow pattern and the effective shape of the tube cross-sections In the course of time the properties of the deposits also change resulting in further changes of thermal resistance (Pronobis 1989) The ability to remove the deposit by soot blowing and recovery of lost heat transfer is also important and is determined by the thickness strength and phase of the deposit and the available soot blowing power (Wagoner 1988)
If the effects of these changes on heat transfer can be determined or assumed the turbine heat rate can be evaluated via thermodynamic analysis Several computer programs have been developed to analyse complex thermodynamic cycles The limiting factor of the models is the specification of the input parameters
In general the heat rate correlations are perceived to be adequate providing that certain key parameters such as excess air carbon loss and mineral matter impacts can be specified In many analyses these are assumed since coal quality impact data are usually not available An example of the cost implications of a coal change on heat rate for a 1000 MW boiler was compiled by Folsom and others (1986a) Figure 26 illustrates this effect based on various assumptions conceming the unit characteristics The relatively large change in coal quality is shown to result in a
73
Coal-related effects on overall power station performance and costs
Change in coal characteristics
Coal ash increase 10
Coal moisture increase 5
Coal heating value decrease 15
Char reactivity decrease
- carbon in ash increase 2
- excess air increase 0
Ash deposition
- superheat decrease 50degC
- reheat at temperature increase 5
- exhaust temperature increase 10
Loss component Cost impact
ESP
Coal handling
Carbon loss
Dry flue gas
Moisture loss
Fans
Turbine efficiency
070
010
055
079
048
066
118
65 capacity factor base line heat rate 10000 Btu kWh thermal efficiency 89 coal heating value 279 MJkg (12000 Btulb) coal ash 10 coal moisture 5 coal carbon 77 and coal cost 35 Sit
Figure 26 Example of cost impact of a coal change on heat rate for a 1000 MW boiler (Folsom and others 1986a)
cost impact in heat rate of $446 millioniy (1986 prices) which is equivalent to an availability loss of about 5
As an alternative to these fairly complex calculations some attempts have been made to correlate coal quality with heat rate and boiler efficiency statistically (Barrett and others 1983 Kemeny 1988)
Several organisations have developed methods to facilitate the calculation of coal quality impacts on heat rate Some of these methods use computer programs to calculate economic effects directly from coal quality data power station design information and economic assumptions Others make use of manual calculations and rely more on engineering judgement and experience with similar coals
The use of both statistical techniques and computer models is discussed in greater detail in Chapter 7
633 Maintenance
While it is widely accepted in the utility industry that coal characteristics can affect maintenance costs primarily via wear by abrasion and erosion and by corrosion of power station components there is at present no effective method for predicting the effects of a coal change on maintenance Utilities use a range of procedures to account for maintenance costs in coal-fired units Whilst these procedures generally meet utility needs they often make it difficult to evaluate actual coal quality impacts For example while the maintenance cost due to a tube failure may be identifiable it may not be possible to determine whether tube failures relate to coal quality water quality structural problems or other effects (Heap and others 1984) Another significant problem is that maintenance costs are due in part to phenomena which should be predictable and form part of scheduled
maintenance routine for example replacement of expendable components (such as worn mill rollers and balls) Unfortunately they are also due to unscheduled failures which may cause partial or full outages It has been demonstrated that both routine maintenance requirements and unscheduled outages can be affected by coal characteristics
The mechanisms involved in wear of components are discussed in more detail in Sections 32 and 422 For many components the major factor affecting wear rates and hence maintenance costs is the mass of material processed This will be directly related to the heating value of the coal and the heat rate of the power station However as discussed in Sections 32 and 422 certain coal minerals are identified as strongly influencing the rate of wear by abrasion in handling equipment and mills In some instances erosion rate depend on power station design and aerodynamic considerations (Walsh and others 1988 Platfoot 1990)
Increases in unscheduled maintenance costs and consequent reduced availability (see Section 634) even involving reduced boiler life which result from excessive boiler flue gas erosion and corrosion can be considerable In a review of the state-of-the-art methods of reducing fireside corrosion and fly ash erosion as factors responsible for tube failures in boilers Wright and others (1988) reported that both of the effects are considered to be major problems only on units burning coal that is rated as very aggressive (high sulphur alkalis and chlorine) or that contains a high percentage of erosive materials such as quartz and ash Fly ash erosion of primary superheater reheater and economiser tubes were considered to be more serious problems than fireside corrosion An interesting observation from the study was that although there were proven permanent solutions for most of the problems encountered such as coal and hardware modifications these were not widely accepted Evidently the
74
Coal-related effects on overall power station performance and costs
costs of these solutions were perceived to compare unfavourably with continued maintenance activities in spite of the inconvenience of several unscheduled outages annually for emergency maintenance
St Baker (1983) reported that a typical 20-day unscheduled outage on a single 350 MW generating unit to repair boiler erosion damage could cost more than A$2 million in 1983 in replacement power costs alone This would amount to more than A$33 million (US$25 million) at 1991 prices
In a study of the use of declining fuel quality in 110 and 200 MW Czechoslovak power stations Teyssler (1988) showed increased maintenance costs due to higher equipment wear Examples of costs were given as Czech crowns 15-25t ash output in 1988 (US$04-07 (1991raquo for the cost of repair and replacement of heating surfaces damaged by erosion a 1 increase in ash content was found to result in at least a 10 higher cost in mill component replacement
Smith (1988) in a paper describing Tennessee Valley Authority s (TVA) experience with switching to improved quality coal presents a comparison of performance variations at the Cumberland power station (2 x 1300 MW) and Paradise power station (2 x 704 MW 1 x 1150 MW) with coal quality over the period 1977-86 The results show that maintenance costs for the boilers burning equipment and ash handling equipment were reduced with improved quality coal Costs dropped by about US$15 millionyon average between 1980 and 1984 at the Cumberland power station In this case the improvement in quality was achieved by cleaning the coal supply Prior to coal washing the units exhibited extensive slagging fouling corrosion and tube leakages Figure 27 shows the effect of a coal quality change that occurred at Cumberland in 1982 The largest change after washing was a reduction in ash content from about 152 to 92 Sulphur was reduced from 35 to 28 and which heating value went up from 249 MJkg (10712 Btulb) to 271 MJkg (11635 Btulb) In contrast
10 o boilers
A burning equipment 9
LD ash handling equipment co en 8~
c Q 7E $ (j) 6 =gt t5 50 u (l) u 4c ro c 2 3c iii ~ 2
I 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986
Figure 27 Adjusted maintenance cost accounts for TVAs Cumberland plant (Smith 1988)
operation and maintenance costs for the Paradise power station do not show dramatic cost improvements on utilisation of washed coals because major modifications and maintenance improvements necessitating significant investment were also made to the station over the same time period TVA believe that damage done to the Cumberland boiler by years of operating with poor quality coal was still causing problems long after the change to washed coal (Smith 1988) This example illustrates the difficulty of obtaining valid information of coal quality effects on maintenance and other power station performance factors independently from the influence of other modifications and changes in operating procedure
Hodde (1988) in an investigation of work conducted by Blake and Robin (1982) which considered the contribution of coal quality effects to total fuel-related operating costs of the Southern Company USA (see Table 29) concluded that whilst the dominant portion of the total fuel-related bill is the delivered cost of fuel comprising about 80 the remaining costs are associated with problems due to coal quality It was shown that approximately three quarters of the quality-related costs are in maintenance and residue disposal From this assessment Hodde (1988) suggested that maintenance costs relate linearly with coal quality in particular ash and could be calculated in advance This figure together with the price of the coal would account for almost 90 of the total costs associated with the coal This simplified approach is adopted in a number of computer models (see Section 72) However the approach has been challenged by a number of other sources (Folsom and others 1986b Mancini and others 1987 Galluzzo and others 1987 Lowe 1988b) who report that maintenance costs are not linearly related to the mass of ash processed by a power station Additionally there is usually a substantial lag between the initial variation in ash content of the fuel and the first experience of its effect on maintenance costs Consequently care should be taken in the use of linearised maintenance cost assessments to allow for the effects of lead times and incubation
In general the relationships between maintenance costs and coal quality are difficult to assess due to four factors the inadequacies of records maintained by utilities the impact of non-coal-related factors power station design variations and delayed effects of coal quality impacts
Table 29 Total fuel costs for power stations of the Southern Company USA (Hodde 1988)
Costs of total For coals with ash content of
15 20
Delivered fuel cost 83 77
Waste disposal cost 5 6 Maintenance cost 7 9 Ash related unavailability 3 4 Other operating costs 2 4 Slagging and fouling -0 -0
Total 100 100
75
r ~ 250 lt9 c o t3 200 J 0 2 a 0 150 3 o a
Ui3 100
50
o 2 (ij 3
~
0 ro Q)r 0 a J
(fJ
0 ~ 0 gt
5 0
(ij 0 c Q)
3 ~ is
CD
~ 2 ro Q)r Q)
a
0 ltJ)
E 0 c 0 U w
c ~
-0 0 Q) u J 0
Ol c 6l Ol ro iii
Coal-related effects on overall power station performance and costs
Table 30 Comparison of reduced boiler availability on the basis of hours in operation and type of fuel (Pasini and Trebbi 1989)
Mean annual All boilers Hours in operation Type of fuel reduced availability lt105 gt105 oil-gas coal
Furnace wall 220 203 270 184 309 Secondary SH 054 032 113 045 075 Reheater 032 032 032 015 075 Primary SH 019 008 051 005 054 Economiser 013 005 036 012 014
Unheated 020 017 029 025 008 Casing 030 025 043 039 009 Others 045 075 048 045 045
Total 433 365 622 370 588
634 Availability
The availability of a power station is important to both system reliability and generating-company profit Improving availability only slightly can save considerably on reserve generating capacity and the cost of replacement power Availability can be defined as the percentage of time that a unit is available for operating regardless of whether electricity is actually generated The total electricity sent out from a power station is affected by the planned shutdowns for maintenance forced down-ratings forced outages and other reductions in its availability (Mellanby-Lee 1986)
While it is clear that availability can be affected by coal quality the nature of the relationship is not well understood Statistical data-gathering studies such as the programme conducted by the North American Electric Reliability Council (NERC) utilising the Generating Availability Data System (GADS) supplied data relating to the component cause of outages and load reduction but were not able to provide information as to why particular components failed (Electrical World 1987) A study conducted by Combustion Engineering USA has gathered information from coal-fired units of 390 MW and larger on the causes of outages and load reductions in nine major equipment categories related to steam generators Included were
water walls superheaters and reheaters economisers furnace soot blowingbottom ash removal equipment convection-section soot blowing and fly ash removal equipment boiler controls fans mills boiler circulating pumps
The study indicated that water wall superheater reheater and economiser tube leaks account for 80-90 of all forced outages whereas coal milling systems accounted for 50 of equivalent down-time hours in load reductions (Llinares and others 1982 Llinares and Lutz 1985) Pasini and Trebbi (1989) reported similar trends of reduced power station availability for ENEL Italy (see Table 30) Mancini and
others (1988) reported that in a study of the top eighteen causes of full and partial outages at coal-fired stations in the USA for the decade from 1971 through 1980 60 of these causes were related to coal-quality (see Figure 28)
A record of boiler tube erosion at two Australian power stations Munmorah (4 x 350 MW) and Liddell (4 x 500 MW) illustrates the considerable costs that can result from excessive flue gas dust burdens in boilers supplied with off-specification coals particularly ash content above the design level They have experience of
up to 7 per annum additional reduced availability due to outages for the repair of boiler tube leaks reduced boiler life before major refurbishment affecting the economic life and gross power station output over
350
300 Coal related outages represent 60 of total power station outages
E
Figure 28 Causes of coal-related outages (Mancini and others 1988)
76
Coal-related effects on overall power station performance and costs
Southern Electric System USA 10 ] D US Industry average
8
7
6
J lLshy 5 ltt w
4 9339
3
2
90
Early units Early units Later units 1975-77 1985-87
Figure 29 Boiler and boiler tubes equivalent availability factor (EAF) record (Richwine and others 1989)
which the power stations initial capital costs could be recovered the necessity to be complemented by a greater level of standby generating capacity in order to ensure adequate reliability of electricity supply to consumers (St Baker 1983)
Richwine and others (1989) reported the results of an availability improvement programme in the Southern Electric System (SES) USA coal-fired units Due to a decline in availability between 1970-76 increased attention was given to this factor such that from 1977 to 1988 an improvement of over 22 percentage points was achieved This turnaround was accomplished by recognising the problems implementing appropriate solutions and adopting new power station practices The problems included coal-related cases such as boiler tube superheater reheater and economiser tube failures arising from fly ash erosion and slagging Figure 29 shows the increase in equivalent availability factor (EAF) achieved when coal quality upgrades were adopted along with tube maintenance during planned outages and the design improvements of later units to incorporate a wider range of coals while maintaining high reliability Problems encountered with mill operation were recognised as being a result of coal characteristics Many units experienced outages due to fires and flow problems due to high moisture coal
It has been suggested that a 5 increased outage rate for a power station designed for a 30 ash coal compared for one designed for 15 ash is a reasonable allowance for possible loss of availability (ERM Consultants 1983)
Due to the undefinable relationship between availability loss and coal characteristics engineering correlations cannot be used directly to evaluate the impacts of coal quality on availability At present the only way to calculate availability loss due to particular coal parameters seems to be to correlate
performance observations in the operating boiler with coal quality data Illustrations of these type of observations have been given above On a larger scale than single power station observations the statistical studies conducted by TVA (Barrett and others 1982) EPRI (Heap and others 1984) and the National Economic Research Associates (NERA) (Corio 1982) (see also Section 731) provided correlations for availability parameters of boilers with
ash sulphur and the age of the boiler (TVA study) actual ash sulphur and moisture content utilised and differences between actual and design values a complex relationship involving 13 independent variables
Most of the methodologies above resulted in equivalent availability values increasing with ash and sulphur contents which is contrary to expectation The correlation utilising the difference between actual and design coal quality values with availability agreed with expectation in that the availability of a power station should be degraded by deviation from the design coal specification A more detailed account of statistical studies is given in Section 731
64 Comments In any final analysis the economic trade offs which take into account system availability cost of coal (at various quality levels) maintenance costs substitute fuel and capacity costs station replacement costs etc must be analysed for each operating situation Only then can any meaningful and specific conclusions about the cost impact of coal quality on the cost of electricity be made Final judgements are often required to compare these costs with other factors such as diversity of supply reliability control of emissions for environmental reasons balance of trade and currency availabilities in order to make final coal selection decisions
Whichever judgement is made it is widely accepted that the capacity availability and cost of operation of each individual boiler are materially affected by the quality of coal fed to it It is generally believed that availability does not depend on the quality of the design coal and will only be affected if the actual coal burnt is outside the design range (Cagnetta and Zelensky 1983) However experience at some stations have shown that substantial losses in availability or down ratings can occur when the quality of the coal used is not outside the design range A summary of these effects is shown in Table 31 The missing links though in coal quality evaluations are the lack of information concerning power station performance and the ability to attach a price to a change in performance as a result of a change in coal quality
There is also the problem that some affects of a change in coal quality require time to show themselves Proper allowance must also be made for this incubation period
Hitherto the accounting systems of many utilities have not been designed to identify easily the costs associated with coal quality impacts (Skinner 1988) These systems need to
77
Coal-related effects on overall power station performance and costs
Table 31 Examples of boiler fireside variables station and cost components which may be affected by those variables when coal quality is changed (Sotter and others 1986)
Variable type Boiler design Operating conditions cost component
affected Coal quality
Capacity Ash size distribution - organic associations - separate species Moisture content Hardgrove grindability index Sulphur content
Heat rate illtimate analysis Moisture content Slow burning macerals Slagging fouling indices (Steam temperature control)
Maintenance Ash content Ash composition (abrasiveness slagging tendency)
Availability Ash Na 0 CaO Fez03 SiOz etc
be updated and improved if utilities wish to take full advantage of new tools that are becoming available In particular improved data are required to support the
Number of mills Precipitator collecting area
Burner type Furnace size
Number and placement of soot blowers
Heat releasefurnace area Convective tube spacing
Excess air
Excess air Coal particle sizes Burner settings
Load history
Load history Soot blowing interval
increasingly sophisticated computer models which can be used to predict the effect of fuel quality on station performance
78
7 Computer models
The decision to buy particular quality coals from either local interstate or from international sources must include a quantitative evaluation of the impact of coal quality on performance of the power station and ultimately the cost of electric power generation As has been demonstrated in Chapter 6 and illustrated further in this chapter the cheapest coal to buy does not necessarily produce the cheapest electricity Because of the large number of processes involved in the coal-to-electricity chain and the complicated nature of coal-power station interactions engineering and economic evaluation studies are usually both time consuming and costly The methodologies adopted can range from manual calculations and a reliance on practical experience with similar coals through to elaborate computer models which calculate performance and resulting economic impacts directly from coal quality data power station design information and economic factors Use of a computer based model to quantify the impact of coal and system parameters on the cost of electrical generation could substantially reduce the time and cost of these studies In theory such a model would be used to evaluate various approaches and the most economic action could be selected with relative ease (Ugursal and others 1990) However it should be noted that the results from the models are only as good as the data used in particular the coal properties measured to predict combustion performance
For the purpose of this report the types of models available for the evaluation of part or all of the coal-to-electricity chain (see Figure 1) have been identified as belonging to one of four categories described below
least cost coalcoal blend models that assess the cost of coals and their associated transport costs They can calculate suitable coal blends according to power station design specifications to provide the lowest cost purchasing plan They may also include allowances for some maintenance and disposal factors
component evaluation models that predict the performanceefficiency of the subsystems of the power station such as mills boiler ESPs unit models that offer coal quality impact evaluation of an entire power station and in some cases attempt to supply costs of the impacts on generation Two methods most commonly put forward as evaluation techniques include
statistically-derived regression analyses leading to overall power station inputoutput models developed for specifying general utility power station requirements These models however do not usually contain detailed predictions of system operation or design requirements
