By GEOFF NAIRN(Published in Renewable Energy World magazine in May 2011. Read the original here or download it.)
A generous tariff regime as well as high insolation has driven spectacular growth in concentrated solar power (CSP) deployments in southern Spain. The challenge is now to drive down costs through economies of scale and new technologies so that CSP can one day stand subsidy-free.
Concentrated solar power (CSP) uses mirrors to concentrate sunlight and generate heat and is typically used to generate electricity via a conventional steam cycle.
Unlike photovoltaic farms or wind energy — which has grown to become Spain’s third largest power source — CSP plants can cost-effectively store energy that cannot immediately be used. In Spain, which has a second demand peak in the evening, this is important. Most new CSP projects incorporate storage so they can keep generating electricity several hours after the sun has gone down, or even right through the night.
But, while CSP is more dispatchable than other renewable energy sources, it also currently costs more. So Spain is the focus for efforts to drive down costs, both through economies of scale and improvements in technologies.
‘All the CSP technologies are expensive so a lot of research seeks to reduce component costs and optimise production and installation,’ says Eduardo Zarza, head of R&D for solar concentrating systems at the Plataforma Solar de Almería (PSA), Spain’s leading solar energy research centre, which researches all four types of CSP technologies. The most mature CSP technology is the parabolic trough design, which accounts for 93% of the 2500 MW of new CSP capacity that Spain has authorised up to 2013. While the other three technologies — solar tower, Fresnel collector and Stirling dish — all have commercial potential, the financial backers of Spain’s CSP projects have opted to reduce their risks through parabolic trough’s longer track record. In the US, parabolic-trough plants date back to the 1980s.
‘With a tower system, for example, it is difficult to get project finance because noone knows how long the receiver will last,’ says Frank Dinter, head of solar at RWE, the German utility, which is investing in several Spanish renewable projects.
To benefit from Spain’s generous feed-in CSP tariff — currently 28 euro cents/kWh for 25 years — CSP plants cannot exceed 50 MW . This size limit is seen as less than optimal, given the current maturity of parabolic-trough technology, and limits potential benefits from economies of scale. Several costs in a CSP project are not proportional to its size. For example, a 200 MW turbine costs less than four times as much as a 50 MW turbine. Dinter estimates that a 200 MW plant would be about 25% cheaper per megawatt than a 50 MW plant.
RWE has a 25 percent stake in Andasol 3, a 50 MW parabolic-trough CSP plant near the Andalucian town of Guadix. The solar field at Andasol 3 consists of 7296 solar collectors arranged in eight banks of 304 parallel rows aligned north to south. Each solar collector comprises a parabolic mirror with a Dewar receiver tube running horizontally along its focal line. A hydraulic drive moves the collector rows in an arc to track the sun from east to west during the day.
Synthetic oil is pumped through the receiver tubes to absorb the sun’s heat, reaching a maximum of 393°C when it exits to the heat exchanger. There, the heat makes steam which drives a turbine and generates electricity using a conventional steam cycle.
Unlike earlier generations of parabolic-trough plant, Andasol 3 also incorporates molten-salt heat storage. When the plant is generating more heat than is needed to produce electricity, some of the hot oil is shunted off to a storage circuit, in which a second exchanger is used to heat up a nitrate salt mixture as it is pumped from a cold tank to a hot tank. To produce electricity once the sun goes down, the flows are reversed and energy is transferred back from the hot salt to the oil.
The heat stored in the 28,500 tonnes of salt can provide an additional seven hours of power at full load in summer evenings and an extra three hours in winter.
‘If we reduced the capacity we can run at 24 hours but we would only be producing 30 MW during the night,’ explains Dinter.
The price of storage has traditionally been high and it complicates the plant design, but Dinter says adding storage to Andasol 3 allows it to operate 4000 hours a year instead of just 1000 operational hours available without storage.
A drawback for parabolic-trough plants that use synthetic fluid as a transfer liquid is the relatively low working temperature of 393°C, as the fluid degrades above 400°C. However, this low temperature limits the overall steam cycle efficiency to about 38%. ‘You can boost the power block efficiency by four percentage points simply by working at higher temperatures,’ says Peter Mürau, Siemens project manager for molten salt technology.
