Reducing CO2 Emissions from Coal-Fired

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Reducing CO2 Emissions
from Coal-Fired Power Plants
CoalFleet for Tomorrow®
John Wheeldon ([email protected])
EPRI
Advanced Coal Generation
CCTR Advisory Panel Meeting,
Vincennes University,
September 10th, 2009
CoalFleet for Tomorrow® is a registered service mark
of Electric Power Research Institute, Inc.
When CO2 Capture Included, Higher PC
Efficiency Lowers Levelized Cost-of-Electricity
1.50
Based on KS-1 solvent, but oxycombustion considered similar
Relative COE, -
1.40
Pittsburgh #8
1.30
PRB
Potential range of COE increase with improvements in CCS
technology either post-combustion capture or oxy-combustion
1.20
1.10
30
35
40
45
50
Efficiency of PC plant without CO2 capture, % (HHV)
Capture only. No allowance for transportation and storage.
© 2007 Electric Power Research Institute, Inc. All rights reserved.
2
Performance Summary: 1300°F USC PC
Subcritical
Supercritical
1100 USC
1300 USC
Main stream, °F
1005
1080
1120
1256
Main steam, psia
2600
3800
4000
5100
Efficiency, % HHV
36.5
38.5
39.2
42.7
Coal flow lb/hr
840,600
797,000
782,700
718,600
Flue gas, ACFM
2,107,000
2,016,000
1,982,000
1,823,000
Make-up water, gpm
4,260
3,750
3,650
3,310
NOX & SO2, lb/MWh
0.280
0.266
0.261
0.240
CO2, lb/MWh from plant
1980
1880
1840
1690
CO2, lb/MWh from mining
and transportation (*)
146
139
136
125
(*) Values based on life-cycle assessment model prepared by Carnegie Mellon University
CO2 emissions from 1300°F USC unit is 14.7% lower than emissions rate
(per MWh) from subcritical unit
© 2007 Electric Power Research Institute, Inc. All rights reserved.
3
Further Efficiency Improvements Identified
• Increase main steam temperature to 1400°F
– US DOE sponsoring research into boiler and steam turbines
materials (mainly high-nickel alloys).
• Double reheat steam circuit.
• Back-end heat recovery
– Widely practiced in Europe and Japan.
• Pass primary air through tubular heat exchanger to reduce air
leakage by 80 percent.
• Potential to reduce CO2 emissions to 1500 lb/MWh
– Over 40 percent lower than US fleet average.
• Cautionary note: all measures may not be cost effective.
© 2007 Electric Power Research Institute, Inc. All rights reserved.
4
Demonstration of Improvements :
EPRI’s UltraGen Initiative
• Series of three commercial power projects and a test facility that
progressively advance USC, NZE, and CCS technology
–
–
–
–
UltraGen I—800 MW net, main steam 1120°F, 25% CO2 capture
UltraGen II—600 MW net, main steam 1290°F, 60% CO2 capture
ComTes-1400 to test materials and components for UltraGen III
UltraGen III—600 MW net, main steam 1400°F, 90% CO2 capture
• The UltraGen projects are commercial units dispatched by their
hosts (i.e., the host operates them for profitability) that incorporate
technology demonstration elements
– Host’s incremental cost for new technology elements will be covered
by tax credits and funds from industry-led consortium
© 2007 Electric Power Research Institute, Inc. All rights reserved.
5
CO2 Post-Combustion Capture (PCC) Plant
CO2 to Compressors
(+99.9% purity)
Flue Gas Out
(~1.5% CO2)
Cooling, power, and
solvent make-up
CW
CW
ABSORBER
(~110°F)
STRIPPER
(~250°F)
FLUE GAS
COOLER
Steam
Flue Gas
(~14% CO2)
Rich Amine
Solution
Condensate
CW
© 2007 Electric Power Research Institute, Inc. All rights reserved.
SO2 POLISHING
WITH CAUSTIC
Lean Amine
Solution
6
Power Plant Losses Associated with PostCombustion Capture Using Advanced Amine
Efficiency, % HHV
lb CO2/MWh
Losses, MW (4)
Auxiliary power
Compressors
Steam turbine
TOTAL
% reduction
Efficiency with CCS, % HHV
Percentage point loss
Sub (1)
36.5
1970
SC (2)
38.2
1880
USC (3)
42.5
1690
9.2
49.5
93.9
152.6
20.3
8.6
47.0
89
144.6
19.3
7.5
41.0
77.9
126.4
16.9
29.3
7.2
31.2
7.0
36.9
5.6
Main steam temperatures: (1) 1005°F, (2) 1050°F, (3) 1260°F
(4) Net output without CCS = 750 MW. Losses for 90 percent CO2 capture
© 2007 Electric Power Research Institute, Inc. All rights reserved.
7
Solvent Used Strongly Influences PCC Plant
Performance
• Need solvents with superior properties
– High CO2 loading to limit sensible heat duty
– Low heat of reaction
– Tolerant to contaminants
– Regenerate at elevated pressure
• Significant development activity in progress
– Amines: Aker, Alstom with Dow, Cansolv, HTC PurEnergy, MHI,
TNO, and Toshiba
– Amino acid salts: BASF, TNO, and Siemens
– Ammonia: Alstom and Powerspan
– Anhydrase enzymes: CSIRO and CO2 Solutions
• Alternative approaches such as adsorption, algae, and membranes
under investigation.
