GE IGCC Technology and Experience with Advanced Gas Turbinesphysics.oregonstate.edu/~hetheriw/energy/topics/doc/elec/coal/igcc... · GE Power Systems GE IGCC Technology and Experience

GE Power Systems

GE IGCC Technologyand Experience with Advanced GasTurbines

R. Daniel BrdarRobert M. JonesGE Power SystemsSchenectady, NY

GER-4207

g

Contents

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Gas Turbine Low Calorific Value (LCV) Fuel Capability and Experience . . . . . . . . . . . . . . . . 1GT Fuel Flexibility with Variable IGCC Process Operations . . . . . . . . . . . . . . . . . . . . . . . . . . 3Environmental Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Economic Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Project Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

GE IGCC Technology and Experience with Advanced Gas Turbines

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GE Power Systems � GER-4207 � (10/00) ii

IntroductionIntegrated gasification combined-cycle (IGCC)systems continue to penetrate the power gener-ation market. General Electric has 17 projectsin design, construction or operation totalingmore than 3 GW of capacity. These projectsrange from 12 MW up to 550 MW in a variety ofconfigurations incorporating eight differentgasification technologies employing heavy oil,petroleum coke, coal, biomass and waste mate-rials as feedstock. Half of these projects are nowin operation and have accumulated over250,000 fired hours of syngas experience whilesimultaneously demonstrating excellent envi-ronmental performance. Power generationavailability has also been excellent, in excess of90%, due to the ability of GE gas turbines toswitch between fuels under load and co-firemultiple fuels.

In addition, IGCC capital cost continues todrop through advances in technology and theincorporation of lessons learned from operat-ing facilities. The ability of IGCC systems to uselow value feedstock and produce high value co-products along with power enhances the eco-nomic viability of new projects. The economicsof IGCC systems now allow the technology tosuccessfully compete in competitive power bid-ding situations where low cost indigenous gas isnot available. The introduction of the next gen-eration of gas turbine technology is expected tofurther reduce the capital cost of IGCC systems.

Gas Turbine Low Calorific Value (LCV)Fuel Capability and ExperienceThe ability to successfully burn LCV fuels overvarying conditions requires significant combus-tion expertise. Since 1990, the can-annularcombustion systems employed by GE have beenmodified to handle a wide variety of fuels andfuel mixtures. In addition, the can-annular

approach to combustion systems provides sig-nificant advantages in LCV applications, partic-ularly the ability to conduct combustion testingprior to equipment shipment.

This testing is conducted at a unique facilitylocated in Schenectady, NY. (See Figure 1.) TheCombustion Development Laboratory has ahigh-pressure test stand for each heavy-duty gasturbine model (6B, 6FA, 7EA, 7FA, 9E, 9EC,9FA) as well as a component test rig. Usingthese test stands, a single combustion can istested with a simulated syngas under full pres-sure and flow conditions. As opposed to partialflow and pressure conditions, full flow and pres-sure conditions enable the performance char-acteristics of an individual combustion can to bereadily translated to full machine performance.This ability to test at full flow and pressure con-ditions has been one of the single largest con-tributors to the successful start-up and opera-tion of GE gas turbines in LCV gas applications.

Due to the unique demands on the combustionsystem by LCV gases, full characterization ofcombustor performance is essential. This test-ing involves considerably more than a simpleverification of combustion stability. It is impor-tant to address combustor operation and itsaffect on overall gas turbine operation. As aresult, a wide variety of tests are conducted for


GE Power Systems � GER-4207 � (10/00) 1

Figure 1. GE Combustion Development Laboratory

all unique LCV gases. Figure 2 shows the list oftypical combustion tests and variables. The pur-pose of these tests is to evaluate combustor andmachine performance as load conditions, LCVgas composition, fuel mixtures, ambient condi-tions, diluent composition and conditions andother factors vary. As these conditions change,an assessment of combustion dynamics, metaltemperatures, system pressure losses, emissions,and exit temperature profiles is conducted.

