gas turbine technology for syngas/hydrogen in coal-based igcc

Gas turbine technology forsyngas/hydrogen in coal-based IGCC

Irene M Smith

CCC/155

October 2009

Copyright © IEA Clean Coal Centre

ISBN 978-92-9029-475-7

Abstract

Gas turbines have been developed for burning natural gas and fuel changes to burn syngases affect operational performance andemissions. The composition of syngas varies widely and is mostly H2 and CO rather than the CH4 of natural gas. Carbon removalincreases the H2 content with its high flame speed, high flame temperature and wide flammability range. The compressor, fuelsystem and turbine (expander) need some modifications. Improvements are required in thermal barrier coatings and film coolingdesigns. The combustor is the part of the gas turbine which is most affected by burning synfuels/H2. Diffusion and pre-mixcombustors, hybrid designs, as well as catalytic combustors are being developed to burn high H2 synfuels at firing temperatures>1400°C. The aim is to develop fuel flexible, low NOx combustors over the next few years, with minimal need for diluent.Current commercial and demonstration IGCC plants using coal have gas turbine firing temperatures of up to 1300°C on syngas,with net plant efficiency of about 40->43%. Future IGCC plants will require CO2 reduction, probably with zero air integration toreduce operating complexity. Tradeoffs between efficiency, reliability, availability and maintainability (RAM) need to beoptimised and then validated on the next generation of demonstration plants, due to start this year.

AVC advanced vortex combustion CCS carbon capture and storage EGT European Gas Turbines GE General Electric GSP Gas Schwarze Pumpe (gasifier)HECA Hydrogen Energy California projectHEGSA high efficient gas turbine with syngas application (EU project)HHV higher heating value HRSG heat recovery steam generator HTW high temperature Winkler (gasifier)IGCC integrated gasification combined cycleLHV lower heating value MHI Mitsubishi Heavy Industries MNQC multi-nozzle quiet combustor NETL National Energy Technology Laboratory (US DOE)NOx nitrogen oxides (NO + NO2)RAM reliability, availability and maintainability RCL rich-catalytic, lean-burn combustion rpm revolutions per minuteRQL rich-burn, quick-mix, lean-burn SCR selective catalytic reduction

2 IEA CLEAN COAL CENTRE

Acronyms and abbreviations

Acronyms and abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Contents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2 Fuels and gas turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62.1 Fuel composition and properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62.2 Effects on gas turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

2.2.1 Compressor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102.2.2 Safety and fuel system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112.2.3 Combustor. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122.2.4 Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

2.3 Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

3 Diffusion combustors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173.1 Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173.2 Pollutant emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

3.2.1 Diluents for NOx reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203.2.2 Combustion measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

3.3 Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

4 Premixed combustors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 244.1 Tests with syngas/H2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 254.2 Developments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 254.3 Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

5 Catalytic combustors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295.1 Catalytic systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295.2 Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

6 Gas turbines for IGCC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 336.1 Experience with existing IGCC plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

6.1.1 Europe. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 336.1.2 USA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 356.1.3 Japan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

6.2 Future plants with CO2 reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 366.2.1 Implications for gas turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 376.2.2 IGCC projects with CCS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

6.3 Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

7 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

8 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

3Gas turbine technology for syngas/hydrogen in coal-based IGCC

Contents

IEA CLEAN COAL CENTRE4

Future developments in integrated gasification combinedcycle (IGCC) have recently been reviewed at the IEA CleanCoal Centre by Henderson (2008). One of the conclusions isthat more total experience of operating coal-fuelled IGCCsystems in a power utility environment is required. Theprospects for IGCC are improved by the attention now beinggiven to reducing CO2 emissions from power plants. This isbecause IGCC technology is considered to provide a goodbasis for CO2 capture and storage (CCS) and has a highcapability of biomass co-utilisation. Another benefit of IGCCis that it can form part of a polygeneration scheme.Polygeneration has been reviewed by Carpenter (2008).

Nevertheless IGCC projects often face an uncertain future dueto political issues. For example, in the USA, momentum waslost in 2007 due to rising capital costs and regulatoryuncertainty. Now the new government promises to fund cleancoal projects (Klein, 2008; Smith, 2009). Many natural gascombined cycle power plants have become uneconomic dueto the high price of natural gas. This offers opportunities forrefuelling natural gas combined cycle power plants to run onsyngas as the incremental cost would be less than building anew IGCC (Blankinship, 2006). According to Liu and others(2008), the huge requirement for new power generatingcapacity in China and its heavy reliance on coal, givesopportunities to exploit IGCC with its benefits of moreeconomic CO2 emissions reduction and polygenerationpotential.

Gas turbines have been developed for burning natural gas andare an essential part of the IGCC system. Fuel changes toburn syngases affect operational performance and emissions,especially nitrogen oxide (NOx). Gas turbine technologyrequires fuel flexibility with low emissions. Of particularimportance is the need to fire gas turbines on hydrogen (H2)when CO2 capture is applied to IGCC plants.

The four major suppliers of gas turbines offering machines forIGCC are GE, Siemens-Westinghouse, Alstom and MitsubishiHeavy Industries (MHI) (Henderson, 2008). Designdevelopment is affected by the frequent acquisitions that haveoccurred among gas turbine manufacturers. Totally differentdesign philosophies have merged as a result. An example isSiemens’ acquisition of Westinghouse. The latter had newmodels which had originated from MHI design methods,because of the technology cooperation they had previouslywith Westinghouse. Later Siemens acquired a subsidiary ofwhat was Alstom Power (formerly ABB) in Sweden. ABBdeveloped gas turbines independently in Sweden and thesewere not always a scaled version of ABB designs inSwitzerland, although they drew on specialised knowledgethat had been developed there. At one point, ABB Alstom hadacquired what was European Gas Turbines (EGT) whichformerly was Ruston, an English manufacturer. Joint venturesfrom component suppliers’ previous programmes tend to addto the technology pool at the disposal of an originalequipment manufacturer (Soares, 2006). The current leadingnames of gas turbines have differing codes to denote the class.


Siemens have recently altered their series of code names. Inthis report, all code names are cited from the original alongwith the new names in an attempt to reduce confusion.

This report aims to provide an update on the effects of firinggas turbines with syngas/H2, instead of natural gas. The mainissues in operation are reliability, availability, andmaintainability (RAM), discussed by Marini (2006). It isessential to achieve high RAM, high performance and lowemissions when burning syngases. This requires detailedknowledge of the characteristics of syngases and their effectson all parts of gas turbines (see Chapter 2). There are twobroad categories of gas turbine combustor – diffusion flameand premixed combustors. These are also being developed ashybrids, in order to meet the requirements for burningdiffering synfuels. Catalytic combustors are being tested.These are examined in Chapters 3-5 respectively. Gas turbinesusing coal-based syngas are operating in four commercialplants and one demonstration plant so the experience gainedfrom overcoming problems during their operation provide agood basis for developments to burn H2-rich syngas in futureplants (see Chapter 6). This includes the latest availableinformation on planned pilot and demonstration projects withpre-combustion CO2 reduction measures. It does not includepost-combustion CO2 control such as flue gas scrubbing oroxyfuel concepts.

A major report, written for the IEA Greenhouse Gas R&DProgramme (IEA GHG, 2000) on gas turbines for CO2

abatement, has formed a good basis from which to examinemore recent developments. The excellent gas turbinehandbook from the US DOE (NETL, 2006) provides in-depthknowledge on all aspects of the subject and has beenextensively cited in this report. It has been recognised fromthe outset that there would be limited data available in thepublic domain, due to commercial interests. This has meantthat information on recent developments in gas turbinetechnology has not been available. Many apparently recentpapers are actually based on experimental results from overfive years ago. These are often presentations with little text,giving aims rather than results. Gas turbine manufacturers andusers at utilities have generally not been able to cooperate byproviding either information or guidance for the preparationof this review, as is normally the case for other topicsreviewed at the IEA Clean Coal Centre. However, thecontribution from Marco Kanaar of Nuon, The Netherlands,in giving greater insight to practical experience of gasturbines, is gratefully acknowledged.

1 Introduction

The raw syngas from a gasifier requires cleaning before it canbe used in a gas turbine. This topic is not included here but it isuseful to differentiate between techniques in commercial useand those undergoing research and development. ExistingIGCC plants use cold gas scrubbing, usually followingcarbonyl sulphide hydrolysis, for acid gas removal from theraw gasifier product gas. This is often after a dry gasparticulate removal system operating at moderate temperaturesof around 300°C. Candle filters are in commercial use at theIGCC plants in Europe, operating at 230–280°C. Alternativelyscrubbing may be used for particulate control, and is also oftenneeded for ammonia removal as it is a NOx precursor. Multi-contaminant removal, to include mercury, is being developedin the USA. Research and development of hot gas clean-up attemperatures up to 450°C, to remove halogens, sulphur andammonia, continues in Japan (Carpenter, 2008; Henderson,2008). As gas turbine operating temperatures increase toimprove efficiencies, synfuels will need hot gas clean-up andgettering with a final polishing to remove the alkali contentbefore use in gas turbines (Schofield, 2005).

The composition and properties of cleaned syngas fuel arediscussed in Section 2.1 and their effects on gas turbines inSection 2.2.

2.1 Fuel composition andproperties

The main fuel used for gas turbines in power generation is


natural gas but, for the reasons mentioned in Chapter 1, thereis an incentive to use syngas, the product of coal, petroleumcoke or biomass gasification. The composition of these fuelsvaries considerably, depending on the type of fuel and thegasification process used (Laster and others, 2006). Someexamples of the composition of natural gases and syngasesare summarised in Table 1. Pipeline natural gas containsmainly methane (CH4). Weak natural gas – often from coal-seams – may contain as little as 30 vol% CH4 and itsexploitation as pipeline gas is rarely economic. However, itmay be burnt in gas turbines (Molière, 2005).

The composition of syngases from coal shown in Table 1varies considerably in combustible components, mainly H2

and carbon monoxide (CO) with small amounts of CH4. Nodetails were given as to whether the gasifiers were quench orradiant. However, the air blown gasifier appears to producethe syngas with the lowest H2 content. Out of the oxygen(O2)-blown gasifier products, syngases from the slurry fedgasifiers result in higher H2 contents of 24–35 vol%. The dryfed gasifiers also have H2 contents in this range. The COcontent of the synfuels from slurry fed gasifiers (35–50 vol%)is less than that from the dry fed gasifiers (63, 64 vol%). Thecalorific values of the fuels from coal varied considerablyover 4–11 MJ/m3 based on lower heating value (LHV).However, as McDonell (2006) points out, the variation ismuch less if a given feedstock and gasification process isconsidered.

Syngases from coal, biomass, heavy residue, and orimulsion

2 Fuels and gas turbines

Table 1 Composition of natural gas and syngas from coal

Fuel, vol% Natural gas,pipeline1

Natural gas,weak1

Syngas, coal2

Syngas,coal2

Syngas,coal4

Syngas,coal4

Syngas,coal2

Gasifier Air blown Shell, dry Dry feed, N2 Slurry Texaco (GE), slurry

CH4 85–97 30–85 3 0 – – 0.2

H2 0 0 23 31.3 28 35 34

CO 0 0 7 62.7 64 50 49

CO2 0 – 20 1.5 3 14 9.7

N2 0–1 <70 47 4.5 5 1 6.1

Total S

Ar

H2O <0.01 – dry dry dry

CO/H2 0 0 0.3 2.0 2.3 1.4 1.4

LHV, MJ/m3 32–38 10–20 4.2 10.7 10.2 9.2 9.4

* H2S1 Molière, 20052 Drnevich and others, 20043 Anand and others, 20064 Williams and others, 20065 James and others, 2006

are compared by Hasegawa and others (2005) from workpublished in 1999 for air and O2 blown gasification systems(see Table 2). Considering the O2 blown products, the H2

contents of syngas from heavy residue and orimulsion weregreater than those from coal. The biomass synfuels had theleast H2. The CO content of the coal synfuels was greater thanthose from heavy residue and orimulsion, with the biomasssynfuels containing the least. Fuel calorific values variedwidely over 4–13 MJ/m3 based on the higher heating value(HHV), from about one tenth to one third of that of naturalgas, depending on the raw material, the gasification agent andthe type of gasifier. For example, a gasified fuel derived frombiomass contained 30–40% steam. Data for petcoke fromanother source (Laster and others, 2006) are included inTable 2. The calorific value of this synfuel of 12.1 MJ/m3

(325 Btu/standard cubic foot) cannot be directly comparedwith the data based on HHV but is significantly greater thanthose from coal shown in Table 1.

The H2 syngases in Table 1 have undergone carbon removalby means of the shift reaction which is discussed inSection 6.2. This converts CO and steam in the raw syngas toH2 and CO2 which is removed by a solvent for storage. TheH2 content of the fuel gas increased to 68% from 31% in theGE gasifier outlet and to 73% from 24% in the CoP gasifieroutlet. For the same moisture content in the syngas, the GEgasification process produced lower shift conversion. Thiswas due to a lower amount of inlet CO and higher percentageof CO2 and H2 in the pre-shifted syngas (Anand and others,2006). The composition of syngases investigated by Williamsand others (2006) varied from 1% to 96% H2 with 76% to 1%CO respectively. However, pre-combustion de-carbonisationof syngas from coals will result in gas turbine fuels thatconsist of 90% or higher H2 content (Jones and others, 2007).

7

Fuels and gas turbines

Gas turbine technology for syngas/hydrogen in coal-based IGCC

An example of syngas compositions (vol% at 25 bar, 2.5 MPa)from a lignite IGCC, using the O2-blown high temperatureWinkler (HTW) gasifier with no CO2 capture (A) and with 85%carbon recovery (B), is presented by Buschsieweke (2008):

A BH2 32 80CO 37 0.8CO2 17 0.1N2 6.5 10CH4 6 6.5

The sulphur content of the synfuel has a potential effect onoperation and maintenance of the IGCC plant. Theconcentration of sulphur entering the gas turbine can be in theorder of 30–40 ppmv (similar to the values in Table 1 of0.003 vol%) for IGCC without selective catalytic reduction(SCR) for NOx control. For IGCC with SCR, the maximumsyngas sulphur content entering the gas turbine should be inthe order of 5–12 ppmv. This compares to 4.2 ppmv fornatural gas and the Siemens natural gas specificationcurrently limits fuel gas sulphur to 6 ppmv (Haywood, 2007).

Combustion properties of fuels sometimes cited for gasturbines include the density, Wobbe Index (HHV/square rootof specific gravity of gas) and flammability limit ratio (rich tolean volume basis). The density of pipeline natural gas is0.7–0.9 kg/m3 and for weak natural gas 0.9–1.1 kg/m3

(Molière, 2005). The properties of the last three H2 syngaseslisted in Table 1 were (James and others, 2006):

A B B(+N2)Relative density 0.7 0.3 0.6Wobbe Index, MJ/m3 7.09 16.9 6.47Flammability limit ratio 8.3 15.6 8.3

Syngas outlet,coal3

H2 syngas,coal3

Syngas outlet,coal3

H2 syngas, coal3

H2

syngas A5

H2

syngas B5

H2 + N2

syngas B5

GE, slurry GE, slurry CoP slurry CoP slurry local GEM local GEM local GEM

0.06 0.06 4.13 4.64 0.07 0.1 0.05

30.9 68 23.7 73.1 52 79.1 43.5

35.0 4.68 39.7 1.14 2.64 3.93 2.16

14.6 2.57 11.5 1.79 37.3 4.7 2.59

0.78 3.31 0.99 1.18 7.36 11.2 52.2

0.84 0.003 0.57 0.002 0.0003* 0.0005* 0.0005*

0.95 1.05 0.96 1.13 0.62 0.93 0.51

16.9 20 18.4 17 0.03 0.01 0.01

1.1 0.07 1.7 0.02 0.05 0.05 0.05

5.66 9.06 4.98

When comparing syngases with natural gas, it is useful toexamine the properties of H2 and CO (Renzenbrink andothers, 2006):

CH4 H2 COLHV, MJ/m3 35.8 10.2 12.6Flame speed in air, cm/s 43 350 20Stoichiometric combustion temperature, K 2227 2370 2374

Density, kg/m3 0.72 0.09 1.25Specific heat, kJ/kg K 2.18 14.24 1.05Flammability limits, vol% 5–15 4–75 12.5–74

The Wobbe Index of these gases is 48.6–53.8 MJ/m3

(11,597–12,837 kcal/m3) for CH4, 40.7–48.3 MJ/m3

(9715–11,528) kcal/m3 for H2, and 12.8 MJ/m3

(3060) kcal/m3 for CO (Engineering ToolBox, 2008).

The key combustion characteristics of H2 are low ignitionenergy, low density, high flame speed, high flame temperatureand wide flammability range (Jones and others, 2007a).

Walton and others (2007) report on their experimentalinvestigation of the ignition properties of H2 and CO mixturesfor syngas turbine applications. They conclude that the severelack of data on syngas combustion properties such asflammability limits, flame speeds, and ignition characteristicsat conditions relevant to syngas combustor operation is asignificant handicap to syngas turbine design.

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IEA CLEAN COAL CENTRE

2.2 Effects on gas turbines

A conventional gas turbine cycle consists of compressing aworking fluid (air), followed by combustion of the fuel; theenergy thus released from the fuel is absorbed into theworking fluid as heat. The working fluid with the absorbedenergy is then expanded in a turbine to produce mechanicalenergy, which may in turn be used to drive a generator toproduce electrical power (Rao, 2006a). The main componentsof gas turbines for IGCC are highlighted in Figure 1, acompressor, combustor, and turbine. Gas turbines convert heatinto shaft power by using air as the working fluid rather thanthe steam in a steam turbine. The air is first compressed,usually in a multi-stage axial compressor, to around 1.5 MPa(higher pressures up to 3 MPa are used in aero-engines andtheir land-based derivatives). The air is then heated bycombustion of a fuel in it, and the added energy is exploitedby expansion of the hot product gases in the turbine section.The fluid is expanded and its pressure reduced as it passesthrough a sequence of stages of stators and rotors while itsenergy is converted into rotational energy. The turbine drivesthe compressor directly and the balance of motive powerdrives the generator. Gas turbines are most easily designed forfuelling on natural gas and distillate oils, but coal-derived gascan be used (Henderson, 2004).

Unconverted energy is exhausted in the form of heat whichmay be recovered for producing additional power. Theefficiency of the engine is at a maximum when thetemperature of the working fluid entering the expansion step

Table 2 Typical composition of syngas from coal, biomass, heavy residue and orimulsion (Hasegawa andothers, 2005)

Fuel Coal, dry Coal, dry Coal, dryCoal,slurry

Biomass BiomassHeavyresidue, dry

Orimulsion,dry

Petcoke*

IGC Shell HYCOL Texaco Tampella Tampella Texaco CRIEPI CFBR

% air O2 O2 O2 air O2 O2 O2

CH4 0.5–1.4 0.01–0.03 1–2 0.1 4–8 2.2 0.2 0.4 7.42

H2 9.4–10.9 28.8–31 31.3–33.7 29.9 8–12 12.5–22.4 43.1 42.2 24.0

CO 25.9–27.6 65.2–69.5 55.2–59.4 40.9 8–15 21.9–23.1 51.7 43.5 59.8

CO2 5.4–6.7 1–2.8 7.6–10.4 9.5 13–18 18.6–20.7 3.2 11.8 7.89

NH3 0.1† 0.01–0.06 – – – 0–0.02 – –

H2S+COS 0.04–0.07 0.14–1.1 – – – 0.29–1.13 1.6 1.35

H2O – – – 12.3 7–15 31.5–40.9 – – 0

Others, N2 54.2–56.1 – – 7.3 – 1.05–1.8 0.2 0.75 0.89

CO/H2 2.4–3 2.1–2.4 1.6–1.9† 1.4 – 1–1.8 1.2 1 0.25

HHV, MJ/m3 4.9–5.2 12.2–12.5 12† 9 4–7 5.2–6.6 12.1 11

LHV, MJ/m3 12.1

* Laster and others, 2006† estimated values

is also at a maximum. This occurs when the fuel is burned inthe presence of the pressurised air under stoichiometricconditions but excess air is used in practice. Novel advancedgas turbine cycles to improve the cycle performance andreduce pollutant emissions are currently under developmentfor natural gas as well as coal-derived syngas and H2 fuels(for further details see Rao, 2006a).

Key properties of a gas turbine are the inlet air flow rate, theturbine inlet temperature and the pressure ratio. The lattersometimes refers to the pressure ratio across the wholeturbine (the compressor delivery pressure divided by theturbine outlet pressure). It may also refer to the compressor inwhich case it is the ratio of the outlet to inlet pressure of thecompressor. As gas turbines both aspirate and exhaust atambient pressure, these two pressure ratios are numericallysimilar. The only slight difference comes from any pressuredrop between the compressor outlet and expander. The airflow rate sets the output, while the turbine inlet temperatureand the pressure ratio across the gas turbine determine theefficiency. Developments in gas turbine technology haveresulted in higher inlet temperatures, raising efficiency. Theefficiency is related to the initial and final temperatures of thesystem (� = (T1–T2/T1). The most advanced gas turbines usedin power generation have turbine inlet temperaturesapproaching 1400°C. This has been achieved through the useof improved alloys and blade cooling systems, for example,using air channels which aspirate through holes in the blades.Exhaust gases leaving gas turbines are typically at atemperature of 550–600°C, sometimes higher, for the steamcycle (see Figure 1). The efficiency of a gas turbine istypically around 30% (HHV) because of this high exhausttemperature. Newer gas turbines reach higher values.Increasing the pressure ratio raises efficiency up to amaximum before it decreases. This is because the compressorpower requirement rises faster than the power developed by

9



the turbine. The optimum lies at higher pressures as theturbine inlet temperature is increased. As most gas turbinesexit to atmosphere, ambient conditions generally affectoutput. The lower the turbine outlet pressure, the greater thedelivered motive power obtained by expansion of the gases(Henderson, 2004, 2009).

Thermal barrier coatings are used extensively to insulate hotsection metallic components in gas turbine engines and havebecome a critical technology for improving the efficiency andperformance of advanced gas turbines. Thermal barriercoatings are generally multilayered systems consisting of aceramic top coat (Ytrria-stabilised zirconia-ZrO2 stabilisedwith 7–8 wt% Y2O3) for thermal insulation, a thermallygrown oxide scale, a metallic bond coat that providesoxidation/corrosion resistance, and a superalloy substrate(Mohan and others, 2007). Gas turbine advances require notonly use of new materials (including thermal barrier coatings)but also technologies such as single crystal blading,compressor intercooling and reheat. These developments areinitially on natural gas-fired versions but flowing throughlater to syngas firing technology. In general it is most efficientand economic to choose the most advanced gas turbine thatcan be supplied with full commercial guarantees based on theexpected syngas quality (Henderson, 2004).