© 2007 Electric Power Research Institute, Inc. All rights reserved.
8
EPRI Role in Demonstrating Improved PostCombustion CO2 Capture Technologies
• Supporting test program for Alstom’s chilled ammonia process at
two locations
– 1.7-MW pilot plant at We Energies’ Pleasant Prairie power plant
– 20-MW ―product validation facility‖ at AEP’s Mountaineer plant
that captures and stores over 120,000 tons/year of CO2.
• Supporting test program for MHI’s advanced amine process at a
Southern Company’s Plant Barry, near Mobile, Alabama
– 25-MW facility that captures and stores over 150,000 tons/year
of CO2 in support of Southeast Regional Carbon Sequestration
Partnership Program (SECARB).
• Supporting DOE’s National Carbon Capture Center in Wilsonville,
Alabama
– Supporting development of improved pre- and post-combustion
capture technologies.
© 2007 Electric Power Research Institute, Inc. All rights reserved.
9
Power Plant Losses for Different
Percentages of CO2 Capture
Percent CO2 capture
90
60
30
25
17
8
Steam extraction, % (1)
Losses, MW (2)
Auxiliary power
Compressors
Steam turbine
TOTAL
% reduction
9.2
49.5
93.9
152.6
20.3
6.1
33.0
62.6
101.7
13.5
3.1
16.5
31.3
50.9
6.8
CO2 capture, M-tons/yr
4.66
3.11
1.55
(1) Steam required for solvent regeneration
(2) Net output without CCS = 750 MW
© 2007 Electric Power Research Institute, Inc. All rights reserved.
10
Space and Storage Requirements for CCS
• Space required for
– Capture plant, CO2 compressors, and added cooling capacity
– Power plant interconnections and maintenance,
– Routing steam piping, flue gas ducting
– Construction activities
– Possible upgrades to SO2 and NOX controls
• Space a limiting factor setting achievable percent CO2 capture
– Riverside plant with FGD may have no space available
• Suitable geological strata to store CO2 or prospects for extended
duration EOR
© 2007 Electric Power Research Institute, Inc. All rights reserved.
11
Retrofits Require a Lot of Space:
First Come, First Served
CO2 capture plant for 500-MW unit occupies 6 acres (i.e., 510 ft x 510 ft)
© 2007 Electric Power Research Institute, Inc. All rights reserved.
12
EPRI Retrofit Study
•
•
•
Owner:
Great River Energy
•
Location: North
Dakota
Owner:
MidWest
Generation
•
Owner:
Nova Scotia
Power
•
Location: Nova
Scotia
Location: Illinois
EPRI Retrofit Study Considers:
• 5 different sites
•
Owner:
FirstEnergy
• 5 separate owners
•
Location: Ohio
• Different designs of plant and
emission control technologies
• Focus on establishing several
different data points
© 2007 Electric Power Research Institute, Inc. All rights reserved.
•
Owner:
Intermountain
Power
•
Location: Utah
13
One Steam Extraction Option
Desuperheater can
be replaced by
expansion turbine to
recoup some of the
energy
Thrust
balance point
At high steam extraction rates thrust bearing design changes
required. Below 15 percent design changes not required (~60
percent CO2 capture)
Source: Imperial College London
© 2007 Electric Power Research Institute, Inc. All rights reserved.
14
Let-Down Turbine and Condensate Return:
Heat Integration
G
© 2007 Electric Power Research Institute, Inc. All rights reserved.
PCC
System
15
PC Plant with PCC: Heat Integration
G
PCC
System
Heat from CO2 stripper condenser
and CO2 compressors
© 2007 Electric Power Research Institute, Inc. All rights reserved.
16
California’s “De Facto” Coal Moratorium
• In January 2007, California
became first state to place ―de
facto moratorium‖ on new coal
plants
– Set the standard for CO2
emissions at 1100 lb-CO2/MWh
(500 kg-CO2/MWh )
– Washington state has followed
a similar approach
Pulverized Coal Plant = 1760 lb/MWh
(800 kg/MWh)
California Standard = 1100 lb/MWh
(500 kg/MWh)
CTCC = 800 lb/MWh
(360 kg/MWh)
~80%
capture
required on
CTCC?
Pulverized Coal at 90%
CO2 Capture = 180 lb/MWh (80 kg/MWh)
© 2007 Electric Power Research Institute, Inc. All rights reserved.
17
Concluding Remarks
• CO2 capture from flue gas has been carried out at small scale (~20
MW) for high-value applications in chemical and food industries.
• For power industry need larger plants that minimize increase in
cost of electricity
– Current designs are estimated to result in a 60 percent increase.
• Part of the approach to reduce costs is to increase power
generating efficiency and lower CO2 emitted per MWh
– This benefits both post-combustion and oxy-combustion.
– Post combustion also requires improved solvents.
• EPRI is increasing its effort in oxy-combustion and is supporting Air
Products in demonstrating the ion transfer membrane technology
as a more cost-effective alternative to cryogenic separation.
© 2007 Electric Power Research Institute, Inc. All rights reserved.
18
Together…Shaping the Future of Electricity
© 2007 Electric Power Research Institute, Inc. All rights reserved.
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