LCV gases can vary widely from one applicationto another and are highly dependent on theparticular process producing the gas, the oxi-dant used in the process and the process feed-stock. For example, the LCV gas produced byan air-blown, coal-fueled, fluid bed gasifier willdiffer significantly in composition from an oxy-gen-blown, vacuum residue-fueled, entrained-flow gasifier. The resulting gas composition,flammability and calorific value work in concertto form the basis for the combustion systemdesign and response.

Most LCV gases have a wide range of flamma-bility when compared to more conventionalfuels such as natural gas. In Figure 3 it can beshown that there is considerable differencebetween the rich and lean fuel firing limits formost LCV fuels. As gas calorific value becomes

lower (moving to the left on the flammabilitycurve), flammability limits narrow and the com-bustion process itself becomes more sensitive tochanges in calorific value. Changes in the gascomposition of very low calorific value gasessuch as blast furnace gas (BFG) can quicklymove a gas from flammable to the non-flamma-ble region of the chart. As a result, GE hasdeveloped special designs to accommodate verylow heating value fuels such as BFG. Theunique capabilities of the CombustionDevelopment Lab allow GE to fully explorethese issues and design LCV combustion sys-tems for a specific application. Combustionissues can be explored in the lab and solutionsimplemented in the combustion system designand production hardware prior to actual fieldoperation.

As shown in Table 2, as of March 2000, GE gasturbines applied to LCV applications have accu-mulated approximately 260,000 syngas-firedhours with the three 109E combined cycles atILVA representing the fleet leader with morethan 78,000 hours of operation. GE gas turbinesburning LCV gas encompass a wide variety ofoperational demands, varying gas composi-tions, and gas turbine frame sizes and include"E" and "F" level gas turbine technology. Someunits such as the 6FAs at Exxon Singapore are



Combustion Test Parameters

• Emissions

- NO, NOx, CO, UHC, O2, CO2

• Combustor Metal Temperatures

• Combustion Dynamic Pressures

• Combustor Exit Temperature Profiles

• Combustion System Pressure Drop

• Air Extraction Limits

• Power Augmentation Limits

• Combustion System Temperaturesand Pressures

• Turn Down

- Minimum Temperature Rise

- Minimum Calorific Value GT24485 . ppt

• Air Flow and Temperature

• Air Extraction Flow

• Diluent (Inert) Injection Flow

• Syngas Composition

• Syngas Temperature

• Conventional Fuel Flow

• Syngas/Conventional Fuel Split

• Power Augmentation Flow

• Combustor Exit Temperature

Combustion Parameters Test Parameters

Figure 2. Combustion test parameters

Figure 3. Syngas flammability limits

expected to operate at 40 discrete points whileothers such as the 7FA at Tampa Electric aredesigned to operate at baseload conditions onsyngas once the unit has achieved startup. Thecomposition of the syngas consumed in theseoperating units also varies considerably fromproject to project. A measure of this project-to-project variability is the hydrogen content ofthe fuel. As shown in Table 3, the hydrogen con-tent of these operating units varies widely froma low of 8.6% at ILVA to a high of 61.9% atSchwarze Pumpe with heating values of 193 and318 Btu/SCF respectively. These diverse condi-tions and operating demands emphasize theimportance of sound combustion systemdesign.

Based on the operating history of these units, itis clear that GE gas turbines and combinedcycles applied to LCV applications can achievereliability, availability and maintainability(RAM) performance levels comparable to natu-ral gas-fueled units. The use of a properlydesigned dual-fuel combustion system and itscontrols are key to achieving these RAM levels.

GT Fuel Flexibility with Variable IGCCProcess OperationsFor IGCC high-hydrogen content syngas fuels,GE gas turbine units include dual fuel capabili-ty (syngas/natural gas or syngas/liquid). A con-ventional fuel is required for startup and shut-down, although the combustion and control sys-tems are designed to operate over the entireload range on either fuel. Depending upon thequantity of syngas available, the unit may beoperated in a variety of fuel conditions rangingfrom co-firing (i.e. startup fuel and syngas), tofull syngas firing at rated load conditions.During normal process operations, where thesyngas production matches the turbine fuelrequirements, the unit is transferred fully onto

syngas, and may utilize supplemental diluentinjection (e.g. nitrogen, carbon dioxide, orsteam), to effect NOx emission control and/oraugment power production.

