Modern ways for concentrating solar power(CSP)

ABSTRACT Advanced and This essay is a summary of modern ways for concentrating alternative solar power, within this essay all types of CSP will be discussed. Things like their main components, costs and energy performance will be discussed. Finally, a little forecast and systems conclusions about it will be implied. (302.064)

Eric Martínez Lara

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Contents

Introduction ...... 3 Different types of CSP (concentrating solar power) ...... 5 parabolic trough collector technology ...... 5 linear fresnel plants ...... 10 solar dish systems ...... 13 power tower solar plants ...... 18 Thermal Storage Systems for Concentrating Solar Power ...... 22 forecast and conclusions ...... 26 Figure list ...... 31 References list ...... 32

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Introduction

The origin of this kind of power production comes from a legend, this legend explain that Archimedes using a "burning glass" concentrated sunlight on the invading Roman fleet and repelled them from Syracuse. Then, in 1973 a Greek scientist, Dr. Ioannis Sakkas, which was curious about whether Archimedes could have destroyed the Roman fleet in 212 BC, put near of 60 Greek sailors holding oblong mirrors tipped to catch the sun's rays and direct them at a target plywood silhouette 160 feet away. This ship caught fire after few minutes.

Figure 1: Ioannis Sakkas experiment

On the other hand, in 1866, Auguste Mouchout used a parabolic trough to produce steam for the first solar steam engine. Then, the first patent for solar collector was obtained by the Italian Alessandro Battaglia, in the same year. Over the following years, inventors such as John Ericsson and Frank Shuman developed concentrating solar-powered devices for irrigation, refrigeration and locomotion.

Then, in 1968, Professor Giovanni Francia designed and built the first concentrated- solar plant. This plant had the architecture of today's concentrated-solar plants with a solar receiver in the center of a field of solar collectors. This plant was able to produce 1 MW with a superheated steam of 100 bar and 500 degrees Celsius. The next development came in 1981, in Southern California, it was a Solar One power tower of 10MW. But the parabolic-trough technology of the nearby Solar Energy Generating Systems, begun in 1984, which was more workable.

Concentrated solar power (also called concentrating solar power, concentrated solar thermal, and CSP) are systems which use mirrors or lenses to concentrate a large area onto a small area. This concentrated light is converted to heat, which drives a heat

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Figure 2: CSP example

The innovative aspect of CSP is that it captures and concentrates the sun’s energy to provide the heat required to generate electricity, rather than using fossil fuels or nuclear reactions. Another attribute of CSP plants is that they can be equipped with a heat storage system in order to generate electricity even when the sky is cloudy or after sunset. This significantly increases the CSP capacity factor compared with solar photovoltaics and, more importantly, enables the production of dispatchable electricity, which can facilitate both grid integration and economic competitiveness. CSP technologies therefore benefit from advances in solar concentrator and thermal storage technologies, while other components of the CSP plants are based on rather mature technologies and cannot expect to see rapid cost reductions.

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Different types of CSP (concentrating solar power)

CSP plants can be divided into two different groups, based on whether the solar collectors concentrate the sun rays along a focal line or on a single focal point (with much higher concentration factors). Line-focusing systems include parabolic trough and linear Fresnel plants and have single-axis tracking systems. Point-focusing systems include solar dish systems and solar tower plants and include two-axis tracking systems to concentrate the power of the sun.

The next step will be to intensely present, one by one, all systems that I have mentioned above.

Line-focusing systems

parabolic trough collector technology

The parabolic trough collectors (PTC) consist of solar collectors (mirrors), heat receivers and support structures. The parabolic-shaped mirrors are constructed by forming a sheet of reflective material into a parabolic shape that concentrates incoming sunlight onto a central receiver tube at the focal line of the collector. The arrays of mirrors can be 100 metres (m) long or more, with the curved aperture of 5 m to 6 m. A single-axis tracking mechanism is used to orient both solar collectors and heat receivers toward the sun (A.T. Kearney and ESTELA, 2010). PTC are usually aligned North-South and track the sun as it moves from East to West to maximize the collection of energy. The receiver comprises the absorber tube (usually metal) inside an evacuated glass envelope. The absorber tube is generally a coated stainless steel tube, with a spectrally selective coating that absorbs the solar (short wave) irradiation well, but emits very little infrared (long wave) radiation. This helps to reduce heat loss. Evacuated glass tubes are used because they help to reduce heat losses.