systems engineering analysis for defining relative impacts of fuel properties on each systems performance These types of models are being developed by both equipment manufacturers and research contractors and utilise in addition to fuel property data (that is proximate and ultimate analyses and slagging and fouling indices) special bench-scale measurements of key parameters and pilot-scale data These data combined with the proprietary models can allow for the determination of operating limits for specific units
integrated site models that bring together the information from unit models systems performance and other models and are integrated directly into the control room data system
In this chapter brief examples of the above methodologies are described with particular emphasis given to unit models which are known to include coal quality impact assessments Although particular attention is given to coal specification details used by the models the overall intention is to provide a cross-section of the procedures and the capabilities of the various methodologies
79
Computer models
71 Least cost coalcoal blend models
Least cost models in most cases use linear relationships for the evaluation and purchasing of fuels for power stations The technique is used to find the lowest cost purchasing plan for a utility fuel buyer from among a large number of fuel supplies available and will meet the constraints imposed by the fuel supplies and by the utilityS system The programs are usually designed to run on personal computers and to be user-friendly (Allman 1987 Bek 1987 Hodde 1988 Maher and Smith 1990)
Examples of this type of model include the International Coal Value Model (ICVM) (Maher and Smith 1990) Least Cost Fuel System (LCFS) (Hodde 1988) and Perfectblend (Bck 1987) and Steam coal blending plan (Allman 1987 1991) for blending coals
Least cost coalcoal blend models are reported to have the ability to conduct an economic evaluation of thermal coals as traded on the world market The main users of the models are identified as power companies buying coals of various properties and costs from a number of sources In many cases
blending of coals would also be employed The coals would be selected by the model in accordance with the coal specification requirements of the power stations based on their design and operating experience They are designed as a tool to determine the real cost of coal and energy at the inlet of the power station being considered (see Figure 1 Sections 1-4 of the coal-to-electricity chain) They permit comparison of all coal properties within allowable power station coal specifications including other coals and blends It allows for the blending of a large number of coals in any desired proportions (Maher and Smith 1990) Examples of the types of input data required and the items included in the results for a Least cost model are given in Tables 32 and 33
This type of model does not apply merits or demerits in value for particular properties for example sulphur The reason given by the developers is that the effect of such properties is very site-specific being dependent on the design of the power station and accessories for example flue-gas desulphurisation environmental regulations applying residue disposal costs etc
Hodde (1988) illustrated the use of the Least Cost Fuel System model by considering a utility system with three
Table 32 Model input output data -International Coal Value Model (ICVM) (Maher amp Smith 1990)
Developer Coal input Generating unit input Key output
Joint Coal Board CSIRO Australia
Gross specific energy Total moisture Proximate analysis Elemental analysis Chlorine Phosphorus Free swelling index Hardgrove index Ash fusion temperatures degC Top size mm Fines ltlmm Sulphur form Ash analysis Cost fob cif Currencies amp
exchange rates Ocean freight costs Insurance costs Handling costs
Power station power output MW Generated thermal efficiency Capacity factor
Gross and net specific energy and other properties calculated to different bases and units
Slagging and fouling tendencies Average blend properties with non-linearity warnings CoalconsumptionUy Ash production Uy Cost of coal at pulverisers in various currencies on a
tonne per consignment and per energy unit basis Thermal coal database
Table 33 Comparison of coal energy costs based on gross heating value (at power station pulverisers) - in order of increasing cost (Maher and Smith 1990)
Coal Cost US$GJ Total Specifications moisture
ash VM gross specific energy MJlkg
BBB 206 90 1193 330 2953 AAA 212 95 1238 316 2909 Blend 2 220 84 1434 288 2903 Blend 1 222 86 1406 291 2901 CCC 229 80 1596 260 2869
80
Computer models
coal-fired power stations evaluating the purchase of coal from eleven coal sources supplying contract and spot deliveries Like the ICVM model the objective function to be minimised includes the sum of the fob mine coal cost transport cost and coal quality costs for all three stations on the system But unlike the ICVM the LCFS includes additional costs related to coal quality that are net of the following
maintenance costs assumed to be linearly proportional to the tons of ash processed by each power station ash disposal costs also assumed to be linearly proportional to the tons of coal burned at each station fuel handling costs assumed to be linearly proportional to the tons of coal burned at each station FGD operation and maintenance cost and FGD residue disposal costs assumed to be linearly proportional to the tons of sulphur removed from the flue gas revenue from the sale of ash for construction material assumed to be linearly proportional to the ash content of the fuel
These factors are calculated separately and fed into the LCFS model Additional constraints can be added for utility application For example some utilities are located in regions which have legislated that a certain fraction of the coal burned for power production must be sourced from the region
These programs make only limited provision for coal quality because most of the effects on costs are non-linear so that they cannot be accommodated by these models Warnings are issued by some models of the non-linear behaviour of coal blend properties for example Hardgrove grindability index ash fusion temperatures and ash analysis
Coal quality impacts that are not assessed by the simple models include
slagging and fouling costs cost of reduced boiler availability impacts of coal quality on gross power station heat rate and boiler efficiency impacts of coal quality on the capacity of various station systems including mills fans and ash handling systems
72 Component evaluation models Since the mid-1970s boiler manufacturers utilities and other research centres have been developing advanced numerical system models that can be used to optimise performance of power station components and hence improve overall system performance Most of the development effort has been directed to modelling the boiler With the increasing availability of substantial computing power numerical simulation of combustion systems is now feasible and provides a new engineering tool for evaluating designs and the complex interactions in the flow and combustion processes More recently the techniques have been applied to improve understanding of NOx formation and control in increasingly complex combustion systems For boilers the intricacy of the models range from single zoned one-dimensional (I-D) models
that predict combustion and thermal efficiency for boilers with staged or unstaged combustion systems (Smith and Smoot 1987 Hobbs and Smith 1990 Misra and Essenhigh 1990) to models attempting to solve the fully elliptic multi-zoned three-dimensional systems with finite difference approximations of the conservation equations for mass momentum turbulence combustion and heat transfer (Thielen and others 1987 Boyd and Lowe 1988 Gomer 1988 Jarnaluddin and Fiveland 1990 Luo and others 1991) A widely used boiler computer code known as FLUENT has also been applied to model PF boilers (Tominaga and Sato 1989 Swithenbank and others 1988 Vissar and others 1987 Lockwood and Mahmud 1989) Other examples are documented in literature and a review of the application of these types of models to addressing both NOx formation and unburned carbon has been presented recently by Latham and others (1991a)
The output from these models includes coal particle trajectories within the boiler predictions of unburned carbon involving coal devolatilisation and char burnout models furnace exit gas temperatures (FEGT) species concentrations heat release and heat absorption (Latham and others 1991a)
The coal characteristics that have been found to have the greatest influence in these boiler models are
ultimate analysis carbon hydrogen nitrogen sulphur oxygen
moisture content volatile matter content ash content heating value particle size distribution
Most of the models do not include provision for the effects of fouling and slagging propensity of a particular coal on heat transfer Work on developing computer models that describes the transformation of mineral matter during combustion the mechanism of ash deposition on surfaces as well as the physical properties of the ash deposit after deposition has been initiated (Hobbs and Smith 1990 Smith and others 1991b Beer and others 1992) Baxter (1992) has recently reported the development of a model that considers ash deposit local viscosity index of refraction and ash composition (ADLVIC) in coal-fIred power stations In contrast to other ash deposition predictor models which are based on the elemental composition of ash ADLVIC is based on the mineralogical description of a coals inorganic matter and can be used to predict changes in these mineral properties with time and their effect on ash deposition as the particles flow through the boiler It has received some validation during a three week test burn in a 600 MW boiler operated by Centrallllinois Public Services The approach of using mineralogical descriptions of a coals inorganic matter has also been utilised in a model called the Slagging Advisor developed by PSI Technologies (Heble and others 1991)
81
Computer models
I
Performance factors
MAXIMUM MILL CAPACITY
INLET AIR TEMPERATURE
GRIND CHARACTERISTICS
POWER ~
I
I
I I
Indicescorrelations
Fineness bull passing 200 mesh bull gt50 mesh
Grindability bull
bull HGI Wear
bull abrasion index bull ash burden bull wear index bull equal life
moisture
Pulverised coal distribution bull Rosin - Rammler distribution
function perameter
Mass throughputMMBtu
HGI
moisture
i
Engineering analysis model
COMPOSITE MILL MODEL
- Maximum capacity bull base capacity (as new - of MCR) bull 10ssMMBtu throughput
- Inlet air temperature bull minimum inlet temperature
- Mill power
I
U)0 ttl
~ 0 Q5
~ 0 0 E
Q Level 1 predictions
Q Level 2 predictions
Figure 3D Mill engineering model analysis approach (Nurick 1988)
Nurick (1988) describes an engineering model for the detennination of performance factors for each major system component as impacted by coal quality The modelling approach for each component is described For example Figure 30 illustrates the analysis approach for the mill engineering model The figure also highlights two levels of prediction capability The first level is based on the manual assessment of indicescorrelations of the coal properties and the second level refers to predictions from correlations obtained from application of the mill model The latter predictions can be included into an overall power station model In this particular case the overall performance model does not include any cost evaluations These models can form part of larger more comprehensive systems engineering unit models as described in Section 73
73 Unit models The development of models to assess the impact of coal quality on overall power station performance was initiated in the 1970s when statistical methods were used to compare historical power station performance and cost data (such as forced outage hours or maintenance costs) with coal use and coal quality data in order to fmd working relationships
More recently engineering-based methods have been employed to predict power station performance directly from coal characteristics by using individual component models as modules in an overall power station model In some of the unit models both statistical assessments and operating experience are employed to produce an overall assessment
731 Statistically-derived regression models
Most statistical studies of coal quality impacts on power station performance have been conducted by utilities and research organisations in the US A notable and extensively publicised statistical study has been performed by Battelle Columbus Laboratories and Hoffman-Hold Incorporated on Tennessee Valley Authoritys (TVA) coal-fired power stations (Barrett and others 1982)
The TVA study was aimed at evaluation of how coal quality impacts on boiler operation and costs Information was collected from nine TVA power stations for the period 1962 to 1980 based on monthly proximate analyses of the coal used power station outages maintenance costs boiler
82
Computer models
Table 34 Boiler groupings in TVA study (Barrett and others 1982)
Plant and unit Size Manufac- Firing Stearn Year put Capacity Coal Firing configuration MWlUnit turer methodsect temperature into
degC COF) commercial gt500 MW lt500 MW Midshy
operation Large Small Eastern Western Wall Tangential
Bull Run 1 950 CE PF-DB 538538degC 1967 j j
(10001OOOdegF) Colbert 1-4 200 BampW PF-DB 566566degC 1955 j j
(l0501050degF) Colbert 5 550 BampW PF-DB 566538degC 1965 j j
(10501OOOdegF) Gallatin 1-2 300 CE PF-DB 566566degC 1956 j j j
(l0501050degF) Gallatin 3-4 328 CE PF-DB 566566degC 1959 j j j
(l0501050degF) John Sevier 1-4 200 CE PF-DB 566566degC 1955-6 j j
(l0501050degF) Johnsonville 1-6 125 CE PF-DB 538538degC 1951-3 j j j
(l 0001 OOOdegF) Johnsonville 7-10 173 FW PF-DB 566538degC 1958-9 j j j
(l 0501OOOdegF) Kingston 1-4 175 CE PF-DB 538538degC 1954 j j j
(l0001OOOdegF) Kingston 5-9 200 CE PF-DB 566566degC 1955 j j j
(l0501050degF) Paradise 1-2 704 BampW Cyc 566538degC 1963 j j
(l 0501OOOdegF) Paradise 3 1150 BampW Cyc 538538degC 1970 j j
(l 0001 OOOdegF) Shawnee 1-10 175 BampW PF-DB 538538degC 1953-6 j j j
(l0001 OOOdegF) Widows Creek 1-6 141 BampW PF-DB 538538degCj[ 1952-4 j j
(l 0001ooodegF) Widows Creek 7-8 550 CE PF-DB 566538degC 1961-5
(l 0501 OOOdegF)
BampW = Babcock amp Wilcox CE = Combustion Engineering FW = Foster Wheeler PF = pulverised fuel Cyc= cyclone fired DB = dry bottom
II Units 1-4 do not have reheat
efficiency and where available griruklbility data The data were organised into 15 groups of similar boilers (see Table 34) In addition six aggregates of these 15 groups were assembled based on the capacity of the boilers (greater or less than 500 MW) coal characteristics (Eastern or Western US coal) and firing configuration (wall or tangential)
A variety of statistical techniques including linear and non-linear multiple regression techniques were used to look for meaningful relationships Power station boiler capacity was considered for inclusion in the analysis but dropped due to lack of precise historical data Operating costs other than maintenance costs as determined by TVA were not deemed dependent on coal quality so that analysis in this area was also discontinued (Barrett and others 1983)
In spite of the fact that considerable quantities of data were available within the TVA system it was recognised at the time that the data were not designed to support this study Hence the preferred data such as data on boiler capacity and detailed coal analyses were not always available The investigators sometimes found themselves under severe
limitations They persisted because they believed that the results from what was originally conceived as a limited study might provide utilities with additional useful information for making decisions conceming coal purchase and use
The study identified some quantitative relationships between certain coal quality properties and power station performance and cost However the statistical analyses suffered from the difficulty of co-linearity (or correlated variables) as it was found that the impact of ash and sulphur also generally increased with boiler age due to unavoidable changes in the quality of the coal supplies over time Analysis of data from most TVA units showed that the ash and moisture contents of the coal together with boiler age had the greatest effect on boiler efficiency (see later Figure 32 on page 86)
Availability on the other hand was found to be influenced mainly by ash and sulphur content of the coal although boiler age was still relevant Only outages attributed to equipment that were exposed to coal flue gas or ash were considered in the analysis Over the range of ash fired at TVA power stations (generally 12 to 14) the statistical relationship indicated that for a typical power station the outage hours
83
Computer models
may vary by 360 hy because of changes in ash content alone Likewise over the range of sulphur values for TVA power stations (generally 10 to 50) outage hours at a typical power station may vary by as much as 870 hy due to sulphur alone
Only maintenance costs for coal-related equipment were considered relevant for evaluating the operating cost variations when fIring different coals It was found that ash sulphur content of the coal and power station boiler age were the independent variables although it was determined eventually that age was not a signifIcant factor affecting maintenance costs so that was dropped from further consideration This is somewhat surprising since it is commonly accepted that maintenance costs for most types of equipment increase with equipment age However the effects of age may have been overshadowed by the effects of changes in coal quality with time especially increasing ash
It was reasoned that maintenance costs were not an instantaneous effect of coal quality but rather a result of firing the coal over a period of time To account for delayed or integrated effects over time (for example erosion) the ash and sulphur mass variables were allocated a lag coefficient of several months in the correlations It was reasoned that correlations which suggested that maintenance costs decreased as ash and sulphur mass increased could be regarded as unreasonable because they did not agree with practical experience Consequently these correlations were dropped from further consideration independent of their statistical significance The final correlations were selected as those which produced the highest correlation coefficient value The correlations for the nine separate TVA power stations are listed in Table 35 There appears to be no relationship between the correlation coefficient and the number of units at a power station In addition to these separate power station correlations an overall correlation was developed The optimum correlations were obtained when the lag coefficient for ash and sulphur were set at six and ten months respectively
The reports and reviews of the study stress that the correlations developed for TVA are not necessarily applicable to other power stations because of some significant limitations of the study (Barrett and others 1982 Heap and others 1984 Folsom and others 1986b) First the correlations are based on only one utility - TVA This utility
has its own design philosophy for selecting units its own maintenance and operation strategy and for some units studied there is only one design fuel a bituminous coal Also over the 19 years of data evaluated the TVA units fired only Eastern and mid-Western US coals Thus the range was limited Furthermore TVAs coal purchasing strategy changed such that the coal quality deteriorated to provide higher levels of ash and sulphur as time progressed Thus it was to be expected that the range in ash and sulphur coefficients in the resulting correlations may be at least partially attributable to age effects Overall the study was viewed as an advance in coal quality impact assessment as it had attempted to address the problem of performance prediction and highlighted the inadequacies of coal quality and performance data records
Other studies have been carried out in an attempt to improve and extend the TVA analytical approach Heap and others (1984) reported that EPRI conducted a statistical study to determine whether the TVA methodology could be applied to a more diverse and larger data set that is 25 utilities The study focused on equivalent availability only No attempt was made to separate coal related and other outages Instead a wide range of boiler design parameters were included in the correlation The analysis also utilised the same coal variables as the TVA study ash sulphur and nwisture
As discussed earlier in Section 634 EPRI used an alternative approach to analyse the data In addition to using the log of equivalent availability as the dependent variable and linear ash and sulphur terms based on the as-fired coal data EPRI also used the equivalent availability directly as the dependent variable and the difference between the actual and power station design values of the ash sulphur and moisture content of the fuel as the independent variables This approach makes the effects of coal changes additive terms rather than multiplicative terms as in the TVA approach and the correlation exhibits a relationship that reflected engineering judgement such that the availability of a power station is degraded by deviation from the design coal specification Heap and others (1984) compared the correlations developed by the TVA and EPRI studies by using them to evaluate the effects on a 1000 MWe unit (see Figure 31) The base availability loss due to coal related effects was taken as 97 Base case coal was the design coal and the effects of increasing ash and sulphur content by
Computer models
Correlation predicts maximum 55465 h
100
lt 806
vi Q) OJ co 605 0 -0 Q) range for 6 ro correlations of ~ 40 large unit groups Cii 0 u 0 Ul 200 0
97
0
Base 5 ash increase
8760 (full year)
8000
CfJ
6000 ~ c Q) OJ CIl 5
4000 ~ Q)
ro ~ Cii
2000 8
o
2 sulphur increase
Decreasing coal quality ---
Figure 31 Comparison of TVA and EPRI availability correlations to a 1000 MW boiler (Heap and others 1984)
5 and 2 respectively were calculated The cost of availability loss was taken as $1000000 The ranges of predictions for the TVA correlations based on the 15 groups of similar boilers the six larger groups and the entire database are shown in Figure 31 The correlations based on similar units cover a wide range Note that the large change in coal quality as represented by the changes in ash and sulphur contents in each case evaluated resulted in some of
the correlations predicting greater outage hours than are contained in a year At the other extreme some of the correlations predict that performance would improve with a decrease in coal quality The range of correlations for the larger groups of units was smaller and shows an increase in cost with decrease in coal quality as does the overall correlation The EPRI correlation predicts a greater cost due to coal degradation than the TVA study by a factor of two