Recent introductions of gas turbines on natural gas, H-classmachines, are discussed by Henderson (2008). The GeneralElectric (GE) H-class machines use steam cooling of movingand static blades, with a firing temperature of 1426°C. TheSiemens H-class machine is air cooled and the first modelwas being supplied to a site owned by E.ON in Germany fortesting and validation prior to commercial release (Siemens,2007). Phillips (2007) noted the increased complication thatwould ensue in applying steam-cooled H-class gas turbines toIGCC and the Siemens reversion to air cooling for

steam

air

steamturbine

stack

waste heatboiler

steam

steam

gascleaninggasifier

raw gascoal feed

oxygen plant

oxygen

gasturbinecompressor

combustor

clean gas

Figure 1 Principle of IGCC power generation (Henderson, 2005)

H machines may give them a future advantage. On the otherhand, the Mitsubishi G series gas turbine incorporates steamcooling (Rao, 2006a) and has a turbine inlet temperature of1500°C. Most recently, Mitsubishi have announced theircompleted development of the J-class gas turbine, with aturbine inlet temperature of nearly 1600°C for delivery in2011. This also uses steam cooling with a compressor with ahigher compression ratio (MHI, 2009).

As described in Section 2.1, the combustible components ofsyngases, H2 and CO, are characterised by significantlyhigher stoichiometric combustion temperatures and muchsmaller volumetric calorific values than the CH4 in thestandard natural gas turbine fuel. These factors, combinedwith the much reduced auto-ignition delay times, mean thatthe gas turbine combustion concept has to be modified toavoid pre-ignition and flashback. In addition, the low densityof H2 causes a large increase in the volumetric fuel flowwhich requires an increased cross-section of the fuel passage(Renzenbrink and others, 2006). Hydrogen affects rates ofwall heat transfer as well as flame stabilisation (Bunkute andMoss, 2007). Burning of H2 in gas turbines requiresmodifications to the fuel supply system, combustor andcontrol system (IEA GHG, 2000). An increased residencetime is needed for CO burn-up. Mixed gases containing waterand salts attack current air-foil base materials so that researchfor more robust barrier blade coatings is justified in order toincrease the operating temperature and life (Day and others,2006). The control systems may need additionalinputs/outputs and integration with the gasifier process(Donaldson and Mukherjee, 2006).

IGCC performance is most influenced by gas turbine internaldesign parameters such as firing temperature, turbine andcompressor geometry, combustion and cooling technology.IGCC cycle integration parameters such as syngas fuel anddiluent flow and supply conditions have secondary impactsexcept for NOx emissions (Anand and others, 2005). Ingeneral terms, the turbine inlet temperature is a function ofthe turbine flame/firing temperature, compression ratio, massflow, and centrifugal stress. These factors limit size andultimately efficiency. A rough rule of thumb is that anincrease in firing temperature of 55°C gives a 10–13%increase in power output and a 2–4% increase in efficiency.The combustion chambers and the turbine first stagestationary nozzles and blades are the most critical areas of theturbine that determine its power output and efficiency (Soares,2006).

Progress in performance must not sacrifice RAM. Reliabilityis used to express and quantify the unplanned maintenanceneeds of a power plant – that is how often a plant is availablein comparison to the total number of hours the plant would beavailable with no unexpected maintenance. Availabilityconsiders both scheduled and unscheduled maintenance andcompares that to an ideal case with no maintenance outages atall. Maintainability is used to express the cost of keeping theplant in operating condition. The concept of RAM is used toconsider the tradeoff between higher technology, immaturetechnologies and less advanced, but more reliable operation(Marini, 2006). The RAM targets for gas turbines burningsyngas are the same as for a standard natural gas fired engine.

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Investigating conditions for retrofitting the SGT6-5000F gasturbine for natural gas combined cycle on IGCC, Gadde andothers (2006a) at Siemens, considered that RAM and engineoperability would not be affected by the modificationsrequired for this application.

2.2.1 Compressor

Low and medium calorific value gases have the advantagethat for a given heat rate, they allow higher flow rates throughthe gas turbine than natural gas. This in turn can increasepower by 10% or more compared with natural gas and gives acorresponding increase in efficiency (Butcher, 2004).Nitrogen (N2) from the air separation unit may be used todilute the syngas flow. This reduces the flame temperature(and hence NOx emissions) and flame speed in the gasturbine. As a result, the design of the compressor should bemodified for less air flow; and the inlet guide vanes should beimproved to reduce the minimum air flow through thecompressor, for example from 60% to 50% to improve part-load behaviour. With CO2 removal, the amount of availableN2 increases by 10.4%. Hence the amount of air needed in thegas turbine can be reduced and also the amount ofcompression work, resulting in a higher gas turbine output(Hannemann and others, 2007; van Art and others, 2007).

The amount of air inducted by the compressor varies with theambient temperature. On cold days, the air flow increases dueto constant volumetric flow through this component and theincrease in air density. The mass flow can be controlled by theinlet guide vane in order to level the flow across varyingambient conditions (Gutierrez and others, 2006).

Compared to a gas turbine working with natural gas fuel,there is a mismatch in the mass flow between the compressorand the turbine, caused by the higher volume flow and addedN2 diluent. Compressor surge (instabilities) may be managedthrough the degree of integration by removing mass flow fromthe compressor discharge to feed the air separation unit. Thedegree of integration varies with the specific plant designs butis normally about 50% where half the feed air to the airseparation unit comes from the main gas turbine and halfcomes from separate electric drive feed air compressors. Theclose coupling of the air separation unit and the main gasturbine may appear synergistic but it is susceptible to systemlosses and less than optimum component matching.Alternative use of four-stage intercooled motor-drivencompressors to feed the air separation unit would bringconsiderable savings and could include waste heat recovery(Steele and Baldwin, 2006).

Many IGCC plants use air bled from the gas turbinecompressor to supply the gasifier, either directly or as feed foran O2 plant. The Siemens.SGT5-2000E (formerly V94.2K)gas turbine, which was designed specifically for IGCC plants,has an extra row of compressor blades for this purpose(Butcher, 2004). It is a standard SGT5-2000E (V94.2) with anextra compressor stage to allow a higher margin againstcompressor surge (Bonzani and others, 2007).

The compressor section has been modified to reduce the inlet

air design mass flow of the V94.2K gas turbine for use withlow calorific value syngases (4.6 MJ/kg). This modificationled to the 2007 V94.2K2 version, reported by Bonzani andothers (2007, 2008) at Ansaldo Energia. They eliminated thefirst compressor stage, the original second stage becoming thefirst one with a reduction in inlet air flow. This considerablyreduced the front area of the inlet guide vane. The compressorinlet duct was therefore also modified to adapt it to thereduced inlet guide vane cross sectional area. Two additionalcompression stages were added on the delivery side to restorethe previous surge margins. Some blades were re-staggered tokeep the same bleed inlet pressures and to restore the correctvelocity triangles. The modifications to the compressor weresummarised: � new compressor vane-carrier casings with minor changes

to compressor fixed stages;� compressor bearing casing changed at the interface

towards the compressor vane carrier casing;� first stage of rotor removed and two final stages added

but rotor otherwise unchanged.

Evaporative cooling into the compressor intake system wasinvestigated by Brusca and Lanzafame (2004) with a view toimproving performance at high atmospheric temperatures.The cooling effects on engine power production andefficiency were studied from both a theoretical andexperimental point of view. The gas turbine studied was asingle shaft, cold-end drive, dual combustor, heavy dutyindustrial gas turbine. It was suitable for a varied range offuels, including syngas, in combined cycle operations. Asmall percentage of compressed air was bled from the mainflow at the end of the compressor to the interior of the rotor. Itwas directed to the first row of blades. Another percentage ofcompressed air was bled from the main flow at the thirteenthcompressor stage and introduced into the rotor interior to coolthe second, third and fourth stage rotor disks and the secondstage rotor blades. Two combustion chambers were arrangedvertically on both sides of the expander and connected tolateral flanges on the turbine common outer casing. Thisdesign enabled concentric gas and air paths to lead from thecompressor to the combustion chambers and from thecombustion chambers to the turbine, resulting in relativelylow flow velocities and thus minimum pressure drops.

Two operating modes were considered: the first involved aconstant air relative humidity at the compressor intake of95%; the second a constant air temperature, set equal to thetemperature corresponding to the maximum inlet guide vaneopening. The first setting achieved a higher degree of bothpower production and global efficiency than the secondsetting. However, the results showed that the 95% relativehumidity setting used about five times more water than theconstant temperature while achieving twice the energy gain.The achievable performance advantages of evaporativecooling techniques were greater than their implementationand running costs (Brusca and Lanzafame, 2004).

Where additional N2 dilution is necessary for gas turbines tooperate on H2--rich syngases, the pressure ratio of the gasturbine compressor increases so that the security margin to thesurge limit decreases (Rieger and others, 2008). Syngascombustion testing was initiated to verify the readiness of the

11



SGT6-5000F gas turbine for syngas as it is currently used fornatural gas. The compressor surge margin was investigated todetermine whether there was a need to re-stagger the firststage turbine vane so as to reduce the operating pressure ratio.The compressor analysis involved aerodynamic andmechanical considerations. Calculations were carried out onaerodynamic loading on marginal stages, stall, surge marginand thrust balance. The results showed that an acceptablesurge margin and performance could be achieved without re-staggering the vane (Gadde and others, 2006a,b).

2.2.2 Safety and fuel system

Use of syngas instead of natural gas requires less combustionair since the fuel/exhaust flow ratio increases significantly. Astart-up fuel is required for cofiring or as full back-up.Auxiliary skids may be needed for fuel and diluent,ventilation, purge and fire protection (Donaldson andMukherjee, 2006).

Modifications to the Siemens SGT5-2000E (V94.2) gasturbine for low calorific value fuels (see Section 2.2.1)included a new design for the fuel skid system (Bonzani andothers, 2007).

Storage and handling of H2 are major issues. The H2 needs tobe supplied at sufficient pressure to enter the enginecombustor. Most gasifiers produce syngas at a sufficientpressure, but the power to do this must be considered in theoverall plant accounting (over 60 MW is required to compress10 kg/s of gaseous H2 to a pressure ratio of 20:1). Newsoftware and hardware (such as valves) are needed in the fuelcontrol systems (IEA GHG, 2000).

Burning of H2 with N2 injection requires more fuel piping andchanged fuel injectors to handle the mixed fuel. If the fuelpressure is not high enough, additional compression would berequired to that for H2. This means a further 60 MW to pump140 kg/s of gaseous N2 to the same pressure as the H2. Thecontrol system would need considerable modification. Adevice to detect the fraction of N2 in the fuel would enable aplant and gas turbine to be designed to cope with a limitedrange of N2 to H2 fractions (IEA GHG, 2000).

The extremely low flammability limit of H2 requires thatadditional time and volume of purge gas be provided overnormal experience to ensure that lines are free following fueltransfers and shut-downs. Transfer and purge strategies mustbe meticulously developed and tested with dynamicmodelling. Coordination with process controls and upsetresponses must also be meticulously worked out. A start-upfuel must be provided that does not contain H2. The materialsof construction, especially for highly stressed componentssuch as valves and valve seats, must be suitable for H2

exposure and resistant to H2 embrittlement. Weldedconnections or gasketing materials must be designed for thelow molecular weight and high diffusivity of H2. Enclosuresmust be provided with special sensing, explosion proofingand additional ventilation determined by appropriate chemicalindustry codes and standards specific to H2 (Shilling andJones, 2004).

2.2.3 Combustor

The dual role of the combustor in a gas turbine is to transformthe chemical energy in the fuel into thermal energy forexpansion in the turbine; and to tailor the temperature profileof the hot gases at the exit plane so as not to compromise thematerial constraints of the turbine. The combustor processesare therefore a complex combination of fluid mixing,chemical kinetics, and heat transfer (Samuelson, 2006a). It isin the combustion system that the main changes have to bemade to accommodate the high gas flow rates, lower heatingvalues and other characteristics of synfuels. Flame stabilitycan be a concern since the H2 in the syngas has a high flamespeed (Butcher, 2004).

Static and dynamic combustion stability are described in thegas turbine handbook from the US DOE NETL by Lieuwen(2006). Blowoff refers to the flame physically leaving thecombustor and ‘blowing out’ of the combustor. This issue isoften called static stability. Blowoff occurs when the flamecannot be anchored in the combustor. Fluid mechanics, andnot just chemical kinetics, must be accounted for inunderstanding how blowoff limits vary with fuel composition.Because the flow field and the flame are coupled, variationsof the chemistry do impact the flow. Combustion instability,or ‘dynamic instabilities’ refer to damaging oscillations drivenby fluctuations in the combustion heat release rate. Theseoscillations cause wear and damage to combustor componentsand, in extreme cases, can cause liberation of pieces into thehot gas path and resulting damage to downstream turbinecomponents. The oscillations are not always associated withthe natural acoustic modes of the combustor. They may beexcited by a coupled convective-acoustic mode which occursat frequencies lower than those of purely acoustic modes.Such oscillations occur when a hot gas packet or vortexconvects through the nozzle, where it excites an acoustic wavethat propagates back to the flame. This excites anotherconvected wave, thus repeating the process. These types ofmodes are often encountered in systems that are operatingclose to flame blowoff. Although the high flame speed of H2

causes dynamic instability, H2 addition can promote dynamicstability under near blowout conditions where low frequencydynamic instabilities occur. By promoting a more staticallystable flame, H2 addition could potentially make these typesof dynamic instabilities less problematic.

The amplitude of the instability grows if the rate of energyaddition to the oscillations exceeds the rate of energydissipation by damping processes in the combustor. Theamplitude of the oscillations reaches its maximum value whenthe time averages of the energy addition and removal areequal. The resulting oscillations are referred to as a limitcycle. Unstable combustors under limit cycle conditions maygenerate harmonic oscillations at higher frequencies as well.The presence of oscillations also changes the mean flameposition and flow field so the flame may become eithershorter or longer (Lieuwen, 2006).

The widely varying flame speeds of gas turbine synfuels mayresult in blowout and flashback. Blowout is a concern in lowemissions combustors. The blowout limits of a combustor can

12



vary significantly with fuel composition, due to their widerange in chemical kinetic rates. For example, many candidatefuels have similar heating values but also have chemicalkinetic times that vary by an order of magnitude (Noble andothers, 2006). A consistently uniform definition of blowout iscomplicated by the fact that the manner in which the flameblows out varies with the fuel composition. In many cases, theblowout point is unambiguous where the point of blowout andlift-off are nearly identical, as for mixtures composed largelyof CH4 or CO. However, for mixtures with more than about60% H2, the blowoff and lift-off events are quite distinct.Usually the flame becomes visibly weaker, lifts off from theholder and moves progressively downstream before blowingout for good. It may be defined as the point where the flame isno longer visible in the 10.2 cm long optically accessiblesection of the combustor. This should be kept in mind whencomparing fuels containing 0–60% H2 and 60–100% H2

(Zhang and others, 2005).

Flashback may occur at high flame speed fuels, such as thosecontaining high H2 contents. This happens when the flamephysically propagates upstream of the region where it issupposed to anchor and into regions which are not designedfor high temperatures (Noble and others, 2006). The flamespeed of H2-air mixtures is six times greater than a naturalgas-air mixture (Steele and Baldwin, 2006). The need to avoidflame attachment to the burner nozzles to prevent overheating,while maintaining the desired low NOx emissions, ideallyrequires combustion zones of specific dimensions and/orshape for each fuel. This makes the concept of dual-or multi-fuel capability difficult to achieve in a single combustiondesign. Combustor liner materials that require less cooling area continuing need (Wright and Gibbons, 2007).

Approaches for maintaining metal temperatures at acceptablevalues (around 950°C) involve the combination of cooling airand thermal barrier coatings, or the use of ceramic tiles. Suchcomponents have generally performed well in most types ofgas turbine, but, with further increases in firing temperatureand more complex combustion conditions, there has beensome effort to evaluate alternative materials. Among these,both oxide dispersion-strengthened ferritic alloys (such asPM2000) and ceramic matrix composites have beenconsidered. Some success has been achieved with SiC-SiC aswell as oxide-oxide ceramic matrix composites. Engine trialshave been carried out on components manufactured from thistype of material (Wright and Gibbons, 2007).

Burning syngas instead of natural gas requires that dry, lowNOx burners are replaced by multi-nozzle, quiet combustors.A diluent and start-up fuel connections are needed. The caps,liners, and flow sleeves have to be modified or replaced. Thefiring temperature needs to be reduced to mitigate the adverseeffect of high flame temperature of H2 on component life. Theoutput can be maintained fairly constant over a wider range ofambient temperatures. Typical emissions from burning syngasare 15–25 ppm NOx/CO (Donaldson and Mukherjee, 2006).

Combustor developmentsGadde and others (2006a) summarised design modificationsto the combustor of the SGT6-5000F gas turbine, currentlyused for natural gas, verifying its readiness for coal-based

IGCC, The combustor baskets and fuel nozzles requiredmodification. The syngas combustor basket was designed tooperate on syngas and natural gas. The combustor wasdeveloped to the minimum amount of diluent on both primaryand secondary fuels. The cover plate was modified toaccommodate continuous dynamics monitoring and acontinuous, online, self tuning system. The fuel nozzle wasdesigned to inject syngas and natural gas separately; syngasand natural gas simultaneously during fuel transfers; syngasand natural gas during cofiring; N2 as the primary diluent;steam mixed with syngas as the secondary diluent on syngasoperation; and steam as the primary diluent on natural gasoperation. The nozzle was to be designed to operate ondistillate oil in similar combinations as for natural gas.

The V94.2K2 gas turbine (see also Sections 2.2.1 and 2.2.2),developed by Ansaldo Energia for low calorific value fuels,has two combustion chambers arranged vertically on eitherside of the turbine and connected to lateral flanges on theturbine casing. This design allows concentric gas and air pathsfrom the compressor to the combustion chambers and fromthese to the turbine. The flow velocities are relatively lowwith a minimum pressure drop. Each combustion chamber isprovided with eight separate burners equipped for burninglow calorific value fuel as main fuel with natural gas as aback-up fuel. Typical fuels suited for this gas turbine have alower heating value of 4.8–6.0 MJ/m3 and 3.8–9.9%vol H2

(see Bonzani and others, 2007), considerably lower than thecoal based syngas properties shown in Table 1.

A modified dry low emissions reverse-flow can-annularcombustion system has been developed by Siemens for lowcalorific value fuels in its small gas turbines. It can burn fuelscontaining up to 90% H2 (Butcher, 2004).

Retrofits to a gas turbine combustor for high H2 mediumheating value syngas fuel, modelled and tested by Xu andothers (2005) in China, were based on three modifications.The main focus was on the design of the fuel injectors. Theseutilised swirlers with stronger swirl and enlarged fuelinjection holes. The results indicated that the swirl of theswirler injection should be strengthened. The area of thesyngas fuel holes could be determined by keeping the sameinjection velocity as that of the original injector for burningnatural gas to achieve the design specification forperformance. The injection velocity should be greater than thesafety velocity of flashback to maintain stable flame holding.Blowout was not especially important at 37% H2 in thesyngas.

The combustor is the key gas turbine element in an IGCCplant (Parkinson, 2004). There are various flameconfigurations: diffusion, premixed and catalytic, developedto achieve stable and efficient combustion with low emissions.These are discussed in more detail in Chapters 3, 4 and 5respectively.

2.2.4 Turbine

The turbine (expander) does not require redesign or extrastages to burn fuels containing H2. However, the life of the

13



turbine section of a gas turbine operating at base load andusing natural gas is essentially determined by the creep life.Creep life is reduced to a half, each time the turbine blademetal temperature is increased by 15–20°C. Thus a reductionin the ability to control the temperature at the exit of thecombustor can have a major impact on the life cycle cost ofthe machine (IEA GHG, 2000).

The higher firing temperature as well as increased moisturecontent when operating on syngas or H2 fuels increases thethermal load on the turbine airfoils. Maintaining adequatelives of the hot parts will pose a challenge and requireadvanced cooling technology, thermal barrier coatings, bondcoat performance, alloy strength or use of novel concepts suchas ceramic matrix composites or fabricated airfoils (Bancalariand others, 2006). Where additional N2 dilution is necessaryfor gas turbines to operate on H2--rich syngases, the turbinecooling would have to increase in order to achieve the samehot gas temperature as for natural gas combustion. Theavailable cooling air is almost fixed through the turbinedesign, which means that the turbine blading temperaturewould increase at higher dilution rates. The hot gastemperature and consequently the firing temperature thereforehave to be derated in order to avoid overheating the turbineblades (Rieger and others, 2008).

The increased pressure ratio increases aerodynamic loadingsand may result in an increase in the number of stages, in orderto avoid an efficiency penalty. The higher pressures will resultin increased leakage and a performance loss (Bancalari andothers, 2006).

The increased mass flow leads to elevated Mach numbersthroughout the flow path and may penalise efficiency. Asolution may be to increase the turbine annulus area but thisincreases loads exerted on the turbine discs. This is especiallycritical for the last stage blade which is already near itslimiting height from both disc load and flutter considerations(Bancalari and others, 2006).

Turbine developmentsConsidering the suitability of current gas turbines for syngas,Gadde and others (2006a) concluded from their analysis thatall the components of the turbine in the SGT6-5000F wouldmeet the design requirements without any modifications.Similarly, gas turbines such as the GE 9001 EC are able toaccommodate the increase in mass flow through the turbine.However, the increase in flow, due to greater fuel flow and theaddition of diluent for NOx emissions control, produces backpressure on the compressor and can bring an engine close tosurge conditions (Steele, 2006). Burning syngas instead ofnatural gas may necessitate replacing the first-stage nozzle ofthe turbine, its support and retaining rings (Donaldson andMukherjee, 2006). Use of water or steam injection to reducethe temperature, and hence NOx emissions, when burning H2

fuels, may lead to overheating of the first-stage turbinenozzle, due to the high heat exchange coefficient of H2O(Molière, 2005).

A small increase in turbine capacity may be advisable whenusing H2 fuel mixed with N2 to ensure adequate compressorsurge margins. There may also be a small effect on the turbine

cooling required due to the presence of extra N2 in the flow.The ratio of turbine cooling fluid to mainstream fluid remainsessentially unaltered (IEA GHG, 2000).

Use of syngas and H2 instead of natural gas increases thewater vapour content of the combustion gas at the turbineinlet from 10–15% for natural gas to about 60% for H2. Thisleads to concern that oxidation-resistant coatings will beimpaired, especially thermal barrier coatings. New bondcoating compositions are being investigated, such as high Pt,low Al coatings. Test results on cyclically oxidised coatings at1100°C in air with 10% and 50% water vapour werecompared to the behaviour in dry O2. For Y-and Hf-dopedalloys, the effect of water vapour was minor with no increasein the scale growth rate. For undoped alumina-formers withless spallation resistance, the amount of spallation increasedwith increasing water vapour content. Longer exposures areneeded to clarify the effects of higher water vapour contentson the coated superalloys (Pint and others, 2006).