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Figure 3: Solar/Rankine parabolic trough system schematic

Components of a Parabolic trough solar collector

The basic component of a parabolic trough solar field is the solar collector assembly or SCA. A solar field consists of hundreds or potentially thousands of solar collector assemblies. Each solar collector assembly is an independently tracking, parabolic trough solar collector composed of the following subsystems:

Concentrator Structure

Mirrors or reflectors

Linear receiver or heat collection element

Collector balance of system

Also, each parabolic trough solar collector assembly consists of multiple, torque-tube or truss assemblies (often referred to as solar collector elements or modules).

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Concentrator Structure

The structural skeleton of the parabolic trough solar collector is the concentrator structure. The concentrator structure:

Supports the mirrors and receivers, maintaining them in optical alignment

Withstands external forces, such as wind

Allows the collector to rotate, so the mirrors and receiver can track the sun.

Mirrors or Reflectors

The most obvious object within the parabolic trough solar collector are its parabolic- shaped mirrors or reflectors. Those mirrors are curved in the shape of a parabola, which allows them to concentrate the sun's direct beam radiation on the linear receiver.

All current parabolic trough power plants use glass mirror panels manufactured by Flabeg. The mirrors are second-surface silvered glass mirrors (which means that the reflective silver layer is on the backside of the glass). The glass is a 4-milimeter-thick, special low iron or white glass with a high transmittance. The mirrors have a solar- weighted specular reflectivity of about 93.5%. A special multilayer paint coating protects the silver on the back of the mirror. And each mirror panel is approximately 2 square meters in area.

The glass mirror panels have performed very well during the operation of the SEGS (solar electric generating system) power plants. They've maintained high reflectivity and suffer low annual breakage rates. However, mirror breakage does occur and replacements have been relatively expensive. A number of alternative mirror concepts have been under development to reduce cost, improve reliability, or increase performance.

Linear Receiver or Heat Collection Element

The parabolic trough linear receiver, also called a heat collection element (HCE), is one of the primary reasons for the high efficiency of the original Luz parabolic trough collector design.

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The receiver is a 4-meter-long, 70-mm diameter stainless steel tube with a special solar-selective absorber surface, surrounded by an anti-reflective evacuated 115-mm diameter glass tube. Located at the mirror focal line of the parabola, the receiver heats a special heat transfer fluid as it circulates through the receiver tube.

The receiver has glass-to-metal seals and metal bellows to accommodate for differing thermal expansions between the steel tubing and the glass envelop. They also help achieve the necessary vacuum-tight enclosure.

The vacuum-tight enclosure primarily serves to significantly reduce heat losses at high- operating temperatures. It also protects the solar-selective absorber surface from oxidation.

The selective coating on the steel tube has good solar absorptance and a low thermal emittance for reducing thermal radiation losses. The glass cylinder features an anti- reflective coating to maximize the solar transmittance. Getters—metallic compounds designed to absorb gas molecules—are installed in the vacuum space to absorb hydrogen and other gases that permeate into the vacuum annulus over time.

The original Luz receiver design suffered from poor reliability of the glass-to-metal seal. Solel Solar Systems and Schott Glass have developed newer designs that have substantially improved:

Receiver reliability

Optical and thermal performance

The lifetime of receivers.

Collector Balance of System

The localize controller for a LS-2 parabolic trough solar collector assembly communicates with a computer in a central control building.

A number of other key components make up the balance of system in the parabolic trough solar field, including pylons and foundations, drive, controls and collector interconnect

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Performance and cost discussion

Plant Performance

Increasing the performance of the solar collectors and power plant are one of the primary opportunities for reducing the cost of trough technology. Collector performance improvements can come from developing new more efficient collector technologies and components but often also by improving the reliability and lifetime of existing components.

The year 2000 technology shows a 20% improvement in net solar to electric efficiency over the 1997 baseline system performance. This is achieved by using current technologies and designs, by reducing HCE heat losses and electric parasitic. New HCEs have an improved selective surface with a higher absorptance and a 50% lower emittance. This helps reduce trough receiver heat losses by one third.

