from coal or oil to 550 mw via 9h igcc - globalsyngas.org · gasifier unit syngas...

From Coal or Oil to 550 MW via 9H IGCC

by

Texaco Power and Gasification– Jim Falsetti– Richard De Puy

• General Electric Power Systems– Daniel Brdar– Ashok Anand

• Praxair Inc.– Jerry Paolino

GE’s 9H Gas Turbine

Battery Limits between Gasification, Air, and Power Island

Gasification Island

Coal Storage, Grinding, & Heating Slurry Preparation & Pumping Gasifier Unit Syngas Cooling/Saturation/Heating Syngas Cleaning Sulfur Recovery Process Island Sub-Station Syngas Flare Ash Handling System Main Process Contingency & Safety System Process Island Interconnecting Piping & Cabling

Air Separation Unit

Main Air Compressor Oxygen Compressor Nitrogen Compressor Gas Turbine Ext/N 2 Heat Exchanger Nitrogen Saturation ASU Auxiliary

ASU Control System ASU Sub Station

Power Island

Gas Turbine Steam Turbine Generator HRSG Condenser Expander Turbine Generator Demineralizer Boiler Feedwater Pumps Auxiliary Cooling Water System Power Island Sub-Station Distributed Control System Turbine Building Power Island Interconnective Piping & Cabling

Power InputSyngas

HP SteamMP SteamLP Steam

LP Condensate Return

LP FeedwaterDemineralized Make-up Water

HP Economizer Water

Auxiliary Cooling Water Return

Process Condensate

MP Feedwater

LP Condensate

Auxiliary Cooling Water

Cal

Conveying

Raw

Water

NaturalG

as

Power

Input

CirculatingW

ater

CirculatingW

ater

HP N 2Purge

HP O2

Sulfur

Slag

Power Input

Air Extraction

HP N 2 Injection

Circulated Water

Circulated Water Return



Auxiliary Steam to ASU

NaturalG

as

MunicipalW

ater

Power

Output

LP O 2

Battery Limits between Gasification, Air, and Power Island

Gasification Island

Coal Storage, Grinding, & Heating Slurry Preparation & Pumping Gasifier Unit Syngas Cooling/Saturation/Heating Syngas Cleaning Sulfur Recovery Process Island Sub-Station Syngas Flare Ash Handling System Main Process Contingency & Safety System Process Island Interconnecting Piping & Cabling

Air Separation Unit

Main Air Compressor Oxygen Compressor Nitrogen Compressor Gas Turbine Ext/N 2 Heat Exchanger Nitrogen Saturation ASU Auxiliary

ASU Control System ASU Sub Station

Power Island

Gas Turbine Steam Turbine Generator HRSG Condenser Expander Turbine Generator Demineralizer Boiler Feedwater Pumps Auxiliary Cooling Water System Power Island Sub-Station Distributed Control System Turbine Building Power Island Interconnective Piping & Cabling

Power InputSyngas

HP SteamMP SteamLP Steam

LP Condensate Return

LP FeedwaterDemineralized Make-up Water

HP Economizer Water


Process Condensate

MP Feedwater

LP Condensate


Coal

Conveying

Raw

Water

NaturalG

as

Power

Input

CirculatingW

ater

CirculatingW

ater

HP N 2Purge

HP O 2

Sulfur

Slag

Power Input

Air Extraction

HP N2 Injection

Circulated Water

Circulated Water Return



Auxiliary Steam to ASU

NaturalG

as

MunicipalW

ater

Power

Output

LP O 2

Goals of this Study

• Increase Net Efficiency

• Lower Capital Cost ($/kW)

• Lower Cost of producing Electricity

DESIGN BASIS

1. ISO ambient conditions (59ºF, 14.7 psia, 60% RH)2. Heavy Residual Oil, 4.4% Sulfur, 18,060 Btu/lb HHV3. Sub-bituminous coal, 1% Sulfur, 12,559 Btu/lb HHV4. Single train gasification, combined cycle, and air separation5. Low emissions NOx < 25 ppm, SOx < 5 ppm6. Zero process waste water discharge7. Total plant availability 95%, (88% HEQ and 85% HR on syngas)8. Natural gas as start up and back up fuel9. Cooling water at 68ºF, 13ºF temperature rise

Case Matrix

CaseDesignation 9F_HEQ_O 9H_HEQ_O 9H_HR_O 9F_HEQ_C 9H_HEQ_C 9H_RO_C

Feedstock Oil Oil Oil Coal Coal Coal

GasifierPressure 1,230 1,230 740 1,230 1,230 540

SyngasCoolers Quench Quench Convective Quench Quench Radiant

SyngasExpander Yes Yes Yes Yes Yes Yes

AirExtraction 50 100 100 50 100 100

Overall Block Flow Diagram

ProductSulfur

Extraction Air

Air SeparationUnit

Gasification(Quench or Heat

Recovery)