A statistical study conducted by the National Economic Research Associates (NERA) USA and reported by Corio (1982) evaluated the impacts of coal quality on gross heat rate and availability based on the performance of 171 coal-fired boilers with capacities greater than 200 MW included in the Edison Electric Institute (EEl) database Only those units which had burned coal exclusively for three or more years were included in the study As with the TVA and EPRI study the coal quality data were limited to the ash sulphur and mnisture contents
The NERA study developed a single correlation with parameters to account for the differences in unit design Table 36 lists the specific variables and coefficients determined in the regression analysis
Both the TVA and NERA coefficients for the correlations are positive indicating that an increase in ash and moisture will increase gross heat rate (GHR) These trends cannot be compared with the TVA boiler efficiency trends exactly as the dependent variables are different Folsom and others (1986b) in a review of the two studies made an approximate comparison by examining the relative changes in the dependent variables (percentage) as ash and moisture content vary This is equivalent to neglecting the NERA GHR correlation The
Table 36 NERA study - gross heat rate correlation (Corio 1982)
Class Variable
Coal quality
Unit designoperation
Ash H2O
Vintage
Age
Output factor
Firing configuration
Stearn conditions
Feedwater pump
Oil firing
Constant
Type
Linear Linear
Linear
Linear
Linear
Switch
Switch
Switch
Switch
Independent
Year - woo
Years
Reciprocal
Cyclone = 1 Other = 0
Supercritical =1 Subcritical = 0
Shaft = 1 Other = 0 Stearn = 11565 Other = 0
Oil = 1
Coefficient
1107 1326
6770
4884
11517640
18485
-11953
7255
31563
273500
Output factor = capacity factor(service hoursperiod hours) expressed as
85
Computer models
150 150
125 125
gf2 0
(l) (l)10 1015 0
co~ sectco gt gt C C (l) ~1lJ (l)
7gtlJ lJ a5 075 ~ a5 07500Q Q (l) (l)~ lJ ~O lJ
lt0~ ~ (l) 0- (l)
OJ OJ~0c 05 c 05 co co
r r U U
025 025
O-JL------------------------------o o 2 4 6 8 10 o 2 4 6 8 10
Ash
Figure 32 Comparison of ash and H20 effects on boiler efficiency and gross heat rate (Folsom and others 1986b)
comparison made is shown in Figure 32 where the selected trends of the overall TVA correlation are plotted against the trends of the NERA correlation The trends for moisture were shown to be similar but the effect of ash was shown to be a factor of about 45 greater for the NERA GHR correlation
More recently the Illinois Power Company (Behnam-Giulani and others 1991) conducted a statistical study based on a database containing NERC and Utility Data Institute (UDI) USA data of 5600 unit-years for coal-frred units from 1982-88 They developed four statistical models to describe heat rate equivalent forced-outage rate operation and maintenance costs and capital addition costs In terms of coal quality impacts the models indicated that
heat rate increased by 127 and 74 kJlkWh for each percentage point increase in ash and moisture content respectively OampM costs increase by 005 with each percentage point increase in ash capital addition costs including costs due to wear and tear increased by 010 $kW of installed capacity with each percentage point increase in ash Capital addition costs were shown to decrease with increasing percentage sulphur content This is contrary to actual experience and is believed to be an erroneous result caused by inaccuracies in the database
Some of the models for example the heat rate model were reported to display good accuracy while some others for example the equivalent forced-outage model proved to be less accurate It was believed that further refinement to the data and methodologies was necessary and for this reason the
study results were recommended for secondary (not primary) computations
It should also be noted that as in the earlier statistical studies only the coal qualities ash moisture and sulphur content were considered in the correlations This highlights the difficulty of obtaining relevant and reliable coal data and corresponding power station data to form such correlations
To summarise statistical methodologies have been shown to have several disadvantages
engineering data are required The TVA study evaluated boiler efficiency only and the NERA study evaluated gross heat rate only The statistical correlations provide only a portion of the information required to evaluate net heat rate the full range of designs cannot be correlated If separate correlations are developed for each unit or group of similar units the accuracies of the correlations are reduced due to the smaller number of data points Increasing the number of independent variables included in the correlation also reduces the statistical importance of each variable concurrent variation If two variables change in sympathy it is difficult to determine the effects of each variable independently coal quality variables are incomplete All the studies primarily correlated performance with the coal ash sulphur and moisture contents only due to the limited availability of coal quality data However several other coal quality parameters can have significant impacts on heat rate These effects cannot be evaluated statistically based on the existing databases
86
Computer models
database accuracies The accuracies of the statistical correlations are limited in part by the accuracies of the input data It is difficult to obtain coal samples that are representative of a full year or even a month of firing database representativeness Statistical correlations are based on limited databases poor accuracy The statistical correlations have fairly wide error bands
multitude of results For example for any given unit in the TVA system boiler efficiency can be evaluated by the individual correlation capacity correlation fuel type correlation and overall correlation Each of these correlations predicts a different effect of ash and moisture content Also the trends of ash and moisture content effects on boiler efficiency and gross heat rate predicted by the four studies are somewhat different particularly for ash
COAL PROPERTIES POWER STATION DATA
Total moisture Unit size Proximate analysis Transport Ultimate analysis Pulverisation
Sulphur Fly ash collection Calorific value Emission limits
HGI Ash disposal Ash fusion temperature
Ash resistivity
HEAT amp MASS BALANCE
(Combustion drying steam production flue gas loss FGD reheat)
STREAM FLOW RATES ampCOMPOSITION
(coal flue gas fly ash)
COAL TRANSPORT HANDLING STOCKPILING
POWER STATION OPERATIONS
(pulverisation electrostatic precipitation flue gas desulphurisation ash disposal)
NET POWER PRODUCTION
OPERATING COSTS
(centskWh as a function of fob coal price)
Figure 33 Outline of CIVEC model operation (Meyers and Atkinson 1991)
87
Computer models
732 Systems engineering analysis CCI Valuation of Energy Coals (CIVEC) Meyers and Atkinson (1991) have reported on the
Several advanced systems engineering-based models have development of ClVEC a techno-economic model by been developed in Australia Canada and the USA in the last Carbon Consulting International Australia to evaluate coals decade The models can be used to predict the overall on the basis of their cost effectiveness in terms of net power coal-related generation cost and become ultimately the generated when applied to a specific generating system The singular basis of comparison for all coals being considered valuation is based on a reference coal whose properties and taking into account the coals effect on availability power fob price are well established station capacity operating costs maintenance costs and power station performance as well as the unit price of the Details of the coals to be studied and specific power station coal In general the method used by systems engineering parameters are entered into the model Heat and mass models is to apply values to coals being considered with balances are determined using these parameters so that the respect to reference coals whose properties fob prices and annual coal requirement may be established The cost effect performance are well established of the coal properties are determined for different sections of
the power station (see Figure 33) The fob price of the study Many models are now available to run on personal coal is subsequently adjusted to give a power production cost computers whereas in the past large main frame systems equivalent to that obtained with the reference coal This were required to carry out the necessary computations model assumes that the overall power station design will be
suitable for the coals studied in terms of parameters such as Several illustrations that use these techniques based on fouling slagging and NOx emissions predictive calculations and comparison with the performance of reference coals and others that utilise a combination of An illustration of the use of ClVEC to assess a suite of these and statistical techniques are presented below In each typical steaming coals from New Zealand Australia and case the coal qualities used and assumptions made in the USA relative to a reference coal was reported by Meyers and model are highlighted Atkinson (1991) The reference coal used in the study was
Table 37 CIVEC coal specifications input (Meyers and Atkinson 1991)
Base Coal A Coal B Coal C CoalD
Total moisture as 80 140 150 100 90
Total ballast as 224 178 228 220 211
Proximate analysis ad Moisture 22 90 70 25 60 Ash 153 40 85 130 125 Volatile matter 258 370 280 315 335 Fixed carbon 567 500 565 530 480
Total sulphur ad 035 025 035 080 110
Heating value MJkg (gross ad) 280 276 281 289 285 MJkg (gross ar) 264 261 256 267 256
Ultimate analysis daf Carbon 839 800 835 840 830 Hydrogen 50 55 45 50 60 Nitrogen 16 20 20 20 15 Oxygen 91 125 96 82 84 Sulphur 04 00 04 08 11
Hardgrove grindability index 49 50 60 50
Freight rate U5$t 1000 1000 1000 1000 1000
total moisture (as) + Ash (as)
Coal quality data were obtained by averaging numerous coal qualities from various mines Coal A Typical New Zealand steaming Coal B Typical low ash low sulphur Australian steaming Coal C Typical high ash high sulphur Australian steaming Coa1D Typical high ash high sulphur US steaming
88
Computer models
Table 38 CIVEC power station operational parameters (Meyers and Atkinson 1991)
Reference coal Coal A Coal B Coal C Coal D
Quantity Mtly 1453 1483 1503 1448 1409 Boiler efficiency 889 880 885 884 878 Mill-capacity factor 093 127 120 108 105 - Power drawn MW 289 216 222 268 268 SOz in flue gas (ppm) 531 363 528 1168 1636
(gGJ) 231 153 214 498 703 Required ESP efficiency 998 993 996 998 998 Residue Mtly 0228 0068 0134 0219 0235
see Table 37 for coal types
Table 39 CIVEC factors contribution to utilisation value (Meyers and Atkinson 1991)
Basis Base coal at 4085 US$t fob standard plant 90 capacity
Coal type Cost variations US$1t
2 3 4 5 6 Utilisation value US$t fob
A -080 -025 180 270 250 070 4750 B -135 -040 100 150 040 030 4230 C 015 005 000 005 -395 -235 3480 D 135 040 -025 -035 -585 -300 3315
1 Variation in coal tonnage to provide same energy input 2 Difference in transport and handling costs 3 Maintenance costs (induding overheads) 4 Disposal costs (including overheads) 25 US$1t waste 5 FOD costs (including overheads and limestone 20 US$t)
6 Power consumption difference - mainly pulverisers and FOD
also an Australian Hunter Valley thennal coal which was well established with Japanese power utilities Table 37 summarises the properties for each coal used in the study The power station modelled was a 500 MW unit with a capacity factor of 90 Ash collection was implemented with a cold side ESP Each coal type was valued under these base conditions and also for a range of residue disposal costs (0-50 US$t) and 100 flue gas scrubbing with limestone costs set at 20 US$t Table 38 summarises the power station operational parameters for each coal studied Table 39 shows the utilisation value resulting from the model together with the component contributions to coal value It should be noted that highest utilisation value implies the best coal for the system For example coal A whilst requiring a small additional annual tonnage as a result of a slightly lower heating value with respect to the reference coal (see Table 39 - minor penalties indicated under factors 1 and 2) actually compares favourably with the base coal case due to its very low ash level (low residue disposal costs) and lower than reference sulphur level (low FGD costs) The authors of the report pointed out that unit availability and the handleability characteristics of each coal have not been taken into account and that the costs of domestic transport were not included in the study In this respect the model does not take into account 100 of available coal quality impacts on power station perfonnance but can be considered as an improved least cost type model as described in Section 71
COALBUY In 1976 Carolina Power And Light Company (CPampL) developed a program called COALBUY which they use to calculate the operating expense incurred by utilising coal of a given quality at a selected generating unit The program essentially evaluates a series of six potential penalties
boiler efficiency auxiliary power requirements coal handling equipment maintenance ash handling equipment maintenance ash storage cost replacement power due to load limitations
The program contains an extensive database for each CPampL coal-fired generating unit together with detailed specifications for a reference coal Each offered coal is compared with the reference when calculating potential operating penalties Any penalties are added to the offer price of the coal to obtain a total cost of burning it The program is also used to predict the extent to which a unit might be load-limited when burning off-specification coal Details utilised for each unit are given in Table 40 The operating data listed are taken from actual performance tests at a series of load levels
COALBUY is in fact a sub-routine of CPampL s EVAL
89
Computer models
Table 40 Model input output data - COALBUY (Corson 1988)
Developer Coal input Generating unit input Key output
Carolina Higher heating value Net unit heat rate Operating penalties Power amp Light Grindability Base boiler efficiency Total cost of coal ($IMBtu) USA Proximate analysis Estimated boiler radiation losses Load limitation on generating unit capacity
Total sulphur content Ambient air temperature Identification of system causing the load limitation Purchase price including Ambient air humidity ratio Operating characteristics of boiler fans with
transport Stack gas temperature reference to coal and purchased coal Standard deviation of the Unburned carbon in fly ash Boiler efficiency losses and related parameters
variation in higher Unburned carbon in bottom ash - boiler efficiency heating value Carbon dioxide and oxygen in the - auxiliary power requirement
boiler gases entering and leaving the - coal handling equipment maintenance air heater - ash handling equipment maintenance
Monthly unit demand profiles - ash storage cost - replacement power
The operating data listed above are taken from actual boiler tests at a series of load levels
Also includes escalation factors for database cost factors
program which was developed to maintain files on quotations a coal buyer in making a detailed assessment of cost and and purchase orders to select suppliers of spot-market coal performance impacts of using a candidate coal in his power and to plan the distribution of long-term and spot-market station Model input and output parameters are summarised purchases throughout CPampLs generating system each month in Table 41 (Corson 1988)
The system establishes the coal rank (based on ASTM D388 Coal Quality Advisor (CQA) guidelines) ash type and determines ash fouling and The CQA expert system was developed by a joint utility slagging characteristics based on empirical slagging and (Houston Lighting amp Power Company (lllampP)) and fouling indexes It compares the provided analysis values architectengineering company (Stone and Webster) team against those expected for the reference of coal and coal ash (Arora and others 1989) Its intended application is to assist Arora and others (1989) describe the specific functions in
Table 41 Model input output data - Coal Quality Advisor (CQA) (Arora and others 1989)
Developer Coal input Generating unit input Key output
Houston Lighting amp Power Stone amp Webster Engineering Corporation USA
Proximate analysis Higher heating value Ultimate analysis Sulphur forms Ash mineral analysis Ash fusion temperature Trace elements Equilibrium moisture Quartz content Coal size Coal cost (fob)
Pulveriser horse power input Number of mills in service Plant capacity factor PA temperature (OF) amp pressure (lbft2mill) Primary air to fuel ratio (lbairnbfue1 )
Plan area heat release rate actual (Btuh ft2 x 106)
Boiler efficiency () Approximate net heat rate (BtukWh) Limestone cost Total change in OampM costs ($y) Annual fuel flow (ty) Differential power costs at equivalent coal flow (ty)
Intermediate output variables Maximum mill capacity (th) Required coal flow (Pph) Coal flow per mill (th) Percent base mill Super heater gas velocity (ftsec) Reheater gas velocity (ftlsec) Air flow (lbh) Excess air () Fuel flow (Pph) from boiler calculations Annual fuel flow 075 capacity factor Gas temperature - out CF) Bottom ash flow (Pph) Fly ash flow (Pph) Volumetric heat release (Btuh x 106)
Furnace exit gas temperature (OF) Limestone usage rate (th) Unburned carbon (lbslOO lbs coal)
90
Computer models
greater detail than can be discussed here It should be noted that due to the lack of a suitable database the basis of OampM cost methods was a percentage of equipment capital costs for each major power station component
The model has been validated for HLampP use It has been reported to have been used for (Arora and others 1989)
blending of up to five coals to a specific mix or to achieve a specified quality for the blend (that is sulphur ash heating value) classifying the coal (blend) to permit assessment in various components of the power station determination of empirical slagging and fouling indices evaluating the required performance against the given limits for the major components of the power station determination of OampM costs and the net heat rate change for a candidate coal relative to a given base coal unit No 8 at HLampP Parish power station but it can be configured to enable evaluation of other coal-fired units in the HLampP system with minor changes
The impact assessment for each of the systems is classified by severity level and displayed to the user with appropriate recommendations
Coal Quality Engineering Analysis Model (CQEA) From 1963 to the mid-1970s NYSEG have used a coal evaluation program to determine bonuses and penalties on each parameter of the coal offered by suppliers (Mancini and
others 1988) In 1975 the company commenced a two-year coal quality study to develop a method of fitting the existing program to each of the five NYSEG generating stations The model approach was changed to combine generating station engineering data with coal analysis data in a workable package for fuel evaluation engineering and economic analyses The result is the CQEA which has been used by NYSEG since 1977
Table 42 summarises the coal input data generating unit data required and the key and intermediate output variables The CQEA is calibrated to each units characteristics The generating unit input data are reported to be recalibrated annually
An illustration of the capability of the CQEA is shown in Figure 34 It compares the overall production cost for five different coals burned in one unit (unit 5 of Figure 34) as calculated by CQEA If only delivered cost is used as a measure to purchase coal then coal 3 would be the lowest cost However the overall cost of coal 1 is about 80 ckWh lower than the overall cost of coal 3 Similarly it is shown that paying the highest cost for high-quality coal 2 compared to coal 1 is not overall economically beneficial Also if the choice were among coals 2 4 and 5 - which are almost equal - the best quality would be chosen knowing the results of the CQEA These results have been verified by actual experience of the above coals in the units discussed
The CQEA system is used by two different groups within
Table 42 Model input output data - Coal Quality Engineering Analysis (CQEA) (Mancini and others 1988)
Developer Coal input Generating unit input Key output
NYSEG Delivered price USA Heat content
Proximate analysis Sulphur Ash softening temperature Grindability
Maximum gross capacity Hours operating at peak and average power Station service power Turbine heat rate Forced draft fan inlet temperature Stack exit gas temperature Carbon in ash and ash as fly ash versus
bottom ash moisture added to ash for dust-free disposal
Excess combustion air Base pulveriser capacity Pulveriser capacity correction factors for
fineness and grindability Radiation amp unaccounted boiler loss Fuel oil rate for low volume coal Minimum volatiles in coal without ignition oil
Average gross generation Ash collection capacities fly ash
and bottom ash Ash and scrubber sludge disposal cost Flue gas desulphuriser removal
efficiency and OampM costs
Cost of coal and oil burned Ash disposal costs Maintenance costs for coal and ash handling equipment Scrubber OampM and waste disposal costs Replacement power cost Net output MWh Replacement power MWh
Intermediate output variables Boiler efficiency () Total station service power () Net station heat rate (B tukWh) Percent utilisation of capacity Total Btu fired in coal and oil
Additional system data Maintenance wage rate Replacement power demand and energy charge Fuel oil heating value and price
91
Computer models
D coal quality - related costs 16shy D delivered coal cost
14 c 3 ~ 12ifgt U5 0 100
u c 0
OJ 8 D 2 0shyD 6 (j)
iii ~ 4 a OJ
u 2
0 Coal 1
MJkg 256 ash 210 moisture 70 sulphur 21
Coal 2 Coal 3 Coal 4 CoalS
302 263 284 270 120 203 127 177 40 53 72 70 27 12 26 20
Figure 34 CQEA evaluation of the impact of different coals on overall production costs of one unit (Mancini and others 1987)
NYSEG These are the Perfonnance and Fuel Engineering group which maintains the CQEA calibration factors for each unit and the Fossil Fuel Supply group which uses the
BOILER bull subcritical PC bull supercritical PC bull parallelseries backpass bull flue gas recirculation
COAL PREPARATION bull 41 mill offerings bull vertical spindle mills bull exhauster mills bull other
r
BOnOM ASH SYSTEM bull wet system
- jet pumps - centrifugal pumps
COAL HANDLING bull rail truck bargeship conveyor unloading bull emergency and normal stockout bull stacker reclaimers lowering wells
other reclaim systems bull ring granulator hammermill crushers
CQEA as a tool for evaluating coal purchase offers from coal producers (Mancini and others 1987)
Coal Quality Impact Model (CQIM) In 1985 Black amp Veatch a US architect-engineering group and EPRI worked together to develop a comprehensive computer program for predicting coal quality impacts The result was the Coal Quality Impact Model (CQIM) As of the end of 1991 112 copies had been distributed to 72 different utilities and six different companies or agencies Black amp Veatch has also sold the program to eight companies including four outside of the US Four additional sales to non-EPRI member companies are in their last stages of negotiations This is the most widely used systemsshyengineering model in the world