The German engineering giant is promoting molten salt as a working fluid because its use enables plants to work at higher temperatures. Siemens is involved in a research project at the University of Evora in Portugal that will build a test facility using molten salt as the transfer medium. A 300 metre loop will be able to operate at temperatures above 500°C and will test different types of salt as the transfer liquid. A similar 5 MW demonstration plant is already operating in Sicily.
‘Molten salt has significant potential to bring down the levelised cost of electricity (LCOE),’ says Mürau. Another advantage of using molten salt both as a working fluid and for storage is that plant design is simplified as the oil-to-salt heat exchanger is not needed. Eliminating the exchanger allows the salts in the hot storage tank to reach higher temperatures than in an oil-based plant. The size of the tank can thus be reduced as less salt is needed to store a given amount of energy, leading to a cost saving of about 30% on the tank component.
But the big drawback with molten salt is that it changes phase and solidifies at about 220°C. Care has to be taken to ensure the viscosity of salt does not exceed the limits of the solar field piping during the night. ‘That is quite a challenge over a big solar field,’ admits Mürau.
Researchers are looking to develop new salts with lower freezing points but the attraction of the current mixture — 60% sodium nitrate and 40% potassium nitrate — is that the ingredients are cheap. ‘There is a lot of research into new storage materials but molten salt is currently the favourite,’ says Mürau. The existing salt mixture is also environmentally benign and — unlike synthetic oil — does not catch fire. Andasol has already suffered a fire in the solar field due to escaping oil.
Researchers at the PSA are also investigating other types of working fluids for parabolic-trough plants. Direct steam generation is one of the options that would allow parabolic plants to operate at still higher temperatures.
Using steam would also greatly simplify plant design through eliminating the main heat exchanger. More expensive receiver tubes are needed to withstand high-pressure steam but the switch to steam could reduce total plant costs by 5% and increase efficiency by up to 7%, according to a recent report on CSP from consultancy firm AT Kearney. However, the big disadvantage posed by using steam is that an efficient and high-capacity storage solution still needs to be developed.
Researchers at the PSA are also investigating using a compressed gas such as carbon dioxide or nitrogen as the working fluid, says Zarza. But plant designs would have to be radically redesigned to work with a gas instead of a liquid.
Mirrors and receiver tubes are critical components in a parabolic-trough plant and so are the subject of much innovation. The current thick-glass parabolic mirrors offer 93.5% reflectivity. By 2015, AT Kearney expects that new mirror technology could boost that figure to 95%, which translates into an increase in overall plant efficiency of 3.5%. According to the study from AT Kearney, more precise bending of the mirrors could also deliver a further 2% gain in plant efficiency for a new generation of CSP installations.
But only a few manufacturers produce mirrors and receiver tubes — just three in the latter case — and so competition in the supply of key components is currently limited. This is where linear Fresnel CSP technology offers a key advantage. Linear Fresnel plants have a much simpler and therefore cheaper solar field design than parabolic-trough installations.
Long strips of flat mirrors focus the reflected sunlight onto the solar receiver tube, through which saturated steam circulates at up to 285°C and 70 bar. As the sun moves, the mirrors rotate but the receiver tube remains fixed.
The drawback of a Fresnel plant is that it only captures 65% of the sunlight that a parabolic-trough plant can harvest. The business case for Fresnel technology therefore hinges on lower costs. ‘If a Fresnel plant costs 20% less but produces 35% less electricity than a parabolic-trough plant, it is still not competitive,’ says Zarza.
Novatec Solar, a German company, has been operating a small-scale 1.4 MW Fresnel plant — Puerto Errado 1 (PE1) — in the Murcia region of Spain since 2009. A larger 30 MW plant, called Puerto Errado 2 and majority-owned by two Swiss utilities, is being built and is due to go live in March 2012.
Martin Selig, founder of Novatec Solar, argues that while Fresnel technology is less mature, it has significant potential for cost reductions once its components are mass manufactured. Because it operates at lower temperatures, the receiver tube is much simpler than the Dewar tube technology used in parabolic-trough receivers. Similarly, the manufacture and installation of flat mirrors can more easily be automated.
As experts see linear Fresnel’s relatively low thermal efficiency — of about 26% — as a potential stumbling block to its emergence as a low-cost, low-temperature technology, Novatec is therefore planning an evolution of its technology that uses superheated steam to boost turbine cycle efficiency. This will be done by adding an additional high-temperature loop to its PE1 demonstration plant, with redesigned piping and new collectors that can handle superheated steam at 450°C.
