igcc for refinery

GE Power Systems

IGCC Gas Turbines forRefinery Applications

Robert M. JonesNorman Z. ShillingGE Power SystemsSchenectady, NY 12345

gGER-4219

Contents

Abstract. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1IGCC Refinery Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Gas Turbine Advancements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Fuel Flexibility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Environmental Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

GE IGCC Gas Turbine Product Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Economic Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15List of Figures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

IGCC Gas Turbines for Refinery Applications

GE Power Systems � GER-4219 � (05/03) i

GE Power Systems � GER-4219 � (05/03) ii


GE Power Systems � GER-4219 � (05/03) 1

AbstractIntegrated Gasification Combined Cycle(IGCC) plant designs are successfully operatingand meeting challenging service requirementsat several world-class refinery locations aroundthe globe. Advancements in gasification, airseparation, syngas cleanup, and gas turbinecombined cycle equipment designs have con-tributed to continuous improvements in systemperformance and operating characteristics.These improvements enhance the prospect forcontinued growth in the IGCC refinery seg-ment. Today's challenge for IGCC systems is tomeet market requirements (which demandlower capital costs, improved operating reliabil-ity, and increased fuel flexibility) in combina-tion with increasing efficiency and environmen-tal performance standards.

This paper focuses on improvements in gas tur-bine technology that contributed to the com-mercialization and leadership of IGCC systemsfor the clean conversion of refinery residuesand solid wastes to economical “poly-genera-tion” of power and other high valued by-prod-ucts used by the refiner.

Environmental performance is a key bench-mark for contemporary IGCC plant design.IGCC’s high marks in environmental perform-ance stem from both the fundamental charac-teristics of the process and advances in gas tur-bine technology. The early breed of commercialIGCC refinery projects (at Texaco El Doradoand Shell Pernis) still achieve performance incriteria pollutants that are better than that ofmany direct-combustion technologies. IGCC’sviability is ensured by its capability to meettighter emissions standards for criteria pollu-tants including NOx, SOx, and particulates.

Fuel flexibility provides a hedge against poten-tial excursions in both fuel cost and availability.The robustness of gasification technology to

deal with a wide range of solid and liquid fuelshas been demonstrated in refinery applicationsfueled by heavy oil and petroleum cokeresidues—integrated with systems providingboth power generation and chemical co-pro-duction. Current gas turbine combustion con-trol systems provide for full or combined “co-fir-ing” of synthesis gas with natural gas or distillateback-up fuels.

To date, GE gas turbines have accumulatedmore than 499,000 fired hours on synthesis fuelgas (of which 132,000 hours were fired on syn-gas derived from refinery feedstocks). Thisbroad experience—enabled in large part bydevelopments in gas turbine technology—serves as a superb entitlement for environmen-tally superior value generation from poor quali-ty, low cost opportunity fuels.

Improvements in gas turbine performance onlow heating value syngas fuels have enhancedthe economics of IGCC systems to where it is aclear choice for new power generation atrefineries. GE has a total of ten IGCC projectsthat have gone into syngas operations, with fivemore plants either beginning or planned foroperation within the next four to five years.Nine of these fifteen plants are associated withrefinery operations. GE continues to invest inturbine product development efforts allowingfor increased performance benefits with liquidand solid fuel IGCC projects.

IntroductionIntegrated Gasification Combined Cycle(IGCC) systems are receiving increased recog-nition as flexible, environmentally superiorsolutions for the conversion of solid and heavyliquid feedstock to power, co-generation steam,and other chemical production purposes. Thecapability of IGCC systems to use opportunityfuels to produce high value co-products along



with power generation enhances the economicviability of new projects. The co-production ofchemicals and other utility products requiredby refineries is a key advantage afforded byIGCC technology. By fully utilizing the capabil-ities of modern combined cycle designs, IGCCsystems are able to achieve exceptional levels ofenvironmental performance, availability, andefficiency at a competitive cost of electricity.

With the production of conventional syngasfuel components, the opportunity exists to fur-ther separate carbon elements prior to combus-tion and sequester CO2 when necessary.Improvements in advanced gas turbine tech-nologies—allowing for increased power densi-ties, improved cycle efficiencies, and lowerinstalled costs—will continue to enhance IGCCsystems to provide increased benefits and capa-bilities to refineries for the foreseeable future.

