Since completion of the Solar Two molten-salt power tower demonstration in 1999, the solar industry has been developing initial commercial-scale projects that are 3 to 14 times larger. Like Solar Two, these initial plants will power subcritical steam-Rankine cycles using molten salt with a temperature of 565 °C. The main question explored in this study is whether there is significant economic benefit to develop future molten-salt plants that operate at a higher receiver outlet temperature. Higher temperatures would allow the use of supercritical steam cycles that achieve an improved efficiency relative to today's subcritical cycle (~50% versus ~42%). The levelized cost of electricity (LCOE) of a 565 °C subcritical baseline plant was compared with possible future-generation plants that operate at 600 or 650 °C. The analysis suggests that ~8% reduction in LCOE can be expected by raising salt temperature to 650 °C. However, most of that benefit can be achieved by raising the temperature to only 600 °C. Several other important insights regarding possible next-generation power towers were also drawn: (1) the evaluation of receiver-tube materials that are capable of higher fluxes and temperatures, (2) suggested plant reliability improvements based on a detailed evaluation of the Solar Two experience, and (3) a thorough evaluation of analysis uncertainties.
Concentrating solar power (CSP) technologies continue to mature and are being deployed worldwide. Power towers will likely play an essential role in the future development of CSP due to their potential to provide dispatchable solar electricity at a low cost. This Power Tower Technology Roadmap has been developed by the U.S. Department of Energy (DOE) to describe the current technology, the improvement opportunities that exist for the technology, and the specific activities needed to reach the DOE programmatic target of providing competitively-priced electricity in the intermediate and baseload power markets by 2020. As a first step in developing this roadmap, a Power Tower Roadmap Workshop that included the tower industry, national laboratories, and DOE was held in March 2010. A number of technology improvement opportunities (TIOs) were identified at this workshop and separated into four categories associated with power tower subsystems: solar collector field, solar receiver, thermal energy storage, and power block/balance of plant. In this roadmap, the TIOs associated with power tower technologies are identified along with their respective impacts on the cost of delivered electricity. In addition, development timelines and estimated budgets to achieve cost reduction goals are presented. The roadmap does not present a single path for achieving these goals, but rather provides a process for evaluating a set of options from which DOE and industry can select to accelerate power tower R&D, cost reductions, and commercial deployment.
The Solar Two Project was a United States Department of Energy sponsored project operated from 1996 to 1999 to demonstrate the coupling of a solar power tower with a molten nitrate salt as a heat transfer media and for thermal storage. Over all, the Solar Two Project was very successful; however many operational challenges were encountered. In this work, the major problems encountered in operation of the Solar Two facility were evaluated and alternative technologies identified for use in a future solar power tower operating with a steam Rankine power cycle. Many of the major problems encountered can be addressed with new technologies that were not available a decade ago. These new technologies include better thermal insulation, analytical equipment, pumps and values specifically designed for molten nitrate salts, and gaskets resistant to thermal cycling and advanced equipment designs.
A study was performed to compare the annual performance of 50 MW{sub e} Andasol-like trough plants that employ either a 2-tank or a thermocline-type molten-salt thermal storage system. trnsys software was used to create the plant models and to perform the annual simulations. The annual performance of each plant was found to be nearly identical in the base-case comparison. The reason that the thermocline exhibited nearly the same performance is primarily due to the ability of many trough power blocks to operate at a temperature that is significantly below the design point. However, if temperatures close to the design point are required, the performance of the 2-tank plant would be significantly better than the thermocline.
NREL's Solar Advisor Model (SAM) is employed to estimate the current and future costs for parabolic trough and molten salt power towers in the US market. Future troughs are assumed to achieve higher field temperatures via the successful deployment of low melting-point, molten-salt heat transfer fluids by 2015-2020. Similarly, it is assumed that molten salt power towers are successfully deployed at 100MW scale over the same time period, increasing to 200MW by 2025. The levelized cost of electricity for both technologies is predicted to drop below 11 cents/kWh (assuming a 10% investment tax credit and other financial inputs outlined in the paper), making the technologies competitive in the marketplace as benchmarked by the California MPR. Both technologies can be deployed with large amounts of thermal energy storage, yielding capacity factors as high as 65% while maintaining an optimum LCOE.
