Thermal storage improves the dispatchability and 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 low-cost 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.

Solar Two (SII) completed successful operations in the spring of 1999 and demonstrated advanced molten-salt power tower technology. It proved that solar energy could be collected and stored on a large scale. The 10 MWe SII power plant operated over a wide range of conditions and demonstrated that electrical power could be generated and dispatched at night during peak demand periods reliably and cost effectively. The experience gained from designing and operating SII is being applied to the design of the next generation commercial Solar Power Tower, 15 MWe Solar Tres (S III) to be located near Cordoba, Spain. The S III design criteria have been developed incorporating the SII lessons learned and a conceptual design is being prepared. Design innovations impact all SIII system elements and result in: • Molten-nitrate salt thermal storage capacity for 24 hour a day of full electrical energy production. • Thermal Storage raises annual plant capacity factor from 20–22% for SII to over 60% for SIII. • Improved plant availability with a 6% improvement in overall annual plant efficiency. • Improved receiver thermal efficiency by 3%. • Significant reductions in capital and operating costs. This paper provides an overview of the technological innovations in SIII resulting from Solar II experience.

Solar hybrid power plants have a significant potential for cost reduction when the solar energy is introduced into a gas turbine system. The introduction in gas turbine systems could be realized with pressurized volumetric air receivers heating the compressed air of the gas turbine before it enters the combustor. A receiver module, consisting of a secondary concentrator and a volumetric receiver unit, was tested at the Plataforma Solar de Almería, Spain. Air exit temperatures up to 815°C and power levels of 410 kW were achieved. Total solar test time summed up to 247 h. Receiver efficiencies were in the range of 70%. A new secondary concentrator with improved efficiency was designed and built. Based on an inexpensive manufacturing technology, the secondary concentrator geometry was optimized to reduce the optical losses. Performance tests with this new secondary and a cold-water calorimeter proved the efficiency increase of about 10%. Maximum operation power was 450 kW at the exit aperture. The incidence-angle depending behaviour showed good agreement with the predictions, as well as the results of a special photographic measurement campaign. Several configurations of solar-hybrid gas turbine cycles in the low to medium power range are examined for performance and costs. The results confirm the promising potential of this technology to reach competitiveness in certain power markets: Results of a comparison between a 30 MW solar-hybrid combined cycle plant and an ISCCS power plant are presented. Future developments for system improvement and cost reduction are discussed.

California is about to complete its third year of a deregulated competitive wholesale power market. During the first two years of the competitive market, power prices averaged between 2 and 3¢/kWh. During 2000, electric supply to California was constrained a number of times causing maximum the price of power to peak over 100¢/kWh, and the average price of power to quadruple. The power output from solar plants tends to coincide with the high power demand periods in California. This fact had been demonstrated by the solar electric generating stations (SEGS) located in the California Mojave Desert, which operate under specific contracts signed in the 1980’s and early 1990’s with the local utility. This paper, on the other hand, examines how new parabolic trough solar plants would have faired on the wholesale competitive power market during 1999 and 2000.

A number of factors are creating an increased market potential for small trough power technology. These include the need for distributed power systems for rural communities worldwide, the need to generate more electricity by non-combustion renewable processes, the need for sustainable power for economic growth in developing countries, and the deregulation and privatization of the electrical generation sector worldwide. Parabolic trough collector technology has been used in large central station power plants. Organic Rankine cycle (ORC) air-cooled modular power units have been successfully applied for large and small-scale geothermal power plants, with over 600 MW of capacity, during the same period. The merging of these two technologies to produce distributed modular power plants in the 200 kW to 10 MW range offers a new application for both technologies. It is our objective in this paper to introduce a modular trough power plant (MTPP) and discuss its performance and the cost of electricity generation from such system.