The 2005 technology shows a 7% increase in efficiency primarily as a result of adding thermal storage. Thermal storage eliminates dumping of solar energy during power plant start-up and during peak solar conditions when solar field thermal delivery is greater than power plant capacity. Thermal storage also allows the power plant to operate independently of the solar field. This allows the power plant to operate near full load efficiency more often, improving the annual average power block efficiency. The thermal storage system is assumed to have an 85% round-trip efficiency. Minor performance improvements also result from scaling the plant up to 160 MW from 80 MW. Annual net solar-to-electric efficiency increases to 13.8% [1].

The 2010 technology shows a 6% increase in net solar-to-electric efficiency primarily due to the use of the tilted collector. Power plant efficiency improves slightly due to larger size of the 320 MW power plant. Thermal storage has been increased to 10 hours and the solar field size increased to allow the plant to operate up to a 50% annual capacity factor. As a result, more solar energy must be stored before it can be used to generate electricity, thus the 85% round-trip efficiency of the thermal storage system tends to have a larger impact on annual plant performance. The resulting annual net solar-to-electric efficiency increases to 14.6%. The 2020 and 2030 technologies show 5% and 10% improvements in performance over the 2010 trough technology.

Cost Reductions

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The technology shows a 30% cost reduction on a €/kW basis and a 55% reduction on a €/m2 basis. These cost reductions are due to: larger plants being built, increased collector production volumes, building projects in solar power park developments, and savings through competitive bidding. In general, the per kW capital cost of power plants decreases as the size of the plant increases. For trough plants, a 49% reduction in the power block equipment cost results by increasing the power plant size from 30 to 320 MW. The increased production volume of trough solar collectors, as a result of larger solar fields and multiple plants being built in the same year, reduces trough collector costs by 44%. Power parks allow for efficiencies in construction and cost reduction through competitive bidding of multiple projects. A 10% cost reduction is assumed for competitive bidding in later projects.

O&M costs show a reduction of almost 80%. This large cost reduction is achieved through increasing size of the power plant, increasing the annual solar capacity factor, operating plants in a solar power park environment, and continued improvements in O&M efficiencies. Larger plants reduce operator labor costs because approximately the same number of people are required to operate a 320 MW plant as are required for a 30 MW plant. The solar power park assumes that five plants are co-located and operated by the same company resulting in a 25% O&M savings through reduced overhead and improved labor and material efficiencies. In addition, about one third of the cost reduction is assumed to occur because of improved O&M efficiency resulting from improved plant design and O&M practices based on the results of the KJC O&M Cost Reduction Study [4]. linear fresnel plants

Linear Fresnel collectors (LFCs) are similar to parabolic trough collectors, but use a series of long flat, or slightly curved, mirrors placed at different angles to concentrate the sunlight on either side of a fixed receiver (located several meters above the primary mirror field). Each line of mirrors is equipped with a single-axis tracking system and is optimized individually to ensure that sunlight is always concentrated on the fixed receiver. The receiver consists of a long, selectively-coated absorber tube.

Unlike parabolic trough collectors, the focal line of Fresnel collectors is distorted by astigmatism. This requires a mirror above the tube (a secondary reflector) to refocus the rays missing the tube, or several parallel tubes forming a multi-tube receiver that is wide enough to capture most of the focused sunlight without a secondary reflector.

The main advantages of linear Fresnel CSP systems compared to parabolic trough systems are that:

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• LFCs can use cheaper flat glass mirrors, which are a standard mass-produced commodity; • LFCs require less steel and concrete, as the metal support structure is lighter. This also makes the assembly process easier; • The wind loads on LFCs are smaller, resulting in better structural stability, reduced optical losses and less mirror-glass breakage; and. • The mirror surface per receiver is higher in LFCs than in PTCs, which is important, given that the receiver is the most expensive component in both PTC and in LFCs.

These advantages need to be balanced against the fact that the optical efficiency of LFC solar fields (referring to direct solar irradiation on the cumulated mirror aperture) is lower than that of PTC solar fields due to the geometric properties of LFCs. The problem is that the receiver is fixed and in the morning and afternoon cosine losses are high compared to PTC. Despite these drawbacks, the relative simplicity of the LFC system means that it may be cheaper to manufacture and install than PTC CSP plants.

