Impact of Carbon Tax on H2/CO2/Electricity Co-Production for Gasification Plants Compared to Natural Gas Based Combined Cycle and Hydrogen Plants

Gasification Technologies 2002 Conference -

San Francisco, California USA

By Ravi Ravikumar and Giorgio Sabbadini

1

Purpose

Evaluate the relative overall plant economics for petcoke fed IGCC plants that co-produce hydrogen, and electricity versus conventional combined cycle and hydrogen plants using natural gas as the feed

Evaluate the relative economics of reducing carbon emissions from pet coke fed IGCC plant when a carbon tax is levied versus conventional combined cycle and hydrogen plants that have no CO2 sequestration.

2

Figure 1-1Potential Gasification Feeds and Products

Coal

3

Site Conditions

Location: US Gulf Coast

Ambient Temperature: 59°F (ISO Conditions)

Relative Humidity: 60%

Ambient Pressure: 1 Atmosphere

Cooling Water System: Cooling Towers

4

Table 2-1Petroleum Coke Analysis

Component wt%Carbon 89Hydrogen 4Nitrogen 1Oxygen 1Sulfur 5 *Ash <1Total 100

HHV, kcal/kg (dry basis) 8,422 (15,160 Btu/lb)

* Assumed. Gasification can process coke with much higher sulfur.

5

Cases Considered

Case A - IGCC Electrical Power Production without CO2 Removal

Case B - IGCC Electrical Power and Hydrogen Production from Petcoke with CO2 Removal.

Case C - IGCC Electrical Power Production from Petcoke with CO2 Removal.

Case D - Steam Natural Gas Reforming Hydrogen Production with no CO2 Recovery.

Case E - Natural Gas Fired Combined Cycle Power Production Plant with no CO2 Removal.

6

Study Parameters

Pet Coke Feed Rate for IGCC cases set at 3,639 short ton/day (dry).

IGCC Hydrogen Production Case B - Hydrogen Production set at 100 MMSCFD and the balance of syngas is used to produce electrical power

Recovery and compression of CO2 to 2000 psig

Storage and Injection of CO2 is not included.

7

Study Parameters (Cont.)

Conventional Hydrogen Production Plant Case D -Hydrogen Production Set at 100 MMSCFD.Combined Cycle Power Plant, Case E - Two on One configuration using two GE 7FA GTs with HRSG Duct Firing

8

Figure 3-1IGCC with Electrical Power Production

Case A

NOTES:

AGR = ACID GAS REMOVALBFW = BOILER FEEDWATERCO = CARBON MONOXIDECO2 = CARBON DIOXIDECWS = COOLING WATER SUPPLYCWR = COOLING WATER RETURNGTG = GAS TURBINE GENERATORH2 = HYDROGENHP = HIGH PRESSUREHRSG = HEAT RECOVERY STEAM GENERATORN2 = NITROGENO2 = OXYGENSTG = STEAM TURBINE GENERATOR

GASIFICATION

N2 TO GASTURBINE

N2VENT

HP STEAMTO GASIFIER

SLAGTO

DISPOSAL

SYNGAS HEATRECOVERY

BFW STEAM

AtmAIR

AIRSEPARATION

UNIT(ASU)

3,639 st/d

RAW SYNGASPET COKE

O2 TO SULFURRECOVERY UNIT

HP O2

PROCESS CONDENSATE

POWER BLOCKINCLUDING

GTG, STG, HRSG

FLUE GAS TOATMOSPHERE

POWER

CWSCWR

HP STEAM TOGASIFICATION

503 MWe (NET)Atm.AIR

N2

BFW

ELECTRICALPOWERPRODUCTION

O2FROM ASU

SULFURRECOVERY

UNIT

LIQUIDSULFUR

VENT

CLEAN FUEL GASACID GASREMOVAL

ACID

GAS

9

Figure 3-2IGCC with Hydrogen Export and Electricity Production

Case B

ACID GASREMOVAL &

CO2COMPRESSION

POWER BLOCKINCLUDING

GTG, STG, HRSG

SOUR/CO SHIFT& HEAT

RECOVERY

BFW STEAM

ACID

GAS

SULFURRECOVERY

UNIT

LIQUIDSULFUR

VENT

POWER

HYDROGENEXPORT

H2

CWS

CWR

FUEL

GAS

FUEL

GAS

100 MMSCFD

RAW SYNGAS

CLEAN H2 RICHGAS

ATM. AIR

N2

GASIFICATION

N2 TO GASTURBINE

N2VENT

HP STEAMTO GASIFIER

SLAGTO

DISPOSAL

SYNGAS

ATM.AIR

AIRSEPARATION

UNIT(ASU)

3,639 st/d

PET COKE

O2 TO SULFURRECOVERY UNIT

HP O2

221 MWe (Net)

ELECTRICALPOWERPRODUCTION

FLUE GAS TOATMOSPHERE

HP STEAM TOGASIFICATION

BFW

O2 FROM ASU

NOTES:

AGR = ACID GAS REMOVALBFW = BOILER FEEDWATERCO = CARBON MONOXIDECO2 = CARBON DIOXIDECWS = COOLING WATER SUPPLYCWR = COOLING WATER RETURNGTG = GAS TURBINE GENERATORH2 = HYDROGENHP = HIGH PRESSUREHRSG = HEAT RECOVERY STEAM GENERATORN2 = NITROGENO2 = OXYGENSTG = STEAM TURBINE GENERATOR

PROCESS CONDENSATE

PRESSURESWING

ADSORPTION

2000 Psig CO2TO SEQUESTRATION,

9,967 st/d

10

Figure 3-3IGCC with CO2 Removal and Electrical Power Production

Case C

ACID GASREMOVAL &

CO2COMPRESSION

SOUR/CO SHIFT& HEAT

RECOVERY

BFW STEAM

ACID

GAS

SULFURRECOVERY

UNIT

LIQUIDSULFUR

VENT

RAW SYNGAS

CLEAN H2 RICHGAS

GASIFICATION

N2 TO GASTURBINE

N2VENT

HP STEAMTO GASIFIER

SLAGTO

DISPOSAL

SYNGAS

ATM.AIR

AIRSEPARATION

UNIT(ASU)

3,639 st/d

PET COKE

O2 TO SULFURRECOVERY UNIT

HP O2

O2 FROM ASU

NOTES:

AGR = ACID GAS REMOVALBFW = BOILER FEEDWATERCO = CARBON MONOXIDECO2 = CARBON DIOXIDECWS = COOLING WATER SUPPLYCWR = COOLING WATER RETURNGTG = GAS TURBINE GENERATORH2 = HYDROGENHP = HIGH PRESSUREHRSG = HEAT RECOVERY STEAM GENERATORN2 = NITROGENO2 = OXYGENSTG = STEAM TURBINE GENERATOR

PROCESS CONDENSATE

2000 Psig CO2TO SEQUESTRATION,

9,967 st/d

POWER BLOCKINCLUDING

GTG, STG, HRSG

POWER

CWS CWR

ATM. AIR

N2

444.1 MWe (Net)

ELECTRICALPOWERPRODUCTION

FLUE GAS TOATMOSPHERE

HP STEAM TOGASIFICATION

BFW

11

Figure 3-4Hydrogen Production Plant

Case D

HYDROGENEXPORT

100 MMSCFD

Net LP Steam

NOTES:

AGR = ACID GAS REMOVALBFW = BOILER FEEDWATERCO = CARBON MONOXIDECO2 = CARBON DIOXIDECWS = COOLING WATER SUPPLYCWR = COOLING WATER RETURNGTG = GAS TURBINE GENERATORH2 = HYDROGENHP = HIGH PRESSUREHRSG = HEAT RECOVERY STEAM GENERATORN2 = NITROGENO2 = OXYGENSTG = STEAM TURBINE GENERATOR

CWS CWR

HYDROGEN PLANT UTILIZINGSTEAM HYDROCARBON

REFORMINGNatural Gas

Net HP Steam

BFWMPSteam

FLUE GAS(2,835 st/d CO2)

1,821 MMBtu/h LHV

12

Figure 3-4Combined Cycle Power Plant

Case E

NOTES:

AGR = ACID GAS REMOVALBFW = BOILER FEEDWATERCO = CARBON MONOXIDECO2 = CARBON DIOXIDECWS = COOLING WATER SUPPLYCWR = COOLING WATER RETURNGTG = GAS TURBINE GENERATORH2 = HYDROGENHP = HIGH PRESSUREHRSG = HEAT RECOVERY STEAM GENERATORN2 = NITROGENO2 = OXYGENSTG = STEAM TURBINE GENERATOR

NAT. GAS

UTILITIES ANDGENERAL FACILITIES

FLUE GAS TOATMOSPHERE(5,789 st/d CO2)

POWER

CW

S

CW

R

MAKE-UPWATER

582 MWe (NET)

Atm.AIR

DEM

IN. W

ATER

ELECTRICALPOWERPRODUCTION

COMBINED CYCLE POWER PLANTINCLUDING

GTGs, STG, HRSGs

3,718 MMBTU/H LHV

BLOWDOWNSTREAMS

13

Basis for Economics

Debt/Equity Ratio 70/30Cost of Electricity, cents/kWh 3.5Cost of Petroleum Coke, $/ton dry 0Cost of Natural Gas, $/MMBtu LHV 3Price of Hydrogen, $/1000 SCF 2Price of Steam (<1450 psig), $/1000 lb 2.7Carbon Tax, $/ton CO2 0Tax Rate, % 40Annual Escalation, % 3Financing Rate, % 8Loan Term, Years 10

