PHOTO: Solar Millennium

1 October 2008—A few weeks from now, the Andasol 1 solar thermal power plant in Andalucía, Spain, will begin charging the largest installation built expressly for storing renewable energy (other than the tried-and-true hydroelectric dam, of course). Heat from the solar thermal power station's 510 000-square-meter field of solar collectors will be stored in 28 500 tons of molten salt—enough to run the plant's 50-megawatt steam turbine for up to 7.5 hours after dark.

It's pretty strange for solar power to generate electricity in the dark. Stranger still for a renewable-energy project is the fact that Andasol 1's developers—German renewable-energy firm Solar Millennium and Madrid-based engineering and construction firm ACS/Cobra—believe the energy storage that makes the plant's output more predictable will also make it more affordable. The developers say Andasol 1's electricity will cost 11 percent less to produce than a similar plant without energy storage—dropping from 303 euros per megawatt-hour to 271 euros per MWh.

The lower cost of production is actually a by-product of Andasol 1's energy-storage system, according to Paul Nava, a managing director of Flagsol GmbH, the Cologne, Germany–based engineering subsidiary of Solar Millennium that designed the plant. Nava says storage is a means of maximizing the net energy production from each plant and thus maximizes the revenues paid under Spain's generous incentive program for renewable-energy generation. A feed-in tariff for solar thermal power pays 2.5 to 3 times the average power price for every MWh of energy generated for 25 years (though new rules will reduce the rate for future projects) but limits the capacity of qualifying facilities to 50 MW. Storage enables Andasol 1 to run its 50-MW turbine for more hours.

Nava estimates that Andasol 1 will generate 178 000 MWh of renewable electricity per year, whereas the same field of solar collectors and turbine would turn out just 117 000 MWh sans storage—a difference worth more than 24 million euros per year (US $36 million) at today's power prices.

At Andasol 1, generating this clean energy surplus starts with 24 kilometers of trough-shaped mirrors concentrating sunlight on solar collector tubes and heating the synthetic oil flowing within as high as 400 degrees Celsius (the safety and durability limit for the oil). To put power on the grid, hot oil is circulated to the plant's “power block,” where the heat is converted to steam and drives the turbine. However, when the sun is strongest, Andasol 1's oversized collector field should gather almost twice as much heat as the turbine can handle. This extra heat will be dumped into the storage system: a heat exchanger connecting two insulated storage tanks, each 14 meters high and 36 meters in diameter, holding molten potassium and sodium nitrate salt.

The tanks are kept at different temperatures. Molten salt pumped from the “cold” tank (maintained at a not-so-chilly 260 °C to keep the salt molten) into the heat exchanger picks up heat from the oil and then flows into the hot tank (which will reach 400 °C when fully charged). To discharge the stored energy, the process is reversed, with molten salt pumped from the hot tank to the cold tank to reheat the oil.

One problem with running a molten-salt storage system is that the salt could freeze during cold snaps, necessitating an injection of heat that reduces the plant's power output. But Nava says Andasol 1 has some improvements over earlier experimental designs to minimize the need to warm the salt. Andasol 1's valves are fewer in number, and both the valves and the heat exchanger are designed to drain when not in use, eliminating the need to keep them hot. The pumps, which cannot be drained regularly, sit submerged within the tanks instead of outside the tanks, where they would have to be heated separately. Nava estimates that, overall, annual energy losses from the storage system will be just 5 percent.

More such plants are on the way in Spain. Solar Millennium and its Spanish partner expect to start up a twin plant, Andasol 2, next spring and plan to begin building a third 50-MW plant early next year.

Spain's Abengoa Solar and Sener, meanwhile, are each testing solar thermal plants with integrated molten-salt storage. Both use a “power tower” configuration in which arrays of mirrors direct sunlight onto a central solar receiver where the light directly heats a molten salt. This configuration matches that of Solar Two, a 10-MW solar thermal demonstration plant at Sandia National Laboratories, in New Mexico, built in the 1990s. The power-tower design makes energy storage cheaper and more compact because the salts can be safely heated well beyond the limit of the synthetic oils.

“Using the molten salt as both the working and storage fluid gave us high heat capacity,” says Sandia concentrating solar-power program manager Thomas Mancini. “Instead of 260 °C to 390 °C, you're going from 260 °C to 560 °C. It's a bigger temperature difference, so you need less salt to store the same amount of energy.”

At present, most of the anticipated U.S. solar thermal projects, which are driven by state-level renewable-energy mandates rather than a rich feed-in tariff, are focused on minimizing upfront costs, and few projects plan to integrate energy storage. But Mancini and Nava say that may change as utilities adopt time-of-day electricity pricing.

Nava says a pricing scheme already introduced by Southern California Edison should encourage what he calls a “solar booster” thermal power plant. The California utility pays 3.28 times its base rate for electricity delivered between noon and 6 p.m. on summer weekdays. A solar booster would use an undersized collector field and storage to focus generation on that sweet spot. “In the morning, you use the solar field only to charge the storage, and then from noon on, when you have that factor of three for the electricity rate, you discharge the storage and use the field in parallel to drive the steam turbine,” says Nava.