The environmental legislation proposed in theU.S. to reduce sulfur content in transportationfuels from >250 ppm to <15 ppm by the year2006 has many refiners facing costly processdesign changes. The crude slate available to

U.S. refiners continues to reflect increasing sul-fur content and decreasing quality as morediversified supplies come to market. (SeeFigure 1.) At the same time there is an increas-ing demand for middle distillates. The incre-mental capital cost to refiners to meet theserequirements is projected to be more than $8billion, which figures to add $0.06 per gallon tocurrent fuel pump prices nationwide. Similarly,the hydro-treatment needed to increase lightpetroleum production requires hydrogen fromthe expansion of coking facilities. The neteffect is an increase in petroleum coke produc-tion coming from U.S. refining, which is eitherstockpiled or marketed for export. Givenincreased worldwide environmental awareness,combined with a general acceptance of theKyoto agreements, there is a shrinking globalmarket available for petroleum coke.

The logical solution for refiners is to utilize petcoke on site as a ready fuel source for the bene-ficial production of power and/or steam prod-ucts. The qualifying technologies suitable forproviding this energy conversion are quickly

Refinery Segment

Higher Sulfur ResidualsFavor IGCC• Transportation fuel Sulfur will change

from >250 ppm to <15 ppm by '06

Increased Petroleum CokeProduction• Increasing demand for middle distillates• Hydrogen from expansion of coking

facilities and IRCC

Kyoto & Enviro ShrinkingMarket for Pet Coke• Pet coke stockpiled or handled by

middlemen for blending to saleable fuel• Several countries are restricting new

coking capacity or import pendingenvironmental solutions

6543210

876543210-1

32.5

32.0

31.5

31.0

30.5

1.3

1.2

1.1

1.0

API

Gra

vity

Wt %

Sul

fur

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

'92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06

SPENDINGSPENDING$B Env'tl BaseRef. & Mktg.

ROIC

1987

1989

1991

1993

1995

1997

1999

Crude Quality

Sulfur Content

Figure 1. Refinery drivers

Refinery Segment


reduced to IGCC and CFBC (CirculatingFluidized Bed Combustion), owing to strictenvironmental emissions standards. A technol-ogy assessment illustrating comparative sourcevolume reduction, air emissions, and annualdisposal costs is shown in Figure 2. IGCC tech-nology clearly provides significant environmen-tal advantages for air emissions and lower dis-posal costs albeit at higher initial capital invest-ment. When operating costs, flexibility for co-production, and collateral environmental costsare factored into the financial analysis, IGCCcan provide improved project net present value.

This paper discusses the features, capabilities,and experience of gas turbines applied to IGCCsystems designed for efficient conversion ofrefinery waste liquid and solid petroleumresidues to useful energy products.

IGCC Refinery ExperienceAn IGCC plant is the product of collaborationbetween major subsystem providers and the

owner to form an optimized design that meetsdemanding process and environmental require-ments. Figure 3 shows the five major technolo-gies contributing to this design:

� Gasification island

� Gas treatment

� Air separation

� Combined-cycle power block

� Integration

Typically for existing refinery applications,IGCC plants provide a number of useful by-products which contribute to the economic via-bility of the overall integrated facility. Theseproducts can include power, steam, and hydro-gen—depending upon project specific needs.

There have been five refinery-based IGCC proj-ects using GE-designed gas turbines that havegone into commercial operation during thepast six years. (See Figure 4.) Included amongthese are two petroleum coke refineries(Texaco El Dorado and Motiva Enterprises) and

Air Emissions IGCC vs. CFBCSource Volume Reduction

Annual Disposal Costs

IGCC Technology Provides SuperiorEnvironmental

Benefits To Refineries

0.6

0.5

0.4

0.3

0.2

0.1

0

Cub

ic m

eter

of s

olid

s/m

etri

c to

n of

feed 0.51

0.06

0.36

CFB FGD IGCC SO2

CFBC

IGCC

NOx CO Particulates

Solids Volume Production by Power Generation Technologies

Net Annual Solid Waste Disposal Costs of Power Generation Technologies Using Petroleum Coke

($600,000) ($300,000) $300,000

Dollars Per Year

$600,000 $900,000 $120,000$0

Source: Black & Veatch Pritchard

PoundsperMillionBtu's

0.45

0.40

0.35

0.30

0.25

0.20

0.15

0.10

0.05

0.00

Pou

nds

per

Mill

ion

Btu

’s

Air Emissions of IGCC vs. Fluidized Bed PowerGeneration Using Petroleum Coke

Figure 2. Refinery competitive assessment


Source Volume Reduction Air Emissions IGCC vs. CFBC


three heavy oil refineries (Shell Pernis, Sarlux,and Exxon Singapore). The gas turbines usedin these projects included both E class (6B, 9E)units and more recently advanced F class (6FA)gas turbine technologies.