The role of CQIM is to quantify both perfonnance and cost impacts associated with changes in coal quality (Evans 1991 Stallard and Mehta 1991) The equipment types modelled by CQIM are summarised in Figure 35 As described earlier for other models CQIM evaluates alternative coals by comparing them with a reference or current coal supply It is also designed to consider station-specific design and operation characteristics on a component-by-component basis as well as the unit as a whole This allows the CQIM to identify potential system limitations (sources of derate)
The effort required to collect CQIM input data varies according to the background of the user the availability of data and the purpose of the evaluation CQIM contains a
AIR HEATERS bull bisectors bull trisectors
PARTICULATE REMOVAL bull hot ESP bull cold ESP bull fabric filter
1 FLY ASH HANDLING bull pressurisedbull vacuum
FD FANS bull axial bull centrifugal
~
~ PA FANS bull axial bull centrifugal bull coldhot bull exhuasters
Figure 35 Equipment types modelled by CQIM (Galluzzo and others 1987)
ID FANS bull axial bull centrifugal
SRUBBER ADDITIVE bull limestone bull lime bull none
to stack
t GAS REHEAT bull 5 alternatives
f---shy FGD SYSTEM bull wet limestone bull spray dryer --- bull none
WASTE DISPOSAL bull stabilised waste bull fixated waste bull evaporation ponds bull other
92
Computer models
Table 43 Model input output data - Coal Quality Impact Model (CQIM) (Stallard and others 1988 Stallard and Mehta 1991)
Developer Coal input Generating unit input Key output
EPRI amp Heating value Black amp Veach Ultimate analysis USA Moisture content
Ash content Chlorine content Sodium content in ash HOI Ash fusion temperatures Ash analysis Fuel cost Transport cost
Unit size (MW net) Capacity factor () Net power level Auxiliary power requirements Auxiliary equipment specifications
and capacities Hours of operation Net turbine heat rate (BtukWh) Excess air level () Boiler losses Boiler dimensions Soot blowing details Tube bank configurations Maximum heat input per plan area (MBtuJhft2)
Design FEGT Maximum allowable flue gas velocity Economiser
Economic data Replacement energy cost ($millkWh) Limestone cost ($ton) Salarymaintenance rate ($person-year)
Discount rate Replacement power cost Limestonellime cost Total annual fuel related costs Transport costs Escalation rates Overall unit performance data - slagging fouling and erosion potentials - equipment performance and derate info - maintenance availability data - calculated derate by system - generation cost summary page Sensitivity analysis Comparison tables Error warnings
feature for supplementing data provided by the user This default information is based on the data entered by the user the overall power station configuration the characteristics of the design coal and established equipment design practices Since default data can be substituted for most missing data the program can be run with limited input Of course the more actual data used the more comprehensive the predictions
Table 43 illustrates the type of data required for conducting an initial screening evaluation of coal quality CQIM contains programs for translating each major performance impact into a discrete cost component
During the course of the development of the CQIM model validation was carried out by means of a host utility program Initially 12 utilities worked with EPRI to develop case studies to validate the CQIM equipment performance models The CQIM performance and cost predictions were compared with historical data and actual utility operating experience Any discrepancies were used to modify the program modules and improve the overall predictive capability of the CQIM The case studies covered a wide range of US unit designs and US coals With the sale of the CQIM to international utilities this has prompted the development of CQIM International which will have facilities to convert input data utilising SI units
There are several examples of literature describing the application and validation of the CQIM (Galluzzo and others 1987 Boushka 1988 Stallard and others 1989 Cox and others 1990 Kehoe and others 1990 Afonso and Molino 1991 Giovanni and others 1991 Vitta and others 1991)
Coal Quality Expert (CQE) The US Department of Energy (DOE) selected the
development of the CQE in Round 1 of the Clean Coal Technology program The project initiated in 1990 and scheduled for completion in August 1994 will cost $217 million
The CQE computer system is designed to give utilities a tool that will predict the total cost of impact of coal quality on boiler performance maintenance operational costs and emissions
Figure 36 shows the major components of the CQE system The foundation for the CQE is EPRIs CQIM (see section on CQIM) More than 20 software models and databases including the CQIM a flue gas desulphurisation model a coal cleaning model a transport model and a new power station construction model will be integrated into a single tool to enable planners and engineers to examine the cost and effects of coal quality on each facet of power generation from the mine to the stack The expert system is intended to evaluate numerous options including various qualities of coal available transport methods and alternative emissions control strategies to determine the least expensive emission control strategy for a given power station
It is intended that the CQE will include cost estimating models for new and retrofit coal cleaning processes power production equipment and emissions control systems Individual models are to be made available as they are developed The first of these models the Acid Rain Advisor (ARA) has already been released (CQ Inc 1992) The ARA developed primarily to assist users in managing US Clean Air Act compliance evaluations can be used to quantify costs and emissions allowance needs for potential utility compliance strategies
A core part of the CQE program is extensive data gathering
93
Computer models
ENGINEERING AND ECONOMIC MODELS
bull Coal Quality Impact Model
bull coal cleaning cost model
bull flue gas desulphurisation
bull NOx emissions
ADVANCED USER INTERFACE
Integrated report and graphic capabilities
CQE ASSISTANCE Integrated applications
bull strategic planning
bull plant engineering
bull fuel procurement
bull environmental strategies
bull acid rain advisor
Figure 36 Major components of the CQE system (Evans 1991)
and analysis to validate the models and it is one of the largest efforts ever attempted to link pre-combustion combustion and post-combustion technologies to solve power station emission problems (Evans 1991) Samples of the various coals identified for the project are being collected at mines commercial cleaning plants and the six host power stations Extensive measurements of the performance of all ancillary equipment are taken during the field tests Moreover the project will generate considerable data from laboratory bench- and pilot-scale combustion tests using the same coals All the data will be used to develop and validate the CQE models including those that predict mill wear slagging and fouling precipitator performance flue gas particulate removal NOx formation and the flue gas desulphurisation performance
IMPACT Ugursal and others (1990) reported the development of a computer-based techno-economic model that can predict the impact of coal quality and other key variables on the busbar cost of electricity generated by new power stations The IMPACT model has been structured to focus on four major cost sectors of the coal-to-electricity chain (see Figure 1) This includes transport power station post-combustion particulate and SOz emission controls and residue disposal
Table 44 Ranges of selected coal-ash combustibility parameter that predict approximate classification of CF values (Ugursal and others 1990)
Incombustibility index RI1 Classification of CF values
lt21 21--43 43-75 gt75
94
low laquo017) medium (017-D34) high (034-D47) severe (gt047)
INFORMATION AND DATA BANKS
bull fLe1 sources
bull plant specifications
bull transport rates
bull waste handling
bull coal quality information systems
The impact of coal characteristics on power station performance is quantified in IMPACT as follows
steam cycle heat rate calculation assumes that the boiler is designed for the given coal and operates at design load boiler efficiency is evaluated using the heat loss method (see Section 632) A notable additional approach adopted to evaluate unburnt combustible losses in the calculation of efficiency includes an incombustible parameter Rh which is inversely proportional to the base-to-acid ratio of coal ash Rh is directly proportional to the amount of unburnt combustibles in the fly ash The amount of unburnt combustibles is expressed by CF and can be defined as
CF = [(flyash combustible$ (lb of fly ash formed)] (lb of coal feed)
The approximate ranges of CF values that corresponds to the incombustibility parameter ranges are given in Table 44 Once CF is determined from Table 44 the percentage of combustibles in the coal feed that is lost in the flue gas can be determined from
CFx 100 coal feed combustIbles = n1 1 d b tmiddotbl70coa lee com us 1 es
where the percentage of coal feed combustibles = 100 - ash - moisture with the ash and moisture content determined from proximate analysis of the coal
IMPACT utilises empirical correlations (developed by regression of data published by Bechtel Power Corporation (Holstein 1981)) between auxiliary power consumption and the sum of the ash and moisture contents of the coal for both subcritical and supercritical units (Ugursal and others 1990) availability values of 80 are assumed to apply to new
Computer models
Table 45 Model input output data - IMPACT (Ugursal and others 1990)
Developer Coal input Generating unit input Key output
University of Ultimate analysis () Plant capacity (MW) Levalised busbar cost of electricity Nova Scotia Ash content Unit type Annual operational cost Canada Ash composition () Steam generator efficiency () Capital costs
Heating value Steam cycle heat rate (BtulkWh) Annual coal consumption Cost of coal Flue gas exit temperature
Average load Equivalent availability Auxiliary equipment specifications Cost of limestone
power stations This assumption is adopted due to the lack of information available quantifying the impact of coal quality on the availability of power stations coal consumption and coal bum rate of a given power station are calculated using an energy balance based on the results obtained from the parameters above and the specified annual generation capacity annual ash and S02 generation are determined by a mass balance on the annual coal consumption rate and the ash and sulphur contents of the coal
Although this model has yet to be fully validated the authors carried out sensitivity analyses for a number of coals with various levels of ash and sulphur (Ugursal and others 1990) on a representative power station with two 500 MW units The input and output parameters of the coals and power station for the model are summarised in Table 45 Overall from the study it was concluded that the capital and operating costs of most of the sectors of the coal-to-electricity chain increase with increasing ash content of the coal fIred The authors emphasised that the findings apply for the particular conditions of the case the results might be quite different under other site specific conditions
Coal quality impact study model (CQI) Kemeny (1988) reported on work performed to develop a method of analysis using a combination of statistical and engineering methods which could be applied to any power station operating system The method adopted also developed a model that computes a power stations total coal-related generation cost on a specific coal It was developed initially for an Italian power station Fusina 3 to determine the economics of burning four different coals at the station
The method adopted for the calculation of availability assumed that planned outages were unaffected by coal quality whereas their effects on forced outages was the sole influence on availability Because of the random nature of equipment failures an analysis of forced outage rates was carried out statistically Historical coal usage data were correlated against historical outage data to see if there was a coal quality relationship For Fusina 3 power station the coal type was changed so frequently that data from a single unit were considered suffIcient for such a study The results of the availability analysis are shown graphically in Figure 37 A low correlation coefficient of 0447 was observed for the relationship indicating that there was a fairly high probability
that the apparent correlation between forced outages and ash was due to random scatter of data points and not to any cause-and-effect relationship In addition the large negative y-axis indicated that the regression equation may not have been accurate across the full range of ash values In light of the results demonstrated by this study it would appear that it would be more prudent not to include the results of the availability analysis in the coal quality impact model However the investigators believed that the regression analysis conformed to engineering expectations and because of the probabilistic nature of forced outages it was quite unlikely that with the amount of data available outages would correlate very strongly with coal quality Therefore the results of the availability analysis were included in this coal quality impact model
Coal-related operating costs accounted for in the model cover any cost not specifically covered by fuel costs At Fusina 3 for example these areas included the cost of sulphur for S03 conditioning and the cost of ash disposal Other areas might include the cost of fuel additives scrubber related costs cost of additional equipment The effects of coal quality on the cost of routine and emergency maintenance at the power station is most easily measured statistically in a similar way in which forced outages were correlated
01000
~ L 800 (j)
~
L0 600 81 Q) 0 OJ co 5 400 -0 Q)
0 0
~4() 82 00 200 u
83 o
40 60 80 100
Ash throughput kty
o not included in regression
Figure 37 Correlations of forced outage hours against ash throughput using the cal model (Kemeny 1988)
95
Computer models
Table 46 Assessment of four coals for Fusina unit 3 using the CQI model (Kemeny 1988)
Coals
South Africa Polish American
Low ash High ash
Coal characteristics High heating value MJkg [Btulb] Ash content Sulphur Moisture content Carbon content Ash resistivity ohmcm x E13
Coal cost $GJ [$MMBtu]
Results from model Boiler efficiency Availability US$y Capacity - ESP limit - Auxiliary power
Fuel costs - coal - supplementary
OampM costs - maintenance - flue gas conditioning - ash disposal
Totals
2625 [11291] 1339 038 830
6474 375
153 [161]
8890 3905122
1764549 3765822
25565882 3450848
2806626 24916
458876
4172640
2707 [11639] 1226 063 780
6796 500
163 [172]
8889 3204389
1514442 3817118
27980093 3059766
2538408 9051
330618
424453886
3012 [12950] 742 081 720
7433 500
177 [187]
8931 336355
357460 4033183
33180022 1625800
1440618 o
175209
40798228
2830 [12173] 1152 075 710
7033 500
177 [187]
8886
2459658
2325523 o
228820
44008125
Without going into power station details as this is described elsewhere (Kemeny 1988) an illustration of the type of results produced by the model of the comparison of four coals from Poland South Africa and the USA is given in Table 46
As in the case of other similar models the value of the total coal-related production cost in the cost summary is just an indicator it is neither a calculation nor a prediction of the actual generating cost The number in this model does not include costs such as maintenance costs for non-coal-related systems However it can be used for comparative purposes Quite simply the coal which gives the lowest production cost is the most economical
More briefly other models that have been reported in the literature include
Waters (1987) reported the development of a computerised mathematical model known as ECUMEC Data taken from the model subroutines are used to calculate the power cost for example at the busbar including the cost of coal Once again the method used to assign an economic value to a coal is to select a base coal or yardstick coal to which a coal price (fob) can be ascribed The equivalent value of another coal is that price (fob) which gives the same power production cost as the base coal Waters (1987) demonstrated the
capability of the model by considering the effect of some coal properties such as sulphur ash and moisture content on the equivalent coal value in a 500 MW power station The base coal was a 15 ash Australian Hunter Valley coal The coal price (fob) was shown to be very dependent upon ash with a 5 ash coal worth approximately US$745 more per tonne than a 15 ash coal (based on 1987 prices) The effect of moisture on equivalent coal price is similar to ash but not as marked It was shown using the model that a 05 increase in sulphur content had a much greater effect on coal value than a 5 increase in ash content This was because the capital and operating costs associated with FGD to meet air quality requirements were very high a program developed by Southern Company Services USA to help estimate the benefits from cleaning coals The constituents of coal that were found to affect the cost factors were primarily ash moisture sulphur and carbon content (Blake 1988) the Consol Coal QualityPower Cost model which was used by Deiuliis and others (1991) to evaluate the performance of six US regional coals in a typical 500 MW pulverised coal-fired unit The study was focused on developing a cleanliness factor for model relating to heat flux and soot blower effectiveness data obtained from pilot combustion tests the Coal Utilisation Cost Model which utilises a three-step modelling approach-statistical analysis of
96
Computer models
historical data (source NERC) development of an engineering algorithms and evaluated cost calculations based on the algorithm results (Nadgauda and Hathaway 1990)
733 Integrated site models
With further advancements in computer and sensor technology in the last ten years integrated site models are being developed that allow the integration of information from unit models systems perfonnance and other models directly into the control room data system These programs allow the continuous monitoring of for example selected coal properties such as ash moisture and sulphur furnace and convective pass deposits and can define overall heat rates based on these continuous measurements taken from the unit (Elliott 1991) The diagnostics packages can also include a routine for predicting the implementation and impact of operating practices on heat rate (Nurick 1988 Alder and others 1992)
Smith (1991) and Reinschmidt (1991) have reviewed the wider application of integrated control systems from individual component control to full automation of the power
Coal quality COAL MANAGEMENT
as a function MODULEof time at mills
Coal quality collection and assessment
station and the new computer technologies that are being applied such as neural network approaches that processes input data without identification of particular algorithms connecting the output results with the input data and fuzzy logic An example of this application is the C-QUEL system
Coal quality evaluation system (C-QUEL) Mitas and others (1991) have reported on the current development of a comprehensive software system C-QUEL that will allow utilities to use on-line analysers to try to solve or mitigate existing coal-related problems This will be accomplished by the C-QUEL system by providing information about coal quality before it is burned predict potential effects on operation and provide recommendations of control actions which can be taken to adjust coal quality andor improve power station response to quality changes The use of on-line coal analysers has been reviewed by Makansi (1989) and Kirchner (1991)
C-QUEL is a suite of computer programs which can be used as a basis for control of various processes in a power station Figure 38 shows a schematic of the structure of the system Appropriate control actions will be determined based on a wide variety of information gathered by the operator on-line
ON-LINE PERFORMANCE MONITORING SYSTEM
Equipment status Current performance
Load demand
ON-LINE COAL ANALYSER
SUPERVISORY CONTROL MODULE
COAL QUALITY CONTROLACTION
RELATIONSHIP MODULES
Coal data logging
Monitor CQ and equipment modify operation to
meet goals
DATA ARCHIVE AND TRENDING
USER INTERFACE
EPRI COAL QUALITY IMPACT MODEL
Annunciation Predicted performance Interactive dialogue Information retrieval
Figure 38 Schematic showing the structure of the e-aUEL system (Mitas and others 1991)
97
Computer models
coal analyser real-time station data on-line performance calculations equipment performance predictions and coal flow models The EPRI Coal Quality Impact Model (CQIM) will be incorporated into C-QUEL to provide the prediction capability for the performance of all major power station systems directly impacted by coal quality Operational strategies as a result of expected unit performance will be evaluated by C-QUEL and provided to the operator These strategies will take into account the current and future unit generating requirements as well as cost information associated with each possible action Specific control recommendations and supporting information are presented to the power station operators
Figure 39 shows a simplified case as an example of the use of C-QUEL in which the primary goal is to maximise electrical generation from a base load power station Figure 39a depicts the sequence of events that can be expected at a particular point in time The operator is unaware that a change in coal quality has occurred until a
a) Without C-QUEL
Ash and moisture content have
increased
drop in load is detected In the second scenario Figure 39b the goal of maximising electrical production has been fed into the C-QUEL supervisory module Since decreased mill capacity will have a direct effect on generation this information together with a recommended course of action is given to the operator and allows him enough time to make the proposed adjustments before load production is affected Because of detection of the higher moisture and ash content of the coal supply by the on-line coal analyser a decrease in mill capacity was predicted To prevent any load reduction the operator would be instructed by the system to bring another mill into operation
The project team for development of the C-QUEL system consists of two host US utilities - Oklahoma Gas and Electric (OGampE) and Pennsylvania Electric (penelec) two engineering contractors - Black amp Veatch and Praxis Engineers and EPRI Demonstration of the system will take place at OGampEs Muskogee power station and the Penelec-operated Conemaugh plant OGampEs Muskogee
I I
Only two pulverisers are on-line consistent with the requirements
of the previous coal quality
I I I L_
On
Electrical production has
dropped
Operator determines decreased pulveriser capacity has caused the load drop and brings another pulveriser on-line
b) With C-QUEL Pulveriser module predicts Other controlaction modules decreased pulveriser capacity