The integrated solar plant concept was initially proposed by Luz Solar International [1] as a means of integrating a parabolic trough solar plant with modern combined cycle power plants. An integrated plant consists of a conventional combined cycle plant, a solar collector field, and a solar steam generator. During sunny periods, feedwater is withdrawn from the combined cycle plant heat recovery steam generator, and converted to saturated steam in the solar steam generator. The saturated steam is returned to the heat recovery steam generator, and the combined fossil and solar steam flows are superheated in the heat recovery steam generator. The increased steam flow rate provides an increase in the output of the Rankine cycle. During cloudy periods and at night, the integrated plant operates as a conventional combined cycle facility. Two studies on integrated plant designs using a General Electric Frame 7(FA) gas turbine and a three pressure heat recovery steam generator are currently being conducted by the authors. Preliminary results include the following items: 1) the most efficient use of solar thermal energy is the production of high pressure saturated steam for addition to the heat recovery steam generator; 2) the quantity of high pressure steam generation duty which can be transferred from the heat recovery steam generator to the solar steam generator is limited; thus, the maximum practical solar contribution is also reasonably well defined; 3) small annual solar thermal contributions to an integrated plant can be converted to electric energy at a higher efficiency than a solar-only parabolic trough plant, and can also raise the overall thermal-to-electric conversion efficiency in the Rankine cycle; and 4) annual solar contributions up to 12 percent in an integrated plant should offer economic advantages over a conventional solar-only parabolic trough power plant.

As interest for clean renewable electric power technologies grows, a number of parabolic trough power plants of various configurations are being considered for deployment around the globe. It is essential that plant designs be optimized for each specific application. The optimum design must consider the capital cost, operations and maintenance cost, annual generation, financial requirements, and time-of-use value of the power generated. Developers require the tools for evaluating tradeoffs between these various project elements. This paper provides an overview of a computer model that is being used by scientists and developers to evaluate the tradeoff between cost, performance, and economic parameters for parabolic trough solar power plant technologies. An example is included which shows how this model has been used for a thermal storage design optimization.

As an alternative to conventional tracking trough systems, one may use line focus Fresnel reflector systems. Before the current Australian work, each field of Fresnel reflectors was directed to a single tower. However, efficient systems of very high ground utilisation can be set up if a field of reflectors uses multiple receivers on different towers (Mills and Morrison, 1999). This paper describes an Australian line focus system, called the Compact Linear Fresnel Reflector (CLFR) system and a project to produce an initial 25MWe solar array. The array will be used as a retrofit preheater for a coal fired generating plant. Future use of such arrays as stand alone high capacity factor powerplants in New South Wales are discussed.

The availability of storage capacity plays an important role for the economic success of solar thermal power plants. For today’s parabolic trough power plants, sensible heat storage systems with operation temperatures between 300°C and 390°C can be used. A solid media sensible heat storage system is developed and will be tested in a parabolic trough test loop at PSA, Spain. A simulation tool for the analysis of the transient performance of solid media sensible heat storage systems has been implemented. The computed results show the influence of various parameters describing the storage system. While the effects of the storage material properties are limited, the selected geometry of the storage system is important. The evaluation of a storage system demands the analysis of the complete power plant and not only of the storage unit. Then the capacity of the system is defined by the electric work produced by the power plant, during a discharge process of the storage unit. The choice of the operation strategy for the storage system proves to be essential for the economic optimization.

An updraft Solar Tower power plant — sometimes also called ‘solar chimney’ — is a solar thermal power plant utilizing a combination of solar air collector and central updraft tube to generate a solar induced convective flow which drives pressure staged turbines to generate electricity. In the paper we first describe the functional principle of the Solar Tower and give some results from designing, building and operating a small scale prototype in Spain. Then future commercial Solar Tower systems like the one being planned for Australia are described. We present technical issues and basic economic data.

One of the main problems when designing a solar thermal power plant is to find the optimal parabolic trough field size. Errors made in this context can easily lead into a financial disaster. Simulation tools that handle all aspects of a power plant (technical as well as economical) treat such economical problems as a whole and can be very helpful during the design process. However, even the smartest simulation tool depends significantly on the input parameters, such as the solar irradiance. As a result of the given considerations a new method for estimating the solar field size as a function of the solar irradiance is proposed. Additionally, this paper demonstrates a path to simulate the complexity of a parabolic trough power plant.

