co2 capture: comparison of cost & performance of · pdf file · 2016-01-252...

Workshop on Gasification Technologies

Denver, Colorado

March 14, 2007

Jared P. Ciferno, National Energy Technology Laboratory

CO2 Capture: Comparison of Cost & Performance of Gasification and Combustion-based Plants

2

DisclaimerThis presentation was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government or any agency thereof.

3

CO2 Capture from Fossil Energy Power Plants

“2006 Cost and Performance Comparison of Fossil Energy

Power Plants”

-Report Contains-Subcritical Pulverized CoalSupercritical Pulverized CoalIntegrated Gasification Combined

CycleNatural Gas Combined Cycle

4

Study Matrix

PlantType

ST Cond.(psig/°F/°F)

GTGasifier/

BoilerAcid Gas Removal/

CO2 Separation / Sulfur RecoveryCO2

Cap

Selexol / - / ClausSelexol / Selexol / Claus 90%

MDEA / - / ClausSelexol / Selexol / Claus 88%1

Sulfinol-M / - / Claus

IGCC

1800/1050/1050 (non-CO2

capture cases)

1800/1000/1000(CO2 capture

cases) Selexol / Selexol / Claus 90%Wet FGD / - / Gypsum

Wet FGD / Econamine / Gypsum 90%Wet FGD / - / Gypsum

Wet FGD / Econamine / Gypsum 90%

- / Econamine / - 90%NGCC 2400/1050/950 F Class HRSG

3500/1100/1100 Supercritical

2400/1050/1050 SubcriticalPC

Shell

CoPE-Gas

GE

F Class

GEE – GE EnergyCoP – Conoco Phillips

1 CO2 capture is limited to 88% by syngas CH4 content

5

Design Basis: Bituminous Coal Type

Illinois #6 Coal Ultimate Analysis (weight %)As Rec’d Dry

Moisture 11.12 071.725.061.41

Chlorine 0.29 0.33Sulfur 2.51 2.82

Ash 9.70 10.91Oxygen (by difference) 6.88 7.75

100.0 100.0HHV (Btu/lb) 11,666 13,126

Carbon 63.75Hydrogen 4.50

Nitrogen 1.25

6

Environmental Targets

IGCC1 PC2 NGCC3

SO20.0128

lb/MMBtu0.085

lb/MMBtu< 0.6 gr S /100

scf

NOx 15 ppmv (dry) @ 15% O2

0.07 lb/MMBtu

2.5 ppmv @ 15% O2

PM 0.0071 lb/MMBtu

0.017 lb/MMBtu Negligible

Hg > 90% capture 1.14 lb/TBtu Negligible

1 Based on EPRI’s CoalFleet User Design Basis Specification for Coal-Based IGCC Power Plants2 Based on BACT analysis, exceeding new NSPS requirements3 Based on EPA pipeline natural gas specification and 40 CFR Part 60

7

Economic AssumptionsEconomicStartup 2010-2012Plant Life (Years) 20 Capital Charge Factor (%) 14Dollars (Constant) Jan 2006Coal ($/MM Btu) 1.34

SiteGreenfield, Midwestern USA, 0 ft ElevationRail and Highway AccessMunicipal Water300 Acres

8

Pre-Combustion CO2 Capture Baseline

IGCC Power Plant

Current State CO2 CaptureUsing Selexol

9

IGCC without CO2 Capture

Process Design Assumptions:Dual Train: 2 gasifiers, 2 Comb. Turbine, 1 Steam TurbineOxygen: 95% O2 via Cryogenic ASU, ~4-7% Air Extraction

from combustion turbineTurbines: Advanced F-Class Turbine - 232MWe

N2 dilution employed to full extent in all cases Humidification/steam injection used only when necessary to meet syngas specification of ~120 Btu/scf LHV

Steam: 1800psig/1050°F/1050°F

Process Design Assumptions:Dual Train: 2 gasifiers, 2 Comb. Turbine, 1 Steam TurbineOxygen: 95% O2 via Cryogenic ASU, ~4-7% Air Extraction

from combustion turbineTurbines: Advanced F-Class Turbine - 232MWe

N2 dilution employed to full extent in all cases Humidification/steam injection used only when necessary to meet syngas specification of ~120 Btu/scf LHV