Low TemperatureSyngas Cooling &Energy Recovery

Acid GasRemoval Heat Recovery

Steam Generator

Black Waterand SolidsHandling

Sulfur Recoveryand Tail GasTreating Unit

Gas Turbine -Steam Turbine -Generator Block

HPOxygen

Hydrocarbon

SolidByproducts

CondensateBlackWater

Grey Water

AcidGas

StackGas

NitrogenSaturation and

Heating

LPOxygen

Clean Syngas

Nitrogen Nitrogen

Steam

LP Steam / BFW

HP & MP Steam / BFW

Vent Gas

Exhaust

PowerAir

Overall Performance Summary


Fuel Feed(STPD) 2,311 2,563 2,514 3,502 3,942 3,940

Pure OxygenFeed (STPD) 2,612 2,873 2,663 3,176 3,578 3,576

IGCC Gross(MW) 494.6 544.7 546.3 517.5 569.7 574.2

IGCC Net (MW) 435.8 505.7 510.3 449.2 520.9 527.6

Net IGCCEfficiency

(LHV)45.1% 47.2% 48.6% 43.3% 44.6% 45.2%

Goals of this Study



• Lower Cost of producing Electricity

Increased Efficiency by more than 5%.

IGCC Plant Layout

LEGEND:

A AIR SEPARATIONB FEEDSTOCK PREPARATION AREAC GASIFICATION STRUCTURED SYNGAS SATURATION / EXPANDERE LOW TEMPERATURE GAS COOLINGF ACID GAS REMOVALG SULFUR LOADING PADH AMMONIA STRIPPERI PIPE RACKJ CONTROL BUILDINGK COMBINED CYCLEL HEAT RECOVERY STEAM GENERATORM STACKN STEP UP TRANSFORMERO BALANCE OF PLANT (AIR & DEMIN. WATER)P CIRCULATING WATER PIPESQ SYNGAS FLARE STACK

0m.

12.6m.

21m. 42.01m.

A

Q

N

J

M

G

I

O

K

P

B

L

HF

ED

C

Basis for Capital Cost Estimate

• U.S. Gulf Coast equipment and installation costs• Greenfield site• Excludes waste disposal, and feedstock delivery• Assumes municipal supply water for cooling• Average accuracy of the cost estimate is +/- 20%• No site specific owner’s cost

Capital Cost Comparison


AreaDesignation Installed Costs ($000)

Gasification 84,000 88,200 108,500 110,800 118,500 167,400

AirSeparation 61,000 60,800 59,750 69,200 69,200 66,400

CombinedCycle 176,300 223,800 220,400 178,600 226,400 228,400

Balance ofPlant 27,200 27,900 32,100 27,700 29,600 31,100

Total IGCC 348,500 400,700 420,750 386,300 443,700 493,300

Net MW 435.8 505.7 510.5 449.2 520.9 527.0

$/kw 800 792 824 860 852 935

Goals of this Study



• Lower Cost of producing ElectricityLowered Capital by more than 10%.


Basis for the Economic Analysis

• Feedstock price range is $0.5 to $3.00 US per MMBtu• Natural Gas price is $2.40 US per MMBtu• Cost of Electricity evaluation term is 20 years• Fixed charge rate 18%, discount rate 10%• Escalation 3.0%/year• Construction interest & owners cost are 20% of turnkey• First year of operation is 2002• Capacity factor is 95% overall

Cost of ElectricitySensitivity to Feedstock Price

33.5

44.5

55.5

6

0.50 1.00 1.50 2.00 2.50 3.00

Feedstock Price ($/MMBtu)

Cos

t of E

lect

ricity

(c

ents

/kW

h)

9F_HEQ_O 9H_HEQ_O 9H_HR_O9F_HEQ_C 9H_HEQ_C 9H_RO_C

1994 Study

1997 Study

Goals of this Study



• Lower Cost of producing ElectricityLowered COE by more than 12%.

Lowered Capital by more than 10%.


Economic Impact of HEQ IGCC Design Improvements

50%

60%

70%

80%

90%

100%

Heat Rate Total InstalledCost

Cost of Electricity

1994 9F HEQ 1997 9FA FHR 1999 9H HEQ Coal 1999 9H HEQ Oil

Enhancements of the IGCC

• Elevated Pressure Air Separation Unit• 50% to 100% Extraction Air from Gas Turbine• Nitrogen supplied to the Combined Cycle Unit• High Pressure Gasification• Sour gas expander• Higher GT Pressure Ratio• Higher GT Firing Temperature• Closed Loop Steam Cooling• Better MP Steam Integration

Conclusions

• IGCC Economics and Performance continue to improve• Lessons learned from operating plants have improved

reliability and lowered costs• Better Integration Schemes result in better performance

and lower costs

Result:With higher efficiency and lower capital costswe are able to reduce the Cost of Electricityby 12% as compared to the 1997 Study

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