technical guidelines - generator efficiency standards

TECHNICAL GUIDELINES Generator Efficiency Standards

Australian Greenhouse Office Department of the Environment and Heritage

December 2006

2

Technical Guidelines

Generator Efficiency Standards

Australian Greenhouse Office Department of the Environment and Heritage

December 2006

Technical Guidelines - Generator Efficiency Standards

Australian Greenhouse Office, Department of the Environment and Heritage, December 2006 1 1

Published by the Australian Greenhouse Office in the Department of the Environment and Heritage. © Commonwealth of Australia 2006 This work is copyright. Apart from any use as permitted under the Copyright Act 1968, no part may be reproduced by any process without prior written permission from the Commonwealth, available from the Department of the Environment and Heritage. Requests and inquiries concerning reproduction and rights should be addressed to: Assistant Secretary Industry Partnerships Branch Department of the Environment and Heritage GPO Box 787 Canberra ACT 2601 ISBN: 1 9212 97 247 This document is available electronically at: www.greenhouse.gov.au/ges/ The views and opinions expressed in this publication are those of the authors and do not necessarily reflect those of the Australian Government or the Minister for the Environment and Heritage. While reasonable efforts have been made to ensure that the contents of this publication are factually correct, the Commonwealth does not accept responsibility for the accuracy or completeness of the contents, and shall not be liable for any loss or damage that may be occasioned directly or indirectly through the use of, or reliance on, the contents of this publication.



Contents

1.0 SCOPE..........................................................................................................................5 2.0 REFERENCE DOCUMENTS ........................................................................................6 3.0 DEFINITIONS..............................................................................................................10 4.0 APPLICATION OF GREENHOUSE EFFICIENCY STANDARDS..............................13

4.1 PRINCIPLES ...............................................................................................................13 4.2 APPLICABLE GASES AND ASSOCIATED GREENHOUSE WARMING POTENTIAL ................15 4.3 APPLICATION TO EXISTING, REFURBISHED AND NEW PLANT ........................................15

4.3.1 General .............................................................................................................15 4.3.2 Existing/Refurbished Plant................................................................................18 4.3.3 New Plant .........................................................................................................23

4.4 OPTIONS FOR REDUCING GREENHOUSE EMISSIONS ...................................................25 5.0 EMISSION FACTORS FOR GAS-FIRED PLANT ......................................................26

5.1 MEASUREMENT OF GAS VOLUME AND QUALITY ..........................................................26 5.1.1 General .............................................................................................................26 5.1.2 Volumetric Measurement..................................................................................26 5.1.3 Energy Measurement .......................................................................................27 5.1.4 Gas Metering Equipment ..................................................................................27 5.1.5 Standard Conditions .........................................................................................28 5.1.6 Inspection and Audit .........................................................................................29

5.2 EMISSION FACTORS...................................................................................................29 5.2.1 Carbon Dioxide (CO2) .......................................................................................29 5.2.2 Methane (CH4) and Nitrous Oxide (N2O) ..........................................................29

6.0 EMISSION FACTORS FOR OIL-FIRED PLANT ........................................................31 6.1 FUEL OIL QUANTITY AND QUALITY..............................................................................31

6.1.1 Oil Metering ......................................................................................................31 6.1.2 Oil Sampling .....................................................................................................31 6.1.3 Fuel Oil Analysis ...............................................................................................31

6.2 EMISSION FACTORS...................................................................................................32 6.2.1 Carbon Dioxide (CO2) .......................................................................................32 6.2.1 Methane (CH4) and Nitrous Oxide (N2O) ..........................................................32

7.0 EMISSION FACTORS FOR COAL-FIRED PLANT....................................................33 7.1 COAL QUANTITY AND QUALITY ...................................................................................33

7.1.1 Coal weighing ...................................................................................................33 7.1.2 Stockpile quantities...........................................................................................34 7.1.3 Coal sampling and sample preparation ............................................................35 7.1.4 Coal analysis ....................................................................................................37 7.1.5 Carbon in ash ...................................................................................................37

7.2 EMISSION FACTORS...................................................................................................38 7.2.1 Carbon Dioxide (CO2) .......................................................................................38 7.2.2 Methane (CH4) ..................................................................................................39 7.2.3 Nitrous Oxide (N2O) ..........................................................................................39

8.0 MEASUREMENT PROTOCOL FOR ELECTRICITY OUTPUT ..................................40 9.0 MEASUREMENT PROTOCOL FOR COGENERATION PLANTS.............................41

9.1 GENERAL ..................................................................................................................41 9.2 DETERMINATION OF GREENHOUSE INTENSITY.............................................................42 9.3 ENERGY AS PROCESS STEAM ....................................................................................42



9.4 APPLICATION TO COGENERATION PLANTS ..................................................................43 9.5 ENERGY METERING ...................................................................................................43

9.5.1 Electricity ..........................................................................................................43 9.5.2 Steam, condensate return, and make-up water................................................43 9.5.3 Other energy products (e.g., compressed air) ..................................................44

10.0 CALCULATION OF GREENHOUSE INTENSITY...................................................45 10.1 GREENHOUSE INTENSITY MEASUREMENT INTERVAL................................................45 10.2 ANNUAL AVERAGE GREENHOUSE INTENSITY...........................................................45

11.0 GREENHOUSE EFFICIENCY REPORTING REQUIREMENTS.............................46 12.0 REVIEW OF GREENHOUSE EFFICIENCY STANDARDS ....................................47 APPENDIX A THERMAL EFFICIENCY THEORY AND PRINCIPLES ...........................48

A.1 GENERATED AND SENT-OUT THERMAL EFFICIENCY ....................................................48 A.2 THERMAL PLANTS......................................................................................................49

A.2.1 Boiler Efficiency ................................................................................................49 A.2.2 Steam Turbine Efficiency..................................................................................51

A.3 GAS TURBINE PLANTS ...............................................................................................52 A.4 COMBINED CYCLE PLANTS.........................................................................................53 A.5 COGENERATION/COMBINED HEAT AND POWER PLANTS ..............................................53

A.5.1 General .............................................................................................................53 A.5.2 Cogeneration Thermal Efficiency......................................................................54 A.5.3 Greenhouse Intensity........................................................................................54

A.6 CALORIFIC VALUE OF FOSSIL FUELS...........................................................................54 APPENDIX B POWER PLANT DEGRADATION ............................................................56

B.1 INTRODUCTION ..........................................................................................................56 B.2 BACKGROUND ...........................................................................................................56 B.3 TYPES OF DEGRADATION ...........................................................................................56

B.3.1 Recoverable losses ..........................................................................................56 B.3.2 Non-recoverable degradation ...........................................................................56

B.4 GAS TURBINES ..........................................................................................................57 B.4.1 Causes of degradation - overview ....................................................................57 B.4.2 Rates of degradation ........................................................................................57 B.4.3 Compressor degradation ..................................................................................58 B.4.4 Turbine degradation...............................................................................................61

B.5 STEAM TURBINES AND ANCILLARIES ...............................................................................62 B.5.1 Steam turbine ........................................................................................................62 B.5.2 Condensers ...........................................................................................................66

B.6 BOILERS ........................................................................................................................67 B.6.1 Boiler (PF fired, for Steam power plant) ................................................................67 B.6.2 Heat Recovery Steam Generators.........................................................................68

B.7 CYCLING OPERATION .....................................................................................................68 B.7.1 Gas turbines ..........................................................................................................68 B.7.2 Steam turbines.......................................................................................................69 B.7.3 Boilers....................................................................................................................69

B.8 LITERATURE REFERENCES .............................................................................................69 APPENDIX C GAS METER CATEGORIES AND MEASUREMENT RECOMMENDATIONS..........................................................................................................70 APPENDIX D INDICATIVE OPTIONS FOR REDUCING GREENHOUSE GAS EMISSIONS FROM EXISTING PLANTS...............................................................................72

D.1 RANGE OF OPTIONS ......................................................................................................72



APPENDIX E COSTING OF OPTIONS ...........................................................................77 APPENDIX F NEW PLANT STANDARDS......................................................................80

F.1 TYPES OF POWER GENERATION CYCLES.........................................................................80 F.2 PERFORMANCE OF ELECTRIC POWER GENERATION SYSTEMS ....................................80

F.2.1 Background.......................................................................................................80 F.2.2 Reference conditions ........................................................................................81 F.2.3 Simulation results .............................................................................................83

F.3 REFERENCES ............................................................................................................91 APPENDIX G GES GREENHOUSE INTENSITY CALCULATOR...................................92



1.0 SCOPE This guide covers the application of Generator Efficiency Standards, measured in terms of greenhouse intensity, to Australian fossil fuel based electricity and steam producers (when in conjunction with electricity production), existing and proposed, and sets out recommended practices for:

a) determining best practice greenhouse efficiency standards for existing/refurbished

power/cogeneration plant b) determining best practice greenhouse efficiency standards for new

power/cogeneration plant c) determining the actual greenhouse intensity for power plant based on total fuel

burned over a twelve month period and the corresponding energy output as electricity, and steam if applicable

d) comparison of actual greenhouse intensity with best practice efficiency standards e) reporting greenhouse intensity performance.

This guideline also provides background theory and principles on power plant and cogeneration plant thermal efficiency, and indicative options for reducing greenhouse intensity. Greenhouse efficiency is measured on the basis of the six Inter-governmental Panel on Climate Change (IPCC) gases. However, this guideline is applicable only to greenhouse gases from fuel burning, i.e., CO2, CH4 and N2O1. Greenhouse intensity is measured as the ratio of the quantity of greenhouse gases expressed as carbon dioxide equivalent to the quantity of electrical and if applicable thermal energy dispatched. The other greenhouse gases are not normally applicable but should be included where they arise.

1 Carbon dioxide, methane and nitrous oxide,respectively.



2.0 REFERENCE DOCUMENTS American Gas Association/American Petroleum Institute

AGA Report No. 3 Orifice Metering of Natural Gas

Part 1: General Equations & Uncertainty Guidelines (1990)

Part 2: Specification and Installation Requirements (2000)

Part 3: Natural Gas Applications (1992)

Part 4: Background, Development Implementation Procedure (1992)

AGA Report No. 7 Measurement of Gas by Turbine Meters (1996)

AGA Report No. 8 Compressibility Factor of Natural Gas and Related Hydrocarbon Gases (1994)

ANSI/API 14.3.1 - 2003 General Equations and Uncertainty Guidelines - Concentric, Square edged Orifice Meters (reaffirmed 2001)

ANSI/API 14.3.2 - 2000 Specification and Installation Requirements - Concentric, Square-edged Orifice Meters

ANSI/API 14.3.3 - 2003 Natural Gas Applications (reaffirmed 2003)

API 14.3 Part 4 1991 Background, Development, Implementation Procedures and Subroutine Documentation (reaffirmed 1999)

ASME/ANSI Codes

ANSI B109.3 - '00 for Rotary-Type Gas Displacement Meters

ASME PTC 4 - 1998 Fired Steam Generators

ASME PTC 4.4 - 1981 Gas Turbine Heat Recovery Steam Generators (reaffirmed 2003)

ASME PTC 4.3 - 1968 Air Heaters (reaffirmed 1991)

ASME PTC 6 - 1996 Performance Test Code for Steam Turbines

ASME PTC 6S - 1988 Procedures for Routine Performance Test of Steam Turbines (reaffirmed 2003)

ASME PTC 22 - 1997 Performance Test Code on Gas Turbines (reaffirmed 2003)

ASME PTC 46 - 1996 Overall Plant Performance

ASTM Standards

ASTM D1298-99 Ed 2 Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method

ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography

ASTM D4057-95(2000) Standard Practice for Manual Sampling of Petroleum and Petroleum Products

ASTM D4916-04 Standard Practice for Mechanical Auger Sampling



ASTM D6347/D6347M-99 Standard Test Method for Determination of Bulk Density of Coal Using Nuclear Backscatter Depth Density Methods

Australian Codes

AS/NZS 1376:1996 Conversion factors

NMI R76-1 Ed 3 Rev 3 2002 Non-automatic Weighing Instruments Part 1 - Metrological and Technical Requirements - Tests

NMI R50-1 Ed 3 Rev 3 2004 Continuous Totalising Automatic Weighing Instruments (Belt weighers) Part 1 - Metrological and Technological Requirements

NMI R106 Ed 3 Rev 1 2004 Automatic Rail Weighbridges National Electricity Code Version 1, Amendment 9 - 2004

Australian Standards

AS ISO 1000-1998 The international system of units (SI) and its application

AS 1038.1-2001 Coal and coke - Analysis and testing - Higher rank coal - Total moisture (supersedes 1038.1 - 1992)

AS 1038.3-2000 Coal and coke - Analysis and testing - Proximate analysis of higher rank coal

AS 1038.5-1998 Coal and coke - Analysis and testing - Gross calorific value

AS 1038.6.1-1997 Coal and coke - Analysis and testing - Higher rank coal and coke - Ultimate analysis - Carbon and hydrogen

AS 1038.6.2-1997 Coal and coke - Analysis and testing - Higher rank coal and coke - Ultimate analysis - Nitrogen

AS 1038.6.3 Coal and coke - Analysis and testing - Higher rank coal and coke - Ultimate analysis - Total sulfur (Part 1 1997, Part 2 2003, Part 3 1997)

AS 1038.6.4-2005 Coal and coke - Analysis and testing - Higher rank coal and coke - Ultimate analysis - Carbon, hydrogen and nitrogen - Instrumental method

AS 1038.16-1996 Coal and coke - Analysis and testing - Assessment and reporting of results

AS/NZS 1376-1996 Conversion factors

AS 2096-1987 Classification and coding systems for Australian coals

AS 2434.1-1999 Methods for the analysis and testing of lower rank coal and its chars - Determination of the total moisture content of lower rank coal

AS 2434.6.1-2002 Methods for the analysis and testing of lower rank coal and its chars - Lower rank coal - Ultimate analysis - Classical methods (supersedes AS2434.6.1-1986)

AS 2434.8-2002 Methods for the analysis and testing of lower rank coal and its chars - Lower rank coal - Determination of ash (supersedes AS2434.8 - 1993)

AS 2649-1983 Petroleum liquids and gases - Measurement - Standard reference conditions



AS 2651-1983 Liquid hydrocarbons - Volumetric measurement by turbine meter systems (and Amendment 1 - 1984)

AS 2652-1983 Liquid hydrocarbons - Volumetric measurement by displacement meter systems other than dispensing pumps

AS 3583.2-1991 Methods of test for supplementary cementitious materials for use with Portland cement - Determination of moisture content

AS 3583.3-1991 Methods of test for supplementary cementitious materials for use with Portland cement - Determination of loss on ignition

AS 4250.1-1995 Liquid hydrocarbons - Dynamic measurement - Proving systems for volumetric meters - General principles

AS 4250.2-1995 Liquid hydrocarbons - Dynamic measurement - Proving systems for volumetric meters - Pipe provers

AS 4250.3-1995 Liquid hydrocarbons - Dynamic measurement - Proving systems for volumetric meters - Pulse interpolation techniques

AS 4250.4-1995 Liquid hydrocarbons - Dynamic measurement - Proving systems for volumetric meters - Temperature corrections in volumetric calibration by water transfer method

AS 4250.5-1995 Liquid hydrocarbons - Dynamic measurement - Proving systems for volumetric meters - Dynamic measurement

AS 4264.1-1995 Coal and coke - Sampling - Higher rank coal - Sampling procedures

AS 4264.3-1996 Coal and coke - Sampling - Lower rank coal - Sampling procedures

AS 4264.4-1996 Coal and coke - Sampling - Determination of precision and bias

AS 4264.5-1999 Coal and coke - Sampling - Guide to the inspection of mechanical sampling systems

AS 4323.1-1995 Stationary source emissions - Selection of sampling positions (and Amendment 1 1995)

AS 4323.2-1995 Stationary source emissions - Determination of total particulate matter - Isokinetic manual sampling - Gravimetric method

British Standards

BS 845-1:1987 Methods for assessing thermal performance of boilers for steam, hot water and high temperature heat transfer fluids. Concise procedure

BS 845-2:1987 Methods for assessing thermal performance of boilers for steam, hot water and high temperature heat transfer fluids. Comprehensive procedure

BS 2869:1998 Specification for fuel oils for agricultural, domestic and industrial engines and boilers

BS 3135:1989 Specification for gas turbine acceptance test (identical with ISO 2314 - 1989)

BS EN 12952-15:2003 Water-tube boilers and auxiliary installations. Acceptance tests

BS EN 60953-1:1996 Rules for steam turbine thermal acceptance tests. High accuracy for large condensing steam turbines



BS EN 60953-2:1996 Rules for steam turbine thermal acceptance tests. Wide range of accuracy for various types and sizes of turbines

BS EN 60953-3:2002 Rules for steam turbine thermal acceptance tests. Thermal performance verification tests of retrofitted steam turbines

ISO Standards

ISO 2314:1989 Gas turbines; acceptance tests (and amendment 1 1997, and technical corrigendum 1 1997)

ISO 2314:1989 Gas turbines - Acceptance tests; Amendment 1: Acceptance test for combined-cycle power plants

ISO 6976:1995 Natural gas - Calculation of calorific values, density, relative density and Wobbe index from composition (and technical corrigendums* 1,2 1997 & 3 1999)

New Zealand Standards

NZS 5259:2004 Gas measurement

US EPA Methods

Method 1 - 1996 Sample and Velocity Traverses for Stationary Sources

Method 5 - 1996 Determination of Particulate Matter Emissions from Stationary Sources

Method 3A - 1989 Carbon Dioxide and Oxygen Concentrations - IAP

Method 4 - 1995 Moisture Content in Stack Gases

Method 10B - 1994 Carbon Monoxide from Stationary Sources

General References

Australian Greenhouse Office, Efficiency Standards for Power Generation, Integrating report (to identify best practice emission standards for Australian or fossil fuel generation and assess the financial and economic implications of the measure) SKM Final Report, Jan 2000.

Australian Greenhouse Office, Australian Methodology for the Estimation of Greenhouse Gas Emissions and Sinks 2004 Energy (Stationary Sources), National Greenhouse Gas Inventory Committee, 2006

Babcock & Wilcox, Steam - Its Generation and Use, 40th edition, 1992

DPIE/Australian Cogeneration Association, Profiting from Cogeneration, 1997

Intergovernmental Panel on Climate Change (IPCC), Climate Change 2001: The Scientific Basis. Contribution of Working Group I to the Third Assessment Report of the Intergovernmental Panel on Climate Change (IPCC), 2001

Smith I M, Greenhouse Gas Emission Factors for Coal - The Complete Fuel Cycle, IEA Coal Research (London) CR/98 Nov 1998

Walsh P P and Fletcher P, Gas Turbine Performance, Blackwell Science, 1998



3.0 DEFINITIONS Ash (Aar) Ash in fuel, expressed as mass % as-received, as-sampled or

as-fired.

Auxiliary power/energy All electricity consumed internally within the boundary of a power station or cogeneration plant to run the plant.

Black coal Synonymous with higher rank coal. (ref AS 2096)

Brown coal Synonymous with lower rank coal. (ref AS 2096)

Calorific value, gross (Qgr,p,ar)

Gross calorific value - The number of heat units liberated per unit quantity of fuel burned in oxygen under standard conditions (25 °C; 101.325 kPa); the products of combustion are assumed to consist of gaseous oxygen, carbon dioxide, nitrogen and oxides of nitrogen, sulfur dioxide, and liquid water.

Calorific value, net (Qnet)

The number of heat units liberated per unit quantity of fuel burned in oxygen under standard conditions (25°C; 101.325 kPa); the products of combustion are assumed to consist of gaseous oxygen, carbon dioxide, nitrogen and oxides of nitrogen, sulfur dioxide and water vapour.

Capacity The rated continuous load-carrying ability, expressed in megawatts, of generation equipment; sometimes referred to as maximum continuous rating (MCR) or continuous maximum rating (CMR).

Capacity factor Total energy produced for a specified period relative to the total possible amount of energy that could have been produced for the same period.

hoursperiodMWcapacityinstalledTotalMWhgeneratedenergyperiodTotal×

×)(

%100)(

Carbon (C) Carbon in fuel, expressed as mass % as-received, as-sampled

or as-fired (Car); and for coal, mass % dry ash-free (Cdaf).