Power production ranges from a single 6B 40

MW gas turbine (the first refinery IGCC GE

unit) at the Frontier Oil refinery in El Dorado,

Kansas—to the world’s largest IGCC cogenera-

tion plant (serving the Saras refinery in

Sarroch, Italy), which produces more than 550

MW and 185 tons of steam from three single-

shaft combined cycle units (3x109E). Another

significant IGCC co-production facility at Shell’s

~~

Gasification

Gasifier HX

OxidantSupply System

Combined Cycle

Cleanup

Sulfur

SlagSyngas

CleanFuel

Slag

HydrogenAmmoniaMethanolChemicals

Electricity

ProductsFuels

l Bituminous Coall Sub Bituminous Coall Lignite

l Orimulsionl Residual Oilsl Refinery Bottomsl Petroleum Cokel Refinery Gas

l Biomassl Wastes

l 2 Stage CombustionPartial in GasifierComplete in Gas Turbine

l 5 Technologies Oxidant SupplyGasificationClean UpCombined CycleIntegration

- Air or Oxygen - CO + H2 - Sulfur - Syngas - Synergy

Steam

Opportunity Fuels to Clean Electricity

-- 2

Motiva Delaware(Petroleum Coke)

240 MW2 x 6FA

Exxon Singapore(Heavy Oil)

180 MW2 x 6FA

Shell Pernis(Heavy Oil)

80 MW2 x 6B

Texaco El Dorado(Petroleum Coke)

40 MW1 x 6B

Sarlux(Heavy Oil)

550 MW3 x 109E

Figure 3. IGCC process

Figure 4. GE gas turbines in refinery IGCCs


•••

•••••

••

•

•H2

H2


Pernis refinery in Rotterdam, Netherlands

includes two 6B units that co-generate to pro-

duce power and steam from syngas and other

available refinery gases.

More recently, two 6FA advanced gas turbinesunits with heat recovery steam generators are incommercial operation at Exxon Chemical’s facil-ity on Jurong Island, Singapore. Similarly, anoth-er two 6FA units at the Motiva Enterprises refin-ery in Delaware City are beginning to fire on syn-gas with improved gasification operations.

Taken as a whole, these five plants have accu-mulated in excess of 132,000 fired hours on syn-gas fuels, and represent ~26% of the total GEexperience base (now expected to top 500,000fired hours before year end) for gas turbinesburning low heating value fuels. (See Figure 5.)

Low calorific value (LCV) fuel applications—including refinery IGCCs and steel mills—encompass a wide variety of operationaldemands and time-varying fuel gas composi-tional requirements. For example, the 6FAs at

Exxon’s Singapore refinery are expected tooperate over a range of syngas fuel composi-tions, including co-firing with start-up fuels.Other units such as the 9Es at Sarlux IGCC aredesigned to operate at baseload conditions,operating on fairly consistent syngas once theunit has achieved start-up. The composition ofthe syngas consumed in these operating unitsalso varies considerably from project to project.(See Figure 6.)

A measure of this project-to-project variability isthe hydrogen content of the fuel. As shown inFigure 6, the hydrogen content for these appli-cations varies widely from a low of 8.6% at ILVAto a high of 61.9% at Schwarze Pumpe—withheating values of 193 and 318 Btu/SCF respec-tively. These diverse conditions and operatingdemands emphasize the importance of soundcombustion system design. For most projects adiluent is introduced at the combustor toreduce NOx emissions and consequentlyincrease output through turbine expansion.Air extraction from the gas turbine can also be

GE Syngas Hours of Operation

SyngasStart Date

Cool WaterPSITampaTexaco El DoradoSierra PacificSUV VresovaSchwarze PumpeShell PernisISE / ILVAFife EnergyMotiva DelawareSarluxPiombinoExxon Singapore

107E7FA

107FA6B

106FA209E

6B2x6B

3x109E6FA

2x6FA3x109E

109E2x6FA

120262250

40100350

4080

54080

240550150180

5/8411/959/969/96

- 12/96 9/9611/9711/96

-8/0010/0010/003/01

27,00024,50033,50030,660

090,04037,60058,250

141,0000

45033,10012,4009,700

- 1,800

- 56,37248,4381,715

- 22,6874,732

26,220- -

2,93012,776

1,0004,1007,101

- - -

3,800- - -

5,29010,500

- 921

Customer

Totals 499,100

Type MWHours of Operation

Syngas N.G. Dist

September 2002

IGCC Product Technology — Proven Through Operating Experience

Refinery Applications

Figure 5. GE gas turbine syngas experience



used to supply all or a portion of compressed airfor the air separation plant. This reduces thecapital for compressors, while providing gas tur-bine compressor margin to contend with high-er resistance from increased fuel mass flow andnitrogen injection in the gas turbine.