Turbine blade corrosion problems result from the formationof sodium sulphate or potassium sulphate in the presence ofchlorine when fuels other than natural gas are used in gasturbines at high temperatures. This is especially a problemwith biomass fuels and coals. Although turbine blades withthermal boundary coatings are in an advanced stage ofdevelopment, they are also extremely sensitive materials inregard to fuel purity. Their porous nature has a tendency towick even slight traces of chemical deposits into theirstructure while operating at high temperatures. This leads to acatastrophic failure whenever the turbine is cooled. Synfuelscontaining even minute traces (parts per million or less) of analkali impurity can gradually destroy a superalloy turbineblade. It is estimated that low alkali concentrations in theorder of tenths of parts per billion are needed to ensure anadequate operational lifetime (Schofield, 2005).

The addition of molybdenum or tungsten additives to the pre-cleaned fuel, just prior to combustion or sprayed into the hotcombustion gases ahead of the gas turbine, can inhibitcorrosion. Trace amounts of molybdenum salt of around twicethat of the gaseous alkali, on an atomic basis, are required.This is an economic solution when applied to neutralising theeffects of alkali concentrations in the order of parts permillion or less. Depending on the operational turbine bladetemperatures, the deposition of such a protective molybdatecoating as a liquid rather than possibly a solid, might beadvantageous. This would ensure retention of only a thinprotective film on the blades with no buildup over time(Schofield, 2005).

The higher fuel to air ratio in syngas combustion makes it likelythat the deposition-erosion-corrosion trigger points in the hotgas path of the turbine will be reached with lower amounts ofimpurity in the fuel. Hence the potential for hot corrosion maybe increased compared with natural gas, depending on therange and amount of impurities in the fuel. Extensive work isrequired to develop coatings to cope with the risk of hightemperature degradation. This is because the coatingsdeveloped to provide protection for natural gas fired turbinesare typically deficient in Cr which is the major element neededto counter sulphidation and hot corrosion attack. There may be

14



potential for further development of polycrystalline,directionally solidified materials with higher Cr to combatsulphur related corrosion (Wright and Gibbons, 2007).

Research on the relevance of environmental degradationissues in gas turbines to plant life extension is described byOakey and others (2004). Corrosion life predictions for gasturbines operating on a gasification system, require detailedinformation about the exposure conditions within the gasturbine hot gas path, in terms of, for example, the entry gascomposition, gas partial pressures, deposition fluxes, andmetal temperatures. Such detailed information about gasturbine and system performance is commercially sensitive buta set of generic conditions may be used with assumptionsabout gas contaminant levels of SOx and HCl. Many hot gaspath turbine components are reliant on thermal barriercoatings for life. These are used increasingly to reduce themetal temperatures and hence increase creep and thermo-mechanical fatigue lives. Coating life is one of the mainfactors governing the repair and refurbishment intervals of thehot gas path parts. Hence it is important to understand themechanisms of spallation of such coatings and to developmodels to predict the event and validate the models.

Thermal barrier coatings are attached to the substrate bymeans of bond and key coats, giving a complex, multi-layeredcoating structure. For example, bond coats may have Ni or Cocoatings applied by low pressure plasma spraying, highvelocity oxyfuel or electroplating. Pt-Al electroplate isfollowed by aluminising. Key coats are applied by similarmeans with only Pt electroplate. This layer is processeddifferently to the bond coat to give different coating layerproperties, for example surface roughness, thinner coating.The lives of these coatings are determined by a host ofparameters such as the chemistry of the material, method andquality of coating deposition, and gas turbine duty cycle. Theformation of an �-alumina oxide between the bond/key coatsof thermal barrier coatings is believed to be critical to theattachment of the coatings. However, growth of this oxidelayer (thermally grown oxide) had frequently been identifiedas having a major influence on spallation of the thermalbarrier layer. Other possible factors have been identified butthe magnitudes of the effects and their interactions (if any) areas yet unknown, although under investigation (Oakey andothers, 2004).

Component lives almost always exceed the designers’cautious expectations, but the techniques used to assess theircondition and predict remaining life are often empirical andsubjective. Modelling degradation behaviour and potentiallives of materials systems in gas turbines requiresconsideration of a wide range of factors, including thedetailed exposure environment, mechanical requirements andlife criteria. As components tend to fail from the regions ofworst corrosion damage, statistically based corrosion modelsneed to be derived from metal loss data that show thesensitivity of corrosion damage parameters. Some corrosionmodels have been developed to meet these objectives forspecific components within the hot gas paths of these powersystems. Further studies are planned to extend these models toinclude thermal barrier coatings and a wider range of fuels(Oakey and others, 2004).

Use of coal/petcoke blends in IGCC gives rise to impurities ofvanadium, phosphorus and sodium with ensuing hightemperature material degradation. For example, the presenceof molten V2O5 was found to destabilise the yttria-stabilisedzirconia in thermal barrier coatings. Also Na2SO4 wasreported to destabilise it in the presence of a relatively highpartial pressure of SO3. Hot corrosion studies at 700–900°Cwere therefore performed to examine the degradation reactionmechanisms of a free-standing air plasma-sprayed, yttria-stabilised zirconia topcoat by V2O5, P2O5, Na2SO4, andNa2SO4 + V2O5 mixtures at 50–50 mol% in a molten state(for experimental details see Mohan and others, 2007).

The predominant reaction at temperatures below 747°C wasobserved to be the formation of ZrV2O7. At temperaturesabove 747°C, V2O5 degraded yttria-stabilised zirconia to formYVO4, which leads to disruptive zirconia phasetransformation to a monoclinic phase. These two differentreaction mechanisms were explained by the incongruentmelting behaviour of ZrV2O7 at 747°C. Molten Na2SO4 waschemically inert in the yttria-stabilised zirconia, although itsinfiltration into the interlamellar gaps and pores of yttria-stabilised zirconia and crystallisation while cooling wouldresult in thermo-mechanical damage. At elevatedtemperatures, Na2O in a molten state, dissociated fromNa2SO4, tends to form vanadates of sodium such as NaVO3 inthe presence of V2O5. Degradation tests at 700°C led to theconclusion that the presence of Na2SO4 enhances the hightemperature degradation of yttria-stabilised zirconia by V2O5.Degradation studies by P2O5, revealed that the only observedreaction between ZrO2 and P2O5 was the formation of ZrP2O7,This enriched the yttria content in the yttria-stabilisedzirconia, leading to the phase transformation to fluorite-cubicphase (Mohan and others, 2007).

Surface erosion is a potential risk from the presence of highvelocity particles, despite their essential elimination throughcold gas clean up. Consequently there is an interest inapproaches (should they be needed) for guarding againstsurface erosion of hot gas path parts, especially of thermalbarrier coatings on air foil leading edges and blocking ofcooling holes on blades and vanes which could impair coolingefficiency. At temperatures above the dewpoints ofcondensable alkali salts, a relatively new phenomenoninvolving the formation and deposition of eutectic compoundswith CaO may become important. This would result indeleterious interactions with otherwise protective surfaceoxide films. For the airfoils, one major need is to reduce thecosts and simplify the manufacturing procedures for singlecrystal components. More efficient use of available coolingair should be made as the firing temperatures, at least initially,of syngas turbines are higher than in those burning natural gas(Wright and Gibbons, 2007).

Particulate deposition may affect film cooling, for example,surface deposition, hole blockage, and spallation of thermalbarrier coatings, especially on the leading edge of a vane endwall. This is because the first rows of vanes in a gas turbineare subjected to direct impingement of the mainstream gas onthe cold surface, resulting in particulate deposition. Anexperimental turbine vane section was placed in a closed loopwind tunnel facility (for details see Sundaram and Thole,

15



2007). For example, specific deposits on the vane end wallwere used to simulate cooling hole distortions by deposits.Film cooling hole blockages were manufactured to reduce theexit hole area by 25%. Sandpaper on the end wall simulatedthe uniform roughness and this was removed to simulatespallation of the thermal barrier coating on the end wall.Adiabatic end wall temperatures were measured for differentflow rates through film cooling holes, through the combustorto turbine interface slot and a constant flow rate through thevane-to-vane interface gap.

At the leading edge region, it was found that partial holeblockage and spallation of the thermal barrier coating causeda greater reduction in adiabatic effectiveness than surfacedeposition. Near hole depositions were studied with varyingdeposit heights. Smaller deposit heights enhanced the overallfilm cooling effectiveness downstream of the film cookingrow. With an increase in deposit height, the coolant jet tentedto lift off, decreasing the film cooling effectiveness. Studies ofhole blockages showed that partially blocked holes have thegreatest detrimental effect on degrading film coolingeffectiveness downstream of a film cooling row. These effectsshould be considered when determining improved filmcooling designs so that partial hole blockages can be avoidedon turbine components (Sundaram and Thole, 2007).

Krishnan and others (2008) studied the effect of temperatureand salt deposition rate (particularly for sulphur derived salts)in the presence of film cooling. The operating temperaturegoverns the mechanism in hot corrosion to a large extent.Degradation due to hot corrosion is particularly high at twotemperatures. At 700° it is referred to as low temperature hotcorrosion or type II. The other high degradation appears attemperatures of 850–1000°C and is called high temperaturehot corrosion, or type I, which is mostly observed in aircraftengines. Although film cooling might be expected to reducethe corrosion rate, earlier work showed that it can evenincrease.

The analytical study concluded that film cooling impededboth the heat and mass transfer processes. The corrosioncould either increase or decrease, depending upon the blowingratio, mainstream velocity and coolant temperature. Theoptimum blowing ratio as regards good film coverage couldprove detrimental with regard to low temperature hotcorrosion. With film cooling there was a sharp rise in thecorrosion rate close to the cooling hole. The base superalloymay be exposed in this region. Hence designers shouldconsider the high corrosion rate seriously. While the corrosionrate peaked close to the hole for a mainstream velocity of600 m/s, it decreased significantly as the velocity wasreduced (300 m/s). Although film cooling is a commontechnique to reduce the surface temperature, the resultsindicated that it could prove detrimental with respect to lowtemperature hot corrosion. Proper optimisation of theoperating conditions and design methodology was thereforerecommended, particularly for turbines burning coal syngas.The study employed a simple resistance model with a generalfilm cooling effectiveness distribution and heat transfercoefficient enhancement distribution for various blowingratios. This provided a simple baseline predictionmethodology and set direction for optimisation needs. A more

sophisticated reaction model is necessary to providequantitative output for design optimisation (Krishnan andothers, 2008).

2.3 Comments

The wide variation in the composition of syngas from coaland its difference from that of natural gas is shown in Table 3which summarises the data cited in this chapter. Removingsome of the carbon may lead to an H2 content exceeding70 vol% (see Table 1). The high flame speed, high flametemperature and wide flammability range of H2, along withlow ignition energy and low density, cause major problems.Gas turbines are designed firstly to operate on natural gas.Most of their components have required modifications toovercome problems due to burning syngas, especially when it

16



is H2-rich. The modifications include:� compressor (surge protection by removing air to feed the

air separation unit or gasifier, extra row of compressorblades);

� fuel system (start-up fuel and diluent, ventilation, purgeand fire protection, materials resistant to H2 exposure);

� combustor (affected most, metal temperatures controlledby cooling air, thermal barrier coatings, or ceramic tiles,different flame configurations are under development,based on diffusion, premixed and catalytic combustors);

� turbine ( improvements in thermal barrier coatings andfilm cooling design to avoid overheating, corrosion,erosion and deposition).

Such modifications for retrofitting a gas turbine developed fornatural gas on IGCC are not considered to affect engineoperability and RAM.

Table 3 Summary of composition of natural gas and syngas from coal cited in Chapter 2

Fuel, vol% Natural gas Syngas, coal Syngas, coal Syngas, coal H2 syngas, coal

Gasifier Air blown Dry feed Slurry feed Slurry feed

CH4 85–97 3 0.01–2 0.1–0.2 0.1–4.6

H2 0 23 28–34 30–35 68–73

CO 0 7 55–70 41–50 1.1–4.7

CO2 0 20 1–10 10–14 1.8–2.6

N2 0–1 47 4.5–5 1–6 1.2–3.3

H2O <0.01 dry dry dry 17–20

CO/H2 0 0.3 2.0–2.4 1.4 0.02–0.07

LHV, MJ/m3 32–38 4.2 10.2–10.7 9.2–9.4

Diffusion combustors have been used for many years. Herethe fuel and air (or other oxidant) are injected separately intothe combustion chamber. Mixing by turbulent diffusion has totake place before combustion can occur (Pater, 2007). Thefuel burns at points where the mixture becomes combustible.Stability of the flame is achieved by a suitable recirculation inthe flow. This means that there are some very hot regions inthe flow and these are diluted with the air to reduce thetemperatures to acceptable levels before the hot gases enterthe turbine (Drnevich and others, 2004; IEA GHG, 2000).Hydrogen or any H2-rich gas requires diffusion flames and isunsuitable for premixed flame combustion (Molière, 2005)which is the subject of Chapter 4.

These processes within a conventional combustor aredescribed in the US DOE NETL’s gas turbine handbook bySamuelson (2006a). The size of the large scale mixingassociated with recirculation is in the order of the combustordiameter (see Figure 2). Turbulent eddies are generated withinthe reaction zone before breaking up, mixing with adjacenteddies and forming a new eddy. Some eddies, containingunreacted fuel and air, ignite while others wait to mix withother eddies to acquire sufficient energy at the necessarymixture ratio that is required for ignition. Hence a variety offuel/air packets are formed with a myriad of mixture ratios.As a result, mixing of the fuel and air does occur beforereaction of the individual packets. The extent to which, in theaggregate, the fuel and air mix prior to reaction depends uponthe fuel properties, the fuel and air injection hardware, and thetime for mixing prior to reaction. While the combustor is notpremixed (see Chapter 4), since the fuel and air are injectedseparately, the reaction is not strictly a diffusion flame.Instead, the reaction is partially-mixed and distributed. Non-premixed operation has been the preferred option due tosafety. However, the need to reduce pollutant emissions hasfocused interest on finding a reaction in the primary zone thatbehaves closer to a premixed reaction. To approach apremixed reaction, the fuel and air must be either intenselymixed after injection in a zone that precedes reaction butprecludes auto-ignition (rapidly mixed, non-premixed) orintroduced over a spatially large area through a large number


of discrete injection points (spatially injected, non-premixed).

Gas turbines fired on syngas from coal show combustioninstabilities unless design precautions are taken. The heatrelease in the flame fluctuates and the turbulent flamegenerates sound. If only a small fraction of the thermal poweris converted into noise, the amplitude of the pressurefluctuations is very high and may lead to failure ofcomponents. This thermo-acoustic noise interacts withturbulence, mixing and combustion of the flame andcomplicates the heat release in turbulent flames (Kok andKlein, 1999; Klein and Kok, 2002).

Greater thermal NOx production may result with the mediumcalorific value (9–13 MJ/m3) syngas from O2-blown gasifierswhich burns at a higher flame temperature than low calorificvalue (4 MJ/m3) syngas from air-blown gasifiers (Hasegawaand others, 2005). The higher stoichiometric flametemperature with H2 than with natural gas in diffusion flames,increases NOx production (IEA GHG, 2000). Thermal NOxproduction is approximately proportional to temperature tothe fifth power, and so the hot regions in the combustorproduce large amounts of NOx. These emissions may bereduced by injecting steam or water (IEA GHG, 2000) todilute and control the temperature (Shilling and Jones, 2004).Other diluents include N2 and CO2 to reduce the NOxformation (Drnevich and others, 2004). Also, hot/dry clean-upof the synthetic gas does not remove ammonia contained inthe gasified fuels. This is converted into fuel NOx which hasto be reduced both in the case of air-or O2-blown gasifiers(Hasegawa and others, 2005).

3.1 Operation

The main advantage of diffusion combustors is the flamestability which enables combustion of liquid and gaseousfuels with high flame speeds, such as coal gas (Drnevich andothers, 2004). They are less likely to experience burnerdamage caused by a flashback of the flame than premixcombustion systems (James and others, 2006). Currentburners for syngases or H2-enriched gases are run in diffusionmode with low air/fuel ratio as well as high laminar flamespeed and high primary zone temperatures. However,diffusion mode combustion is limited to only moderateturbine inlet temperatures due to the limited NOx abatementby dilution (Renzenbrink and others, 2006).

Diffusion combustion systems are used by GE for IGCCapplications. All GE gas turbines burning low calorific valuefuels have dual fuel capability, either dual gas or gas/liquid. Aconventional non-H2 bearing fuel is used for start-up and shutdown, as well as allowing for operation over the entire loadrange if load demand requirement cannot be satisfied bysyngas production (Jones and others, 2007a,b). For high H2

fuels, additional time and volume of purge gas must beprovided over normal syngas experience to ensure that fuellines are devoid of H2 following fuel transfers and shut-downs

3 Diffusion combustors

secondaryzoney

primaryzone

swirler dilutionzone

airair

airair

dilution jetsprimary jetswall cooling

axis of symmetryfuel

exhausthot products

Figure 2 Diffusion combustor features(Samuelson, 2006a)

(Jones and others, 2006). The diffusion combustor systems forIGCC control NOx by means of diluent injection. The earlydry low NOx combustors are limited to a maximum H2

content <10% due to the potential for flashback so the currentGE combustor in F-class machines for H2 containing fuels isthe IGCC version of the multi-nozzle quiet combustor(MNQC) (Payrhuber and others, 2007).

Potential high H2 applications are described (Jones andothers, 2006, 2007a; Shilling and Jones, 2004). GE completedfeasibility testing from 100% H2 to 100% CO fuel for a full-scale MNQC. Combustion testing was performed at full firingconditions on a full-scale 6FA combustor, originally reportedin 2000. The results showed that all combustor componenttemperatures, including combustor liner and nozzle tips, weremaintained within acceptable tolerance limits with lowcombustor dynamics. The 85–90% H2 case is representativeof pre-combustion removal of CO2 for enhanced oil recoveryor as CO2 storage, and allows for power plants to be nearlyfree of CO2. Fuel ratios of 40%/60%-50%/50% H2/N2 provideenhanced output in a modern IGCC gas turbine.

Anand and others (2005) concluded that IGCC efficiencygains from 40.5% to 43.3% and IGCC net output gains up to25% were possible by improving gas turbine technologyalone. The recommended gas turbine design at GE Energyshould have:� for the near term (2006), a 1316°C (2400°F) class firing

temperature, base class compressor pressure ratio,diffusion combustor, integrated air extraction;

� for mid-term (2008), a 1371°C (2500°F) class firingtemperature, base class compressor pressure ratio,diffusion combustor, integrated air extraction;

� for long term (2010), a 1427°C (2600°F) class firingtemperature, increased compressor pressure ratio,further combustion and hot gas path technologyenhancements.

Development of the advanced H2 turbine for the US DOE isbased on the SGT6-6000G gas turbine with its high firingtemperature, output power and efficiency, as well as itsadvanced secondary air and steam cooling systems. Severalcompeting combustion concepts such as diffusion flame,

18

Diffusion combustors


premixed and catalytic are being investigated (Bancalari andothers, 2006).

Current diffusion burners applied by Siemens on coal-firedIGCC plants in Europe (see Figure 3) are working with about10 vol% H2 in the fuel gas with acceptable NOx emissions butonly with a moderate firing temperature (1060°C and 1250°C;see Section 6.1.1) and dilution. The next step was a triple fuelsyngas burner (SGT5-4000F) concept developed in the FP5-project 2003-05 termed the high efficient gas turbine withsyngas application (HEGSA) project (see Figure 4). This hasbeen developed for F-class gas turbines and is based on theproven hybrid burner design of F-class engines combinedwith the syngas experience obtained with silo combustorengines. The syngas is supplied through two independentpassages: the natural gas diffusion passage, used for syngasafter switch-over and acting more or less as pilot, and theadditional main passage into a premixing nozzle. This mainsyngas/H2 enriched gas passage is arranged as an additionalring, around the basic standard HR3 burner, and is fedthrough several pipes. During syngas operation the mainsyngas flame is stabilised by a small syngas pilot flame. Testswith syngases confirmed the design but a small amount ofsteam was needed to reduce the high reactivity of CO and H2.For H2 enriched gases, base load operation without flashbackcould be achieved only by dilution with N2 and a significantamount of steam. Additional combustion tests were planned todemonstrate the potential for further minimising the requireddilution for flashback control in premix syngas mode, whilekeeping the fuel flexibility of the standard hybrid burner(Gadde and others, 2006b; Renzenbrink and others, 2006).

Tests to extend the gas turbine operating conditions using thediffusion burner of an Ansaldo Energia V94.2K gas turbine(see also Section 2.2) are described by Bonzani and Gobbo(2006). The composition of the undiluted syngas from thecoal gasification process of a typical IGCC plant included14.1 vol% N2, 26.9 vol% H2 and 59 vol% CO. It wasdemonstrated that feeding the burner with raw syngas dilutedwith 20 wt% N2 was safe to avoid flashback and humming butresulted in overheating inside the axial swirler. Dilution with40 wt% N2 was preferred as it gave a greater safety marginwith neither humming nor overheating. Tests from ignition up

200

150

100

50

0

Hydrogen content, vol %

Lam

inar

flam

e sp

eed

, %

250

300

50403020100 60

risk of overheating

standard syngascombustion system

maximum H2 forsteam dilution

maximum H2 forN2 dilution

ISAB

PuertollanoBuggenum

Servola

engine references

risk of lean blow-off

Figure 3 Siemens experience with syngas on E-class engines (Renzenbrink and others, 2006)

to change over to the main syngas line gave the following N2

dilution in the main operating points of the engine:

Ignition: 40 wt%Acceleration: 100 wt%Full speed, no load: 100 wt%Synchronisation: 100 wt%Loading up to change over: 40 wt%Change over: 40 wt%

Further investigation and tuning will have to be performed ona real engine in order to validate the N2 content in thetransient passage between the ignition and synchronisationworking conditions. This will allow a simpler regulation ofthe fuel system and, consequently, of the engine (Bonzani andGobbo, 2006).

The recent publications from Ansaldo Energia relate more tolow calorific value fuels with an LHV at 4–6 MJ/kg andinclude a summary of the performance of the V94.2 onnatural gas with the V94.2K and V94.2K2 on syngases (seeTable 4) (Bonzani and others, 2007, 2008).

