Thermal storage improves the dispatchability a nd marketability of parabolic trough power plants allowing them to produce electricity on demand independent of solar collection. One such thermal storage system, a thermocline, uses a single tank containing a fluid with a thermal gradient running vertically through the tank, where hotter fluid (lower density) is at the top of the tank and colder fluid is at the base of the tank. The thermal gradient separates the two temperature potentials. A lowcost filler material provides the bulk of the thermal capacitance of the thermal storage, prevents convective mixing, and reduces the amount of fluid required. In this paper, development of a thermocline system that uses molten-nitrate salt as the heat transfer fluid is described and compared to a two-tank molten salt system. Results of isothermal and thermal cycling tests on candidate materials and salt safety tests are presented as well as results from a small pilot-scale (2.3 MWh) thermocline. NOMENCLATURE INTRODUCTIONThermal storage for parabolic-trough power plants

An evaluation was carried out to investigate the feasibility of utilizing a molten salt as the heat transfer fluid (HTF) and for thermal storage in a parabolic trough solar field to improve system performance and to reduce the levelized electricity cost. The operating SEGS1 plants currently use a high temperature synthetic oil consisting of a eutectic mixture of biphenyl/diphenyl oxide. The scope of this investigation included examination of known critical issues, postulating solutions or possible approaches where potential problems existed, and the quantification of performance and electricity cost using preliminary cost inputs. The two leading candidates were the so-called solar salt (a binary salt consisting of 60% NaNO3 and 40% KNO3) and a salt sold commercially as HitecXL (a ternary salt consisting of 48% Ca(NO3)2, 7% NaNO3, and 45% KNO3). Assuming a 2-tank storage system and a maximum operation temperature of 450°C, the evaluation showed that the levelized electricity cost can be reduced by 14.2% compared to a state-of-the-art parabolic trough plant, such as the SEGS plants in California. If higher temperatures are possible, the improvement may be as high as 17.6%. Thermocline salt storage systems offer even greater benefits.

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Central Receiver Systems that use large heliostat fields and solar receivers located on top of a tower are now in the position to deploy the first generation of grid-connected commercial plants. The technical feasibility of the CRS power plants technology can be valued as sufficiently mature after the pioneering experience at the early 1980s of several pilot plants in the 0.5–10 MW power range and the subsequent improvement of key components like heliostats and solar receiver in many projects merging international collaboration during the past 15 years. Solar-only plants like Solar Tres and PS10 or hybrid schemes like SOLGAS, CONSOLAR, or SOLGATE are being developed and supply a portfolio of alternatives leading to the first scaling-up plants during the period 2000–2010. Those projects with still non-optimized small sizes of 10–15 MW are already revealing a dramatic reduction of costs versus previous feasibility studies and give the path for the formulation of a realistic milestone of achieving a LEC of $0.08/kWh by the year 2010 and penetrating initial competitive markets by 2015 with LECs between $0.04/kWh–$0.06/kWh.

A thermocline tank is a low-cost thermal energy storage subsystem for concentrating solar power plants that typically utilizes molten salt and quartzite rock as storage media. Longterm thermal stability of the storage concept remains a design concern. A new model is developed to provide comprehensive simulation of thermocline tank operation at low computational cost, addressing deficiencies with previous models in the literature. The proposed model is then incorporated into a system-level model of a 100 MW e power tower plant to investigate storage performance during long-term operation. Solar irradiance data, taken from measurements for the year 1977 near Barstow, CA, are used as inputs to the simulation. The heliostat field and solar receiver are designed with DELSOL, while the transient receiver performance is simulated with SOLERGY. A meteorological year of plant simulation with a sixhour capacity for the thermocline tank storage yields an annual plant capacity factor of 0.531. The effectiveness of the thermocline tank at storing and delivering heat is sustained above 99% throughout the year, indicating that thermal stratification inside the tank is successfully maintained under realistic operating conditions. Despite its good thermal performance, structural stability of the thermocline tank remains a concern due to the large thermal expansion of the internal quartzite rock at elevated molten-salt temperatures, and requires further investigation.

Solar Two was a collaborative, cost-shared project between 11 U. S. industry and utility partners and the U. S. Department of Energy to validate molten-salt power tower technology. The Solar Two plant, located east of Barstow, CA, comprised 1926 heliostats, a receiver, a thermal storage system, a steam generation system, and steam-turbine power block. Molten nitrate salt was used as the heat transfer fluid and storage media. The steam generator powered a 10-MWe (megawatt electric), conventional Rankine cycle turbine. Solar Two operated from June 1996 to April 1999. The major objective of the test and evaluation phase of the project was to validate the technical characteristics of a molten salt power tower. This report describes the significant results from the test and evaluation activities, the operating experience of each major system, and overall plant performance. Tests were conducted to measure the power output (MW) of the each major system, the efficiencies of the heliostat, receiver, thermal storage, and electric power generation systems and the daily energy collected, daily thermal-to-electric conversion, and daily parasitic energy consumption. Also included are detailed test and evaluation reports.

An evaluation was carried out to investigate the feasibility of utilizing a molten salt as the heat transfer fluid (HTF) and for thermal storage in a parabolic trough solar field to improve system performance and to reduce the levelized electricity cost. The operating SEGS plants currently use a high temperature synthetic oil consisting of a eutectic mixture of biphenyl/diphenyl oxide. The scope of this investigation included examination of known critical issues, postulating solutions or possible approaches where potential problems existed, and the quantification of performance and electricity cost using preliminary, but reasonable, cost inputs. The two leading candidates were the so-called solar salt (a binary salt consisting of 60% NaNO3 and 40% KNO3) and a salt sold commercially as HitecXL (a ternary salt consisting of 48% Ca(NO3)2, 7% NaNO3, and 45% KNO3).

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