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Revision 2 – November 2010 Revision 1 – August 2007 Original – May 2007

Cost and Performance Baseline for Fossil Energy Plants – Volume 1 Bituminous Coal and Natural Gas to Electricity. Revision 2 – November 2010 Revision 1 – August 2007 Original – May 2007. U.S. Department of Energy National Energy Technology Laboratory. Disclaimer

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Revision 2 – November 2010 Revision 1 – August 2007 Original – May 2007

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  1. Cost and Performance Baseline for Fossil Energy Plants – Volume 1Bituminous Coal and Natural Gas to Electricity Revision 2 – November 2010 Revision 1 – August 2007 Original – May 2007 U.S. Department of Energy 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.

  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 in the near term • Provides baseline costs and performance • Compare existing technologies • Guide R&D for advancing technologies within the FE Program

  4. Study Matrix GEE – GE Energy CoP – Conoco Phillips

  5. Design Basis: Coal Type

  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

  7. Economic Assumptions First Year of Capital Expenditure 2007 Effective Levelization Period (Years) 35 (PC & IGCC) 33 (NGCC) Dollars 2007 Coal ($/MM Btu) 1.64 Natural Gas ($/MM Btu) 6.55 Capacity Factor IGCC 80 PC/NGCC 85

  8. Technical Approach Systems Analyses Categorization STUDY CATEGORY • Order of Magnitude Estimate (+/- >50% Accuracy) • Very little project-specific definition • Rough scaling of previous related but dissimilar analyses • “Back-of-the-envelope” analyses • Concept Screening (+/- 50% Accuracy) • Preliminary mass and energy balances • Modeling and simulation of major unit operations • Factored estimate based on previous similar analyses • Budget Estimate (+30% / -15% Accuracy) • Thorough mass and energy balances • Detailed process and economic modeling • Estimate based on vendor quotes, third-party EPC firms

  9. 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 WorleyParsons Vendor sources where available • Follow DOE Analysis Guidelines

  10. 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 syngascooler) • 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 4,000 feet and monitored for 80 years • CO2 transport, storage and monitoring (TS&M) costs were included in the levelized cost of electricity (COE)

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

  12. Current TechnologyIGCC Power Plant without CO2 Capture 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

  13. Gasifiers GEE Texaco Gasifier ConocoPhillips E-Gas Shell SCGP Fuel Gas HP Steam O2 Dry Coal Slag

  14. IGCC Power Plant With CO2 Capture

  15. Current TechnologyIGCC Power Plant with CO2Capture • 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 < 6 ppmv H2S in syngas • Claus plant with tail gas recycle for ~99.8% overall sulfur recovery • Hg: Activated carbon beds for ~95% removal • Advanced F-Class CC Turbine:232 MWe • Steam Conditions:1800 psig/1000°F/1000°F

  16. Water-Gas Shift Reactor System • Design: • Sulfur Tolerant Catalyst • Up to 98.5% CO Conversion • 2 stages for GE and Shell, 3 stages for E-Gas • H2O/CO = 1.8 – 2.25 (to achieve 90% CO2 capture) Steam Steam 400oF 700-870oF 800psia 550oF H2O + CO CO2 + H2 1 Recovered from Heat Integration

  17. 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

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

  19. IGCC Economic Results 1Total Plant Capital Cost (Includes contingencies and engineering fees but not owner’s costs) 280% Capacity Factor

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

  21. 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

  22. 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/1050°F

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

  24. PC and NGCC Economic Results 1Total Plant Capital Cost (Includes contingencies and engineering fees but not owner’s costs) 285% Capacity Factor

  25. Environmental Performance Comparison IGCC, PC and NGCC

  26. Criteria Pollutant Emissions for All Cases

  27. CO2 Emissions for All Cases

  28. Raw Water Withdrawal and Consumption Comparison IGCC, PC and NGCC

  29. Raw Water Withdrawal and Consumption per MWnet(Absolute)

  30. Economic Results for All Cases

  31. CO2 Avoided Costs

  32. Plant Cost Comparison

  33. Cost of Electricity Comparison Coal cost $1.64/106Btu,Gas cost $6.55/106Btu

  34. Highlights

  35. 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

  36. 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 Overnight Cost: IGCC ~25% higher than PC • NGCC: $718/kW • PC: $2010/kW (average) • IGCC: $2505/kW (average) • Total Overnight Cost with Capture: PC > IGCC • NGCC: $1497/kW • IGCC: $3568/kW (average) • PC: $3590/kW (average)

  37. Results HighlightsCOE ($2007) • COE: NGCC & PC lowest cost generators • NGCC: 59 $/MWh • PC: 59 $/MWh (average) • IGCC: 77 $/MWh (average) • With CCS: PC lowest coal-based option • NGCC: 86 $/MWh • PC: 108 $/MWh (average) • IGCC: 112 $/MWh (average) • Breakeven FY COE* when natural gas price is: • No Capture IGCC: $9.24/MMBtu PC: $6.59/MMBtu • With Capture IGCC: $9.80/MMBtu PC: $9.34/MMBtu * At baseline coal cost of $1.64/MMBtu

  38. Summary Table for All Cases

  39. Summary Table

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