A syngas fired gas turbine may be fired with a variety of

19



fuels, for example start-up with natural gas, coal and biomass.Some of the European IGCC plants suffered from acousticproblems in the combustion chamber of the gas turbine (seeKok and Klein, 1999; Klein and Kok, 2002). When thecombustion process fell into unstable modes, causing greatmechanical damage, experience showed that the addition ofCH4 to the fuel mixture usually solved the problem. Hence itis assumed that fuels containing CH4 are less sensitive toacoustic instabilities than fuels that do not. The influence ofCH4 in the syngas on thermo-acoustic instabilities wasinvestigated by means of computational fluid dynamicssimulations. Two different synfuel compositions wereconsidered: one with (7) and the other without CH4 (6) inaddition to H2, CO and N2. The flame transfer function is animportant parameter in the identification of thermo-acousticinstabilities in gas turbine combustion installations. It showsthe relation between a perturbation in the fuel mass flow andthe response of the flame, in terms of heat releasefluctuations. The response of syngas 6 showed a strongoscillatory behaviour. The response of syngas 7 is in adamped form. This is probably explained by the differences inchemical time scales, which are longer with CH4. CompleteCH4 combustion is slower than CO combustion and certainlyslower than H2 combustion. This could be a reason for the

fuel oil (diffusion)

syngas 2/NG (diffusion)

air

natural gas (premix)

syngas 1(premix)

fuel gas (premix)

a) triple-fuel syngas burner b) prototype of advanced burner

air air

Figure 4 Triple-fuel syngas burner (Renzenbrink and others, 2006)

Table 4 Performance comparison of the V94.2 gas turbine on different fuels (Bonzani and others, 2007,2008)

Gas turbine model SGT5-2000E (V94.2) V94.2K V94.2K2

Fuel natural gas syngas syngas

Power output at generator terminals, MW 166 170 170

Grid frequency, Hz 50 50 50

Pressure ratio 11.8 12.0 10.7

Exhaust gas mass flow, kg/s 531 540 511

Exhaust gas temperature, °C 544 545 559

Efficiency at generator terminals, % 34.5 36 36

Lower heating value, MJ/kg 50 9 4

effect of CH4 addition to the syngas (Pater and others, 2006;Pater, 2007).

Figure 5 shows the time delay of the heat release of the fuelflow after leaving the burner mouth for both syngas 6 withoutCH4 and syngas 7 with 6.2 wt% CH4. The peak heat release aswell as the total time of heat release was longer for syngas 7than for syngas 6. This is a possible cause of the difference inflame transfer functions between the syngases. It is concludedthat syngas without CH4 responds to perturbations up to highfrequencies. This results from the short delay times in bothchemistry and convection. Addition of CH4 reduces thisresponse. The main reason for this reduction is that the flowvelocities are lower than the flow velocities in the syngaswithout CH4.. This does not necessarily lead to longer flames,but to longer delay times between perturbation and response.As the calculation of the flame transfer function is based onheat release in the flame, it can be concluded that the flametransfer function is highly dependent on the velocity of theflow. For turbine manufacturers this can mean the use of fuelswith a higher calorific value and also the use of lowervelocities (Pater and others, 2006).

Different burner designs can be compared using suchparameter studies of the flame transfer function. At themoment this is time consuming. Hence efficient algorithmshave to be developed to overcome this problem. If the flametransfer function is known, it can be placed in a model of theacoustic system of a gas turbine combustion chamber. If totaldamping in the acoustic system is possible, it should bepossible to predict whether the gas turbine will showcombustion instabilities or not (Klein and Kok, 2002).

A feasibility study of converting an existing combined cyclegas turbine to fire on a coal-derived syngas by E.ON UKconcluded that a gas turbine fitted with a dual-fired MNQCcould operate over 100% of its load range on natural gas andfrom around 30% to 100% load on syngas. Start-up times tofull load on the VEGA 109FA units when operating on syngaswould be expected to be the same as with natural gas. Start-up

20



would be on natural gas with fuel switchover at about 30%load. Start-up times would be 210 minutes for a cold start,150 minutes for a warm start and 80 minutes for a hot start tobaseload. The availability was predicted to increase from 80%in the first year to around 90% after the second year. Thebiggest design risks associated with a conversion of the gasturbine were predicted to be combustion dynamics, life of thehot gas path components, start-up damage and overheating ofthe combustion system (James and others, 2006).

3.2 Pollutant emissions

The formation of NOx emissions may be broadly categorisedas thermally generated, flame generated, or from fuel-boundNOx. Thermal NOx requires sufficient temperature and timeto produce NOx. Below about 1700K, the residence time intypical gas turbine combustors is not long enough to producesignificant thermal NOx. Where temperatures higher than1700K cannot be avoided, it is necessary to limit theresidence time to control NOx formation. This favours shortcombustor designs (Strakey and others, 2006).

Flame-generated NOx occurs in the flame front and isindependent of residence time. There are a variety of chemicalmechanisms involved, all linked to intermediate combustionspecies that exist only in the reaction zone of the flame. NOxformation depends on the flame temperature and poorpremixing may increase NOx formation by as much as afactor of three in turbulent flames. This may happen wherecombustion products are mixed with the fresh reactants rightat the flame. It has been suggested that combustionconfigurations, without significant stirring between the flamefront and products, may reduce the flame generated NOx.This may be the basis for NOx reductions reported in the low-swirl combustors (Strakey and others, 2006).

Fuel NOx is produced by nitrogen species in the fuel reactingwith air during combustion. For coal syngas, the mostprominent fuel nitrogen species is ammonia. Ammonia shouldideally be removed from the fuel before entering thecombustor or it will be converted to NOx by most combustionsystems. Where this is not possible, rich-lean strategies havethe most potential to reduce NOx pollutants. In this approach,combustion is first carried out under fuel-rich conditions andthen completed under fuel lean conditions. Studies haveshown that as much as 95% of the fuel ammonia can bereduced to N2 and water using rich-lean combustion.Ammonia concentrations in untreated syngas can exceed1000 ppm, where even 5% conversion would lead to 50 ppmNOx, which is well above emission limits. Hence it isdesirable to remove fuel ammonia during gas clean-up(Richards, 2006). In H2-fuelled systems, the prominence ofH radicals may contribute to NOx in a different manner fromthat in systems fuelled with natural gas. Hence researchcontinues to understand the most prominent mechanisms atultra low NOx conditions (Strakey and others, 2006).

3.2.1 Diluents for NOx reduction

The disadvantage of diffusion combustors is that the flame

0.6

0.4

0.2

0

1.5

Time delay, ms

Nor

mal

ised

hea

t rel

ease

in fl

ame

0.8

1 Syngas 6Syngas 7

10.50 2

Figure 5 Heat release of syngases depending onthe delay time after leaving the burner(Pater and others, 2006)

zone temperature is inherently higher than a premixed systemand substantial quantities of NOx are produced. Tests onIGCC systems, using syngas with diffusion flames, haveshown that the addition of diluents such as N2, CO2, or steamcan substantially reduce NOx emissions. However, the mixingwith the diluent is incomplete so that the flame temperaturecannot be lowered to the same degree as a premixed system(Drnevich and others, 2004).

IGCC plants with an O2-blown gasifier are equipped with anair separation unit. This provides a freely available supply ofN2 that would otherwise be discarded but can be blended withthe syngas fuel. Dilution of the fuel with N2 significantlyreduces or eliminates the requirement for steam to be takenfrom the steam cycle, thereby improving overall cycleefficiency. Nitrogen dilution also has a less negative effect onthe life of the hot gas path components, compared to steamdilution (James and others, 2006). Hydrogen could be dilutedup to about 50% with N2 in a typical IGCC configuration.Unfortunately, this degree of dilution produces an adiabaticflame temperature around 2025 K which is still too high forultra-low NOx performance (Richards, 2006; Strakey andothers, 2006).

Steam injection as a NOx diluent is used in those cases whereN2 is limited in availability, such as with air-blown gasifiersand membrane H2 separation (Jones and others, 2007a,b;Shilling and Jones, 2004). This is not completely desirable.The extra energy required to make steam is not recovered,penalizing the cycle efficiency, (but raising power output fromthe added mass flow). Additional steam in the exhaustproduces a modest increase in the turbine nozzle heat transfer,raising metal temperatures. The protective thermal oxidelayers in turbine material sets can be affected by increasedmoisture. Finally, steam consumption by stationary turbinesshould be minimised to conserve water resources. For thesereasons, any further development of diffusion flamecombustors for IGCC applications would ideally use N2 ratherthan steam (Richards, 2006).

Dilution with CO2 has a greater NOx reduction effect than N2

but is not appropriate for an IGCC plant with carbon capture.It would allow combustion of syngas in an undiluted form in acapture-ready plant, that is prior to the carbon capture plantbeing commissioned (James and others, 2006).

An inert diluent, presumably N2, is used by GE for NOxcontrol in IGCC applications of diffusion combustors. Thefeasibility test results with 100% H2 to 100% CO for a full-scale MNQC are shown in Figure 6. Fuel ratios of40%/60%-50%/50% H2/N2 can produce very low NOxemissions in a modern IGCC gas turbine (see alsoSection 3.1) (Jones and others, 2007a).

At Siemens, base load operation for H2 enriched gaseswithout flashback could be achieved only by dilution with N2

and a significant amount of steam (see Section 3.1). Thisreduced the formation of NOx (Renzenbrink and others,2006).

Combustion tests on the hybrid SGT5-4000F gas turbineusing syngases containing different amounts of H2 (13–17%,

21



25–30%, 30–40%) produced NOx emissions <5 ppm and CO<1 ppm (at 15% O2) using steam diluent. No further dilutionwith N2 was necessary from the combustion point of view. Ifthe overall plant concept provides additional N2, it can easilybe mixed with the combustion air without any negativeinfluence on the combustion performance. The syngas canalso be blended with natural gas. Syngas capable designswere investigated, based on the SGT6-5000F and SGT6-6000G combustion systems which have demonstrated reliableoperation on natural gas and distillate oil. The combustors metdesign goals for syngas operation in an IGCC and furtheremissions testing was planned for the higher temperature, airflow and pressure in the SGT6-6000G combustor (Gadde andothers, 2006b).

Diffusion flame technology with diluent injection is 30 yearsold and the challenge, according to Payrhuber and others(2007), is to develop new advanced low NOx combustiontechnology for high H2 fuels without the need for diluent. Thenew combustion technology needs to be robust and scaleable,balancing the tradeoffs between operability, flashbacktolerance, cost, life of equipment and emissions.

3.2.2 Combustion measures

Various techniques to reduce NOx emissions include designsbased on staged combustion, lean direct injection, highlystrained diffusion flame and oxyfuel combustion. Furtherreductions may be achieved by SCR which is convenientlyincluded here.

Staged combustionA hybrid, low emission burner was developed and tested witha GT 750-6, used for gas transport at gas pipelines in severalcountries in Europe. Pre-combustion is required to meetemission targets safely after 2015. This combines a leanmixture with diffusion combustion. The hybrid burner hasadjustment of the primary air flow through a circular flowregulator valve. This turns in a casing and both are perforated

10

0

1.8

Steam/fuel, kg/kg

NO

x at

15%

O2,

pp

mvd

100

1000

(*) T exit 100-200 K lower

85-90% H2/bal N2

73-77% H2/bal N2

56-60% H2/bal H2Oprimary-nominal46% H2/13% H2O/bal N2

1.61.00.80.60.40.20 2.01.41.2

Figure 6 NOx emissions mapping for H2 fuelcontent (Jones and others, 2007a)

to allow changes in the flow cross section in addition to thethroughput. Test results enabled the concept for the modulesystem to be made for the combustion chamber of the GT750-6. The NOx emissions were �50 mg/m3 in the operatingrange of 40–100%. The module could be used on other typesof gas turbines such as frames 2–6. Further developmentsmust achieve good mixing of the fuel and air in the mixingchamber of the hybrid burner. This will reduce NOxemissions to below 30 mg/m3 (Veselý and others, 2008).

Experiments from CRIEPI, Japan, using a small diffusionburner for fuels from air-blown and O2-blown gasifiers, aredescribed by Hasegawa and others (2005). Flame stabilitywas achieved by means of an auxiliary combustion chamberat the entrance to the combustor, taking 15% of the totalamount of fuel. The rest of the fuel was introduced into themain combustion zone from around the exit of the auxiliarycombustion chamber. The combustor liner wall temperaturewas maintained at below 850°C by equipping the combustorwith a dual-structure transition piece. The cooling air in thetransition piece could be recycled to cool the combustor linerwall. The cooling air flowing into the transition piece fromthe exterior wall cooled the interior wall by impingement andmoved to the upper side of the combustor liner. Combinedimpingement and film cooling was used for the auxiliarycombustor and primary combustion zone where temperatureswere expected to be especially high. Film cooling was usedfor the secondary combustion zone.

A two-stage, rich-lean combustion method was introduced toreduce fuel NOx production (from NH3 in the fuel), by usinga two chamber structure to separate the primary from thesecondary combustion zone. Primary air inlet holes wereremoved in order to maintain the fuel-rich conditions in theprimary combustion zone. In addition, the equivalence ratio ofthe primary combustor was set at 1.6 (fuel rich), based onprevious tests to minimise the NOx conversion rate. The fueland combustion air were premixed by injection through themain swirler. Also, the secondary air was slowed down byinstalling an exterior wall at the secondary air inlet section tomake an intermediate pressure zone of the dual structure. This

22



decreased the flow speed of the secondary air from 120 m/s to70 m/s and weakened secondary air mixing to reduceconversion of NH3 in the fuel to NOx (Hasegawa and others,2005).

Tests were carried out using syngas from an air-blowngasification system with hot dry gas clean-up. Thecomposition of the synfuel was adjusted to be the same as thatfrom the air blown, entrained flow IGCC gasifier given inTable 2. At a turbine load of 25% or higher, the conversionrate of NH3 to NOx was reduced to 40%, giving NOxemissions of 60 ppm (at 16% O2), while the combustionefficiency was around 100% for each gas turbine load(Hasegawa and others, 2005).

Tests with syngas from an O2-blown gasifier with wet gasclean-up deployed the large quantity of N2 produced in the airseparation unit to decrease the greater thermal NOx emissionsproduced. The N2 was not blended with the fuel but injectedinto the primary combustion zone to reduce thermal NOxformation. The primary zone had fuel lean conditions toachieve low NOx and stable combustion over a wide range ofturn-down operations. The thermal NOx production wasreduced to one fifth of that with no N2 injection. Nitrogen wasbypassed and premixed with the combustion air to maintain astable flame under partial load conditions. At a turbine load of25% or higher, the NOx emissions were reduced to 11 ppm(at 16% O2), increasing slightly with gas turbine load. Thecombustion efficiency was around 100% (Hasegawa andothers, 2005).

Tests with syngas from an O2-blown gasifier using hot dry gasclean-up required a combination of the above measures forfuel NOx, from NH3 which could not be removed, and thethermal NOx. Additionally, N2 injection had to be tailored soas to decrease the power to compress N2 which was returnedinto the gas turbine in order to recover a part of the powerused for the air separation unit. The design concept for a1500°C class combustor is shown in Figure 7. An auxiliarycombustion chamber, taking 30% of the total amount of fuel,was installed at the entrance to the combustor. The N2

stable combustion• auxiliary combustor

reduction of thermal NOx• nitrogen direct injection lowers the flame temperature

fuelN2

air

by secondary-air,unburnt fuel is combusted

secondary air holesreduction of fuel NOx

reducing flamedecomposes NH3 to N2

Figure 7 Design concept of a gas turbine combustor for medium heating value synfuel after hot drycleanup (Hasegawa and others, 2005)

injection nozzles were set up in the main swirler which was atthe exit of the auxiliary combustion chamber. It was foundpreferable to premix the N2 with the syngas to decreaseemissions of both thermal and fuel NOx but careful attentionhad to be paid to the homogeneity of the mixture in order toprevent an increase in thermal NOx production. Premixing N2

with the primary combustion air gave slightly higheremissions and an increase in the power to compress N2,leading to a decrease in the thermal efficiency of the plant.When the syngas contained 0.1% CH4 and 500 ppm NH3,total NOx emissions were 34 ppm (at 16% O2) at gas turbineloads of 25% or higher, tending to increase slightly with load.With simulated fuel containing no NH3, the thermal NOxemissions were 8 ppm (at 16% O2). Combustion efficiencywas expected to be around 100% (Hasegawa and others,2005).

SCRThe best case, practical NOx reduction limit for non-premixedsyngas combustors is between 10 and 20 ppmv. Furtherreductions in NOx emissions to reach the 3 ppm regulatedlimit requires SCR but this will not work unless the sulphur isremoved from the syngas. For example, the Polk IGCC powerplant, FL, USA, has experienced some sulphur deposits on thetube surfaces of the heat recovery steam generator (HRSG).Any additional deposits that would be generated by theaddition of an SCR unit would make the plant inoperable onsyngas in its current configuration (Steele and Baldwin,2006). Future IGCC plants will be able to use SCR forstringent NOx control with physical scrubbing systems suchas Selexol or Rectisol which reduce sulphur gases sufficientlyto avoid sulphate deposition in the HRSG (Henderson, 2008).

However, Klein (2009) points out that system efficiency andreliability are more important goals than zero NOx emissions.An SCR system increases both CO2 and N2O emissions andthese greenhouse gas emissions have to be considered.

Lean direct injection, highly strained diffusionflame and oxyfuel combustionFurther developments to overcome the dilution limit to reducethe diffusion flame temperature are considered by Richards(2006). The diffusion flame temperature is set by the ratio ofthermal diffusion away from the reaction zone to heatgenerated by reactants. If the reaction zone is ‘strained’ byfluid shear, it is possible to change the balance betweendiffusion and reaction in the reaction zone, changing theflame temperature. Strongly sheared flows can locallyextinguish the flame, providing opportunity for fuel airmixing before combustion is initiated elsewhere. This raisesthe possibility that strong shearing could be used to make adiffusion flame combustor behave more like a premixedcombustor (see Chapter 4). The required amounts of shearing,known as stretch or strain, have not been fully characterised.The concepts are lean direct injection and highly straineddiffusion flame combustors.

Lean direct injection combustion was developed to reduceNOx emissions from aircraft gas turbines. The fuel is injectedinto the combustion chamber where it is mixed with air in theshortest possible distance in order to provide an essentiallylean premixed fuel/air mixture that burns in a low NOx flame.

23



The jets of fuel and air introduce high strain rates in thecombustion zone. The technique was tested for its potential toburn pure H2 in gas turbines. More fuel injection ports per airjet reduced NOx emissions due to higher fuel jet momentumand mixing. Increasing the number and decreasing the size ofthe air jets was shown to lower NOx emissions by reducingthe length of the combustion zone, although this came at theexpense of increased combustor pressure drop. This may havebeen required to reduce flashback or flameholding potential.Dilution with N2 would lower flame speeds and may reducethe need for large injector pressure drops and high airvelocities to avoid these issues (Richards, 2006).

Highly strained diffusion flame combustion prevents localreactions from completing before the flow carries thecombustion radicals away from the reaction zone. Increasedstrain rates are a possible path to reducing or effectivelyeliminating thermal NOx in a diluted diffusion flame.Impinging fuel and air jet injector configurations have anadvantage over co-axial jet configurations, as forced mixingof the fuel and air should improve the flameholding abilitiesof these diffusion flames. More studies are required todetermine injector configurations that maximise flame strainwhile minimising concerns about stability and combustorpressure drop. The effects of increased flame strain oncombustion efficiency and on in-flame NOx productionmechanisms also require further investigation (Richards,2006).

Oxyfuel combustion for power cycles, proposed as a means ofcapturing CO2 from engine operations, is most easily appliedto diffusion flame combustors. This is because of theirstability and simple operation. There is no need to controlNOx emissions if the combustion products are stored, andthere is otherwise little N2 in the combustor. Even withoutstorage, the peak flame temperature in diffusion flames can becontrolled by the amount of diluent added, thereby avoidingNOx formation (Richards, 2006; Strakey and others, 2006).

3.3 Comments

The diffusion combustor is the most commonly usedtechnology for burning syngas and earlier problems have beenovercome in current, commercial IGCC. Early dry low NOxcombustors were limited to a maximum H2 content of only<10%, to avoid flashback. Dilution with N2 and steamenabled use of syngases with higher H2 content. Gas turbinesare being developed to operate on syngases with greater H2

contents (40–50%) and at higher firing temperatures(>1400°C). NOx emissions are reduced by steam or N2

diluents but this may be achieved partly by using combustionmeasures. These include two-stage, rich-lean combustion,lean direct injection, and highly strained diffusion flamecombustors. Future IGCC plants will be able to use SCR forfinal NOx reductions.

Although diffusion burners, which give rise to high NOxemissions on H2 fuel, are the only systems that can currentlybe used, other technologies are being explored and may bringcommercial solutions in the long term. Research programmesare developing premix H2 burners for syngases, sometimesincluding modifications to introduce elements of diffusioncombustion (Henderson, 2008).

Premixing is a means of overcoming the problem of highNOx emissions in diffusion flames, without resort to H2Oinjection. The basic principle is that the air and fuel are wellmixed before the combustor. Mixing may occur before or inthe combustion chamber. This gives a uniform flamerelatively free of ‘hot spots’ and therefore minimum NOx areproduced for a given average flame temperature. However,perfect premixing is difficult to achieve because the timerequired (or the length of the premixing duct) may beconstrained by increased possibility of ‘auto ignition’.Further, lowering the flame zone fuel to air ratio moves thecombustor design closer to its ‘weak extinction limit’. Oneconsequence of this is that such designs may have limitationsin terms of transient performance, particularly in the contextof load shedding (IEA GHG, 2000).

Useful definitions are given by the US DOE NETL gasturbine handbook. The fuel to air ratio normalised by thestoichiometric value is known as the equivalence ratio. Thishas a value of slightly more than 0.5 in many practicalpremixed turbine combustors. Thus approximately half thefuel is needed to burn all the air, or conversely twice as muchair is needed to burn all the fuel. The excess air serves todilute the combustion and keep the flame temperatures lowenough to avoid thermal NOx formation (Richards, 2006;Strakey and others, 2006). Combustion using different typesof fuel is readily described as lean for an equivalence ratio <1or rich if it is >1 (Bender, 2006).

The premixed combustor must operate in a very narrow rangeof equivalence ratio, the lower limit to avoid blowout (seeSection 2.2.3) at typically <0.5 and increasing NOxformation at the upper limit of a little over 0.6. Thecombustor controls must include some form of staging, sincethe range of desired exit temperatures usually cannot beachieved with such a small range of equivalence ratio. Forexample, if four fuel injectors are used in a combustor, it ispossible to reduce the heat input 50% by keeping twoinjectors operating, but turning two off. The difficulty withthis approach is that the air flow from inactive injectors canquench the boundary of the flame from operating injectors,raising CO emissions. However, this can be addressed withgood aerodynamic design. Beyond simply de-activatinginjectors, staging is also accomplished by operating someinjectors at slightly richer equivalence ratios, to improveflame stability. This can be achieved by using ‘pilots’ onindividual injectors. The pilot flame is typically suppliedwith some air for partial premixing, and the pilot fuel circuitis controlled to achieve stable combustion at the lowestpossible NOx emissions, by means of tuning the fuel delivery


and combustor control. Diagnosing conditions in thecombustor are important for combustion tuning and control.There is potential for using optical signals, acoustic signals,or flame ionisation to monitor and control the combustionprocess (for details see Richards, 2006; Strakey and others,2006).

