Nexant Parabolic Trough Solar Power Plant Systems Analysis; Task 1: Preferred Plant Size, 20 January 2005 - 31 December 2005

Technical Report · Sat Jul 01 04:00:00 EDT 2006

DOI:https://doi.org/10.2172/887340· OSTI ID:887340

Kelly, B

The Rankine cycles for commercial parabolic trough solar projects range in capacity from 13.5 MWe at the Solar Electric Generating Station I (SEGS I) plant, to a maximum of 89 MWe at the SEGS VIII/IX plants. The series of SEGS projects showed a consistent reduction in the levelized energy cost due to a combination of improvements in collector field technology and economies of scale in both the Rankine cycle and the operation and maintenance costs. Nonetheless, the question of the optimum Rankine cycle capacity remains an open issue. The capacities of the SEGS VIII/IX plants were limited by Federal Energy Regulatory Commission and Public Utility Regulatory Policy Act requirements to a maximum net output of 80 MWe. Further improvements in the Rankine cycle efficiency, and economies of scale in both the capital and the operating cost, should be available at larger plant sizes. An analysis was conducted to determine the effect of Rankine cycle capacities greater than 80 MWe on the levelized energy cost. The study was conducted through the following steps: (1) Three gross cycle capacities of 88 MWe, 165 MWe, and 220 MWe were selected. (2) Three Rankine cycle models were developed using the GateCycle program. The models were based on single reheat turbine cycles, with main steam conditions of 1,450 lb{sub f}/in{sup 2} and 703 F, and reheat steam conditions of 239 lb{sub f}/in{sup 2} and 703 F. The feedwater heater system consisted of 5 closed heaters and 1 open deaerating heater. The design condenser pressure was 2.5 in. HgA. (3) The optimization function within Excelergy was used to determine the preferred solar multiple for each plant. Two cases were considered for each plant: (a) a solar-only project without thermal storage, and (b) a solar-fossil hybrid project, with 3 hours of thermal storage and a heat transport fluid heater fired by natural gas. (4) For each of the 6 cases, collector field geometries, heat transport fluid pressure losses, and heat transport pump power requirements were calculated with a field piping optimization model. (5) Annual electric energy outputs, capital costs, and annual operating costs were calculated for each case using the default methods within Excelergy, from which estimates of the levelized energy costs were developed. The plant with the lowest energy cost was considered the optimum.

• Research Organization: National Renewable Energy Laboratory (NREL), Golden, CO.
• Sponsoring Organization: USDOE
• DOE Contract Number: AC36-99GO10337
• OSTI ID: 887340
• Report Number(s): NREL/SR-550-40162; LDC-5-55014-01
• Country of Publication: United States
• Language: English

Related Subjects

03 NATURAL GAS
14 SOLAR ENERGY
25 ENERGY STORAGE
CAPACITY
CAPITALIZED COST
CONCENTRATING SOLAR POWER
DESIGN
EFFICIENCY
ENERGY ACCOUNTING
FEEDWATER HEATERS
HEAT STORAGE
MAINTENANCE
NATURAL GAS
OPERATING COST
OPTIMIZATION
RANKINE CYCLE
SOLAR
SOLAR PARABOLIC TROUGH
SOLAR POWER PLANTS
SOLAR THERMAL ELECTRICITY
STEAM
SYSTEMS ANALYSIS
Solar Energy - Thermal
TURBINES
US FERC