14

Performance Results

Case A Case B Case C Case D Case E

st = short ton

mt = metric tonne

IGCC PowerProduction

IGCC PowerProduction

with

H2 Export

IGCC PowerProductionwith CO2Removal

HydrogenProduction

Plant

CombinedCycle PowerProduction

Gas Turbines: 2 x GE 7FA 1 x GT 2 x GTs NA 2 x GE 7FA

Coke Feed Rate, st/d (dry) 3639 3639 3639 NA NA

Natural Gas Feed, MMBtu/h LHV NA NA NA 1,821 3,718

Net Power Output, MW 503 221 441 (0.2) 582

Net Heat Rate, Btu/kWh LHV 8,926 NA 10,112 NA 6,391

CO2 to Atmosphere, st/d 11,417 1,414 1,414 2,835 5,789

CO2 Recovered for Sequestration, st/d 0 9,967 9,967 0 0

H2 Produced, MMSCFD 0 100 0 100 0

Steam Export, lb/h 0 0 0 352,700 0

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Configuration Information

Case A Case B Case C Case D Case E

FeedStock Petcoke Petcoke Petcoke N. Gas N. Gas

Gasification Facilities and ASU X X X

Sour/Shift Unit X X

CO2 Removal X X

Acid Gas Removal X X X

Sulfur Recovery X X X

Power Block X X X X

Steam Methane Reformer X

PSA X X

16

Sensitivity to Electricity Price

Coke: $0/ton; No Carbon Tax; H2 Price $2/kSCF; N. Gas Price $3/MMBtu LHV

8

12

16

20

24

28

32

36

40

3 3.5 4

Power Price (cents/kWh)

ROE

%

Case ACase BCase CCase E

17

Sensitivity to Carbon Tax

Coke: $0/ton; Power Price $0.035/kWh; H2 Price $2/kSCF; N. Gas Price $3/MMBtu LHV

4

8

12

16

20

24

28

32

0 5 10 15 20 25 30

Carbon Tax ($/ston CO2)

ROE

%

Case ACase BCase CCase DCase E

18

Sensitivity to Coke Price

No Carbon Tax; Power Price $0.035/kWh; H2 Price $2/kSCF; N. Gas $3/MMBtu LHV

0

4

8

12

16

20

0 5 10 15 20 25

Coke Price ($/tonne)

RO

E % Case 1

Case 2Case 3

19

Sensitivity to Hydrogen Price

Coke Price 0$/ton; No Carbon Tax; Power Price $0.035/kWh; N. Gas $3 MMBtu LHV

048

1216202428

0 0.5 1 1.5 2 2.5 3

Hydrogen Price ($ / 1000 SCF)

RO

E % Case B

Case D

20

Sensitivity to Natural Gas Price

Coke Price 0$/ton; No Carbon Tax; Power Price $0.035/kWh; Hydrogen $2/kSCF

5

10

15

20

25

30

35

2 2.5 3 3.5 4 4.5 5

Natural Gas Price ($/MMBtu LHV)

RO

E % Case D

Case E

21

IGCC Power Production versus Combined Cycle- Carbon Tax Sensitivity

Coke: $0/ton; Power Price $0.035/kWh

0

5

10

15

20

25

30

0 5 10 15 20 25 30Carbon Tax ($/ston CO2)

ROE

%

Case C Case E NG @ $3/MMBtuCase E NG @ $4/MMBtu Case A

22

Hydrogen Production Cases - Carbon Tax Sensitivity

Coke: $0/ton; Power Price $0.035/kWh; H2 Price $2/kSCF

0

5

10

15

20

25

30

0 5 10 15 20 25 30

Carbon Tax ($/ston CO2)

RO

E %

Case B Case D NG @ $3/MMBtu Case D NG @ $4/MMBtu

23

Sensitivity to Carbon Tax for IGCC with and without CO2 Removal

Coke: $0/ton; Power Price $0.035/kWh

0

4

8

12

16

20

0 5 10 15 20 25 30

Carbon Tax ($/ston CO2)

RO

E % Case A

Case C

24

Discussion of Results

The breakeven point between an IGCC facility (Case A) and an IGCC facility with CO2 removal (Case C) is about $7.5/ton CO2 tax.

Co-production of hydrogen from an IGCC facility becomes more attractive compared to a natural gas based H2 production plant, even without a carbon tax levy, as natural gas prices increase.

An increase in natural gas price or a significant carbon tax levy is needed for an IGCC plant with CO2 removal to be comparable to a Combined Cycle facility fired on natural gas.

25

Discussion of Results (Continued)

Case B, IGCC with Co-Production of hydrogen and Power, becomes the most attractive case when a CO2 tax in excess of $15 is levied.

With no carbon tax levy or increase in natural gas price, conventional production facilities are more economically attractive in comparison to coke fed IGCC plant when the natural gas is < $3/MMBtu.

As CO2 tax increases, Case B remains economically attractive, Case A and D rapidly become less attractive, and Case E becomes less attractive.

26

Discussion of Results (Continued)

Case B (IGCC + H2) is comparable to the economics for Case A (IGCC) even when no CO2 tax is levied. The economics for Case A rapidly become less attractive with the inclusion of a carbon tax on emissions; whereas the Case B ROE is relatively unaffected by a carbon tax.

Reducing CO2 emissions for Cases B and C to less than 10% of the Case A emissions with CO2 recovery for sequestration, significantly reduces the impact a carbon tax would have on their Return on Equities.