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Cost and Performance Baseline for Fossil Energy Plants

Cost and Performance Baseline for Fossil Energy Plants. Final Results. May 15, 2007 Revised August 2007. National Energy Technology Laboratory. Disclaimer

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Cost and Performance Baseline for Fossil Energy Plants

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  1. Cost and Performance Baseline for Fossil Energy Plants Final Results May 15, 2007 Revised August 2007 National Energy Technology Laboratory

  2. Disclaimer This 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. 2

  3. Objective • Determine cost and performance estimates of near-term commercial offerings for power plants both with and without current technology for CO2 capture • Consistent design requirements • Up-to-date performance and capital cost estimates • Technologies built now and deployed by 2010-2012 • Provides baseline costs and performance • Compare existing technologies • Guide R&D for advancing technologies within the FE Program 3

  4. Study Matrix 1 CO2 capture is limited to 88% by syngas CH4 content GEE – GE Energy CoP – Conoco Phillips 4

  5. Design Basis: Coal Type 5

  6. Environmental Targets 1 Based on EPRI’s CoalFleet User Design Basis Specification for Coal-Based IGCC Power Plants 2 Based on BACT analysis, exceeding new NSPS requirements 3 Based on EPA pipeline natural gas specification and 40 CFR Part 60, Subpart KKKK 6

  7. Economic Assumptions Startup 2010 Plant Life (Years) 20 Capital Charge Factor, % High Risk (All IGCC, PC/NGCC with CO2 capture) 17.5 Low Risk (PC/NGCC without CO2 capture) 16.4 Dollars (Constant) 2007 Coal ($/MM Btu) 1.80 Natural Gas ($/MM Btu) 6.75 Capacity Factor IGCC 80 PC/NGCC 85 7

  8. Technical Approach • 1. Extensive Process Simulation (ASPEN) • All major chemical processes and equipment are simulated • Detailed mass and energy balances • Performance calculations (auxiliary power, gross/net power output) • 2. Cost Estimation • Inputs from process simulation (Flow Rates/Gas Composition/Pressure/Temp.) • Sources for cost estimation Parsons Vendor sources where available • Follow DOE Analysis Guidelines 8

  9. Study Assumptions • Capacity Factor assumed to equal Availability • IGCC capacity factor = 80% w/ no spare gasifier • PC and NGCC capacity factor = 85% • GE gasifier operated in radiant/quench mode • Shell gasifier with CO2 capture used water injection for cooling (instead of syngas recycle) • Nitrogen dilution was used to the maximum extent possible in all IGCC cases and syngas humidification/steam injection were used only if necessary to achieve approximately 120 Btu/scf syngas LHV • In CO2 capture cases, CO2 was compressed to 2200 psig, transported 50 miles, sequestered in a saline formation at a depth of 4,055 feet and monitored for 80 years • CO2 transport, storage and monitoring (TS&M) costs were included in the levelized cost of electricity (COE) 9

  10. IGCC Power Plant Current State-of-the-Art 10

  11. Current TechnologyIGCC Power Plant Emission Controls: PM: Water scrubbing and/or candle filters to get 0.0071 lb/MMBtu NOx: N2 dilution to ~120 Btu/scf LHV to get 15 ppmv @15% O2 SOx: AGR design target of 0.0128 lb/MMBtu; Claus plant with tail gas recycle for ~99.8% overall S recovery Hg: Activated carbon beds for ~95% removal Advanced F-Class CC Turbine:232 MWe Steam Conditions: 1800 psig/1050°F/1050°F (non-CO2 capture cases) 1800 psig/1000°F/1000°F (CO2 capture cases) 11

  12. GE Energy Radiant 95% O2 Coal Slurry 63 wt.% Syngas 410°F, 800 Psia Composition (Mole%): H226% CO 27% CO212% H2O 34% Other 1% H2O/CO = 1.3 To Acid Gas Removal or To Shift Slag/Fines 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 12

  13. ConocoPhillips E-Gas™ To Fire-tube boiler Syngas 1,700°F, 614 psia Composition (Mole%): H226% CO 37% CO214% H2O 15% CH4 4% Other 4% H2O/CO = 0.4 Syngas To Acid Gas Removal or To Shift Stage 2 Coal Slurry 63 wt. % (0.22) Design: Pressurized, two-stage, upward firing, entrained flow, slurry feed, oxygen blown, slagging, fire-tube boiling syngas cooling, syngas recycle (0.78) Char Slag Quench 95 % O2 Stage 1 2,500oF 614 Psia Note: All gasification performance data estimated by the project team to be representative of an E-Gas gasifier Slag/Water Slurry 13

  14. Shell Gasification HP Steam Convective Cooler Soot Quench & Scrubber Design: Pressurized, single-stage, downward firing, entrained flow, dry feed, oxygen blown, convective cooler • Notes: • All gasification performance data estimated by the project team to be representative of Shell gasifier. • CO2 capture incorporates full water quench instead of syngas quench. Gasifier 2,700oF 615 psia Syngas Quench2 Syngas 350°F, 600 Psia Composition (Mole%): H229% CO 57% CO22% H2O 4% Other 8% H2O/CO = 0.1 Steam HP Steam 95% O2 To Acid Gas Removal or To Shift 650oF Dry Coal Slag Source: “The Shell Gasification Process”, Uhde, ThyssenKrupp Technologies 14

  15. IGCC Performance ResultsNo CO2 Capture 15

  16. IGCC Economic ResultsNo CO2 Capture 1Total Plant Capital Cost (Includes contingencies and engineering fees) 2January 2007 Dollars, 80% Capacity Factor, 17.5% Capital Charge Factor, Coal cost $1.80/106Btu 16