Within the lean premix staged concept, a number ofpossible solutions are available. The first stage or stages areusually used for low power operation. Subsequent stagesare brought into operation as the engine power is increased.Premixed combustors using lean or weak fuel air ratios areprone to combustion pulsation. Nonetheless, maximumflame temperatures within the burning zone tend to besignificantly reduced over those typically involved withcombustion systems employing diffusion flames (IEAGHG, 2000).

Use of leaner fuel mixtures that reduce the flame temperatureand therefore thermal NOx formation is the basis for dry lowNOx combustor operation (Drnevich and others, 2004). Thisis also referred to as lean premixed combustion and hasbecome the standard technique for gas turbine originalequipment manufacturers, particularly for natural gasapplications. Its increased combustion efficiency compared todiffusion flame technology has reduced not only emissions ofNOx but CO and volatile organic compounds. A leanpremixed turbine may operate in diffusion flame mode duringoperating conditions such as start-up and shut-down, low ortransient loads and cold ambient (Bender, 2006).

If a lean premixed engine is already near the limits of leanoperation at full power, it is not possible to reduce thecombustor temperature rise on all of the fuel injectors,because the flame would be extinguished. The flame may bekept within its operating boundaries by using fuel or airstaging. Fuel staging may be accomplished radially, forinstance by using pilot flames or reducing/eliminating fuelfrom some injectors completely. Alternatively, axial fuelstaging injects fuel at two places along the combustion gasflow path. Products from the first combustion zone aremixed with fuel and air in a subsequent combustion zone,providing an advantage for lean operation of the secondzone. Finally, some engine designs use air staging, alsoknown as variable geometry, to accomplish the goal ofmaintaining low flame temperatures. This approach canmaintain the desired combustion zone temperature at alloperating conditions, but adds the complexity of having tocontrol the large volume flow of combustion air. Syngaseswith low heating value have lower flame temperatures andflame speeds than natural gas (see Section 2.1) which resultsin lower thermal NOx emissions. The greater volume of fuelflow requires different combustor aerodynamics and thesemust be redesigned. This may affect low-emission back-upoperation on conventional fuels. Advances in turbinesystems for natural gas are critical to achieving performancegoals for future coal-based IGCC plants operating on syngasand H2 (Bender, 2006).

4 Premixed combustors

4.1 Tests with syngas/H2

For premixed operation, flashback and pre-ignition are safetyand turbine performance concerns (Walton and others, 2007),discussed in Section 2.2.2. The ability of the flame toflashback increases as the flame speed of the fuel increases.This happens as H2 is added to a fuel. For example, a modelcoal gas containing 40% H2, 51% CO, 8.5% CO2, and 0.5%H2O had a laminar flame speed of about 48 cm/s in its rawform but the flame speed decreased considerably as diluent N2

was added. At about 50% N2 addition, the flame speed wasabout 20 cm/s and comparable to that of pure CH4 (Drnevichand others, 2004).

At the Georgia Institute of Technology, Atlanta, GA, USA,Noble and others (2006) present experimental data detailingsensitivities of flashback and lean blowout (see alsoSection 2.2.3) limits to the widely varying fuel compositionof syngas mixtures. Different flashback mechanisms werefound for different fuel compositions. For low H2 mixtures atlower pressures, the flame anchoring location movedgradually upstream (along the centerbody) with increasedequivalence ratio. In other words, flashback was not adiscontinuous phenomenon where the flame actuallypropagated upstream into the premixer in a rapid manner.Flame temperature was the key parameter describing thetendency to this kind of flashback. For high H2 mixtures andhigher combustor pressures, flashback occurred abruptly,triggered by only a slight change in mixture stoichiometry,and the flame propagated upstream into the premixer. Thismechanism depended greatly on the percentage of H2,

increasing with reactant preheat and combustor pressure.

The H2 content of the fuel had far less an effect on the slowflashback limits than expected, for fuels with H2 molarfractions less than 60% and combustor pressure less than 7atmospheres (0.7 MPa). In these instances, where the flamespeed is never high enough to propagate upstream, the flamecan possibly manipulate the region of vortex breakdown byimposing an adverse pressure gradient ahead of the flame.Such a mechanism would be far less sensitive to the flamespeed but a strong function of the temperature ratio across theflame, as shown by these measurements (Noble and others,2006).

Blowout can also be expected to be a serious issue, given thevariability of the fuels burned in fuel flexible combustors,particularly because achieving low emissions requiresoperating near the blowout limits of the system. In manycases during the experiments, the flame blew off abruptlywith a small change in fuel composition, although sometimespreceded by slight lift-off from the burner. Defining theblowoff point was unambiguous in these instances; moreover,the point of blowoff and of flame lift-off was nearly identical.This was the case for mixtures composed largely of CH4 orCO. However, for mixtures with greater than about 60% H2,the blowoff and lift-off events were quite distinct. Usually theflame became visibly weaker, lifted off from the holder, andmoved progressively downstream with decreases inequivalence ratio before blowing off for good (Noble andothers, 2006; Zhang and others, 2005).

25

Premixed combustors


At Sandia National Laboratories, Livermore, CA, USA,Williams and others (2006, 2008) examined the effect of H2

content in syngas on the emissions from a laboratory-scale,optically accessible, swirl-stabilised premixed gas turbinecombustor. The syngases shown in Table 1 were comparedwith pure CH4, an H2-lean syngas and an H2-rich syngas. Thelatter two cases require evaluation as they represent the twoconcepts for IGCC with CO2 storage and H2 production,involving shift reaction or the oxyfuel combustor IGCCconcept (see Section 6.2). The fuels were burned aspremixtures in air and in CO2-diluted O2 at atmosphericpressure. The global flame structures were analysed forequivalence ratios varying from the lean blow-off limit toslightly rich conditions. The greater H2 content of the syngasincreased flame stability, NOx emissions, and burning rate,allowing operation at very lean stoichiometries. Dilute O2

power systems would necessarily operate near thestoichiometric point and here the CO emissions wereinsignificant until the equivalence ratio exceeded 0.95. At thispoint, CO emissions increased more rapidly for combustion inO2-CO2 mixtures than for combustion in air. Other than thisminor difference, the presence of high concentrations of CO2

in the CO2-diluted O2 flames was not found to have asignificant effect on burner performance or emissions.Operation of the near-stoichiometric CO2-diluted O2 flames atO2 concentrations of 20–24% was found to be promising forachieving low emissions of both CO and NOx.

The gas turbine combustors with premixed flames presentedby Jones (2006) at GE are dry low NOx combustors operatingwith <5–10% H2 in the synfuel. Fuels with low H2 content aredifficult to burn and often require fuel enrichment to increasetheir heating value and flammability. Fuels with high H2

content have a high flame velocity that makes standard drylow NOx premixing techniques difficult to employ due to thepotential for flashback or flame holding into the premixer. GEis developing multiple approaches to H2-rich fuel combustion,allowing combustion at higher flame temperatures forincreased efficiency with low emissions and low-to-no diluentrequired using advanced premix technology. This is inaddition to further improvements to current diffusion flametechnology (see Section 3.1). Test results using a variety ofH2/N2 and H2/CH4 mixes indicate that the swirl premixcombustor achieves lower NOx emissions at higher flametemperature than the current multi nozzle quiet and advanceddiffusion combustors (Jones and others, 2006, 2007a).

4.2 Developments

The Siemens triple-fuel syngas burner (see Figure 4 andSections 3.1 and 3.2), developed in the EU FrameworkProgramme 5 (2003-05) from the standard HR3 burner,includes a premixing nozzle. However, as noted above,dilution with N2 and a significant amount of steam wererequired for H2-enriched gases. The formation of NOx wasclearly reduced (Renzenbrink and others, 2006).

The ENCAP SP2, within the EU Framework Programme 6(2006-09), requires development of a combustor that can burnH2 under high pressure. Two European turbine manufacturers,Siemens and Alstom, are collaborating on the further

development of their respective burner designs to enable thesafe combustion of H2-rich mixtures with H2 contentapproaching 100%. The HR3 burner is being used as asuitable platform by Siemens and the EV unit by Alstom. Thedistinguishing feature of the EV MBtu unit relative to thestandard, natural gas fired version, is that the syngas fuel isinjected perpendicular to the air flow at the burner exit, ratherthan in the combustion air slots (see Figure 8). In essence, thelean-premix burner has been converted into a largelydiffusion-type burner, in which 55% N2 dilution is necessaryin order to comply with stringent NOx regulations (Carroni,2006; Lenze and Carroni, no date). Buschsieweke (2008)concludes that premix burners for IGCC with CO2 capture areunder development but not finished within ENCAP SP2. Thedevelopment of an H2 burner is challenging but feasible.

Within the Advanced Hydrogen Turbine Development Projectin the USA, H2 fuel mixing studies were performed usingcomputational fluid dynamics on a premixed swirler fuelinjection design. The H2 fuel mixing characteristics werecompared with existing natural gas results. This was todetermine if design changes are required prior to performing arig test on H2 fuel. The development work started from theSGT6-6000G gas turbine and will be adapted for operation oncoal and biomass derived H2 and syngas fuels, as well asnatural gas. The aim is to achieve high performance andreduced capital costs and validation of the advanced gasturbine technology by 2015 (Bancalari and others, 2006).

Premixed systems as well as diffusion flame combustors wereto be tested by Siemens in the summer of 2006 at elevatedfiring temperatures and pressures on diluted syngas and H2.Hydrogen was deemed the most challenging fuel beingconsidered for the Advanced Hydrogen Turbine Developmentproject (Phases 1 and 2) of the US DOE, due to its high flamespeed, propensity for flashback and higher dilutionrequirement for NOx emissions abatement, flame speed andflashback abatement. The higher temperatures will requireadvanced or novel materials (Bancalari and others, 2006).

Flame holding and emissions have been tested at GE on a‘state of the art’ premix swirler nozzle, now ready for

26

Premixed combustors


production, using a variety of H2/N2 and H2/CH4 mixes,including pure H2. The velocities in the premixing sectionwere gradually increased until stable combustion wasachieved downstream of the burner tube. Emissions weremeasured at the combustor exit. NOx emissions were verylow for H2 rich fuels and flame holding/flashback could beconsistently avoided at high enough burner tube velocities(Payrhuber and others, 2007).

Ramgen Power Systems is developing an advanced vortexcombustion (AVC) technology for H2-based fuels. Here theflame stabilisation is accomplished by a stable vortex that isproduced adjacent to the main fuel-air flow path. The vortexbehaviour is virtually independent of the main flowcharacteristics and must provide stabilisation by lateralmixing from the vortex region into the main flow. Therecirculation of hot products into the main fuel-air mixture isaccomplished by incorporating two critical features. First astable recirculation zone must be generated adjacent to themain fuel-air flow. If the vortex region, or cavity region, isdesigned properly, the vortex is stable and no vortex sheddingoccurs. This stable vortex is generally used as a source of heator hot products of combustion. Second, the transport andmixing of the heat from the vortex generally uses wakeregions generated by bodies, or struts, immersed in the mainflow. This ignites the incoming fuel-air mixture by lateralmixing, instead of a back-mixing process. By using geometricfeatures to ignite the incoming fuel-air mixture, instead ofpure aerodynamic features, the AVC concept has the potentialto be less sensitive to instabilities and process upsets. This isparticularly important near the lean flame extinction limit,where small perturbations in the flow can lead to flameextinction (Steele and Baldwin, 2006).

Steele (2006) explains such a trapped vortex combustion indetail (see Figure 9). A conventional bluff or fore body islocated upstream of a smaller bluff body, commonly referredto as an aft body. The flow issuing from around the first bluffbody separates as normal; but the alternating array of vorticesare conveniently trapped or locked between the two bodiesinstead of developing shear layer instabilities which, in mostcircumstances, is the prime mechanism for initiating blowout.

flow direction

gas injection holes combustion air

flame front MBtu - fuel

vortex breakdown

Figure 8 Concept of the EV MBtu burner (Carroni, 2006; Lenze and Carroni, ND)

Early research has demonstrated the trapped vortexconfiguration can withstand throughput velocities nearMach 1. This provides a mechanism that can overcome thehigh flame speed of H2-rich syngas and potentially allowIGCC gas turbines to operate the combustor in premixedmode. This system configuration also has greater flameholding surface area and hence will facilitate the morecompact primary/core flame zone essential to promoting highcombustion efficiency and reduced CO emissions.

The concept has been tested on natural gas and has potentialto operate in a low NOx, lean premixed combustor on H2-richsyngas, accommodating its high flame speed. It wouldeliminate the need for high pressure diluent gas for NOxreduction and post-combustion control. More types of gasturbine could be used for IGCC applications, by decreasingthe mass flow through the turbine section. The overall cycleefficiency of the gas turbine would be improved by decreasingthe pressure drop through the combustor and the lean blowoutlimit would be extended, offering greater turndown (loadfollowing), with improved combustion and process stability(Steele and Baldwin, 2006). Differences between the conceptsunder development at Ramgen Power Systems and ALMTurbines are described by Steele (2006).

Low swirl combustion, developed at Lawrence BerkeleyNational Laboratory, CA, USA, exploits divergent flow whichis an expanding flow stream formed when the swirl intensitiesare deliberately low such that vortex breakdown and hencerecirculation does not occur. Small air jets swirl the perimeterof the premixture but leave the centre core flow undisturbed.The flow through the injector is therefore split between a non-swirling central core and a swirling outer annular flow. Thetwo flows interact to generate a diverging flow-field at thethroat of the injector. The flow divergence region generatedby low swirl above the burner tube is the key element forflame stabilisation. The flame settles where the local velocityis equal and opposite to the turbulent flame speed. The lowswirl concept is fundamentally different from the high swirlconcept of typical dry low NOx gas turbines which generate awell formed vortex to hold and continuously re-ignite theflame (Cheng, 2006; Littlejohn and others, 2007).

Low swirl burners have been commercialised for industrialprocess heaters and are under development as a dry low NOxtechnology for natural gas powered turbines. The concept isadaptable for burning other hydrocarbons and H2-enrichedfuels. Research activities have been limited to proof-of-

27

Premixed combustors


concept laboratory experiments using H2 and H2/hydrocarbonblended fuels. Studies have shown that operating pressure andvelocity have little effect on lean blow-off. The equivalenceratio at which lean blow-off occurs is reduced by: preheatingthe air-fuel mixture, by adding H2 to the fuel blend, or byincreasing the swirl of the injector. Flame flashback is notsignificantly affected by pressure. Flashback is inhibited byreducing the swirl or increasing the operating velocity.Flashback is promoted by preheating the air-fuel mixture orby adding H2 to the fuel. More extensive laboratory studiesare necessary to develop basic low swirl injector designsoptimised for syngases, the accompanying scaling rules andengineering guidelines. Flow-field characteristics and howthese affect flame properties are central to the futuredevelopment of the technology for IGCC turbines (Cheng,2006; Littlejohn and others, 2007).

The main challenge is accommodating the variability insyngas fuel properties (see also Section 2.1). A syngas withlower flame speeds than natural gas and lower flametemperatures is difficult to stabilise although NOx emissionsare lower. On the other hand, the syngas produced after CO2

separation and storage may have 65–85% H2. This is muchmore flammable with high flame speeds. Development workfocuses on stabilising the potentially faster flames at very leanconditions at low enough flame temperatures to prevent NOxformation. Additional issues arise due to the high diffusivityof H2 and its low flammability limit, as well as shorter auto-ignition delays than hydrocarbon mixtures. Hence integrationof the low swirl injector with fuel injection and premixer willbe a significant part of the development. The interestingquestion is whether or not the absence of a large recirculationzone in the low swirl injector flame will have an effect on thecombustion oscillation characteristics. Initial tests, showing alack of a strong acoustic signature from the flame, areencouraging but require more systematic investigation to gaina fundamental understanding in order to address issues thatmay arise when the technology is adapted for complex IGCCgas turbines (Cheng, 2006).

The rich-burn, quick-mix, lean-burn (RQL) combustorconcept, used to reduce NOx emissions from aero-propulsionengines, is of growing interest for stationary applications dueto the attributes of more effectively processing fuels ofcomplex and varying composition. A rich-burn condition inthe primary zone, for example with equivalence ratio of 1.8,enhances the stability of the combustion reaction byproducing and sustaining a high concentration of energetic H2

and HC radical species. A quick-mix jet of air is injectedthrough wall jets to mix with the primary zone effluent tocreate a lean-burn condition with equivalence ratio of 0.6,before further dilution with another air jet to 0.3. Newresearch is exploring NOx formation for fuels of varyingcomposition. The hypothesis that optimal mixing in the quick-mix section leads to minimisation of NOx emissions has beenchallenged by recent observations. In particular the generationof N2 containing species in the rich-burn zone and subsequentprocessing in the quick-mix section may affect NOxemissions. Although the RQL concept is inherently a low-NOx generator, a further understanding of the primary zonechemistry and the coupling between the chemical kinetics andfluid mechanics in the quick-mix section may be required in

conceptual rendering

air

combustion zone

main vortex

Figure 9 Trapped vortex combustion (Steele, 2006)

order to optimise the design for fuels of varying composition(Samuelson, 2006b).

Oxyfuel combustion has been proposed for advanced enginecycles as a means of capturing CO2. For an oxyfuel turbine,the excess O2 needs to be lower than in a boiler, with muchshorter residence times to avoid excessively large, pressurisedcombustion chambers. Although the easiest combustionstrategy is to employ a diffusion flame combustor (seeSection 3.2), premixing the fuel and oxidant can reduce theunmixed streams of fuel and O2 that form in diffusion flamesystems where relatively small fuel jets must penetrate andmix in the large combustion volume. There is a lack offundamental data on premixed oxyfuel flames diluted bywater or CO2 so that proposed designs must include somemargin with respect to issues like flame speed (Richards,2006; Strakey and others, 2006).

4.3 Comments

Research programmes are in progress to develop premix H2

burners for syngases. They have to overcome the increasedtendency for flashback and pre-ignition and reduce NOxemissions. Premix burners for IGCC with CO2 capture areunder development in Europe but not yet finished. In theUSA, the advanced swirl premix combustor is to be adaptedand validated by 2015. Concepts in various stages ofdevelopment or with potential for IGCC include trappedvortex combustion, low swirl combustion, and the rich-burn,quick-mix, lean burn combustor concept.

28

Premixed combustors


Active interest in catalytic combustion for power generationincreased during the early 1990s as it became clear thatcontinued pressure for reduced emissions may not be metsimply by redesign of conventional combustors. A newapproach of partial conversion in the catalyst bed and the useof metal catalyst substrates to circumvent thermal shockissues became increasingly successful, demonstrating lowNOx potential for gas turbine applications. Ultimately, twodifferent systems emerged: a fuel-lean catalyst systemdeveloped by Catalytica Inc and a fuel-rich catalyst systemdeveloped by Precision Combustion Inc (Smith and others,2006a). Details of the technologies are given by severalauthors in the gas turbine handbook of the US DOE (NETL,2006).

5.1 Catalytic systems

The fuel-lean system premixes all combustion fuel and airupstream of the catalyst and uses a partial conversion catalyticreactor to oxidise only a portion of the fuel in the catalyststage at <950°C (metal limiting temperature). Thetemperature rise due to fuel oxidation in the catalytic reactorinduces gas-phase auto-ignition in the downstream gas-phasecombustion stage, where combustion is completed at>1100°C. The catalyst stage is operated fuel lean and uses aPd-based catalyst. A pre-burner is generally employed toensure that the catalyst remains active during low-emissionengine operation (Smith and others, 2006a). This raises thetemperature from the compressor exit temperature of a typicalgas turbine to the required inlet temperature for the catalyst ofapproximately 500°C. Operation of the catalyst in the leanregion requires very close control of the air fuel ratio in thevicinity of the catalyst to avoid high reaction rates andexcessive catalyst temperatures (Laster, 2006). The stabilityof the catalyst material and its long term performance are themajor challenges in the development of an operationalcatalytic combustor. Also, catalytic combustion is an unlikelysolution for retrofitting existing turbines. Lean premixedcombustion is the basis for achieving low emissions fromcatalytic combustion (Drnevich and others, 2004).

The fuel-rich catalyst system is shown schematically inFigure 10, as originally developed for operation on naturalgas. The combustion air stream is split into two parts


upstream of the catalyst. One part is mixed with all or most ofthe fuel and contacted with the catalyst, while the second partof the air is used to backside cool the catalyst. Hence all thefuel, along with a limited quantity of air, is fed to the catalyticreactor for partial fuel conversion. The reaction is limited bythe amount of O2 on the catalyst bed, preventing flashback,auto-ignition and substrate overheating. Also, this limited O2

allows widely varying fuels to be used regardless of theintrinsic reactivity of the fuel on the catalyst. At the exit of thereactor, the catalysed fuel/air stream and the cooling flow aremixed rapidly to produce a fuel-lean, reactive mixture prior tofinal combustion. Low NOx emissions are maintained over awide range of firing conditions. This eliminates the need forexpensive exhaust gas clean-up technologies. Fuel-richcatalyst effluent mixes with catalyst cooling air prior to fuel-lean gas-phase combustion. Hence the system is calledrich-catalytic, lean-burn combustion (RCL™). The flameholding in the combustor is based on recirculation. Fuel-richoperation of the catalyst provides advantages, including awide choice of catalyst (because many catalysts are activeunder fuel-rich conditions), improved durability in a non-oxidising environment, and low catalyst lightoff and operatingtemperatures. The catalyst activity is also greater than forfuel-lean operation, such that a pre-burner is not normallyrequired during low-emission engine operation. This isbecause the fuel and air react at a compressor exit temperatureof only 400°C, which is typical of gas turbine engines. Thesystem has been successfully tested on multiple fuels,including syngas and is being developed by PrecisionCombustion Inc and Siemens Power Generation Inc (Bairdand others, 2006; Laster, 2006; Smith and others, 2005,2006a).

Catalytic combustion systems can be combined with non-catalytic lean-premixed systems to offer advantages inperformance, cost, pressure drop, and space requirements. Forexample, Precision Combustion Inc has developed a catalyticpilot system that combines its RCL™ system with non-catalytic, swirl-based fuel/air injection. This has been testedin cooperation with Solar Turbines (Smith and others, 2006a).

DesignMore details of the RCL™ design (see Etemad and others,2004; Laster, 2005, 2006; Laster and others, 2006) are basedon the building blocks shown in Figure 11. Investigations onnatural gas fuelled turbines have been carried out over severalyears. It is essential to IGCC operation that each componentcan operate successfully on both natural gas and syngas. Theconcept is undergoing validation at test facilities. Thecatalytic combustion module consists of an array of tubes (seeFigure 12). The part of the air stream which is mixed with thefuel reacts on the outside surface of the turbines at an overallequivalence ratio which is greater than the flammability limitof the mixture. The remaining air stream is directed to theinside of the tubes and is used to cool the reverse side of thecatalyst. The fraction of the air that mixes with the fuel isdefined as the split air flow. It is controlled by the componentflow resistances and resulting pressure drops through the

5 Catalytic combustors

air

fuel

burnt gas

combustioncatalyst cooling

catalyticreactor

post-catalystmixing

premixer

Figure 10 Two-stage rich-catalytic lean-burncombustion for natural gas (Smith andothers, 2006a)

system. This air split is a critical parameter in the design ofthe catalytic reactor and an optimal value, working for allfuels, must be determined. Generally 20–40% of the fuelreacts in the catalytic stage. At the exit to the reactor, the twostreams mix before entering the downstream burnout sectionof the reactor. The stability of the flame in the homogenousburnout zone is significantly improved by reacting a portionof the fuel in the catalyst.