The third significant commercial CSP technology in Spain is the solar tower, which uses a circular arrangement of ground-based heliostats to focus sunlight onto a tower-mounted receiver.
The PSA research centre has had a small-scale tower in operation for more than 25 years, although Spain’s first commercial tower plant, Abengoa’s PS10 near Seville, only started operating in 2007. The 11 MW plant has very limited storage — sufficient to ride out 30 minutes of cloud cover — and uses saturated steam as the transfer medium.
The new generation of tower technology is represented by Gemasolar, a 17 MW tower built by Torresol Energy, a joint venture between Spanish engineering firm Sener (60%) and Abu Dhabi’s Masdar (40%). Gemasolar was due to go live this spring.
Gemasolar uses molten salts both as the heat transfer medium and for storage of up to 15 hours. Although Gemasolar’s rated power is only 17 MW, it can still produce as much energy as a 50 MW parabolic-type design due to its longer hours of operation.
By using molten salts, Gemasolar works at higher temperatures than previous generations of tower plant such as the PS10. At 560°C, the efficiency of a molten-salt tower plant is about 24% higher than that of its steam-powered predecessors.
Juan Ignacio Burgaleta, head of technology at Torresol Energy, argues that one of the big advantages that a central tower design can offer over the alternatives is simpler operation and maintenance. In a parabolic-trough or Fresnel plant the transfer fluid must travel through perhaps 80 km of collector pipes before reaching the power block. In a tower plant, the transfer fluid is confined to a much smaller circuit comprising the central tower and the nearby storage system.
Researchers are already looking beyond today’s tower plants to new designs that can work at up to 800°C using ambient air as a transfer fluid. That would boost the efficiency of the plant by as much as 13%. Temperatures could be pushed even higher using new materials, but the more innovative the receiver, the more difficult it is to obtain project finance.
CSP’s fourth competing technology is Stirling dish technology, which has yet to be deployed commercially in Spain. This uses a parabolic dish to focus sunlight onto a Stirling engine and, theoretically, could offer the highest efficiencies of the four alternative approaches.
Stirling dish technology is inherently small-scale and commercial systems typically generate around 2.5 kW. That makes it more suitable for off-grid applications, although PSA’s Zarza says many dishes could be located together to create a larger grid-connected system.
Stirling technology also offers perhaps the most potential for cost reduction, by shifting manufacturing to low-cost countries and using more off-the-shelf components, for example. But Zarza says the big commercial stumbling block is the poor long-term reliability of Stirling engines, which have to withstand temperatures of up to 700°C and pressures of 150 bar.
‘At the moment the engine components suffer a lot so we are going to need new materials,’ he says.
Another big advantage of the Stirling dish is that it requires less water than other competing solar technologies. Water use can generate considerable controversy in southern Spain.
The best places to locate CSP plants tend to be arid regions with little cloud, but such environments are often subject to water restrictions. A plant such as Andasol 3 consumes 500,000 m² of water a year, mostly to condense steam, but also to clean mirrors.Investors in Novatec Solar’s PE2 plant insisted on air cooling to avoid such controversy, even though reduces the economic return.
‘Air cooling costs much more and it reduces the output by 5%-6%,’ says Selig. Opinions are nevertheless divided on this issue. RWE’s Dinter says water cooling is essential to boost the thermodynamic efficiency of the steam cycle of
parabolic-trough plants like Andasol 3 with a relatively low inlet temperature. ‘With dry cooling, you cannot reduce the outlet temperature as much as with water,’ he says.
Burgaleta of Torresol Energy says that even though the Gemasolar central tower plant works at higher temperatures, water access was not a problem, and so the designers opted for water cooling. But one of Torresol’s central tower projects planned for the future will have air cooling instead, he adds.
As Spain is now discovering, concentrating solar power is far from being a single technology, but rather embraces a wide range of designs and key technologies, each with different operating characteristics, risk profiles and trade-offs. ‘There is no clear winner,’ clarifies Siemens’ Mürau.
Even without any radical technological breakthroughs, improvements in technologies and greater economies of scale are expected to drive a 30% reduction in the cost of CSP-generated electricity in Spain by 2015. And by 2025, costs may fall as much as 50%, at which point CSP plants will finally be in a position to substitute conventional sources in Spain’s energy mix.