Analyser detects Iincrease in coal ash and moisture conten t I
III I +0bull
Goalmaximise output
-
1 Supervisory module evaluates this information relative to operational
t--- goals and constraints and information from other modules
I
A message notifies the
Pulveriser 2
operator of potential generation loss and the need for an additional pulveriser
1-~e~C 1
I I L_
Operator brings another pulveriser on-line before the high ashhigh moisture coal is fed to the fuel preparation system Maximum electrical production is successfully maintained
Figure 39 Comparison of the operations with and without the use of e-aUEL (Mitas and others 1991)
98
power station fires primarily western low-sulphur coal that is currently blended with more expensive higher sulphur Oklahoma coal which also has a higher heating value on a 10 by heating value basis The station must also meet a strict SOz emission limit OGampE has installed an on-line analyser - PGNAA elemental analyser - that will provide data to assist in blending and feeding An elemental analyser has also been installed at the Conemaugh power station Initial data gathering will focus on the Muskogee power station (Mitas and others 1991)
Couch (1991) has also reviewed the influence of integrated computer control and modelling on coal preparation plant
74 Comments The studies described above demonstrate the feasibility of developing various quantitative relationships which are essential for optimum planning and operation of generating units Table 47 summarises the capabilities of the models described in this chapter Many of the results are based on data and methodologies which still require further refinement
When considering the two major techniques for assessing power station performance that is statistical and engineering analysis modelling a weak link with both approaches is within the coal specification parameters used in the correlations
Table 47 Summary of model types and capabilities
Computer models
For the purpose of selecting an economically attractive coal it is important to determine heat rate effects due to coal quality as accurately as possible In their review of statistical and engineering based relationships Folsom and others (1986b) did not believe that the correlations from statistical studies were close enough to be useful for this purpose Consequently the use of engineering correlations and experience to evaluate heat rate impacts was highlighted as the preferred procedure
Engineering based models have their critics also Many utilities apply least cost models for purchasing coals and component models and some acknowledge the benefits of expert unit or integrated models Others remain sceptical over the capability of devising a truly representative model of the coal combustion process Some of the reasons given for this scepticism include
the present methods that describe coal properties require substantial refinement for use in the models as they are not adequate for predictingaccounting for unit performance a belief that coal blending solutions based on pragmatism and simple empirical methods are more appropriate providing a here-and-now solution a belief that processes such as fouling and slagging and mill performance cannot be accurately modelled whilst the basic mechanisms are not clearly understood
Model type Modelling capabilities Developed by Application Comments Model name Assessmentcountry
Heat Capacity Avail- Maintenance Other of origin
rate costs ability costs
Least cost coal coal blend model
Least cost fuel system total fuel cost architectengineer buyer manualAustralia ICVM total fuel cost research organisation buyer manualAustralia Steam coal blending plan - total fuel cost supplier buyer manuallUSA Perfectblend total fuel cost research organisation buyer manuallUSA
Single component model Boiler models --I --I research organisation operator computerintershyand others utilityequip manufacturer national
Unit model Statistical
TVA study --I --I --I research organisationutility operator manualUSA EPR study --I --I --I research organisationutility operator manuallUSA NERA srudy --I --I research organisation operator manuallUSA PC study --I --I --I capital costs utility operator manuallUSA
Engineering ClVEC --I --I estimated total fuel costs research organisation buyer computerAustralia COALBUY --I --I --I --I total fuel costs utility buyer computerlUSA CQA --I --I --I estimated total fuel costs architect engineerutility buyeroperator computerlUSA CQEA --I --I --I coalash handling total fuel costs utility buyeroperator manuallUSA CQIM --I --I --I --I total fuel costs architect engineerutility supplierlbuyer computerlUSAUK
operator CQE --I --I --I --I total fuel costs architect engineerutility buyeroperator computerlUSA IMPACT --I --I --I --I total fuel costs research organisation buyeroperator computerCanada CQI --I --I --I statistical evaluation total fuel costs research organisationutility buyersoperator computerlUSA
Site model C-QUEL --I --I --I --I total fuel costs architect engineerutility operator computerlUSA
total fuel costs for engineering models refers to the total fuel-related production costs in terms of the price of electricity at the busbar
99
Computer models
new advanced boiler configurations such as low NOx
combustion regimes increase the complexity of boiler models many of the models have not been applied to a wide range of international coals and therefore have not received adequate validation
The analysis approach adopted by many of the unit models available can vary in complexity such that a form of quantitative predictability can be produced to a reasonable or to what may be deemed as a high level The lower level of prediction capability has been perceived by critics to produce too general a fmding In contrast the higher level may require more detailed unit specific information than a utility may have readily available such that special provisions would have to be made in order to collect the necessary data (Johnson and others 1991) This is known to be time consuming and is perceived by some operators to detract from the main utility priority that is to produce electricity Others believe that the models incorporate performance measurement errors that may compound to reduce the effectiveness of the model and make it only useful for comparing coals that show a wide range of coal property values
Many of the model descriptions have cited the beneficial role of the model in fuels purchasing It is considered that when models are used in such a manner they could become an improved means of communication between supplier buyer and user as they can ultimately aid the purchase of an economical coal of adequate quality for a particular power station The advantages of having the ability to assign an overall cost to a coal particularly in terms of its impact on component and overall power station performance could prove to be of technical and financial benefit to the utility in helping to justify supplier buyer or operator policies such as coal cleaning blending power station retrofitting or purchase of replacement energy to the advantage of the utility
In general however operators remain reluctant to move toward a predictive approach to coal quality impacts in preference to reliance on post mortem type remedies In the future integrated computer models such as C-QUEL may prove more acceptable when they can provide real time cause and effect information and advice on how to remedy problem situations as soon as they occur and can be seen to rely on dependable input data
100
8 Conclusions
Fuels purchasing and management presents an important opportunity for utilities to control costs It is also recognised that final judgements on coal selection often require a trade-off between these costs and qualitative factors such as diversity of supply reliability control of emissions for environmental reasons balance of trade and currency availabilities The contribution of coal to the cost of electricity extends far beyond the purchase price of the fuel Over the last fifteen years it has become generally accepted by coal-fired power station operators that the capacity availability and cost of operation of each individual component of the power station are materially affected by the quality of coal fed to it To generate power at least cost it is important to evaluate the overall total cost associated with each coal for a particular power station
The principal coal properties that were found to cause greatest concern to operators include
ash content and composition heating value sulphur content moisture content grindability volatile matter content
Enforcement of environmental legislation has resulted in the elevation of total sulphur content to a key position in the specification of coal along with total ash moisture and heating value Table 48 summarises the effects of these properties and other coal characteristics that are used as coal specifications for combustion on component and overall power station performance
Little has changed over the years in the way that coal is assessed and selected for combustion Operators continue to use quality parameters in their specifications that were mostly developed for coal using processes other than direct combustion Whilst many empirical relationships have been
established between coal specifications and certain component and plant performance indicators the coal characterisation tests themselves have been shown to have serious shortcomings and in some cases do not adequately reflect the process conditions For example
coal composition measurements cannot be used to explain the problems of dusting flowability freezing and oxidation that can occur during coal handling mill capacities for lower rank coals or coal blends are difficult to evaluate using existing grindability correlations combustion characteristics including flame shape stability and char burnout cannot be evaluated accurately based on standard coal composition tests the correlations that have been developed for slagging and fouling are inadequate there is considerable disagreement as to the best method of measuring fly ash resistivity there is no correlation between coal composition and fly ash fineness there is no adequate means to predict NOx emissions
Because the procurement specifications are based on tests which do not relate well to actual practice there is still a need for expensive large scale test burns to confirm suitability
Coal quality affects a wide variety of plant components and ultimately the overall station performance that is total system capacity availability maintenance costs substitute fuel costs plant replacement costs and the final cost of electricity There is a growing awareness that coal suppliers should take more responsibility with respect to determining the quality of coal made available on the market Suppliers that best understand the consumers fuel quality concerns prove to be the most successful in securing contracts and maintaining market share
Plant operators and other organisations are working to
101
Conclusions
Table 48 Summarymiddot of the impacts of coal quality on power station performance
Coal specification Power station component performance Overall power station performance
Environmental control
l u l
tl a
B
amp ~ o(l co S c r
~
~
E l
aI
0
~ C
co
~ B en
c= E co c E c ~
c= E 5 0 co c ~
U - 0 U
c au
~ u
lt5i if
c= ~ ~ amp 0 j c a u
6 en
c= sect l 0 0 1sect a u gtlt
0 Z
1(j at
4-lt a
E c
l 0
tl sect 0 ~ l
QI
0 ~
U
B ~ lta r
c= E S 0
U
sect c B c
ca ~
~ ~ ca gtlt
Ash content increase decrease
Heating value increase decrease
Sulphur content increase decrease
Moisture increase decrease
Hardgrove grindability index increase decrease
Volatile matter increase decrease
Ash fusion temperature increase decrease
Ash resistivity increase decrease
Sodium content increase decrease
Chlorine content increase decrease
Fuel ratio increase decrease
Free swelling index increase decrease
Size consist increase decrease
compiled from observations from literature and the lEA Coal Research survey worsened (or decreased for components marked ) improved (or increased for components marked )
102
improve their understanding of how their equipment or systems respond to particular coals and coal blends but the lack of data for appropriate direct correlations of plant performance and coal behaviour has hindered the development of true prediction capability Until these relationships have been developed and proven respecting differences in boiler design coal buyers will continue to operate at a disadvantage when selecting new sources of coal
With the advances that have been made in computer technology there has been some success in the development of computer models that demonstrate the feasibility of developing various quantitative relationships for optimum planning and operation of generating units Many utilities use least cost models for purchasing coals that have no performance prediction capability Many use component models that supply fundamental data of plant component performance There is a growing number of utilities that are adopting expert unit or integrated models that are being developed Others have shown scepticism over the capability of devising a truly representative model of a coal combustion plant for reasons that include the following
a belief that coal blending solutions based on pragmatism and simple empirical methods are more appropriate providing a here-and-now solution a belief that many of the coal quality impacts cannot be accurately modelled as the basic mechanisms are still not fully understood new advanced boiler configurations such as low NOx
combustion regimes increase the complexity of boiler models many of the models have not been applied to a wide range of international coals and therefore have not received adequate validation the present methods that describe coal properties require substantial refinement as used in the models as they have been found to be inadequate in many cases for predictingaccounting for unit performance
Many of the shortcomings in the traditional coal characterisation tests that form the basis for specifications for
Conclusions
combustion have been exposed by the efforts to develop computer models and their improved data processing Prior to their application manual comparisons provided only limited indications of coal behaviour and in many cases precluded the ability to attach a price to a change in performance as a result of a change in coal quality Development of the models has also initiated extensive validation exercises to acquire the necessary performance data In addition coal characterisation tests are being reassessed It is recognised that an overly conservative approach to the development and adoption of new techniques as characterisation tests which may more realistically reflect the conditions extant to coal combustion has also hindered progress into acquiring true predictive capability
Specific needs that have been identified during the course of this review include
the need to develop an internationally acceptable method(s) of defining coal characteristics so plant performance can be predicted more effectively specific relationships between boiler performance in particular for advanced boiler configurations such as low NOx combustion regimes and coal quality need to be developed For example the specific impact of sulphur chlorine sodium overall ash content and coal rank (or reactivity) on carbon burnout slagging fouling corrosion and abrasion all need to be established economic parameters to measure the impact of plant performance on the cost of electricity need to be established and agreed upon in the electric utility industry The accounting systems of many utilities are not designed to easily identify the costs associated with coal quality impacts These organisations need to review their methods particularly if they intend to take advantage of new developing tools that are available such as expert computer models
Successful resolution of these issues is fundamental to achieving optimum use of coal as pulverised fuel in utility power stations
103
9 References
Abbott M F Bilonick R A (1992) Applied heat flux and soot blower effectiveness measurements in the CONSOL pilot and research combustors In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast R USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 471-497 (1992) Afonso R F Molino N M (1991) Compliance coal and low volatile bituminous coal testing at New England power In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 421-436 (JulI991) Ainsworth C C Rai D (1987) Chemical characterization of fossil fuel combustion wastes EPRI-EA-5321 Palo Alto CA USA EPRI Technical Information Services 136 pp (Sep 1987) Akers D J Norton G A Buttermore W H Markuszewski R (1989) Trace elements in coal In Trace elements in coal and coal wastes EPRI-GS-6575 Palo Alto CA USA EPRI Technical Information Services pp 21-28 (Dec 1989) Alder G Klein K Rettberg L (1992) Optimization of automated sootblowing through on-line boiler heat balance modeling In Power-Gen 91 Tampa R USA 4-6 Dec 1991 Houston TX USA PennWell Conferences and Exhibitions pp 1863-1881 (1992) Allman W P (1987) Steam coal blending planning and economic analysis facilitated by computer-generated tables Journal of Coal Quality 6 (1) 19-22 (Jan 1987) Allman W P (1991) A cost-minimization planning model for the coal sourcingtransport network problem emphasizing environmental emission restrictions Energy Systems and Policy 15 (1) 65-73 (Jan-Mar 1991) Anson D (1988) Interpretation and use of empirical slagging criteria In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 181-1101 (1988) Arnold B J (1988) Workshop on defining coal handleability
its cost impact and control Palo Alto CA USA EPRI Technical Information Services 128 pp (Nov 1988) Arnold B J (1991) Effect of chemical and physical coal properties on handling behaviour Mining Engineering 43 (2) 228-231 (Feb 1991) Arnold B J OConnor D C (1992) The effect of coal quality on coal handling Paper presented at Impact of coal quality on power plant peljormance La Jolla CA USA 25-27 Aug 1992 Arnold P C (1990) Storage systems for coal the requirement for implementation of modern design techniques In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 40-46 (Jun 1990) Arora B R Racine J P Sirois R H Finn G A Hanna R S Kern E E Buffinton A L (1989) Coal quality advisor for coal buyer Paper presented at Expert systems applications for the electric power industry Orlando R USA 5-8 Jun 1989 Babcock amp Wilcox (1978) Steam its generation and use (39th edition) New York NY USA Babcock amp Wilcox Company vp (1978) Bailey J G Tate A Diessel C F K Wall T F (1990) A char morphology system with applications to coal combustion Fuel 69 (2) 225-239 (Feb 1990) Baker J W Bennett P Conroy A Naylor P Smith G B (1987) Utilization characteristics of Australian steaming coals in overseas power stations In Coal Power 87 The AUSIMM annual conference in association with the Mining and Metallurgical Institute ofJapan (MMlJ) Newcastle NSW Australia May 1987 Parkville Vic Australia The Australasian Institute of Mining and Metallurgy pp 303-311 (May 1987) Baker J W Holcombe D (1988a) Use of the drift velocity apparatus to determine electrostatic precipitation performance In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp N13-NI6 (1988)
104
References
Baker J W Holcombe D (1988b) Electrostatic precipitations and fabric collection In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp L121-L1239 (1988) Balling L Hein D (1989) DeNOx catalytic converters for various types of furnaces and fuels - development testing operation In 1989 Symposium on stationary combustion nitrogen oxide control San Francisco CA USA 6-9 Mar 1989 EPRI-GS-6423-vol 2 Palo Alto CA USA EPRI Technical Infonnation Services vol 2 pp 7A27-7A40 (JuI1989) Barrett R E (1990) Designing boilers to avoid slagging fouling Power 134 (2) 41-45 (Feb 1990) Barrett R E Holt E C Jr Mack G A Frank R L (1983) Power plant perfonnance Assessing the impact of coal quality In SME-AIME annual meeting Atlanta GA USA 6-10 Mar 1983 Littleton CO USA Society of Mining Engineers of AIME pp 1-12 (Mar 1983) Barrett R E Mack G A Holt E C Jr (1982) Examining relationships between coal characteristics and the perfonnance of IVA power plants TVA10PIEDT-8312 Columbus OH USA Batelle-Columbus 254 pp (Sep 1982) Barrett R E Tuckfield R C (1988) Correlation of slaggingfouling from utility operating data In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 163-180 (1988) Bauver W P Bianca J D Fishburn J D (1984) Characterization of erosion of heat transfer tubes in coal fired power plants ASME Paper 84-JPGC-F4-3 New York NY USA American Society of Mechanical Engineers vp (1984) Baxter L L (1992) Combustion model predicts properties of coal ash deposits Sandia Science News 27 (6) 4 (Jun 1992) Beer J M SarorllD A F Barta L E (1992) From properties of coal mineral matter to deposition tendencies of fly ash - a modelling route Journal of the Institute of Energy 65 (462) 55-62 (Mar 1992) Behnam-Guilani K Hickey G L Hipple M J (1991) Statistical models for predicting coal-fired generating unit costs and performance Proceedings of the American Power Conference 53 888-892 (1991) Bend S L (1989) Coal characterisation and combustion PhD Thesis Newcastle upon Tyne UK University of Newcastle upon Tyne 189 pp (Nov 1989) Bennett R Fogel W Aloia P (1988) Wet fuel handling A program to minimize plugging In Defining coal handleability Its cost impact and control Lexington KY USA 30 Apr-l May 1987 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Information Services pp 41-410 (Nov 1988) Benson S A Steadman E N Kalmanovitch D P (1988) Studies of the fonnation of alkali and alkaline earth aluminosilicates during coal combustion using a laboratory scale furnace In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 31-312 (1988) Berkowitz N (1985) The methods of coal chemistry In The chemistry of coal Amsterdam the Netherlands Elsevier Science Publishers pp 33-102 (1985)
