Solar thermal power plants that produce hotter steam can capture more solar energy. That’s why Siemens is exploring an upgrade for solar thermal technology to push its temperature limit 160 °C higher than current designs. The idea is to expand the use of molten salts, which many plants already use to store extra heat. If the idea proves viable, it will boost the plants’ steam temperature up to 540 °C—the maximum temperature that steam turbines can take.

Siemens’s new solar thermal plant design, like all large solar thermal power plants now operating, captures solar heat via trough-shaped rows of parabolic mirrors that focus sunlight on steel collector tubes. The design’s Achilles’ heel is the synthetic oil that flows through the tubes and conveys captured heat to the plants’ centralized generators: the synthetic oil breaks down above 390 °C, capping the plants’ design temperature.

Startups such as BrightSource, eSolar, and SolarReserve propose to evade synthetic oil’s temperature cap by building so-called power tower plants, which use fields of mirrors to focus sunlight on a central tower.  But Siemens hopes to upgrade the trough design, swapping in heat-stable molten salt to collect heat from the troughs. The resulting design should not only be more efficient than today’s existing trough-based plants, but also cheaper to build. “A logical next step is to just replace the oil with salt,” says Peter Mürau, Siemens’s molten salt technology program manager.

The German engineering giant will actually be the second player to try to push molten salts through solar collector tubes. Last summer, the Italian utility Enel began running molten salt through a field of about 30,000 square meters of trough mirrors adjacent to its natural gas-fired power plant near Syracuse, Sicily. The salt exits the 5.4-kilometers of collector pipe at 565 °C, boosting the power plant’s output by 5 percent.

Enel’s plant uses collector tubes from Italy’s Archimede Solar Energy, the only producer of collector tubes designed to handle molten salts. Their collector tubes use a heat-stable metalloceramic coating to maximize heat absorption, as well as thicker titanium-stabilized steel pipes to resist bending at high temperatures. Paolo Martini, Archimede’s business development director, says the plant is operating well. Enel plans to build a 30-megawatt plant in Sicily.

Since 2009, Siemens has amassed a 45 percent stake in Archimede, but it has opted to go back to pilot-scale to optimize the molten-salt concept before offering commercial-scale plants to global clients. “We are convinced the technology itself will work. But a lot of work needs to be done to optimize the economics,” says Mürau.

Siemens is building a molten-salt pilot plant on the grounds of the University of Evora in Portugal. The plant should be operating by early next year. The plant—part of a German research consortium including salt and chemicals giant K+S AG and the German Aerospace Center—will be used to drive down energy losses associated with both the highest and lowest temperatures that a commercial plant will experience.

At the high end, the losses come from heat that’s captured by the collector tubes and then dissipated before it can be delivered to the plant’s turbines. “The heat loss is an exponential curve, and it climbs very steeply at the higher temperatures,” explains Mürau. Siemens will seek to achieve the highest temperatures possible without going so high that these losses outweigh the gains from the hotter steam.

The low-end challenge stems from molten salt’s high freezing point. The mixture of molten potassium and sodium nitrate used in heat storage systems and in Enel’s demo plant freezes when it cools below 220 °C. Freezing is easy to prevent in centralized energy storage tanks, but presents a serious risk in kilometer-long stretches of collector tube. To counter the freezing threat, Enel’s plant maintains the salt in its tubes above 290 °C, using considerable heat that could otherwise be used to generate power. Mürau says Siemens is looking for a salt formulation with a 150 °C or lower freezing point, which would mean they’d have to use much less heat to prevent the tubes from freezing.

If Siemens’s efforts succeed, trough plants heating molten salt could reduce the cost of power generation by more than 10 percent compared to an oil plant, according to Mürau. (Estimates of current solar thermal costs vary between 13 to 20 cents per kilowatt-hour, which is still significantly higher than power generated by fossil fuels.) The cost reduction comes from both a several-percent increase in generation from turbines running on hotter steam, and a lower cost of construction.

However, some experts argue that the risk of freezing could still be a deal-killer for commercializing molten-salt-based plants. Thomas Mancini, program manager for Sandia National Laboratory’s concentrating solar-power program, says he remains “skeptical” of using molten salts in collector tubes given the inherent freezing threat. Mancini says that even at 100 °C (the temperature that boils water), there would be a significant risk of freezing.

But others in the industry are warming to molten salt’s potential. In January, for example, Colorado-based SkyFuel kicked off a $4.3-million R&D effort, supported by the U.S. Department of Energy, to scale up its metallic film-based trough mirrors for use with high-temperature collector tubes.