Carbon-in-ash (Ca) Unburned carbon in ash (furnace ash, economiser ash, or fly ash), expressed as mass % as-sampled.

Cogeneration/ combined heat and power

Simultaneous production of both useful thermal energy (heat, typically as steam) and electrical energy.

Fossil fuels Energy-rich substances created from the partial decomposition of prehistoric organisms over long periods of time. Examples are coal, coal seam methane, natural gas, and oil.



Global warming potential (GWP)

The instantaneous radiative forcing that results from the addition of 1 kg of a gas to the atmosphere, relative to that of 1 kg of carbon dioxide.

Greenhouse efficiency General term indicating the performance of a power plant with respect to greenhouse emissions resulting from the combustion of fossil fuels. Also see greenhouse intensity.

Greenhouse intensity (GI)

Measure of Greenhouse efficiency as the emission rate of greenhouse gases from fuel burning expressed in kg CO2 (equiv.)/MWh sent-out. For cogeneration, this is discounted for steam/heat production.

Greenhouse gases (GHG)

Those gaseous constituents of the atmosphere, both natural and anthropogenic, that absorb and re-emit infra-red radiation.

Heat Rate Heat Rate is a measure of generating station heat efficiency. This is the total fuel heat input expressed in MJ divided by the energy produced by the power plant expressed in MWh. It is related to thermal efficiency by the following expression

100(%)

600,3×=

EfficiencyThermalHR given in units of MJ/MWh

See also Equation A.5

Higher heating value (HHV)

This is synonymous with gross calorific value.

Higher rank coal Coal that is geothermally mature, as defined quantitatively in AS 2096 (gross calorific value ≥ 27 MJ/kg dry, ash-free).

Lower heating value (LHV)

This is synonymous with net calorific value.

Lower rank coal Coal that is geothermally immature, as defined quantitatively in AS 2096 (gross calorific value <27 MJ/kg dry, ash-free).

Non-recoverable degradation (NRD)

The component of degradation in the sent-out thermal efficiency of a power plant due to ageing that is not recoverable through normal maintenance practices. Note that this degradation is normally measured as an increase in heat rate.



Output factor (or load factor)

Total energy produced for a specified period relative to the total possible amount of energy that could have been produced for the service hours during the same period.

hoursserviceMWcapacityinstalledTotalMWhgeneratedenergyannualTotal×

×)(

%100)(

The term output factor is intended to apply to electricity generators and may not be directly applicable to some cogeneration plants.

Period hours The number of hours the unit was in an active state.

Refurbishment Any improvement activity on an existing power plant. Refurbishments are deemed ‘significant’ if they result in an accumulative capacity upgrade of a plant at least 10% above the maximum capacity used to determine the GES reference curve.

Retrofit Any improvement activity on an existing power plant that generally involves fitting new equipment to an existing plant. The prefix retro means “backwards” and in this context implies going back to an existing plant, after it has been commissioned, and fitting new equipment, that it did not have when first commissioned or at the time of the last greenhouse review.

Service hours Total number of hours a unit was electrically connected to the transmission system. For a twelve month reporting period, the service hours correspond to the period for which electricity was metered; i.e., corresponding to the MWhs for the period.

Thermal efficiency, Generated (ηGEN) )/()(

%1003600)(kgMJconsumedfuelofvaluecalorificgrosskgfuelQuantity

MWhgeneratedenergyTotal×

××

Thermal efficiency, Sent-out (ηSO) )/()(

%1003600)(kgMJconsumedfuelofvaluecalorificgrosskgfuelQuantity

MWhoutsentenergyTotal×

××

Total installed capacity Total installed capacity is the sum of the capacity for each unit

making up the power plant, where capacity is as defined above. Also see definition of “service hours”.

Upgrade Any improvement activity on an existing power plant that generally involves the replacement of obsolete technology with current technology.



4.0 APPLICATION OF GREENHOUSE EFFICIENCY STANDARDS 4.1 Principles Greenhouse efficiency is measured in terms of greenhouse intensity from fuel burning. It is the intent of the Generator Efficiency Standards that greenhouse intensity be reported on an annual basis as calculated from power plant data. The application and implementation of Generator Efficiency Standards shall be based on the following principles:

(i) Standards shall not discriminate between fossil fuels

(ii) Standards shall apply to both grid and off-grid generating plants that meet all of the following criteria:

• 30 MW electrical (MWe) capacity or above

• 50 GWh per annum electrical output

• capacity factor of 5% or more in each of the last three years.

(iii) Standards shall be based on greenhouse intensity as defined in section 3.0 Definitions

(iv) Standards shall be based on Greenhouse gases produced from fossil fuel burning as defined by the Intergovernmental Panel on Climate Change (IPCC), namely carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulphurhexafluoride (SF6). Fugitive emissions such as methane from coal stockpiles shall be excluded.

(v) Standards shall apply to plant as currently configured, with provision for acceptable degradation over time2

(vi) Standards for refurbished plant shall be as for existing plant but with adjustment for changes in performance if refurbishments are deemed significant, see section 12.0 Review of Greenhouse Efficiency Standards

(vii) Standards for new plant shall be based on best practice performance, adjusted for technical and commercial factors (e.g. market generation role may require frequent stops/starts or part-load operation) verified by the AGO

(viii) Standards applicable to a given plant shall be reviewed on a 5 yearly basis. Power plant performance shall be reported annually to the AGO for comparison to best practice performance.

With the agreement of the AGO, alternate methodologies can be used by GES participants if they can be demonstrated to yield results where the error or uncertainty in the determination of greenhouse intensity does not exceed the values given in Table 1. In addition, this guide does not draw a distinction concerning the location of fuel sampling and quantity metering. In other words, the fuel sampling and quantity metering systems may be owned and maintained by the fuel supplier or the fuel purchaser. However, the guiding principal is that approved methods of fuel sampling and fuel quantity metering are used and

2 The standards for the current configuration shall allow for plant retrofits and upgrades to meet other environmental standards, such as fabric filters for particulate removal, which may reduce sent-out efficiency of the plant.



that the calibration/checking of these measurement devices and the data produced is verifiable. The error or uncertainty for the determination of greenhouse intensity will depend on the specific metering equipment installed at a given plant, the type of equipment and method used for the analysis of the fuels consumed, and the frequency of measurement. It is expected that the best installed systems at the power plant will be used to determine greenhouse intensity. Using the methodology outlined in this Guide, the expected maximum error in the estimate of greenhouse intensity is indicated in Table 1.

Table 1 – Expected maximum error or uncertainty in the determination of greenhouse intensity.

Plant Type Maximum GI estimate error Electricity Generation ± 1.5%

e.g., 800 ± 12 kgCO2/MWh SO

Cogeneration Plant ± 3.0% e.g., 800 ± 25 kgCO2/MWh SO

Note: Factors that may significantly affect the estimate error in greenhouse intensity are the measurement of coal consumption, and the methods and frequency of determination of coal properties. Section 7.1.1 Coal Weighing allows for measurement of coal consumption by methods that have a demonstrated maximum error not exceeding ±1.5%. The AGO appreciates the limitations to measurement accuracy facing different power plants and the difficulty in setting a maximum measurement error. It is recognised that some methods currently used by some plants for fuel consumption measurement, such as mine and coal stockpile survey, are not able to provide measurement within this error allowance. GES participants are, therefore, required to estimate the error in the determination of greenhouse intensity for their plant based on real measurement and report the value whether it is less than or greater than the expected maximum error of ±1.5%. In addition, greenhouse intensity may also be estimated from the direct measurement of stack gases. Where appropriate GES participants, particularly those that have difficulty in setting a maximum measurement error for their fuel consumption should also use these measurements to estimate greenhouse intensity and provide an estimate of the error.



4.2 Applicable Gases and Associated Greenhouse Warming Potential Standards shall apply to the gases outlined in Table 2.

Table 2 – Greenhouse gases applicable to the Generator Efficiency Standards.

Greenhouse Gas

GWP Applicability

Coal Oil Gas CO2 1 yes yes yes CH4 21 yes yes yes N2O 310 yes yes yes

HFCs, PFCs & SF6

Usually not applicable



From Table 2, it can be seen that the equivalent CO2, in mass from fuel burning is:

ONCHCOCO mmmequivm2422

31021. ×+×+= Eqn (1) where mCO2, mCH4, and mN2O = quantity of CO2, CH4 and N2O, respectively, over the measurement period (e.g., tonnes in 1 year). 4.3 Application to Existing, Refurbished and New Plant 4.3.1 General For the purposes of this guide, Australian Best Practice has been based on the findings of independent studies undertaken on behalf of the AGO as reported at the July 1999 Workshop on Efficiency Standards, and reviewed in 2004/5. These studies considered the performance of Australian and overseas plant on an ‘as-designed’ basis and on a ‘current-performance’ basis. The ‘current-performance’ sent-out thermal efficiency (ηSO) is normally lower than the ‘as-designed’ ηSO as a result of a number of factors. These factors are:

• operational requirements not included in the design ηSO or in acceptance testing, such as frequent stops/starts and part-load operation required by market generation role

• non-recoverable degradation in efficiency caused by build up of scale and deposits, and by increased clearances, steam leakages etc, that cannot be recovered except by major refurbishment

• long-term recoverable reductions, which can be recovered by means of maintenance, repair, replacement and refurbishment of plant components

• short-term recoverable reductions, which can be recovered by means of correction of operational settings and by routine maintenance.

The objective of the Generator Efficiency Standards is to have power plants move towards best practice efficiency by minimising the recoverable reductions from design/acceptance test efficiency.



For existing plant, best practice is defined by a non-recoverable degradation in ηSO of not more than 0.2 - 0.3% of net heat rate per annum (unless otherwise indicated by plant manufacturer’s data)3, which translates to an equivalent increase in greenhouse intensity, applied to plant as follows:

• as currently configured • current fuel • design/acceptance test operating conditions and performance with allowance for

additional thermal losses that would not normally be taken into consideration during performance or acceptance testing of new plant (eg. market generation role may require frequent stops/starts or part-load operation)

In the case of gas turbines, manufacturers plant deterioration curves shall be used if available. For new plant best practice has been defined in terms of best available technology with allowances made for performance under typical Australian conditions and for commercial factors. Figure 1 below presents a flow chart giving an overview of the application of the Generator Efficiency Standards Measure to existing/refurbished plant and new plant GES participants. Appendix A presents an overview on the theory and principles of power plant efficiency. It may be noted that greenhouse intensity of fuel burning is a function of the sent-out efficiency (ηSO) of the power plant and the greenhouse emission factor for the fuel (F) expressed as kg CO2 equivalent/kg fuel.

Appendix B presents an overview on the theory and principles of power plant degradation. It describes recoverable/non-recoverable degradation, causes/effects, and rates of degradation for different power plant components.

This guide recognises the difficulties inherent in determining plant-specific greenhouse efficiency standards for either existing/refurbished plant or new plant. The intent of clauses 4.3.2 and 4.3.3 is to provide a pragmatic methodology for determining the following.

(a) For existing/refurbished plant: A baseline level of greenhouse intensity as a function of plant output factor against which current performance can be evaluated on a relative basis.

(b) For new plant: Guidelines to assist in establishing a baseline level of greenhouse

intensity as a function of output factor, relative to a comparable technology based standard, making due allowance for technical and commercial factors which may affect both the selection of plant and the final accepted performance of the plant.

3 The allowed degradation rate will be cumulative on a linear scale capped at 9.0% degradation in sent-out heat rate corresponding to an average plant life of 30 years



(c) Figure 1 – Generator Efficiency Standards – Process flow chart

New Plant

Incorporate greenhouse considerations in plant procurement processes

NoSubmit Action Plan for independent assessment. Action Plan forms Part B of Deed of Agreement

No

Yes. New design performance tests to be used for Strategic Plan

Deed of Agreement expires after 5 years. Has actual GI been reported below reference curve?

Annually report progress of all abatement actions including any changes

Use GI calculator (optional) provided by AGO to annually report GI

Have the actions increased plant capacity by 10% or more?

Provide detailed project information for each abatement action

Calculate cost of abatement in $/tonne of each action

Conduct detailed technical/financial feasibility analyses of abatement actions

Identify potential actions for reducing greenhouse intensity including, but not limited to, Appendix C of Technical Guidelines (For new plant, not required for the 1st 5 years)

Compare actual GI to best practice range

Use GES GI Calculator to: - Determine reference curve using commissioning or other performance test results - Determine best practice performance range - calculate actual GI

Sign Deed of Agreement

Commissioned plant with stable operations becomes 'existing plant'

Submit yearly operational stability monitoring report

AGO/proponent agree in principle with plant selection

Submit detailed case for plant selection

Yes. New design performance tests to be used for Strategic Plan

Submit Strategic Plan for independent assessment. It becomes Part A of deed of agreement

Existing/refurbished plant

Strategic Plan Part A - Deed of Agreement

Action Plan Part B - Deed of Agreement



4.3.2 Existing/Refurbished Plant 4.3.2.1 General Steps 1 - 6 described below should be used to compare current greenhouse intensity performance to a best practice performance range. In working through these steps, it may be necessary to refer established test codes such as:

• ASME PTC 4 - 1998 • ASME PTC 4.4 - 1981 • ASME PTC 22 - 1997/ISO 2314 - 1989 • other equivalent International test codes.

In addition, other readily available technical sources may also be used, including:

• technical reference books such as Gill, 1984; Babcock & Wilcox, 1992; Walsh and Fletcher, 1998

• recognised power plant modeling packages such as GateCycle and GT Pro. Note: A spreadsheet tool, GES Greenhouse Intensity Calculator, is available from the Generator Efficiency Standards measure to complete the following steps. An excerpt of the calculator can be found at Appendix G. The AGO encourages participants to obtain an electronic copy of the calculator from the GES website to assist with the following steps. 4.3.2.2 Procedure for existing/refurbished plant Step 1 – Documentation of performance test results

Document or estimate on the basis of the best available information results of reliable power plant performance tests. These may have been performed for commissioning/acceptance testing. Test results should indicate power plant efficiency as a function of load. A minimum of four points that are spread across the range of stable loads should be used. The expected maximum and minimum stable loads should be included. If reliable performance test data is not available, document or estimate on the basis of the best available information the design/test conditions that applied during the performance tests.

Test conditions should include:

• dry bulb temperature • wet bulb temperature • air relative humidity • design fuel quality

⇒ For coal - total moisture, ash, gross calorific value, and ultimate analysis ⇒ For oil - non-combustibles, gross calorific value, and ultimate analysis ⇒ For gas - molecular composition including non-combustibles such as

water, nitrogen, carbon dioxide, and argon. • combustion air (% in excess of stoichiometric requirements, or air-fuel ratio in

the case of gas turbines) • flue gas exit temperature • other losses

⇒ surface radiation losses ⇒ radiation losses through furnace throat to ash hopper ⇒ sensible heat in furnace ash (if applicable) ⇒ sensible heat in fly ash (if applicable)

• auxiliary loads



• cooling water temperature • condenser cleanliness factor • generator Transformer loss • start-up fuel component.

Step 2 – Recalculate ηGEN and ηSO to reflect operation using current fuels, and adjusted for additional heat losses that would occur under normal as-new or as-refurbished operating conditions but were not included in the initial performance/acceptance tests if applicable. Step 3 – Calculate the Reference greenhouse intensity (GIR) as kgCO2 equiv./MWh sent-out as a function of output factor to provide the ‘reference’ greenhouse intensity curve, using either of the following Equation:

( )jONjCHjCOj

jaspgrSO

R FFFXavQ

GI ,,,,,

2242

31021.

110600,3++×××= ∑η

Eqn (2a)

or

( )∑ ++××=j

jONjCHjCOjaspgr

R FFFXavQ

SHRGI ,,,,,

24231021

.1

Eqn (2b)

where Qgr,p,asav. = mass weighted average gross calorific value of the fuels used (in MJ/kg, as-

fired) F = emission factors from burning fuel j, for CO2, CH4, and N2O, respectively, as

applicable, in kg/kg fuel. Xj = mass fraction of each fuel type (j) burnt (e.g., coal, fuel oil) Procedures for determining emission factors are given in Sections 5 - 7 of this guide. For example see section 7.2 Emission Factors. Note that in Eqns 2a and 2b, an adjustment is made to the reference greenhouse intensity for start-up fuel (also see Section 4.3.2.5 Start-up Fuel). For a cogeneration plant similar curves can be prepared on the basis of the quantity of electrical and thermal energy produced (refer to Section 9 Measurement Protocol for Cogeneration Plants). Step 4 – Calculate the “Lower” and “Upper” values of greenhouse intensity for a range of loads (GIL) used in acceptance/performance tests. At least four load points should be used. Using non-recoverable degradation of not more than 0.2 - 0.3% of net heat rate per annum, calculations are as follows:

)002.0(1: ,

, ×−=

YGI

GIvalueLower LRLowerL Eqn (3)

)003.0(1: ,

, ×−=

YGI

GIvalueUpper LRUpperL Eqn (4)



where Y = age of plant (since new or refurbished) in Years. Note: For gas turbine plant, manufacturer’s curves for degradation in thermal efficiency as a function of operating hours between major overhauls should be used. Calculate the tolerance bands of the Lower and Upper GIL values as follows:

Lower value range = (1 ± 0.015) x GIL, Lower

Upper value range = (1 ± 0.015) x GIL, Upper The multiplier 0.015 is an allowance for the expected measurement error associated with GIL, see Section 4.1 Principles. Note: GES participants should use a multiplier determined from their actual reported measurement error associated with GI, whether that is less than or greater than the expected maximum error of ±1.5%. Step 5 – Plot the results of Step 4 to produce the greenhouse intensity standard as a basis for comparing actual plant performance in Year Y as follows:

(i) Upper curve of best practice performance range = (1 + 0.015) x GIL,Upper (ii) Lower curve of best practice performance range = (1 - 0.015) x GIL, Lower (iii) Reference GI curve (from Step 3).

These three sets of coordinates should be regressed by third order polynomial and plotted as shown in Figure 2. A third order polynomial is in this form: Y=aX3+bX2+cX+d where a, b, c, and d are constants. The lower curve will be adjusted upwards to the same position as the reference GI curve, if applicable.

Figure 2 - GES Template plot of reference curve, best practice performance range and actual GI as a function of output factor for a given plant of age 20 years. See Appendix G for more information.

Step 6 – Determine the actual greenhouse intensity for the plant in question following the procedures defined in Sections 5 - 10. Compare the actual greenhouse intensity with the corresponding best practice greenhouse intensity for the average output factor for the year.

950

1,000

1,050

1,100

1,150

1,200

45 55 65 75 85 95

Output Factor (%)

Gree

nhou

se I

nten

sity

(kgC

O2

equi

v./M

Wh

sent

-out

)

Reference Curve GI Upper Curve Lower Curve Actual GI



4.3.2.3 Non-Recoverable Degradation and Plant Age The recommended approach to establishing the greenhouse efficiency standard for a particular plant, as described in Figure 1 and as set out in Steps 1 - 6 above, is based on the concept of non-recoverable degradation with plant age (in years). In the case where a power plant (station) consists of a number of units of different age, an average plant age has been used in the methodology described above. However, a more rigorous approach would be to apply a greenhouse efficiency standard on a unit by unit basis. Where a power station consists of two or more units, the plant owner may adopt this approach, in which case, it will be necessary to portion station auxiliaries, and fuel burnt, to individual units. 4.3.2.4 Use of Multiple Fuels In a number of installations, individual power plant units are fired using a number of fossil fuels either in combination or at different times. It should also be noted that although fuel switching is beyond the scope of this measure, it is encouraged where it will reduce the greenhouse intensity of energy supply. Where a number of fossil fuel types are used, this guide recommends that the following approach be adopted.

(i) The actual performance of the power plant in any given year should be determined in the same manner as described in Sections 5 - 10 but on the basis of total annual MWh sent-out, total CO2 equivalent released, and average annual output factor.

(ii) The reference value of greenhouse intensity should be determined for the

year preceding the first year of agreement with the AGO, based on the weighted average fuel and calculation of sent-out thermal efficiency and corresponding greenhouse intensity, using the parameters and factors described in Clause 4.3.2.2 and the Theory and Principles outlined in Appendix A.