However, it remains to be seen if costs per kWh are lower. Additionally, given that LFCs are generally proposed to use direct steam generation, adding thermal energy storage is likely to be more expensive.

Components of Linear Fresnel reflector plant

Reflectors

The reflectors are located at the base of the system and converge the sun’s rays into the absorber. A key component that makes all LFR’s more advantageous than traditional parabolic trough mirror systems is the use of "Fresnel reflectors". These reflectors make use of the Fresnel lens effect, which allows for a concentrating mirror with a large aperture and short focal length while simultaneously reducing the volume of material required for the reflector. This greatly reduces the system’s cost since sagged-glass parabolic reflectors are typically very expensive. [2] However, in recent years thin-film nanotechnology has significantly reduced the cost of parabolic mirrors. [5]

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A major challenge that must be addressed in any solar concentrating technology is the changing intensity of the incident rays (the rays of sunlight striking the mirrors) as the sun progresses throughout the day. The reflectors of a CLFR are typically aligned in a north-south orientation and turn about a single axis using a computer controlled solar tracker system. This allows the system to maintain the proper angle of incidence between the sun’s rays and the mirrors, thereby optimizing energy transfer.

Absorbers

The absorber is located at the focal point of the mirrors. It runs parallel to and above the reflector segments to transport radiation into some working thermal fluid. The basic design of the absorber for the CLFR system is an inverted air cavity with a glass cover enclosing insulated steam tubes, shown in Figure 4. This design has been demonstrated to be simple and cost effective with good optical and thermal performance.

Figure 4: Incident solar rays are concentrated on insulated steam tubes to heat working thermal fluid

Figure 5: LFR solar systems alternate the inclination of their mirrors to focus solar energy on multiple absorbers, improving system efficiency and reducing overall cost.

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For optimum performance of the LFR, several design factors of the absorber must be optimized.

• First, heat transfer between the absorber and the thermal fluid must be maximized. [1] This relies on the surface of the steam tubes being selective. A selective surface optimizes the ratio of energy absorbed to energy emitted. Acceptable surfaces generally absorb 96% of incident radiation while emitting only 7% through infra-red radiation. [7] Electro-chemically deposited black chrome is generally used for its ample performance and ability to withstand high temperatures. [1] • Second, the absorber must be designed so that the temperature distribution across the selective surface is uniform. Non-uniform temperature distribution leads to accelerated degradation of the surface. Typically, a uniform temperature of 300 °C (573 K; 572 °F) is desired. Uniform distributions are obtained by changing absorber parameters such as the thickness of insulation above the plate, the size of the aperture of the absorber and the shape and depth of the air cavity.

Point-focusing systems solar dish systems

The dish/engine system is a concentrating solar power (CSP) technology that produces relatively small amounts of electricity compared to other CSP technologies—typically in the range of 3 to 25 kilowatts. Dish/engine systems use a parabolic dish of mirrors to direct and concentrate sunlight onto a central engine that produces electricity. The two major parts of the system are the solar concentrator and the power conversion unit.

Figure 6: Solar dish System

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Components of solar dish systems

Solar Concentrator

The solar concentrator, or dish, gathers the solar energy coming directly from the sun. The resulting beam of concentrated sunlight is reflected onto a thermal receiver that collects the solar heat. The dish is mounted on a structure that tracks the sun continuously throughout the day to reflect the highest percentage of sunlight possible onto the thermal receiver.

Concentrators use a reflective surface of aluminum or silver, deposited on glass or plastic. The most durable reflective surfaces have been silver/glass mirrors, similar to decorative mirrors used in the home. Attempts to develop low-cost reflective polymer films have had limited success. Because dish concentrators have short focal lengths, relatively thinglass mirrors (thickness of approximately 1 mm) are required to accommodate the required curvatures. In addition, glass with a low-iron content is desirable to improve reflectance. Depending on the thickness and iron content, silvered solar mirrors have solar reflectance values in the range of 90 to 94%.

The ideal concentrator shape is a paraboloid of revolution. Some solar concentrators approximate this shape with multiple, spherically-shaped mirrors supported with a truss structure . An innovation in solar concentrator design is the use of stretched- membranes in which a thin reflective membrane is stretched across a rim or hoop. A second membrane is used to close off the space behind. A partial vacuum is drawn in this space, bringing the reflective membrane into an approximately spherical shape. Figure 2 is a schematic of a dish/Stirling system that utilizes this concept.

