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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
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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
35% total CO299 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
35% 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
Auxiliary Power (MW)
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
Auxiliary Power (MW)
Base Plant Load 19 36
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
Auxiliary Power (MW)
Base Plant Load 19 21
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
Note: Preliminary results as of May 2006. Final report release Date: May 2007
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
Without CO2 Capture With CO2 Capture
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
Note: Preliminary results as of May 2006. Final report release Date: May 2007
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
Without CO2 Capture With CO2 Capture
Current State IGCC with CO2 Capture less than PC
with CO2 Capture
Current State IGCC with CO2 Capture less than PC
with CO2 Capture
Note: Preliminary results as of May 2006. Final report release Date: May 2007
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
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