(iii) The lower and upper values of greenhouse intensity and the non-recoverable

degradation are then calculated as per Steps 4 and 5 in Clause 4.3.2.2. The method for multi fossil fuels is illustrated by the example in Appendix G. 4.3.2.5 Start-up Fuel Power generation plant requires fuel for start-up, to bring the plant up to operating temperature and speed. Start-up consumes fuel but generates no electricity. Intermediate, peak load and emergency generators may have a relatively high number of starts. It is acknowledged the requirement for fuel to start-up, and in particular the quantity of fuel used during start-up, is a function of:

• primarily, the technology employed and as such is an accepted characteristic of the technology

• secondly, the commercial environment in which the technology is obliged to function. It is further acknowledged that for conventional thermal (Rankine cycle) plant there are a number of start-up regimes depending on the temperature condition of the boiler and steam



turbine at the time of starting; hot starts taking less time and consuming less fuel than cold starts. During any year a plant may perform varying numbers of cold, warm and hot starts. Therefore, the “adjustment for additional heat losses” may also include an adjustment for fuel used during start-up (refer to Section 4.3.2.2 Step 3). 4.3.2.6 Non-Start-up Electricity and Fuel Consumed While Off-line Intermediate, peak load and emergency generators spend considerable periods off line in varying states of readiness. Maintaining a state of readiness may consume both electricity and fuel without generating electricity. It is acknowledged that the use of electricity and fuel to maintain a state of readiness or the ability to start rapidly, especially in the case of conventional thermal (Rankine cycle) plant, is a function of both the technology employed and the commercial environment in which the technology is obliged to function. Therefore, such electricity may be excluded from the calculation of the actual greenhouse intensity for the plant in question (refer to Section 4.2.2.2 Step 6).



4.3.3 New Plant 4.3.3.1 General

The supply of electricity (and heat in cogeneration applications) at competitive cost is a decisive factor for the market penetration of new fossil fuel based conversion concepts in a liberalised energy market, and is influenced at an operating level by such factors as:

• cost of fuel • capital cost of power plant • operating cost of power plant • reliability of power plant • net heat rate (or net thermal efficiency) • emission standards (particulates, NOx, SOx, trace elements, and greenhouse

gases) • electricity market requirements and constraints - including pool price, ramp rates,

output voltage and frequency limits, and unit turn-down or minimum load • infrastructure requirements - including electricity transmission and water

availability. On the key issue of efficiency and greenhouse gas intensity, the following factors are important:

• Fossil fuel type and characteristics - Black coal, brown coal, fuel oil, natural gas, coal seam gas or coal bed methane, coal derived fuel gases (including syngas from coal gasification processes, coke oven off-gas, and coal mine methane.

• Power technology - Sub-critical boiler, Super-critical boiler, ultra-super-critical boiler, atmospheric fluidised bed combustor, pressurised fluidised bed combustor (PFBC), open-cycle gas turbine (OCGT), combined cycle gas turbine (CCGT), and Integrated gasification combined cycle (IGCC).

• Emissions control technology - Particulates (Fabric Filters or Electrostatic Precipitators), Oxides of Nitrogen (combustion control, flue gas reburn, selective catalytic reduction - deNOx), Oxides of sulfur (fuel sulfur limits, lime injection, scrubbing systems - deSOx)

• Rankine cycle cooling system - Wet cooled, dry cooled, hybrid cooling • Ambient conditions - Dry bulb temperature, wet bulb temperature or relative

humidity, and ambient air pressure. Because of the factors that influence the net thermal efficiency of a power plant, it is not possible to prescribe a specific set of efficiency standards based on fuel type and technology alone. A technology review has been prepared by the Technical Advisory Group to the Australian Greenhouse Office - Generator Efficiency Standards Program (Appendix F) in order to:

(i) present a technical description of the key fossil fuel technologies (ii) compare the indicative performance data for the various plant classes as a

function of fuel type and characteristics, and ambient conditions (iii) provide guideline values for the comparison and selection of new power plant.

The following specific fossil fuel types and technologies have been examined; they represent the most common applications for electricity generation in Australia:

• black and brown coal in super-critical and ultra super-critical boilers



• natural gas/coal seam gas in open and combined cycle gas turbines • distillate in open and combined cycle gas turbines.

It is intended that the values of efficiency and GI values presented are indicative only (typically ±1% relative) and represent performance of various classes of plant in new condition, at ‘maximum continuous rating’, and as defined by the specific assumptions tabulated in Appendix F. It is also intended that the efficiency and GI of plants having fuel types and operating conditions different to the specific cases presented, can be estimated by extrapolation using a “reasonableness” approach. Procedure for New Plant Standards

1. Incorporate greenhouse considerations in plant procurement processes and submit detailed case for plant selection which addresses:

• New Plant Standards efficiency benchmark figures and principles in Appendix F • best available technologies with consideration for economic feasibility • diverse fuel/configuration options • opportunities for cogeneration • site options • water supply options • influence of statutory SOx, NOx and particulates requirements on plant options • transmission line losses.

2. AGO/proponent agree in principle with plant selection

3. During commissioning, a power plant may experience a period of ‘bedding-in’ to

achieve stable operations. GES participants are not expected to report actual GI for comparison to best practice performance during this period, but should provide updates of operational stability in six-monthly reports which include information about:

• capacity factor stabilised (largely market-driven) • monitoring/maintenance regime predictable • chemical controls are tuned • corrosion stabilised • forced outage rates trend • planned outages vs actual outages in first 12 months • actual efficiency (production levels) matching the specifications provided by

manufacturer • temperature/pressure levels to production specs.

4. After a plant has been commissioned, operations stabilised and final acceptance

testing has occurred, follow the steps in 4.3.2.2 to calculate current greenhouse intensity and a best practice performance range.

5. Report performance on an annual basis. Note: For new plant, a menu of options for performance improvement is not required for the first five years of operation.



4.4 Options for Reducing Greenhouse Emissions In the event that the actual greenhouse intensity for an existing plant is outside the performance range, as noted in Figure 1 and Section 4.3 of this guide, it will be necessary to identify and evaluate options for greenhouse efficiency improvement. The process for selecting and agreeing on greenhouse efficiency improvements is as follows:

(i) identify a range of greenhouse efficiency options and associated cost or benefit. A menu of options is presented in Appendix C to assist in this process. For each option derive the cost/t of CO2 equivalent avoided

(ii) undertake a detailed technical and economic analysis of each option (refer to Appendix D)

(iii) agree on a set of options, and document the anticipated reduction in greenhouse intensity.



5.0 EMISSION FACTORS FOR GAS-FIRED PLANT In this guide, gas-fired plant includes all plant consuming gas and producing electricity that meets the criteria in Clause 4.1. The following methodology covers the measurement of annual quantities of gas and the determination of the emission factors for CO2, CH4 and N2O from gas fired power plant. Note that Section 5 is written primarily in the context of ‘pipeline quality natural gas’, but may be extended to include other gaseous fuels where appropriate. 5.1 Measurement of Gas Volume and Quality 5.1.1 General

(i) The overall accuracy of metering equipment shall comply with the requirements set forth in regulations under the relevant Gas Acts.

(ii) The most accurate installed gas metering equipment shall be used. This

could be the equipment used for custody transfer metering. (iii) Gas metering equipment can be categorised according to the proportion of

Maximum Daily Quantity (MDQ) which may be provided. Gas metering categories (1 - 4) are defined in Appendix B.

(iv) The metering equipment should continuously record the volume flow rate and

all measurements used in computations. Metering systems of category 3 or 4 should also continuously record the energy flow rate and gross calorific value (Qgr,p,as).

5.1.2 Volumetric Measurement

(i) Volumetric measurement should be in cubic meter per hour (m3/h) at Standard Conditions. It should be calculated by a Flow Computer to be installed and maintained at the delivery location from flow signals, associated instruments, relative density and composition analyses.

(ii) The volumetric flow rate should be continuously recorded and integrated. The

integrating device should be isolated from the Flow Computer such that, if the Flow Computer fails, the last reading is retained.

(iii) Calculations for metering equipment of category 1 or 2 should be based on

average gas composition and relative density. Metering equipment of category 3 or 4 should use on-line instantaneous measurement.

(iv) All measurements, calculations and procedures used in determining volume,

except for the correction for deviation from the Ideal Gas Law, should be made in accordance with the instructions contained in the following Codes: • for Orifice Plate Metering systems - American Gas Association Report

No. 3 (AGA3), API 14.3, Parts 1 to 4 • for Turbine Metering systems - AGA Transmission Measurement

Committee Report No. 7 • for Positive Displacement (PD) Metering systems - ANSI B109.3 (1986).



Other internationally recognised Codes such as New Zealand standard NZS 5259: 1997, may also be used as appropriate.

(v) Measurements made using any of the instructions listed in Clause 5.2.2 (iii)

will be converted where necessary for compliance with: • Australian Standard AS 1000 “International System of Units (SI) and its

Application” • Commonwealth “National Measurement Act 1960” and regulations there

under, and the • Australian Gas Association publication “Metric Units and Conversion

Factors for use in the Australian Gas Industry”.

(vi) The correction for deviation from the Ideal Gas Law should be determined from the relevant method contained in AGA Transmission Measurement Committee Report No. 8 (1992) “Super-compressibility”. Metering equipment of category 3 or 4 should calculate super-compressibility using composition data. Metering equipment of category 1 or 2 may calculate super-compressibility by using an alternative method in AGA Report No. 8.

5.1.3 Energy Measurement

(i) For metering equipment of category 3 or 4, the Flow Computer should calculate the energy flow in GJ/h from the product of gross calorific value (Qgr,p,ar in MJ/m3) and volumetric flow (V in m3) at standard conditions. The gross calorific value should be calculated from gas composition in accordance with ISO 6976: 1995. The energy flow rate should be continuously recorded and integrated.

(ii) Metering equipment in category 1 or 2 should measure volumetric flow at

standard conditions. The energy total should be calculated by multiplying the volumetric flow by the average gross calorific value calculated from gas composition in accordance with ISO 6976: 1995. The gas composition should be measured by gas chromatography in accordance with ASTM D1945.

5.1.4 Gas Metering Equipment For the purposes of this guide, metering equipment should satisfy the following requirements. 5.1.4.1 Flow Devices

(i) Orifice metering systems should be constructed and installed in accordance with the provisions of AGA Report No. 3 such that the maximum uncertainty of the discharge coefficient is not greater than ±0.5%.

(ii) Turbine metering systems should be constructed and installed in accordance with the provisions of AGA Report No. 7 such that the maximum uncertainty of flow measurement is ±1.0%.

(iii) Positive Displacement Metering systems should be constructed and installed in accordance with the provisions of ANSI B109.3 (1986) such that the maximum uncertainty of flow is ±1.0%.

5.1.4.2 Differential Pressure, Pressure and Temperature

(i) Differential pressure, pressure and temperature measurement should satisfy the requirements listed in Appendix B. The stated accuracy required includes



the effects of static pressure and ambient temperature. Calibrated ranges should be selected to minimise the uncertainty of readings.

(ii) For orifice plate metering systems, high and low range differential pressure

transmitters may be installed to maintain the overall system accuracy. If fitted, the Flow Computer should automatically select the transmitter with the optimum operating range.

5.1.4.3 Flow Computer

(i) For each flow device of metering equipment of category 3 or 4, a self-contained single channel proprietary type Flow Computer should be installed. For metering equipment of category 1 or 2, a self-contained multi channel proprietary type flow computer should be installed where one flow device will be connected to each channel. The following outputs, and the instantaneous values for all primary measurement inputs, should be recorded:

• instantaneous corrected volumetric flow • cumulative corrected volumetric flow • instantaneous energy flow (metering categories 3 and 4) • cumulative energy flow (metering categories 3 and 4) • instantaneous uncorrected volumetric flow (turbine and PD metering

systems only) • cumulative uncorrected volumetric flow (turbine and PD metering

systems only) • super-compressibility factor.

5.1.4.4 Energy and Relative Density

(i) Gas samples should be analysed in accordance with the following Codes:

• ASTM D1945 • ISO 6976: 1995 or GPA Standard 2172 • other equivalent internationally recognised codes.

(ii) The energy content of the gas delivered should be determined by either on-

line gas chromatography or by the analysis of a representative composite sample of the gas over a period of not less than 1 month.

(iii) Gas chromatographs should be factory tested and calibrated using a certified

gas gravimetric standard and should perform with an accuracy of ±0.15% for gross calorific value and ±0.25% for relative density.

(iv) Gas chromatographs should include a facility for automatic re-calibration

against a certified calibration gas. 5.1.5 Standard Conditions Standard conditions for gas measurement should be as follows:

• Standard pressure 101.325 kPa • Standard temperature 15.0°C • Density of air at standard temperature and pressure 1.225 kg/m3



5.1.6 Inspection and Audit This guide recommends that an in-house inspection and audit program be developed and implemented to cover all operations associated with gas measurement and reporting. 5.2 Emission Factors 5.2.1 Carbon Dioxide (CO2) The emission factor for CO2 (in kg CO2/kg gas) from combustion of the fuel in a boiler or gas turbine (FCO2) should be calculated as shown in Table 3. Note the emission factor calculated in the example given in Table 3 is 2.4925 kg CO2/kg Fuel.

Table 3 – Calculation of CO2 emission factor for gas

Mole% 1

(or Vol%) Molecular

Wt (kg/kmole)

Density 2 (kg/m3)

Mass (%)

Carbon atoms in

component molecules

kg CO2/ kg Fuel

a b c d e f g 44.01 x e x f /

Component

b/V* 3 a x c d x 100/ dtotal (b x 100)

Methane CH4 94 16.043 0.6785 63.7801 87.9679 1 2.4132

Ethane C2H6 0.2 30.070 1.2718 0.2544 0.3508 2 0.0103

Propane C3H8 0.15 44.097 1.8650 0.2798 0.3858 3 0.0116

Butane C4H10 0.005 58.123 2.4582 0.0123 0.0170 4 0.0005

Pentane C5H12 0.003 72.150 3.0515 0.0092 0.0126 5 0.0004

Carbon Monoxide CO 0.005 28.016 1.1849 0.0059 0.0082 1 0.0001

Hydrogen H2 0 2.016 0.0853 0 0 0 0

Hydrogen Sulphide H2S 0.005 34.082 1.4414 0.0072 0.0099 0 0

Oxygen O2 0.05 31.999 1.3533 0.0677 0.0933 0 0

Water H2O 0.04 18.015 0.7619 0.0305 0.0420 0 0

Nitrogen N2 3.337 28.013 1.1848 3.9536 5.4529 0 0

Argon Ar 0.005 39.948 1.6895 0.0084 0.0117 0 0

Carbon Dioxide CO2 2.2 44.010 1.8613 4.0949 5.6479 1 0.0565

Totals 100 72.5039 100.0000 2.4925

1. Gas composition is the only input variable required in this table

2. Density at conditions of 15°C and 1 atmosphere

3. V* gas volume at 0°C and 1 atmosphere is 22.4136 m3/kmole, equal to 23.6444 m3/kmole at 15°C and 1 atmosphere

5.2.2 Methane (CH4) and Nitrous Oxide (N2O) There is no significant production of methane from combustion of natural gas in a boiler or gas turbine as methane emissions result from incomplete combustion, which, if persistent, is both inefficient and uneconomic. Whereas the quantity of carbon dioxide emitted can be calculated based on the quantity of natural gas consumed, assuming stoichiometric combustion, it is not possible to similarly calculate the quantity of methane emitted. Methane emissions must either be measured using a program of regular sampling and analysis, or estimated.



Nitrous oxide is generally formed under low temperature and reducing conditions, and as a consequence there is no significant production of nitrous oxide from natural gas fired power plant. Whereas the quantity of carbon dioxide emitted can be calculated based on the quantity of natural gas consumed, assuming stoichiometric combustion, it is not possible to similarly calculate the quantity of nitrous oxide emitted. Nitrous oxide emissions must either be measured using a program of regular sampling and analysis, or estimated. For the purposes of this guideline, emission factors for methane and nitrous oxide shall be taken from the most recent Methodology Workbook - Energy (Stationary Sources)4 released by the National Greenhouse Gas Inventory Committee. The conversion of emission factor from t CH4/PJ to kg CH4/kg fuel is as follows:

6,,44

1011

×××=d

QPJ

tCHkgFuelkgCH

arpgr Eqn (7)

where, Qgr,p,ar is gross calorific value of the gas in MJ/m3 , and d the density of the gas in kg/m3, at standard conditions. The conversion of emission factor from t N2O/PJ to kg CH4/kg fuel is as follows:

6,,22

1011

×××=d

QPJ

OtNkgFuel

OkgNarpgr Eqn (8)

where, Qgr,p,ar is gross calorific value of the gas in MJ/m3, and d the density of the gas in kg/m3, at standard conditions.

4 available at: http://www.greenhouse.gov.au/inventory/methodology/index.html



6.0 EMISSION FACTORS FOR OIL-FIRED PLANT In this guide, oil-fired plant includes all plant consuming fuel oil and producing electricity that meets the criteria in Clause 4.1. In the case where fuel oil is the principal fossil fuel used, or when the relative quantity is high (nominally >5% of total fuel), it is recommended that the metering system used be inspected and certified on an annual basis in accordance with the relevant State requirements under the National Measurement Act (1960). For plant that uses less than nominal 5% fuel oil, the following clauses are a guide only to metering, sampling and analysis. The following methodology covers the measurement of annual quantities of oil and the determination of the emission factors for CO2, CH4 and N2O from oil-fired power plant. 6.1 Fuel Oil Quantity and Quality The calculation of emission factors for oil firing requires that procedures be in place for the following operations:

(i) oil metering (ii) oil sampling (iii) oil analysis.

Specific requirements of each operation are as follows. 6.1.1 Oil Metering Australian standards applicable to the measurement of fuel oil quantities include:

• AS 2649 • AS 2651 • AS 2652 • AS 4250.1 • AS 4250.2 • AS 4250.3 • AS 4250.4 • AS 4250.5.

6.1.2 Oil Sampling The recommended practice for the sampling of fuel oil for analysis, be it from tanker, drum or fuel oil tank, is ASTM D4057. 6.1.3 Fuel Oil Analysis For the purpose of determining greenhouse emission factors, Table 4 sets out the recommendations for fuel oil analysis.



Table 4 – Oil analysis requirements for greenhouse efficiency reporting.

Parameter Frequency of testing Method

Gross calorific value Monthly, quarterly or by

consignment BS 2869, API Data Book (Figure 14A1-2), ASTM D 240, or other equivalent Internationally recognised code.

Density (for calculation of calorific value)

Monthly, quarterly or by consignment

ASTM D1298-99 Ed 2

Carbon Monthly, quarterly or by consignment

Instrumental carbon analysis or calculation from gas chromatograph analysis.

6.2 Emission Factors 6.2.1 Carbon Dioxide (CO2) The emission factor for CO2 in kg CO2/kg fuel from combustion shall be calculated as follows.

1244

1002×= a

COC

F Eqn (9)

where, Ca carbon in fuel, mass % as-received, as-sampled, or as-fired 6.2.1 Methane (CH4) and Nitrous Oxide (N2O) There is no significant production of methane from combustion of oil in a boiler or gas turbine. As in the gas of gas-fired plant, it is not possible to calculate the quantity of methane emitted as a result of incomplete combustion. Methane emissions must either be measured using a program of regular sampling and analysis, or estimated. For the purposes of this guideline, emission factors for methane and nitrous oxide shall be taken from the most recent Methodology Workbook - Energy (Stationary Sources)5 released by the National Greenhouse Gas Inventory Committee. The conversion of emission factor from t/PJ to kg/kg fuel is as follows:

6,, 10−××= arpgrQ

PJt

kgFuelkg

Eqn (10)

where, Qgr,p,ar is gross calorific value of the fuel oil in MJ/kg.




7.0 EMISSION FACTORS FOR COAL-FIRED PLANT In this guide, coal-fired plant includes all plant consuming coal and producing electricity that meets the criteria in Clause 4.1. The following methodology covers the measurement of annual quantities of coal, coal quality, and the determination of the emission factors for CO2, CH4 and N2O from coal-fired power plant. 7.1 Coal Quantity and Quality The calculation of emission factors for coal firing requires that procedures be in place for the following operations:

(i) coal weighing (ii) stockpile quantities (iii) coal sampling and sample preparation (iv) coal analysis (v) carbon in furnace ash and fly ash.

