Reducing CO 2 Emissions from Coal-Fired Power Plants

Transcription

1 Reducing CO 2 Emissions from Coal-Fired Power Plants CoalFleet for Tomorrow John Wheeldon (jowheeld@epri.com) EPRI Advanced Coal Generation CCTR Advisory Panel Meeting, Vincennes University, September 10 th, 2009 CoalFleet for Tomorrow is a registered service mark of Electric Power Research Institute, Inc.

2 Relative COE, - When CO 2 Capture Included, Higher PC Efficiency Lowers Levelized Cost-of-Electricity Based on KS-1 solvent, but oxycombustion considered similar 1.30 Pittsburgh #8 PRB 1.20 Potential range of COE increase with improvements in CCS technology either post-combustion capture or oxy-combustion Efficiency of PC plant without CO 2 capture, % (HHV) Capture only. No allowance for transportation and storage. 2

3 Performance Summary: 1300 F USC PC Subcritical Supercritical 1100 USC 1300 USC Main stream, F Main steam, psia Efficiency, % HHV Coal flow lb/hr 840, , , ,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 NO X & SO 2, lb/mwh CO 2, lb/mwh from plant CO 2, lb/mwh from mining and transportation (*) (*) Values based on life-cycle assessment model prepared by Carnegie Mellon University CO 2 emissions from 1300 F USC unit is 14.7% lower than emissions rate (per MWh) from subcritical unit 3

4 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 CO 2 emissions to 1500 lb/mwh Over 40 percent lower than US fleet average. Cautionary note: all measures may not be cost effective. 4

5 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% CO 2 capture UltraGen II 600 MW net, main steam 1290 F, 60% CO 2 capture ComTes-1400 to test materials and components for UltraGen III UltraGen III 600 MW net, main steam 1400 F, 90% CO 2 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 5

6 CO 2 Post-Combustion Capture (PCC) Plant Flue Gas Out (~1.5% CO 2 ) CO 2 to Compressors (+99.9% purity) Cooling, power, and solvent make-up CW CW ABSORBER (~110 F) Flue Gas (~14% CO 2 ) FLUE GAS COOLER Rich Amine Solution STRIPPER (~250 F) Condensate Steam CW SO 2 POLISHING WITH CAUSTIC Lean Amine Solution 6

7 Power Plant Losses Associated with Post- Combustion Capture Using Advanced Amine Sub (1) SC (2) USC (3) Efficiency, % HHV lb CO 2 /MWh Losses, MW (4) Auxiliary power Compressors Steam turbine TOTAL % reduction Efficiency with CCS, % HHV Percentage point loss Main steam temperatures: (1) 1005 F, (2) 1050 F, (3) 1260 F (4) Net output without CCS = 750 MW. Losses for 90 percent CO 2 capture 7

8 Solvent Used Strongly Influences PCC Plant Performance Need solvents with superior properties High CO 2 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 CO 2 Solutions Alternative approaches such as adsorption, algae, and membranes under investigation. 8

9 EPRI Role in Demonstrating Improved Post- Combustion CO 2 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 CO 2. 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 CO 2 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. 9

10 Power Plant Losses for Different Percentages of CO 2 Capture Percent CO 2 capture Steam extraction, % (1) Losses, MW (2) Auxiliary power Compressors Steam turbine TOTAL % reduction CO 2 capture, M-tons/yr (1) Steam required for solvent regeneration (2) Net output without CCS = 750 MW 10

11 Space and Storage Requirements for CCS Space required for Capture plant, CO 2 compressors, and added cooling capacity Power plant interconnections and maintenance, Routing steam piping, flue gas ducting Construction activities Possible upgrades to SO 2 and NO X controls Space a limiting factor setting achievable percent CO 2 capture Riverside plant with FGD may have no space available Suitable geological strata to store CO 2 or prospects for extended duration EOR 11

12 Retrofits Require a Lot of Space: First Come, First Served CO 2 capture plant for 500-MW unit occupies 6 acres (i.e., 510 ft x 510 ft) 12

13 EPRI Retrofit Study Owner: Great River Energy Location: North Dakota Owner: MidWest Generation Location: Illinois Owner: Nova Scotia Power Location: Nova Scotia 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 Owner: Intermountain Power Location: Utah Owner: FirstEnergy Location: Ohio 13

14 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 CO 2 capture) Source: Imperial College London 14

15 Let-Down Turbine and Condensate Return: Heat Integration G PCC System 15

16 PC Plant with PCC: Heat Integration G PCC System Heat from CO 2 stripper condenser and CO 2 compressors 16

17 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 CO 2 emissions at 1100 lb-co 2 /MWh (500 kg-co 2 /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% CO 2 Capture = 180 lb/mwh (80 kg/mwh) 17

18 Concluding Remarks CO 2 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 CO 2 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. 18

19 Together Shaping the Future of Electricity 19