from coal or oil to 550 mw via 9h igcc - globalsyngas.org · gasifier unit syngas...
TRANSCRIPT
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 Cooling Water
Auxiliary Cooling 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
Auxiliary Cooling Water Return
Process Condensate
MP Feedwater
LP Condensate
Auxiliary Cooling Water
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 Cooling Water
Auxiliary Cooling 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 ($/kW)
• Lower Cost of producing Electricity
DESIGN BASIS
1. ISO ambient conditions (59ºF, 14.7 psia, 60% RH)2. Heavy Residual Oil, 4.4% Sulfur, 18,060 Btu/lb HHV3. Sub-bituminous coal, 1% Sulfur, 12,559 Btu/lb HHV4. Single train gasification, combined cycle, and air separation5. Low emissions NOx < 25 ppm, SOx < 5 ppm6. Zero process waste water discharge7. Total plant availability 95%, (88% HEQ and 85% HR on syngas)8. Natural gas as start up and back up fuel9. Cooling water at 68ºF, 13ºF temperature rise
Case Matrix
CaseDesignation 9F_HEQ_O 9H_HEQ_O 9H_HR_O 9F_HEQ_C 9H_HEQ_C 9H_RO_C
Feedstock Oil Oil Oil Coal Coal Coal
GasifierPressure 1,230 1,230 740 1,230 1,230 540
SyngasCoolers Quench Quench Convective Quench Quench Radiant
SyngasExpander Yes Yes Yes Yes Yes Yes
AirExtraction 50 100 100 50 100 100
Overall Block Flow Diagram
ProductSulfur
Extraction Air
Air SeparationUnit
Gasification(Quench or Heat
Recovery)
Low TemperatureSyngas Cooling &Energy Recovery
Acid GasRemoval Heat Recovery
Steam Generator
Black Waterand SolidsHandling
Sulfur Recoveryand Tail GasTreating Unit
Gas Turbine -Steam Turbine -Generator Block
HPOxygen
Hydrocarbon
SolidByproducts
CondensateBlackWater
Grey Water
AcidGas
StackGas
NitrogenSaturation and
Heating
LPOxygen
Clean Syngas
Nitrogen Nitrogen
Steam
LP Steam / BFW
HP & MP Steam / BFW
Vent Gas
Exhaust
PowerAir
Overall Performance Summary
CaseDesignation 9F_HEQ_O 9H_HEQ_O 9H_HR_O 9F_HEQ_C 9H_HEQ_C 9H_RO_C
Fuel Feed(STPD) 2,311 2,563 2,514 3,502 3,942 3,940
Pure OxygenFeed (STPD) 2,612 2,873 2,663 3,176 3,578 3,576
IGCC Gross(MW) 494.6 544.7 546.3 517.5 569.7 574.2
IGCC Net (MW) 435.8 505.7 510.3 449.2 520.9 527.6
Net IGCCEfficiency
(LHV)45.1% 47.2% 48.6% 43.3% 44.6% 45.2%
Goals of this Study
• Increase Net Efficiency
• Lower Capital Cost ($/kW)
• 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
CaseDesignation 9F_HEQ_O 9H_HEQ_O 9H_HR_O 9F_HEQ_C 9H_HEQ_C 9H_RO_C
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
$/kw 800 792 824 860 852 935
Goals of this Study
• Increase Net Efficiency
• Lower Capital Cost ($/kW)
• Lower Cost of producing ElectricityLowered Capital by more than 10%.
Increased Efficiency by more than 5%.
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
• Increase Net Efficiency
• Lower Capital Cost ($/kW)
• Lower Cost of producing ElectricityLowered COE by more than 12%.
Lowered Capital by more than 10%.
Increased Efficiency by more than 5%.
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