Specific requirements for each of the operations are defined below. In each case, with the agreement of the AGO, alternate methodologies can be used if it can be demonstrated that these alternatives provide values of the same accuracy or better as those recommended in the guidelines. 7.1.1 Coal weighing The method of weighing coal depends on the mode of transport of the coal to the power plant and can be carried out at the coal loading facility or at the coal receiving facility. Equipment for weighing or determining coal quantity includes rail weighers, weigh bridges, hopper weighers, and belt weighers. Calibration of the coal weighing system should be carried out as per the manufacturer’s instructions and at least on an annual basis. Some types of weighing system, e.g., belt weighers will require more frequent calibration. Calibration masses should be traceable to the appropriate National Standard of measurement. Guidance on technical requirements for weighers is included in the following codes:

• NMI R76-1 Ed 3 Rev 3 2002 • NMI R50-1 Ed 3 Rev 3 2004 • NMI R106 Ed 3 Rev 1 2004.

The maximum permissible error for weighers as prescribed by the National Standards Commission (Australia) is given in Table 5. Other methods for determining total coal quantity, such as mine volume change, may be used provided that any such method has a demonstrated maximum error not exceeding ±1.5%.



Table 5 – Maximum permissible errors for coal weighers on installation.

Weigher NSC Document MPE

Weigh bridges Class III (Static conditions)

Doc. 100 0 - 500 scale intervals 501 - 2,000 >2,000

±0.5 SI ±1 SI ±1.5 SI

Hopper weighers Class III (Dynamic conditions)

Doc. 100 ±0.1% (new) ±0.1% (re-verification)

Belt weighers (dynamic conditions)

Class I Doc. 102 ±0.5% Class II

Doc. 102 ±1.0%

Rail weighers Doc’s 113 and 117 Train: ± 5t or ± 0.2% of total mass, whichever is the greater. Wagons: ±1t or ±1% of total mass, whichever is the greater (under dynamic conditions).

7.1.2 Stockpile quantities The determination of the quantity of coal on a stockpile at a particular point in time should be determined using the following two-step procedure:

(i) Volume survey (ii) Stockpile bulk density.

It should be noted that the determination of the quantity of coal on a stockpile is relatively imprecise particularly because of the inherent difficulties in measuring bulk density. In most locations, the amount of coal on a stockpile at any given point in time is relatively small (5 - 10% of the total quantity of coal burnt in one year). However, at some locations it has been the practice to stockpile very large quantities of coal in which case the estimation of stockpile quantity becomes problematic. 7.1.2.1 Volume survey Stockpile volume may be estimated using accepted aerial survey or general survey techniques. 7.1.2.2 Stockpile bulk density The determination of the bulk density of a stockpile is inherently difficult because most of the coal is inaccessible to sampling. The recommended procedure for determining the bulk density of stockpiled coal is detailed in ASTM D6347/D6347M-99. Failing that, the recommended procedure is dependent on the quantity of coal stockpiled relative to the quantity of coal burnt for the year. Recommended procedures are given in Table 6.



Table 6 – Recommended procedures for stockpile bulk density.

Approximate Stockpile Mass (mSTOCKPILE)

Bulk Density Procedure

mSTOCKPILE ≤10% of annual coal burn Extraction of sample by mechanical auger as per ASTM D4916 - 89 • Weigh mass of sample extracted • Measure volume of hole • Bulk density equals mass over volume

mSTOCKPILE > 10% of annual coal burn Extraction of sample by coring • Weigh mass of sample extracted • Measure volume of hole • Bulk density equals mass over volume

7.1.3 Coal sampling and sample preparation 7.1.3.1 Coal sampling and sample preparation procedures The purpose of coal sampling is to obtain representative samples of the coal burnt for analysis as required to determine CO2 emissions. For the purposes of measurement as-received and as-fired will be treated as equivalent methods, dependent upon sampler location and plant configuration. Standards for the sampling, preparation of test samples, and verification of sampling and sample preparation systems and operations are ASTM D6347/D6347M-99 and AS 4264 Parts 1, 3, 4 & 56. As coal is a heterogeneous material, for the sample to be truly representative it must contain the correct proportions of each particle size present, as well as the correct proportions of particles of varying impurity content. Therefore, in the process of collecting a representative sample, each particle in the Lot must have an equal probability of being sampled (’equal selection probability’); the representivity of the sample being a function of the mass of the sample, or more correctly, the number of particles in the sample. A mechanical sampling system, designed and operated in accordance with AS 4264 should be used to sample the coal. Ideally, this type of sampling system would be set up to intersect coal as it is either being loaded at the coal source or unloaded at the power plant, and that a Lot of coal will normally represent 1 day or one train load of coal. If necessary, manual sampling of the coal may be used provided that the sampling equipment and procedure used is in accordance with AS 4264. Sample preparation as required providing a laboratory sample for analysis is normally carried out in two steps:

6 Standards Australia Committee MN1 is currently preparing a guide to the sampling of coal stockpiles for the determination of bulk density.



Step 1 – Initial crushing and subdivision of the samples as part of an operation that is integrated with the coal sampling

Step 2 – Final crushing and subdivision at the laboratory to provide the analysis sample.

7.1.3.2 Inspection and Audit Having installed a mechanical sampling system which conforms to the design criteria of AS 4264 (Part 1 or Part 2), this Guideline recommends that an in-house inspection and technical audit program be implemented, as described in AS 4264 Part 5, to cover equipment and operations associated with the sampling of coal. 7.1.3.3 Sampling precision Precision is defined as a measure of the extent to which the observations within a set agree with each other; usually expressed as twice the standard deviation (95% confidence level). Precision checks should be carried out on the sampling process to confirm that the sampling rate is acceptable, and it can be carried out on the sample preparation process. The procedure for determining the precision of coal sampling and sample preparation is prescribed in AS 4264.5. It is recommended that precision tests be undertaken on a yearly basis and whenever there is a change in the coal source or a significant change in the quality characteristics of a particular coal. In the case where several coals are being sampled through a given plant, sampling conditions and sample precision checks should be carried out on the coal that exhibits the highest degree of heterogeneity. 7.1.3.4 Sampling bias Bias can be defined as the tendency to obtain a value that is either consistently higher or consistently lower than the reference value; in practice, the difference between the reference value and the average result obtained from a large number of determinations. The recommended procedure for the estimation of bias in a coal sampling system is given in AS 4264.4. In the case of bias testing of mechanical samplers, the reference samples are usually stopped belt samples off a conveyor belt. For the purposes of verification of a coal sampling system, the coal samples taken for bias testing (i.e., pairs consisting of a reference sample and a sample taken by the coal sampler) should be analysed for total moisture and ash. Bias testing should always be carried out on a new sampling system. For an existing system the following verification procedure may be followed if there is some doubt about the conformance of the sampling system.

(a) Conduct a detailed technical audit of the sampling system. (b) Correct any non-conformances that have been observed. (c) Conduct a limited bias test on the system, usually with the coal that exhibits

the widest stochastic variability in total moisture or ash, to provide a more quantitative verification that the sampling system is performing correctly.



7.1.4 Coal analysis For the purposes of determining CO2 per unit mass of coal, Table 7 sets out the recommendations for coal analysis.

Table 7 – Coal analysis requirements for CO2 reporting.

Parameter

Frequency of testing Standard method

Total moisture (as-received or as-fired basis)

Every consignment Higher rank coal: AS 1038.1 and AS 1038.3 Lower rank coal: AS 2434.1

Ash (as-received or as-fired basis)

Every consignment Higher rank coal: AS 1038.3 Lower rank coal: AS 2434.8

Carbon (dry, ash free basis)

Monthly analysis sample composite

Higher rank coal: AS 1038.6 Lower rank coal: AS 2434.6.1

Gross calorific value Monthly analysis sample composite

AS 1038.5

Coal analysis verification and reporting practices are described in AS 1038.16. 7.1.5 Carbon in ash It is recognised that the configuration of plant varies and measurement of carbon in ash should be based on representative operating conditions for the plant. 7.1.5.1 Furnace ash Furnace ash includes ash collected at the bottom of the furnace hopper of the coal unit and ash collected within the economiser hopper at the rear pass of the coal fired power plant. There is no standard procedure to collecting furnace ash or economiser hopper ash; however, in a wet extraction system reasonable samples may be obtained by using sampling ladles to collect material from sluiceways, whilst in a dry extraction system good representative samples can be obtained directly from the conveyor. Note: Particular care must be taken in attempting to obtain samples of furnace ash because of the inherent dangers associated with such operations. 7.1.5.2 Fly ash Fly ash is that ash which is carried over from the furnace. There are several procedures for sampling fly ash:



Method I Sampling of the dust either at the outlet of the boiler airheater or the inlet to the flue gas cleaning plant using isokinetic sampling procedures as per AS 4323.1 - 1995 and AS 4323.2 - 1995.

Method II Collection of fly ash using standard industry ‘cegrit’ extraction equipment.

Method III Sampling of the fly ash from the fly ash collection hoppers of the flue gas cleaning plant or downstream of the fly ash collection hoppers from ash silos or sluice ways.

Method IV On-line carbon in ash analysers using sample extraction probes and infra-red analysers have been installed in some power plants.

Method I is preferred. If Method II or Method IV is used, the carbon in ash determined from such samples should be calibrated against isokinetic fly ash samples collected using Method I. For the purposes of determining carbon in ash, the following sampling frequency is recommended:

Method I Every two years, and as a function of load. Method II Every year, and as a function of load. Method III Every year. Method IV Every two years, and as a function of load.

7.1.5.3 Carbon in ash In the case where physical furnace ash and fly ash samples have been taken, the carbon in ash should be determined using the following methods:

• AS 3583.2 - 1991 Determination of moisture content • AS 3583.3 - 1991 Determination of loss on ignition

7.2 Emission Factors 7.2.1 Carbon Dioxide (CO2) The emission factor for CO2 (in kg CO2/kg Coal), from combustion, shall be calculated as follows.

1244

10)100(10 222×⎟⎟⎠

⎞⎜⎜⎝

⎛×−

×−=

a

arararCO C

ACCF Eqn (11)

where Car carbon in fuel, % as-received or as-fired Ca carbon in ash, % as-sampled (weighted average of fly ash and furnace ash) Aar ash in fuel, % as-received or as-fired



In addition,

100)100( arar

dafarAM

CC−−

×= Eqn (12)

Where Cdaf carbon in coal, mass % dry ash-free basis Mar the moisture in coal, mass % as-received or as-fired Aar the ash, mass % as-received or as-fired. 7.2.2 Methane (CH4) There is no significant production of methane from combustion of coal in a boiler, although it could be an issue in the case of synthesis gas (syngas) leakage from coal gasifier plants as syngas usually contains a proportion of methane. For the purposes of this guideline, emission factors for methane and nitrous oxide shall be taken from the most recent Methodology Workbook - Energy (Stationary Sources)7 released by the National Greenhouse Gas Inventory Committee. To convert t CH4/PJ to kg CH4/kg coal multiply by Qgr/106. For example, if the gross calorific value of the coal were 25 MJ/kg or 25 GJ/t, then an emission factor of 0.9 t CH4/PJ becomes 0.0000225 kg CH4/kg coal. 7.2.3 Nitrous Oxide (N2O) Nitrous oxide is generally formed under low temperature, reducing conditions (in other words, pyrolysis conditions) and as a consequence its concentration is normally very low in coal fired power plants. For the purposes of this guideline, emission factors for methane and nitrous oxide shall be taken from the most recent Methodology Workbook - Energy (Stationary Sources)7 released by the National Greenhouse Gas Inventory Committee. To convert t N2O/PJ to kg N2O/kg coal multiply by Qgr/106. For example, if the gross calorific value of the coal were 25 MJ/kg or 25 GJ/t, then an emission factor of 1.4 t N2O/PJ becomes 0.000035 kg N2O/kg coal.




8.0 MEASUREMENT PROTOCOL FOR ELECTRICITY OUTPUT This section sets out how electricity generation is to be measured for the purposes of this guideline. The period of one year used for determining the annual quantity of electricity shall coincide with the period of one year used for determining the annual amount of fuel consumption. The quantity to be measured is the net or sent-out electricity generation in energy terms, using units of MWh, designated MWhso for the purposes of this guideline. The terms “net” and “sent-out” are synonymous in this guideline and are defined in accordance with the National Electricity Rules (NER):

In relation to a generating unit, the amount of electricity supplied to the transmission or distribution network at its connection point.

It is recommended that sent-out electricity generation be measured in terms of active energy, in units of watt-hours, and in accordance with the applicable requirements of Chapter 7 (Metering) of the National Electricity Rules (NER). GES participants must comply with NER metering requirements and use the best installed equipment for electricity metering.. Access to the NER may be obtained via the Australian Energy Market Commission web site at http://www.aemc.gov.au/rules.php. Electricity consumed by workshops or other facilities attached to the plant but serving other functions than plant operations shall not form part of the calculation of greenhouse intensity.



9.0 MEASUREMENT PROTOCOL FOR COGENERATION PLANTS 9.1 General Cogeneration can be both a means of reducing the heat energy rejected by conventional power generation technologies, and a means of generating electricity as a by-product of thermal energy produced for or by industrial processes. The term “cogeneration” may cover a range of technologies and the plant configuration is host specific. (Note: the term “host” refers to the industrial process providing or using the thermal energy). In this guide, cogeneration is treated as a special case for the following reasons:

(i) the power plant is usually configured around particular process needs and not the converse

(ii) many cogeneration plants are off grid and the host consumes all the electricity produced.

Theoretical concepts for cogeneration are outlined in Appendix A. The energy inputs and outputs for the process (Figure 3) are generally as follows:

Energy Inputs Fuel, in GJ (EFuel)

Energy Outputs Thermal energy (usually as steam), in GJ (EThermal) Electricity sent-out, GJ, including electricity used by the host and, where applicable, electricity exported to grid (Esent-out)

Process

Fuel

Condensate return

Make-up water

Processsteam

Imported electricity

Electricity to grid

Auxiliary power

Power cogeneration

Power Plant

Cogeneration plant boundary

Power generated Power sent-out

Figure 3 – Schematic representation of a typical cogeneration plant.



Therefore, the Cogeneration Efficiency (ηCOGEN) is as follows:

%100×+

=Fuel

OutSentThermalCOGEN E

EEη Eqn (16)

where ESent-out is the electrical energy sent-out (i.e., electricity generated less power plant auxiliary load) in MWhs. Electricity used off-grid by the cogeneration host (the receiver of energy, either thermal or electrical) is to be considered as electricity sent-out. 9.2 Determination of Greenhouse Intensity For cogeneration plant, greenhouse intensity shall be calculated as follows:

( )ONCHCOThermaloutSent

FCOGEN FFF

EEmGI

242310216.3

. +++×

=−

Eqn (17)

Where mF is quantity of fuel consumed for the measurement period, in kg (see Sections 5-7), and EThermal and Esent-out are in units of GJ. Note: 1 MWh = 3.6 GJ. The Emission Factors (Fi) are as previously defined. 9.3 Energy as Process Steam

(a) For process steam, calculation of the thermal energy consumed by the process requires the measurement and recording of the following temperature, pressure, and mass quantity data at a frequency sufficient to provide reliable annual average data.

Delivered steam temperature, in °C

Delivered steam pressure, in kPa or bar Delivered steam quantity, designated msteam, in tonnes

Condensate return temperature, in °C Condensate return quantity, designated mcond, in tonnes

Make-up water temperature, in °C Make-up water quantity, designated mmake, in tonnes

(b) From the above pressure and temperature data, the specific enthalpy in units of

GJ/t for each stream shall be determined from the Steam Tables and designated as follows.

Delivered steam enthalpy hg (in GJ/t)

Condensate enthalpy hf,cond (in GJ/t) Make-up water enthalpy hf,make (in GJ/t)

(c) The energy delivered to the host, designated EThermal, in units of GJ, shall be

calculated by using the following formula.



)}({ ,, makefmakecondfcondgsteamThermal hmhmhmE ×+×−×= GJ Eqn (18)

i.e., EThermal = EProcess steam – ECondensate return – EMake-up 9.4 Application to Cogeneration Plants This guide treats cogeneration plant as a special case because the ηCOGEN is a function of electrical and thermal energy outputs; each of which can vary widely depending on process requirements. Therefore, for cogeneration plant, greenhouse efficiency should be assessed in terms of individual plant elements using the results of tests conducted periodically or by measuring or modelling actual performance. The tests to be carried out should be designed to do the following.

• Boilers - Compare the actual performance of the boiler at a range of loads calculated using the heat loss method described in Appendix A, with the performance expected under a series of reference conditions as referred to in Clause 4.3.2.2.

• Gas Turbine Generators - Compare the actual performance of the gas turbine at a range of loads based on simplified heat rate tests, with the performance expected under a range of reference conditions.

• Steam turbines - Compare the actual performance of the steam turbine at a range of loads/steam off-takes based on simplified heat rate tests, with the performance expected under a range of reference conditions.

• Auxiliaries - Compare the consumption of power of plant auxiliaries with that expected under reference conditions.

It is recommended that cogeneration plants prepare an in-house protocol based on the methodology described above or alternative appropriate methods for approval by the AGO, as a basis for assessing greenhouse efficiency under GES. 9.5 Energy Metering 9.5.1 Electricity Electricity sent-out as shown in Figure 3 shall be metered at the output terminals to the electrical transmission grid using metering equipment supplied with the plant. In the case of new cogeneration plant, electricity metering shall be in accordance with the requirements of the National Electricity Code (see Section 8 of this guide). Where electricity used by the host is not measured, a site-specific protocol shall be developed for determining Electricity sent-out for approval by the AGO. 9.5.2 Steam, condensate return, and make-up water The measurements required for steam in cogeneration plants include flow, temperature and pressure; and for condensate return and make-up water, flow and temperature. In the case where greenhouse intensity of a particular plant is to be reported on the basis of a series of periodic tests at one or more loads or cogeneration ratios [i.e., MW thermal/(MW thermal + MW electrical)], then the standards of measurement described in ASME PTC 4, 4.4, 22 or equivalent International code, shall apply.



9.5.3 Other energy products (e.g., compressed air) Cogeneration plants, especially those that are physically mingled and commercially vertically integrated with host industry sites may pose challenges to the application of these guidelines because of:

• the absence of metering on all energy streams

• the production of energy streams other than electricity and process heat (typically in the form of steam). Examples of other energy streams are hot water, chilled water (from absorption chiller), hot oil, compressed air, and hot exhaust gas.

Where energy streams are presently not accurately metered then either accurate metering will need to be fitted by the owner or a site-specific methodology developed for estimating those streams. Where the cogeneration plant produces energy streams other than electricity and process heat in the form of steam, it is recommended that the cogeneration plant boundary be redrawn upstream on the energy conversion chain such that it crosses the primary energy product from the cogeneration plant. This concept is illustrated by the following example. A cogeneration plant exports compressed air to the host. Both steam turbines and electric motors drive the air compressors. The respective energy conversion chains could be depicted as shown below, where the symbol M (metering) shows the recommended location for the redrawn cogeneration plant boundary: Fuel → Heat → Steam →M→ Turbine Drive Shaft Power → Compressed Air → Consumer

Fuel → Heat → Steam → Turbine Alternator Shaft Power → Electricity →M→ Electric Drive

Shaft Power → Compressed Air → Consumer While compressed air is exported from the cogeneration plant to the host, the compressed air is considered a secondary energy product, the primary energy products being steam, in the case of the steam turbine compressor drives, and electricity, in the case of the electric motor compressor drives.