The combustor basket for this application is formed by sixcatalytic modules surrounding a central pilot. The gas flowingthrough both the pilot and the modules exits into thedownstream burnout region. The pilot is necessary to providestability to the downstream burnout region while operating atlow loads. At base load the diffusion stage of the pilot is shutoff and the premix stage is shut off or minimised. Unlikeother catalytic combustor concepts, this design does notrequire a preburner; the catalyst is designed to become activeat the compressor exit temperature. In order to eliminate thepreburner, catalyst materials have been developed to becomeactive at temperatures typical of the compressor exit (Lasterand others, 2006).

30

Catalytic combustors


The requirements for the catalytic coating for use in a fuelflexible catalytic reactor are summarised (Laster and others,2006):� it must become active at typical SGT6-5000F

compressor exit temperatures;� it must be able to oxidise multiple fuels (natural gas,

syngas, H2) efficiently;� it must stay attached to the metal substrate and maintain

acceptable fuel conversion for more than 8000 hours or800 cycles of operation;

� it must be resistant to poisoning, sintering, spallation,and so on;

� the cost of the catalytic system must be less than the costof back end clean-up, that is SCR.

The coatings for this development utilise precious metalparticles (Pl, Pd, Rh) co-dispersed or incipient wet on to atraditional ceramic wash coat applied to a metal substrate.The focus has been on optimisation of precious metalconcentration and wash coat composition. The Siemens singletube test rig for coating, screening and durability studies isdescribed. Initial screening of catalytic coatings is performedon natural gas because it has the highest lightoff temperaturesof any fuel. Once a catalyst has proven repeatable lightoffcharacteristics on natural gas, additional work is performed onsyngas and H2 (Laster and others, 2006).

Single tube testing has confirmed that syngas and pure H2 areconsiderably more reactive than natural gas. Light off onsyngas occurs typically at roughly 50–100°C lower thannatural gas. Pure H2 is even more reactive with light offoccurring at temperatures slightly above ambient. Syngastesting began at SGT6-5000F conditions and continued toSGT6-6000G conditions. At the higher firing temperaturewith syngas, flashback occurred in the mixing zone of themodule exit. This resulted in damage to the walls. Theflashback was confined to the mixing zone and the catalytictube was not damaged. Metal temperatures and combustiongenerated dynamics were well within the allowable range forthe conditions tested (Laster and others, 2006).

Pollutant emissionsThere was an increase in the NOx emissions for syngascompared with natural gas at the same firing temperature,although they were still lower than can be achieved throughdiffusion flame conditions. The natural gas fired combustor

a) catalytic elements b) catalytic reactor

c) catalytic module d) catalytic basket

Figure 11 Basic building blocks for the RCLcombustor (Laster and others, 2006)

cooling air inlet ~85%

reactive mixture

fuel mixer fuel manifold

mixing zone

air inlet (≈15%)fuel inlet

gas jets 45°

tubes with catalytic coating on the outside

Figure 12 RCL catalytic module (Laster, 2006)

could meet the 2 ppm (at 15% O2) NOx limit at F classconditions and 3 ppm at G class temperatures (Laster, 2005;Laster and others, 2006).

Design improvements were made to give more margin forflashback on syngas operation and to reduce the NOxemissions by increasing the mixing profile out of the syngasmanifold. The main changes were (Laster and others, 2006):� the size of the inlet manifold was increased to prevent

the flow being restricted at the inlet;� a second syngas inlet was incorporated and the two inlets

were positioned so as to achieve the optimal flowdistribution into the plenum;

� the fuel injection holes were also analysed and animproved injection hole pattern was chosen to achievebetter mixing.

In addition to successful testing on natural gas (both at fullscale and in-engine at Solar Turbines), the RCL® combustionsystem has been tested at sub-scale with syngas and H2 fuelsat atmospheric pressure and at high pressures (Baird andothers, 2006; Smith and others, 2005).

Syngas fuel tests were first performed at atmospheric pressureto provide some initial experience in syngas fuel operation,and in catalyst and combustor behaviour using syngas fuels.The results were used to help guide reactor design and testplanning for subsequent high pressure tests. For fuel-richconditions, the syngas light off temperature was about 180°Cwhile the extinction temperature was <80°C. The requiredNOx emissions limit of 3 ppm was easily achieved forequivalence ratios as high as 0.53 (Smith and others, 2005).

The high pressure, 10 atmospheres (1 MPa) sub-scale testswere based on operating conditions from the Polk IGCC plant(see also Section 6.1.2), which uses a GE 107FA system onsyngas generated from a Texaco O2-blown coal gasifier withN2 injection for NOx control. The syngas contained 20% H2,20% CO, 10% CO2 and 50% N2. Stable operation wasachieved with catalytic combustion even at flametemperatures as low as 1260°C. NOx emissions were <3 ppm(at 15% O2, dry) under modified operating conditions duringparametric tests, simulating operation of the IGCC plant(Etemad and others, 2004; Smith and others, 2005, 2006a). `

Hydrogen fuels (42 vol%, 52 vol%, 65 vol% H2 with N2

balance) were tested at 9 atmospheres (0.9 MPa) with inlet airand fuel temperatures of 400°C and 200°C respectively atPrecision Combustion Inc. Increasing the catalytic air splitreduced NOx emissions to <1 ppm (at 15% O2). Thisincreases the amount of reaction within the reactor. However,there are limits to the reductions in NOx emissions that can beachieved by this means. Increased catalytic reaction releasesmore energy within the catalyst bed, producing higher surfacetemperatures. The wall temperature of the reactor is limitedby material considerations so advanced cooling is required.Cooling techniques such as inserts, wall treatments, flowimpingement, film cooling, or increased cooling velocity(through increased wall thickness or higher allowablepressure drop) allows the operation at a higher air split andthus the achievement of lower NOx emissions. With thedevelopment of high temperature materials, the potential for

31



higher H2 percentages with lower emissions could beachieved. Rich catalytic combustion showed a NOx emissionof 3.2 ppm (at 15% O2) with an H2 concentration of 42% at9 atmospheres (0.9 MPa) in sub-scale tests at simulatedengine operating conditions (Baird and others, 2006).

Precision Combustion Inc aims to demonstrate a lowemissions, rich catalytic combustion system for fuel flexible,ultra-low NOx (<3 ppm), megawatt-scale gas turbines. Thesystem should facilitate high efficiency operation, be installedor retrofitted into existing turbines, and be commerciallyviable to meet the US DOE goal by the year 2015 (Baird andothers, 2006).

Further development to bring the RCL® combustion systemto an engine, and eventually to commercialisation requireslong term catalyst durability tests. These should preferably bein an actual syngas slipstream at an operating IGCC plantwhere real contaminants are present (Smith and others,2006a).

The RCL® design was chosen by Siemens Power GenerationInc for two main reasons. By eliminating a pre-burner, thedesign was much more compact and could easily be fitted intothe existing envelope of the current gas turbine combustorwithout major modification to the casing. Also, because of theoperation in the rich region the design was much moretolerant of variations in both air and fuel flow. Over firingtests were performed on both the fuel-lean and the fuel-richsystems and the fuel-rich design was able to survive a severeover fuel transient without damage while the fuel-lean systemfailed. The RCL® catalytic module and the conceptual designof the catalytic basket were developed and then applied to thelower firing temperature SGT6-3000E engine. Full-scalebasket testing was performed on this design at both E-classand F-class firing temperatures (Laster, 2006).

Catalytic module testing confirmed that emissions could bemaintained at <2 ppm NOx and 10 ppm CO for a wide rangeof conditions, including both the E and F class engines.Throughout all conditions, the catalyst and metaltemperatures remained within limits. The catalytic combustorfor the Siemens SGT6-5000F engine is shown in Figure 13.This full scale combustor basket was designed using sixcatalytic modules surrounded by a central pilot. The pilot isnecessary to ensure stable operation of the combustor basketat low loads. The aim is to minimise or completely shut offthe fuel flow to the pilot at base-load conditions. Although thepilot contributes to NOx emissions, this can be minimised byreplacing the standard diffusion pilot design with a premixedpilot. Based on this concept, a full-scale basket was fabricatedand tested at the Siemens full pressure single basket testfacility in Italy. As expected, the emissions for the full baskettests were slightly higher than those of the module tests due tothe pilot. For the SGT-6-3000E engine it was necessary to adddilution air to raise the combustor temperature in order toachieve proper CO burnout. At these conditions, the emissionswere 3.3 ppm NOx and 7 ppm CO. When the temperature wasincreased to SGT-6-5000F conditions, the improved stabilityat higher temperatures enabled the combustor to run at asignificantly lower pilot fraction. This resulted in emission of3.6 ppm NOx and 9 ppm CO. Basket and catalyst metal

temperatures and combustor pressure oscillations were wellbelow the design limits during the test. An over-firing test wasperformed, with no damage to the catalytic modulecomponents (Laster, 2006).

Development of a fuel flexible, H2 turbine at Siemensincludes catalytic combustion for IGCC applications usinglarge industrial gas turbines such as the SGT6-5000F engine.A new thermal stress resistant and robust catalytic system foradvanced combustors is being developed. The three-yearprogramme aims to reduce NOx emissions for the currentdiffusion flame based IGCC combustion systems down to2 ppm, without the need for dilution. Three new noble metalshave been selected as modifying elements for new hightemperature bond coat. New ceramic compositions have beenidentified for the development of advanced thermal barriercoatings. The test matrix and substrates have been defined forspray trials. Four rare earth elements have been selected asalloying additions to enhance the CM247LC superalloy(Bancalari and others, 2006; Laster, 2005; Laster and others,2006). Future combustion systems development under the USDOE co-funded ‘Catalytic Combustor for Fuel FlexibleTurbine Program’ and the ‘Advanced Hydrogen Turbine forFutureGen’ as well as the European Commission co-fundedsyngas/H2/IGCC programmes will enhance operability on abroad range of syngas compositions and high H2 content fuelswith near zero emissions (Gadde and others, 2006b).

32



5.2 Comments

It is noteworthy that this chapter is based only on informationpublished up to 2006. It is not therefore possible to present arecent overview of the latest developments. The role ofcatalytic combustors in IGCC may become clear when currenttesting programmes on syngas/H2 in Europe and the USAhave been completed and the results made available.

The RCL™ system has the advantage of not requiring a pre-burner. This makes it sufficiently compact to fit into currentgas turbine combustors. The design has proved tolerant ofvariations in both air and fuel flow. However, the walltemperature of the reactor is limited by materialconsiderations, requiring advanced cooling techniques. Longterm catalyst durability tests in an actual syngas slipstream atan operating IGCC with real contaminants are necessary forcommercialisation.

centrebody assembly flow divider pilot pilot cone

RCL module (6 per basket) wagon wheel/liner

coated tubes

Figure 13 Catalytic combustor for the Siemens SGT6-5000F engine (Laster, 2006)

Coal-based IGCC technology has been demonstrated at acommercial scale for more than ten years at two sites in theUSA and two in Europe. The US plants use gas turbines fromGE and the European plants from Siemens. The EuropeanIGCC plants differ from the US plants in that they are fullyintegrated, so that the turbine is used to compress all the airthat the plant needs. About 16–18% of the airflow is used forthe gasification process and N2 is returned to the turbine forsyngas dilution and for NOx control. The full-integrationconcept was selected in Europe to achieve high efficiencies inthe plant. However, lessons learned are expected to lead topartial air-side integration (50% of the air separation unit airdemand) for future coal-based designs using an SGT5-4000F(V94.3A) turbine (Parkinson, 2004). The philosophy of MHIat the new demonstration IGCC plant at Nakoso, Japan, is touse an air-blown gasifier in order to avoid the extremely highauxiliary load of the air separation unit. This is considereddesirable to improve the overall efficiency and reliability ofthe design (Sakamoto, 2007). However, because a small airseparation plant is needed to supply N2 for the plant, by-product O2 from this is used to enrich the gasification air,making gasifier operation easier (Henderson, 2009).

Apparently basic, but essential, data on firing temperaturesand turbine inlet temperatures appear to have been confusedin the literature. The firing temperature is around 50–100°Chigher than turbine inlet temperature, and it is not alwaysclear in statements which is being referred to (Henderson,2008). Syngas combusting models generally have firingtemperatures about 110–170°C lower than their natural gasfired equivalents to maintain the required blade metaltemperatures (Phillips, 2007). There are also problems withdata on availability so that it is not always clear whether theavailability of the gas turbine is meant, or that of the gasifieror complete plant. Bearing in mind these difficulties,experience on coal-based IGCC plants is reviewed in thefollowing Section 6.1 and future trends are examined inSection 6.2.

6.1 Experience with existing IGCCplants

The STEAG/Kellermann plant in Germany was the firstcombined cycle plant with integrated Lurgi hard coalgasification. Several IGCC plants using coal have come intooperation over the last two decades (see Table 5) and currentexperience is reviewed in the following sections.

6.1.1 Europe

Buggenum IGCC plantThe Willem Alexander IGCC plant at Buggenum, TheNetherlands, was first fired on syngas in April 1994. It hasbeen operating commercially since 1998 and usesinternational coal. The syngas has a heating value of4.5 MJ/m3 (Butcher, 2004) after dilution with N2 and water


saturation. The Siemens SGT5-2000E (V94.2) gas turbine hasvertical, twin silo combustors, in a single shaft arrangementwith a steam turbine and a common generator. The syngasburner is a modified Siemens hybrid burner with an additionalcoal gas supply line. The turbine firing temperature is1060°C. The cycle is fully integrated with extraction of airfrom the gas turbine compressor for the air separation unit.Full integration has resulted in a lengthy start-up time andlimited load ramp rate. Availability was also adverselyaffected by the high probability of overall trip when oneisland failed. Problems with turbine humming arose on firingthe syngas and these were solved in1996 by modifying theburners and control systems. Other changes made to improvethe performance of the gas turbine have included injection ofnatural gas to increase load ramping and improve operationalflexibility (IEA, 2007; Gadde and others, 2006b; Kanaar,2008b, 2009; Mills, 2006).

The main problems in 15 years of operation for the combinedcycle and air separation unit were summarised (Kanaar,2008a, 2009):� humming and overheating of the gas turbine burners;� too much integration of combined cycle unit/air

separation unit/gasifier lead to complex controls;� special air separation unit design with sliding inlet

pressure ranging from 5 to 11 bar (0.5 to 1.1 MPa);� hydro-thermal aging of molecular sieve material;� trips of the diluent N2 (D-GAN) compressor.

Measures to enable the gas turbine to be reliably started usingsyngas were tried but abandoned after the first attempts failedand the business case in its favour changed. There had been ahigh capacity fee for natural gas but during the project, the feehad decreased to one sixth of the original. Hence there was noincentive from a business perspective to avoid starting up withnatural gas. The plant has achieved a 12-month averageavailability of 93.1% on syngas with natural gas and 71–80%on syngas during the last five years. The best 12-month periodof operation with syngas corresponded to an availability of86%. Studies have been carried out on the feasibility ofreducing the degree of plant integration, although this mayaffect plant heat rate. However, this was found to be toocapital intensive (Kanaar, 2008b, 2009).

The total operating hours had reached 103,000 in 2008(Kanaar, 2009).

Puertollano IGCC plantThe plant mainly uses a 50 wt% mix of local high ash(41–50%) bituminous coal and high-sulphur petroleum coke,but various biomass materials have been added at 5–10%. TheSiemens SGT5-4000F (V94.3) gas turbine has twohorizontally opposed silo-type combustion chambers. The gasturbine firing temperature is 1250°C. The design of the IGCCplant is based on the concept of maximum integrationbetween the gasification island, combined cycle and highpressure air separation unit producing N2 and O2. All of theair fed to the air separation unit is extracted from the gas

6 Gas turbines for IGCC

turbine compressor. The residual N2 from the air separationunit is mixed with the clean gas to increase the gas flow fed tothe burner of the gas turbine. This increases the power outputand decreases NOx emissions. The clean coal gas is saturatedwith water to reduce NOx formation during combustion in thegas turbine (Casero and Garcia-Peña, 2006; Mills, 2006;Pater, 2007; Schellberg and others, 2008).

Some overheating problems and acoustic oscillations(humming) were detected during coal gas combustion fromJune 1998. The coal gas burner was therefore optimised toachieve stable flame conditions during start-up with naturalgas and switch-over operations, and to prevent overheatingproblems (Casero and Garcia-Peña, 2006; Casero and others,2005). There have been three main milestones with the gasturbine (see Figure 14) since the IGCC has been running onsyngas. The gas turbine was responsible for 75% of theunavailability of the combined cycle during 2004-06, the restbeing due to the water steam cycle (19%) and the gassaturator (6%). The combined cycle was, however, onlyresponsible for 29% of overall unavailability (Casero, 2007).In 2007, this decreased to 20% and the gas turbine was onlyresponsible for 73% of the unavailability (Schellberg andothers, 2008).

Until the latest design of syngas burner was installed in 2003,

34

Gas turbines for IGCC


the hot gas path had to be inspected every 500–1000 operatinghours, with a high rate of change of the ceramic tiles. Sincethen there has only been a minor inspection every 4000operating hours (Casero and Garcia-Peña, 2006). Thecombustion chamber tiles gave problems due to misalignment(IEA, 2007).

Availability of the gas turbine is improved by (Casero andothers, 2006):� using new models with more robust combustors,

increasing the resistance of components to hightemperature and improving the ceramic tile material;

� integrating the air extraction only during normaloperation, having start-up without air extraction,evaluating and optimising integration of the airextraction in normal operation;

� installing a fogging system with proper drain system;� increasing power and efficiency with last proven models;� pressure control on the extracted air side over the full gas

turbine load range was installed in order to operate theextracted air flow as smoothly as possible and tominimise even minor gas turbine temperature fluctuation.

When the gas turbine load decreases because of a rise in theambient temperature, the gasifier needs to be operated in partload due to the integration between the gasifier and gas

Table 5 Existing IGCC power stations (>100 MW)

Name Location Gasifier FeedGas turbine(new7)

Net efficiency,% LHV2

Electricaloutput (net),MWe

Start-up

STEAGLünen,Germany

Lurgi hard coal Siemens, V93 163 19721

WillemAlexander

Buggenum, TheNetherlands

Shellnatural gashard coal +biomass

Siemens V94.2(SGT5-2000E)

>43 25319931

1994-95

Wabash RiverWest TerreHaute, IN, USA

ConocoPhillipsE-Gas

bituminous coal+ petcoke

GE MS7001FA >40 262 19952,5

TampaElectric Polk

Polk County,FL, USA

GEbituminous coal+ petcoke

GE MS7001FA 36.7 250 19962,5

PuertollanoPuertollano,Spain

Krupp-UhdePrenflo

natural gassubbituminouscoal + petcoke

Siemens V94.3(SGT5-4000F)

<42 29819961,4,5

1997-98

VresovaVresova, CzechRepublic

HTW lignite + petcoke 2xGE MS9171E 42.2 385 19963,6

Sanghi, India U-Gas lignite 2002

Nakosademonstration

Nakoso, IwakiCity, Japan

MHI bituminous coalmodified MHIM701DA

42 220 20072,5

1 Hannemann and others, 20042 IEA, 20073 GTC, 20084 Minchener, 20055 Carpenter, 20086 Jones and others, 2007b7 Gadde and others, 2006b

turbine. An additional gas turbine inlet air cooling systemshould therefore be considered in order to operate the plantwith maximum power output throughout the year andespecially during the summer season (Casero and others,2006).

The gas turbine has performed well on syngas. However, ithas required several burner modifications to obtain enoughstability in syngas combustion and improved burner design.The gas turbine performance was limited by a higher numberof inspections caused by overheats, inducted corrosion ofceramic tiles, and thermal shock, which has been improved byslight modifications since the first years of operation (Caseroand others, 2006). Plant start-up is slow because of the highlyintegrated nature of the design. ELCOGAS would use partialintegration in any future installation (IEA, 2007).

The high unavailability of the air separation unit, added tothat of the gasifier and combined cycle, resulted in only4332 hours producing electric power based on coal gas in2007. Low operating hours were similarly anticipated for2008 (Schellberg and others, 2008).

VresovaThis commercial IGCC in the Czech Republic has beenrunning with two Frame 9E gas turbines since 1996 with asyngas containing 45–47% H2 (Jones and others, 2007b). Thesyngas is produced by old gasifiers from local brown coal.Natural gas is sometimes added as secondary fuel in order toachieve maximum output (Mills, 2006). A new Gas SchwarzePumpe (GSP) entrained flow gasifier, supplied by FutureEnergy GmbH, was installed to gasify by-products from theexisting fixed bed gasifiers and supply syngas to the IGCC

35



(Mills, 2007); commissioned in 2007 as a Siemens FuelGasification system and generating 400 MW (Carpenter,2008).

6.1.2 USA

PolkThe Tampa Electric Polk project IGCC has been runningcommercially since October 2001 and uses a GE 7FA gasturbine with turbine firing temperature of 1300°C. The air forO2 production is supplied from a separate compressordedicated to the air separation unit and not from the gasturbine, although recently, some air extraction from the gasturbine has been incorporated. Diluent N2 is fed to the gasturbine combustor to control the flame temperature in order toreduce NOx production. There were the usual initial bedding-in problems, but the unit now operates with a goodavailability of 78% on syngas (IEA, 2007; Ishibashi andShinada, 2008) and has been listed with an availability of84% (Ekborn, 2007).

The efficiency of 36.7% LHV, shown in Table 5, wasdetermined with a 100% coal feed (Peabody Camp KentuckyNo 9). This was penalised by the carbon conversion beinglower than the anticipated 97.5–98% (IEA, 2007).

The gas turbine has been running on syngas containing 37.2%H2 (Jones and others, 2007b).

WabashThe Wabash River coal gasification project is a repoweringproject established under the US DOE CCT Program. It

75,000 EOH gas turbine major overhaul

severe fault in main generation transformer of GT

50,000 EOH gas turbine major overhaul

March 2007: new record on syngas: 958 hours

December 2006: 14,673 GWh (9,184 GWh with coal gas)

March 1998: 1st switch-over to syngas in the GT. 1st production as IGCC

October 1996: commercial operation of CC with NG (1st CC in Spain)

1996

2002

2001

2000

1999

1998

1997

2008

2006

2003

2005

2004

2007

Figure 14 Main milestones in the Puertollano IGCC power plant (Casero, 2007)

continues to operate commercially and uses a GE Frame 7FAgas turbine with turbine firing temperature of 1300°C. Theplant has operated on both high sulphur Illinois No 6bituminous coal and petcoke but on 100% petcoke since 2000.The clean gas is reheated and moisturised to reduce NOxemissions before combustion in the gas turbine. The gasturbine and related components operated largely as expectedover the course of the project, with few failures related tosyngas (IEA, 2007; Ishibashi and Shinada, 2008).