The solar chimney is a simple renewable energy source consisting of three main components, a solar collector, chimney and turbine. Air under the collector is heated by the greenhouse effect. This less dense air rises up a chimney at the collector centre and drives an electricity-generating turbine. The operation of a solar chimney power plant is simple but high component efficiencies are needed for successful operation. A turbine design based on the design requirements for a full-scale solar chimney power plant is presented. The design integrates the turbine with the chimney. It is proposed that the chimney base legs be offset radially to act as inlet guide vanes and introduce pre-whirl before the rotor to reduce the exit kinetic energy. A three-step turbine design method is presented. A free vortex analysis method is used to determine the major turbine dimensions. A matrix throughflow method predicts the flow path through the inlet guide vanes and rotor. Finally the blade profiles are design using an optimization scheme coupled to a surface vortex method to achieve blades of minimum chord and low drag. The proposed turbine design can extract over 80% of the power available in the flow.

An overview of the market potential of various solar electric technologies considers the application to both distributed generation (DG) systems and building integrated systems. The State of California is used as an example of the analysis of system performance, economic return on investment and market penetration over the next decade. California was chosen as a test case because of recent central generation and T&D shortages. In the distributed generation context, solar energy has the potential to meet a large portion of the peak demand of California. With existing tax credits, systems are cost effective in certain locations at the present time. PV can be installed relatively quickly (weeks) on existing residential and commercial buildings with no requirements for the lengthy environmental reviews and siting problems of most power plants; therefore they are the fastest source which can be deployed in most locations in California. The approach in this article uses hourly loads derived from standard simulations. Along with the California building inventory by building type, hourly solar system simulations for standard buildings from each sector (e.g., hospitals, restaurants, schools, offices) and microeconomic calculations, returns on investment for each location and each building type are found. Finally the Bass diffusion model is used to calculate the number of solar modules that will be sold each year for the next decade. Results show that much of the output of the US photovoltaic industry could be economically dispatched in California.

Parabolic trough solar technology has over 125 plant-years of successful operation at nine commercial Solar Electric Generating Systems (SEGS) power plants that are operating near Barstow, California. These solar plants utilize conventional steam Rankine turbine-generator systems, and as a result most people associate parabolic trough solar technology with steam Rankine cycle power plants. Although these plants are clearly optimized for their particular application, other power cycle designs may be appropriate in other situations. Of particular interest is the integration of parabolic trough solar technology with combined cycle power plant technology, a configuration called the integrated solar combined cycle system (ISCCS). Four potential projects in India, Egypt, Morocco, and Mexico are considering the ISSCS configuration. This paper compares the performance, cost, and carbon emissions of ISCCS and SEGS plants with a standard combined cycle plant.

Parabolic trough power systems that utilize concentrated solar energy to generate electricity are a proven technology. Industry and laboratory research efforts are now focusing on integration of thermal energy storage as a viable means to enhance dispatchability of concentrated solar energy. One option to significantly reduce costs is to use thermocline storage systems, low-cost filler materials as the primary thermal storage medium, and molten nitrate salts as the direct heat transfer fluid. Prior thermocline evaluations and thermal cycling tests at the Sandia National Laboratories’ National Solar Thermal Test Facility identified quartzite rock and silica sand as potential filler materials. An expanded series of isothermal and thermal cycling experiments were planned and implemented to extend those studies in order to demonstrate the durability of these filler materials in molten nitrate salts over a range of operating temperatures for extended timeframes. Upon test completion, careful analyses of filler material samples, as well as the molten salt, were conducted to assess long-term durability and degradation mechanisms in these test conditions. Analysis results demonstrate that the quartzite rock and silica sand appear able to withstand the molten salt environment quite well. No significant deterioration that would impact the performance or operability of a thermocline thermal energy storage system was evident. Therefore, additional studies of the thermocline concept can continue armed with confidence that appropriate filler materials have been identified for the intended application.

Parabolic trough power plant technology is one of the most demonstrated solar power options commercially available. While trough power plants are the least expensive solar option, cost of electricity still exceeds that needed to directly compete with conventional fossil-fired large-scale central power technologies. Several evaluations have been done that identify a series of mechanisms for significant cost reduction over the next decade. One of the opportunities for improving the economics of parabolic trough plants is the development of lower cost and more efficient thermal energy storage (TES) technologies. This paper focuses on several of the TES technologies currently under development, namely: the use of an indirect molten-salt storage system, the use of molten-salt as a heat transfer fluid in the solar field and thermal energy storage system, and the development of new types of storage fluids. The assessment compares the cost and performance of these candidate thermal energy storage technologies by evaluating their impact on the levelized cost of electricity from the plant. This analysis is updated based on work conducted on these technologies during the last year.

