Solar thermal systems need sunlight rather than the more diffuse light which can be harnessed by solar PV. A solar thermal power plant has a system of mirrors to concentrate the sunlight on to an absorber, the energy then being used to drive turbines – concentrating solar thermal power (CSP). About 2.55 GWe of CSP capacity worldwide (end of 2012), three-quarters of this in Spain, supplies a proportion of the solar electricity. More CSP is under development.
The concentrator may be a parabolic mirror trough oriented north-south, which tracks the sun’s path through the day. The absorber is located at the focal point and converts the solar radiation to heat in a fluid such as synthetic oil, which may reach 700°C. The fluid transfers heat to a secondary circuit producing steam to drive a conventional turbine and generator. Several such installations in modules of up to 80 MW are now operating. Each module requires about 50 hectares of land and needs very precise engineering and control. These plants are supplemented by a gas-fired boiler which generates about a quarter of the overall power output and keeps them warm overnight.
A simpler CSP concept is the Fresnel collector using rows of long narrow flat (or slightly curved) mirrors tracking the sun and reflecting on to one or more fixed linear receivers positioned above them. The receivers may generate steam directly.
In mid-2007 Nevada Solar One, a 64 MWe capacity solar thermal energy plant, started up. The $250 million plant is projected to produce 124 million kWh per year and covers about 160 hectares with 760 mirrored troughs that concentrate the heat from the desert sun on to pipes that contain a heat transfer fluid. This is heated to 390°C and then produces steam to drive turbines. Nine similar units totaling 354 MWe have been operating in California as the Solar Energy Generating Systems. More than twenty Spanish 50 MWe parabolic trough units including Andasol 1-3, Alvarado 1, Extresol 1-2, Ibersol and Solnova 1-3, Palma del Rio 1-2, Manchasol 1-2, Valle 1-2, commenced operation in 2008-11. Andasol, Manchasol and Valle have 7.5-hour heat storage.
Other US CSP parabolic trough projects under construction include Abengoa’s Solana in Arizona, a 280 MWe project with six-hour molten salt storage enabling power generation in the evening. It has a 778 ha solar field and started operation in 2013. The $2 billion cost is offset by a $1.45 billion loan guarantee from the US Department of Energy. Abengoa’s 280 MWe Mojave Solar Project near Barstow in California also uses parabolic troughs in a 715 ha solar field and is due on line in 2014. It has a $1.2 billion federal loan guarantee.
In 2010 California approved construction of the $6 billion, 968 MWe Blythe CSP plant by Solar Trust, the US arm of Solar Millennium at Riverside, Calif., using parabolic trough technology in four 250 MWe units occupying 28.4 sq km and funded partly by US Dept of Energy. The company has a $2.1 billion loan guarantee and a 20-year power purchase agreement with SC Edison, from 2013. However, this has now become a solar PV project, apparently due to difficulty in raising finance. Also in California, Imperial Valley (709 MWe), and Calico (663 MWe) are Stirling engine systems (see below), though the new owners of Calico are switching 563 MWe of it to PV, and Imperial Valley is re-permitting for PV. Abu Dhabi commissioned its 100 MWe Shams parabolic trough CSP plant in 2013; it cost $600 million.
Another form of this CSP is the power tower, with a set of flat mirrors (heliostats) which track the sun and focus heat on the top of a tower, heating water to make steam, or molten salt to 1000°C and using this both to store the heat and produce steam for a turbine. California’s Solar One/Two plant produced 10 MWe for a few years. An 11 MWe Spanish power tower plant PS10 has 624 mirrors, each 120 m2 and produces steam directly in the tower. A 20 MWe version PS20 is adjacent, and by 2015 Spain expects to have 2000 MWe of CSP operating. The 500 MWe Guzman CSP plant at Palma de Rio was opened in 2012. Power production in the evening can be extended fairly readily using gas combustion for heat.
The US Department of Energy awarded a $1.37 billion loan guarantee to BrightSource Energy to build the 392 MWe Ivanpah Solar Power complex in the Mojave Desert of California. It comprises three CSP Luz power towers which simply heat water to 550°C to make steam, using 300,000 heliostat mirrors in pairs each of 14 m2 per MWe, in operation from 2013 as the world’s largest CSP plant. The steam cycle uses air-cooled condensers. There is a back-up gas turbine. The company is seeking some A$ 450 million Australian government support for a similar two-tower, 250 MWe plant with gas-fired evening function in Australia. BrightSource plans a similar 500 MWe plant nearby in the Coachella Valley.
Using molten salt in the CSP system as the transfer fluid which also stores heat, enables operation into the evening, thus approximating to much of the daily load demand profile. Spain’s 20 MWe Gemasolar (formerly Solar Tres) plant has 2500 mirrors/ heliostats, each 115 m2 and molten salt storage, claiming to be the world’s first near base-load CSP plant, with 63% capacity factor. Its cost is reported to be $33,000 /kW. Spain’s 200 MWe Andasol plant also uses molten salt heat storage, as does California’s 280 MWe Solana and Nevada’s 110 MWe Crescent Dunes plant with power tower and 10-hour heat storage claimed. The salt used may be 60% sodium nitrate, 40% potassium nitrate with melting point 220°C. Andasol stores heat at 400°C and requires 75 t of salt per MW of heat. Its condensers require 5 L/kWh for cooling. Spain’s Gemasolar employs 6250 tonnes of salt. Solana uses 125,000 tonnes of salt, kept at 277°C. In Colorado the 2×100 MWe SolarReserve plant in San Luis Valley will use molten salt.
A small portable CSP unit – the Wilson Solar Grill – uses a Fresnel lens to heat lithium nitrate to 230°C so that it can cook food after dark.
Another CSP set-up is the Solar Dish Stirling System which uses reflectors to concentrate energy to drive a stirling cycle engine. A Tessera Solar plant of 709 MWe is planed at Imperial Valley in California. The system consists of a solar concentrator in a dish structure with an array of curved glass mirror facets which focus the energy on the power conversion unit’s receiver tubes containing hydrogen gas which powers a Stirling engine. Solar heat pressurizes the hydrogen to power the four-cylinder reciprocating Solar Stirling Engine and drive a generator. The hydrogen working fluid is cooled in a closed cycle. Waste heat from the engine is transferred to the ambient air via a water-filled radiator system. The stirling cycle system is as yet unproven in these large applications, however.
With solar input being both diffuse* and interrupted by night and by cloud cover, solar electric generation has a low capacity factor, typically less than 15%, though this is partly addressed by heat storage using molten salt. Power costs are two to three times that of conventional sources, which puts it within reach of being economically viable where carbon emissions from fossil fuels are priced.
Solar energy producing steam can be used to boost conventional steam-cycle power stations. In the USA the federal government has a SunShot initiative to integrate CSP with fossil fuel power plants as hybrid systems. Some $20 million is offered for two to four projects. The US Department of Energy says that 11 to 21 GWe of CSP could effectively be integrated into existing fossil fuel plants, utilizing the turbines and transmission infrastructure.
While CSP is well behind solar PV as its prices continue to fall and utilities become more familiar with PV. However, CSP can provide thermal storage and thus be dispatchable and it can provide low-cost steam for existing power plants (hybrid set up). Also, CSP has the potential to provide heating and cooling for industrial processes and desalination.