Steam: 1800psig/1050°F/1050°F

10

IGCC Power Plant with CO2 ScrubbingPre-Combustion Current Technology

Process Design Assumptions:Oxygen: 95% O2 via Cryogenic ASU, No

air extraction from combustion turbineSteam: 1800psig/1000°F/1000°FCO2 Capture: 95% separation factorCO2 Compression: 2,200 Psig

Process Design Assumptions:Oxygen: 95% O2 via Cryogenic ASU, No

air extraction from combustion turbineSteam: 1800psig/1000°F/1000°FCO2 Capture: 95% separation factorCO2 Compression: 2,200 Psig

CO2 Capture Advantages:1. High PCO22. Low Volume Syngas Stream3. CO2 Produced at Pressure

CO2 Capture Advantages:1. High PCO22. Low Volume Syngas Stream3. CO2 Produced at Pressure

Mole % (Dry)H2 36-40CO 37-40CO2 18-20

Mole % (Dry)H2 53-55CO 1-2CO2 38-41

11

GE Energy Radiant

Coal

Water

High Pressure

Steam

Radiant Syngas Cooler

Radiant Quench Gasifier

SyngasScrubber

Saturated Syngas 398OF

Quench Chamber

2,500OF

1,100OF

419OF

Coal

Water

High Pressure

Steam

Radiant Syngas Cooler

Radiant Quench Gasifier

SyngasScrubber

Saturated Syngas 398OF

Quench Chamber

2,500OF

1,100OF

419OF

Coal Slurry63 wt.%

95% O2

Slag/Fines

Syngas to Shift410°F, 800 PsiaComposition (Mole%):H2 26%CO 27%CO2 12%H2O 34%Other 1%H2O/CO = 1.3

Design: Pressurized, single-stage, downward firing, entrained flow, slurry feed, oxygen blown, slagging, radiant and quench cooling

Note: All gasification performance data estimated by the project team to be representative of GE gasifier

2,400oF

12

ConocoPhillips E-Gas™

Coal Slurry63 wt. %

Stage 2

95 % O2Slag

Quench

Char

Slag/Water Slurry

Syngas Syngas1,850°F, 614 psia

Composition (Mole%):H2 27%CO 38%CO2 14%H2O 14%CH4 4%Other 3%H2O/CO = 0.4

(0.22)

(0.78)

Stage 12,500oF

614 Psia

To Fire-tube boiler

Design: Pressurized, two-stage, upward firing, entrained flow, slurry feed, oxygen blown, slagging, fire-tube boiling syngas cooling, syngas recycle

Note: All gasification performance data estimated by the project team to be representative of an E-Gas gasifier

13

Shell

750°F, 600 PsiaComposition (Mole%):H2 16%CO 31%CO2 1%H2O 48%Other 4%H2O/CO = 1.6

DryCoal

ConvectiveCooler

95% O2

HP Steam

Note: All gasification performance data

estimated by the project team to be representative of Shell gasifier.

To Scrubberand WGS

Slag

Gasifier2,700oF615 psia

400°F, 575 PsiaComposition (Mole%):H2 29%CO 57%CO2 2%H2O 4%Other 8%H2O/CO = 0.06

Syngas Quench

WaterQuench

No Capture Case

Capture

Design: Pressurized, single-stage, upward firing, entrained flow, dry feed, oxygen blown, convective cooler

To Scrubber

2 Options

14

Water-Gas Shift Reactor System

H2O/CO Ratio1

GE 1.3

E-Gas 0.4

Shell 1.5

Design: Haldor Topsoe SSK Sulfur Tolerant CatalystUp to 97.5% CO Conversion2 stages for GE and Shell, 3 stages for E-GasH2O/CO = 2.0 (Project Assumption)Overall ΔP = ~30 psia

775oF 450oF 500oF 450oF Cooling

Steam Turbine Output (MW)

0.9

2.4

1.0

Relative HP* Steam Flow

230Shell

230E-Gas

275GE

455oF

Steam Steam

H2O + CO CO2 + H2

*High Pressure Steam

1 Prior to shift steam addition

15

Advantages• Physical Liquid Sorbent High loadings at high CO2 partial

pressure• Highly selective for H2S and CO2 No need for separate

sulfur capture system• No heat of reaction (ΔHrxn), small heat of solution• Chemically and thermally stable, low vapor pressure• 30+ years of commercial operation (55 worldwide plants)