When process operations change whereby syn-gas fuel becomes limited or otherwise unable tomeet the total turbine fuel requirements, atransfer back to co-fired operations using start-up fuel is selected or can be automated to holdpower to operating limits. While operating inco-fired or mixed-fuel mode, fuel input limits(expressed as a percentage of total heat input tothe gas turbine), on each fuel are imposed inorder to maintain minimum allowable pressuredrop conditions. The limits for co-firing syn-gas/liquid are typically 90% / 10% syngas/liq-uid to 30% / 70% syngas/liquid. Since each gaspassage in the fuel nozzle is essentially a fixedorifice, the minimum syngas flow correspondsto a minimum allowable pressure drop acrossthe particular gas nozzle, which in turn hasbeen determined for each system primarily toavoid unacceptable pressure fluctuations (com-bustion dynamics). A minimum pressure ratio isalso required to maintain adequate can-to-canfuel distribution as well as avoiding cross flowfrom can-to-can. The minimum liquid flowbeing that required to avoid overheating of fuelpumps and again to establish good fuel distri-bution.

For dual gas fuel (syngas/natural gas) systems,the minimum gas flow requirement can be sub-stantially reduced below 30% heat input byusing a variety of control schemes that mayinclude a combination of co-firing and fuelblending. The Shell Pernis fuel system, forexample, operates on a variety of syngas, naturalgas, LPG mixtures, as well as 100% natural gasas illustrated in Figure 4. A similar system hasbeen applied to the Exxon Singpore gasifica-tion project to meet operational requirements



which allow for a 90% / 10% split on syngas andnatural gas as illustrated in Figure 4. Nominally,for a dual gas – dual manifold system withoutblending, the minimum fuel split for any onegas is 30% by heat input at rated load.

Variation in syngas production can be compen-sated by co-fired operations when constant out-put is necessary. For example, in cases wherethe quantity of available syngas is changing dueto chemical co-production priorities, a modu-lating fuel split arrangement can be utilizedwhere the percent syngas firing is continuouslyadjusted to match the process operations. Theco-fired fuel is then raised or lowered to main-tain turbine output on load control. While co-firing operations may increase operating costs,the revenue gained from incremental kilowatthour generation may more than compensatewith improved generation capacity factors accu-mulated over annual operating periods.

The gas turbine when fully fired on typical syn-gas compositions has the potential to developenhanced power output capacity due in largepart to the significant flow rate increase (~14%incr. over natural gas), resulting from the lowheating value fuel combustion products passingthrough the turbine. Figure 5 shows the 20-25%higher ratings that are normally achieved when

operating on syngas, and illustrates the poten-tial for flat ratings across the ambient tempera-ture range. These increased ratings take intoaccount the GE criteria for parts lives whichrequires a reduction in syngas firing tempera-tures to maintain hot gas path parts at tempera-tures similar to natural gas units. The higherturbine flow and moisture content of the com-bustion products can contribute to overheatingof turbine components. The insert in Figure 6,shows that these effects, uncontrolled, couldlead to life cycle reductions on the “stage 1bucket” of more than half. GE IGCC control sys-tems include provisions to compensate forthese effects.

Since fuel process operations do not vary signif-icantly with ambient operating conditions, thegas turbine power train provides nearly con-stant output generation when linked to syngasfuel production. At low ambients the gas tur-bine airflow is regulated by variable inlet guidevane (IGV) position to maintain constantfuel/air ratios. As ambient temperaturesincrease, IGVs open to maintain airflow untilfull open position is reached. The flat outputrating may be further extended to higher ambi-ents by utilizing surplus process steam and/ornitrogen injection for power augmentation.Such an arrangement is employed at the Tampa



IGCC Mixed Fuel Capability

BKGT25004A . ppt

For a Dual Fuel GT (Gas/Natural Gas)