10.0 CALCULATION OF GREENHOUSE INTENSITY 10.1 Greenhouse Intensity Measurement Interval This guide recommends that the greenhouse intensity for a given plant, expressed in units of kg CO2 equiv./MWh sent-out, be measured at intervals of not more than 3 months (and preferably monthly). The greenhouse intensity for the measurement interval shall be calculated as follows:

( )ONCHCO FFFoutsentMWh

FuelTonnesGI242

31021103

++−×

= Eqn (19)

For cogeneration plant, refer to Section 9.2. 10.2 Annual Average Greenhouse Intensity The Annual Average Greenhouse Intensity (AAGI) shall be calculated as the average GI for each measurement period (e.g., 12 × 1 month intervals) weighted on the basis of the MWh sent-out for the measurement period. All fuels used in the maintenance of the plant need to be included in calculating AAGI. However, the fuel used in plant vehicles does not need to be included. Annual average greenhouse intensity initially needs to be reported for comparison to a best practice performance range, and subsequently reported annually.



11.0 GREENHOUSE EFFICIENCY REPORTING REQUIREMENTS GES participants are obligated to provide an annual business report to the Commonwealth. Key Performance Indicators to be incorporated are:

• type of fuel (black coal, brown coal, gas, oil, other) • average annual greenhouse intensity • capacity • capacity factor • output factor • tonnes of fuel used • MWh generated, MWh sent-out, MWh imported, GJ thermal energy produced in

cogeneration. • sent-out thermal efficiency • details of improvement options undertaken and other options identified • greenhouse target.



12.0 REVIEW OF GREENHOUSE EFFICIENCY STANDARDS Greenhouse Efficiency Standards are to be reviewed every 5 years for existing and new plants. Any affected GES participant may request a review for their plant at any time during this period. A review of the standards applicable to an existing power plant will be triggered by a significant refurbishment. Refurbishments are "significant" if they result in an accumulative capacity upgrade of at least 10% above the maximum capacity used to determine the GES reference curve. When this occurs the reference curve and best practice performance range will be recalculated with new acceptance/performance data resulting from the refurbishment. The non-recoverable degradation period will also be reset.



APPENDIX A THERMAL EFFICIENCY THEORY AND PRINCIPLES A.1 Generated and Sent-Out Thermal Efficiency

The thermal efficiency of the power plant is defined as the ratio of energy out to the useful energy in, and may be expressed in terms of Generated Thermal Efficiency (ηGEN) or Sent-out Thermal Efficiency (ηSO):

%100,,

×=arpgrF

GGEN Qm

Pη Eqn (A.1)

%100,,

×=arpgrF

NSO Qm

Pη Eqn (A.2)

AGN PPP −= Eqn (A.3)

and, %1100 ⎟⎟

⎠

⎞⎜⎜⎝

⎛−××=

G

ATBSO P

Pηηη Eqn (A.4)

where

ηB, ηT efficiency of boiler and turbine, respectively, % PN power at the generator terminals less the auxiliary load (not driven by the turbine or

other prime mover), i.e., sent-out power, in MWh PG power at the generator terminals, MWh PA auxiliary load (including unit and station auxiliaries), MWh mF fuel burn rate, kg/s Qgr,p,ar gross calorific value of the fuel at constant pressure, as-fired, MJ/kg An alternative expression for thermal efficiency is Heat Rate (HR), where:

100(%)

3600×=

EfficiencyThermalHR , in units of MJ/MWh Eqn (A.5)

In expressing the units of power, it is common to draw a distinction between electrical power MWe and thermal power MWT. The terms Generated Heat Rate (GHR), and Sent-out Heat Rate (SHR), relate to ηGEN and ηSO, respectively.



A.2 Thermal Plants A.2.1 Boiler Efficiency There are two basic approaches to the determination of boiler efficiency:

• Heat loss method • Input/Output method.

Heat Loss Method The heat loss method is usually the most accurate and simplest and is based on a subtraction from the total heat input of heat losses from the boiler (ASME PTC 4 - 1998). The boiler absorbs most of the heat released on combustion of the fuel, however, the following significant energy losses invariably occur depending on ambient air conditions, coal quality, and the size, configuration and age of the boiler.

(i) Heat loss due to moisture in combustion air (La) (ii) Heat loss due to dry flue gas (Lg) (iii) Heat loss due to moisture in coal (Lmf) (iv) Heat loss due to water from combustion of hydrogen (H) in coal (LH) (v) Heat loss due to sensible heat in fly ash, furnace ash, economiser ash and mill

rejects (LA) (vi) Radiation and convective heat losses from the external surface of the boiler, (LR) (vii) Radiation loss to ash hopper.

Hence, the overall boiler efficiency is 100 less the sum of the losses in (i) to (vi) above. The following Equations (based on ASME PTC 4 - 1998) may be applied in the calculation of boiler heat losses from the combustion of fuels. (i) Heat loss due to moisture in combustion air

wvpagAaa cTTWWL ,)( −= MJ/kg Eqn (A.6)

where Wa is the mass of water vapour per kg of combustion air, WA the mass of combustion air per kg of fuel as-fired, Tg is the exit flue gas temperature in °C, Ta the inlet air temperature in °C, and cp,wv the average specific heat capacity of water vapour (0.002 MJ/kgC between 20 and 200°C).

(ii) Heat loss due to dry flue gas

gpaggg cTTWL ,)( −= MJ/kg Eqn (A.7)

where Wg is the mass of dry flue gas per kg of fuel as-fired using theoretical air, and cp,g the average specific heat capacity of flue gas (0.001 MJ/kgC between 20 and 200°C).

(iii) Heat loss due to moisture in fuel

{ }wvpgwgwpaar

mf cThcTM

L ,, )100()100(100

−++−= MJ/kg Eqn (A.8)



where Mar is the moisture content of the fuel in % as-fired, cp,w the specific heat of water (0.0042 MJ/kgC at <100°C), and hwg the specific enthalpy of formation of steam from water at 100°C (2.26 MJ/kg). The ASME test code requires the enthalpy of formation to be at the partial pressure of the moisture in the flue gas (Section 7.3.2.03 of code).

(iv) Heat loss due to water from combustion of Hydrogen in fuel

{ }wvpgwgwpaar

H cThcTH

L ,, )100()100(100

9−++−= MJ/kg Eqn (A.9)

where Har is the hydrogen content of the fuel in % as-fired.

(v) Heat loss due to carbon-in-ash

AAar

C QCA

L 410= MJ/kg Eqn (A.10)

where Aar is the Ash in fuel in % as-fired, CA the carbon-in-ash (%), and QA the average gross calorific value of the carbon/char in the ash (typically 33.8 MJ/kg).

Note: this heat loss is not applicable to gas firing.

(vi) Heat loss due to sensible heat in fly ash, furnace ash, economiser ash and mill

rejects (LA)

AagiAi

A cTTAL )(100 , −= ∑ β MJ/kg Eqn (A.11)

where βA,i is the mass fraction of total ash for each ash component (i) such as fly ash, furnace ash, etc., and cA is the specific heat capacity of ash (typically 0.00105 MJ/kgC between 20°C and 200°C).

Note: this heat loss is not applicable to gas firing.

Other heat losses normally include radiation heat loss from the boiler external surface (0.3 – 0.7% depending on the size, configuration and condition of the boiler), Lradiation. Hence,

%100)(

100,,

×⎥⎥⎦

⎤

⎢⎢⎣

⎡ +++++−−=

aspgr

ACHmfgaradiationB Q

LLLLLLLη Eqn (A.12)



Direct Method The direct method relies on accurate measurement of coal burn rate, and steam and feedwater conditions, so that boiler efficiency (ηB) is given by the expression:

100)(

,,

1111 ×−

=arpgrF

B Qmhhm

η Eqn (A.13)

where m1 feedwater flow to the steam generator, kg/s h1 enthalpy of steam directly upstream of high pressure (HP) turbine stop valve(s),

MJ/kg h11 enthalpy at the outlet of the final feed heater, MJ/kg mF burn rate of fuel, kg/s Qgr,p,ar gross calorific value of the coal at constant pressure as-fired, as-sampled or as-

received in MJ/kg. A.2.2 Steam Turbine Efficiency A steam turbine produces power by expanding steam through nozzles, which produce a high steam velocity to drive the turbine rotor, i.e., conversion of kinetic energy (heat) to mechanical work. For a typical coal fired power plant with three-stage steam turbo-generator and single reheat, turbine efficiency is given by:

%100)()( 2331111

×−+−

=hhmhhm

PGTη Eqn (A.14)

where PG Power generated (MWe) m1 Feedwater flow to steam generator, kg/s h1 Enthalpy of steam directly upstream of high pressure (HP) turbine stop valve(s),

MJ/kg h11 Enthalpy at the outlet of the final feed heater, MJ/kg m3 Steam flow directly upstream of intermediate pressure (IP) turbine stop valves, kg/s h3 Enthalpy of steam directly upstream of IP turbine stop valves h2 Enthalpy of steam at the exhaust of the turbine HP from which steam passes to the

reheater. The energy losses that occur in the turbo-generator include:

• friction and mechanical losses • glands steam losses • wetness losses (due to drag of water droplets on the moving blades) • leaving losses (kinetic energy of high velocity exit steam)



• exhaust losses (due to pressure drop in the hood between turbine outlet and condenser)

• generator (windage and friction) losses. For simplicity, it may be noted that not withstanding the reduced output of the turbine at partial loads due to reduced steam conditions (mass flow, temperature and pressure), the effect of the above losses increases as the steam flow through the turbine decreases at partial loads. Guidelines for performance testing of steam turbines include:

• ASME PTC 6 - 1996

• ASME PTC 6S - 1988

• BS EN 60953-1:1996

• BS EN 60953-2:1996

• BS EN 60953-3:2002. A.3 Gas Turbine Plants In a gas turbine (GT), or combustion turbine (CT, US terminology), the fuel is burned with compressed air and the resulting pressurised, hot gas expands through the turbine, which in turn drives both the air compressor and an electrical generator. (Note: Terminology confusion sometimes results with aero-derivative GT plant where the turbo-jet aero-engine derivative may be referred to as a “gas generator” because it simply produces pressurised hot gas. It may also have more than one turbine driven compressor, using concentric shafts. With the aero-derivative GT, the turbine driving the electrical generator is mounted on a separate shaft and is physically separate from the aero-engine’s turbine.) Regardless of its configuration, for a typical GT plant, GT efficiency is defined as:

arpgrF

n

QmP

,,,=η Eqn (A.15)

Typically, Q is given in LHV terms. [For most natural gases, the HHV/LHV ratio is in the order of 1.11]. Presentation of efficiency figures must always be accompanied by the qualifications of “sent-out” or “generated”, depending on whether auxiliary power is excluded or included in Pn, and “LHV” or “HHV” depending on whether Q is given in LHV or HHV terms. Energy losses that occur within the cycle include:

• frictional and mechanical • inlet pressure losses • exhaust pressure losses • generator windage • cooling losses.



Typically, part load performance remains reasonable until about 80% output is reached. Thereafter, efficiency falls off rapidly. Guidelines for the performance testing of GT’s include:

• ASME PTC 46 • ASME PTC 22 • ISO 2314.

Performance is normally corrected to standard ISO or agreed local conditions. This is necessary, for rating purposes because GT output and efficiency are directly impacted by ambient temperature, pressure and humidity. Other factors to consider include power factor and frequency. Manufacturers provide curves to perform these corrections. A.4 Combined Cycle Plants Typically, in a combined cycle (CC) plant, the hot exhaust gas leaving a GT is ducted to a heat recovery steam generator (HRSG) or boiler, which recovers some of the useful remaining energy to generate steam which in turn is expanded through a steam turbine (ST). Both the GT and ST drive electrical generators. Again, efficiency is defined by Eqn A.15. Here, Pn will include the electrical output from more than one electrical generator unless the CC plant is a modern single shaft machine where the GT and ST are on the same shaft and drive a single electrical generator. Typically, for the older plants, there may be more than one GT/HRSG combination supplying steam to a single ST. Normally, mf is the fuel burnt in the GT(s) only. Occasionally the HRSGs are fitted with duct burners to raise extra steam for the ST. In this case, the fuel flow to the duct burners must be measured too. As with a GT plant, CC plant output and efficiency vary with ambient conditions. Manufacturers provide curves to perform these corrections. The corrections may be complex as HRSG performance is affected by GT exhaust temperature and flow. Also, ST performance is affected by condenser CW temperature which in turn is affected by ambient temperature and humidity, especially if a cooling tower is employed. Guidelines for performance testing include ASME PTC 46. A.5 Cogeneration/Combined Heat and Power Plants A.5.1 General Cogeneration refers to the simultaneous generation of electricity and process heat (usually as steam) in a single power plant (DPIE/Aust. Cogeneration Association, 1997). An analogous term, used more commonly throughout Europe is “Combined Heat and Power”. Its most common application is in processing industries and in particular food processing industries where low-pressure process steam is required as well as electrical power, and in municipalities for district heating as is the case in many northern European countries.



A.5.2 Cogeneration Thermal Efficiency For a simple cogeneration plant involving the production of process steam and electricity, and the return of condensate from the process, the overall efficiency (ηCOGEN), is given by:

arpgrFCOGEN Qm

E

,,

=η Eqn (A.16)

arpgrF

mumupspsG

QmhmhmhmP

,,

1111 )( −−+= Eqn (A.17)

where E energy out, MW mF fuel burn rate, kg/s Qgr,p,ar gross calorific value of the fuel at constant pressure as-fired, MJ/kg PG power at the generator terminals, MWe mps mass flow rate of process steam, kg/s m11 mass flow rate of condensate return, kg/s mmu mass flow rate of make up (where mps = m11 – mmu) ΔhP heat energy taken from the process steam, MJ/kg hps enthalpy of process steam, MJ/kg h11 enthalpy at the outlet of the final feed heater (condensate return), MJ/kg hmu enthalpy of make-up water, MJ/kg A number of cogeneration plants do not export electricity and may in fact import some electricity. For cogeneration plants, the concept of generated thermal efficiency (ηGEN) versus sent-out thermal efficiency (ηSO) is not used, and the efficiency (ηCOGEN) as calculated in Eqn A.17 is taken as an equivalent sent-out thermal efficiency. A.5.3 Greenhouse Intensity Greenhouse intensity for a power plant or cogeneration plant is calculated as follows:

( )∑ ++×××=j

jONjCHjCOjarpgrSO

R FFFXavQ

GI ,,,,,

2242

31021.

110600,3η

Eqn (A.18)

or

( )∑ ++××=j

jONjCHjCOjarpgr

R FFFXavQ

SHRGI ,,,,,

24231021

.1

Eqn (A.19)

where Eqns A.18 and A.19 are equivalent to Eqns 2a and 2b, respectively. A.6 Calorific Value of Fossil Fuels The calorific value of a fuel (Q) is a measure of the heat actually produced on combustion of the fuel under prescribed conditions.



The methods of determining gross calorific value, Qgr (or higher heating value, HHV) of a fuel include:

• Coal – Bomb calorimeter • Oil – Bomb calorimeter or calculation from density • Gas – Boys calorimeter or calculation from gas composition.

Details of the methods are referred to in the main sections of this guide.



APPENDIX B POWER PLANT DEGRADATION B.1 Introduction Power plant performance degradation is an issue of major concern to the owners and operators of power plants, since degradation will have an impact on plant output levels and specific fuel consumption. This in turn of course has significant negative impact on the plant operational profitability and environmental impact. Appendix B describes:

• What is recoverable / non-recoverable degradation

• What are the causes of degradation

• How degradation applies to different parts of generating plants

• What are the recoverable elements of degradation

• The effect of degradation on output and heat rate

• Indicative degradation curves for various plant types.

B.2 Background Thermal power plant performance starts degrading as soon as the plant is taken into operation the first time. Overall, degradation will occur to a varying degree in most parts of the plant, but based on the results from an extensive information search, the industry’s focus is primarily on turbine degradation, since performance recovery efforts are more complicated and expensive on turbines than on other parts of the plant. This guideline does not address the performance losses from factors which as a rule are dealt with through standard operational procedures, e.g. soot blowing of heat transfer surfaces in boiler, compressor washing of gas turbine compressors etc, nor will it address sudden performance degradations caused by Foreign Object Damage (FOD) or Domestic Object Damage (DOD). Instead, the focus will be on degradation caused by fouling, surface roughness and clearances. B.3 Types of Degradation Degradation is generally divided into recoverable and non-recoverable. B.3.1 Recoverable losses Recoverable degradation relates to the performance losses that can be recovered through regular cleaning of the degraded component (e.g. primarily those that relate to fouling on a turbine). B.3.2 Non-recoverable degradation Non-recoverable degradation relates to performance losses that cannot be recovered through cleaning, but requires component refurbishment or replacement.



B.4 Gas Turbines B.4.1 Causes of degradation - overview Overall, gas turbine performance degradation is attributable to flow path deterioration, which leads to flow reductions and/or component efficiency reductions, which in turn reduces the unit’s output and efficiency. According to GE document: GER-3567h - GE Gas Turbine Performance Characteristics:

“All turbomachinery experiences losses in performance with time. Gas turbine performance degradation can be classified as recoverable or non-recoverable loss. Recoverable loss is usually associated with compressor fouling and can be partially rectified by water washing or, more thoroughly, by mechanically cleaning the compressor blades and vanes after opening the unit. Non-recoverable loss is due primarily to increased turbine and compressor clearances and changes in surface finish and airfoil contour. Because this loss is caused by reduction in component efficiencies, it cannot be recovered by operational procedures, external maintenance or compressor cleaning, but only through replacement of affected parts at recommended inspection intervals. Quantifying performance degradation is difficult because consistent, valid field data is hard to obtain. Correlation between various sites is impacted by variables such as mode of operation, contaminants in the air, humidity, fuel and dilutent injection levels for NOx. Another problem is that test instruments and procedures vary widely, often with large tolerances. Typically, performance degradation during the first 24,000 hours of operation (the normally recommended interval for a hot gas path inspection) is 2 - 6% from the performance test measurements when corrected to guaranteed conditions. This assumes degraded parts are not replaced. If replaced, the expected performance degradation is 1 - 1.5%. Recent field experience indicates that frequent off-line water washing is not only effective in reducing recoverable loss, but also reduces the rate of non-recoverable loss. One generalisation that can be made from the data is that machines located in dry, hot climates typically degrade less than those in humid climates.”

As outlined in above quote, the key factors for performance loss are caused by increased internal leakages, surface roughness and blade profile deterioration. Although GT original equipment manufacturers (OEMs) as a rule only supply general, overall anticipated degradation values for output and efficiency/heat rate, without any separation into compressor and turbine degradation, this paper will also attempt to describe the main individual causes for performance degradation in compressor and turbine. B.4.2 Rates of degradation In above quote from GE, degradation values of 2 - 6% are mentioned over the first 24,000 operating hours. As there is no qualification of the data, one can assume that this range covers both output and efficiency degradation, for both gas and liquid fired units, and covering a range of ambient conditions. Other information sourced from a gas fired GE Frame 6B quotation indicates a 2.0% output reduction and a 1% heat rate increase over 24,000 hours, increasing to 2.5 and 2.0%, respectively, over 36,000 fired hours.



Similar information from other OEM’s (GT specific information) indicate: Utility size GT (“E-class”): 24,000 hours: 2.0 - 2.6% heat rate increase 3.0 - 3.9% output decrease 36,000 hours: 2.4 - 2.8% heat rate increase 3.3 - 4.2% output decrease Above values applicable after off-line cleaning of the unit. No information on level of

recoverable losses. Industrial unit (40 MW class) over 80,000 Equivalent Operating Hours (EOH): Data assumes off-line cleaning of the unit before testing. The graph also shows

anticipated performance recovery through hot section component replacement / refurbishment. The graph also highlights the fact that compressor components are generally not part of the engine refurbishment, and that the compressor non-recoverable degradation has a greater impact than that of the hot section components.

It should also be pointed out that degradation seems to be engine specific, particularly in view of the trend for higher pressure-ratios and more advanced compressor designs with newer gas turbines. Thus, it is not possible to provide general, equipment-independent guidelines for GT degradation, but one needs to rely on specific OEM data for each installation. B.4.3 Compressor degradation Although every percentage point in efficiency degradation on the turbine section of the GT has greater performance impact on the overall GT cycle, generally compressor degradation is regarded as a greater performance issue, since the compressor typically experiences far higher levels of degradation, both in terms of efficiency and mass flow capability through fouling, increased tip clearance, and erosion and corrosion. Erosion and corrosion of the compressor blading, together with tip clearance increases represent the non-recoverable degradation of the GT’s compressor section.