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Figure 7: Schematic of a dish/engine system with stretched-membrane mirrors

Power Conversion Unit

The power conversion unit includes the thermal receiver and the engine/generator. The thermal receiver is the interface between the dish and the engine/generator. It absorbs the concentrated beams of solar energy, converts them to heat, and transfers the heat to the engine/generator. A thermal receiver can be a bank of tubes with a cooling fluid—usually hydrogen or helium—that typically is the heat-transfer medium and also the working fluid for an engine. Alternate thermal receivers are heat pipes, where the boiling and condensing of an intermediate fluid transfers the heat to the engine.

Figure 8: Schematic which shows the operation of a heat-pipe solar receiver. Eric Martinez Lara 15

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The engine/generator system is the subsystem that takes the heat from the thermal receiver and uses it to produce electricity. The most common type of heat engine used in dish/engine systems is the Stirling engine. A Stirling engine uses the heated fluid to move pistons and create mechanical power. The mechanical work, in the form of the rotation of the engine's crankshaft, drives a generator and produces electrical power.

Figure 9: Schematic showing the principle of operation of a Stirling engine

Performance and cost discussion

The base-year technology (1997) is represented by the 25 kW dish-Stirling system developed by McDonnell Douglas in the mid 1980s. Southern California Edison Company operated a MDA system on a daily basis from 1986 through 1988. During its last year of operation, it achieved an annual efficiency of 12% despite significant unavailability caused by spare part delivery delays. This annual efficiency is better than what has been achieved by all other solar electric systems, including photovoltaic's, Eric Martinez Lara 16

302.064 - Advanced and alternative energy systems Modern ways for concentrat ing solar energy solar thermal troughs, and power towers, operating anywhere in the world [11,12]. The base-year peak and daily performance of near-term technology are assumed to be that of the MDA systems. System costs assume construction of eight units. Operation and maintenance (O&M) costs are of the prototype demonstration and accordingly reflect the problems experienced.

Performance for 2005 is largely based on one of the solarizable engines being commercialized for a non-solar application. Use of a production level engine will have a significant impact on engine cost as well as overall system cost. This milestone will help trigger a fledgling dish/engine industry. A production rate of 2,000 modules per year is assumed. Achieving a high production rate is key to reducing component costs, especially for the solar concentrator.

Performance for years 2010 and beyond is based on the introduction of the heat-pipe solar receiver. Heat-pipe solar receiver development is currently being supported by SunLab in collaboration with industrial partners. The use of a heat-pipe receiver has already demonstrated performance improvements of well over 10% for the STM 4-120 compared to a direct-illumination receiver [10]. While additional improvements in mirror, receiver, and/or engine technology are not unreasonable expectations, they have not been included. This is, therefore, a conservative scenario. A production rate of 30,000 modules per year is assumed. By 2010 dish/engine technology is assumed to be approaching maturity. A typical plant may include several hundred to over a thousand systems. It is envisioned that a city located in the U.S. Southwest would have several 1 to 50 MWe installations located primarily in its suburbs. A central distribution and support facility could service many installations. In the table, a typical plant is assumed to be 30 MW e.

Production levels for 2020 and 2030 are 50,000 and 60,000 modules per year, respectively. No major advances beyond the introduction of heat pipes in the 2010 time frame are assumed for 2020-2030. However, evolutionary improvements in mirror, receiver, and/or engine designs have been assumed. This is a reasonable assumption for a $2 billion/year, dish/engine industry, especially one leveraged by a larger automotive industry. The system costs are therefore 20 to 25% less than projected by MDA and SAIC at the assumed production levels. The MDA and SAIC estimates are for their current designs and do not include the benefits of a heat-pipe receiver. In addition, the MDA engine costs are for an engine that is being manufactured primarily for solar applications. Advanced concepts (e.g., volumetric Stirling receivers) and/or materials, which could improve annual efficiency by an

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302.064 - Advanced and alternative energy systems Modern ways for concentrat ing solar energy additional 10%, have not been included in the cost projections. With these improvements installed costs of less than $1,000/kWe are not unrealistic.

power tower solar plants

In power tower concentrating solar power systems, numerous large, flat, sun-tracking mirrors, known as heliostats , focus sunlight onto a receiver at the top of a tall tower. A heat-transfer fluid heated in the receiver is used to generate steam, which, in turn, is used in a conventional turbine generator to produce electricity. Some power towers use water/steam as the heat-transfer fluid. Other advanced designs are experimenting with molten nitrate salt because of its superior heat-transfer and energy-storage capabilities. Individual commercial plants can be sized to produce up to 200 megawatts of electricity.