Refinery-based IGCC projects can also bephased in over time to meet changing opera-tional requirements. The Total refinery inGonfreville, France for example, will first installa natural gas fired combined-cycle cogenera-tion plant to produce steam and power for ini-tial operations. It is planned to add the IGCCprocess later to produce valuable chemicalproducts needed by the refinery at that time—and also provide a LCV fuel feed for the exist-ing cogeneration facility.

By combining the combustion technology withoutput enhancement capability, IGCC plantscan be designed with an optimum and eco-

nomic mix of fuel and diluents. For example,CO2 streams generated from hydrogen produc-tion may be effectively used in the gas turbine asa diluent for NOx reduction. The multi-genera-tion capability afforded by the IGCC processdesign provides significant operating flexibilityto meet changing refinery needs over time.

Gas Turbine AdvancementsGas turbine technology development has great-ly contributed to increased use of IGCC powerplants worldwide. Several specific areas ofdevelopment have resulted in 21 IGCC plantscurrently on line, in construction or develop-ment. (See Figure 7.) Fuel flexibility and envi-ronmental performance are proving to be criti-cally important to contemporary IGCC plantsdesigned for integrated operations with refiner-ies. Significant advancements have been madein each of these areas to extend the viability ofIGCC technology.

34.4

35.1

0.3

30.0

0.2

--

210

Pernis

14.5

23.6

1.3

5.6

49.3

5.7

128

SierraPacific

8.6

26.2

8.2

14.0

42.5

--

183

ILVA

61.9

26.2

6.9

2.8

1.8

--

317

SchwarzePumpe

22.7

30.6

0.2

5.6

1.1

39.8

163

Sarlux

34.4

55.4

5.1

1.6

3.1

--

319

Fife

44.5

35.4

0.5

17.9

1.4

0.1

241

ExxonSingapore

32.0

49.5

0.1

15.8

2.15

0.44

248

MotivaDelaware

42.3

47.77

0.08

8.01

2.05

0.15

270.4

PIEMSA

10.3

22.3

3.8

14.5

48.2

0.9

134.6

Tonghua

8274 5024 7191 12,492 6403 12,568 9,477 9,768 10,655 5304

200/98

.98

Steam

1000/538

.61

Steam

400/204

.33

--

100/38

2.36

Steam

392/200

.74

Moisture

100/38

.62

H 2O

350/177

1.26

Steam

570/299

.65

H2O/N

338/170

.89

N2

-

.46

n/a

* Always co-fired with 50% natural gas

H2

CO

CH4

CO2

N2 + AR

H2O

LHV, - Btu/ft3

Syngas

- kJ/m3

Tfuel F/C

H2 /CO Ratio

Diluent

Equivalent LHV

- Btu/ft3

- kJ/m3

37.2

46.6

0.1

13.3

2.5

0.3

253

Tampa

9962

700/371

.80

N2

118

4649

35.4

45.0

0.0

17.1

2.1

0.4

242

El Dorado

9528

250/121

.79

N2/Steam

113*

4452

198

7801

110

4334

--

--

200

7880

--

--

PSI

24.8

39.5

1.5

9.3

2.3

22.7

209

8224

570/300

.63

Steam

150

5910*

--

116

4600

150

5910

129

5083

134.6

5304

Demonstrated: Syngas Fuel Flexibility

Refinery Projects

Figure 6. GE gas turbine syngas capabilities



Fuel FlexibilityGas turbine fuel flexibility is measured by fourkey characteristics:

� Capability to deal with low heatingvalue fuel containing varying hydrogencontent

� Operability on a wide range of fuels,including startup, transfers and systemupsets

� Capability to co-fire synthesis gas withnatural gas over a wide total heat input

� Low emissions

The key component in meeting these require-ments is the gas turbine combustor.

Combustor Design: The gas turbine combustor isthe principal process orifice for an entire IGCCplant. The standard IGCC combustor for GEgas turbines is derived from the Multi-NozzleQuiet Combustor (MNQC). (See Figure 8.) Sincehydrogen is a typical constituent of synthesisgases, Dry Low NOx (DLN) combustors are notappropriate for synthesis gas due to hydrogen’shigh flame speed, which can initiate flashback

and combustor failure. GE’s contemporaryIGCC combustor has evolved to an increaseddiameter standard that allows a wider range offuel constituents and co-firing capability.

The lower specific calorific content of synthesisgas requires that the combustor be able toprocess more than five times the fuel flow rela-tive to a natural gas combustor. Also, combus-tion of 100% syngas results in NOx emissionsthat exceed regulatory requirements, so dilu-tion of the syngas with nitrogen, water, CO2 orcombinations is needed to achieve desired per-formance. Note that the quantity of diluentneeded to achieve acceptable NOx concentra-tions typically is equal or greater than the quan-tity of synthesis gas. This means the flow of dilu-ent plus fuel in the combustor may be eighttimes or more than that of a natural gasmachine. The combustion engineer’s challengeis to deliver stable, low-noise combustion,acceptable liner temperatures and full fuelburnout despite relatively high fuel injectionvelocities. The key to achieving this is full-scaletesting.

