reducing co2 emissions from coal-fired power plants · •supporting test program for mhi’s...
TRANSCRIPT
CoalFleet for Tomorrow®
CoalFleet for Tomorrow® is a registered service mark
of Electric Power Research Institute, Inc.
Reducing CO2 Emissions from Coal-Fired Power Plants
John Wheeldon ([email protected])
EPRI Advanced Coal Generation
CCTR Advisory Panel Meeting,Vincennes University, September 10th, 2009
2© 2007 Electric Power Research Institute, Inc. All rights reserved.
When CO2 Capture Included, Higher PC Efficiency Lowers Levelized Cost-of-Electricity
Capture only. No allowance for transportation and storage.
1.10
1.20
1.30
1.40
1.50
30 35 40 45 50
Efficiency of PC plant without CO2 capture, % (HHV)
Rela
tive C
OE
, -
Pittsburgh #8 PRB
Based on KS-1 solvent, but oxy-
combustion considered similar
Potential range of COE increase with improvements in CCS technology either post-combustion capture or oxy-combustion
3© 2007 Electric Power Research Institute, Inc. All rights reserved.
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
4© 2007 Electric Power Research Institute, Inc. All rights reserved.
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.
5© 2007 Electric Power Research Institute, Inc. All rights reserved.
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
6© 2007 Electric Power Research Institute, Inc. All rights reserved.
CO2 Post-Combustion Capture (PCC) Plant
Flue Gas Out
(~1.5% CO2)
CO2 to Compressors
(+99.9% purity)
Steam
Flue Gas
(~14% CO2)
CW
CW
CW
ABSORBER
(~110°F)
FLUE GAS
COOLER
STRIPPER
(~250°F)
Rich Amine
Solution
Lean Amine
Solution
Condensate
SO2 POLISHING
WITH CAUSTIC
Cooling, power, and
solvent make-up
7© 2007 Electric Power Research Institute, Inc. All rights reserved.
Power Plant Losses Associated with Post-Combustion Capture Using Advanced Amine
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
Sub (1) SC (2) USC (3)
Efficiency, % HHV 36.5 38.2 42.5
lb CO2/MWh 1970 1880 1690
Losses, MW (4)
Auxiliary power 9.2 8.6 7.5
Compressors 49.5 47.0 41.0
Steam turbine 93.9 89 77.9
TOTAL 152.6 144.6 126.4
% reduction 20.3 19.3 16.9
Efficiency with CCS, % HHV 29.3 31.2 36.9
Percentage point loss 7.2 7.0 5.6
8© 2007 Electric Power Research Institute, Inc. All rights reserved.
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.
9© 2007 Electric Power Research Institute, Inc. All rights reserved.
EPRI Role in Demonstrating Improved Post-Combustion 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.
10© 2007 Electric Power Research Institute, Inc. All rights reserved.
Power Plant Losses for Different Percentages of CO2 Capture
(1) Steam required for solvent regeneration
(2) Net output without CCS = 750 MW
90 60 30
Steam extraction, % (1) 25 17 8
Losses, MW (2)
Auxiliary power 9.2 6.1 3.1
Compressors 49.5 33.0 16.5
Steam turbine 93.9 62.6 31.3
TOTAL 152.6 101.7 50.9
% reduction 20.3 13.5 6.8
CO2 capture, M-tons/yr 4.66 3.11 1.55
Percent CO2 capture
11© 2007 Electric Power Research Institute, Inc. All rights reserved.
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
12© 2007 Electric Power Research Institute, Inc. All rights reserved.
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)
13© 2007 Electric Power Research Institute, Inc. All rights reserved.
• Owner:
MidWest
Generation
• Location: Illinois
• Owner:
Great River Energy
• Location: North
Dakota
• Owner:
Nova Scotia
Power
• Location: Nova
Scotia
• Owner:
Intermountain
Power
• Location: Utah
• Owner:
FirstEnergy
• Location: Ohio
EPRI Retrofit Study
EPRI Retrofit Study Considers:
• 5 different sites
• 5 separate owners
• Different designs of plant and emission control technologies
• Focus on establishing several different data points
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One Steam Extraction Option
Source: Imperial College London
Thrust
balance point
Desuperheater can
be replaced by
expansion turbine to
recoup some of the
energy
At high steam extraction rates thrust bearing design changes
required. Below 15 percent design changes not required (~60
percent CO2 capture)
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PCC
System
Let-Down Turbine and Condensate Return: Heat Integration
G
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PCC
System
PC Plant with PCC: Heat Integration
G
Heat from CO2 stripper condenser
and CO2 compressors
17© 2007 Electric Power Research Institute, Inc. All rights reserved.
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 at 90%
CO2 Capture = 180 lb/MWh (80 kg/MWh)
Pulverized Coal Plant = 1760 lb/MWh
(800 kg/MWh)
CTCC = 800 lb/MWh
(360 kg/MWh)
California Standard = 1100 lb/MWh
(500 kg/MWh)
~80%
capture
required on
CTCC?
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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.
19© 2007 Electric Power Research Institute, Inc. All rights reserved.
Together…Shaping the Future of Electricity