Disadvantages• Requires Gas Cooling (to ~100oF)• CO2 regeneration by flashing

CO2 Capture via Selexol Scrubbing

16

Solubility of Gases in Selexol SolventComponent Solubility Indexa

H2 0.2

CO 0.8

CH4 1.0

CO2 15

COS 35

H2S 134

CH3SH 340

H2O 11,000

HCN 38,000

C6H6 3,800

1. Single component solubilities only and are approximate for multi-component loaded solvents

2. Process can be configured in many ways depending on the requiredlevel of H2S and CO2 removal

aRelative to CH4 at 25oC

System designed to take advantage of

solubility difference

System designed to take advantage of

solubility difference

17

SelexolTM Scrubbing

To ClausH2S/CO2

Steam 120 MMBtu/hr

Stage 1H2S Absorber(2 Columns)

H2S Concentrator

N2 PurgeH2S/CO2 Acid Gas Stripper

Makeup60 gpd

MP Flash

LP Flash

Stage 2CO2 Absorber(4 Columns)

17% total CO297 Mol % CO2


HP Flash

To TurbineFuel Gas6 MMscfd

95oF/495 psia

H2S/CO2 RichShifted Syngas100oF/500 psia

Lean Selexol10,000 gpm

CO2 Rich

CO2 Rich Selexol

10,000 gpm

Semi-Lean Selexol50,000 gpm

Reabsorber

13% total CO278 Mol% CO2


300 psia

160 psia

50 psia

400 psia

18

GE Energy IGCC Performance Results

GE EnergyCO2 Capture NO YES

CO2 Compression - 27

Energy Penalty1 - 5.7

Gross Power (MW) 770 745

Auxiliary Power (MW)

Base Plant Load 23 23

121

18

189

556

10,505

32.5

Total Aux. Power (MW) 130

Heat Rate (Btu/kWh) 8,922

Air Separation Unit 103

Gas Cleanup/CO2 Capture 4

Net Power (MW) 640

Efficiency (HHV) 38.2

1CO2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO2 Capture

in ASU air comp. load w/o turbine

integration

Steam for WGS, Selexol Unit

Includes H2S/CO2Removal in Selexol

Solvent

19

IGCC Performance Summary

GE Energy E-Gas ShellCO2 Capture NO YES NO YES NO YES

CO2 Compression - 27 - 26 - 28

Energy Penalty1 - 5.7 - 7.6 - 9.1

Gross Power (MW) 770 745 742 694 748

26 21

90

1

112

636

8,306

41.1

109

15

176

518

10,757

31.7

23

121

18

189

556

10,505

32.5

693


Base Plant Load 23 25 19

Total Aux. Power (MW) 130 119 176

Heat Rate (Btu/kWh) 8,922 8,681 10,674

Air Separation Unit 103 91 113

Gas Cleanup/CO2 Capture 4 3 16

Net Power (MW) 640 623 517

Efficiency (%HHV) 38.2 39.3 32.0

1CO2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO2 Capture

CO2 Capture decreases net efficiency by ~6-9 percentage points

20

IGCC Economic Results SummaryGE Energy E-Gas Shell

CO2 Capture NO YES NO YES NO YES

Increase in COE (%) - 25 - 29 - 38

$/tonne CO2 Avoided - 19 - 22 - 30

Plant Cost ($/kWe)

Base Plant 1,311 1,457 1,173 1,399 1,726

158 154

302

CO2 Compression - 66 - 67 - 70

2,252

4.90

2.90

7.80

237

1,861

4.00

2.65

6.65

165

262

1,950

4.25

2.85

7.10

1,354

Air Separation Unit 100 133 124

Gas Cleanup/CO2 Capture 146 111 115

Total Plant Cost ($/kWe) 1,557 1,417 1,593

Capital COE (¢/kWh) 3.40 3.10 3.50

Variable COE (¢/kWh) 2.30 2.05 2.10

Total COE (¢/kWh) 5.70 5.15 5.60

Note: Preliminary results as of May 2006. Final report release Date: May 2007

IGCC CO2 capture results in:Increase in Capital Cost (TPC) ~ $500—600/kWIncrease in COE ~1.5—2.2 cents/kWh (~ 30%)

21

IGCC with CO2 Capture Key Points

1. Gasifier design (dry feed vs. slurry, quench vs. heat exchanger) has large influence on water-gas shift steam requirement, steam turbine output and net plant efficiency