Figure 10: power tower solar plant Two large-scale power tower demonstration projects have been deployed in the United States. During its operation from 1982 to 1988, the 10-megawatt Solar One plant near Barstow, California, demonstrated the viability of power towers by producing more than 38 million kilowatt-hours of electricity.

The Solar Two plant was a retrofit of Solar One to demonstrate the advantages of molten salt for heat transfer and thermal storage. Using its highly efficient molten-salt energy storage system, Solar Two successfully demonstrated efficient collection of solar energy and dispatch of electricity. It also demonstrated the ability to routinely produce electricity during cloudy weather and at night. In one demonstration, Solar

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Two delivered power to the grid 24 hours a day for almost 7 consecutive days before cloudy weather interrupted operation.

Spain has several power tower systems. Planta Solar 10 and Planta Solar 20 are water/steam systems with capacities of 11 and 20 megawatts, respectively. Solar Tres will produce some 15 megawatts of electricity and have the capacity for molten-salt thermal storage.

The dispatchability of electricity from a molten-salt power tower is illustrated in Figure 2, which shows the load dispatching capability for a typical day in Southern California. The figure shows solar intensity, energy stored in the hot tank, and electric power output as functions of time of day. In this example, the solar plant begins collecting thermal energy soon after sunrise and stores it in the hot tank, accumulating energy in the tank throughout the day. In response to a peak-load demand on the grid, the turbine is brought on line at 1:00 PM and continues to generate power until 11 PM. Because of the storage, power output from the turbine generator remains constant through fluctuations in solar intensity and until all of the energy stored in the hot tank is depleted. Energy storage and dispatchability are very important for the success of solar power tower technology, and molten salt is believed to be the key to cost effective energy storage.

Figure 11: Dispatchability of molten-salt power towers.

Hybrid alternative

To reduce the financial risk associated with the deployment of a new power plant technology and to lower the cost of delivering solar power, initial commercial-scale (>30 MW ) power towers will likely be hybridized with conventional e fossil-fired

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302.064 - Advanced and alternative energy systems Modern ways for concentrat ing solar energy plants. Many hybridization options are possible with natural gas combined-cycle and coal-fired or oil-fired Rankine plants. In a hybrid plant, the solar energy can be used to reduce fossil fuel usage and/or boost the power output to the steam turbine. In the power boost hybrid plant, additional electricity is produced by over sizing the steam turbine, contained within a coal-fired Rankine plant or the bottoming portion of a combined-cycle plant (Figure 12), so that it can operate on both full fossil and solar energy when solar is available. Studies of this concept have typically oversized the steam turbine from 25% to 50% beyond what the turbine can produce in the fossil-only mode. Oversizing beyond this range is not recommended because the thermal-to- electric conversion efficiency will degrade at the part loads associated with operating in the fuel-only mode.

Figure 12: Power tower hybridized with combined cycle plant. Power is produced in the gas turbine (fossil only) and from the steam turbine (fossil and solar). Steam from the solar steam generator is blended with fossil steam from the heat recovery steam generator (HRSG) before entering a steam turbine.

Environmental impact

No hazardous gaseous or liquid emissions are released during operation of the solar power tower plant. If a salt spill occurs, the salt will freeze before significant contamination of the soil occurs. Salt is picked up with a shovel and can be recycled if necessary. If the power tower is hybridized with a conventional fossil plant, emissions will be released from the non-solar portion of the plant.