Customer C.O. Date MW Application GasifierSCE Cool Water - USALGTI - USADemkolec - NetherlandsPSI/Global - USATampa Electric - USATexaco El Dorado - USASUV - Czech.Schwarze Pumpe - GermanyShell Pernis - NetherlandsPuertollano - SpainSierra Pacific - USAISAB - ItalyAPI - ItalyMOTIVA - DelawareSarlux/Enron - ItalyEXXON - Singapore

FIFE - ScotlandEDF/ Total - GonfrevilleFIFE Electric - ScotlandNihon Sekiyu - JapanPIEMSA

� GE GTs

1984198719941995199619961996199619971998199819992000200020002000

20012003200320042006

120160250260260

40350

40120320100500250240550180

120400400350800

Power/CoalCogen/CoalPower/CoalRepower/CoalPower/CoalCogen/Pet CokeCogen/CoalPower/Methanol/LigniteCogen/H2/OilPower/Coal/Pet CokePower/CoalPower/H2 /OilPower/H2 /OilRepower/Pet CokeCogen/H2/OilCogen/H2/Oil

Power/SludgePower/H2/Cogen/OilPower/Coal/RDFPower/OilPower/H2/Oil

Texaco - O2Destec - O2 Shell - O2Destec - O2Texaco - O2Texaco - O2ZUV - O2Noell - O2Shell - O2Prenflow - O2KRW - AirTexaco - O2Texaco - O2Texaco - O2Texaco - O2Texaco - O2

BGL - O2Texaco - O2BGL - O2Texaco - O2Texaco - O2

5,810

21 Global IGCC Plants

Figure 7. Current IGCC plants



Owing to the can-annular design of GE tur-bines, a single can may be fully tested andproven at full airflow and pressure for manymachines over the entire range of cycle condi-tions before releasing it to the field. The per-formance of new designs is subsequently veri-fied in the field. In 2002, GE successfully com-missioned its new IGCC combustion laboratoryin Greenville, S.C. (See Figure 9.) This state-of-the-art facility includes two test stands dedicatedsolely to IGCC combustion development. Eachsingle burner test stand is designed to simulatethe internal flow patterns of a particularmachine. Fuel blending tank farms and gas con-ditioning skids allow for simulation of fuelcharacteristics representative of all anticipatedfuel and gasifier types. Compressor capability iscapable of simulation of up to H-turbine com-bustor conditions.

IGCC machines require a start-up fuel becauseof the dangers of starting on fuels containinghydrogen. This allows many plants to beginoperation on backup fuel with introduction ofIGCC and synthesis gas capability phased-in at alater date. The dual fuel capability has been

developed into a standard co-firing feature sousers can design plants for higher power outputif syngas production is restricted, or if a plant iscontemplating parallel or staged co-productionfor utilization of syngas.

Fuel Flexibility: The application of IGCC technol-ogy to refinery plants presents another interest-ing synergistic opportunity to incorporate awater shift reactor for hydrogen production tofeed both the refinery and power island. (SeeFigure 10.) GE has completed feasibility testingfor 100% H2 and 100% CO fuel to define theentire combustion map. The H2-only case isrepresentative of pre-combustion removal ofCO as CO2 for Enhanced Oil Recovery (EOR)or sequestration, and allows for CO2-free powerplants. Figure 11 indicates that ratios of 50/50hydrogen/nitrogen can produce very low NOx

as well as provide enhanced output in a modernIGCC gas turbine. With this new combustiontechnology it may be possible to use IGCC forCO2-free plants at about 15% extra cost withapproximately 3 points of reduction in netplant efficiency.

Dynamic PressureLocations Flowsleeve

Emissions Sample

Transition Piece(Differs for 9FA)

Stage 1 Nozzle(Nozzle Box for Test)

T/C Rake Location

CombustionLiner

CombustionCasing

Endcover

Fuel NozzlesSteam

BlendedFuel

Natural Gas

Same System Design for 6FA, 7FA, & 9FA

Figure 8. GE multi-nozzle combustor



Operability: Mixed fuel operation or co-firing hasbecome an important operating mode toenhance project economics. Co-firing was firstused at the Texaco El Dorado IGGC plant inKansas where the gasifier provides about one-third (1/3) of the gas turbine thermal inputrequirements. Since starting in 1996 the ElDorado GT has performed at better than 97%power availability. More recently, ExxonSingapore also has this feature. The standardtypes of fuel systems and operating characteris-tics are provided in Figure 12. For a dual gas

design the co-firing operability standard is in

the 70/30% range. This range is dictated by

combustion system controllability requirements

at low fuel flow rates. However, a new system

now operating at Exxon Singapore is capable of

operating over the 90/10% range. Mixed fuel

operation can generally be accommodated

down to ~30% load. For a dual fuel—

syngas/distillate application, the distillate can

be controlled down to 10% while the syngas is

generally regulated over the 30%–70% range.