2. CoP/E-Gas has high methane content, with Selexol at 95% separation, can only get 88% carbon capture

3. Average cost of electricity without CO2 capture = 5.5 cents/kWh

4. Average cost of electricity with CO2 capture = 7.2 cents/kWh

5. Average CO2 mitigation cost = $24/tonne CO2 avoided*Main Air Compressor

22

Post-Combustion CO2 Capture Baseline

Pulverized Coal Power Plant

Current State CO2 CaptureUsing Amine Scrubbing

23

PC Power Plant with CO2 ScrubbingPost-Combustion Current Technology

CO22,200 Psig

Coal

Air PC Boiler(With SCR)

Steam

Bag Filter

WetLimestone

FGD

Flue Gas

Ash

ID FansSteam

Steam toEconamine FG+

Power

Process Design Assumptions:Steam:

Subcritical 2400psig/1050°F/1050°FSupercritical 3500psig/1100°F/1100°F

Process Design Assumptions:Steam:

Subcritical 2400psig/1050°F/1050°FSupercritical 3500psig/1100°F/1100°F

CO2 Capture Challenges:1. Dilute Flue Gas (10-14% CO2)2. Low Pressure CO23. 1.5 Million scfm4. 17,000 ton CO2/day removed5. Large Parasitic Loads (Steam +

CO2 Compression)

CO2 Capture Challenges:1. Dilute Flue Gas (10-14% CO2)2. Low Pressure CO23. 1.5 Million scfm4. 17,000 ton CO2/day removed5. Large Parasitic Loads (Steam +

CO2 Compression)

24

Amine Advantages1. Proven Technology Remove CO2 and H2S from NG2. Chemical solvent High loadings at low CO2 partial pressure3. Relatively Cheap ($1.50-2.0 per lb chemical)

Amine Disadvantages1. High heat of reaction high regeneration energy required

− 1,500 to 3,500 Btu/lb CO2 removed− Low pressure steam derates power plant by 20 to 40%

2. Degradation and Corrosion− Requires < 10ppm sulfur

3. High cost

Amine Scrubbing Advantages/Disadvantages

25

Amine Scrubbing Improvements

Improvements Benefits Outcome

Reaction RatesPacking volume, Absorber sizeAbsorber cost

Solvent circulation, Reboiler Duty

Reaction RatesPacking volume, Absorber sizeAbsorber cost

5. Integrated Steam Generation Reboiler Duty Power plant efficiency

7. Non-Thermal Reclaimer Solvent LossesSolvent make-up costs, eliminate

any solid hazardous waste

2. Heat Integration

CO2 CapacitySolvent circulation, Reboiler

Duty

Power plant efficiency

Reboiler Duty

1. New Solvent Formulation

CO2 Capacity

3. Split Flow Reboiler Duty

4. Condensate Flash Steam Stripping

Semi-Lean Loading

6. Larger Diameter Vessels 60 foot diameter Accommodate power plants

Amine CO2 scrubbing technology leaders are Fluor (Econamine FG PlusSM) and Mitsubishi Heavy Industry

26

• Overall absorption rate of CO2 absorber size, capital cost• Rich solvent loading solvent circulation rate, reboiler duty

Absorber Interstage Cooling2

Flue Gas

FG to Stack

Rich Amine

Lean Amine

Reddy, S., Scherffius, J., Fluor’s Econamine FG PlusSM

Technology; An enhanced amine-based CO2 capture process,2nd Annual Carbon Sequestration Conference, 2004.