Approx 20

• % Split Is in Terms of % GT Total Heat Consumption

% Load

% Natural Gas

100

00 10 50 90 100

% Split

100 90 50 10 0 % Syngas

Shaded: MixNot Permitted

Mix Permitted(Allowable Splits)

Figure 4. Mixed fuel firing

• 14% Difference in Flow atSame Firing TemperatureMakes 28% More Output(No Compression Power)

20% Extra Output20% Extra Output

Natural Gas 2% NG Exhaust 102%

CG Exhaust 116%Coal Gas16%

Air - 100%

Gas TurbineGen

Ambient Temperature

59 F15 C

Natural Gas

Flat-Rated Region9F

OutputMW

50 Hz

7FOutput

MW60 Hz

Low Heating Value Gas

GT IGCC

- 6FA- 7FA- 9EC- 9FA- 7H- 9H

----

90 MW200 MW215 MW300 MW

126 MW280 MW300 MW420 MW460 MW550 MW

GT23887G

Figure 5. IGCC output enhancement

Electric Polk IGCC project where gas turbineoutput is maintained nearly constant for ambi-ent temperature conditons up to 32°C/90°Fwith process nitrogen injection.

Environmental CostsIGCC plants sited to date offer designs thatexhibit superior environmental performancecompared with generation alternatives usingsimilar feedstocks. Emission pollutants caninclude low levels of oxides of nitrogen (NOand NO2), carbon monoxide, unburned hydro-carbons, oxides of sulfur, and particulate mat-ter. In particular, the emission of acid rain pol-lutants (including NO2 and SO2), from gas tur-bines fueled by syngas are to a large degreecharacterized and controlled by process designand integration with the turbine combustionsystem. Figure 7 lists NOx emission levelsachieved to date with GE gas turbine units oper-ating at several plant facilities over the past fif-teen years, in addition to predicted levels forother IGCC sites currently under construction.

Typically, with oxygen-enriched gasificationprocesses, nitrogen is readily available for directinjection into the gas turbine combustion sys-

tem as a primary diluent for NOx control.Similarly, for syngas processes where nitrogen isnot available, fuel moisturization using aprocess saturator is extremely effective in reduc-ing combustion flame temperatures to controlNOx emissions. GE has performed extensivelaboratory testing using lower calorific valuesyngas to evaluate combustion system perform-ance including flame stability and efficiency, aswell as emission characterization. Full pressureand temperature test programs using variousprocess diluents including: N2, H2O, and CO2,as shown in Figure 8, illustrate that dramaticNOx reduction is achievable, even at 1400°C



Syngas - Reliability / Availability / Maintenance

• Need Automatic FuelSwitch/Nitrogen Purge

• Need Clean Syngas

• Reduced Firing Temp to MaintainDesign Metal Temp / 100% Life

Proven Experience ImportantProven Experience Important GT26110A .ppt

Syngas Combined Cycle Can Have Same Performance asNatural Gas Combined Cycle

Lessons Learned

1984 Cool Water - 3 Year Program to Reach 80% Availability (CC at 95%)

1996 Tampa - 1 Year Program - Auto Fuel Switching (N 2 Purge Solution)

1996 PSI - Some Cracking of Combustors - Replaced SuccessfullyWith Tampa Design

1996 El Dorado - Successful Start-Up First Try

- 1997 - 99.7% Availability of GT

- 1998 - 98.0% Availability of GT

0 20 40

1

0.8

0.6

0.4

0.2

0

Vol % H2O in Exhaust

Life F

raction

IGCC ControlSystem

10 30

Figure 6. Effect on firing temperature

IGCC Environmental PerformanceOperating NOx ( ppmdv @15% O2)

Cool Water 25PSI - Wabash <20Tampa - Polk <20Texaco - El Dorado <25

Predicted Sierra Pacific <42 (<9 Thermal)

Motiva Delaware 9-15Sarlux <30Fife <42

Figure 7. IGCC NOx emissions

combustor exit temperatures, by effectivereduction in equivalent fuel heating valueand primary flame zone temperatures.Although many process applications utilize pre-mixing of these diluents with the syngas prior todelivery to the gas turbine, laboratory testinghas determined there is little difference on thenet effect of emissions reduction between pre-mixing and direct injection into the combustorreaction zone. GE prefers direct diluent injec-tion into the individual combustors for reasonsassociated with controllability, efficiency, andsystem cost. For extremely low NOx emissionsites (i.e. < 9 ppmvd @ 15% O2), back end treat-ment using selective catalytic reduction meth-ods in the exhaust heat recovery equipmentarea may become necessary.