The 12-month (trailing) average availability was 70–80%from October 2006 to April 2008 while the reliability variedfrom 84% to 91% (Payonk, 2008).

The gas turbine has been running on synfuel containing24.8% H2 (Jones and others, 2007b).

6.1.3 Japan

Nakoso IGCC demonstration plantThe 1700 t/d plant was started up in September 2007, using abituminous coal from China in the air-blown, dry feed MHIgasifier. The MHI 701DA gas turbine has a firing temperatureof 1200°C on natural gas. A net efficiency of 42.2% LHV hasbeen achieved during the first year of operation. The SOxemissions were 1 ppm, meeting the target of 8 ppm. NOxemissions were 3.4 ppm. An SCR system was included tomeet NOx limits of 5 ppm (all at 16% O2) (IEA, 2007;Henderson, 2008; Ishibashi and Shinada, 2008).

The gas turbine has run on syngas from December 2007 andachieved a total operating time of 2590 hours on syngasduring the first year. The plant operating parameters are to beadjusted to increase the net plant efficiency and load changingrate from December 2008. US Powder River Basin andIndonesian coals are planned to be used early 2009 with a5000 hour durability test planned from May to December2009 (Ishibashi and Shinada, 2008).

The demonstration plant will effectively provide reference

36



plant designs based on the M501F and, eventually, M501Ggas turbines, with net efficiencies of 45% and 48% LHVrespectively (IEA, 2007). The tests to 2009 prepare for acommercial plant from 2012 which will use an air-blowngasifier with dry coal feed and deliver 900 MWe net plantoutput with the M501G gas turbine, without CO2 capture. TheCO2 capture rate will be 60–65% or more (Sakamoto, 2008).Improvements in net plant efficiency with CO2 reduction areprojected to increase from 42% on the 1200°C gas turbine atNakoso demonstration plant to 45–46% on the 1300°C gasturbine, and 48–50% on the 1500°C gas turbine (Ishibashi andShinada, 2008).

6.2 Future plants with CO2reduction

It will be necessary to capture and store CO2 from futureIGCC plants. The restructured FutureGen approach of theUS DOE aims to accelerate deployment of IGCC with CO2

capture and storage. Hence projects are being encouraged onnew plants and CO2 capture-ready plants have been defined.CO2 capture in future IGCC plants has been reviewed recentlyby the IEA Clean Coal Centre (see Henderson, 2008) and inthe gas turbine handbook of the US DOE NETL.

The capture of CO2 consists of gasifying the feedstock in anO2-blown gasifier and shifting the CO to CO2 by catalyticreaction with steam (Rao, 2006b):

CO + H2O = CO2 + H2

The CO2 is then removed for storage to produce adecarbonised fuel gas for combustion in a gas turbine. Thereare primarily two schemes for this process for current or nearterm technology plants. These are: sour shifting of the syngasfollowed by desulphurisation and CO2 recovery within thesame acid gas removal unit; or desulphurising the syngas firstfollowed by shifting and removal/recovery of the CO2 (seeFigure 15). The choice of sour or sweet shift conversiondepends primarily on the gasification heat recovery system

a) sour shift conversion

raw syngas clean syngas

CO2H2S

b) sweet shift conversion

raw syngas clean syngas

CO2H2S

sulphur removal(≈ 40°C)

hydrolysis(≈ 200°C)

CO2 capture(≈ 40°C)

sour shift(200-500°C)

sweet shift(200-500°C)

hydrolysis(≈ 200°C)

CO2 capture(≈ 40°C)

sulphur removal(≈ 40°C)

Figure 15 Sour and sweet shift conversion for CO2 capture from syngas (van Aart and others, 2007)

employed, that is the extent to which cooling of the rawgasifier effluent is accomplished in a syngas cooler before thesyngas is quenched or scrubbed with water to removeparticulate matter (Rao, 2006b). With sour shift, the sulphurremoval step would require substantial modification – anadditional train as well as an H2S concentration step. This canbe avoided with sweet shift, but then additional expense isincurred to recover the heat of the shift reaction as steam(Higman, 2007).

6.2.1 Implications for gas turbines

The composition of a typical decarbonised syngas with 90%CO2 removal from a high temperature, slurry-fed, entrained-bed gasifier fed with bituminous coal is (Rao, 2006b):

% (dry and S free)CO 2.8H2 94.1CO2 0.6CH4 0.1Ar + N2 2.4

The decarbonised syngas requires more diluent to limit NOxformation than un-carbonised syngas. Two types of diluentare available, water vapour introduced into the syngasstream by direct contact with hot water in a counter-currentcolumn while recovering low temperature waste heat and/orN2 from an elevated pressure air separation unit. The choiceof diluent depends on factors such as: the amount of lowtemperature waste heat available for humidification; and theamount of excess N2 available from the air separation unit(Rao, 2006b).

The amount of low temperature waste heat available in turndepends primarily on the gasification heat recovery systememployed, that is the extent to which cooling of the rawgasifier effluent is accomplished in a syngas cooler before thesyngas is quenched/scrubbed with water. The amount of N2

available depends on the specific consumption of the gasifier,since the air separation unit produces less N2 when thespecific O2 consumption of the gasifier is lower. It alsodepends on the type of gasifier feed system. Hence, dry feedsystems use significant portions of the N2 as lock hopperpressurisation gas as well as in the drying and transport of thecoal into the gasifier. A combination of the two diluents maybe used, the relative amounts depending on the overall plantintegration and the trade-offs between efficiency and capitalcost. Moisturised N2 may be either premixed with thedecarbonised syngas before supplying it to the combustor ofthe gas turbine or it may be introduced into the combustorthrough a separate injector. Premixing the diluent with thesyngas is more effective in decreasing the NOx than if it wereentered through a separate nozzle. On the other hand, the N2

compressor horsepower may be reduced when the diluent isintroduced into the combustor separately, if the pressuredrop associated with the fuel control valve is much higherthan that for the diluent. The composition of the diluenttherefore depends on the type of gasifier, heat recovery andenergy integration options as well as on the type of airseparation unit, that is whether it is at elevated pressure and

37



able to supply high pressure N2 for NOx control (Rao,2006b).

The pressure ratio of the gas turbine increases when firingsyngas, which has a much lower heat content than natural gas(see also Section 2.2). The increase in pressure ratio dependson the amount and nature of the diluent added and the degreeto which the compressor inlet guide vanes are closed. Thesurge margins available in the compressor could thusconstrain the amount of diluent that may be added and theresulting NOx emissions, in addition to the constraints set bythe combustor design with respect to achieving stablecombustion while limiting the CO emissions. Air may need tobe extracted from the compressor to limit the increase in theengine pressure ratio. In this case, the extracted air (aftercooldown/heat recovery) may be used efficiently in anelevated pressure air separation unit (Rao, 2006b).

Decarbonised syngas may require derating of the turbinefiring temperature due to changes in the aero-heat transfercharacteristics. These result from the increased water vapourin the working fluid and increased pressure ratio since thetemperature of the cooling air increases as the pressure ratio isincreased. Derating of the firing temperature may be lesssignificant for a steam-cooled gas turbine, since the coolingsteam temperature may be maintained independently of thegas turbine pressure ratio. That is unless the low pressure air-cooled stages of the gas turbine become the bottleneck. Thelife of the thermal barrier coatings and any ceramics that maybe used in advanced gas turbines in the future may beadversely affected. On the other hand, the penalty of using anSCR for stringent NOx emissions regulations can be lesssevere for a decarbonised syngas compared to its use in anIGCC without upstream CO2 capture (Rao, 2006b).

Capture of CO2 and firing the turbine with H2 is likely toreduce the extraction air available for feeding the airseparation unit. This results in additional compressioninvestment and operating cost for the O2 plant. Air integrationhas been chosen to maximise the efficiency of the overallcycle. Hence 100% air integration was included in bothEuropean IGCC demonstration plants. Studies performed bySiemens and Linde and by the Institute of Energy andChemical Engineering, Freiberg University, Germany, haveexamined the effects of total, partial and zero air extractionfor feeding the air separation unit in terms of turbine designand performance. One interesting conclusion was that, withwell matched equipment, the efficiency penalty was small,whatever the extraction rate. Zero air integration maytherefore be a good strategy for a plant that is required to beready for carbon capture (Higman, 2007).

Air extraction is currently not possible for H2 turbines andmanufacturers such as Siemens are working to develop it. Airsupply integration can create its own difficulties but doesprovide a means of limiting surges that would otherwise arisefrom the much higher flow rate within the turbine section forsyngas compared with high calorific value fuels (Henderson,2008).

PerformanceRieger and others (2008) at the Institute of Energy Process

Engineering and Chemical Engineering, Freiberg, Germany,discuss the effects of air separation unit integration on IGCCperformance and gas turbine operation. Air extraction varyingfrom 0% to 12% was selected for calculations on acommercially available F-class turbine. The clean syngaswould contain over 90% H2 but this would be reduced toabout 72% by clean gas saturation using low temperature heatfrom raw gas cooling. Further dilution to even lower H2

contents would use excess N2 from the air separation unit. To

38



compensate for the higher hot gas mass flow through the gasturbine (as a result of a decreasing heating value) it might bebeneficial to extract some pressurised air after the gas turbinecompressor. Hence the gas turbine design (for example,compressor stages, turbine stage, air bleed, syngascombustion system) needs to be adjusted for high H2 syngasoperation (see Sections 2.2 and 3.1). In general, air extractionenlarges the gas turbine operating window and reduces theamount of hot gas temperature reduction required. However,the plant complexity increases significantly and consequentlythe operating flexibility suffers considerably. The gas turbinepower output also increases at higher dilution rates whichcould lead to mechanical limitations such as striking againstthe shaft limit. Gas turbine operation might also be restrictedby factors such as the torque difference between thecompressor and turbine section, the compressor outlettemperature, and NOx emissions.

The IGCC net efficiency would vary with the air extractionand H2 dilution rates as shown in Table 6. The heating value ismuch reduced at the higher dilution rates used to reduce theH2 content. However, as noted in Table 6, partly closing thevariable inlet guide vane of the gas turbine compressor wouldnarrow the gap in efficiency at high dilution rates. The overallconclusion was that none or low air integration IGCCconcepts do not necessarily lead to much lower plantefficiencies. The operating experience of the European IGCCdemonstration plants, where high/fully integrated air

Table 6 IGCC net efficiency at different degreesof air separation unit integration (Riegerand others, 2008)

Airextraction,%

7.0 MJ/kgLHV, 43mol% H2

8.5 MJ/kgLHV, 48mol% H2

11.5MJ/kgLHV, 55mol% H2

14.5MJ/kgLHV, 61mol% H2

0 36.0* 37.0* 37.9 38.1

4 37.3* 37.8 38.0 38.3

8 37.8 38.0 38.1 38.3

12 37.9 38.1 38.1 38.2

* further optimisation by partly closing the variable inlet guidevane of the compressor might increase the efficiency to theother values

all-CO2 exhaust

CO2-free exhaust

high-H2S andCO2 removalfuel

air separationunit

CO shiftgasification

air

O2

CO2H2S

high-H2gas turbine

CO shift and CO2 removal

CO2-free exhaust

H2/COmembranefuel

air separationunit

H2S removalgasification

air

O2 CO + CO2

high-H2gas turbine

H2/CO membrane separation

CO2 gasturbine

H2

commercial mid-term long-term

H2S

Figure 16 Pre-combustion CO2 removal (Hannemann and others, 2004)

separation was responsible for substantial downtime (seeSection 6.1.1), implies that low or zero integration might wellbe chosen in order to reduce complexity and increaseoperating flexibility for future applications (Rieger andothers, 2008).

The effect of CO2 capture on IGCC plant efficiency atdifferent gas turbine design cases has been investigated byseveral authors. The performance for the GE Energy datashown in Table 1, giving H2 contents in the syngas of 23.7%and 73% after 90% carbon removal, was compared for 2300F(1260°C), 2500F (1371°C) and 2600F (1427°C) class firingtemperatures with a 2300F base syngas case without carboncapture. The change (reduction or gain) in plant output andnet plant efficiency are (Anand and others, 2006):

GT class Output, % Efficiency, %

2300F –6.3 –13.42500F +28.6 –4.92600F +90.9 0

The 2500F and 2600F class gas turbines have improvedtechnological design and therefore show increases in plantoutput and less penalty in the net plant efficiency with carboncapture. The results were similar for combined cycleefficiency and output and show greater improvements than onthe net plant basis (Anand and others, 2006).

In Europe, the study by van Aart and others (2007) on theeffect of CO2 capture showed that the heat input had to beincreased from 975 MWth to 1088 MWth to provide the sameheat input to the gas turbine of 757 MWth. The net efficiencywas reduced to 40.3% from 49.6% LHV, that is by 18.8%.The power was reduced by about 9% overall, that is by45 MWe, giving a net power output of 439 MWe.

DevelopmentsBefore its restructure, the FutureGen alliance in the USA wasworking towards developing a zero emission coal plant with2012 as the target year for first operation. In Europe,operation of a large-scale IGCC system with CO2 capturemay be operating by 2015 (Shah, 2006).

39



Hannemann and others (2004) at Siemens, Germany,summarised different concepts for pre-combustiondecarbonisation for current commercial deployment, mid-term and long-term (see Figure 16). Although processingunits are commercially available, low NOx, H2 combustion ingas turbines and plant integration are challenges to beaddressed. The mid-to long-term variant of separating H2 andCO by membranes includes one gas turbine for the high H2

gas and another for the O2-blown combustion of the CO.

Concepts were studied within the integrated ENCAP project(EU FP 6) for pre-combustion decarbonisation in IGCC forhard coal and lignite fuels. In the case of lignite, sweet, lowtemperature shift was used to provide a sufficient CO2 capturerate despite a greater amount of CH4 in the syngas resultingfrom the fluidised bed gasifier. A CO2 capture rate of >85%could not be achieved with lignite whereas a raw gas, hightemperature shift (two-step) with hard coal fuel, led to a CO2

capture rate of >90%. Lurgi’s Rectisol concept was selectedfor H2S and CO2 removal. Calculations were based on theSiemens SGT5-4000F gas turbine with partial integration sothat the compressor supplied up to 70% of the air for the airseparation unit. The results are shown in Table 7 and indicatea large reduction in net efficiency (LHV) for CO2 captureamounting to 23% for hard coal and 22% for lignite. This wasmainly due to losses during shift conversion and CO2

compression. The large differences between the gross and netpower outputs was also due to the air separation unit whichused 40% of the power demand for hard coal and 26% forlignite. This was due to the higher O2 demand of the Shellgasifier compared to the High Temperature Winkler gasifier.Adding internal demands for these and for the gasifier, powerisland and gas conditioning resulted in a total internal powerdemand of 220 MW for hard coal (23% of gross poweroutput) and 182 MW for lignite (20%) (Renzenbrink andothers, 2006).

There is thus a wide range of relative loss in net plantefficiency resulting from various configurations for CO2

reduction in IGCC of 5–23% for hard coal. Henderson (2008)notes that it is also not yet proven what performanceimplications there would be for a subsequent conversion to H2

firing in a coal-fuelled IGCC which had been initially

Table 7 Efficiency loss due to CO2 capture in IGCC based on the SGT5-4000F gas turbine (Renzenbrinkand others, 2006)

No CO2 capture With CO2 capture

hard coal lignite hard coal lignite

Fuel flow, t/h 267 647 293 716

Fuel LHV, MJ/kg 25.2 8.9 25.2 89

Syngas to GT, t/h 499 500 146 129

Gross power, MW 986 932 956 899

Net power, MW 874 826 737 717

Net efficiency, % 46.2 51.7 35.5 40.5

CO2 capture, % 0 0 >91 85

optimised for normal syngas operation. However, theefficiency of the gas turbine itself could remain substantiallysimilar. Kanaar (2008b) points out that a loss in efficiency of10% for precombustion separation from IGCC is less than the35–45% for CO2 capture in pulverised coal-fired power plant.

Gas turbine development for burning H2 needs to consider(Jones, 2006; Jones and others, 2007a):� advanced alloy and thermal barrier coatings for

interactions with high moisture/high temperaturecombustion gas;

� aero-thermal studies and experimental validation foroptimised tradeoffs between efficiency and RAM;

� process evaluations for optimal gas turbine integrationand demonstrations to validate concepts.

The US DOE H2/IGCC turbines programme is aiming toimprove efficiency by 2–3 percentage points by 2010 and by3–5 percentage points total by 2015; and to reduce NOxemissions to 2 ppm by 2015 with fuel flexibility (Jones andothers, 2007a).

Innovative design of highly stressed, thermally andmechanically, components such as combustion chamberlinings and turbine blade cooling is being addressed by joint

40



efforts of experts from several fields of engineering at theInstitute of Steam and Gas Turbines, RWTH AachenUniversity, Germany. Open porous structures have beendeveloped using the reaction slip foam sintering process forcombustion chamber linings. The process leads to foams withlarge primary pores that are connected by smaller, secondarypores in which the porosity can be influenced in a controlledmanner. The application of thermal barrier coatings on themetallic foams is possible, for example ZrO2 is deposited onan MCrAlY-bond coat with atmospheric plasma spraying. Theporous sub-layer provides a homogeneous distribution of thecoolant before it is emitted through the opened thermal barriercoating into the hot gas flow. The permeability of the closedthermal barrier coating is ensured by drilling cooling holeswith a diameter of 0.2 mm through the covering layers intothe porous foam. This leads ultimately to full-coveragecooling of the part (Bohn, 2008).

Turbine blades require full-coverage cooling (effusioncooling) as the first step to achieving transpiration coolingusing open porous structures. The effectiveness of this coolingcan be increased by distributing the cooling holes on thesurface according to local demand. It can be increased evenfurther by contouring the holes. The coolant is fed through thestructural material to a cavity underneath a porous interlayer.

Table 8 IGCC with CCS projects (Carpenter, 2008; Farley, 2008; IEA, 2007; Henderson and Mills, 2009; Jorgensen, 2008; Zeus Development Corporation, 2008a; ZEP, 2008)

Name Location Partners Start

Stanwell Queensland, Australia ZeroGen Pty Ltd 2012

Maritsa Bulgaria tba 2008?

Genesee Alberta, Canada EPCOR 2015

GreenGen Tianjin, China China Huaneng, Peabody Energy2009, 2015,2020

Hürth RWE North Rhine-Westfalia, Germany RWE 2015

Magnum Eemshaven, Netherlands Nuon 2013

Rotterdam CGEN Netherlands CGEN NV 2014

Rotterdam Essent Netherlands Essent 2016

Kedzierzyn PKE Kedzierzyn Kozle, Slaskie, Poland PKE/ZAK 2014

Puertollano CCS Spain Elcogas, Siemens, Krupp Uhde, Babcock 2009

Killingholme E.ON Lincolnshire, UK E.ON UK 2016+

Hatfield Powerfuel Power South Yorkshire, UK Powerfuel Power Ltd 2012-14

Teesside Progressive Energy Northeast England, UK Centrica, Progressive Energy, Coastal Energy 2013

Drym Progressive Energy Onllwyn, South Wales, UK Progressive Energy, BGS, CO2STORE

Duke Energy Edwardsport, IN, USA GE, Bechtel 2012

Erora Group Cash Creek, Henderson County, KY, USA 2012

Mesaba Energy Project Taconite, MN, USA Excelsior Energy 2014

Hydrogen Energy International HECA Project, CA, USA 2014

This layer is protected against direct contact with the hot gasby a permeable thermal barrier coating, through which thecoolant leaves the component as full-coverage cooling. Bothlaser-drilled, multi-layer systems and coated, open-porous,metallic foams can be applied, depending on the prevailingboundary conditions. Application of thermal barrier coatingsbased on ZrO2 would make it possible to increase the gasturbine inlet temperature by almost 150°C. The greatestchallenge for their application is the uncertainty in theprediction of their life-span. A novel approach to this problemis being tested, where a graded layer of bond coat and thermalbarrier coating is applied to the surface of the blade. Thisapproach promises to reduce spalling of the thermal barriercoating and improve its life-span considerably (Bohn, 2008).

Models are used to determine the parameters for manufactureof the novel structures. The cooling holes in the coated multi-layer system are manufactured by laser drilling, either bysingle pulse laser, percussion drilling or trepanation. Thecreep resistance of the gas turbine blade cannot be guaranteedwhen using only open porous materials. A new concept has aload-bearing core made of NiAl with inlaid ceramic fibressupporting a thin outer contour. This contour will be shieldedfrom the hot gas by a thermal barrier coating and arrays ofcooling holes. The temperature can be increased considerably

41



while at the same time reducing the cooling fluid by thismeans. The core of the blade with Al2O3 fibres is made bydiffusion welding, the fibres being coated to maximiseadhesion with the matrix. The outer contour is provided withlaser-drilled fields of cooling holes and a thermal barriercoating. The distribution of the holes varies over the bladesurface depending on the temperature and pressure as well asthe flow field over the blade. This concept allows a substantialincrease in the temperature inside the blade and a decrease inthe cooling fluid required, compared to current materials(Bohn, 2008).

6.2.2 IGCC projects with CCS

Announced carbon capture and storage (CCS) demonstrationand pilot projects for European coal-based IGCC are listed inTable 8, and projects from elsewhere in the world areincluded. The Nakoso demonstration IGCC is also expectedto have CO2 reduction in future (see Section 6.1.3). There arefurther plants planned for China, India, Japan, Spain and theUSA which are included by Ekborn (2007) and Mills (2008).Many plants have an uncertain future due to difficulties inobtaining permits and financial constraints.

AustraliaStanwell, nr Rockwell, QueenslandThe 120 MW (gross) demonstration IGCC plant with CCS isdue to be developed by 2012. The plant will capture up to75% of CO2 which will be compressed and transported forpartial storage in deep underground reservoirs in the NorthernDenison Trough. This will be followed by a 400 MW (gross)commercial-scale IGCC with CCS plant at a separate site inQueensland to be deployed by 2017. The power plant willcapture up to 90% of CO2 for full storage. The gas turbineprovider is currently GE (Zeus Development Corporation,2008a).

CanadaGeneseeThe Genesee IGCC project is in its second phase of front-endengineering and design, which is scheduled for completion in2009. Siemens will license its SFG-500 coal gasifertechnology. If subsequent investment and constructiondecisions go as planned, a 270MW coal-based IGCC withsingle train would be targeted to commence operations in2015. The near-zero emissions demonstration plant isdesigned to capture about 85% of the CO2 contained in thecoal and use it for enhanced oil recovery in nearby oil fields(EPCOR, 2008; Peckham, 2008). No information appears tobe available about the gas turbine.