GE Investment in IGCC

—

—

State-of-the-art combustion development facility at Greenville, S.C.

— Standard machines with optimal integration of turbine and gasification plant with gasification developers

— Program to develop fuel-tolerant, lean-pre-mix combustor for ≤9 ppm NOx

— At GE's Global Research Laboratory – advanced concepts for single-digit NOx

Validation of Performance at Full Flow and Geometry

Petroleum Cokevis Breaker Tars

ResidualsAsphalts

~

H2

O2

CO2

H2

Syngas

GasifierSulfur

RemovalShift

Reactor HCU

HRSGASU

H2 Manufacture

ProcessSteam

SteamTurbine

Air

Air

IGCC Provides "Poly-Generation" Benefits With Cost Effective CO2 Separation Capability

~

Figure 9. GE combustion test facility

Figure 10. Refinery IGCC flow sheet



A tri-fuel dual gas system design concept wasdeveloped for the Gonfreville refinery IGCCproject. This dual manifold system incorporatesfuel nozzles and piping sized for natural gas andrefinery gas, with a separate syngas manifoldand nozzle assembly to handle syngas. A trans-fer valve arrangement is utilized to interconnectthe two systems during fuel transfers and co-fir-

ing operations. A simplified fuel system

schematic illustrates the fuel module configura-

tion, including inert and main air purge systems

for this design. (See Figure 13.) Both nitrogen

and air from the compressor discharge (CPD)

are used for line purge during various operat-

ing modes.

ppmvdVideo Capture

of FlameStructure

85-90% H2

4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000

100 150 200 250 300

1000.0

100.0

10.0

1.0

Equivalent Heating Value = Heating Valueof Mixture of Syngas and Injected Steam

NO

x @

15%

O2,

pp

mvd

LHVeq, Btu/SCF

LHV, kJ/m3

50–95% H2 By Volume, Bal. N2, N2 + H2O

Figure 11. GT hydrogen combustion capability for CO2 removal

Type Operational capabilities for IGCC systems* Fuel OperabilityRange

1Baseline Distillate/SG system

- Similar to other dual fuel standard combustor machine except inert purge on SG side.- Cofiring capability provided for Singapore (ADO/Syngas)

100% SG100% DIST

90% SG/ 10% dist30% SG/ 70% dist

2 Baseline NG/SG system- NG and syngas travel down separate paths- Simplest, least expensive

100%SG100% NG

65% SG/ 35% NG35% SG/ 65% NG

3 Extended Turndown system- Verified at Exxon-Singapore- Manifolds interconnect via transfer valves- Exclusion zone 10% wide from 15% to 30% NG

100%SG100%NG

90% SG/ 10%NG10% SG/ 90%NG

4Simplified ExtendedTurndown System

- Same as #3 except 35% min SG- Eliminates exclusion zone- Simplifies control logic

100% SG100% NG

85% SG/ 15% NG35%SG/ 65% NG

* All assumed to provide for maintaining load set point using NG modulation.

Figure 12. Syngas control configurations



Environmental PerformanceEmissions: As already discussed, NOx reductionas well as power augmentation can be realizedby using diluents to lower the heating value ofthe syngas. GE has chosen to inject nitrogen inthe combustor in the same manner used forsteam injection rather than mix it with the fuel.In this manner the nitrogen pressure can belower than the syngas pressure and the fuel con-trol valves can be reduced to half size since theyare controlling only the fuel. Combinations ofN2 and moisture are frequently the most costeffective, considering the aero limitations in astandard GT for additional flow. Figure 14 com-pares several methods of moisturization. Theamount of water saturation is generally limitedby the low-level heat available and varies widelyby gasifier type. Several recent systems have cho-sen to moisturize the nitrogen.

