High temperature molten salt storage is being increasingly used to ballast the output of thermal solar plants, and as a heat transfer fluid in some new facilities. The first of 17 projected plants of this kind has been inaugurated in Italy. Is this the way forward for concentrated solar power?


With several GW in the planning and construction stages worldwide solar power generation is on the brink of making a serious contribution to total generation capacity. Of its two forms, photovoltaic and thermal, the latter is the more familiar and therefore and more mature technology. Power plants are typically an order of magnitude greater in size and although PV doesn’t tail off so much at low insolation levels this advantage has little impact when most solar plants are being built in the sun belt to a thermal design and at sizes now getting into the 100 MW plus class. Its proportion in the general mix is therefore greater by far.

Modern thermal plants use concentrating mirrors. Concentrated solar power generation is very simple in principle – solar energy is focused by mirrors, either parabolic or flat, to vessels containing a suitable fluid that, when heated to 400°C or more can be used to create steam to drive a turbogenerator. With parabolic mirrors the vessel is a series of pipes running along the focus of the mirrors; flat mirrors reflect the heat directly to a collector in a central tower (the ‘power tower’). In at least one form of the technology that collector is a directly heated steam boiler.

The heat transfer system is usually water/steam or mineral oil/steam but can be a molten salt mixture. In the latter case if a molten salt thermal storage system is also incorporated it can be included in the primary heat transfer crcuit and save the need for a secondary heat exchanger loop. High temperature molten salt storage, a standard technology in several process industries, has several advantages and is being increasingly used to ballast the output of thermal solar plants, to provide flexibility in output, and as a heat transfer fluid in some new facilities. The first of 17 projected plants of this kind (Table 1) has been inaugurated recently.

Various ionic salts have proved to be the best choice for heat transfer fluids. Common cooking salt (NaCl) is very available and cheap but its melting point is 800°C, too high to be suitable at currently useful steam temperatures. More appropriate is a mixture of sodium and potassium nitrates, which melts at 330°C and is composed of chemicals cheaply available owing to their widespread use as fertilisers. This 60/40% mix is now regarded as the standard.

Several plants utilising molten salt storage are now under construction in Spain and the USA, although the first to come on line is in neither of those countries, but in Italy, where owners Enel inaugurated it in July this year. At 5 MW it is a small plant, only a pilot by modern standards, but it is complete in every detail and incorporates another important innovation – as well as containing storage, it is the first hybrid solar/natural gas facility.

In the next couple of years several more similar facilities including Andasol, Valle and Extresol in Spain will come on line, and soon after that another dozen or so in Spain, the USA and elsewhere in sizes up to around 300 MW. From a standing start a couple of years ago, solar plants incorporating molten salt storage account for nearly a third of all thermal projects announced in the last year.

Archimede hybrid plant inaugurated

Leading the way is Archimede, a 5 MW concentrated solar power (CSP) plant at Priolo Gargallo near Syracuse in Sicily that was inaugurated on 14 July. It is the first concentrated solar power plant to use molten salt for heat transfer and the first commercial plant to use it for storage. It is also the first plant in the world to integrate a combined cycle gas facility with a solar thermal plant, says the owner and operator, Italian utility Enel. It uses technology developed by ENEA (the Italian National Agency for New Technologies, Energy and Sustainable Economic Development) and Archimede Solar Energy, a joint venture between Angelantoni Industrie and Siemens Energy.

The plant is named for Archimedes, the most famous resident of the nearby city of Syracuse, because of its rows of huge parabolic mirrors used to capture the sun’s rays. These recall the ‘burning mirrors’ that Archimedes is reputed to have used to set fire to enemy ships blockading the then separate kingdom of Syracuse during its war with Rome, 214–212 BC.

The solar field consists of about 30 000 square metres of parabolic mirrors that concentrate sunlight onto 5400 m of pipe carrying the molten salt thermal fluid. The fluid’s working temperature is 550°C.