The residual sulfur compounds remaining inthe syngas following process treatment andcleanup directly determine sulfur oxide emis-sions. A variety of process designs are usedwhich establish the level of sulfur recovery fromthe raw syngas. Cost constraints are the primaryconsideration, however, sulfur recovery effi-ciencies in the range of 98–99.5% incorporat-ing COS hydrolysis are readily achievable tomeet site permitting requirements.

The thermal performance of IGCC plants burn-

ing heavy fuels are proving to be superior toother generation alternatives particularly whenusing today’s advanced gas turbine technolo-gies. Continued improvements in IGCC cycleintegration coupled together with further tech-nological advances in turbine designs (e.g. GEmodel H), are paving the way for higher cycleefficiency levels that will not be achievable withcompeting generation technologies. As a result,carbon dioxide production per kilowatt ofpower generation with IGCC plants burningthese fuels will be the lowest in the industry.Combustion testing completed earlier this yearat GE’s Combustion Development Laboratoryin Schenectady, NY have confirmed stable com-bustor operations and excellent emission per-formance characteristics while burning syngascomposed of 50% hydrogen and 50% nitrogen,allowing for the elimination of nearly all CO2emissions. IGCC plants, where necessary, can bereadily designed to extract and sequester CO2from pre-combustion syngas, allowing for virtu-ally carbon-free emissions.

Economic ConsiderationsDramatic improvements have been made inIGCC system capital cost. Solid fuel plants havebeen recently bid for less than $1,000/kW on aturnkey basis. This is 30–40% of the cost of thefirst few IGCC plants. These capital cost reduc-tions are due to a variety of factors, the mostinfluential being: 1) gas turbine performanceenhancements; 2) gasification system enhance-ments; and 3) EPC learning curve effects.

Economics have largely shaped the configura-tions, applications, and end users of IGCC sys-tems in recent plant decisions. Although earlytechnology studies focused on coal-based utilitypower production, economics now favor a dif-ferent approach. Most of the later IGCC plantsare constructed by IPPs, predominately in refin-



4000 5000 6000 7000 8000 9000 10,000 11,000

1000

100

10

0

100 150 200 250 300

N2

CO2

H2O

•Simulated Coal Gas

•2550 F/1400C CombustorExit Temperature

LHV, Btu/SCF

LHV, kJ/m3

NO

x, PP

MVD

Full Load NOx at 15% O2 vs Heating Value

Figure 8. Effect of diluents for NOx

ery applications using refinery bottoms as gasi-fication feedstock and produce electricity andhigh value co-products such as hydrogen andsteam for refinery purposes. In these configura-tions the technology has become very competi-tive and will continue to drive down costs andspur innovation.

Based on today’s gas turbine technology, appli-cations using solid and liquid opportunity fuelswith cogeneration and/or co-productionschemes are competitive in the marketplace.Continued technology improvements and opti-mized cycle and co-production configurationscontinue to drive down the capital cost of IGCCand its resulting cost of electricity. In addition,coal-based IGCC plants are now a competitivealternative in countries with severe environ-mental restrictions or areas that depend on theuse of high-priced power generation fuels suchas LNG.