Solid particle receivers have the potential to provide high-temperature heat for advanced power cycles, thermochemical processes, and thermal storage via direct particle absorption of concentrated solar energy. This paper presents two different models to evaluate the performance of these systems. One model is a detailed computational fluid dynamics model using FLUENT that includes irradiation from the concentrated solar flux, two-band re-radiation and emission within the cavity, discrete-phase particle transport and heat transfer, gas-phase convection, wall conduction, and radiative and convective heat losses. The second model is an easy-to-use and fast simulation code using Matlab that includes solar and thermal radiation exchange between the particle curtain, cavity walls, and aperture, but neglects convection. Both models were compared to unheated particle flow tests and to on-sun heating tests. Comparisons between measured and simulated particle velocities, opacity, particle volume fractions, particle temperatures, and thermal efficiencies were found to be in good agreement. Sensitivity studies were also performed with the models to identify parameters and modifications to improve the performance of the solid particle receiver.
A screening analysis was performed to identify concentrating solar power (CSP) concepts that produce hydrogen with the highest efficiency. Several CSP concepts were identified that have the potential to be much more efficient than today's low-temperature electrolysis technology. They combine a central receiver or dish with either a thermochemical cycle or high-temperature electrolyzer that operate at temperatures >600 C. The solar-to-hydrogen efficiencies of the best central receiver concepts exceed 20%, significantly better than the 14% value predicted for low-temperature electrolysis.
Power towers are capable of producing solar-generated electricity and hydrogen on a large scale. Heliostats are the most important cost element of a solar power tower plant. Since they constitute {approx} 50% of the capital cost of the plant it is important to reduce heliostat cost as much as possible to improve the economic performance of power towers. In this study we evaluate current heliostat technology and estimate a price of $126/m{sup 2} given year-2006 materials and labor costs for a deployment of {approx}600 MW of power towers per year. This 2006 price yields electricity at $0.067/kWh and hydrogen at $3.20/kg. We propose research and development that should ultimately lead to a price as low as $90/m{sup 2}, which equates to $0.056/kWh and $2.75/kg H{sup 2}. Approximately 30 heliostat and manufacturing experts from the United States, Europe, and Australia contributed to the content of this report during two separate workshops conducted at the National Solar Thermal Test Facility.
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 ({approx}1000 C) power tower with a sulfuric acid/hybrid thermochemical cycle 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.
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.
This report utilizes the results of the Solar Two project, as well as continuing technology development, to update the technical and economic status of molten-salt power towers. The report starts with an overview of power tower technology, including the progression from Solar One to the Solar Two project. This discussion is followed by a review of the Solar Two project--what was planned, what actually occurred, what was learned, and what was accomplished. The third section presents preliminary information regarding the likely configuration of the next molten-salt power tower plant. This section draws on Solar Two experience as well as results of continuing power tower development efforts conducted jointly by industry and Sandia National Laboratories. The fourth section details the expected performance and cost goals for the first commercial molten-salt power tower plant and includes a comparison of the commercial performance goals to the actual performance at Solar One and Solar Two. The final section summarizes the successes of Solar Two and the current technology development activities. The data collected from the Solar Two project suggest that the electricity cost goals established for power towers are reasonable and can be achieved with some simple design improvements.
Solar power towers, based on molten salt technology, have been the subject of extensive research and development since the late 1970s. In the mid 1980s, small experimental plants were successfully fielded in the USA and France that demonstrated the feasibility of the concept at a 1 to 2 MW{sub e} scale. Systems analyses indicate this technology will be cost competitive with coal-fired power plants after scaling-up plant size to the 100 to 200 MW{sub e} range. To help bridge the scale-up gap, a 10 MW{sub e} demonstration project known as Solar Two, was successfully operated in California, USA from 1996 to 1999. The next logical step could be to scale-up further and develop a 30 MW{sub e} project within the country of Mexico. The plant could be built by an IPP industrial consortium consisting of USA's Boeing and Bechtel Corporations, combined with Mexican industrial and financial partners. Plausible technical and financial characteristics of such a ``Solar-Two-type'' Mexican project are discussed in this paper.