In general, IGCC NOx emissions will dependupon the specific fuel characteristics and thetype, quality and quantity of available diluent.Figure 15 lists NOx emission level experienceachieved to date with GE gas turbine units oper-

ating at several IGCC plant facilities over thepast eighteen years, in addition to predicted lev-els for other IGCC sites currently under devel-opment. Figure 16 summarizes the U.S. permit-ted NOx levels for IGCC plants past and pres-ent. The TECO Polk IGCC plant was originallypermitted at 25 ppm NOx but recently under-went a BACT re-determination to 15 ppm—equivalent to 0.065 lb/MMBtu—which is wellbelow recently permitted new pulverized coalplants. The 6FA gas turbines at the Motiva refin-ery have demonstrated single digit NOx at 85MW approaching full load.

Process Integration: Most recent IGCC efforts forrefineries have concentrated on high-to-medi-um pressure oxygen-blown systems due to thelarge size of plants and particularly the co-pro-duction of chemical products. The IGCC plantdesign for PIEMSA has included partial integra-tion where ~1/3 of the ASU air requirement isextracted from the gas turbines. On Model Fmachines the IGCC combustor allows for airextraction up to 20% (full integration), withoutaffecting turbine cooling air. Overall IGCC


N2

Figure 13. 90/10 Tri-fuel dual gas system


Cool Water 25PSI - Wabash <25Tampa - Polk <25Texaco - El Dorado <25Motiva - Delaware 9 - 15Sarlux - Italy <30Exxon - Singapore 42

PredictedSierra Pacific - Pinon <42 (<9 Thermal)Gonfreville 35

PIEMSA 30

Operating N0x PPMVD @15%O2

Figure 14. Moisturization alternatives

Figure 15. Typical NOx emissions

optimization for a specific project dependsupon site operating requirements and fuel typeto determine the kind of airside integration tobe used, if any. In larger plants, IGCC operabil-ity can be enhanced with partial air integrationallowing for reduced ASU MAC size by utilizingthe excess air available from the gas turbinecompressor.

Controls: An important consideration for IGCC

operations is the method of overall plant con-trol. IGCC plants can be designed to follow thegasifier syngas production. They can also bedesigned to meet electrical load demand eitherby regulating the gasifier to follow the demand,or by co-firing with backup fuel. The latter ismore frequently used as it provides a higherdegree of control and faster response than gasi-fier follow. The design validation process nor-



mally incorporates a GT control simulation.The system study of startup and shutdownmodes and ambient effects at the beginning ofthe power plant design effort is crucial and asignificant design aid to establish an integratedcontrol strategy.

GE IGCC Gas Turbine Product LineGE pioneered IGCC nearly three decades agoand has developed a broad dedicated IGCCproduct line of gas turbines and matchingsteam turbines ranging from 10 to 300 MW. (SeeFigure 17.) GE gas turbines having LCV fuelcapabilities are proven products with a total of22 units sold, and collectively accumulated over340,000 hours of operation on synthesis gasfrom gasification.

Gas turbines for IGCC applications have basictechnical and functional requirements that aredifferent from those of a gas turbine operatingon natural gas. Therefore, IGCC gas turbinesmust be modified with features that allow forefficient and reliable syngas service. The IGCC-

specific features relate primarily to the combus-tion and fuel system components but alsoinclude special fire protection, packaging, andcontrols modifications.

GE has developed the technology to providepower producers with a complete range of gasturbines that can be efficiently integrated withIGCC plants and refineries to generate leastcost electricity and co-generation steam whilemeeting strict environmental regulatoryrequirements. With new product introductionprograms (NPI), GE continues to improve itsIGCC gas turbine product line technology andcompetitiveness. As an example, Figure 18 showsthe evolution of the advanced 7FA gas turbinepower output from the initial 150 MW naturalgas rating to the present 197 MW on syngas(more than a 30% increase) over a five-yearperiod—with expectations for an additional 7%increase by the year 2006 for applications.Similar advancement programs are in theplanning stages for the 6FA and 9FA IGCCproducts.

Representative USA IGCC NOx Levels and Permits

Plant Date Fuel NOx(ppmbv@15%O2 )

Cool Water 1984 Coal 25

Wabash River 1995 Coal/Pet Coke < 25

Polk 1996 Coal/Pet Coke < 25

Texaco El Dorado 1996Pet Coke/RefineryWastes

< 25

Motiva Delaware 2000 Pet Coke 15

PolkBACTRedetermination

2002 Coal/Pet Coke 15

Kentucky Pioneer* 2001 Coal 15**

* Permit issued 6/17/2001** Subject to re-evaluation

NOxO2)

Figure 16. NOx emissions for recently permitted IGCC plants




IGCC 7FA

IGCCGAS TURBINES Model Syngas Power Rating Model Net Plant Power Rating

GE10 10 MW (50/60 Hz)6B 40 MW (50/60 Hz)7EA 90 MW (60 Hz)9E 150 MW (50 Hz)6FA 90 MW (50/60 Hz)7FA 197 MW (60 Hz)9FA 286 MW (50 Hz)