An example of the continued improvement incoal-based IGCC performance and economicsis shown in Figure 9. A recent study by GE,Texaco, Inc. and Praxair, Inc. evaluated a varietyof coal-fueled IGCC configurations based on aGE 9FA based combined cycle. Through cycleoptimization studies and by incorporating thelessons learned from operating facilities, cyclessuch as the high efficiency quench (HEQ) can

be utilized. The HEQ cycle uses high pressurequench gasification coupled with a syngasexpander. The HEQ cycle maintains high IGCCsystem output while reducing the total capitalcost by eliminating a significant portion of thehigh temperature heat exchangers in the gasifi-cation plant. The results of the study indicatethat the 9FA HEQ configuration costs 10% lesson a cost of electricity basis than it did just twoyears ago. The full results of this study are pub-lished in other papers. Continued improve-ments in gas turbine and gasification systemperformance along with increased operatingexperience will continue to reduce the invest-ment required on future IGCC plants.

The next generation of gas turbines is expectedto enhance the economic competitiveness oftoday’s cogeneration/co-production IGCC con-figurations as well as allow coal-based power-only IGCC plants to successfully compete in themarket. Technology improvements embodiedin the GE “H” machine are projected to yieldsubstantial improvements in performance andsignificant reductions in the capital cost of allIGCC systems. Early studies predict a significanttotal capital cost reduction in mature “H”-based IGCC systems cost with efficiency reach-ing 50% (LHV basis) on coal-based power pro-duction. Figure 10 shows the relative cost of elec-tricity for various technology and fuel options.



9FA Based HEQ IGCC

Feedstock

Output (MW)

Efficiency (%)

- LHV

- HHV

Cost of Electricity*

1997Coal

1999 2000Coal Oil

408 449 436

42.5 43.3 45.140.9 41.8 42.8

5.26 4.69 4.39

*(20 yr. levelized)

Another 10% COE ReductionAnother 10% COE Reduction

Figure 9. Continued COE reductions

C/k

Wh

(20

Yr.

Lev

eliz

ed)

2

Combined Cycle IGCC - Coproduction

Fuel

O&M

Capital

Differential

Fuel Cost

1

3

4

5

6

0F Ref. H

Bottoms

H

Coal

F

Coal

F

Gas

H

Gas

F

LNG

H

LNG

GT26115A .PPT

IPP Economics: 1.5$/Mbtu Coal; 1.0 $/Mbtu Bottoms, 2.5 $/Mbtu Gas; 4.0 $/Mbtu LNG

Figure 10. Cost of electricity comparison

In places that do not have cheap indigenousgas, IGCC is already a competitive technology.Since IGCC can use dirty, low cost opportunityfuels, the “fuel cost differential” further reducesthe cost of electricity. The introduction of “H”level gas turbine technology is expected to fun-damentally shift the economics of IGCC sys-tems. Studies are currently in progress to morefully evaluate this potential.

Project ExperienceGE leads the world in the application of itsheavy duty gas turbines to gasification com-bined-cycle gas projects. As of December 1999,twelve GE heavy-frame gas turbines were opera-tional using synthesis gas from the gasificationof coal, petroleum coke and other low gradefuels. Seven additional gas turbines at three dif-ferent plants will become operational in 2000.These plants are Motiva-Delaware (two 6FAs),Sarlux (three 109Es), and Exxon Singapore(two 6FAs). Additional units for gasificationapplications are on order with startup datesranging from 1999 through 2003. Once theseprojects are in operation, a total of 26 GE gasturbines will be operational with syngas cover-ing the entire product family from PGT10B upthrough and including 9FA gas turbines.

The IGCC projects include various levels ofintegration with the gasification plant, rangingfrom steam-side integration only on many proj-ects, to nitrogen return (Tampa & Motiva), andfull steam and air integration including both airextraction and nitrogen return (El Dorado,Pinon Pine). GE turbines are in operation onsyngas-from-gasifier technologies by Texaco(solid fuels and oil), Destec (coal), GSP (coaland waste), Shell (oil), and operation with theLurgi gasifier (biomass), is scheduled for 2001.

In addition to the synthesis gas applications andoperating experience summarized in Tables 1

and 2 below, GE also has numerous turbines inoperation on other special fuel gases, includingrefinery gases containing hydrogen, butane,propane, ethane, and blends of various processgases. These units include six Frame 3s, seven-teen Frame 5s, 19 Frame 6s, and 15 Frame 7EAs.