Solar system

The thermal energy harvested by the system produces high pressure steam that is sent to the CCGT plant’s steam turbines, reducing its consumption of fossil fuels and, as a result, enhancing its environmental performance. The solar collectors (the parabolic mirrors and pipes or receivers), together with a steam generator and two heat storage tanks – one ‘cold’ and one hot – make up the solar section of the system.

When the sun shines, the thermal fluid drawn from the cold tank is circulated through the network of collectors, where it is heated to a temperature of 550 °C and injected into the hot tank, where the thermal energy is stored. The fluid is drawn from the hot reservoir to produce steam at high pressure and temperature, which is sent to the nearby combined-cycle plant where it contributes to electricity generation. This storage system enables the plant to generate steam at any time of the day and in all weather conditions until the stored energy is depleted. The solar plant should reduce by 2100 tonnes of oil equivalent the amount of gas burned at the plant and cut annual carbon dioxide emissions by about 3250 tonnes.

Archimede also produces specialised CSP receiver tubes under license from ENEA and parabolic trough receivers for thermal power plants. It says it is the sole producer of solar receivers operating at high temperature (up to 550°C) with molten salts as the primary thermal medium. It also says that its front line product, designated HEMS08, is the most advanced solar receiver tube thanks to a revolutionary coating process and a casing kept in a vacuum.

The surface coating deposited on the tube is constituted of a thin film multilayer structure with an inferior layer of metal, reflecting in the infrared, and a superior one of non-reflecting or antireflective ceramic material. A graded ceramic-metallic material (‘CERMET’) is interposed between the two films. With this spectrally selective coating, the receiver tubes have an absorbance equal to or higher than 95%, with a design emissivity lower than 10% at 400°C and lower than 14% at 580°C. The external glass has an antireflective coating on both surfaces with a solar transmittance equal to or higher than 96.5%.

Molten salts vs oil

Molten salts work as the sole fluid for both heat absorption and storage, simplifying the plant’s design. Compared to conventional plants, a smaller thermal storage is needed to fully compensate for solar discontinuities. The entry conditions for standard turbines are matched by its higher operating temperature. And unlike oil, molten salts form an environmentally friendly, non-flammable, stable fluid, with no degradation of the receiving tube.

Currently operating parabolic trough plants use a synthetic aromatic fluid as heat transfer fluid. This fluid is organic (benzene) based and cannot reach temperatures above 400ºC with acceptable performance because it breaks down chemically at high temperatures. Above 400ºC, the fluid stops operating. This limited temperature range puts a cap on overall steam cycle efficiency.

Molten salt offers three other advantages. With a single primary fluid for storage and transfer, the storage system’s heat exchanger can be eliminated. Owing to operation at higher temperatures, the molten salt volume for the storage system can be reduced by two thirds which also leads to a reduction in size of the storage tanks with an impact on costs estimated by Archimede at 20-30%. And due to the higher operating temperature, plant efficiency can increase by up to 6%.

First large system

Construction work on Andasol 3, likely to be the first or among the first large plants of this type, is reported to be on schedule. It is being realised by Stadtwerke München, RWE Innogy, RheinEnergie and Flagsol (a joint venture of Ferrostaal and Solar Millennium) with start of operation slated for mid 2011. With its integrated thermal storage, which contains 28 500 tonnes of salt mixture, the 50 MW plant will be able to continue providing power at full load for a further 7.5 hours after sunset.

By June this year the assembly of all parabolic trough collectors had been completed: 7296 collectors together weighing over 18000 tons and carrying around 210 000 parabolic mirrors had been assembled and anchored in the 2 square kilometre solar field. Each collector unit is 12 metres long and weighs approximately 2.5 tons. The power plant block is being prepared for the delivery of the 50 MW steam turbine. During June the turbine pedestal was being completed while the 160 tonne turbine itself was undergoing final inspection at the manufacturer MAN Diesel & Turbo prior to immediate shipment. It consists of high-pressure and low-pressure modules and was especially developed and optimised for use in the Andasol facility. ‘As opposed to conventional power plants, a solar-powered turbine has to be designed to allow for being started and shut down on a daily basis, depending on the availability of steam’, said Herbert Spelleken, the project manager at Flagsol.