Solar Two was a collaborative, cost-shared project between eleven US 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, was comprised of 1926 heliostats, a receiver, a thermal storage system and a steam generation system. Molten nitrate salt was used as the heat transfer fluid and storage media. The steam generator powered a 10 MWe, 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 paper describes the significant results from the test and evaluation activities.
This report describes the results of a six-year, $6.3 million project to reduce operation and maintenance (O&M) costs at power plants employing concentrating solar power (CSP) technology. Sandia National Laboratories teamed with KJC Operating Company to implement the O&M Improvement Program. O&M technologies developed during the course of the program were demonstrated at the 150-MW Kramer Junction solar power park located in Boron, California. Improvements were made in the following areas: (a) efficiency of solar energy collection, (b) O&M information management, (c) reliability of solar field flow loop hardware, (d) plant operating strategy, and (e) cost reduction associated with environmental issues. A 37% reduction in annual O&M costs was achieved. Based on the lessons learned, an optimum solar- field O&M plan for future CSP plants is presented. Parabolic trough solar technology is employed at Kramer Junction. However, many of the O&M improvements described in the report are also applicable to CSP plants based on solar power tower or dish/engine concepts.
SolarPACES (Solar Power and Chemical Energy Systems) is the International Energy Agency's solar thermal working group. To date, research and development activities sponsored by the group have helped reduce the cost of solar thermal systems to one-fifth that of the early pilot plants. This report presents the collective position of the SolarPACES community on solar thermal electricity-generating technology. Topics discussed include the current status of the technology and likely near-term improvements, the needs of target markets, and important technical and financial issues that must be resolved for success in near-term global markets.
At the request of US sponsors Spencer Management Associates (SMA) and Sun{diamond}Lab, China`s Center for Renewable Energy Development and former Ministry of Electric Power conducted an initial appraisal of the issues involved with developing China`s first solar thermal electric power plant in the sunbelt regions of Tibet or Xinjiang provinces. The appraisal concerns development of a large-scale, grid-connected solar trough or tower project capable of producing 30 or more megawatts of electricity. Several of the findings suggest that Tibet could be a niche market for solar thermal power because a solar plant may be the low-cost option relative to other methods of generating electricity. China has studied the concept of a solar thermal power plant for quite some time. In 1992, it completed a pre-feasibility study for a SEGS-type parabolic trough plant with the aid of Israel`s United Development Limited. Because the findings were positive, both parties agreed to conduct a full-scale feasibility study. However, due to funding constraints, the study was postponed. Most recently, Sun{diamond}Lab and SMA asked China to broaden the analysis to include tower as well as trough concepts. The findings of this most recent investigation completed i November of 1997, are the subject of this paper. The main conclusions of all studies conducted to date suggest that a region in the proximity of Lhasa, Tibet, offers the best near-term opportunity within China. The opportunities for solar thermal power plants in other regions of China were also investigated.
Several hybrid and solar-only configurations for molten-salt power towers were evaluated with a simple economic model, appropriate for screening analysis. The solar specific aspects of these plants were highlighted. In general, hybrid power towers were shown to be economically superior to solar-only plants with the same field size. Furthermore, the power-booster hybrid approach was generally preferred over the fuel-saver hybrid approach. Using today`s power tower technology, economic viability for the solar power-boost occurs at fuel costs in the neighborhood of $2.60/MBtu to $4.40/ MBtu (low heating value) depending on whether coal-based or gas-turbine-based technology is being offset. The cost Of CO[sub 2] avoidance was also calculated for solar cases in which the fossil fuel cost was too low for solar to be economically viable. The avoidance costs are competitive with other proposed methods of removing CO[sub 2] from fossil-fired power plants.