27

Fluor Econamine FG PlusSM Scrubbing

Reboiler Heat Duty (Btu/lb CO2) 1,550 Regeneration (oF) 250’s

Auxiliary Power (MW) 21-24

Absorption (oF) 100’s Induced Draft Fan (MW) 13-15

MEA Circulation Rate (GPM) 35,000

28

Subcritical PC PerformanceSubcritical

Coal Flow Rate 5,252 7,759

CO2 Capture - 24

CO2 Captured (Ton/day) 0 16,566

CO2 Compression - 52

Energy Penalty (% Points) - 11.8

Gross Power (MW) 584 681



14

5

131

550

25.0

Total Aux. Power (MW) 33

Forced + Induced Draft Fans 10

Flue Gas Cleanup 4

Net Power (MW) 550

Efficiency (%HHV) 36.8

CO2 Capture decreases net efficiency by ~12 percentage points

Larger Base Plant

48% Increase in Coal Flow Rate

MEA Scrubbing

~17,000 TPD to 2,200 Psig

29

Pulverized Coal Performance SummarySubcritical Supercritical

Coal Flow Rate 5,252 7,759 4,935 7,039

CO2 Capture - 24 - 21

CO2 Captured (Ton/day) 0 16,566 0 15,029

CO2 Compression - 52 - 47

Energy Penalty (% Points) - 11.8 - 11.9

Gross Power (MW) 584 681 580 664

36 32

13

5

118

546

27.2

14

5

131

550

25.0



Total Aux. Power (MW) 33 30

Forced + Induced Draft Fans 10 9

Flue Gas Cleanup 4 3

Net Power (MW) 550 550

Efficiency (%HHV) 36.8 39.1

CO2 Capture decreases net efficiency by ~12 percentage points

30

Pulverized Coal Economic Results SummarySubcritical Supercritical

CO2 Capture NO YES NO YES

Increase in COE (%) - 73 - 67

$/tonne CO2 Avoided 50 49

Plant Cost ($/kWe)

Base Plant 1,117 1,367 1,159 1,664

285 257

622

CO2 Compression - 82 - 82

2,368

4.88

3.46

8.35

624

2,358

4.87

3.76

8.63

SOx and NOx Cleanup 206 196

CO2 Capture - -

Total Plant Cost ($/kWe) 1,323 1,355

Capital COE (¢/kWh) 2.73 2.80

Variable COE (¢/kWh) 2.26 2.17

Total COE (¢/kWh) 4.99 4.97


Pulverized Coal CO2 capture results in:Increase in Capital Cost (TPC) ~ $1000/kWIncrease in COE ~ 3 - 4 cents/kWh (~70% in COE)

31

1. Advanced amine scrubbing technology for 90% CO2capture continues to be very energy intensive and costly• Definite need for performance and cost improvements

2. Average cost of electricity with CO2 capture = 8.5 cents/kWh

3. Average CO2 mitigation cost = $50/tonne CO2 avoided

4. “Post-combustion CO2 capture scrubbing processes can be regarded as current technology, but some demonstration of these technologies at large scale coal fired power plants is needed before they can be widely adopted with an acceptable level of commercial risk.” (IEA 2004)

Pulverized Coal CO2 Capture Key Points

32

Net Efficiency Comparison

0

5

10

15

20

25

30

35

40

45

IGCC PC IGCC PC

Net

Effi

cien

cy (%

HH

V)

Without CO2 Capture With CO2 Capture

38-41%37-39%

32-33%

25-27%

Note: Final results

33

Average Total Plant Cost Comparison

Total Plant Capital Cost includes contingencies and engineering fees


15221350

2021

2360

0

500

1,000

1,500

2,000

2,500

IGCC PC IGCC PC

$/k

Wh

(Jan

200

6)

CO2 Capture adds ~$500/kW to IGCC ~1,000/kW to PC

CO2 Capture adds ~$500/kW to IGCC ~1,000/kW to PC


34

0

1

2

3

4

5

6

7

8

9

10

IGCC PC IGCC PC

Cos

t of E

lect

ricity

(cen

ts/k

Wh)

Average Cost of Electricity Comparison


Current State IGCC with CO2 Capture less than PC

with CO2 Capture

Current State IGCC with CO2 Capture less than PC

with CO2 Capture


35

Thank You!

Email: [email protected]: 412-386-5862

NETL Energy Analysis Link:www.netl.doe.gov/energy-analyses

Model Links:Power Systems Financial Model (PSFM):Integrated Environmental Control Model (IECM):www.netl.doe.gov/energy-analyses/technology/html

mailto:[email protected]

http://www.netl.doe.gov/energy-analyses

http://www.netl.doe.gov/energy-analyses/technology/html

Supplemental Slides

37

Performance Metrics

Cost of Avoided Emissions ΔCOE / ΔCO2 Emissions

(mills/kWhcapture – mills/kWhbase)(kgCO2/kWhbase – kgCO2/kWhcapture)

Percent increase in COE

( c/kWhcapture / c/kWhbase ) – 1 0 0.2 0.4 0.6 0.8 1

CapturePlant

ReferencePlant

CO2 Emissions (tonne CO2/kWh)

CO2 Avoided

CO2 Captured

co2 capture: comparison of cost & performance of · pdf file · 2016-01-252...

Documents