Thermal storage is the ace up CSP's sleeve. The ability to store the sun's energy means concentrating solar plants can generate power 24 hours a day or when demand for electricity is highest. Conversely, solar PV and wind farms grind to a halt once the sun stops shining or the wind stops blowing.
The benefits are clear. But the business case is not always as apparent given the high cost of thermal energy storage (TES) technologies. As a result, many of the CSP projects in the United States do not include TES. But this may change as the share of solar power in the grid increases and utilities demand a more stable, predictable power supply from power producers.
Several existing large-scale storage systems already use molten salt, a mixture of sodium and potassium nitrate, to store solar energy.
The first molten salt thermal storage system was installed in the Andasol 1 50MW parabolic trough plant in southern Spain, which came online at the end of 2008.
Andasol 2 (in start-up phase) and Andasol 3 (currently in construction) also include thermal storage systems with 7.5 hours' of thermal storage.
The Andasol plants use a two-tank indirect system where the secondary heat transfer fluid is heated in solar receiver then transferred to salt for storage. The process has almost doubled the plant's operational hours, says Sven Moormann, spokesperson for Solar Millennium, the plant developer.
The first commercial plant in the world with a central tower receiver using molten salt technology is the 50MW Gemasolar plant being developed by Torresol Energy. The storage will produce around 63 percent more hours of power than a conventional plant.
Given the additional costs of the storage equipment (19 percent of the total project cost) and of building a larger solar field to accumulate the excess energy during the day (the solar field accounts for 43 percent of total costs), the cost-benefit is roughly even, says Santiago Arias, chief infrastructures officer, Torresol Energy.
"The major advantage is the plant's availability and manageability," he says.
In the US, Abengoa Solar is building Solana, a 280MW solar trough plant in Arizona with thermal storage using molten salts.
Developer, SolarReserve has also filed an application to build a 150MW solar power tower plant with seven hours' of salt storage in California. The proposed Rice Solar Energy Project will use technology built by Rocketdyne that was tested at the 10MW Solar Two demonstration project near Barstow, California in the 1990s.
In this two-tank system, molten salt is used for both thermal transfer and storage, which means direct thermal storage is possible and oil-to-salt and salt-back-to-oil heat exchangers can be eliminated.
Most of the projects operating in the United States, however, do not have thermal storage. This is because to date, the economics haven't added up.
Studies conducted by engineering consultancy WorleyParsons have shown that the cost of electricity is more expensive if storage is included. "Thermal storage costs have risen significantly from earlier estimates," says Kelly Beninga, renewable energy director at WorleyParsons. Beninga says the costs can range from an additional US$50 (€35; £31) to US$125 (€87; £77) per kW-hr.
Given these costs, storage only becomes viable when there is time-of-day pricing (where a premium is paid for power during peak-demand periods), or where utilities provide capacity credits (additional payment for guaranteeing generation during certain times of the day), says Beninga. "If the cost of electricity is flat 24 hours a day, there isn't much reason to have thermal storage."
Beninga also argues the widespread use of storage in Spain is driven by artificial market factors. He explains that the 50MW limit placed on Spain's renewable projects motivates power producers to store excess energy.
"If there was no limitation in Spain, I think all those plants would be 250 MW plants without storage," he says.
The business case also depends on the quality of solar radiation and characteristics of electricity demand. As Moormann at Solar Millennium points out, companies are building plants without storage in California because there is more reliable solar radiation than in Spain, and because utilities don't need to stabilise power production 24-hours a day.
But as the proportion of renewable energy in the grid increases, Benigna expects storage to become a critical factor. "If a utility only buys 1 per cent of solar power, then it doesn't care when it is generated. But if that increases to 20 per cent then utilities will start demanding greater predictability and manageability," he says.
Speaking to CSP Today in November, Fred Morse, senior US advisor to Abengoa, similarly noted that he expects to see an increasing number of utilities requiring thermal storage in the future.
In the meantime, a number of research projects are underway to reduce the costs of thermal storage technology in order to support its cost effectiveness.
Sandia National Laboratories (SNL), for example, has demonstrated a 2.5-MWhr plant using a single tank thermocline storage system.
This uses a single tank for storing both the hot and cold fluid and significantly lowers the cost of storage by replacing some of the salt with a low-cost quartzite rock and sand filler. SNL currently awaits funding to build a full-scale demonstration unit.
The German Aerospace Centre (DLR) is also examining the use of solid, thermal energy storage media such as high-temperature concrete or castable ceramic materials. Phase-change materials could also allow large amounts of energy to be stored in relatively small volumes.
As research such as this continues, the business case for thermal storage could soon become indisputable.