Recent experiences with the 10 MW{sub e} Solar Two and the 2.5 MW{sub t} TSA (Technology Program Solar Air Receiver) demonstration plants are reported. The heat transfer fluids used in these solar power towers are molten-nitrate salt and atmospheric air, respectively. Lessons learned and suggested technology improvements for next-generation plants are categorized according to subsystem. The next steps to be taken in the commercialization process for each these new power plant technologies is also presented.
The five Solar Electric Generating Systems (SEGS) at Kramer Junction, California, now have nearly 30 years of cumulative operating experience. These 30 MW plants employ parabolic trough technology originally deployed by LUZ International in the late 1980`s and are now managed, operated and maintained by the Kramer Junction Company. In this paper, Sandia National Laboratories performed an analysis of the annual energy production from the five plants. Annual solar-to-electric conversion efficiencies are calculated and the major factors that influenced the results are presented. The generally good efficiencies are primarily attributed to the excellent equipment availabilities achieved at all plants.
A SEGS LS-2 parabolic trough solar collector was tested to determine the collector efficiency and thermal losses with two types of receiver selective coatings, combined with three different receiver configurations: glass envelope with either vacuum or air in the receiver annulus, and glass envelope removed from the receiver. As expected, collector performance was significantly affected by each variation in receiver configuration. Performance decreased when the cermet selective coating was changed to a black chrome coating, and progressively degraded as air was introduced into the vacuum annulus, and again when the glass envelope was removed from the receiver. For each receiver configuration, performance equations were derived relating collector efficiency and thermal losses to the operating temperature. For the bare receiver (no glass envelope) efficiency and thermal losses are shown as a function of wind speed. An incident angle modifier equation was also developed for each receiver case. Finally, equations were derived showing collector performance as a function of input insolation value, incident angle, and operating temperature. Results from the experiments were compared with predictions from a one-dimensional analytical model of the solar receiver. Differences between the model and experiment were generally within the band of experimental uncertainty.
This paper summarizes the results of a study performed by the US and Germany to assess the technical and economic potential of central receiver power plants and to identify the necessary research and development (R&D) activities required to reach demonstration and commercialization. Second generation power plant designs, employing molten-salt and volumetric-air receivers, were assessed at the size of 30 and 100 MWe. The study developed a common guideline and used data from previous system tests and studies. The levelized-energy costs for the second generation plants were estimated and found to be competitive with costs from fossil-fueled power plants. Potential for further cost reductions exists if technical improvements can be introduced successfully in the long term. Additionally, the study presents results of plant reliability and uncertainty analyses. Mid- and long-term technical potentials are described, as well as recommendations for the R&D activities needed to reach the goal of large-scale commercialization. The results of this study have already helped direct research in the US and Europe. For example, the favorable potential for these technologies has led to the Solar Two molten-salt project in the US and the TSA volumetric receiver test in Spain. In addition, early analysis conducted within this study indicated that an advanced thermal storage medium was necessary to achieve favorable economics for the air plant. This led to the design of the thermal storage system currently being tested in Spain. In summary, each of the investigated receiver technologies has mid- and long-term potential for improving plant performance and reducing capital and energy costs (resulting in less than 10 cts/kWh given excellent insolation conditions) in an environmentally safe way and largely independent of fossil-fuel prices.
This paper presents the results of a reliability analysis for a solar central receiver power plant that employs a salt-in-tube receiver. Because reliability data for a number of critical plant components have only recently been collected, this is the first time a credible analysis can be performed. This type of power plant will be built by a consortium of western US utilities led by the Southern California Edison Company. The 10 MW plant is known as Solar Two and is scheduled to be on-line in 1994. It is a prototype which should lead to the construction of 100 MW commercial-scale plants by the year 2000. The availability calculation was performed with the UNIRAM computer code. The analysis predicted a forced outage rate of 5.4% and an overall plant availability, including scheduled outages, of 91%. The code also identified the most important contributors to plant unavailability. Control system failures were identified as the most important cause of forced outages. Receiver problems were rated second with turbine outages third. The overall plant availability of 91% exceeds the goal identified by the US utility study. This paper discuses the availability calculation and presents evidence why the 91% availability is a credible estimate. 16 refs.