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Performance and cost discussion

At 2000, the following successful operation of Solar Two, the first commercial scale power tower is assumed to be built in the Southwestern U.S. or within a developing nation. At the present time, the Solar Two business consortium is comfortable with scaling up the Solar Two receiver to 145 MW (3.3 times larger than Solar Two [14]). This larger receiver will be combined with a state-of-the-art glass heliostat field (> 95 m2 each) [15], a next-generation molten-salt steam generator design (based on lessons learned at Solar Two), a high-efficiency steam turbine cycle, and will employ modern balance of plant equipment that will improve plant availability. As pointed out in the previous paragraph, these improvements are expected to increase annual efficiency from 8.5 to 15%.

To reduce the financial risk associated with the deployment of this first commercial- scale plant and to lower the cost of delivering solar power, the plant will likely be hybridized with a base-loaded fossil-fired plant. If the solar plant is interfaced with a combined cycle plant, the system layout could be similar to that depicted in Figure 10. Hybridization significantly reduces the cost of producing solar power relative to a solar- only design for the following reasons. • Capital costs for the solar turbine are reduced because only an increment to the base-load fossil turbine must be purchased. • O&M costs are reduced because only an increment beyond the base-load O&M staff and materials must be used to maintain the solar-specific part of the plant. • The solar plant produces more electricity because the turbine is hot all the time and daily startup losses incurred in a solar-only plant are avoided.

Power plant size is assumed to remain at 200 MW e . Power towers built between the years 2010 and 2020 should have a receiver that has a significantly higher efficiency than is currently possible with today’s technology. Receivers within current power towers are coated with a highly absorptive black paint. However, the emissivity of the paint is also high which leads to a relatively large radiation loss. Future power tower receivers will be coated with a selective surface with a very low emissivity that will significantly reduce radiation losses. Selective surfaces similar to what is needed are currently used in solar parabolic trough receivers. Additional research is needed to produce a surface that won’t degrade at the higher operating temperature of the tower. Given this improvement, scoping calculations at Sandia indicate that annual receiver efficiency should be improved to about 90%.

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By 2020, further improvements in heliostat manufacturing techniques, along with significant increases in annual production, are expected to lower heliostat costs to their final mature value (~$70/m2, see Figure 13). The reflectance of the mirrors is also expected to be improved from the current value of 94% to a value of at least 97%. Advanced reflective materials are currently being investigated in the laboratory. As the technology reaches maturity, plant parasitics will be fully optimized and plant availability will also improve. Combining all the effects described above, annual plant efficiency is expected to be raised to 20% and annual capacity factor should be raised above 75%.

Figure 13: Heliostat price as a function of annual production volume.

Thermal Storage Systems for Concentrating Solar Power

One challenge facing the widespread use of solar energy is reduced or curtailed energy production when the sun sets or is blocked by clouds. Thermal energy storage provides a workable solution to this challenge.

In a concentrating solar power (CSP) system, the sun's rays are reflected onto a receiver, which creates heat that is used to generate electricity. If the receiver contains oil or molten salt as the heat-transfer medium, then the thermal energy can be stored for later use. This enables CSP systems to be cost-competitive options for providing clean, renewable energy.

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Several thermal energy storage technologies have been tested and implemented since 1985. These include the two-tank direct system, two-tank indirect system, and single- tank thermocline system.

Two-Tank Direct System

Figure 14: Two-tank direct molten-salt thermal energy storage system at the Solar Two power plant

Solar thermal energy in this system is stored in the same fluid used to collect it. The fluid is stored in two tanks—one at high temperature and the other at low temperature. Fluid from the low-temperature tank flows through the solar collector or receiver, where solar energy heats it to a high temperature, and it then flows to the high-temperature tank for storage. Fluid from the high-temperature tank flows through a heat exchanger, where it generates steam for electricity production. The fluid exits the heat exchanger at a low temperature and returns to the low- temperature tank.

Two-tank direct storage was used in early parabolic trough power plants (such as Solar Electric Generating Station I) and at the Solar Two power tower in California. The trough plants used mineral oil as the heat-transfer and storage fluid; Solar Two used molten salt.

Two-Tank Indirect System

Two-tank indirect systems function in the same way as two-tank direct systems, except different fluids are used as the heat-transfer and storage fluids. This system is used in plants in which the heat-transfer fluid is too expensive or not suited for use as the storage fluid.

