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Past, Present, and Future of Solar Thermal Generation

Bruce Kelly Abengoa Solar, Incorporated Berkeley, California June 2008. Past, Present, and Future of Solar Thermal Generation. Topics . Solar resource Solar thermal technologies Early projects Current projects Future plans. Solar Resource.

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Past, Present, and Future of Solar Thermal Generation

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  1. Bruce Kelly Abengoa Solar, Incorporated Berkeley, California June 2008 Past, Present, and Futureof Solar Thermal Generation

  2. Topics • Solar resource • Solar thermal technologies • Early projects • Current projects • Future plans

  3. Solar Resource • Southwest US, filtered for environmental areas, urban areas, water, and slope < 3% • 9,800 TWhe potential • 3,800 TWhe US energy consumption

  4. Parabolic Trough • Type: Glass mirror; single axis tracking; line focus • Nominal concentration: 80:1 • Heat collection fluid: Synthetic oil • Peak temperature: 393 C

  5. Central Receiver • Type: Glass mirror, two axis tracking, point focus • Nominal concentrations: 600 to 1,200:1 • Heat collection fluids: Steam, air, or nitrate salt • Peak temperatures: 400 to 850 C Photo by Mike Taylor, SEPA

  6. Linear Fresnel • Type: Glass mirror, single axis tracking, line focus • Nominal concentration: ~100:1 • Heat collection fluid: Saturated steam • Peak temperature: ~260 C Photos taken by Mike Taylor, SEPA

  7. Parabolic Trough

  8. Early projects Solar Electric Generating Stations (SEGS) SEGS I and II: 14 and 30 MWe; Daggett SEGS III through VII: 30 MWe; Kramer Junction SEGS VIII and IX: 80 MWe; Harper Lake Financed through very favorable combination of investment tax credits, Standard Offers, and PURPA requirements All are still in operation Parabolic Trough

  9. Current projects Acciona: 64 MWe Nevada Solar One Solar Millennium: 50 MWe AndaSol 1 Nevada Solar One financed through investment tax credit and renewable portfolio standard AndaSol 1 financed through Spanish feed-in tariff at ~$0.40/kWhe Parabolic trough technology investment to date ~$3,000 million Parabolic Trough

  10. Future plans Spain: 50 MWe; limited by tariff structure US: 125 to 250 MWe; economies of scale Advanced collector coolants Direct steam generation, and inorganic nitrate salt mixtures 450 to 500 C collector field temperatures More efficient Rankine cycles Why not yet? → Direct steam generation has complex controls, and salt freezes Parabolic Trough

  11. Central Receiver

  12. Early projects France, Spain, Italy, Japan, and United States 1 to 10 MWe Receiver coolants: Sodium; nitrate salt; compressed air; and water/steam Design point efficiencies were close to, but annual energy efficiencies were well below, predictions Most suffered from lack of operating funds Central Receiver

  13. Current projects Abengoa: PS10 and PS20 US DOE: Solar Two (1999) PS10 and PS20: Saturated steam receivers; high reliability, but below-commercial efficiency Solar Two: Nitrate salt receiver, thermal storage, and steam generator; high efficiency, but poor reliability Technology investment to date ~$1,000 million Central Receiver

  14. Future plans Abengoa: Superheated steam; compressed air; and nitrate salt SolarReserve: Nitrate salt in South Africa and US eSolar: 13 distributed superheated steam receivers; very small heliostats; central 30 MWe Rankine cycle BrightSource: 4 towers; small heliostats; central 100 MWe reheat Rankine cycle Central Receiver

  15. Why not yet? Superheated steam: Moderate annual efficiencies; thermal storage may be impractical Compressed air: Complex receiver; small plant sizes; thermal storage may be impractical Nitrate salt: Less than perfect operating experience; equipment development must occur at commercial scale, with ~$750 million project investment Central Receiver

  16. Performance and Cost • Annual efficiencies, capital costs, operation and maintenance costs, and levelized energy costs • Parabolic trough • Nitrate salt central receiver

  17. Parabolic Trough • Annual solar-to-electric efficiencies • 14 to 16 percent gross • 12 to 14 percent net • Capital cost • ~$4/We without thermal storage; includes project financing, interest during construction, and owner’s costs • ~$5 to $8/We with thermal storage

  18. Parabolic Trough • Operation and maintenance cost • $0.02 to $0.04/kWhe • Levelized energy costs • $0.14 to $18/kWhe with Southwest US direct normal radiation and 30 percent investment tax credit • $0.35 to $0.40/kWhe with southern Spain direct normal radiation and no financial incentives

  19. Salt Central Receiver • Annual solar-to-electric efficiencies • 17 to 19 percent gross • 15 to 17 percent net • Capital cost • ~$4/We with minimum thermal storage; includes project financing, interest during construction, and owner’s costs • ~$7/We with thermal storage at 70 percent annual capacity factor

  20. Salt Central Receiver • Operation and maintenance cost • $0.02 to $0.03/kWhe • Levelized energy cost • For a commercially mature design (which does not yet exist), a nominal 20 percent below that of a parabolic trough project

  21. Future Markets • Capital investment essentially dictated by commodity prices • Energy price parity with natural gas combined cycle plant is unlikely • Solar thermal energy is • Much better matched to utility peak demand than wind • Immune to rapid changes in plant output common with photovoltaic projects

  22. Future Markets • With 30 percent investment tax credit and property tax exemption, solar energy prices are within $0.02 to $0.03/kWhe of market price referant • Renewable portfolio standards, plus a modest carbon tax, should provide a commercial, multi-GWe market for solar thermal projects

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