B.4.3.1 Fouling An axial flow compressor is very sensitive to fouling, which starts to build up as soon as the turbine is started for the first time. Fortunately, most of the fouling-based degradation can be recovered through washing of the compressor, either on-line or off-line. Fouling is caused by dust particles in the intake air stream depositing on the compressor rotating and stationary blading. In part, this may occur through an adherence effect which may be caused by normal air humidity and oil leaks from bearing number 1. The adherence from the air humidity effect is due to the pressure drop that occurs in the inlet bell-mouth, which under certain inlet velocities, the static temperature and pressure may fall below the saturation line, forcing excess water vapour in the air to be condensed. If the amount of condensate falls within a critical range, it may act as a “glue” for the particles that enter the compressor. It should be noted that plants operating under cold and dry conditions, there will not be enough condensate to act as a glue, and at tropical conditions (high wet bulb temperature) the amount of condensate increases to a level where it can provide some kind of on-line washing effect. The oil leakage in bearing 1 will not only cause adherence for the dust particles in the LP section of the compressor, but will also form coke deposits in the hot discharge section of the compressor, which may be very hard to remove through normal washing - may require special chemical cleaning during overhaul. The fouling affects both the efficiency and pumping (flow) capacity of the compressor. According to research, the capacity reduction is approx 1.6% per 1% efficiency reduction. The capacity reduction is a bigger problem for fixed speed GTs (single shaft), since the compressor cannot increase the speed to compensate for the lost capacity. Fouling degradation is caused by increased blade surface roughness and profile changes. B.4.3.2 Efficiency reduction The compressor efficiency reduction leads to increased compressor power demand per unit of air flow, reducing the power available for power generation, thereby reducing the GT’s output and efficiency. In combined cycle applications, there is no recovery for compressor efficiency-derived performance degradation. B.4.3.3 Capacity reduction The capacity reduction leads to a lower air mass flow to the combustion chamber, which in turn both reduced the compressor pressure (lower pressure ratio and consequently a lower expansion line) and reduces the turbine gas mass flow, thereby reducing the GT’s output and efficiency. GE indicates in their document GER-3419A - “Gas Turbine Inlet Air Treatment” that compressor fouling can reduce the GT output by as much as 20% in cases of extreme compressor fouling. In combined cycle applications, the reduced mass flow from capacity reduction will also reduce the steam cycle efficiency due to lower steam generation caused by the lower mass flow. A small portion of this loss can be recovered through the higher exhaust gas temperature as a result of the lower pressure ratio over the GT’s turbine section. B.4.3.4 Inlet air filtration, compressor washing From above it is clear that high quality air filtration and appropriate application of on-line and off-line washing are vital to sustain the highest possible long-term plant performance.



Off-line, or crank-soak, compressor washing is the most efficient method of removing fouling from the gas turbine, but as it must be carried out when the unit is in cold condition, it may not always be possible to perform as frequently as one would wish. On-line (on-load) washing has, thus, been introduced as a stop-gap measure, primarily for continuous duty units, to aid in delaying the onset of large fouling. It must be recognised that on-line washing cannot replace off-line washing, only extend the intervals between these. It should also be recognised that on-line washing first of all only works on the first stages of the compressor where the air temperature is below the corresponding water evaporation temperature. Also, there are risks involved with on-line washing, e.g. moving fouling further upstream in the compressor, clogging of secondary systems and high temperature corrosion - on-line washing does not drain the solved deposits from the compressor, but they follow the compressed air through the engine and may appear in more critical locations, such as cooling passages in a turbine blade. As a result of these risks, the general recommendation is that on-line washing must be carried out at least once per day to prevent excessive build-up of deposits, and if an on-line is missed, a full off-line cleaning is required before any further on-line washing. The scheduling of compressor washing is generally based on a determination of the fouling impact on performance (i.e. comparing actual performance against the nominal performance after anticipated non-recoverable degradation), and whenever the value of the performance improvement exceeds the cost, e.g. the loss of production during downtime, an off-line washing should take place. Also note GE’s comment that recent findings indicate that the higher the frequency of off-line washing, the lower the non-recoverable degradation. B.4.3.5 Tip clearances The tip sealing system is sensitive to wear from e.g. rubbing, which normally is caused by differential expansion between rotating and stationary part during run-up and load transients. Leakages between the stages will not only “re-circulate” air from higher to lower pressures, increasing parasitic losses in the system, but will also disturb the air flow in the compressor stages, reducing the efficiency. Theoretical modeling has found that each 1% increase in rotor clearance will reduce the stage efficiency by approximately 2%. Traditionally, turbines were designed to ensure that there would be no rubbing of the seals in a compressor, but due to the complexities of providing designs which could handle all conceivable modes of operation without having excess clearances, modern GTs are equipped with abradable seals or similar (e.g. brush seals), which allow rubbing without damage (or even as part of “creating” the appropriate tip clearances through cutting into the abradable surfaces). However, unless active clearance control is applied (OEM’s will need to advise of the technology is available), one should expect that seals will experience wear during the operating life, e.g. in connection with turbine trips or similar, resulting in increased leakages during steady state operation. B.4.3.6 Erosion GE in document GER-3419A -Gas Turbine Inlet Air Treatment indicate that:



“Both the axial compressor and the hot-gas-path parts can be affected by erosion from hard, abrasive particles, such as sand and mineral dusts

As these particles impact upon the compressor blades, they cut away a small amount of metal. The net rate of erosion, although not quantifiable, depends on the kinetic energy change as the particles impinge, on the number of particles impinging per unit time, the angle of impingement, and on the mechanical properties of both the particles and the material being eroded”.

In general, experience shows that particles 20 µm and above will cause erosion when present in sufficient quantities. Blade erosion causes an increase in surface roughness and on a longer-term basis, profile changes through material loss, all of which reduce the aerodynamic efficiency of the blading. Extreme levels of erosion can also endanger the structural integrity of the blading, with a risk of major damage to the GT due to blades, or parts there off, breaking off, and passing through the unit. B.4.3.7 Corrosion Wet deposits of sea salt, acids and other aggressive materials can cause compressor corrosion. In addition to corrosion of compressor wheels, corrosion can also cause pitting of the compressor blading, which increases surface roughness, and decreases the aerodynamic performance. B.4.4 Turbine degradation The main causes of turbine degradation are basically the same as for the compressor, although fouling is generally not an issue unless the GT is operating on liquid fuels containing e.g. ash. In particular, tip clearances and surface roughness are of importance, but also profile changes impact on the performance. B.4.4.1 Tip clearance The same general description as for the compressor tip clearance applies for the turbine section, with the additional comment that the very high temperature range that the turbine section experiences from start-up through to base load operation leads to even greater possible differential expansion between rotating and stationary parts. B.4.4.2 Surface roughness and erosion Turbine blading surface roughness will be impacted by high long-term hot gas exposure, as well as possible corrosion through ingestion of certain metals which after combining with sulfur (particularly liquid fired units) and / or oxygen deposit on the surfaces of the hot gas part components. The metals of primary concern are sodium, potassium vanadium and lead. Additionally, the ingested dust particles that do deposit on the compressor blading will of course pass through the machine, and will cause a longer-term erosion of the blading. However, as can be seen from the graph under 4.1.1, the frequency of blading replacement / refurbishment required to maintain the unit within its creep life limitations is such that the performance impact from surface roughness/erosion is relatively limited compared with the compressor degradation impact.



B.5 Steam Turbines and Ancillaries Steam turbine degradation analysis is generally more straightforward than for GTs, since it is a simpler machine and only consists of a turbine section. Flow path degradation can be categorised into 5 main root causes:

• Deposits • Surface roughness • Sealing leakages • Internal leakages • Solid particle erosion (SPE).

In addition to the steam turbine degradation, condenser performance is the other key area of possible performance degradation. An article titled “No deposits, big returns” published in Power Magazine (April 2005) reports the results of a recently completed 2-year study performed by EPRI in the US on the effects of surface roughness and deposits on turbine efficiency. The article can be obtained from www.platts.com. B.5.1 Steam turbine As an example of a typical breakdown of the causes of steam turbine efficiency deterioration, below graph, shown in GE Document GER-3750C Steam Turbine Sustained Efficiency, based on a typical utility size GE steam turbine:

“40 % of the total identified loss is due to the sealing leakages, 15% each due to SPE and deposits and the remaining 30% due to general aging caused by increased surface roughness and geometry changes in the stationary and rotating blading. Information on overall levels of steam turbine degradation is generally hard to find, also for OEM equipment suppliers, particularly in today’s deregulated environment, where actual plant performance levels is often treated as confidential commercial information. Based on limited information provided, following general comments can be made:

• Utilities often have a requirement for 3 - 5% steam flow capacity margin for new plants to ensure that the plant will meet its original net output also after degradation.

• A recent turbine refurbishment in the US resulted in the full recovery of a 6% performance degradation

• A couple of steam turbines in Indonesia had experienced a 15 - 20% capacity reduction over an approx 20 year period, mainly due to substandard feed water quality.”



According the above GE document, there is a notable difference in overall degradation between impulse and reaction type of turbines, in particular the degradation caused by increased sealing clearances (see also Section B5.1.4). Short description of impulse and reaction type turbines: Impulse type turbines In a 100% impulse steam turbine, the pressure drop over each stage takes place in nozzles in the stationary turbine diaphragms, converting the steam volume expansion into a high steam velocity which in impacts at the rotating blades at a high velocity (typically approximately 1.8 - 2.0 times the blade velocity) transferring the steam energy into the rotating blades. As there is no pressure drop over the rotating blades, and therefore no axial thrust due to pressure differences, impulse turbine rotors are typically designed with a slim shaft with discs for the blading (see figure). The small shaft diameter reduces the total leakage area, and thus the inter-stage leakages. Furthermore, as there is no pressure drop over the blades with a 100% impulse unit, blade tip leakages are very small and require only relatively simple sealing arrangements. Also, with the slim shaft, thermal expansion of the rotor is relatively small, potentially allowing tighter shaft labyrinth clearances. Basic blade efficiency for impulse turbines is generally slightly lower than for reaction units, and the efficiency falls off faster when the turbine is not operating at it optimum ratio of blade velocity / steam velocity. In general, impulse turbines are more commonly used for industrial type applications, although a few manufacturers are supplying utility size impulse turbines (e.g. Toshiba and GE, although the latter seems to have changed to reaction designs recently. Reaction type turbines Reaction type turbine actually operates with 50% reaction and 50% impulse, with the pressure drop over each stage split equally between the stator and rotor blading. The steam leaves the stationary blade at a relatively high velocity transferring its energy as an impulse to the rotating blade, where it is further expanded giving a reaction force as it expands through the blade.



As half of the pressure drop in the turbine occurs in the rotation blades, the pressure difference will create an axial thrust in the steam flow direction. To minimise this thrust, the turbine rotor is of “drum” type, with the rotating blades inserted directly into the rotor shaft. The remaining thrust for a single flow turbine must be balanced through the use of a balancing piston (seen as the left-most disc on the drawing above) where high pressure steam acts against a disc where the chamber on the other side of the disc is connected to a lower pressure port on the turbine module. As the balancing steam is not expanded through the blading, it reduces the potential turbine efficiency. Large utility type steam turbines, however, are designed as double-flow units with steam inlet in the middle, where the axial thrust from the two steam paths balance each other and no balancing steam is required. Inter-stage leakages in reaction type turbines are higher than for impulse units. Firstly, the rotor diameter is larger (no blade discs), giving a much larger leakage area between the rotor and the stationary blading, and secondly, half the pressure drop occurs over the blading, giving a substantial blade tip leakage, requiring a more advanced tip sealing system. Furthermore, as the labyrinth seals are located at larger diameters than in impulse units, there may be a need for greater labyrinth clearances to avoid rubbing due to different thermal expansion between rotor and stator during run-up, load transients and shut-down. As mentioned above, reaction type blading generally offers higher basic efficiency than impulse turbine, but unless the potential for large efficiency losses from balancing steam requirements and inter-stage leakages are addressed through careful design, the resulting net efficiency of reaction turbines may in the worst case scenario remove any efficiency advantage. B.5.1.1 Deposits Deposits are normally caused by carry-over effects from the boilers, where unwanted matter is carried with the steam to the turbine. The critical impurities in the steam are:

• silica from make-up and condenser leakages • copper oxides from pre-heaters and condenser tubing (if applicable) • chlorides from make-up and condenser leakages • iron oxides (e.g. magnetite) from superheaters • carbon dioxide • sulfates • organic and inorganic acids.

The various types of impurities tend to distribute at different locations in the turbine. Typically copper deposits tend to deposit in the HP turbine inlet section, often reducing the inlet section’s capacity; and silica tends to deposit in the middle of the LP turbine. Some of the deposits are water soluble, and can, thus, be removed through washing, whereas some



deposits will require mechanical or chemical removal, which can only be performed with the unit opened. The main effects of deposits are increased surface roughness, changes in blade profile and reduction of capacities due to narrowing of the steam path. B.5.1.2 Surface roughness Increased surface roughness is normally due to deposits, but can also be due to ageing, foreign object damage, improper cleaning and conservation. The most common cause for foreign object damage is from metal particle / weld bead carry-over from the boiler during e.g. initial commissioning, or after boiler repairs, i.e. caused by insufficient steam blows. The exhaust stages of the turbine, which operate in wet steam conditions, will also be subject to long-term erosion due to water droplet impingement, leading to increased surface roughness as well as blade profile changes. Turbine manufacturers provide protective measures, such as moisture separation and hardening of the leading edge of the blade to reduce this erosion as far as possible. B.5.1.3 Sealing leakages Sealing leakage damages are in most cases due to tip rubbing, steam flow induced vibrations and wrong assembly. Rubbing is generally avoidable if the unit is operated within the start-up and transient load change limitations set out in the instructions by the manufacturers, as these instructions will be based on maintaining differential expansions such that no rubbing will occur. Modelling in SteamMaster software indicates that a doubling of all gland leakages will reduce the plant output by approx 0.7%. B.5.1.4 Interstage leakages Interstage steam leakages will also of course impact on the plant performance - not only will the steam leakage reduce the amount of steam doing work in the turbine blading, but the leakage steam flow will enter the main steam path perpendicularly, disturbing the flow between rotating and stationary blading. In support of GE’s statement referred to above, reaction type turbines, which distribute the pressure drop over stationary and rotating blading, require larger diameter gland seals, which create larger leakage areas, compared with impulse turbines which have the full pressure drop over the stationary blading (diaphragms) allowing the use of a relatively slim rotor with the blading mounted on discs. Information indicate that each 0.5 mm of radial clearance in the inter-stage seals can reduce the individual stage efficiency by 1 - 3% for each of the tip and root seals, depending on turbine design. Some of the individual stage efficiency loss can be recovered in subsequent stages through the “reheat” effect from the leakage. B.5.1.5 Solid particle erosion The inlet stages of most utility type turbines, operating with steam temperatures of 540°C and higher experience solid particle erosion (SPE) to some degree. This is generally caused by magnetite particles from the superheater during start-up. Thus, it is generally



Condenser pressure

100.0%100.2%100.4%100.6%100.8%101.0%101.2%101.4%101.6%101.8%

100% 110% 120% 130% 140%Relative condenser pressure

Rel

ativ

e he

at ra

te

recommended to have a start-up bypass to the condenser, allowing the magnetite to end up directly in the condenser, instead of causing erosion on problems in the turbine. The efficiency impact of SPE on the inlet stages of HP and IP turbines in reheat applications is according to literature in the order of up to 0.5%, and it is assumed that SPE is repaired during regular maintenance B.5.2 Condensers The condenser behaviour has a direct impact on the overall steam cycle performance, and proper maintenance of the condenser and cooling system will be of great benefit for the efficient operation of the plant. Condenser performance degradation can be caused by any of below (or combination thereof), all of which will impact on the condenser operating pressure and, thus, the plant performance:

• water-side fouling • leakages • vacuum equipment deterioration.

Simulations in SteamMaster of water side cleanliness factor for a turbine with the condenser designed for 0.048 bar operating pressure and 10°C temperature rise and design 0.9 fouling factor show following relative heat rate as a function of cleanliness factor:

Similarly, based on the same condenser design, condenser pressure increase due to leakages / vacuum equipment degradation, the impact of condensing pressure increase on heat rate is shown in attached graph. Cooling water pump efficiency degradation data indicates that a degradation of 10% increases net heat rate by less than 0.05%.

Condenser fouling

100.0%100.2%100.4%100.6%100.8%101.0%101.2%101.4%101.6%101.8%

60% 65% 70% 75% 80% 85% 90%Cleanliness factor

Rel

ativ

e H

eat R

ate



B.6 Boilers A brief qualitative analysis of the other parts of the plant outlines the key degradation issues, separated into PF fired boilers for steam power plants and HRSGs for combined cycles. B.6.1 Boiler (PF fired, for Steam power plant) An article titled “How stealth combustion losses lower plant efficiency” (Power Magazine, March 2005) gives a detailed outline of performance degradation causes in a coal-fired power plant. The article in particular describes the degradation caused by air leakages at various parts of the boiler, and also gives typical values for potential heat rate improvements for various types of plant maintenance. The article can be obtained from www.platts.com. Potential areas that can cause boiler degradation are discussed in short below (see above referenced article for more in-depth information). B.6.1.1 Heat transfer surfaces General experience indicates that there is an initial degradation from new as a result of the heat transfer surfaces fouling compared with the new and clean condition. However, as the surface areas have been calculated based on a fouling level defined by the characteristics of the design fuel, with due consideration of the performance of soot blowing, this normally means that the boiler will actually over-perform during the initial operation. Additionally, water washing of the heat transfer surfaces during regular shutdowns also assists in returning performance to close to original condition. Modeling in SteamMaster shows that a 50% increase in nominal furnace water wall fouling (from 1” - 1.5”) will reduce steam production at constant fuel flow by some 4%, resulting in approx 0.8 - 0.9% total output reduction. Similar modeling of economiser fouling indicates that a doubling of the fouling will have less than 0.2% impact on total steam flow. B.6.1.2 Combustion Degradation can occur through burner wear and / or problems with combustion air supply / distribution (e.g. leakages etc), which may impact on excess air levels, flame control etc., all of which can affect combustion efficiency. Overall, rectification of these issues can be deemed reasonably straightforward, primarily achieved through replacements of seals, air flow control devices, and burner nozzles. Please refer to above referenced article for more details. B.6.1.3 Air preheater A major area of boiler degradation is through increased leakages in rotary air preheaters, impacting on excess air levels, combustion air temperature control etc., with potential large efficiency loss As with the combustion equipment, rectification is relatively straightforward. SteamMaster modeling indicates that a doubling of the leakages will have following plant heat rate impact:



Air path cold / hot end leakages: ~ 0.2% each Primary air cold/hot end leakage ~ 0.05% each

Please refer to above referenced article for more details. B.6.1.4 Auxiliary losses SteamMaster simulations on the impact of boiler air fan and feed pump efficiency losses indicate relatively low heat rate degradation. For a 10% reduction in isentropic efficiencies, following results were achieved:

Boiler FD + ID fan: Heat rate increase: 0.16% Feed water pump: Heat rate increase: 0.11%.

In other words, boiler auxiliary power consumer degradation has relatively minor impact compared with other boiler efficiency losses. B.6.2 Heat Recovery Steam Generators Overall, HRSGs for gas fired combined cycles (relevant for Australia) do not seem to have any major areas of performance degradation, as they operate with clean, ash-free exhaust gases. B.7 Cycling Operation B.7.1 Gas turbines Gas turbine maintenance is generally scheduled on a calculated Equivalent Operating Hour basis (or other modeling taking cycling and thermal fatigue parameters into consideration) which takes onto account factors such as normal running/fired hours, peak load operation, start-stop cycles, trips, fuel quality impact and steam/water injection impact. Overall, the GT maintenance is aimed at ensuring the mechanical integrity of the unit, in particular the hot section components (combustor, turbine stator vanes and turbine blades), which are subject to a combination of cycle fatigue and creep life due to operation at high temperatures in combination with high centrifugal forces and bending moments. Efficiency improvements achieved through refurbishment / replacement of the hot section components can largely be regarded as a beneficial side effect of these component replacements. Cyclic operation will normally be considered in the EOH calculations to ensure maintenance is performed to maintain the unit’s mechanical integrity. If the unit is not operated strictly according to the manufacturer’s recommendations in terms of start-up times, ramping rates etc., cycling potentially also cause accelerated performance degradation through e.g. increased sealing wear due to recurring rubbing caused differential thermal expansions between stator and rotor. It should be noted that a detailed Internet information search for cyclic degradation of turbines did not generate any relevant references to performance degradation - the main concern of cycling of combustion turbines refer to the impact on material/component integrity.



