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High altitude CSP: Molten salts or mineral oil HTF?
CSP Today investigates whether high altitude, low temperature conditions favour certain CSP technolo
By Susan Kraemer, US correspondent
Some of the best insolation in the world near populated regions is in the thinner atmosphere of high deserts that plunge well below 0°C in winter. The excellent insolation of California’s high desert in the Mojave is 2,000 feet up, and temperatures can fall to around -17°C in winter.
Similarly, China’s best solar potential is at high altitudes. “The only regions in China with adequate insolation lie in the high western deserts which are generally above 3,000 feet in elevation”, confirms Bill Gould, the Chief Technical Officer of SolarReserve.
During a recent interview, SolarReserve's Senior Vice President Tom Georgis suggested that solar tower projects using molten salt as the heat transfer fluid are better suited to cold climate, high altitude operation than traditional parabolic trough plants with oil as the HTF, despite thermal oil’s much lower freezing point.
Both solar tower and parabolic trough technologies with storage can deliver power on demand. Most parabolic trough configurations use mineral oil as the heat transfer fluid (HTF) within the receivers - an HTF with a freezing point of 12°C.
So how is it that a solar tower configuration using molten salt heat transfer fluids with a freezing point of 100° - 230°C, such as Torresol’s Gemasolar plant in Spain and SolarReserve’s Tonopah plant in Nevada, would be better suited to low temperature conditions?
The answer lies in the different geometries of the two types of plants, explains Gould. “In a tower configuration, the salt piping consists of only 200 yards from the ground to the top of the receiver, two hundred yards back down to the salt tanks, and about another 200 yards from the tanks to the steam generators and back” he says. All of this is protected from winter winds by being housed within the tower.
Torresol Energy Technical Director of Operation and Maintenance Santiago Arias, agrees. "It is because we do not have any liquids in the solar field" he said. "The salt fluids remain in a very reduced space, are well-controlled and have a huge thermal inertia. It is not likely that the freezing point is achieved, mainly because the area exposed is very limited. The salts remain at 260°-565°C. The external temperature variations have, proportionally, low effect on the energy lost".
Troughs, on the other hand, require about a mile of trough collector piping per megawatt of electrical output. “A 250MWe plant like Abengoa’s Solana plant has about 250 miles of trough collector piping out of doors and is prone to enormous heat losses during winter nighttimes”, notes Gould.
However, several independent experts point out that while both tower and trough technologies have much to offer, the relative exposure of thermal oil in miles of parabolic trough plants in cold climates has so far not been an issue.
Dr. Eckhart Lupfert at CSP Services (a spin-off from Germany's DLR) who provides engineering consulting for both solar technologies and has worked with the parabolic trough technologies for twenty years, says he has never heard the cold climate issue flagged as a problem.
He says that while the degree of freeze protection varies, insulation is needed in both cases - whether indoors with a high freezing point, or outdoors, with a low one. “The molten salt freezes at 230°C. The oil freezes at about 12° -20°C. So the temperatures that we have during night, winter, or standby in winter is below the freeze points of both these systems anyhow.”
Since temperatures in high altitude regions falls well below the freezing points of either molten salts or HTF, insulation is key in both tower and trough plants. “Both technologies need some kind of freeze protection. The only difference is the amount of energy required. So it is a badly used argument”, he adds.
“Use of oil-HTFs in colder climates should not be considered a serious concern”, agrees Mark Mehos, who leads the High Temperature Solar Thermal team at the U.S. National Renewable Energy Laboratory (NREL).
“While receiver tubes used in parabolic trough plants have a relatively small diameter, heat loss is very low due to the use of low IR emissive coatings combined with an evacuated space around the receiver.” These are between 70-90 mm (21/2 to 31/2 inches) in diameter, and a special absorber coating absorbs incoming sunlight and minimizes the emission of infrared radiation.
“The freezing point of the oil HTF is about 12°C, so anything below that point presents some risk”, concedes Craig Turchi, Senior engineer in the same program at NREL. “However, the piping is well insulated and plants circulate the fluid during the night to avoid potential cold spots. As long as the fluid is kept circulating there is little risk of freezing” he adds, saying that the risk is only for localized cold spots due to damaged insulation or lack of flow.
Using NREL’s System Advisor Model, Turchi modeled potential heat loss from a hypothetical plant in chilly Fargo, North Dakota (as a worst case scenario). Referring tot he graphic, top right, he found that during a week with temperatures below 0°C (the purple line) with a run of sunless and cloudy days (shown in green) the HTF (Blue=cold header, Red=hot header) remained above the 12°C freezing point.
To keep the oil temperature within an operating range, effective freeze protection is used, says Conrad Gamble of Solutia, which has manufactured the thermal oil typically used in trough projects since the 1980’s. To prevent the pipe from falling below a set point temperature, a heat tracer, using pressurized steam passed through small-diameter tubing, can be strapped to the pipe under the insulation to cheaply and easily maintain a much higher temperature.
Not only can insulation issues be overcome, but there are many other issues that go into choosing one technology over another, said Georg Brakmann, Managing Director of Fichtner Solar GmbH, the German CSP consultancy. Economics is one of the most important.
Banks, he said, are simply more likely to lend to a proven technology. Trough-based CSP was first patented in Stuttgart in 1907, and proven by the Luz SEGS parabolic trough project operating commercially since the '80s in California. Using the same technology in all these years, it has the advantage in having demonstrated profitability at utility scale.
Dr. Lupfert echoes this sentiment: “The most important issue is the financing. If you want to get a hundred million dollars from the bank, they will ask you if you have ever done that before.”
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