106B 60 MW (50/60 Hz)107EA 130 MW (60 Hz)109E 210 MW (50 Hz)106FA 130 MW (50/60 Hz)107FA 280 MW (60 Hz)109FA 420 MW (50 Hz)

Figure 17. GE IGCC GT/CC product line

7FA Natural Gas150–172 MW ISO

7FA+e IGCC197 MW ISO

192 MW ISO7FA IGCC Year 1995

Year 2000

Year 2006

– IGCC Combustor

– Higher Torque Rotor

– Higher Firing Temperature

– Modified Turbine Nozzle

– Combustor Developments

– Increased Pressure Ratio

7FA Advanced IGCC211 MW ISO

Continued Gas Turbine Advances to Enhance IGCC Plant Economics

Figure 18. 7FA IGCC gas turbine product development


The core of an IGCC gas turbine design is basedon combustion system development and adap-tation through full scale laboratory testing.Advanced programs to develop fuel-tolerantlean pre-mix syngas combustors for ≤9 ppmvdNOx capability are being planned as the nextlogical extension of dry low NOx combustiontechnology. At GE’s Global ResearchLaboratory, advanced combustion concepts forsingle-digit NOx are in the conceptual planningstage with promise for additional application tosyngas and long term emissions reduction.

Economic Considerations Figure 19 shows a COE breakeven curve devel-oped for IGCC plants using various opportunityfeedstocks versus natural gas combined cycle(NGCC). Namely, the graph directly comparescost competitiveness of IGCC and NGCC as afunction of the respective fuel costs. This curveis based on 20-year averaged cost of electricitycalculations for generic domestic 500 MWIGCC and NGCC plants. The conclusion: At

natural gas prices of $2.5 per MMBtu higherthan IGCC fuel prices, IGCC provides a cost ofelectricity equivalent to NGCC. Current naturalgas pricing (e.g., Henry Hub-$3.91/MMBtu-HHV, 10/9/02) would suggest that COE fromrefinery-based IGCC plants fueled by low costopportunity fuels (e.g., residuals or pet coke)should be significantly lower than NGCC plantswith spot-market fuel pricing.

ConclusionGas turbine improvements have come fromoperating experience in many applications andfrom industry competition. In addition, specificattention to IGCC needs in an emerging markethas generated a host of new technology neededfor IGCC viability. Current market drivers arefavorable for refinery-based IGCC projects driv-en in part by high investment costs for environ-mental compliance. Contemporary IGCC plantdesigns are commercially viable with refineryoperations owing to their broad capability to

00.2

0.40.6

0.8

1.0

1.2

1.41.6

1.8

2.0

2.2

1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5

Combined Cycle Fuel Price [$/MMBTU]

IGC

C F

uel

Pri

ce [

$/M

MB

TU

]

Combined CycleCombined CyclePreferredPreferred

IGCCIGCCPreferredPreferred

Pet Coke

Residues

Coal

Orimulsion

E$3.91H Hub10-9-02

COEParity

IGCC Competitive at $2.50 Spread

Figure 19. Breakeven fuel price comparison



List of FiguresFigure 1. Refinery drivers

Figure 2. Refinery competitive assessment

Figure 3. IGCC process

Figure 4. GE gas turbines in refinery IGCCs

Figure 5. GE gas turbine syngas experience

Figure 6. GE gas turbine syngas capabilities

Figure 7. Current IGCC plants

Figure 8. GE multi-nozzle combustor

Figure 9. GE combustion test facility

Figure 10. Refinery IGCC flow sheet

Figure 11. GT hydrogen combustion capability for CO2 removal

Figure 12. Syngas control configurations

Figure 13. 90/10 Tri-fuel dual gas system

Figure 14. Moisturization alternatives

Figure 15. Typical NOx emissions

Figure 16. NOx emissions for recently permitted IGCC plants

Figure 17. GE IGCC GT/CC product line

Figure 18. 7FA IGCC gas turbine product development

Figure 19. Breakeven fuel price comparison

use opportunity and low value waste fuels.IGCC technology enjoys compelling environ-mental advantages for waste fuel conversion toeconomical “poly-generation” products, withgrowth potential to meet future regulatory chal-lenges. Furthermore IGCC economics are atparity or better than conventional solid fueltechnologies using opportunity fuels. GE’s gas

turbine IGCC product line is experienced andwell matched for refinery syngas applications,which favor the advanced F class turbine highoutput and efficiency performance attributes.Finally, the fuel flexibility and high system relia-bility afforded by today’s gas turbines are criti-cally important to the economic success ofrefinery based IGCC projects.


igcc for refinery

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