B.7.2 Steam turbines As for gas turbines, the key issue of cycling of steam turbine relates to the impact on the service life of the equipment- particularly the risk of cracks developing in the rotor or blading due to thermal stresses, although start-up times and load changes outside of the manufacturer’s recommendations can potentially lead to damage to inter-stage labyrinth seals and, thus, increased leakage losses due to excessive differential expansion between rotor and stator. Overall operation within the manufacturer’s recommendations for start-up times and load transients/ramping rates should not have a noticeable additional performance impact. B.7.3 Boilers As with gas and steam turbine, cycling of boilers impact far more on the mechanical integrity of the boiler than on the performance. Cycling will primarily increase fatigue failures, causing damages such as failures of tubes, tube-to-header joints etc due to frequent and large temperature changes. Operational issues such as feed water control can also adversely impact the HRSG, in particular corrosion due to excess oxygen in the feed water etc. Vogt Power International (Babcock Power Inc. Group) has presented a paper: “Design and Modification of Heat Recovery Steam Generators For Cycling Operations” which gives detailed information on the mechanisms that impact on HRSG life and cycling’s impact on these mechanisms. It is available from http://www.babcockpower.com. Similar impacts as those described in above paper can be expected for fired boilers. As indicated earlier, information search has not identified any specific reference to performance degradation from cycling. Of course, steam or feed water leakages as a result of tube or header damage will cause performance degradation, however, as such damages would normally require immediate shutdown for repair, and would thus not impact long-term thermal performance. In case mechanical damage leads to e.g. air / flue gas leakages through e.g. air pre-heaters in the case of fired boilers or casing/ducting leakages in HRSGs performance degradation will occur as a result of leakage losses and possibly sub-optimal combustion in the case of fired boilers. B.8 Literature References GE-3567h - GE Gas Turbines Performance Characteristics GER-3419A - Gas Turbine Inlet Air Treatment GER-3750c - Steam Turbine Sustained Efficiency “Theory for Turbomachinery Degradation and Monitoring Tools” - Magnus Genrup (Licentiate Thesis June 2003, Department of Heat and Power Engineering, Lund Institute of Technology, Sweden) “Design and Modification of Heat Recovery Steam Generators for Cyclic Operation” - Vogt Power International technical paper “No Deposits, Big Returns”, Power Magazine April 2005 “How Stealth Combustion Losses Lower Plant Efficiency”, Power Magazine March 2005.



APPENDIX C GAS METER CATEGORIES AND MEASUREMENT RECOMMENDATIONS

Table C.1 - Gas meter categories and measurement recommendations.

Category Maximum Daily Quantity GJ/day

Metering Standards

Transmitter Requirements & Accuracy (% of Range)

Gas Quality, Qgr,p, and Specific Gravity Measurement Method

Remarks

1 0 – 1,750 Agreed method based on Standards referenced in Sect. 5.1.2/5.1.3

Pressure < ±0.25% Diff. Pressure < ±0.25% Temperature < ±0.50%

Reviewed monthly based on monthly flow weighted average measured at representative metering facility. Qgr declared by Chief Gas Examiner as per Sect. 5.1.2/5.1.3

• 6 monthly validation by an approved person.

• Orifice plate inspections 6 monthly. • Turbine meter spin test to be carried

out every 12 months. • Turbine and PD meters certified 12

monthly by independent testing authority or by Master Meter. The period between checks may be increased up to a maximum period of 3 years, subject to satisfactory test history and check procedures.

• Master meter where used, certified every 5 years.

2 1,750 – 3,500 Satisfies all

Standards referenced in Sect. 5.1.2/5.1.3

Pressure < ±0.25% Diff. Pressure < ±0.25% Temperature < ±0.50%

Reviewed monthly based on monthly flow weighted average measured at representative metering facility. Qgr declared by Chief Gas Examiner as per Sect. 5.1.2/5.1.3

• Monthly validation (includes orifice plate inspections) by an approved person. The validation period may be extended to a maximum of 6 months subject to satisfactory test history and check procedures.

• Turbine meters spin test to be carried out every 12 months.

• Orifice meter inspected, cleaned and certified every 2 years.

• Turbine and PD meters certified by an independent testing authority or Master Meter every 12 months.

• Master meter certified every 2 years.



Table C.1 - Gas meter categories and measurement recommendations.

Category Maximum Daily Quantity GJ/day

Metering Standards

Transmitter Requirements & Accuracy (% of Range)

Gas Quality, Qgr,p, and Specific Gravity Measurement Method

Remarks

3 3,500 – 17,500 Satisfies all Standards referenced in Sect. 5.1.2/5.1.3

Smart Transmitters: Pressure < ±0.10% Diff. Pressure < ±0.10% Temperature < ±0.25%

On-line instantaneous measurement preferred.

• Monthly validation (includes orifice plate inspections) by an approved person. The validation period may be extended to a maximum of 3 months subject to satisfactory test history and check procedures.



• Turbine and PD meters certified by an independent testing authority or Master Meter every 6 months. The period may be extended to 12 months subject to satisfactory test history and check procedures.

• Master meter certified annually.

4 > 17,500 Satisfies all Standards referenced in Sect. 5.1.2/5.1.3

Smart Transmitters: Pressure < ±0.10% Diff. Pressure < ±0.10% Temperature < ±0.25%

On-line instantaneous measurement preferred.

• Monthly validation (includes orifice plate inspections) by an approved person.



• Turbine meters certified by an independent testing authority or Master Meter every 6 months.

• Master meter certified annually.



APPENDIX D INDICATIVE OPTIONS FOR REDUCING GREENHOUSE GAS EMISSIONS FROM EXISTING PLANTS D.1 Range Of Options A range of options for increasing plant efficiency and, thus, reducing CO2 emissions is available. These can be categorised into three classes of action:

• Restore the Plant to Design Condition • Change Operational Settings • Retrofit Improvements.

Tables D.1 and D.2 list options for CO2 reduction, and provides a brief description of each action with an indication of the reduction in Greenhouse Intensity that could be achieved. This list is not intended to be exhaustive - there may be other alternatives. Not all the options listed can be applied to all plants and some of these options are mutually exclusive.



Table D.1 – Options for greenhouse gas reduction: boiler, steam turbine and heat recovery steam

generator plant.

Action Description Potential Efficiency Improvement, % HHV

Restore the Plant to Design Condition Operate boiler at the design O2 in flue gas

Any O2 in the flue gas represents an excess of air above that needed for combustion and is a loss of energy because that excess air leaves the boiler at a higher temperature than it entered. Reduced excess air will bring an immediate increase in boiler efficiency.

Up to 0.6

Restore and maintain air-heaters

The air-heater plays an important part in recovering energy from the combustion products. If the air-heater is allowed to operate with ash deposits or with damaged or missing surface (in the case of rotary air-heaters), boiler efficiency will be reduced.

Up to 0.3

Minimise boiler tramp air

Boiler tramp air does not pass through the air-heater, which means that the reduced air flow through the air-heater will not cool the flue gas as much as intended resulting in lower efficiency. It also forces operation with higher than necessary excess air.

Up to 1.0

Reinstate any feed-heaters out of service

Feed-heaters improve steam cycle efficiency by using low-grade heat from low-pressure steam from the turbine to heat the boiler feed water. Feed-heaters are sometimes taken out of service permanently to overcome water leakage problems. This can lead to an increase in power output, but at reduced fuel efficiency. The effect on efficiency is different depending on the plant design.

Up to 2.0

Reduce turbine gland leakage

The main gland leakage point is between the high pressure cylinder and the intermediate pressure cylinder. Any leakage of steam at this point allows it to bypass the high pressure turbine without any useful work being done by it.

Up to 0.2

Change Operational Settings Low excess air operation

Low excess air operation reduces the quantity of combustion gases and, hence, the heat loss from the dry flue gases leaving the boiler. The excess air level is a trade-off between unburnt fuel loss at low excess air and flue gas heat loss at high excess air. The level can often be reduced, particularly if the combustion system is properly tuned and controlled.

Up to 1.2

Improved combustion control

Improved combustion control enables the boiler to operate with lower excess air without the risk of combustion instability or excessive unburnt fuel. It involves both burner tuning better control system performance to keep the plant in a safe condition with low excess air.

Up to 0.5



Table D.1 – Options for greenhouse gas reduction: boiler, steam turbine and heat recovery steam generator plant.

Action Description Potential

Efficiency Improvement, % HHV

Increased condenser cleaning

Condenser fouling causes the turbine back pressure to increase. More frequent cleaning can keep this increase to a minimum, allowing higher efficiency. The cleaning can either be on-line or off-line. The rate of condenser fouling depends on many factors. The improvement that is possible is plant specific.

Up to 0.5

Increased boiler cleaning

Boiler ash deposits reduce heat transfer rates and ultimately lead to higher flue gas temperatures. The boiler can be kept cleaner, either through off-load cleaning or through the use of better on-load cleaning systems such as soot blowers, water blowers and water cannons.

Up to 1.0

Retrofit Improvements Add extra heat transfer surface in the boiler, e.g. economiser or air-heater

Extra heat transfer surface in the boiler will enable additional heat to be extracted from the flue gas leading to lower flue gas temperatures. In some cases, the boilers already have space allowance for extra air-heater surface. There is an increased risk of low temperature corrosion.

Up to 0.8

Install additional sootblowers

Additional sootblowers will help keep the boiler surfaces cleaner and, thus, increase the effective surface area. This will bring a slight reduction in flue gas temperature.

Up to 0.4

Install dry furnace ash extraction system

Replace existing wet furnace ash extraction system with a dry system to reduce heat losses due to sensible heat in furnace ash, and radiation to ash hopper and save auxiliary power.

Up to 0.7

Install new high efficiency turbine blades

Modern turbine blades have 3-dimensional variation in shape and are more efficient than the original blades. It is possible to install new blades in the last rows or replace all blades and install new rotors.

Up to 1.0

Change to steam driven feed pumps

Steam driven feed pumps can reduce the auxiliary power requirements of the plant by using lower grade energy for feed pumping.

Install variable speed drives on major plant items

Variable speed drives allow the auxiliary power consumption to be reduced as the plant load is reduced, and thus the benefits plants that have long periods of operation at reduced load.

Up to 0.4

Install on-line condenser cleaning system

Improved condenser cleaning can improve efficiency by allowing lower turbine exhaust temperatures. On-line cleaning will allow the condenser to be kept at a high level of cleanliness.

Up to 0.5



Table D.1 – Options for greenhouse gas reduction: boiler, steam turbine and heat recovery steam generator plant.



Install new cooling tower film pack

In plants that use cooling towers, installing new film-type packs can reduce the cooling water temperature to the condensers. Some cooling towers only have spray systems, which are less effective.

Up to 1.0



Table D.2 – Options for greenhouse gas reduction: open-cycle gas turbine plant.



Restore the Plant to Design Condition Replace/clean fouled air filters

Fouled air filters increase the pressure drop across the air inlet to the gas turbine compressor.

Up to 0.4%

Change Operational Settings Increase frequency of compressor cleaning

Compressor washing restores compressor efficiency. Up to 0.5% per wash

Check control system settings

Check IGV angles, instrument calibration and hardware for correct operation.

Up to 0.5%

Retrofit Improvements Consider inlet air conditioning

Options are evaporative cooler, mist/fog system. Up to 0.5%

Upgrade components to increase firing temperature

Increased firing temperature increases efficiency. Application specific

Review air inlet and GT exhaust arrangements

Revised inlet and exhaust duct arrangements may reduce pressure drop.

Up to 0.3%



APPENDIX E COSTING OF OPTIONS The $ cost/t CO2 equivalent avoided is broadly calculated as follows:

savedCOTonnesactionsgreenhousengimplementiofCostNetavoidedtCOCost

22

$/ = Eqn (E.1)

where the $ savings are usually in the form of fuel savings. For example, if a particular action is identified which will cost $100,000 per annum (annualised capital cost plus any additional non-fuel operating and maintenance cost, less annual fuel saving) but with savings of 20,000 t CO2 per annum, then the $ Cost/t CO2 avoided is $5/t. The Australian Greenhouse Office (AGO) developed a tool, the GES Abatement Calculator, to help GES Measure participants and other generators carry out cost analyses in a consistent way. GES participants are encouraged to use the GES Abatement Calculator for financial assessments of proposed abatement actions. The costing calculator includes the following tools:

• Spreadsheet-based model that calculates the cost of abatement in $/tonne CO2-e terms (see note below)

• User Guide. These publications are available from http://www.greenhouse.gov.au/ges/publications/index.html The steps necessary to calculate the $/tonne cost of abatement (whether negative or positive) are explained within the calculator itself. The Model calculates the $/tonne cost of GHG abatement by evaluating the costs and benefits of carrying out an action to reduce GHG emissions. The cost/benefit analysis is carried out using a standard Net Present Value (NPV) project analysis. An improvement project would be considered viable if the NPV of the project was zero (at the selected discount rate) if all relevant factors affecting the financial analysis were taken into account. The costs and revenues are escalated at some percentage of the consumer price index (CPI) and the net cash flows over the years discounted back to “today’s” $ to reflect the “time value of money”. A negative NPV would indicate a project that did not meet the criteria set, caused by insufficient revenue to offset the capital cost and changes in operating costs. The cost of GHG abatement is defined as the Net Present Value below zero. A positive NPV would indicate a project that was viable purely on financial grounds without assigning any value to the GHG savings that will occur as a direct result of the project. The Model uses equations from the GES Technical Guidelines to calculate the Greenhouse Intensity in kg/MWh for the plant before the modification or action (called “business as usual”) and after the action (called “after modification”). The Model is arranged in two sections each comprising two worksheets for: • Coal fired plant (which can be expanded to cater for other fuels). This uses the

methodology in the GES Technical Guidelines Section 7.2 Eqn. (11)



• Gas fired plant - This uses Table 5.1 to evaluate the emission factor for the gas being used and then the formula on page 51 of the Technical Guidelines to calculate the Greenhouse Intensity.

Provision has been made to include the affects of tax and depreciation. Generally, to provide a “level playing field” for the assessments these would be set to zero. These have been included for special cases where there is something unusual about the circumstances of the modification i.e. it attracts a special tax break or increased depreciation. The use of values other than zero would need to be justified. A discount rate of 12% was considered appropriate if the evaluation is being made without considering tax and depreciation. 12% was considered a reasonable Weighted Average Cost of Capital in the electricity industry. A default duration of 10 years of operation with the modification in place is used, but may be amended by users. Generally, a 10 year period is considered a reasonable period for the benefits to be realised. After 10 years operation, the plant may need to be refurbished (above normal maintenance) and the performance gain may decrease considerably. The main inputs that can be varied on the financial modelling worksheet are:

• Unit capacity - Many modifications that improve the efficiency of plant also increase (but not always) the maximum capacity. For some plant this increases the revenue earning potential of the plant

• Auxiliary Load - some modifications change the auxiliary load required for the plant

either increasing or decreasing the amount of electricity available for sale • Capacity Factor (and Reliability) - some modifications change these either

increasing or decreasing the amount of electricity available for sale • Efficiency (expressed as heat rate) - the user can nominate the change in heat rate

on a yearly basis as the affect of the modification may vary over time • Fuel Price - for example as a result of changing fuel source or preparation • Capital Cost of the modification • Changes in operating cost - personnel, materials and contracts.

The greenhouse gas savings are calculated by multiplying the change in Greenhouse Intensity by the “after” electricity output, expressed in MWh. The “value” of the GHG abatement over the calculation period is calculated by:

• Escalating the Dollar/Tonne cost of GHG abatement, using the cumulative CPI at present. There may be reasons why this would change, e.g. carbon trading values

• Converting these value to “real” $ values (i.e. discounting by the cumulative CPI)

• Obtaining “real” $ per year values by multiplying by the amount of GHG abated (in tonnes) for the year

• Discounting these $ values by the discount rate to obtain an NPV for the “value” of GHG abatement



• A solution is found for the $/tonne of abatement where the sum of the NPV’s from the financial analysis and the abatement analysis are zero. This is the cost of the GHG abatement.

The spreadsheets give worked examples of a modification of both a coal and a gas fired plant.


Australian Greenhouse Office, Department of the Environment and Heritage, December 2006 80

APPENDIX F NEW PLANT STANDARDS F.1 Types of Power Generation Cycles An overview of the application of a range of various fossil fuels in power generation technologies is given in Table F.1 below. A general description of the technologies is readily obtained from the literature (see References Section F.3) and is, therefore, not replicated in this guideline. Table F.1 – Fossil fuel/power generation technology applications

Fossil Fuels Combustion Turbine

Air Turbine Boiler

Retort/ Air

Turbine AFBC PFBC IGCC

OCGT CCGT OCGT SubC SC/USC OCGT SubC

Natural Gas X X X Coal Seam Gas/Coal Bed Methane

X X X

Black coal X X X X X Brown coal X X X X X Coal washery rejects

X X

Coke oven off-gas X X Coal mine methane X X X

Heavy fuel oil X X Diesel X X X X Distillate X X X Petroleum Coke X X X X Fuel oil residues X Shale oil X X Notes:

a. Abbreviations – OCGT – Open cycle gas turbine; CCGT – Combined cycle gas turbine; SubC – Sub-critical; SC – super-critical; USC – ultra super-critical; Atmospheric fluidised bed combustor; PFBC – pressurised fluidised bed combustor; IGCC – Integrated gasification combined cycle

b. X – indicates possible fossil fuel/technology applications. c. Shaded cells indicate fossil fuel/technology options specifically covered in the present guide,

which represent the most common applications for electricity generation. d. No distinction is drawn in the present guide between Natural Gas and Coal Seam Gas/Coal

Bed Methane. F.2 Performance of Electric Power Generation Systems F.2.1 Background The AGO recognises that new plant standards for a given class of plant should reflect Best Available Technology (BAT) under a range of Australian conditions. Indicative values of power plant efficiency and Greenhouse Intensity have been determined (CCSD, May 2005) using a recognised power industry software package, GateCycle© from GE Enter Software, for the following technology/fuel types:



(i) Super-critical PF plant under wet and dry cooling conditions (SCW, SCD) for black and brown (lignite) Australian coals

(ii) Ultra-super-critical PF plant under wet and dry cooling conditions (USCW, USCD) for black and brown (lignite) Australian coals

(iii) Open and combined cycle gas turbines using natural gas/coal seam gas, and distillate fuels.

In addition, a basic set of ambient corrections or dry bulb temperature, wet bulb temperature (or relative humidity) and ambient pressure for each of the technology options has been established. The modeling work was validated and tested using the following procedures:

(i) Comparison of predicted performance from the GateCycle© model against actual performance of state-of-the-art coal fired plant (super-critical) and gas turbine combined cycle power plant recently installed and operating under Australian conditions

(ii) Comparison of model outputs for the PF super-critical and ultra-super-critical cases against outputs from other proprietary models such as Steam Master and SteamPro

(iii) Comparison of performance differences against literature data. F.2.2 Reference conditions The power plant efficiency and greenhouse intensity standard values presented in these Guidelines have been based on the reference coal, natural gas/coal seam gas and fuel oil specifications summarised in Tables F.2 – F.4 below. The fuel types assessed were as follows:

• Black Coal: BLC1 - Medium ash, high volatile domestic coal (e.g., Surat basin coal) • Black Coal: BLC2 - Medium ash, low - medium volatile domestic coal (e.g., Hunter

Valley coal) • Black Coal: BLC3 - Medium ash, very high volatile domestic coal (e.g., Collie coal) • Brown Coal: BRC1 - Low ash, high moisture brown coal/lignite (e.g., Latrobe Valley

brown coal) • Natural gas - NG • Coal seam gas - CSG (or Coal Bed Methane, CBM) • Distillate – D.