Berkowitz N (1989) Atmospheric oxidation of coal In Sample selection aging and reactivity of coal New York NY USA John Wiley and Sons pp 217-253 (1989) Blake M W (1988) Estimating benefits from cleaning coals In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 667-676 (1988) Blake M W Robin T T (1982) Coal quality influence on operating plant cost Paper presented at Ninth annual engineering conference on reliability for the electric power industry Hershey PA USA 16-19 Jun 1982 Blondin J Girardeau M Nomine M (1988) Two simple tests for the assessment of wet fine coal handleability In Industrial practice offine coal processing KIimpel R R Luckie P T (eds) Littleton CO USA SME-AIME pp 253-255 (1988) Blough J L Kihara S Wolowodiuk W (1988) Effects of coal properties on superheater corrosion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 235-253 (1988) Boley D G (1984) Calcium chloride A new solution for frozen coal Power 128 (1) 67-69 (Jan 1984) Borio R W Levasseur A A (1986) Coal ash deposition in boilers ACS Symposium Series 103 288-302 (1986) Borio R W Levasseur A A Chow 0 K Miemiec L S (1992) Ash deposition a boiler manufacturers perspective In Engineering Foundation conference on inorganic transfonnations and ash deposition during combustion Palm Coast FL USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 95-120 (1992) Borio R W Plumley A L Sylvester W R (1978) Improved thennal efficiency by controlling of factors affecting metal wastage in pulverized coal-fired steam generators In Ash deposits and corrosion due to impurities in combustion gases Bryers R W (ed) Washington DC USA Hemisphere Publishing pp 163-183 (1978) Boushka M (1988) Application of EPRIs coal quality impact model In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Infonnation Services pp AI-A20 (May 1988) Boyd R K Kent J H (1986) Three-dimensional furnace computer modelling In Twentyjirst symposium (international) on combustion Munich Federal Republic of Gennany 3 Aug 1986 Pittsburgh PA USA The Combustion Institute pp 265-274 (1986) Boyd R K Lowe A (1988) Three-dimensional modeling of a pulverised-coal fired utility furnace In Coal combustion science and technology of industrial and utility application Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 165-172 (1988) Boyd R K Lowe A (1992) Sydney NSW Australia Pacific Power Services Personal communication (Sep 1992) Bretz E A (1991a) Specifying powerplant fuels and combustion systems Electrical World 205 (2) 40-45 (Feb 1991) Bretz E A (1991b) Innovation key to finding unusual ash-disposal options Electrical World 205 (7) 56-57 (Jul 1991) Brooks K Glasser D (1986) A simplified model of
105
References
spontaneous combustion in coal stockpiles Fuel 65 (8) 1035-1041 (Jug 1986) Brooks S Meadowcroft DB Morris C W Flatley T A (1983) J laboratory evaluation of alloys potentially resistant to furnace wall corrosion In Corrosion resistant materials in coal conversion systems Meadowcroft D B Manning M S (eds) London UK Jpplied Science Publishers pp 121-135 (1983) Brown K (1985) Sampling testing and analysis of coals In An intensive course on the characterisation of steaming coals Newcastle NSW Justralia 20-22 May 1985 Newcastle NSW Justralia University of Newcastle Institute of Coal Research pp 21-239 (May 1985) Bryers R W (1992) Fireside behaviour of mineral impurities in fuels from Marchwood 1963 to the Sheraton Palm Coast 1992 In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USJ 10-15 Mar 1991 New York NY USJ Jmerican Society of Mechanical Engineers pp 3-70 (1992) Bull D L (1992) Jsh deposition a utility perspective In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USJ 10-15 Mar 1991 New York NY USJ Jmerican Society of Mechanical Engineers pp 121-132 (1992) Burchill P (1987) Some observations on the variation of nitrogen content and functionality with coal rank In 1987 International conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Jmsterdam the Netherlands Elsevier Science Publishing Company pp 5-8 (1987) Byrne G J Juniper L A (1987) Utilization characteristics of Justralian steaming coals in overseas power stations In Coal Power 87 The AUSIMM annual conference in association with the Mining and Metallurgical Institute of Japan (MMIJ) Newcastle NSW Justralia May 1987 Parkville Vic Justralia The Justralasian Institute of Mining and Metallurgy pp 293-301 (May 1987) Cacka H Lang I Fabianova D (1989) Vliv prvkoveho slozeni uhli HDBS a jejich THF extraktu na nizkoteplotni oxidaci uhli (Effects of elementary composition of coal from the Sokolov brown coal basin and its tetrahydrofuran extracts on low-temperature oxidation) In 2 celostatni konference Samovolne vmecovani uhli v teoril a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSJV pp 1-14 (1989) Cagnetta A C Zelensky G (1983) Coal qualitydesigning a power plant for a wide range or dedicated coal supply In Fifth international coal utilization exhibition and conference Houston TX USJ 7-9 Dec 1982 Houston TX US1 EBJSCO Services Inc pp 3-14 (Dec 1983) Calarco V Bennett D (1989) United States acid rain legislation implications for the international coal markets In CoalTrans 89 sixth international coal trade and transportation conference London UK 16-18 Oct 1989 Worcester Park UK CoalTrans Conferences Ltd vp (1989) Carmichael R L (1987) Factors influencing selection of coals for existing power plants In International symposium on mining technology and science Xuzhou China 18 Sep 1985 Beijing China China Coal Industry Publishing House pp 1365-1371 (1987)
Carpenter A (1988) Coal classification IEJCR12 London UK IEJ Coal Research 104 pp (Oct 1988) Cerkanowicz A E Liskowitz J W Wecharatana M (1991) Potential model of the energy manufacturing process to predict properties of fly-ash as it relates to utilization In Eighth annual international Pittsburgh coal conference Coal - energy and the environment Pittsburgh PJ USJ 14-18 Oct 1991 Greenburg PA USJ Pittsburgh Coal Conference pp 839-842 (1991) Chamberlain R A C Hall D A (1973) The liability of coals to spontaneous combustion Colliery Guardian 221 (2) 65 (Feb 1973) Chen J Y Harris D J Smith I W Zhang D K Wall T F Stanmore B R (1991) Combustion reactivity of coals shyevaluation of laboratory techniques In 1991 international conference on coal science - proceedings Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 303-306 (Sep 1991) Chen X D (1991) The effect of moisture content on the spontaneous ignition process - a review In Proceedings of the fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Jssociation of New Zealand vol 2 pp 327-337 (1991) Chou SF Daniels P L Rodgers L W Theus G J Eskinazi D (1986) Fire-side corrosion in 10w-NOx
combustion systems In Proceedings Symposium on stationary combustion NOx control Boston MJ US1 6-9 May 1985 EPRI-CS-4360 Palo Jlto C1 US1 EPRI Technicallnfonnation Services pp 191-1922 (Jan 1986) Cichanowicz J E Harrison C D (1989) The role of coal cleaning in integrated environmental control In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Jlto C1 USA EPRI Technical Information Services pp 711-724 (Oct 1989) Clarke F Morris C W (1983) Combustion aspects of furnace wall corrosion In Corrosion resistant materials in coal conversion systems Meadowcroft D B Manning M I (eds) London UK Jpplied Science Publishers pp 47-61 (1983) Clarke L Sloss L (1992) Trace elements emissions from coal combustion and gasification IEJCR49 London UK IEJ Coal Research 111 pp (1992) Clemens A H Matheson T W Rogers D E (1990) DTJ studies of the low temperature oxidation of low rank coals Fuel 69 (2) 255-256 (Feb 1990) Coal Research Establishment British Coal Corporation (1991) Studies of the production ofnitrogen oxides and ash deposition from pulverised coal in relation to utilisation in low NOx burners EUR 13443 EN Luxembourg Commission of the European Communities 46 pp (1991) CoaiTrans International (1991) Coal in the environmentshysupplement CoalTrans International 6 (2) VI-XIII (MarlJpr 1991) Colijn H (1988a) Coal properties handleability and bin design In Defining coal handleability Its cost impact and control Lexington KY USJ 30 Jpr-1 May 1987 EPRI-CS-6015 Palo Jlto CJ USA EPRI Research Reports Center pp 21-219 (Nov 1988) Colijn H (1988b) Coal handleability as part of coal quality control In 1988 joint power generation conference
106
References
Philadelphia PA USA 25-29 Sep 1988 New York NY USA The American Society of Mechanical Engineers pp 25-41 (Sep 1988) Collins S (1990) Can problems arising from chlorine in coal be solved generically Power 134 (12) 59-60 (Dec 1990) Connelly L J (1988) Freeze condition agents and their use in the coal industry In Defining coal handleability Its cost impact and control Lexington KY USA 30 Apr-l May 1987 EPRI-CS-6015 Palo Alto CA USA EPRI Research Reports Center pp 31-327 (Nov 1988) Conroy A (1991) Grinding behaviour of hard coals Combustion News 1-4 (Nov 1991) Corder W C (1983) For lower power costs use high quality coal In Third European coal utilisation conference Amsterdam The Netherlands 11-13 Oct 1983 Rotterdam The Netherlands Industrial Presentations pp 221-240 (1983) Corio M R (1982) Heat rates and availability the use of econometric analysis in comparing electric generating unit performance New York NY USA National Economic Research Associates vp (1982) Corson P B (1988) Carolina Power and Light purchasing model (COALBUY) In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 41-410 (May 1988) Cortsen C E (1983) An evaluation of coal properties and their influence on the utilisation in power stations Report No2 2nd ed Fredericia Denmark ELSAM Coal Quality Committee 161 pp (Nov 1983) Couch G R (1988) Lignite resources and characteristics IEACR13 London UK IEA Coal Research 102 pp (Dec 1988) Couch G R (1989) Power generationfrom lignite IEACR19 London UK IEA Coal Research 67 pp (Dec 1989) Couch G R (1991) Advanced coal cleaning technology IEACR44 London UK IEA Coal Research 95 pp (1991) Cox J N Smith S R Metha A (1990) Field evaluation of EPRI coal quality impact model In Proceedings 1989 EPRl heat-rate improvement conference Knoxville TN USA 26-28 Sep 1989 EPRI-GS-6985 Palo Alto CA USA EPRI Research Reports Center pp 4B61-4B68 (Sep 1990) CQ Inc (1992) The Acid Rain Advisor Homer City PA USA CQ Inc 2 pp (1992) Crelling J C Skorupska N M Marsh H (1988) Reactivity of coal macerals and lithotypes Fuel 67 (6) 781-785 (lun 1988) Cumming J W (1980) The electrical resistance of coal ash at elevated temperatures Journal of the Institute of Energy 53 (416) 153-154 (Sep 1980) Cumming J W Livingston W R Hesselmann G J (1987) Coal reactivity assessment for boiler design In Coaltech 87 - Coaltrade 87 - conference papers London UK 9-11 Jun 1987 Schiedam the Netherlands Industrial Presentations pp 11-30 (1987) Cunliffe F (1990) Thornton UK Shell Research Limited Personal communication (1990) Dacey P W Cope D R (1986) Process development In Flue gas desulphurisation - system performance ICEASIB4 London UK IEA Coal Research pp 44-48 (Dec 1986) Daniel M (1991a) Power station coal use prospects to 2000 IEACR4l London UK IEA Coal Research 61 pp (Oct 1991)
Daniel P L (1991b) The effect of coal chlorides on furnace wall corrosion In First international conference on chlorine in coal Chicago IL USA 9-11 Oct 1989 Amsterdam the Netherlands Elsevier Science Publishers pp 207-224 (1991) Darby K (1983) Commercial precipitator design In Second CSIRO conference on electrostatic precipitation Bowral NSW Australia 17-19 Aug 1983 North Ryde NSW Australia Commonwealth Scientific Industrial Research Organisation pp L41-L431 (1983) Davidson R (1990) Effects on coal behaviour In Natural oxidation of coal IEACR29 London UK IEA Coal Research pp 55-65 (Sep 1990) Davis A (1984) Coal petrography and petrographic analysis In Coal geology and coal technology Ward C R (ed) Melbourne Vic Australia Blackwell Scientific Publications pp 74-112 (1984) Deiuliis N J Fink C E Abbott M F (1991) The impact of ash quantity and quality on boiler performance and power cost In Eighth annual international Pittsburgh coal conference Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greenburg PA USA Pittsburgh Coal Conference pp 975-980 (1991) Deutsch W (1922) Bewegung und Ladung der Elektrizitatstrager im Zylinderkondensator (Velocity and loading of charged particles in cyclinder capacitors) Annales der Physik 68 335-344 (1922) Diessel C F K Bailey J G (1989) The application of petrographic techniques to carbonisation and combustion research at the University of Newcastle In MINPET 89shyMineralogy-petrology symposium Sydney NSW Australia 6-8 Feb 1989 Sydney NSW Australia The Australasian Institute of Mining and Metallurgy pp 117-121 (Feb 1989) Donais R T Tyler A L Bakker W T (1988) Effects of coal properties on pulverizer abrasion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 21-217 (1988) Dooley B (1992) Boiler tube failures - a perspective and a vision In International conference on boiler tube failures in fossil plants San Diego CA USA 5-7 Nov 1991 EPRI-TR-100493 Palo Alto CA USA EPRI Distribution Centre pp 11-129 (Apr 1992) Doyle G (1989) Price premiums and inter-coal competition In CoalTrans 89 sixth international coal trade and transportation conference London UK 16-18 Oct 1989 Worcester Park UK CoalTrans Conferences Ltd pp 177-180 (1989) Dusak V (1986) Brown coal and its safe storage Energetika 36 (1011) 471-474 (Oct 1986) Eck G A (1987) Perfectblend coal blending computer program Journal of Coal Quality 6 (3) 100-101 (lui 1987) Electrical World (1987) Utilities report boiler failure chief culprit in forced outages Electrical World 201 (8) 50-52 (Aug 1987) Elliott M A (ed) (1981) Chemistry of coal utilizationshysecond supplementary volume New York NY USA John Wiley and Sons 2274 pp (1981) Elliott T C (1991) Monitoring powerplant performance Power 135 (9) 11-26 (Sep 1991) Elliott T C (1992) Coal handling and preparation Power 136 (1) 17-33 (Jan 1992) ERM Consultants Pty Ltd (1983) Australian case studies
107
References
which relate to coal quality andor consistency to efficiency and economy ofpower production Brisbane Qld Australia ERM Consultants Pty Ltd vp (Mar 1983) Essenhigh R H (1981) Fundamentals of coal combustion In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley and Sons pp 1153-1312 (1981) Evans R J (1991) A computer expert system to reduce power plant emissions PErC Review (4) 24-28 (1991) Falcon L M Falcon R M S (1987) The petrographic composition of Southern African coals in relation to friability hardness and abrasive indices Journal of South African Institute ofMining and Metallurgy 87 (10) 323-336 (Oct 1987) Falcon R M S Snyman C P (1986) An introduction to coal petrography atlas ofpetrographic constituents in the bituminous coals of South Africa Johannesburg South Africa Geological Society of South Africa 27 pp (1986) Falcon R Ham A J (1988) The characteristics of Southern African coals Journal of South African Institute ofMining and Metallurgy 88 (5) 145-161 (May 1988) Fiveland W A Wessel R A (1988) Numerical model for predicting perfonnance of three-dimensional pulverized-fuel fired furnaces Journal ofEngineering for Gas Turbines and Power 110 117-129 (1988) Flatley T Latham E P Morris C W (1981) Co-extruded tubes improve resistance to fuel ash corrosion in UK boilers Material Performance 20 (5) 12-17 (May 1981) Folsom B A Heap M P PoW J H (1986a) Effect of coal quality on power plant performance and costs - Volume 1 State-of-the-art review summary and program plan EPRl-CS-4283-Vol1 Palo Alto CA USA EPRl Technical Infonnation Services 262 pp (Feb 1986) Folsom B A Heap M P PoW J H Smith J L Corio M R (1986b) Effect of coal quality on power plant performance and costs - Volume 2 Review of coal quality impact evaluation procedures EPRl-CS-4283-Vo12 Palo Alto CA USA EPRl Technical Infonnation Services 387 pp (Feb 1986) Folsom B A Heap M P PoW J H Smith J L (1986c) Effect of coal quality on power plant performance and costs - Volume 3 Review of coal quality and power plant performance diagnostics EPRl-CS-4283-Vo13 Palo Alto CA USA EPRI Technical Infonnation Services 176 pp (Feb 1986) Fortune D B (1990) London UK Shell Coal International Ltd Personal communication (1990) Galluzzo N G Stallard G S Boushka M E Mehta A K (1987) Model predicts as-fired costs of changing coal sources Power 131 (6) 53-56 (Jun 1987) Gebel K Madlsperger G Hein K Bokenbrink D (1989) Entwicklung eines Kombinations DeNOx-Verfahrens unter Verwendung von feuerungstechnischen Minderungsrnassnahmen und Hamstoff-SNCR-Technik (Development of a combined DeNOx process using staged combustion and urea-SNCR technology) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Gennany 26-27 Apr 1989 Essen Federal Republic of Gennany VGB Kraftswerkstechnik GmbH pp 173-180 (Apr 1989) Gibb W H (1983) The nature of chlorine in coal and its
behaviour during combustion In Corrosion resistant materials for coal conversion systems Meadowcroft D B Manning M S (eds) London UK Applied Science Publishers pp 25-45 (1983) Gibb W H (1992) Nottingham UK PowerGen Ratcliffe Technology Centre Personal communication (Sep 1992) Gibbs L A Hallett W L H Hughes P M (1989) Coal devolatilization in an entrained flow reactor In The Combustion 1nstitute Canadian Section 1989 spring technical meeting Toronto Ontario Canada 31 May-2 Jun 1989 Ontario Canada The Combustion Institute pp 91-93 (1989) Giovanni D V Afonso R F Dyas B E Mehta A K (1991) Coal quality field test at New England power companys Salem Harbour Unit Three In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRl-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 379-398 (Jul 1991) Given P H (1984) An essay on the organic geochemistry of coal In Coal science volume 3 Gorbaty M L Larsen J Wender I (eds) Orlando FL USA Academic Press pp 63-252 (1984) Given P H Yarzab R F (1978) Coal analysis and mineral matter In Analytical methods for coal and coal products shyVolume II Karr C Jr (ed) New York NY USA Academic Press pp 3-42 (1978) Gluskoter H J Shimp N F Ruch R R (1981) Coal analyses trace elements and mineral matter In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley amp Sons pp 369-424 (1981) Goddard C W Duzy A F (1967) Measuring abrasiveness of solid fuels and other materials by a radiochemical method ASME paper no 67-WAIFU-l New York NY USA American Society of Mechanical Engineers vp (1967) Goetz G J Nsakala N Y Borio R W (1978) Development of methods for determining emissintives and adsorptivities of coal ash deposits In 1987 winter annual ASME meeting Boston MA USA 13 Dec 1978 New York NY USA American Society of Mechanical Engineers vp (1978) Gomer K (1988) Prediction of the turbulent flow heat release and heat transfer in utility boiler furnaces In Coal combustion Science and technology of industrial and utility applications Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 273-282 (1988) Gutberlet H (1988) Einfluss der Feuerungsart auf die Vergiftung von DeNOx-Katalysatoren durch Arsen (The effect of furnace type on the poisoning of DeNOx catalysts by arsenic) VGB Kraftwerkstechnik 68 (3) 287-293 (Mar 1988) Hainley D C Yavuzkurt S Scaroni A W (1986) Effect of coal properties on fluidized bed combustor perfonnance In Energy-sources technology conference and exhibition New Orleans LA USA 23 Feb 1986 New York NY USA American Society of Mechanical Engineers pp 43-54 (1986) Hampartsoumian E Murdoch M Pourkashanian M Williams A (1991) The reactivity of coal chars produced under various pyrolysing conditions In 1991 international conference on coal science - proceedings Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 271-274 (Sep 1991) Harb J N Smith E E (1990) Fireside corrosion in PC-fired
108
References
boilers Progress in Energy and Combustion Science 16 (3) 169-190 (1990) Hardgrove R M (1938) ASME technical paper Paper presented at ASME spring meeting Chicago IL USA 27 Jun 1938 Harrington R C Kaltenback R P Stratton H L (1988) Burner improvement program on a 650 MW supercritical steam generator - a case study In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 541-549 (Sep 1988) Harrison C Zera C (1990) A new way of doing business in coal-fired power generation Power Engineering 94 (4) 33-36 (Apr 1990) Hatt R M (1990) Fireside deposits in coal-fired utility boilers Progress in Energy and Combustion Science 16 (4) 235-241 (1990) Hatt R M (1991) Coal mining and preparation practices shyimpacts on power plant perfonnance In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 365-377 (Jul 1991) Heap M P Kramlich J C Pershing D W Pohl J H Richter W F Seeker W R (1986) Effect of coal quality on power plant performance and costs - Volume 4 Review of coal science fundamentals EPRI-CS-4283-Vo14 Palo Alto CA USA EPRI Technical Infonnation Services 574 pp (Feb 1986) Heap M P Pohl A S Folsom A S Mehta A K (1984) The effects of coal quality and the resulting ash deposition on the costs of power station operation (Die Bedeutung der Kohlqualitiit und der daraus resultierenden Aschelagerungen fur die Kostan des Kraftwerksbetriebes) In Internationale VGB-Konferenz Verschlackungen Verschmutzungen und Korrosionen in Wriimekraftwerken - Vortriige Essen Federal Republic of Gennany 29 Feb-2 Mar 1984 Essen Federal Republic of Gennany VGB Technische Vereinigung der Grosskraftwerksbetreiber eV pp 493-507 (1984) Heble J J Srinivaschar S Boni A A (1991) The behaviour of clay minerals under combustion conditions American Chemical Society Division of Fuel Chemistry Preprints 36 (1) 173-180 (Apr 1991) Heitmiiller W Schuster H (1991) Low-NOx pulverized coal firing systems and their components Infonnation No 189 Hausdruckerei Gennany Deutsche Babcock Energie- und Umwelttechnik AG 17 pp (Mar 1991) Hervol J D Mehta A K Levasseur A A Miemiec L S Lexa G F (1988) Benefits of coal cleaning on the capital and operating costs of a 550 MW boiler In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 81-824 (May 1988) Hewing A N Harvey M R (1981) Evaluating freeze conditioning agents for coal Power Engineering 85 (7) 74-75 (JuI1981) Hjalmarsson A-K (1990) NOx control technologies for coal combustion IEACRl24 London UK lEA Coal Research 102 pp (Jun 1990) Hjalmarsson A-K (1992) Interactions in emissions control for coal-fired plant IEACRl47 London UK lEA Coal Research 81 pp (Mar 1992) Hjalmarsson A-K Soud H N (1990) Systems for controlling
NOxfrom coal combustion IEACRl30 London UK lEA Coal Research 240 pp (Dec 1990) Hobbs M L Smith P J (1990) Algebraic multi-zoned radiation model for a two-zoned zero-dimensional cylindrical furnace Fuel 69 (11) 1420-1427 (Nov 1990) Hodde J A (1988) Least cost fuel system used to plan fuel purchases In 1988 joint power generation conference Philadelphia PA USA 25-29 Sep 1988 New York NY USA American Society of Mechanical Engineers pp 43-51 (Sep 1988) Holstein R A (1981) Coal fired power plant capital cost estimates EPRI-PE-1865 Palo Alto CA USA EPRI Technical Infonnation Services vp (1981) Horsfall D W Zitron Z (1982) High density beneficiation of coal In Proceedings sixth international conference on coal research London UK 4-8 Oct 1982 London UK National Coal Board pp 319-337 (1982) lEA Coal Industry Advisory Board (1985) Coal quality and ash characteristics Paris France OECDIIEA 63 pp (Jan 1985) IEEE (1984) IEEE standard criteria and guidelines for the laboratory measurement and reporting offly ash resistivity IEEE Standard 548-1984 New York NY USA Institute of Electrical and Electronics Engineers 30 pp (21 Dec 1984) ICCP International Committee for Coal Petrology (1963) International handbook of coal petrology - second edition Paris France Centre National de la Recherche Scientifique vp (1963) ICCP International Committee for Coal Petrology (1975) International handbook of coal petrology - supplement to the second edition Paris France Centre National de la Recherche Scientifique vp (1975) ICCP International Committee for Coal Petrology (1985) International handbook of coal petrology - edited reprint of 1975 supplement to the second edition Murchison D G Smith A H V (eds) Newcastle upon Tyne UK University of Newcastle upon Tyne vp (1985) International Energy Agency (1992) Coal information 1992 Paris France OECDIIEA 541 pp (1992) Iskhakov Kh A (1990) The role of sorbed moisture in coal oxidation Solid Fuel Chemistry (English translation) 24 (2) 17-21 (1990) Jacobs J P (1992) Essen Gennany VGB Technical Association of Large Power Plant Operators Personal communication (Sep 1992) Jamaluddin A S Fiveland W A (1990) Practical model for predicting unburned carbon and temperatures in large-scale boilers Paper presented at 1990 spring meeting combustion fundamentals and applications Cincinnati OH USA 20-22 May 1990 Jenson P T (1992) Fredericia Denmark ELSAM Personal communication (Sep 1992) Johanson J R (1989) Evaluating coal handling characteristics In 1989 joint power generation conference Dallas TX USA 22-26 Oct 1989 New York NY USA American Society of Mechanical Engineers pp 1-5 (Oct 1989) Johanson J R (1991) Identify hard-to-handle coal early Power Engineering 95 (11) 35-38 (Nov 1991) Johnson R P Plangemann R Rehm M (1991) Coal quality effects on boiler perfonnance an Eastern utility perspective In Effects of coal quality on power plants St Louis MI