A control algorithm is proposed for a molten-salt solar central receiver in a cylindrical configuration. The algorithm simultaneously regulates the receiver outlet temperature and limits thermal-fatigue damage of the receiver tubes to acceptable levels. The algorithm is similar to one that was successfully tested for a receiver in a cavity configuration at the Central Receiver Test Facility in 1988. Due to the differences in the way solar flux is introduced on the receivers during cloud-induced transients, the cylindrical receiver will be somewhat more difficult to control than the cavity receiver. However, simulations of a proposed cylindrical receiver at the Solar Two power plant have indicated that automatic control during severe cloud transients is feasible. This paper also provides important insights regarding receiver design and lifetime as well as a strategy for reducing the power consumed by the molten-salt pumps.
The 10-MW{sub e} Solar One Pilot Plant was the world's largest solar central receiver power plant. During its power production years it delivered over 37,000 MWhrs (net) to the utility grid. In this type of electric power generating plant, large sun-tracking mirrors called heliostats reflect and concentrate sunlight onto a receiver mounted on top a of a tower. The receiver transforms the solar energy into thermal energy that heats water, turning it into superheated steam that drives a turbine to generate electricity. The Solar One Pilot Plant successfully demonstrated the feasibility of generating electricity with a solar central receiver power plant. During the initial 2 years the plant was tested and 4 years the plant was operated as a power plant, a great deal of data was collected relating to the efficiency and reliability of the plant's various systems. This paper summarizes these statistics and compares them to goals developed by the US Department of Energy. Based on this comparison, improvements in the design and operation of future central receiver plants are recommended. Research at Sandia National Laboratories and the US utility industry suggests that the next generation of central receiver power plants will use a molten salt heat transfer fluid rather than water/steam. Sandia has recently completed the development of the hardware needed in a molten salt power plant. Use of this new technology is expected to solve many of the performance problems encountered at Solar One. Projections for the energy costs from these future central receiver plants are also presented. For reference, these projections are compared to the current energy costs from the SEGS parabolic trough plants now operating in Southern California.
The Direct Absorption Receiver (DAR) concept was proposed in the mid-1970s as an alternative advanced receiver concept to simplify and reduce the cost of solar central receiver systems. Rather than flowing through tubes exposed to the concentrated solar flux, the heat absorbing fluid (molten nitrate salt) would flow in a thin film down a flat, nearly vertical panel and absorb the flux directly. Potential advantages of the DAR over conventional tubular designs include a substantially simplified design, improved thermal performance, increased reliability and operating life, as well as reduced capital and operating costs. However, before commercial-scale designs can be realized, a method for controlling droplet ejection from the panel must be developed. In this paper, we present a new DAR design, which has the potential to control these droplets. The design employs four flat panels that are sloped backwards 5 degrees, wind spoilers, and air curtains. A systems analysis is presented indicating that the levelized-energy cost of the quad geometry should be very similar to cylindrical geometry that was originally proposed for the DAR concept. 19 refs., 5 figs., 3 tabs.
The Solar One Pilot Plant successfully demonstrated the feasibility of solar central receiver power plants. During its operating years much data were collected regarding the efficiency and availability of the various plant systems. This paper summarizes these statistics and compares them to goals developed by the Department of Energy. Based on this comparison, design and operation improvements are recommended so that future central receiver plants can more closely attain these goals. 9 refs., 4 figs., 1 tab.
Solar One is the world's largest central receiver power plant. During the last 4 years the plant availability was 80%, 83%, and 96%, respectively, during hours of sunshine. This reliability is considered to be excellent considering the plant is a first-of-a-kind facility and because it has been subjected to daily cyclic service. In this paper we present the frequencies and causes of the plant outages that occurred. The ten most important causes comprised 72% of the total outage time. Qualitative insights related to the cause and mitigation of these ten are provided. The information presented in this paper will be useful to studies aimed at improving the reliability of future solar central receiver power plants. It is also useful to members of the utility industry who are considering investing in this technology or are considering cyclic operation of conventional power plants. 4 refs., 3 figs.