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The small solar thermal power plant is being developed with funding from EU Horizon 2020 Program. The plant is configured around a 2-kWel Organic Rankine Cycle turbine and solar field, made of Fresnel mirrors. The solar field is used to heat thermal oil to the temperature of about 240 oC. This thermal energy is used to run the Organic Rankine Cycle turbine and the heat rejected in its condenser (about 18-kWth) is utilized for hot water production and living space heating. The plant is equipped with a latent heat thermal storage to extend its operation by about 4 hours during the evening building occupancy period. The phase change material used is Solar salt with the melting/solidification point at about 220 oC. The total mass of the PCM is about 3,800 kg and the thermal storage capacity is about 100 kWh. The operation of the plant is monitored by a central controller unit. The main components of the plant are being manufactured and laboratory tested with the aim to assemble the plant at the demonstration site, located in Catalonia, Spain. At the first stage of investigations the ORC turbine will be directly integrated with the solar filed to evaluate their joint performance. During the second stage of tests, the Latent Heat Thermal Storage will be incorporated into the plant and its performance during the charging and discharging processes will be investigated. It is planned that the continuous filed tests of the whole plant will be performed during the 2018- 2019 period. This study was funded by European Union’s Horizon 2020 Research and Innovation Program under Project Grant Agreement 723596 (Innova MicroSolar).

The design of the Latent Heat Thermal Storage System (LHTESS) was developed with thermal capacity of about 100 kWh as a part of small solar plant, based on the Organic Rankine Cycle (ORC). The phase change material (PCM) used is Solar salt with the melting/solidification temperature of about 220°C. Thermo-physical properties of the PCM were measured, including its phase transition temperature, heat of fusion, specific heat and thermal conductivity. The design of the thermal storage was finalized by means of the 3-D CFD analysis. The thermal storage system is made of six rectangular boxes with dimensions of 1 m (width) × 0.66 m (height) × 0.47 m (depth). The thermal energy is delivered to each of the thermal storage boxes with the use of thermal oil, heated by Fresnel mirrors. The heat is transferred into and from the PCM in the box using 40 bi-directional heat pipes with the external diameter of about 12 mm. The length of the heat pipe in the PCM box is 430 mm and it is placed in the cylindrical metallic protection cartridge, installed in the thermal storage vessel. The working fluid in the heat pipe is water. A set of metallic screens are installed in the box with the pitch of 8–10 mm to enhance the heat transfer from heat pipes to the PCM and vice-versa during the charging and discharging processes, which take about 4 hours. The one unit of the described thermal storage system is undergoing the laboratory tests. Preliminary results demonstrate that the performance of the thermal storage is in a good agreement with numerical predictions. After completion of final design modifications, all units will be assembled at the plant’s demonstration site and tested with the ORC turbine.

The articles in this special issue focus on solar power generation, including new technologies, services, and applications.

The last two years have seen a tremendous increase in the number of installed solar energy systems. In 2010, annual grid-connected photovoltaic (PV) installations in the United States and worldwide were expected to be about 0.8 GW and 16–18 GW, respectively. At the end of 2010, the cumulative installed base of grid-connected PVs in the United States and worldwide was about 2 GW and about 40 GW, respectively. One of the areas that has been receiving much attention recently is large utility-scale solar systems.

The SunShot Vision Study defines a scenario for solar energy technologies to significantly contribute to meeting U.S. electricity demand. To achieve this, work is in progress to identify, quantify, and address the impacts of high levels of distributed PV generation on electric distribution systems. The Department of Energy (DOE) Solar Energy Technologies Program (SETP) initiated a project to gain experience and to identify and quantify these potential impacts, develop and verify models of these systems, evaluate methods for mitigating any impacts, and develop potential solutions. This paper summarizes the current progress of the six competitively selected projects.