Andasol 3 is the third solar power plant to be developed by Solar Millennium at this location on a plateau between Granada and Almeria. Together with its nearby sister projects Andasol 1 and 2, the plant will reduce annual carbon dioxide emissions by some 450 000 tons compared to a modern coal-fired power station.


Construction of the Valle Solar Power Station started in March 2009 at San José del Valle, near Cadiz, Spain. It will consist of two adjacent similar plants with an installed capacity of 50 MW each. Both will employ ‘SENERtrough’ concentrating parabolic trough sun tracking collectors creating in each case a solar field of 510 120 square metres on a surface area of 460 hectares. Net electrical output for the installations is projected at 175 GWh/year and each plant will be able to continue to produce electricity for seven hours without sunshine as a result of its molten salt thermal storage system. The power station, owned by Torresol Energy, a company created by the Spanish firm Sener (60%) and the Abu Dhabi-based Masdar (40%), is scheduled to be operational in 2011.

Foster Wheeler has just been awarded the contract to design, supply and provide site advisory services for two sets of solar steam generators (preheaters, kettle type evaporators, superheaters and reheaters) as well as low pressure and high pressure feedwater heaters. The contract was awarded by the project’s EPC contractor, a joint venture created for the purpose by SEBER and Spain’s COBRA. Equipment delivery is scheduled for the first quarter of 2011.

With the benefit of their energy storage systems the plants are expected to operate approximately 3500 hours per year, with the potential to eliminate 95 000 tonne/year of CO2 emissions.

Solar Tres/Gemasolar

Solar Tres, a project that might have been the first commercial solar unit with molten salt storage, was originally a 15 MW pilot facility in Spain to be built by a consortium of Spanish, French, Czech Republic and US companies. It was due for completion in 2009 but the project fell behind schedule. It is now underway again with the new name of Gemasolar and a new output of 17 MW. It makes use of the Solar One and Solar Two tower power technology tested in Barstow, in California’s Mojave desert, but will be much larger and will benefit from several advances in the molten salt technology since Solar Two was designed and built.

These include a larger plant with a heliostat field three times the size of Solar Two and an improved plant availability with a 6% improvement in overall annual plant efficiency. The field will consist of 2493 glass-metal heliostats (96 m²) with higher-reflectivity glass and because of simplified design 45% reduction in manufacturing costs; a very large thermal energy storage system, storing 6250 tonne of molten nitrate salt (16 hours, 600 MWh); advanced pump designs that will pump salt directly from the storage tanks, eliminating the need for pump sumps; a steam generator system that will have a forced-recirculation steam drum; a more efficient, higher-pressure reheat turbine, and a simplified molten-salt flow loop that reduces the number of valves by 50%.

Although the turbine will be only slightly larger than that at Solar Two, the larger heliostat field and thermal storage system will enable the plant to operate 24 hours a day during summer and have an annual capacity factor of approximately 65%.

Gemasolar2006, the project company, is already funded, with an EU subsidy of 5 million Euros, and land rights and electrical connection have been secured. The site is located in Fuentes de Andalucia, near Seville, in Southern Spain. Technical development has been throughout by Sener, a Spanish company involved in various high-tech fields, and behind the Solar One and Solar Two projects.

Solana, USA

By far the biggest of the projected solar fields with storage, Abengoa’s project, variously reported at 250-280 MW, will when completed be among the largest solar plants of any kind. Perhaps this is why it has attracted so much attention from government, and was recently offered the largest of the loan guarantees ($1.45 bn) under the US DoE’s Title XVII programme. That and the incentive of the estimated 1600 new construction jobs that will result from the project, with around 80 longer termed positions at the facility; and that more than 70 % of the plant’s materials will be US-made.

The new concentrated solar power facility is to be located near Gila Bend, Arizona. Employing about 900 000 mirrors and covering 1900 acres, it will include molten salt storage equivalent to 5 hours of full operation.