109
References
USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 11-113 (Jul 1991) Jones A R Gibb W Johnston J (1992) Nottingham UK PowerGen Ratcliffe Technology Centre Personal communication (Mar 1992) Jones M L Benson S A (1988) An overview of slagginglfouling with Western coals In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 125-147 (1988) Jones R B McCourt C B Morley C King K (1985) Maceral and rank influences on the morphology of coal char Fuel 64 (10) 1460-1467 (Oct 1985) Juniper L Pohl J (1991) Techniques to control NOx
emissions from coal-fIred boilers Australian Combustion Technology Centre Combustion News 1-4 (May 1991) Jiintgen H (1987a) Coal characterization in relation to coal combustion Part I structural aspects and combustion Erdol Kohle Erdgas Petrochemie vereinigt mit Brennstoff-Chemie 40 (4) 153-165 (Apr 1987) Jiintgen H (1987b) Coal characterization in relation to coal combustion Part II environmental problems of combustion ErdOl Kohle Erdgas Petrochemie vereinigt mit Brennstoff-Chemie 40 (5) 204-208 (May 1987) Kalmanovitch D P (1991) A practical approach to predicting ash deposition In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 591-5102 (Jul 1991) Kapteijn F Bruinsma D Mol J Moolijn J A (1990) The characterisation of fly-chars from combustion the effect of temperature and rank on reactivity texture and composition Fuel Processing Technology 24 (113) 391-398 (1990) Kautz K (1982) Importance of maceral content in regard to the properties of coals of worldwide origin and its effects on combustion chamber design of large dry furnaces VGB Kraftwerkstechnik - English Issue 62 (3) 1-12 (Mar 1982) Kehoe D B Hervol J D Evans R J Levasseur A A (1990) Evaluating the effects of cleaned coals in utility boilers In Eleventh international coal preparation congress Tokyo Japan 22-25 Oct 1990 Tokyo Japan Mining and Materials Processing Institute of Japan pp 247-252 (1990) Kemeny P (1988) Coal quality impact on electric power generation costs case study Fusina unit 3 In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 631-655 (1988) King J G Maries M B Crossley H E (1936) Fonnulae for the calculation of coal analysis to a basis of coal substance free of mineral matter Journal for the Society of Chemistry and Industry 55 277-281 (1936) Kirchner A T (1991) On-line analysis of coal IEACR40 London UK lEA Coal Research 79 pp (Sep 1991) Kiss L T King TN (1979) Reporting of low-rank coal analysis - the distinction between minerals and inorganics Fuel 58 (7) 547-549 (Jul 1979) Klingspor J S Vernon J L (1988) Particulate control for coal combustion IEACR05 London UK lEA Coal Research 70 pp (Feb 1988) Klitgaard J (1988) Utility coal quality work at a cross-road Journal of Coal Quality 7 (2) 36-37 (Jun 1988) Knill K J (1987) A review offuel staging in pulverised coal
combustion systems IFRF-G-13a3 IJmuiden Netherlands International Flame Research Foundation 54 pp (Sep 1987) Kok A (1988) The effect of coal type on carbon burnout and NOx fonnation in pulverized coal combustion In Coaltech 88 - Coaltrade 88 seventh international conference on coal technology and coal trade Amsterdam the Netherlands 21-23 Nov 1988 Amsterdam the Netherlands Industrial Presentations (Europe) BV pp 1-14 B3 (1988) Kosvic T C Breen B P Yingling J C Mazumdar M Carpenter M Stothart B Plangemann R Maurer W (1988) A combined mechanisticstatistical approach to relating coal properties and boiler operating characteristics to the perfonnance of coal fIred boilers In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 71-717 (Sep 1988) Kremer H Grigoleit H Jacobs J (1990) Tendency of power station coals to fonn NOx - Results of VGB Research Project 89 VGB Kraftwerkstechnik - English Issue 70 (7) 478-484 (Jul 1990) Latham C E Fiveland W A La Rue A D (1991a) Numerical models as combustion system design tools In Eighth annual international Pittsburgh coal conference proceedings Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greenburg PA USA Pittsburgh Coal Conference pp 34-39 (1991) Latham E Meadowcroft D B Pinder L (1991b) The effects of coal chlorine on fireside corrosion In First international conference on chlorine in coal Chicago IL USA 9-11 Oct 1989 Amsterdam the Netherlands Elsevier Science Publishers pp 225-250 (1991) Laurendeau N M (1978) Heterogeneous kinetics of coal char gasification and combustion Progress in Energy and Combustion Science 4 (4) 221-270 (1978) Lee G K Thambimuthu K V Hill J M (1991) Assessment of ash sintering potential by conductance and dilatometry In Eight annual international Pittsburgh coal conference proceedings Coal - energy and the environment Pittsburgh PA USA 14-18 Oct 1991 Greensburg PA USA Pittsburgh Coal Conference pp 6-11 (1991) Llewellyn W (1991) A practical study of coal handleability In Proceedings of the fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Association of New Zealand vol 1 pp 115-126 (1991) Llinares V Caron M B Schmidt E J Szela F J (1982) The C-E availability data program 1982 further developments on MTTR and MTBF analysis Paper presented at Ninth annual engineering conference on reliability for the electric power industry Hershey PA USA 16-19 Jun 1982 Llinares V Lutz A B (1985) Long range forecast and availability improvement program In Proceedings of the 1985 joint ASMEIEEE power generation conference Milwaukee WI USA 20 Oct 1985 New York NY USA American Society of Mechanical Engineers vp (1985) Lockwood F C Mahmud T (1989) The prediction of swirl burner pulverized coal flames In Twenty-second symposium (international) on combustion Seattle WA USA 14-19 Aug 1988 Pittsburgh PA USA The Combustion Institute pp 165-173 (1989) Lowe A (1987) Important coal properties for power
110
References
generation In Geology and coal mining conference Sydney NSW Australia 13-15 Oct 1987 Sydney NSW Australia Geological Society of Australia Coal Geology Group pp 188-196 (Oct 1987) Lowe A (1988a) Effect of ash levels on large pulverised coal fired furnace performance In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 523-540 (Sep 1988) Lowe A (1988b) Effect of ash in coal on power plant availability In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 733-744 (1988) Luckie P T and others (1980) Coal grinding technology A manual for process engineers ERDA FE-2475-25 USA US Government Printing Office No 1980-640-258-2090 vp (1980) Luo X-L Boyd R K Kent J H (1991) Computational investigation of burnout in a furnace firing pulverised coal Journal of the Institute of Energy 64 (461) 230-238 (Dec 1991) Mackowsky M Th (1982) Minerals and trace elements occurring in coal In Stachs textbook of coal petrology Stach E Mackowsky M Th Teichrnller M Taylor G H Chandra D Teichrnller R (eds) Berlin Federal Republic of Germany Gebriider Borntraeger pp 153-171 (1982) Maher T P Smith MY (1990) A user-friendly coal value model for thermal coals In 1990 international coal engineering conference Sydney NSW Australia 19-21 lun 1990 Barton ACT Australia Institution of Engineers pp 259-263 (lun 1990) Mahr D (1988) Blending coal for quality control In 1988 joint power generation conference - coal quality control fundamentals and applications Philadelphia PA USA 25-29 Sep 1988 New York NY USA American Society of Mechanical Engineers pp 1-8 (Sep 1988) Makanski J (1989) Coal analyzers provide critical link for plant control functions Power 133 (2) 23-25 (Feb 1989) Malhotra V M Crelling J C (1987) Spontaneous combustion of coal and maceral enriched fractions under storage pneumatic transport conditions Final report DOEIPC79863-T13 Carbondale IL USA Coal Extraction and Utilization Research Center 97 pp (Mar 1987) Mancini R A Hopkins B W Hodde J A (1987) Coal quality engineering aids purchasing Power Engineering 91 (6) 16-20 (lun 1987) Mancini R A Hopkins B W Hodde J A (1988) Coal quality engineering analysis used to evaluate coal purchases In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 Palo Alto CA USA EPRI Research Reports Center pp 51-515 (May 1988) Mason D M Gandhi K (1980) Formulas for calculating the heating value of coal and char development tests and uses American Chemical Society Division of Fuel Chemistry Preprints 25 (3) 235-245 (1980) Matsuura S Uchida S (1988) Spontaneous combustion susceptibility of coals Saiko to Hoan 34 (10) 2-14 (25 Oct 1988) Matts S A Ohnfeldt P 0 (1973) Efficient gas cleaning with SF electrostatic precipitators Vaxjo Sweden Flakt Industri AB vp (1973)
McCartney R H Whittaker P S Planner J H (1990) A comparison of United States and Australian practices for power station coal handling facilities In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 lun 1990 Sydney NSW Australia Institution of Engineers pp 174-183 (lun 1990) Mehta A (1989) Coal quality impact model EPRl Journal 14 (8) 49-52 (Dec 1989) Mellanby-Lee H (1986) Effects of coal quality on the costs of electricity generation In Physical coal beneficiation and electricity costs ICEASC3 London UK lEA Coal Research pp 18-30 (Feb 1986) Meyers A D Atkinson B W (1991) Using techno-economic computer modelling to assess the utilisation value of New Zealand coal on the world market In Fourth New Zealand coal conference Wellington New Zealand 14-16 Oct 1991 Lower Hutt New Zealand Coal Research Association of New Zealand pp 160-171 (1991) Mikula R J Parsons I S (1991) Coal dustiness characterisation and control Coal Preparation 9 (314) 199-212 (1991) Misra M K Essenhigh R H (1990) Modelling of one-dimensional pulverised coal flames Paper presented at 1990 spring technical meeting combustion fundamentals and applications Cincinnati OH USA 20-22 May 1990 Mitas D Stallard S Anderson-Higgs A OConnor D (1991) Coal quality analysis linked to power plant control Power Engineering 95 (5) 29-32 (May 1991) Mittelbach G (1989) NOx- Minderung an Kohle-und Mtillkesseln mit dem TermoNOx Verfahren Vergleich von Untersuchungsergebnissen (NOx reduction at coal-fired plants and refuse incinerators with the ThermoNOx process a comparison of test results) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Germany 26-27 Apr 1989 Essen Federal Republic of Germany VGB Kraftswerkstechnik GmbH pp 194-200 (Apr 1989) Morgan M E (1987) Characterisation of coals for use in pulverised coal combustion In International conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 823-826 (1987) Morgan ME (1990) Effect of coal quality on the performance of low-NOx burners Journal of the Institute of Energy 66 (454) 3-8 (Mar 1990) Morgan P A Robertson S D Unsworth J F (1987) Combustion studies by thermogravimetric analysis Fuel 66 (2) 210-215 (Feb 1987) Morrison G F (1982) Control of sulphur oxides from coal combustion ICTISITR21 London UK lEA Coal Research 104 pp (Nov 1982) Morrison G F (1986) Understanding pulverised coal combustion ICTISITR34 London UK lEA Coal Research 46 pp (Dec 1986) Murtha M J (1982) Minerals extraction from ash state of the art In Proceedings of resources from coal coal wastes and ash workshop Reston VA USA 9 lun 1982 BNL-51679 DE83017775 Springfield VA USA National Technical Information Service pp 91-103 (1982) Muter R B Lawrence W F (1986) Mineral matter analysis a technique to improve bituminous coal ACS Symposium Series 301 443-448 (1986)
111
References
Myllynen H (1987) Which thermal coal In Coal Power 87 Neuss Dusseldorf Federal Republic of Germany 27-29 Oct 1987 Worcester Park UK CS Publications Ltd pp 37-42 (1987) Nadgauda S S Hathaway A J (1990) Coal utilization cost model for fuel procurement Journal of Coal Quality 9 (1) 17-21 (Mar 1990) Nakabayashi Y (1988) NOx removal from flue gas In The coal in Sweden conference on the role of coal in the Swedish energy system possibilities and limitation SOdertiilje Sweden 26-27 Oct 1988 Sdertlje Sweden Telge Energe AB pp 1-39 (Oct 1988) Nakata T Sato M Makino H (1988) Methods ofpredicting NOx emissions in coal combustion and unburned carbon in fly ash - effects of coal propenies CRIEPI-W-87003 Tokyo Japan Central Research Institute of the Electrical Power Industry 30 pp (Feb 1988) Nandi B N Brown T D Lee G K (1977) Inert coal macerals in combustion Fuel 56 (4) 125-130 (Apr 1977) Nayak R V Bauer F W Tonden T P (1987) Mineral matter in coal - origin identification and boiler erosion Journal of Coal Quality 6 (2) 37-43 (1987) Neavel R C (1981) Origin petrography and classification of coal In Chemistry of coal utilization - second supplementary volume Elliott M A (ed) New York NY USA John Wiley and Sons pp 91-158 (1981) Neavel R C Smith S E Hippo E J Miller R N (1986) Interrelationships between coal compositional parameters Fuel 65 (3) 312-320 (Mar 1986) Nemec J Dobal V (1988) Contribution to problem of coal spontaneous combustion Acta Montana Zpravy Hornickeho Ustavu CSAV (Ceskoslovenske Akademie Ved) (76) 9-20 (1988) Nicol S K Smitham J B (1990) Coal stockpile dust control In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 Jun 1990 Sydney NSW Australia Institution of Engineers pp 154-158 (Jun 1990) Noskievic P Kolat P Cech B (1987) Operational tests of burners for ignition and stabilization of pulverised coal Energetika 37 (5) 233-236 (May 1987) Nurick W (1988) An engineering approach to prediction of fuel impacts on utility boiler systems In Reducing electricity generation costs by improving coal quality Indiana PA USA 5-6 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Research Reports Center pp 71-760 (May 1988) Oka N Murayama T Masuoka H Yamada S Yamada T Shinozaki S Shibaoka M Thomas C G (1987) The influence of rank and maceral composition on ignition and char burnout of pulverized coal Fuel Processing Technology 15 213-224 (Jan 1987) Osborn G A (1992) Review of sulphur and chlorine retention in coal-fIred boiler deposits Fuel 71 (2) 131-142 (Feb 1992) OKeefe W Hart R M Hopkins B W McIntire D C Harrison C D (1987) Do we need highly detailed coal specs Power 131 (10) 121-123 (Oct 1987) Parish B M (1970) Wear ofpulverisers Research report 363 Cheltenham UK National Coal Board Research Establishment vp (20 Mar 1970) Pasini S Trebbi G (1989) Evolutions of design and operation criteria for ENEL boilers Paper presented at Tenth international conference on power stations Liege Belgium 25-29 Sep 1989
Pavlikova H Machovic V Sebestova E (1989) Study of low-temperature coal oxidation by means of nuclear magnetic resonance spectrometers infrared spectrometers and electron spin resonance In 2 celostatni konference Samovolne vmecovani uhli v teorii a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSAV pp 1-14 (1989) Penninger A (1989) Effect of working parameters on flame stability for coal dust combustion In Tagung iiber Verbrennung und Feuerung14 Deutscher Flammentag (Meeting on combustion and furnaces 14 Gennan flame day) Stuttgart Federal Republic of Germany 5-6 Oct 1989 Dusseldorf Federal Republic of Germany Verein Deutscher Ingenieure (VDI) - Gesellschaft Energietechnik pp 669-679 (1989) Platfoot R (1990) Erosion life of tube banks in coal fired boilers In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 237-241 (Iun 1990) Pohl J S (1990) Procedure for evaluating the performance of low-grade fuels In Low-grade fuels Helsinki Finland 12-16 Jun 1989 Espoo Finland Valtion Teknillinen Tutkimuskeskus vol 1 pp 247-260 (1990) Potter E (1988) Correlations of ash chemistry with pilot-scale electrostatic precipitation experiments In Workshop on steaming coal testing and characterisation Newcastle NSW Australia 17-19 Nov 1987 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp N33-N34 (1988) PowerGen (1991) POSTMAN steady state plant modelling system Information sheet no 34 Nottingham UK PowerGen pic Power Technology Centre 2 pp (1991) Pronobis M (1989) Further fmdings concerning the effect of ash deposits upon the exchange of heat in convection boiler surfaces VGB Kraftwerkstechnik - English Issue 69 (11) 931-938 (Nov 1989) Raask E (1985) Mineral impurities in coal combustion shybehaviour problems and remedial measures London UK Hemisphere Publishing 506 pp (1985) Rademacher F J C (1990) Coal handling developments focusing on The Netherlands In Coal handling and utilisation conference 1990 Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 282-288 (Jun 1990) Rees 0 W (1966) Chemistry uses and limitations of coal analysis Report of Investigations 220 Urbana IL USA lllinois State Geological Survey 50 pp (1966) Reinschmidt K F (1991) Neural networks next step for simulation and control Power Engineering 95 (11) 41-45 (Nov 1991) Repic B Radulovic P Sikmanovic S Grubor B (1988) Boilers start-up with pulverized coal Paper presented at 20 Kraftwerkstechnisches Kolloquium 1988 (20 power plant technical colloquium) Dresden Federal Republic of Germany 11-12 Oct 1988 Richter W Payne R Heap M P (1986) Influence of thermal properties of wall deposits on performance of pulverised fuel fired boiler combustion chambers ACS Symposium Series (301) 375-393 (1986) Richwine R R Quinn A D Mills J B Lowe S D (1989)
112
References
Results of the availability improvement program in the southern electric system Paper presented at Tenth international conference on power stations Liege Belgium 25-29 Sep 1989 Riley J T Gilleland S R Forsythe R F Graham H D Jr Hayes F J (1989) Nonadditive analytical values for coal blends In Proceedings of the seventh international coal testing conference Ashland KY USA 1989 Ashland KY USA Coal Testing Conference pp 32-38 (1989) Rittenhouse R C (1991) Fighting corrosion in air pollution control systems Power Engineering 95 (6) 23-29 (Jun 1991) Rittenhouse R C (1992) New fuel choices change coal handling and storage rules Power Engineering 96 (1) 17-21 (Jan 1992) Robinson G F (1985) A three-dimensional analytical model of a large tangentially fired furnace Journal of the Institute of Energy 116 226-150 (1985) Roy W R Griffin R A Dickerson D R Schuller R M (1984) illinois basin coal fly ashes 1 Chemical characterisation and solubility Environmental Science and Technology 18 (10) 734-739 (1984) Sadowski R S Hunt P J (1978) Consequences of specifying a boiler design fuel before source commitments are firm In Proceedings of the American power conference Vol 40 Chicago IL USA Apr 1978 Chicago IL USA illinois Institute of Technology pp 394-402 (1978) Sanyal A Livingston W R Marsh H Skorupska N M Field D J Edwards 1 AS (1991) Petrography of lignitic and bituminous coals application to assess coal combustibility for power generation In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 51-520 (JuI1991) Saxena S C (1990) Devolatilization and combustion characteristics of coal particles Progress in Energy and Combustion Science 16 (1) 55-94 (1990) Schaeffer J J (1988) Review of coal quality characteristics of potential utility fuel supply sources Journal of Coal Quality 7 (1) 19-22 (Jan 1988) Scieszka S F (1985) New concept for determining pulverizing properties of coal Fuel 64 (8) 1132-1142 (Aug 1985) Sebesta P Vodickova A (1989) Self-ignition of coal according to its reactivity to oxygen In Symposium on coal utilization trends and challenges Dhanbad India 13-14 Dec 1989 Dhanbad India Central Fuel Research Institute vp (1989) Sherman R A Pilcher J M (1938) An experimental investigation of the use of oil in the treatment of coal Transactions ofAmerican Society of Chemical Engineers 60 97-109 (1938) Shibaoka M Thomas C S Heng S Mackay G H (1987) Significance of morphological features of macerals in coal utilization research In 1987 international conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 107-110 (1987) Shida H Adacchi T Karagasaki M Kuminoto T Hisatome M Kobayashi Y (1984) Development of three-dimensional numerical analysis method of boiler furnace characteristics - part 1 flow analysis Technical Review 18-23 (1984)
Shigeta J-I Hamao Y Aoki H Kajigaya 1 (1987) Development of a coal ash corrosivity index for high temperature corrosion Journal of Engineering Materials and Technology 109 (4) 299-305 (Oct 1987) Shimada S Aumiiller A Klemm F (1991) Measurement of property change of coals stored in stockpile for a long time In 1991 international conference on coal science Newcastle upon Tyne UK 16-20 Sep 1991 Oxford UK Butterworth-Heinemann pp 925-928 (Sep 1991) Shonhardt J A (1990) Evaluation of spontaneous combustion characteristics of some Australian coals Coal Journal (Australia) (29) 21-31 (1990) Singer J G (1989a) Steam fundamentals In Standard handbook ofpower-plant engineering New York NY USA McGraw Hill pp 13-19 (1989) Singer J G (1989b) Pulverizers In Standard handbook of power-plant engineering New York NY USA McGraw Hill pp 1157-1182 (1989) Singer J G (1991) Combustion fossil power - a reference book on fuel burning and steam generation Windsor CN USA Combustion Engineering 1010 pp (1991) Skinner M S A (1988) The costs of burning coal In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Specialists pp 719-731 (1988) Skorupska N M Marsh H (1989) The importance of petrographic characterization of coal for combustion processes In Institute of Energy conference on applied energy research Swansea UK 5-7 Sep 1989 Bristol UK Adam Hilger pp 161-181 (1989) Skorupska N M Sanyal A Hesselman G J Crelling J C Edwards 1 A S Marsh H (1987) The use of an entrained flow reactor to assess the reactivity of coals of high inertinite content In 1987 intemational conference on coal science Maastricht the Netherlands 26-30 Oct 1987 Amsterdam the Netherlands Elsevier Science Publishers pp 827-831 (1987) Sligar J (1985) Coal pulverising mill section In Course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 101-1023 (May 1985) Sligar J (1992) Sydney NSW Australia Pacific Power Services Personal communication (Oct 1992) Smith D J (1991) Integrated control systems The next stop Power Engineering 95 (9) 17-21 (Sep 1991) Smith G (1985) Laboratory studies to support the marketing of Australian coals In Proceedings Coal research conference Wellington New Zealand 15-17 Oct 1985 Wellington New Zealand Coal Research Association of New Zealand vol 2 Paper 342 15 pp (1985) Smith 1 W (1982) The combustion rates of coal chars In Nineteenth symposium (international) on combustion Haifa Israel 8-13 Aug 1982 Pittsburgh PA USA The Combustion Institute pp 1045-1065 (1982) Smith 1 W Wall T F Stanmore B R Harris D J Chen J Y Zhang D K (1991a) Coal combustion testing optimum laboratory procedure NERDDP-EG-91-993 Canberra ACT Australia National Energy Research Development and Demonstration Council 89 pp (Feb 1991) Smith P J Davies P R Jamaluddin A S (1991b) Coupling fireside deposition with computational combustion predictions In Effects of coal quality on power plants St
113
References
Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 2119-2140 (Jul 1991) Smith P J Smoot L D (1987) Detailed model for practical pulverized coal furnaces and gasifiers In Proceedings of the AR and TD (Advanced Research and Technology Development) direct utilization and instrumentation and diagnostics contractors review meeting Morgantown WV USA 13 Oct 1987 DOEIMETC-886084-vol 1 Morgantown WV USA Morgantown Energy Technology Center pp 62-71 (Oct 1987) Smith S R (1988) Tennessee Valley Authoritys experience with switching to improved quality coal In Reducing electricity generation costs by improving coal quality Indiana PA USA 5 Nov 1986 Palo Alto CA USA EPRI Technical Infonnation Services pp 31-323 (May 1988) Smoot L D (1984) Modeling of coal-combustion processes Progress in Energy and Combustion Science 10 (2) 229-272 (1984) Smoot L D Smith P J (1985) Coal combustion and gasification New York NY USA Plenum Press 459 pp (1985) Sorter J G Folsom B A Richter W (1986) Application of pilot-scale coal evaluation to utility boilers In Joint ASMElIEEE Power generation conference Portland OR USA 19-23 Oct 1986 New York NY USA American Society of Mechanical Engineers pp 1-8 (Oct 1986) St Baker T C (1983) Technology of coal utilisation for electric power generation In Coal technology and coal utilisation Brisbane Qld Australia 29-31 Aug 1983 Brisbane Qld Australia Australian Mineral Foundation Inc pp 1-42 (Aug 1983) Stach E Mackowsky M Th Teichmiiller M and others (eds) (1982) Stachs textbook ofcoal petrology Berlin Federal Republic of Germany Gebriider Borntraeger 535 pp (1982) Stallard G S Galluzzo N G Brown R E Pavlish J H (1988) Implementing EPRIs state-of-the-art coal quality impact model into fuel procurement practices In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Infonnation Services pp 677-693 (1988) Stallard G S Mehta A (1991) Using EPRI CQIM to evaluate acid rain strategies In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Infonnation Services pp 257-275 (Jul 1991) Stallard S Galluzzo N G Mehta A K (1989) Demonstration coal quality impact model In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Alto CA USA EPRI Technical Infonnation Services pp 91-919 (Oct 1989) Stanmore B R (1990) Ash hopper explosions in coal-fired boilers In Coal handling and utilisation conference Sydney NSW Australia 19-21 Jun 1990 Barton ACT Australia Institution of Engineers pp 274-276 (Jun 1990) Strein D L (1989) Effects of changing coal quality on precipitator perfonnance In Reducing power plant emissions by controlling coal quality Bethesda MD USA 27-28 Oct 1987 EPRI-GS-6281 Palo Alto CA USA EPRI Technical Infonnation Services pp 41-417 (Oct 1989)
Swaine D J (1990) Methods of analysis In Trace elements in coal London UK Butterworths amp Co Ltd pp 50-76 (1990) Swanson A R Taggart I J Wood D L (1982) The economic value of coal for coal fired power stations In Coal Phoenix of the 80s - Proceedings 64th CIC coal symposium Halifax NS Canada 31 May-3 Jun 1981 Ottawa ON Canada Canadian Society for Chemical Engineering pp 324-329 (1982) Swithenbank J Garbett E S Boysan F Ayers W H (1988) Advance of research on coal combustion system modelling In International symposium on coal combustion Science and technology of industrial and utility applications Beijing China 7-10 Sep 1987 New York NY USA Hemisphere Publishing pp 39-63 (1988) Tams D E (1990) Atmospheric fluidized beds - problems and solutions in practice In International conference on steam plant for the 1990s London UK 4-6 Apr 1990 Bury St Edmunds UK Mechanical Engineering Publications pp 117-124 (1990) Taraba B (1989) Effects of grain size and moisture on heat released during oxidation In 2 celostatni konference Samovolne vznecovani uhli v teorii a praxi (2 state conference on spontaneous combustion in theory and practice) Smilovice Czechoslovakia 15-17 May 1989 Smilovice Czechoslovakia Ustav Geologie a Geotechniky CSAV pp 1-9 (1989) Taubert U (1991) New developments in the waste disposal of coal-fired power plants VGB Kraftwerkstechnik - English Issue 2 (91) 86-91 (1991) Teichmillier M (1982) Origin of the petrographic constituents In Stachs textbook of coal petrology Stach E Mackowsky M Th Teichmller M and others (eds) Berlin Federal Republic of Germany Gebriider Borntraeger pp 219-294 (1982) Teyssler J (1988) Dependence of operating cost of a steam generator on inert content of the fuel Paper presented at Twentieth power plant technical colloquium Dresden Federal Republic of Germany 11-12 Oct 1988 Thielen W Odenthal H P Richter W (1987) Investigation of the influence of furnace geometry and coal properties on furnace perfonnance with the help of radiation transfer model In Fundamentals of the physical-chemistry of pulverised coal combustion Les Arcs France 28 Jul-1 Aug 1986 Dordrecht the Netherlands Martinus Nijhoff Publishers pp 424-436 (1987) Thompson A W Gibb W H (1988) Coal ash viscosity measurements on selected British coals as an aid to slagging propensity assessment In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 315-351 (1988) Tisch C Mancini R Sutton J Rini M (1990) Optimize p-c combustion to reduce carbon in fly ash Power 134 (12) 31-33 (Dec 1990) Tominaga H Sato M (1989) Development of a simulation for pulverised coal-fired boiler operation (part 4) evaluation of the FLUENT model Idemitsu Sekiyu Gijutsu 32 (1) 29-37 (1 Jan 1989) Truelove J (1985) Burners and flame stability In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle
114
References
NSW Australia University of Newcastle Institute of Coal Research pp 41-419 (May 1985) Tsai CoY Scaroni A W (1987) Reactivity ofbiturninous coal chars during the initial stage of pulverized-coal combustion Fuel 66 (10) 1400-1406 (Oct 1987) Ugursal V I AI Taweel A M (1990) A method for calculating the area requirement for power plant ash and FGD sludge disposal Journal of Coal Quality 9 (3) 87-90 (1990) Ugursal V I AI Taweel A M Mackay G D M (1990) Impact of coal quality on the cost of electrical power generation a technoeconomic model International Journal of Energy Research 14 (6) 683-699 (Aug 1990) Unsworth J F Barrett D J Roberts P T (1991) Coal quality and combustion performance an international perspective Amsterdam the Netherlands Elsevier Science Publishers 648 pp (1991) Vaninetti G E (1987) The importance of coal quality in marketing Journal of Coal Quality 6 (I) 5-7 (Jan 1987) Vernon J L (1989) Market impacts of sulphur control the consequences for coal lEACRlI8 London UK lEA Coal Research III pp (Oct 1989) Vernon J Soud H (1990) FGD installations on coal-fired plants lEACRl22 London UK lEA Coal Research 84 pp (Apr 1990) Vissar M Boysan F Weber R (1987) Computations of isothermal swirling vortices in the near burner zone Report on the MMF 1-1 investigation IFRF-F-336a9 Umiuden the Netherlands International Flame Research Foundation 179 pp (Iun 1987) Vitta P K Lowe S D Gallaspy D T Afonso R F Molino N M (1991) Application and validation of the coal quality impact model as part of the EPRI coal quality monitoring project In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 295-2117 (luI 1991) van Bush P Snyder T R Chang R L (1989) Determination of baghouse performance from coal and ash properties part II JAPCA Journal of the Air and Waste Management Association 39 (3) 361-372 (Mar 1989) Wagoner C L (1988) New opportunity to predict and verify effects of coal quality on the operation of heat exchangers through generic engineering In Reducing electricity generation costs by improving coal quality Indiana PA USA 5-6 Nov 1986 EPRI-CS-5713 Palo Alto CA USA EPRI Technical Information Services pp 61-626 (May 1988) Wain S E Livingston W R Sanyal A Williamson J (1992) Thermal and mechanical properties of boiler slags of relevance to sootblowing In Engineering Foundation conference on inorganic transformations and ash deposition during combustion Palm Coast FL USA 10-15 Mar 1991 New York NY USA American Society of Mechanical Engineers pp 459-470 (1992) Wall T F (1985a) Coal characterisation for combustion In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 11-119 (May 1985) Wall T F (1985b) Combustion of coal chars In An intensive course on the characterisation of steaming coals Newcastle
NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 51-529 (May 1985) Wall T F Wibberley L J McCol Stewart I (1985) The characterisation of steaming coals - limitations of the standard laboratory and pilot scale tests In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 111-1126 (May 1985) Walsh P M Beer J M Sarofun A F (1988) Estimation of aerodynamic effects on erosion of a tube by ash In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 219-234 (1988) Ward C P Pech J W Woodson H S (1988) Analytical model for coal combustion optimizing boiler operation through combustion control In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 Palo Alto CA USA EPRI Technical Information Services pp 621-629 (1988) Ward C R (1984) Chemical analysis and classification of coal In Coal geology and coal technology C R Ward (ed) Melbourne Vic Australia Blackwell Scientific Publications pp 40-73 (1984) Waters A G (1987) Implications of coal properties for thermal coal exports In Geology and coal mining conference Proceedings Sydney NSW Australia 13-15 Oct 1987 Sydney NSW Australia Geological Society of Australia Coal Geology Group pp AGWOI-AGW08 (1987) Wibberley L J (1985a) Effect of coal composition on deposit formation in PP fired boilers In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 91-918 (May 1985) Wibberley L J (1985b) Characterisation of coals for flyash and sulphur oxide emissions In An intensive course on the characterisation of steaming coals Newcastle NSW Australia 20-22 May 1985 Newcastle NSW Australia University of Newcastle Institute of Coal Research pp 71-715 (May 1985) Wibberley L J Wall T F (1986) An investigation of factors affecting the physical characteristics of fly ash formed in a laboratory scale combustor Combustion Science and Technology 48 177-190 (1986) Wigley F Williamson J Jones A R (1989) Slagging indices for UK coal and their relationship with mineral matter Fuel Processing Technology 24 (13) 383-389 (1989) Wollmann H-J (1990) Danger from residual coal content in hot fly ash VGB Krafiwerkstechnik - English Issue 70 (6) 404-408 (Iun 1990) Wright I G Williams D N Mehta A K (1988) Techniques to reduce fireside corrosion and fly ash erosion In Effects of coal quality on power plants Atlanta GA USA 13-15 Oct 1987 EPRI-CS-5936-SR Palo Alto CA USA EPRI Technical Information Services pp 255-274 (1988) Wu E J Chen K Y (1987) Chemical form and leachability of inorganic trace elements in coal ash EPRI-EA-5115 Palo Alto CA USA EPRI Technical Information Services 202 pp (Iun 1987) Wu K T Payne R Li B Sheldon M (1990) Application of
115
References
engineering computer models and modeling techniques for evaluating boiler thermal performance and emissions control processes In Combustion modeling and burner replacement strategies ASMFIEEE joint power generation conference Boston MA USA 21-25 Oct 1990 New York NY USA American Society of Mechanical Engineers pp 1-8 (1990) Yancey H F Geer M R Price J D (1951) An investigation of the abrasiveness of coal and its associated impurities Mining Engineering 3 262-268 (1951) Yarkin E V Novikova I V (1988) Price as an incentive for improving quality of power fuel Eleckricheskie Stantsii (3) 8-11 (Mar 1988) Yavorskii I A Alaev G P Pugach L I Talankin L P (1968) Influence of the petrographic composition of coals on the efficiency of a pf fired boiler furnace Thermal Engineering (English translation of Teploenergetika) 15 (9) 108-113 (1968) Young R P DuBard J L Hovis L S (1989) Resistivity of fly ashlsorbent mixtures In Seventh symposium on the transfer and utilization ofparticulate control technology Nashville lN USA 22-25 Mar 1988 EPRI-GS-6208 Palo Alto CA USA EPRI Technical Information Services pp 11-115 (1989)
Zehner P (1989) Erfahrungen mit NOx-mindemden Massnahmen an Feuerungen grosser Dampferzeuger (Experience with combustion measures for NOx reduction at large steam generators) In VGB Konferenz Kraftwerk und Umwelt 1989 (VGB conference on power plants and the environment 1989) Essen Federal Republic of Germany 26-27 Apr 1989 Essen Federal Republic of Germany VGB Kraftwerkstechnik GmbH pp 121-136 (1989) Zelkowski J Riepe W (1987) Generation of ash by hard coal power stations and problems of its utilization in the Federal Republic of Germany In Ash - a valuable resource Pretoria South Africa 1987 Pretoria South Africa Council for Scientific and Industrial Research vol 1 pp Bl-5 (1987) Ziesmer B C Barna L J Bull D L (1991) A utility perspective on western coals - operating experience and methods for screening potential fuel supplies In Effects of coal quality on power plants St Louis MI USA 19-21 Sep 1990 EPRI-GS-7361 Palo Alto CA USA EPRI Technical Information Services pp 437-456 (Jul 1991) Zygarlicke C J Steadman E N Benoon S A (1990) Studies of transformations of inorganic constituents in a Texas lignite during combustion Progress in Energy and Combustion Science 16 (4) 195-204 (1990)
116
Appendix List of standards referred to in the report
American Society for Testing and Materials 1916 Race Street Philadelphia PA 19103 USA
D197-1987 Sampling and fineness test of pulverized coal
D291-1986 Cubic foot weight of crushed bituminous coal
D3172-1989
D3173-1987
D3174-1989
Proximate analysis of coal and coke
Moisture in the analysis sample of coal and coke
Ash in the analysis sample of coal and coke from coal
0409-1992 Grindability of coal by the Hardgrove-machine method
D3175-1989 Volatile matter in the analysis sample of coal and coke
D440-1986 Drop shatter test for coal D3176-1989 Ultimate analysis of coal and coke
D441-1986
D547-1941
D720-1991
Tumbler test for coal
Index of dustiness of coal and coke
Free-swelling index of coal
D3177-1989
D3178-1989
Total sulfur in the analysis sample of coal and coke
Carbon and hydrogen in the analysis sample of coal and coke
D1412-1989
D1756-1989
Equilibrium moisture of coal at 96 to 97 per cent relative humidity and 30D C
Carbon dioxide in coal
D3179-1989
D3286-1991
Nitrogen in the analysis sample of coal and coke
Gross CalOrifIC value of coal and coke by the isoperibol bomb calorimeter
D1857-1987 Fusibility of coal and coke ash D3302-1991 Total moisture in coal
D2015-1991 Gross calorific value of coal and coke by the adiabatic bomb calorimeter
D3682-1991 Major and minor elements in coal and coke ash by atomic absorption
D2361-1991
D2492-1990
D2795-1986
Chlorine in coal
Forms of sulfur in coal
Analysis of coal and coke ash
D3683-1978
D4326-1992
Trace elements in coal and coke ash by atomic absorption
Major and minor elements in coal and coke ash by X-ray fluorescence
D2798-1991 Microscopical determination of the reflectance of intrinite in a polished specimen of coal
D4749-1987 Performing the sieve analysis of coal and designating coal size
D2799-1992 Microscopical determination of volume per cent of physical components of coal
D5142-1990 Proximate analysis of the analysis sample of coal and coke by instrumental procedures
117
List of standards referred to in the report
Standards Association of Australia BS 1016 Part 6-1977 Ultimate analysis of coal 80-86 Arthur Street North Sydney NSW 2060 Australia
BS 1016 Part 8-1980 Chlorine in coal and coke
BS 1016 Part 11-1982 Forms of sulphur in coal
BS 1016 Part 12-1984 Caking and swelling properties of coal
BS 1016 Part 14-1979 Analysis of coal ash and coke ash
BS 1016 Part 15-1979 Fusibility of coal ash and coke ash
BS 1016 Part 17-1987 Size analysis of coal
BS 1016 Part 11-1990 Determination of the index of abrasion of coal
BS 1016 Part 20-1987 Determination of the Hardgrove grindability index of hard coal
BS 1016 Part 111-1990 Determination of abrasion index of coal
BS 6127 Part 3-1981 Petrographic analysis of bituminous coal and anthracite Part 3 Method of determining maceral group composition of bituminous coal and anthracite
BS 6127 Part 5-1981 Petrographic analysis of bituminous coal and anthracite Part 5 Method of determining microscopically the reflectance of vitrinite
Deutsches Institut rDr Normung eV Postfach 1107 1000 Berlin 30 Germany
DIN 22020 Part 3-1981 Mikroskopische Untersuchungen an Steinkohle Koks und Briketts Maceralanalyse an Komerschliffen (Microscopic method of analysing coal coke and briquettes maceral group analysis)
DIN 22020 Part 5-1981 Mikroskopische Untersuchungen an Steinkohle Koks und Briketts Reflexionsmessungen an Vitriniten (Microscopic method of analysing coal coke and briquettes measurement of the reflectance of vitrinite)
DIN 51 700-1967 Allgemeines und Ubersicht tiber Untersuchungsverfahren (General and overview of methods of analysis)
DIN 51 705-1979 Bestimmung der Schtittdichte (Determination of bulk density)
AS 1038 Parts 1-11
AS 1038 Part 1-1980
AS 1038 Part 3-1989
AS 1038 Part 5-1989
AS 1038 Part 6-1986
AS 1038 Part 8-1980
AS 1038 Part 11-1982
AS 1038 Part 121-1984
AS 1038 Part 141-1981
AS 1038 Part 15-1972
AS 1038 Part 17shy
AS 1038 Part 20-1981
AS 1038 Part 22-1983
AS 2486-1981
AS 2515-1981
AS 3381-1991
AS 3899-1991
Methods for the analysis and testing of coal and coke (metric units)
Total moisture in hard coal
Proximate analysis of hard coal
Gross specific energy of coal and coke
Ultimate analysis of coal
Chlorine in coal and coke
Forms of sulphur in coal
Determination of crucible swelling number of coal
Analysis of coal ash coke ash and mineral matter (borate fusion-flame atomic absorption method)
Fusibility of coal ash and coke ash
Size analysis of hard coal
Determination of Hardgrove Grindability Index of hard coal
Determination of mineral matter and water of hydration of minerals in coal
Microscopical determination of the reflectance of coal macerals
Determination of the maceral group composition of bituminous coal and anthracite (hard coal)
Size analysis of hard coal
Higher rank coals and coke - bulk density
British Standards Institution Sales Office Linford Wood Milton Keynes MK14 6LE UK
BS 1016 Parts 1-20
BS 1016 Part 1-1989
BS 1016 Part 3-1973
BS 1016 Part 5-1977
Methods for the analysis and testing of coal and coke
Total moisture of coal
Proximate of analysis coal
Gross calorific value of coal and coke
118
Appendix
DIN 51 717-1967
DIN 51 718-1978
DIN 51 719-1978
DIN 51 720-1978
DIN 51 721-1950
DIN 51 722shy
DIN 51 724-1975
DIN 51 726-1980
DIN 51 727-1976
DIN 51 729shy
DIN 51 730-1976
DIN 51 741-1974
DIN 51900shy
Bestimmung der Trommelfestigkeit und des Abriebs von Steinkohlenkoks (Detennination of abrasion indexdrum strength and abrasion of hard coal coke)
Bestimmung des Wassergehaltes (Detennination of water content)
Bestimmung des Aschegehaltes (Detennination of ash content)
Bestimmung des Gehaltes an Fliichtigen Bestandteilen (Detennination of volatile matter content)
Bestimmung des Gehaltes an Kohlenstoff und Wasserstoff (Detennination of content of carbon and hydrogen)
Bestimmung des Stickstoff-Gehaltes (gilt nur fur Kohlen) (Detennination of nitrogen (for coal only)
Bestimmung des Schwefelgehaltes Gesamtschwefel (Part 1 Detennination of sulphur content and total sulphur)
Bestimmung des Gehaltes an Carbonat-Kohlenstoff-dioxid (Detennination of content of carbonate carbon dioxide)
Bestimmung des Chlorgehaltes (Detennination of chlorine content)
Bestimmung der chemischen Zusammensetzung von Brennstoffasche (Detennination of chemical composition of fuel ash)
Bestimmung des Asche-Schmelzverhaltens (Detennination of ash melting behaviour)
Bestimmung der BHihzahl von Steinkohle (Determination of swelling capacityindex)
Priifung fester und fliissiger Brennstoffe Bestimmung des Brennwertes mit dem Bomben-Kalorimeter und Berechnung des Heizwertes (Testing of solid and liquid fuels detenninationlanalysis of the
heating value by bomb-calorimeter and calculation of the heating value)
Teil 2 - 1977 Verfahren mit isothermem Wassermantel (Part 2 Methods with isothermal water jacket)
Teil 3 - 1977 Verfahren mit adiabatischem Mantel (Part 3 Methods with adiabatic jacket)
International Organization for Standardization Casa Postale 56 CH 1211 Geneva 20 Switzerland
ISO 157-1975
ISO 331-1983
ISO 332-1981
ISO 334-1975
ISO 352- 1981
ISO 501-1981
ISO 540-1981
ISO 562-1981
ISO 589-1981
ISO 602-1983
ISO 625-1975
ISO 925
ISO 1018-1975
ISO 1171-1981
Hard coal - Detennination of forms of sulphur
Coal - Detennination of moisture in the analysis sample - Direct gravimetric method
Coal - Detennination of nitrogen shyMacro Kjeldahl method
Coal and coke - Detennination of total sulphur - Eschka method
Solid mineral fuels shyDetennination of chlorine - High temperature combustion method
Coal - Detennination of the crucible swelling number
Solid mineral fuels shyDetennination of fusibility of ash shyHigh temperature tube method
Hard coal and coke shyDetennination of volatile matter content
Hard coal - Detennination of total moisture
Coal - Detennination of mineral matter
Coal and coke - Detennination of carbon and hydrogen - Liebig method
Coal - Determination of carbon dioxide
Hard coal - Detennination of moisture-holding capacity
Solid mineral fuels shyDetennination of ash
119
List of standards referred to in the report
ISO 1921-1976
ISO 1953-1972
ISO 1994-1976
ISO 5074-1980
Solid mineral fuels shyDetermination of gross calorific value by the calorimeter bomb method and calculation of net calorific value
Hard coals - Size analysis
Hard coal - Determination of oxygen content
Hard coal - Determination of Hardgrove grindability index
ISO 7404 Part 3-1984
ISO 7404 Part 5-1984
Methods for the petrographic analysis of bituminous coal and anthracite Part 3 Method of determining maceral group composition
Methods for the petrographic analysis of bituminous coal and anthracite Part 5 Method of determining microscopically the reflectance of vitrinite
120
Related publications
Further lEA Coal Research publications on coal utilisation are listed below
Advanced coal cleaning technology G R Couch IEACRl44 ISBN 92-9029-197-4 95 pp December 1991
Power station refurbishment opportunities for coal D H Scott IEACRl42 ISBN 92-9029-195-8 58 pp October 1991
On-line analysis of coal A T Kirchner IEACR140 ISBN 92-9029-193-1 79 pp September 1991
Coal gasification for IGCC power generation Toshiishi Takematsu Chris Maude IEACR137 ISBN 92-9029-190-7 80 pp March 1991
Lignite upgrading G R Couch IEACRl23 ISBN 92-9029-176-172 pp May 1990
Power generation from lignite G R Couch IEACRl19 ISBN 92-9029-170-2 67 pp December 1989
Lignite resources and characteristics G R Couch IEACRl13 ISBN 92-9029-163-X 100 pp December 1988
Coal-fired MHD G F Morrison IEACRl06 ISBN 92-9029-151-6 32 pp April 1988
Biotechnology and coal G R Couch ICTISfTR38 ISBN 92-9029-147-8 56 pp March 1987
Understanding pulverised coal combustion G F Morrison ICTISfTR34 ISBN 92-9029-138-9 46 pp December 1986
Atmospheric f1uidised bed boilers for industry I F Thomas ICTISfTR35 ISBN 92-9029-136-2 69 pp November 1986
All reports are priced at pound60pound180 (membernon-member countries)
Other lEA Coal Research pUblications Details of lEA Coal Research publications are available from
Reviews assessments and analyses of supply transport and markets lEA Coal Research coal science Gemini House coal utilisation 10-18 Putney Hill coal and the environment London SW15 6AA
United Kingdom Coal abstracts Coal calendar Tel (0)81-7802111 Coal research projects Fax (0)81-7801746