In January of 2003, the Florida Department of Environmental Protection/Florida Energy Office (DEP/FEO) allocated $600,000 in hardware funds toward the installation of photovoltaic (PV) solar systems on Florida schools. As a result of this program, grid-connected PV systems less than six kilowatts in size were installed on 29 schools in the State of Florida. The Florida Solar Energy Center (FSEC) has monitored these systems for approximately one year of operation. The performance of 28 of these systems was analyzed using standard performance parameters such as the performance ratio, PV array efficiency, inverter efficiency, and PV system efficiency. In addition, a life-cycle cost analysis was conducted using new cost data values and updated market assumptions. These data will serve as a benchmark to compare against future systems with respect to performance vs. installed system cost.Copyright © 2006 by ASME

The Florida Solar Energy Center (FSEC) has partnered with Sandia National Laboratories (SNL), the Southwest Technical Development Institute (SWTDI), and the California Energy Commissions Public Interest Energy Research (CEC PIER) in an effort to characterize the performance of PV inverters operating over extended periods of time. As part of this characterization, SNL executed an initial performance characterization in the laboratory to be repeated at one or two year intervals. These inverters were then sent distributed to the above test facilities for installation and long-term testing. To perform this long-term testing, FSEC built an inverter test facility made up of a configurable 10.1 kW PV array and four test beds. Each test bed was set up to monitor the following parameters: DC voltage, DC current, AC Voltage, AC Power and inverter temperature. Solar irradiance, ambient temperature, and several PV array temperatures were recorded by a separate, synchronized datalogger. Three inverters are currently being tested: the Fronius IG 3000, the Xantrex GT 3.0, and the SMA Sunny Boy 2500U. The three inverters were loaded with a PV array close to the maximum power limit allowed by the inverter, and the array power supplied to each inverter was within 100 W of one another. Since the PV array for each inverter used identical PV modules mounted in the same orientation, it was easier to develop a model to compare inverter performance based on energy output. In addition to energy output, other parameters were obtained such as inverter efficiency. An attempt was made to compare the results obtained at FSEC to those results compiled by the California Energy Commission.Copyright © 2006 by ASME

This analysis expands the photovoltaic (PV) life cycle cost (LCC) results presented at ASES 2004. That paper presented the model and concept used to develop PV LCC, and it showed the results of the analysis of over one hundred systems monitored by the Florida Solar Energy Center (FSEC). FSEC began tracking cost, performance and reliability data for systems installed in Florida in 1998, with data now available through a web-accessible database. For the majority of the 124 systems, installed cost information was collected as part of the state’s PV rebate and PV for schools programs. Results presented previously [1] indicated that over an assumed 20–30 system life time a PV system will have a positive life cycle cost. That is, a negative total return on investment. These results were based on actual cost, performance, maintenance, and reliability data. In the baseline case, average total system costs over the lifetime were 32.4¢/kWh while electricity savings totaled 3.7¢/kWh netting a life cycle cost of 28.7¢/kWh. While based on actual data from over 100 installed systems — some installed for over 6 years — a number of conservative assumptions also drove the analysis, such as the exclusion of the state’s rebate programs (varying from $2 to $5 per DC Watt) which impacted nearly all of the systems in the analysis. Since the first presentation of these results the PV LCC model has been further developed to incorporate additional performance information and expands the sample of systems incorporated. This paper will thus provide further insight into the relative importance of various up-front and on-going costs to the overall lifetime economics of a system. The paper will also address additional sensitivity analysis performed. Particular attention is paid to inverter mean time between failure (MTBF), the impact of incentives, and basic financial assumptions used in the model such as the discount rate and electricity rates. Various scenarios are considered in asking the question of what is necessary for the system LCC to break-even.Copyright © 2005 by ASME

The field of photovoltaics has undergone dramatic growth over the past few years. This growth has been accompanied by two significant changes in the commercial photovoltaic (PV) market. 1.The major PV market has shifted from the residential and commercial building markets to central station utility power markets. With this switch has come a new focus on the long-term reliability and durability of PV modules and systems. If you are installing tens or even hundreds of megawatts of PV modules, it is absolutely necessary to ensure that they will continue to perform adequately throughout their expected lifetime of at least 25 years. 2.Selling prices for PV modules have decreased from more than $4 per watt to less than $1 per watt in the last 5 years. This reduction in selling process has been driven by low-cost production in the developing world. This means that most of today's PV modules are being manufactured by companies that did not exist 10 or, in many cases, even 5 years ago. Yet the modules must carry 25-year warranties and are expected to survive at least that long without having the benefit of long-term field experience.