GE’s success with low and medium Btu fuelgases is a consequence of extensive full-scalelaboratory testing on various fuels for over 15years at GE’s Combustion DevelopmentLaboratory in Schenectady, NY. As mentionedearlier, this facility provides the unique oppor-tunity to simulate customer specific fuel gas,and then test a single combustor at full-flow,full-pressure operations to investigate combus-tion conditions, and confirm liner cooling andfuel nozzle designs before fabrication of theproduction hardware. Table 3 shows the widerange of syngas compositions which are beingused on various GE low-Btu projects. Data fromthese tests form the basis for emission guaran-tees, turndown performance, and parts livesestimates. Most recently GE has made laborato-ry improvements to incorporate fuel blendingsystems. The primary combustibles, namely COand H2, are supplied in tube trailers. N2, CO2,steam, natural gas and ammonia may be blend-ed on-line to achieve the desired fuel composi-tion. With this arrangement, it is now possibleto vary the H2 content as well as the H2/COratio during a test to evaluate hardware capabil-ities and simulate field operations where syngascompositions may vary daily to meet changingchemical co-production requirements.

ConclusionsThe successful integration of heavy-duty gas tur-bine technology with synthetic fuel gas process-es using low-value feedstocks is proving to becommercially viable in the global power gener-ation marketplace. Continuous cost improve-



ments in both gas turbine and process plantdesign is allowing for significant market pene-tration into refinery based IGCC applications aswitnessed by several projects currently in opera-tion with additional plants coming on-line byyear’s end. The introduction of the GE "H" gasturbine technology raises the prospect for sig-nificantly greater cost reductions as power den-sities and cycle efficiencies set new operationalbenchmarks for the foreseeable future.

Gas turbine fuel flexibility and co-firing capabil-ity provide additional IGCC economic benefitsallowing for the co-production of other highvalue by-products while maintaining highpower generation availability. The capability topre-test combustion hardware using simulatedfuel gases at full operating conditions has fur-ther demonstrated superior environmental per-

formance with coal and other low grade feed-stock and provides for optimized integratedplant designs. In addition to very low emissionlevels of particulate, sulfur dioxide and nitro-gen oxides, the potential to remove carbondioxide and burn a hydrogen-rich syngas in thegas turbine may become a significant advantagefor IGCC systems as countries take steps toreduce their overall carbon dioxide emissions.

Finally, experience gained from several syngasprojects are providing invaluable lessonslearned that continue to foster cost reductionsand improve operational reliability. As addition-al IGCC plants go operational, further improve-ments in system performance and plant designare to be expected drawing from an extensivesuccessful experience base.





Customer Location COD MW Pwr Block Application Integration Gasifier Fuel

Cool Water Barstow, California 1984 120 107E Power Steam Texaco Coal

IGCC

PSI Wabash River Terre Haute, 1996 262 7FA Power Steam Destec Coal

Indiana

Tampa Electric Polk, Florida 1996 250 107FA Power Steam/N2 Texaco Coal

Pinon Pine Sparks, Nevada 1996 100 106FA Power Steam/Air KRW Coal

Sierra Pacific

Texaco El Dorado, Kansas 1996 40 6B Cogen Steam/Air/ Texaco Pet

El Dorado N2 Pet Coke

ILVA ISE Taranto, Italy 1996 520 3x109E Cogen None Steel Mill COG

SUV Vresova, 1996 350 209E Cogen Steam ZVU Coal

Vresova Czech Rep.