  17. IGCC Power Plant With CO2 Capture 17

  18. Current TechnologyIGCC Power Plant with CO2 Scrubbing • Emission Controls: • PM: Water scrubbing and/or candle filters to get 0.007 lb/MMBtu • NOx: N2 dilution to ~120 Btu/scf LHV to get 15 ppmv @15% O2 • SOx: Selexol AGR removal of sulfur to < 28 ppmv H2S in syngas • Claus plant with tail gas recycle for ~99.8% overall S recovery • Hg: Activated carbon beds for ~95% removal • Advanced F-Class CC Turbine:232 MWe • Steam Conditions:1800 psig/1000°F/1000°F 18

  19. Water-Gas Shift Reactor System • Design: • Haldor Topsoe SSK Sulfur Tolerant Catalyst • Up to 97.5% CO Conversion • 2 stages for GE and Shell, 3 stages for E-Gas • H2O/CO = 2.0 (Project Assumption) • Overall DP = ~30 psia Steam Steam 455oF 500oF 775oF 450oF 450oF Cooling 1 Prior to shift steam addition H2O + CO CO2 + H2 *High Pressure Steam 19

  20. IGCC Performance Results Steam for Selexol h in ASU air comp. load w/o CT integration Includes H2S/CO2 Removal in Selexol Solvent 1CO2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO2 Capture 20

  21. IGCC Performance Results 1CO2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO2 Capture 21

  22. IGCC Economic Results 1Total Plant Capital Cost (Includes contingencies and engineering fees) 2January 2007 Dollars, 80% Capacity Factor, 17.5% Capital Charge Factor, Coal cost $1.80/106Btu 22

  23. Comparison to PC and NGCC Current State-of-the-Art 23

  24. Current TechnologyPulverized Coal Power Plant* *Orange Blocks Indicate Unit Operations Added for CO2 Capture Case PM Control:Baghouse to achieve 0.013 lb/MMBtu (99.8% removal) SOx Control:FGD to achieve 0.085 lb/MMBtu (98% removal) NOx Control:LNB + OFA + SCR to maintain 0.07 lb/MMBtu Mercury Control:Co-benefit capture ~90% removal Steam Conditions (Sub):2400 psig/1050°F/1050°F Steam Conditions (SC):3500 psig/1100°F/1100°F 24

  25. Current TechnologyNatural Gas Combined Cycle* *Orange Blocks Indicate Unit Operations Added for CO2 Capture Case Natural Gas Direct Contact Cooler HRSG Air Cooling Water Stack Gas Combustion Turbine Blower Reboiler Steam MEA Stack Condensate Return CO2 2200 psig CO2 Compressor NOx Control:LNB + SCR to maintain 2.5 ppmvd @ 15% O2 Steam Conditions:2400 psig/1050°F/950°F 25

  26. PC and NGCC Performance Results 1CO2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO2 Capture 26

  27. PC and NGCC Economic Results 1Total Plant Capital Cost (Includes contingencies and engineering fees) 2January 2007 Dollars, 85% Capacity Factor, 16.4% (no capture) 17.5% (capture) Capital Charge Factor, Coal cost $1.80/106Btu, Natural Gas cost $6.75/106Btu 27

  28. Environmental Performance Comparison IGCC, PC and NGCC 28

  29. Criteria Pollutant Emissions for All Cases 29

  30. CO2 Emissions for All Cases 30

  31. Raw Water Usage Comparison IGCC, PC and NGCC 31

  32. Raw Water Usage per MWnet(Absolute) 32

  33. Raw Water Usage per MWnet(Relative to NGCC w/ no CO2 Capture) 33

  34. Economic Results for All Cases 34

  35. CO2 Mitigation Costs 35

  36. Total Plant Cost Comparison Total Plant Capital Cost includes contingencies and engineering fees 36

  37. Cost of Electricity Comparison cents/kWh ($2007) January 2007 Dollars, Coal cost $1.80/106Btu. Gas cost $6.75/106Btu 37

  38. Highlights 38

  39. NETL Viewpoint • Most up-to-date performance and costs available in public literature to date • Establishes baseline performance and cost estimates for current state of technology • Improved efficiencies and reduced costs are required to improve competitiveness of advanced coal-based systems • In today’s market and regulatory environment • Also in a carbon constrained scenario • Fossil Energy RD&D aimed at improving performance and cost of clean coal power systems including development of new approaches to capture and sequester greenhouse gases 39

  40. Result Highlights: Efficiency & Capital Cost • Coal-based plants using today’s technology are efficient and clean • IGCC & PC: 39%, HHV (without capture on bituminous coal) • Meet or exceed current environmental requirements • Today’s capture technology can remove 90% of CO2, but at significant increase in COE • Total Plant Cost: IGCC ~20% higher than PC capex • NGCC: $554/kW • PC: $1561/kW (average) • IGCC: $1841/kW (average) • Total Plant Cost with Capture: PC > IGCC capex • NGCC: $1169/kW • IGCC: $2496/kW (average) • PC: $2788/kW (average) 40

  41. Results Highlights: COE • 20 year levelized COE: PC lowest cost generator • PC: 64 mills/kWh (average) • NGCC: 68 mills/kWh • IGCC: 78 mills/kWh (average) • With CCS: IGCC lowest coal-based option • NGCC: 96 mills/kWh • IGCC: 105 mills/kWh (average) • PC: 116 mills/kWh (average) • Breakeven LCOE* when natural gas price is: • No Capture IGCC: $7.99/MMBtu PC: $6.15/MMBtu • With Capture IGCC: $7.73/MMBtu PC: $8.87/MMBtu * At baseline coal cost of $1.80/MMBtu 41

  42. Summary Table for All Cases 42

  43. Summary Table 43

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