ChinaGreenGen, TianjinThe three-phase project begins with a 250 MWe IGCC plant,to include CO2 separation at pilot scale, in 2009. The secondphase will provide 300–400 MWe with carbon separation by2015, increasing to 650 MWe with 55–60% efficiency andover 80% CO2 separation and storage by 2020 (SourceWatch,2008). The plant will use a Chinese gasifier and a SiemensSGT5-4000F (V94.3A) gas turbine with annular burner(Kanaar, 2008b).

Schellberg and others, 2008; Sears, 2008; van Haperen, 2008;

Feed Size, MWeCO2produced, Mt/y

coal 120

lignite 650 3.43

sub-bituminous coal 270 1.25

Chinese coals

250, 300-400,650

lignite 450 2.8

hard coal, biomass 1300 4.14

hard coal, biomass 450 2.5

hard coal, biomass 1000 4

hard coal 500t+250e 3.4

high ash coal, pet coke 14 MWt 0.035

hard coal 450 2.5

hard coal 900 4.75

hard coal, pet coke 800 4.22

hard coal 450 2.45

bituminous coal 632

bituminous coal 630 + SNG

bituminous coal/coal + petcoke 600

petcoke/coal blends 400 > 2

GermanyHürth RWEThe 455 MW gross IGCC will use Rhenish lignite with coaldrying technology and a quench gasifier at the Godenberg sitenear Cologne. The syngas will be diluted with N2 and H2O foran F class diffusion burner although the gas turbine has notyet been specified. The CO2 capture will use sour shift for92% capture rate. The net capacity will be 320 MWe, most ofthe auxiliary power use being for the air separation unit(49 MW) and gas cleaning (51 MW), with coal drying using19 MW. The net plant efficiency will be 34% (LHV).Contracts are currently being selected for the gas and powerislands, ready for commissioning at the end of 2014-15, ifapproved. The existing draft directive by the EU must betransferred into national law by mid-2009. Suitable CO2

storage formations have been located in north-west and north-east Germany for a maximum storage potential of 20 Gt.Exploratory drilling is to start in 2009-10 (Renzenbrink andothers, 2008).

ItalySulcisATI has been planning to build a 450 MWe (net) IGCC plantin Sardinia. This will use two Shell gasifiers to producesyngas from a 50% blend of the high sulphur, high ash Sulciscoal, with imported, lower heating value coal (Mills, 2006;Ekborn, 2007). No further information on either gas turbine orstart-up date appears to be available.

The Fusina combined cycle demonstration project is notrelevant to this report since it is not fuelled with coal butwith H2 from petrochemicals production. However, the 12MWe gas turbine is to be fed with fuel blends containing upto 100% H2. The plant will use a GE10-1 type of gas turbinewhich has a single shaft, eleven compressor stages, andthree turbine stages with a turbine inlet temperature of1070°C, compression ratio 15.5, outlet temperature of482°C, exhaust flow rate 47.5 kg/s and speed of 11,000 rpm.Reduction of NOx emissions will be achieved by injectingsteam in the combustion air flow and in the fuel gas.Integration with the existing 320 MW coal-fired powerstation will provide an extra 12 MWe from the gas turbine ofthe 16 MWe total (Balestri and others, 2006; Modern PowerSystems, 2008).

The NetherlandsMagnumThe Magnum project for a commercial IGCC at Eemshafenwas delayed due to permitting problems until mid 2011. It isdue to deliver about 1300 MWe from three combined cycleunits, including 550 MWe from natural gas. The proportionsof syngas/natural gas are optional. The specification for threegas turbines to deliver over 430 MW each was met byMitsubishi with the M701F4 design. As the plant has to beCO2 capture ready and hence firing H2, there will not be anyintegration to extract air from the compressor for the airseparation unit (Kanaar, 2008b). This accords with lessonslearned from the plant at Buggenum to favour a non-integrated, modern, standard air separation design, operated atfixed pressure (approximately 5–6 bar, 0.5–0.6 MPa) andbased on the internal compression concept with 100% liquidO2 draw off (Kanaar, 2008a).

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The operating philosophy is for the Magnum plant to providebase load with syngas from coal and secondary fuels, withpeak load on natural gas. Cofiring natural gas and syngas giveshigh flexibility. The plant will first operate on natural gas only,with provision for later conversion to IGCC with CO2 captureand storage. A pilot plant at Buggenum will use 1% of thesyngas flow to test the operating flexibility and performance ofcarbon separation. The carbon capture and storage obligationfor 2020 is likely to be 30% CO2 reduction and the Magnumplant will operate at 30–60% CO2 separation, increasing to60–90% for 2050 when a 60–80% CO2 reduction is required(Kanaar, 2008b; van Haperen, 2008).

SpainConstruction of a 14 MWth pre-combustion CO2 capture andH2 production pilot plant began at the Puertollano IGCC plantin November 2008 and is forecast to finish in July 2009. It isplanned to capture 35,000 tCO2/y. Sour and sweet CO shiftwill be tested as well as various systems for CO2/H2S or onlyCO2 removal. After CO2 separation, the syngas with an 80%H2 content can be added in before the combined cycle(Carbon Capture Journal, 2009; Schellberg and others, 2008).

UKHatfieldThe current consent is for a 430 MW IGCC plant to besituated on land adjacent to the re-developed Hatfield colliery.It is anticipated that a revised permission will be grantedshortly, allowing a resizing to a 900 MW (gross) coal IGCCplant which can also run on 100% natural gas during thecommissioning period and through maintenance periods ofthe gasification island. The proposed project has beendesigned to facilitate a move to burn syngas including CCS.No information appears to be available on the gas turbine.Powerfuel has a letter of intent with GE for the power trainengineering equipment package. The natural gas combinedcycle plant is expected to be commissioned in 2011, followedby the IGCC/CCS in 2013-14. The site is convenientlylocated to provide access to the North Sea for storage of CO2

following capture (Gibbons, 2008).

USAEdwardsportThe air permit was issued in February 2008 for the 630 MWecoal-based IGCC plant at Edwardsport, IN, USA. DukeEnergy Indiana is projecting summer 2012 for commercialoperation. The plant has a target availability of 85%. Therewill be an extended start-up period of 13 months toaccommodate new product introduction testing andvalidations (Sears, 2008). The GE 7FB gas turbine technologyhas been specified for this plant (Henderson, 2008).

Cash CreekCash Creek Generation LLC (a wholly owned subsidiary ofthe Erora Group) plans to build a 630 MW net (730 MWgross) IGCC plant co-producing power and SNG. The plantwould utilise GE gasification technology, methanationtechnology from Davy Process Technology, capture CO2 forEOR, and consume some 2.7 Mt/y of coal. The projectreceived its air permit and is expected to begin construction inmid-2009 for completion in 2012 (Blankinship, 2007;Carpenter, 2008).

Mesaba Energy ProjectExcelsior Energy Inc has applied for a permit to build theMesaba Energy Project – an IGCC plant to deliver 600 MWenet from 100% Powder River Basin subbituminous coal,100% Illinois No 6, or blends of coal with petcoke, usingConocoPhillips E-gas technology. Natural gas back-upprovides added fuel diversity to increase plant availability.The preferred site is on west Iron Range, near Taconite, MN,USA. The plant would include 30% CO2 capture for use inenhanced oil recovery in North Dakota and could be in-service in 2014 (Jorgensen, 2008; Stone, 2008).

HECA ProjectThe Hydrogen Energy California (HECA) project wouldgasify oil refining product and coal, capturing 90% of the CO2

from the fuel. An application for certification permit has beenfiled for the new 390 MW gross power plant to be sited inKern County, CA, USA. The captured CO2 would betransported by pipeline and used for enhanced oil recovery inlocal oil fields and be stored there permanently (HydrogenEnergy International, 2009).

Polk 6Tampa Electric had announced plans to build Polk 6, a full-scale 630 MWe IGCC power plant to provide electricity,expanding its current 250 MWe Polk IGCC (see Table 5).Provision was being made to add CO2 capture capacityincrementally, based on sweet shift technology (Blankinship,2007; Higman, 2007). However, Tampa Electric announced inOctober 2008 that it would meet its 2013 need for baseloadgeneration without using IGCC technology and withdrew itsapplication (TECO, 2009).

Kemper County demonstration IGCCMississippi Power has been invited to submit a formalapplication to the US DOE for a 550 MWe demonstrationIGCC facility in Kemper County, MS, USA, to include about25% removal of CO2. The CO2 would be piped off-site forenhanced oil recovery 60 miles away in Jasper County. TheIGCC would use lignite in two gasifiers to produce syngas fortwo gas turbines. The gas turbines would be capable ofoperating on either natural gas or syngas. If approved, theplant could operate from 2013 and, following a 4.5 yeardemonstration period, the facility would continue withcommercial operations afterwards (Zeus DevelopmentCorporation, 2008b).

6.3 Comments

Experience at the four commercial-scale coal-based IGCCplants in Europe and the USA will lead to future plants usingonly partial air-side integration, or none for plants which arecarbon capture ready. The best 12-month period of operationwith syngas from coal gasification corresponded to anavailability of 86%. The firing temperatures of the SGT5-2000E, SGT5-4000F, and GE 7FA gas turbines used in theseIGCC plants is 1060–1300°C on syngas from bituminouscoals or bituminous coals and pet coke; the net plantefficiency about 40–43% LHV. The demonstration IGCC inJapan has also achieved a net plant efficiency of 42.2% LHVon the M701DA with a firing temperature of around 1100°C

43



on syngas and this should eventually increase to 45% on theM501F and 48% LHV on the M501G gas turbine.

Future IGCC plants with 90% CO2 reduction will need towork using a syngas containing over 90% H2. More diluent isrequired for NOx reduction and this affects the whole system,especially:� the gas turbine pressure ratio, restricting compressor

performance;� derating of the turbine firing temperature may be

required;� thermal barrier coatings may be adversely affected;� 5–23% relative loss in net plant efficiency for various

configurations for CO2 reduction in IGCC for hard coal;� uncertain effect of converting to H2 firing on performance

of an IGCC which has been initially optimised forsyngas.

Gas turbine development for burning H2 needs to includeexperimental validation for optimised tradeoffs betweenefficiency and RAM, optimal gas turbine integration anddemonstration plants to validate concepts. The pilot anddemonstration projects should start this year so that resultsmay eventually become available, for example on theperformance of the GE 7FB, Siemens V 94.3A, andMitsubishi M701F4 gas turbines for syngas/H2.

Gas turbine developments are initially on natural gas-firedversions but flowing through later to syngas firing technology.Recent introductions of gas turbines on natural gas, includethe GE H-class machines using steam cooling of moving andstatic blades, with a firing temperature of 1426°C and theSiemens H-class machine with air cooling. Mitsubishi haveannounced their completed development of the J-class gasturbine, with a turbine inlet temperature of nearly 1600°C fordelivery in 2011. This also uses steam cooling and acompressor with a higher compression ratio. By contrast,current gas turbines on the four coal-based commercial IGCCplants in Europe and the USA, as well as the demonstrationIGCC in Japan, have firing temperatures of only1060–1300°C on syngas and net plant efficiencies of about40–43% LHV. The firing temperature of a gas turbine onsyngas is about 110–170°C lower than the natural gas firedequivalent.

The F and G-class gas turbines are aimed at increasedefficiency at firing temperatures over 1400°C with partiallydecarbonised syngas for 2015. Higher rates of carbonseparation should be achieved by 2020. Gas turbinecombustor development for 2015, to burn H2-rich syngas, isbased on hybrid, diffusion/premixed burners with fuelflexibility and low NOx emissions to 3 ppm. Few data havebeen released on RAM, although one commercial IGCC hasachieved an availability of 86% as a best 12-month period ofoperation on syngas from coal. It is essential that RAM bemaintained at improved efficiencies on H2-rich syngas. Gasturbine manufacturers appear confident that RAM and engineoperability would not be affected by adaptations required toretrofit gas turbines developed for natural gas to burn syngas.The pilot and demonstration projects due to start from thisyear should eventually yield results which may becomeavailable. Meanwhile progress gleaned from currentlypublished information is summarised in the followingsections.


The wide variation in the composition of syngas from coaland its difference from that of natural gas and other fuels isshown in Tables 1-3. Unlike natural gas which mainlyconsists of CH4, the combustible components of syngas fromcoal are mostly H2 and CO. The heating value varies widely.Removing some of the carbon may lead to an H2 contentexceeding 70vol%. The combustion properties of H2 and COare quite different from those of CH4. The high flame speed,high flame temperature and wide flammability range of H2,along with low ignition energy and low density, cause majorchallenges. For example, blowout and flashback have to beavoided. The large increase in volumetric fuel flow has to beaccommodated. The lack of data on syngas characteristics atconditions relevant to combustor operation has hinderedturbine design. However, gas turbine designers consider thatengine operability and RAM would not be affected by themodifications required for burning syngas.


The main effect of burning syngas on the compressor is surgeresulting from the higher volume flow and added N2 diluent.This increases for H2-rich syngases. Compressor surge maybe managed by removing air flow from the compressor tofeed the air separation unit or gasifier. An extra row ofcompressor blades gives a greater margin against compressorsurge.

The fuel system needs modification for start-up fuel anddiluent, ventilation, purge and fire protection, especially forH2-rich syngas. The materials of construction must be suitablefor H2 exposure and resistant to H2 embrittlement. The turbinedoes not require redesign or extra stages to burn synfuels andis usually able to accommodate the increase in mass flow. Thedanger of overheating, corrosion, erosion and depositionwhen using H2-rich synfuels, has led to improvements inthermal barrier coatings and film cooling design.

The combustor is affected most by burning syngas/H2. Ideally,combustion zones of specific dimensions and/or shape arerequired for each fuel. This makes the concept of dual-ormulti-fuel capability difficult to achieve in a single combustordesign. Metal temperatures can be maintained at acceptablevalues (around 950°C) by a combination of cooling air andthermal barrier coatings, or the use of ceramic tiles. The flameconfigurations may be classified into diffusion, premixed andcatalytic, developed to achieve stable and efficient combustionwith low emissions.


The diffusion combustor is the most commonly usedtechnology for burning syngas. The air and fuel are injectedseparately and are mixed by turbulent diffusion. The designhas had to avoid combustion instabilities which resulted fromfluctuating heat release. These lead to thermo-acoustic noisein some European IGCC plants, causing high pressurefluctuations and hence component failures. The H2 content ofsyngas results in a higher flame temperature than natural gas.This increases the NOx emissions. Diluents such as N2 orsteam are required to reduce NOx emissions; combustionmeasures may also be deployed. Early dry low NOxcombustors are limited to a maximum H2 content <10% (seefor example Figure 3) due to the potential for flashback.Current commercial IGCC plants have firing temperatures ofaround 1200–1300°C.

More advanced gas turbines are being developed with a firingtemperature of over 1400°C, increased compressor pressureratio, and further combustion enhancements. Somecharacteristics make the diffusion flame combustor behavemore like a premixed combustor. In Europe, the triple fuelsyngas burner (SGT5-4000F) has been developed in theHEGSA project of the EU Framework Programme 5 (seeFigure 4). This is based on the proven hybrid burner design ofF-class engines combined with the syngas experienceobtained with silo combustor engines. Tests with syngases

7 Conclusions

needed a small amount of steam dilution while H2 enrichedsyngases required both dilution with N2 and a significantamount of steam for base load operation without flashback.Combustion tests with syngases containing up to 40% H2

produced NOx emissions at 5 ppm and CO <1 ppm (at 15%O2) using steam as diluent. In the USA, the GE combustor inF-class engines for H2 is the IGCC version of the MNQC.Fuel ratios of 40%/60%-50%/50% H2/N2 can produce lowNOx emissions in an IGCC gas turbine (see Figure 6). Theadvanced H2 gas turbine for the US DOE is based on theSGT6-6000G which includes diffusion flame concepts withadvanced secondary air and steam cooling systems.

Diffusion flame combustors require low NOx combustiontechnology for high H2 fuels without the need for diluent.Staged combustion (two-stage, rich-lean combustion) hasbeen tested in Japan using wet gas cleaned synfuels from bothair-blown and O2-blown gasifiers. The use of N2 from the airseparation plant as diluent, coupled with fuel lean conditionsin the primary zone, reduced NOx emissions to 11 ppm (at16% O2) at a turbine load of 25% or higher. The designconcept for a 1500°C class combustor (see Figure 7) wastested with syngas from an O2-blown gasifier with hot dry gasclean-up. The NOx emissions could be reduced to 34 ppm (at16% O2) using combustion measures and some N2 injection.The combustion efficiency was around 100% in both cases.Further developments in the USA include lean direct injection(used to reduce NOx emissions from aircraft gas turbines) andhighly strained diffusion flame combustors. Oxyfuelcombustion, proposed to capture CO2 from engines, is mosteasily applied to diffusion flame combustors. Depending onthe regulations applied, there may be no need to control NOxemissions if the products are stored. Further NOx reductionsto reach the 3 ppm emissions limit requires SCR. Sulphurdeposits have been a problem with SCR on current IGCCplants. However, future plants will be able to use SCR withphysical scrubbing systems such as Selexol or Rectisol whichreduce sulphur gases sufficiently to avoid sulphate deposition.

Premixed combustors

Research programmes are developing premix H2 burners forsyngases. These sometimes include some elements ofdiffusion combustion. A lean premixed (dry low NOx) turbinemay operate in diffusion flame mode during operatingconditions such as start-up and shut-down, low or transientloads and cold ambient. A high H2 content in the synfuelincreases the tendency for flashback and pre-ignition inpremixed operation. Several developments to enable safecombustion of H2-rich mixtures (H2 up to 100%) are inprogress. In Europe, the lean-premix burner has beenconverted into a largely diffusion-type burner (see Figure 8).The syngas fuel is injected perpendicular to the air flow at theburner exit, rather than in the combustion air slots. Premixburners for IGCC with CO2 capture are under developmentbut not yet finished. In the USA, the advanced swirl premixcombustor is to be adapted and validated by 2015.

Trapped vortex combustion (see Figure 9) would eliminate theneed for high pressure diluent gas for NOx reduction andpost-combustion control. It has been tested on natural gas and

45

Conclusions


has potential to achieve low NOx, lean, premixed combustionon H2-rich syngas for IGCC applications. Low swirlcombustion is being developed as a dry low NOx technologyfor natural gas-powered turbines. The flow through theinjector is split, giving a non-swirling central core and aswirling outer annular flow. More extensive laboratory studiesare needed to develop low swirl injector designs optimised forsyngases. The rich-burn, quick-mix, lean burn combustorconcept, used to reduce NOx emissions from aero-propulsionengines, is of growing interest but requires moreunderstanding to optimise the design for fuels of varyingcomposition.


Research to develop low NOx catalytic combustors for gasturbines resulted in two different systems: a fuel-lean and afuel-rich system. The fuel-lean method premixes allcombustion fuel and air upstream of the catalyst and oxidisespart of the fuel in the catalyst stage. This induces gas-phaseauto-ignition in the downstream gas-phase combustion stagewhere combustion is completed. A pre-burner is generallyemployed to ensure the catalyst remains active during low-emission engine operation. The rich-catalytic lean-burncombustion (RCL™) system was developed for operation onnatural gas (see Figures 10-12). It has been tested successfullyon syngas and hydrogen fuels. Air staging upstream of thecatalyst (air is split to go through the catalyst and cooling theback of it) limits the amount of O2 on the catalyst bed,preventing flashback, auto-ignition and substrate overheating.At the reactor exit, the rich catalysed fuel/air stream and thecooling flow are mixed rapidly to produce a fuel-lean,reactive mixture prior to final combustion. The combustorgives stable operation with low NOx emissions over a widerange of firing conditions. It eliminates the need for expensiveexhaust gas clean-up and allows a wide choice of catalyst.Catalyst activity is greater than for fuel-lean operation so thata pre-burner is not normally required during low-emissionengine operation. The development of high temperaturematerials, advanced cooling, and long-term catalyst durabilitytests with real contaminants from syngas are required. Thefuel flexible, ultra low NOx (<3 ppm) system was beingtested at both E-class and F-class firing conditions and shouldbe commercially viable by the year 2015, according toinformation published up to 2006.


Lessons have been learned from experience of Siemens andGE gas turbines at the four commercial-scale coal-basedIGCC plants in Europe and the USA. The European plants arefully integrated so that the turbine is used to compress all theair required by the plant, maximising the efficiency. Thiscaused operating difficulties and reduced availability. Hence,future coal-based designs are likely to use partial air-sideintegration (50% of the air separation unit air demand).Nevertheless, the Willem Alexander IGCC, at Buggenum, TheNetherlands, has achieved a 12-month average availability of71–80% on syngas from coal gasification. This is similar tothat achieved on syngas from petcoke at the Wabash River

IGCC, IN, USA. The Nakoso demonstration IGCC in Japanuses an air-blown gasifier in order to avoid the high auxiliaryload of a large air separation unit, aiming to improveefficiency and reliability. The firing temperatures of the gasturbines used in these IGCC plants varies from around1060–1300°C on syngas. The net plant efficiency is about40–>43% LHV on bituminous coals or bituminous coals andpet coke.

Future IGCC plants will require CO2 reduction and a typicaldecarbonised syngas with 90% CO2 removal contains over90% H2. More diluent is required for NOx reduction,depending on several factors such as the type of gasifier, heatrecovery and air separation unit. This affects the pressure ratioof the gas turbine with restrictions on compressorperformance. Decarbonised syngas may require derating ofthe turbine firing temperature. The thermal barrier coatingsmay be adversely affected. Air extraction for feeding the airseparation unit is not currently possible for H2 turbines. Itappears that turbine design and performance is not affectedgreatly by total, partial or zero air integration (see Table 6).Hence zero air integration, which reduces operatingcomplexity, may be advisable for a plant which is carboncapture ready. Various configurations for CO2 reduction inIGCC for hard coal result in a wide range of relative losses inthe net plant efficiency over 5–23%. The effect of convertingto H2 firing on performance of an IGCC which had beeninitially optimised for syngas is uncertain.

Gas turbine development for burning H2 needs to consider:� advanced alloy and thermal barrier coatings for

interactions with high moisture/high temperaturecombustion gas;

� aero-thermal studies and experimental validation foroptimised tradeoffs between efficiency and RAM;

� process evaluations for optimal gas turbine integrationand demonstrations to validate concepts.

This year should see the start of the earliest coal-based IGCCwith CCS projects in China and Spain. Larger demonstrationprojects (500–>1000 MWe) should follow from 2012 (seeTable 8). In most cases, no information is available on the gasturbine, except:Stanwell, Australia GEGreenGen, China Siemens SGT5-4000F (V94.3A)Magnum, The Netherlands Mitsubishi M701F4Edwardsport, USA GE 7FB

46

Conclusions


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gas turbine technology for syngas/hydrogen in coal-based igcc

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