The direct steam generation (DSG) is an attractive option regarding the economic improvement of parabolic trough technology for solar thermal electricity generation in the multi megawatt range. According to [1] and [2] a 10% reduction of the LEC is expected compared to conventional SEGS like parabolic trough power plants. The European DISS project has proven the feasibility of the DSG process under real solar conditions at pressures up to 100 bar and temperatures up to 400°C in more than 4000 operation hours [3]. In a next step the detailed engineering for a pre-commercial DSG solar thermal power plant will be performed. This detailed engineering of the collector field requires the consideration of the occurring thermohydraulic phenomena and their influence on the stability of the absorber tubes. A design tool has been developed at DLR calculating all relevant process parameters including pressure drop, temperature field and stress in the absorber tubes. The models implemented in this design tool have been validated in detail at the DISS test facility under real DSG conditions for pressures between 30 and 100 bar and inner diameters between 50 and 85 mm. The models have been implemented into a MATLAB ® program to allow for a first quick determination of critical process conditions. Once critical process conditions have been identified the FEM package ANSYS ® is used for a detailed investigation. This article summarises the models used and shows the design procedure for a DSG collector field. The design program has proven to be a reliable tool for the detailed design of DSG collector fields.

Solar hybrid fuel production from natural gas using concentrated solar thermal energy in Australia was studied, assuming that 54.6MW/(one unit of solar farm) of the concentrated solar thermal energy is used for the endothermic process of stream reforming ( s olar s team r eforming; SSR) with total solar energy conversion efficiency of 45.5% (120MW of heliostat field; one unit of solar farm). With 23 units of the solar farm, natural gas of 2516t/d can be reformed by the SSR. To ship the product fuel to Japan by existing tankers, the syngas (CO + 3H 2 ) produced by the SSR is separated into one mole of H 2 (375t/d) and the mixed gas of one mole of CO and two moles of H 2 which is converted to one mole of methanol (6000t/d) to be shipped by existing tankers. The one mole of H 2 will be used in Australia as the H 2 fuel with 25% solar share (CO 2 reduction). To improve cost barrier between oil and the methanol produced by SSR, the CO 2 zero emission process of the combined process of SSR and AT ( a uto- t hermal process) is proposed as the one whose methanol cost can be competitive with oil, when carbon tax is introduced. By shipping the methanol produced by the CO 2 zero emission process of the combined process of SSR-AT (economically feasible), we can reduce CO 2 emission by co-firing coal and methanol at coal-firing power stations in Japan. In this system, an excess H 2 fuel with solar energy is produced, and can be used in Australia.

Solar power towers can be used to make hydrogen on a large scale. Electrolyzers could be used to convert solar electricity produced by the power tower to hydrogen, but this process is relatively inefficient. Rather, efficiency can be much improved if solar heat is directly converted to hydrogen via a thermochemical process. In the research summarized here, the marriage of a high-temperature (∼1000 °C) power tower with a sulfuric acid/hybrid thermochemical cycle (SAHT) was studied. The concept combines a solar power tower, a solid-particle receiver, a particle thermal energy storage system, and a hybrid-sulfuric-acid cycle. The cycle is “hybrid” because it produces hydrogen with a combination of thermal input and an electrolyzer. This solar thermochemical plant is predicted to produce hydrogen at a much lower cost than a solar-electrolyzer plant of similar size. To date, only small lab-scale tests have been conducted to demonstrate the feasibility of a few of the subsystems and a key immediate issue is demonstration of flow stability within the solid-particle receiver. The paper describes the systems analysis that led to the favorable economic conclusions and discusses the future development path.

A solar chimney power plant consists of a large greenhouse type collector surrounding a tall chimney. The air, heated within the collector, passes through an inlet guide vane (IGV) cascade and then through a transition section to a turbine that powers a generator. The transition section contains the turbine inlet guide vanes that support the whole chimney and guides the flow entering the turbine. The primary objective of the study was to determine the loss coefficient of this section as dependent on IGV stagger angle and collector roof height. Very good agreement was found between experimental values measured in a scaled model and commercial CFD code predictions of flow angles, velocity components and internal and wall static pressures. The agreement between measured and predicted total pressure loss coefficient was reasonable. The CFD code served to extend the predictions to a proposed full-scale geometry.