Table F.2 - Reference coals Black coal

1 Black coal

2 Black coal

3 Brown coal

1 Proximate Analysis Total moisture (%, ar) 12.4 7.5 25.0 61.5 Ash (%, ar) 25.4 21.2 8.0 0.8 Volatile matter (%, ar) 33.3 29.2 27.6 19.5 Fixed carbon (%, ar) 28.7 42.1 39.4 18.2 Gross calorific value (MJ/kg, ar - HHV) 20.14 24.4 19.20 10.2 Ultimate analysis Carbon (%, daf) 76.5 84.3 75.1 69.8 Hydrogen (%, daf) 6.45 5.3 4.36 4.90 Nitrogen (%, daf) 0.95 1.8 1.39 0.60 Sulphur (%, daf) 0.53 0.6 0.55 0.40 Oxygen (%, daf) 15.57 7.9 18.6 24.3 Unburnt carbon in furnace ash (%) 5.0 5.0 3.0 18.0 Unburnt carbon in fly ash (%) 1.7 2.0 1.0 18.0 Proportion of ash emitted as fly ash (%) 90 90 90 90 Abbreviations: ar - as-received; daf - dry, ash-free Table F.3 – Reference natural gas/coal seam gas Base pressure (bar, absolute) 1.01325 Base temperature (°C) 15 SG of mixture 0.6185 Gross calorific value (MJ/Sm3, HHV) 38.91 Net calorific value (MJ/Sm3, HHV) 35.11 Density (kg/Sm3) 0.7579 Wobbe Index (MJ/Sm3, HHV) 49.48 Composition (mole %) Methane 90.91 Ethane 4.50 Propane 1.04 n-Butane 0.21 i-Butane 0.13 Helium 0.04 Nitrogen 1.11 Carbon Dioxide 2.06 Table F.4 – Reference distillate Moisture (%) 0 Ash (%) 0 Gross calorific value (MJ/kg, HHV) 45.74 Composition (mass %) Carbon 86.67 Hydrogen 13.23 Nitrogen 0.09 Sulfur 0.01 In addition, the following ambient conditions apply. Table F.5 – Reference ambient conditions

Ambient Conditions Parameter Base 1 2 3 4 5 6

Dry bulb temperature (°C) 25.00 10.00 35.00 25.00 25.00 25.00 25.00 Wet bulb temperature (°C) 19.45 6.46 28.16 19.35 19.40 14.37 22.37 Relative humidity (%) 60 60 60 60 60 30 80 Pressure (bar, a) 1 1 1 0.945 0.975 1 1 Equivalent altitude (m) 111 111 111 584 323 111 111



A range of steam conditions were selected for the PF power plant assessments to cover a range of super-critical and “ultra-super-critical” steam conditions. The steam conditions applied to the combined cycle gas turbine application were based on a large state-of-the-art plant already installed in Australia. The steam turbine conditions are given in Table F.6. Table F.6 – Steam turbine conditions

PF plants Wet cooling

Black coal Brown coal

Case 1 Case 2 Case 3 Case 4 Case 5

Dry cooling

Gas turbine combined

cycle plants

Main steam inlet Pressure (MPa) 27.5 28.5 30.0 25.0 26.5 27.5 11.3 Temperature (°C) 605 600 630 566 576 605 565 Reheat steam inlet Pressure (MPa) 5.7 6.1 6.1 4.4 5.7 5.7 2.7 Temperature (°C) 613 620 630 565 600 613 565 Condenser pressure (kPa) - based on 90% cleanliness factor

6 6 6 6 6 12 6

In all cases, the main boiler feed water pump is steam driven and a mechanical draft cooling tower is used. The turbine generator efficiency was assumed to be 99.1% with a power factor of 0.9. The transformer loss of 0.3% was assumed. F.2.3 Simulation results F.2.3.1 Ultra super-critical PF plant with wet cooling with black coals The simulation model for this plant was based on an existing super-critical PF plant. In raising the steam conditions from super-critical to ultra super-critical (see Table F.7), it was assumed that the turbine stage efficiency of each pressure stage remained constant. This was a triple pressure, single reheat cycle with seven feed water pre-heaters, including a deaerator. The main feed water pump was steam driven. The condenser was wet cooled with the cooling water and operated at 6 kPa. The cooling tower was a mechanical-draft type. The boiler exhaust gas left the stack at 130°C. The simulations were performed with three different black coals and the results are shown in Table F.8. Table F.7 – Steam turbine conditions Super-critical Ultra super-critical* Main steam inlet Temperature (°C) 566 605 Pressure (MPa) 25.0 27.5 Reheat steam inlet Temperature (°C) 565 613 Pressure (MPa) 4.4 5.7 Condenser pressure (kPa) 6 6 Isentropic stage efficiency High pressure stage 0.902 0.902 Intermediate pressure stage 0.890 0.890 Low pressure stage 0.896 0.896 * Case 1 in Table 6



Table F.8 – Ultra super-critical PF plant with black coals & wet cooling system, coal variation results Coal Black coal 1 Black coal 2 Black coal 3 CO2 emission factor (kgCO2/GJ fuel) 85.4 90.1 96.1 Ambient and steam conditions Dry bulb temperature (°C) 25 25 25 Relative humidity (%) 60 60 60 Ambient air pressure (mbar absolute) 1,000 1,000 1,000 Main (superheat) steam @ turbine inlet Temperature (°C) 605 605 605 Pressure (MPa) 27.5 27.5 27.5 Reheat (single) steam @ turbine inlet Temperature (°C) 613 613 613 Pressure (MPa) 5.7 5.7 5.7 Final feedwater temperature (°C) 290 290 290 Unit performance Gross power (MWe) 446 446 446 Net power (MWe) 425 426 425 Sent-out power (MWe) 424 425 424 Boiler efficiency (%, HHV) 87.4 89.4 87.3 Turbine efficiency (%) 48.4 48.4 48.4 Sent-out thermal efficiency (%, HHV) 40.2 41.2 40.2 Power station CO2 emission (kg/MWh SO) 765 785 860 Power station SO2 emission (kg/MWh SO) 2.9 3.1 3.4 Water consumption (kg/MWh SO) 1,880 1,870 1,880 Coal feed rate (kg/hr) 188,300 151,900 197,600 F.2.3.2 Ultra super-critical PF plant with black coal and dry cooling system The simulation model in F.2.3.1 was modified by replacing the mechanical-draft water-cooled condenser with a mechanical-draft air-cooled condenser. The condenser operating pressure was increased from 6 kPa to 12 kPa. The simulations were performed with three different black coals and the results are shown in Table F.9.



Table F.9 – Ultra-super-critical PF plant with dry cooling, coal variation results Coal Black coal 1 Black coal 2 Black coal 3 CO2 emission factor (kgCO2/GJ fuel)

85.4 90.1 96.1

Ambient and steam conditions Dry bulb temperature (°C) 25 25 25 Relative humidity (%) 60 60 60 Ambient air pressure (mbar absolute)

1,000 1,000 1,000

Main (superheat) steam @ turbine inlet

Pressure (MPa) 27.5 27.5 27.5 Temperature (°C) 605 605 605 Reheat (single) steam @ turbine inlet

Pressure (MPa) 5.7 5.7 5.7 Temperature (°C) 613 613 613 Final feedwater temperature (°C)

290 290 290

Unit performance Gross power (MWe) 429 429 429 Net power (MWe) 409 410 408 Sent-out power (MWe) 407 408 408 Boiler efficiency (%, HHV) 87.4 89.4 87.3 Turbine efficiency (%) 46.6 46.6 46.6 Sent-out thermal efficiency (%, HHV)

38.7 39.7 38.7

Power station CO2 emission (kg/MWh SO)

795 820 895

Power station SO2 emission (kg/MWh SO)

3.0 3.2 3.6

Water consumption (kg/MWh SO)

0 0 0

Coal feed rate (kg/hr) 188,300 151,900 197,600 F.2.3.3 Ultra super-critical PF plant with wet cooling with black coal 1 The simulation model in F.2.3.1 was modified by changing the steam turbine inlet conditions (see Conditions 2 & 3 in Table F.6). Again, it was assumed that the turbine stage efficiency of each pressure stage remained constant for different steam conditions. The excess air fraction, stack gas temperature and boiler efficiency were also kept constant. The simulations were performed with black coal 1 only and the results are shown in Table F.10.



Table F.10 – Super-critical and ultra super-critical PF plant with black coal 1 and wet cooling system, steam condition variation results Case 1

SC Case 2 USC

Case 3 USC

Case 4 USC

CO2 emission factor (kgCO2/GJ fuel) 85.4 85.4 85.4 85.4 Ambient and steam conditions Dry bulb temperature (°C) 25 25 25 25 Relative humidity (%) 60 60 60 60 Ambient air pressure (mbar absolute) 1,000 1,000 1,000 1,000 Main (superheat) steam @ turbine inlet

Pressure (MPa) 25.0 27.5 28.5 30.0 Temperature (°C) 566 605 600 630 Reheat (single) steam @ turbine inlet Pressure (MPa) 4.4 5.7 6.1 6.1 Temperature (°C) 565 613 620 630 Final feedwater temperature (°C) 287 290 290 292 Unit performance Gross power (MWe) 421.3 446.3 446.9 460.7 Net power (MWe) 401.1 424.9 425.5 438.6 Sent-out power (MWe) 399.9 423.6 424.2 437.2 Boiler efficiency (%, HHV) 87.4 87.4 87.4 87.4 Turbine efficiency (%) 47.1 48.4 48.5 49.1 Sent-out thermal efficiency (%, HHV) 39.1 40.2 40.3 40.8 Power station CO2 emission (kg/MWh SO)

785 764 763 753


3.01 2.92 2.92 2.88

Water consumption (kg/MWh SO) 2000 1877 1871 1825 Coal feed rate (kg/hr) 182,800 188,300 188,200 191,600 F.2.3.4 Ultra super-critical PF plant with wet cooling with black coal 1 – ambient condition variations The simulations under varying ambient conditions were performed with black coal 1 only and the results are shown in Table F.11.



Table F.11 – Ultra super-critical PF plant with black coal 1 and wet cooling system – ambient condition variations results Ref. Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 CO2 emission factor (kgCO2/GJ fuel)

85.4 85.4 85.4 85.4 85.4 85.4 85.4

Ambient and steam conditions

Dry bulb temperature (°C)

25 10 35 25 25 25 25

Relative humidity (%) 60 60 60 60 60 30 80 Ambient air pressure (mbar absolute)

1,000 1,000 1,000 945 975 1,000 1,000


Pressure (MPa) 27.5 27.5 27.5 27.5 27.5 27.5 27.5 Temperature (°C) 605 605 605 605 605 605 605 Reheat (single) steam @ turbine inlet

Pressure (MPa) 5.70 5.70 5.70 5.70 5.70 5.70 5.70 Temperature (°C) 613 613 613 613 613 613 613 Final feedwater temperature (°C)

290 289 289 290 290 289 290

Unit performance Gross power (MWe) 446 446 434 446 446 446 446 Net power (MWe) 425 425 412 425 425 425 425 Sent-out power (MWe) 424 424 411 424 424 424 424 Boiler efficiency (%, HHV)

87.4 87.3 87.5 87.4 87.4 87.5 87.4

Turbine efficiency (%) 48.4 48.6 47.5 48.5 48.4 48.6 48.2 Sent-out thermal efficiency (%, HHV)

40.2 40.4 39.4 40.2 40.2 40.4 40.0


765 760 780 765 765 760 770


2.9 2.9 3.0 2.9 2.9 2.9 2.9


1,877 1,498 2,167 1,888 1,883 2,009 1,808

Coal feed rate (kg/hr) 188,300 187,500 186,500 188,100 188,300 187,500 189,300 F.2.3.5 Ultra super-critical PF plant with dry cooling with black coal 1 – ambient condition variations The simulations under varying ambient conditions were performed with black coal 1 only and the results are shown in Table F.12.



Table F.12 – Ultra super-critical PF plant with dry cooling with black coal 1 – ambient condition variations results Ref. Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 CO2 emission factor (kgCO2/GJ fuel)

85.4 85.4 85.4 85.4 85.4 85.4 85.4

Ambient and steam conditions Dry bulb temperature (°C) 25 10 35 25 25 25 25 Relative humidity (%) 60 60 60 60 60 30 80 Ambient air pressure (mbar absolute)

1,000 1,000 1,000 945 975 1,000 1,000


Pressure (MPa) 27.5 27.5 27.5 27.5 27.5 27.5 27.5 Temperature (°C) 605 605 605 605 605 605 605 Reheat (single) steam @ turbine inlet

Pressure (MPa) 5.70 5.70 5.70 5.70 5.70 5.70 5.70 Temperature (°C) 613 613 613 613 613 613 613 Condenser back-pressure (kPa)

12.2 5.57 19.4 12.4 12.3 12.3 12.2

Final feedwater temperature (°C)

290 287 289 290 290 290 290

Unit performance Gross power (MWe) 429 429 414 429 429 429 429 Net power (MWe) 409 409 394 409 409 409 409 Sent-out power (MWe) 407 408 392 407 408 407 407 Boiler efficiency (%, HHV) 87.4 87.3 87.5 87.4 87.4 87.5 87.4 Turbine efficiency (%) 46.6 47.9 45.3 46.6 46.6 46.5 46.6 Sent-out thermal efficiency (%, HHV)

38.67 39.8 37.55 38.66 38.66 38.60 38.66


795 770 820 795 795 796 795


3.04 2.95 3.13 3.04 3.04 3.05 3.04


0 0 0 0 0 0 0

Coal feed rate (kg/hr) 188,300 183,100 186,800 188,400 188,400 188,700 188,300 F.2.3.6 Super-critical and ultra super-critical PF plants with wet cooling with brown coal 1 The simulation model in F.2.3.1 was modified to be run with brown coal 1. The most significant changes made were the lower furnace exit gas temperature and higher stack gas temperature (160°C); and unburnt carbon in ash (18%). The operating conditions on the steam side were the same as in the black coal cases. Only the overall heat and mass balances around the boiler were performed and the coal drying stage was not modeled separately. The simulations were performed for two sets of steam conditions (see Conditions 4 & 5 in Table F.5). Again, it was assumed that the turbine stage efficiency of each pressure stage remained constant for different steam conditions. The results of the simulations are shown in Table F.13.



Table F.13 – Super-critical and ultra super-critical PF plants with brown coal 1 and wet cooling system Condition 4 Condition 5 CO2 emission factor (kgCO2/GJ fuel) 94.2 94.2 Ambient and steam conditions Dry bulb temperature (°C) 25 25 Relative humidity (%) 60 60 Ambient air pressure (mbar absolute) 1,000 1,000 Main (superheat) steam @ turbine inlet Pressure (MPa) 25.0 26.5 Temperature (°C) 566 576 Reheat (single) steam @ turbine inlet Pressure (MPa) 4.39 5.7 Temperature (°C) 565 600 Final feedwater temperature (°C) 287 288 Unit performance Gross power (MWe) 421 432 Net power (MWe) 394 405 Sent-out power (MWe) 393 404 Boiler efficiency (%, HHV) 72.0 72.0 Turbine efficiency (%) 47.1 47.8 Sent-out thermal efficiency (%, HHV) 31.8 32.3 Power station CO2 emission (kg/MWh SO) 1,065 1,050 Power station SO2 emission (kg/MWh SO) 3.36 3.31 Water consumption (kg/MWh SO) 2,013 1,957 Coal feed rate (kg/hr) 435,900 440,700 F.2.3.7 Open cycle gas turbine plants with natural gas and distillate fuels The data presented below is based on a large scale class F gas turbine representing state-of-the-art commercial technology with high pressure-ratio, staged combustion and proven blade cooling technology. The simulation model utilised the GateCycle© built-in gas turbine library for the performance data of this gas turbine modelled. Auxiliary power loss of 3.9 MWe was included in the overall plant efficiency calculation. The results of the simulations are shown in Table F.14.



Table F.14 – Open cycle gas turbine plants with natural gas and distillate results NG/CSG Distillate Ambient conditions Dry bulb temperature (°C) 25 25 Relative humidity (%) 60 60 Ambient air pressure (mbar absolute) 1,000 1,000 Unit performance CO2 emission factor (kgCO2/GJ fuel) 51.2 69.5 Gross Power (MWe) 269 258 Net power (MWe) 265 253 Sent-out power (MWe) 264 250 Sent-out thermal efficiency (%, HHV) 33.1 32.5 Power station CO2 emission (kg/MWh SO) 555 760 Power station SO2 emission (kg/MWh SO) 0 0.05 Fuel feed rate (kg/hr) 55,950 60,570 F.2.3.8 Combined cycle gas turbine plants with natural gas - ambient condition variations The simulation model for this plant was based on an existing natural gas combined cycle plant. As in F.2.3.7 the gas turbine chosen was Alstom GT26. The steam cycle was sub-critical, triple pressure single reheat cycle extracting all of its heat energy from the gas turbine exhaust via a heat recovery steam generator. The feed water pumps were electric driven. The operating pressure of the water-cooled condenser was 6 kPa. The cooling tower was a mechanical-draft type. The results of the simulations are shown in Table F.15. Table F.15 – Combined cycle gas turbine plant with natural gas/coal seam gas – ambient condition variations results Ref. Case

1 Case 2

Case 3

Case 4

Case 5

Case 6

Ambient conditions Dry bulb temperature (°C) 25 10 35 25 25 25 25 Relative humidity (%) 60 60 60 60 60 30 80 Ambient air pressure (mbar absolute) 1,000 1,000 1,000 945 975 1,000 1,000 Unit performance CO2 emission factor (kgCO2/GJ fuel) 51.2 51.2 51.2 51.2 51.2 51.2 51.2 Gross power (MWe) 406 424 388 386 396 404 407 Net power (MWe) 400 417 382 380 390 398 401 Sent-out power (MWe) 399 416 381 379 389 397 400 Sent-out thermal efficiency (%, HHV) 51.6 51.9 51.1 51.7 51.7 52.1 51.6 Power station CO2 emission (kg/MWh SO) 355 355 360 355 355 355 355 Power station SO2 emission (kg/MWh SO) 0 0 0 0 0 0 0 Water consumption (kg/MWh SO) 950 730 1120 985 965 1010 920 Natural gas feed rate (kg/hr) 54,290 56,360 52,370 51,500 52,910 53,600 54,430 F.2.3.9 Combined cycle gas turbine plant with distillate The simulation model in F.2.3.8 was modified to run with distillate in place of natural gas.



The results of the simulations are shown in Table 16. Table F.16 – Combined cycle gas turbine plant with distillate results Dry bulb temperature (°C) 25 Relative humidity (%) 60 Ambient air pressure (mbar absolute) 1000 Unit performance CO2 emission factor (kgCO2/GJ fuel) 69.5 Gross power (MWe) 411 Net power (MWe) 404 Sent-out power (MWe) 403 Sent-out thermal efficiency (%, HHV) 54.0 Power station CO2 emission (kg/MWh SO) 465 Power station SO2 emission (kg/MWh SO) 0.03 Distillate feed rate (kg/hr) 58,770 F.3 References CCSD – Technology Assessment Report 42: Technical Performance of Electric Power Generation Systems in Australian Conditions (Aug. 2004); E Ikeda, J Stubington, and C Spero. CCSD – New Plant Standards – Simulation of performance of electric power generation systems under Australian conditions (May 2005); E Ikeda, J Stubington, and C Spero. IEA Report CCC/74 – Clean Coal Technologies (October 2003); C Hendersen. IEA CCC/91 – Understanding coal-fired power plant cycles, October 2004, C Henderson. NRW, Concept Study – Reference Power Plant North Rhine-Westfalia, 2004. Power Clean Thematic Network – Fossil Fuel Power Generation State-of-the-art, July 2000.



APPENDIX G GES GREENHOUSE INTENSITY CALCULATOR The AGO advises that an electronic copy of the following GES Greenhouse Intensity Calculator is available from the GES website. Broadly, it calculates current performance GI and a best practice performance range for comparison. It requires the participant to input the following classes of data:

• performance test results • fuel properties • fuel consumption • electrical output.

Please note that the worksheet below has been truncated in order to fit on the following pages, by reducing the number of months of visible data from 12 to 6 months and by removing the performance test data input page.

technical guidelines - generator efficiency standards

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