SVZ Schwarze Pumpe, 1996 40 6B Cogen/ Steam GSP Coal/

Germany MeOH Waste

Shell Pernis Pernis, Netherlands 1997 120 206B Cogen/H2 Steam Shell/ Oil

Lurgi

Fife Energy Fife, Scotland 1999 109 106FA Power None Lurgi Coal/

Waste

Motiva Delaware City, 1999 180 2-6FA Cogen Steam/N2 Texaco Pet Coke

Delaware

Sarlux Sarroch, Italy 2000 550 3x109E Cogen Steam Texaco Oil

Fife Electric Fife, Scotland 2000 350 109FA Power None Lurgi Coal/

Waste

Exxon Jurong Island, 2000 173 2-6FA Cogen None Texaco Oil

Singapore Singapore

IBIL Gujarat, 2001 53 106B Cogen Steam/Air Carbona Coal

Sanghi India

Bioelettrica Cascina, 2001 12 1-PGT10B/1 Power Steam Lurgi Wood/

TEF Italy Waste

EDF-Total Gardanne, 2003 400 2x9E Cogen/H2 Steam Teaxco OilFrance

Table 1. GE IGCC projects

Table 2. GE Syngas experience (March 2000)

SyngasCustomer Type MW Start Date Hours of Operation

Syngas N.G. Dist.

Cool Water 107E 120 5/84 27,000 - 1,000

PSI 7FA 262 11/95 17,230 - 3,500

Tampa 107FA 250 9/96 18,060 - 4,300

Texaco El Dorado 6B 40 9/96 17,180 24,100 -

Sierra Pacific 106FA 100 0 26,500 -

SUV Vresova 209E 350 12/96 53,170 2,200 -

Schwarze Pumpe 6B 40 9/96 21,080 - 3,400

Shell Pernis 2x6B 120 11/97 29,770 18,900 -

ISE/ILVA 3x109E 540 11/96 78,950 3,700 -

Fife Energy 6FA 80 0 11,600 -

GE Totals 262,440 - -



Table 3. Syngas comparison

GT25217B

14.5

23.6

1.3

5.6

49.3

5.7

127

5000

Sierra

Pacific

8.6

26.2

8.2

14.0

42.5

--

193

7600

ILVA

12.7

15.3

3.4

11.1

46.0

11.5

115

4530

IBIL

61.9

26.2

6.9

2.8

1.8

--

318

12,520

Schwarze

Pumpe

22.7

30.6

0.2

5.6

1.1

39.8

163

6420

Sarlux

H2

CO

CH4

CO2

N2 + AR

H2O

LHV, - Btu/ft 3

- kJ/m3

Syngas

8350

PSI

27.0

35.6

0.1

12.6

6.8

18.7

202

7960

Tampa

35.4

45.0

0.0

17.1

2.1

0.4

242

9535

El Dorado

34.4

35.1

0.3

30.0

0.2

--

209

8235

Pernis

* Always co-fired with 50% natural gas** Minimum range

Tfuel, F/ C

H2/CO Ratio

Diluent

Equivalent LHV

570/300

.63

Steam

700/371

.75

N2/H2O

250/121

.79

N2/Steam

200/98

.98

Steam

1000/538

.62

Steam

400/204

.33

--

1020/549

.83

--

100/38

2.36

Steam

392/200

.74

Moisture

- Btu/ft3

- kJ/m3

150

5910

118

4650

113*

4450

198

7800

110**

4334

--

--

115

4500

200

7880

--

--

24.8

39.5

1.5

9.3

2.3

22.7

212

34.4

55.4

5.1

1.6

3.1

--

322

12,690

Fife

100/38

.62

Water

*

--

44.5

35.4

.5

17.9

1.4

.1

242

9,530

Exxon

Singapore

350/177

1.25

N2/Steam

116

4600

List of FiguresFigure 1. GE Combustion Development Laboratory

Figure 2. Combustion test parameters

Figure 3. Syngas flammability limits

Figure 4. Mixed fuel firing

Figure 5. IGCC output enhancement

Figure 6. Effect on firing temperature

Figure 7. IGCC NOx emissions

Figure 8. Effect of diluents for NOx

Figure 9. Continued COE reductions

Figure 10. Cost of Electricity comparison

List of TablesTable 1. GE IGCC projects

Table 2. GE syngas experience (March 2000)

Table 3. Syngas comparison



GE IGCC Technology and Experience with Advanced Gas Turbinesphysics.oregonstate.edu/~hetheriw/energy/topics/doc/elec/coal/igcc... · GE Power Systems GE IGCC Technology and Experience

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