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Figure 15: Two-tank indirect thermal energy storage system

The storage fluid from the low-temperature tank flows through an extra heat exchanger, where it is heated by the high-temperature heat-transfer fluid. The high- temperature storage fluid then flows back to the high-temperature storage tank. The fluid exits this heat exchanger at a low temperature and returns to the solar collector or receiver, where it is heated back to a high temperature. Storage fluid from the high- temperature tank is used to generate steam in the same manner as the two-tank direct system. The indirect system requires an extra heat exchanger, which adds cost to the system.

This system will be used in many of the parabolic power plants in Spain and has also been proposed for several U.S. parabolic plants. The plants will use organic oil as the heat-transfer fluid and molten salt as the storage fluid.

Single-Tank Thermocline System

Figure 16: Single-tank thermocline thermal energy storage system

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Single-tank thermocline systems store thermal energy in a solid medium—most commonly, silica sand—located in a single tank. At any time during operation, a portion of the medium is at high temperature, and a portion is at low temperature. The hot- and cold-temperature regions are separated by a temperature gradient or thermocline . High-temperature heat-transfer fluid flows into the top of the thermocline and exits the bottom at low temperature. This process moves the thermocline downward and adds thermal energy to the system for storage. Reversing the flow moves the thermocline upward and removes thermal energy from the system to generate steam and electricity. Buoyancy effects create thermal stratification of the fluid within the tank, which helps to stabilize and maintain the thermocline.

Using a solid storage medium and only needing one tank reduces the cost of this system relative to two-tank systems. This system was demonstrated at the Solar One power tower, where steam was used as the heat-transfer fluid and mineral oil was used as the storage fluid.

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302.064 - Advanced and alternative energy systems Modern ways for concentrat ing solar energy forecast and conclusions

The most optimistic CSP industry development scenarios in public circulation forecast that 7 percent of the power supply in 2030 may be generated with CSP technology, growing further to a possible share of 25 percent until 2050. More moderate assumptions of SolarPaces, the European Solar Thermal Electricity Association (ESTELA) and Greenpeace International assess the combined solar power output to contribute between 3 - 3.6 percent in 2030 and 8 - 11.8 percent in 2050 to the worldwide power supply. This would imply a capacity of over 830 GW in 2050 and deployments of 41 GW per annum. All in all, the CSP industry could be looking ahead to accumulated annual growth rates of 17 percent to 27 percent in the medium short term over the next five to ten years. MAN Ferrostaal, German Industrial Service Provider and Concentrating Solar Power Industry Player, offers an assessment of worldwide CSP trends and tendencies and the solar market in the Middle East and North Africa in the "Solar Report" October 2009 on the international portal site solarserver.com.

Figure 17: Concentrating Solar Power plant example

Based on the Reference Scenario of the International Energy Agency (IEA), the by far most conservative market prognosis, considerably lower growth rates may have to be expected. On a strict "business-as-usual" basis, with legislative frameworks no more favourable than existing policies, no binding commitments made to enact environmental standard reforms and steady low investor confidence, renewable energies would never contribute significantly to global power generation. It is fact, however, that in 2008 CSP installations accounted for about 430 MW of generated electricity worldwide. Because of several projects in Spain, an addition of about 1 GW

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302.064 - Advanced and alternative energy systems Modern ways for concentrat ing solar energy will foreseeably come online before the end of 2011. In the midterm, a capacity of some 20 GW by 2020 and an accumulated investment volume of about $160 billion seem realistic. "We all know the figures," says Tom Koopmann, Senior Vice President of Solar Energy at Ferrostaal and chief strategist for the MENA region, "and we know that the numbers vary. To predict the market of 2050 with confidence today is to tell a fortune based on assumptions."

"That we won’t see any dynamic growth in CSP, we believe, is quite unlikely. There are several hundred MW in operation and almost 1 GW in construction. The cumulative capacities announced to be in development amount to some 7 GW, but some caution must be exercised at this point. `Under development´ can be interpreted in many ways. It might mean almost anything from a feasibility study that has indicated a potential positive scenario up to a construction in process. At Ferrostaal we pursue a significant amount of projects in early development stages in parallel, of which then some result in an actual power plant in operation. During the pre-development process many factors might impact the final decision to execute a project." Projections and analyses that seemed reasonably optimistic two years ago, whether commissioned corporate studies or publicly available outlooks, it appears, have been underestimating the market, he emphasizes. In Spain, for instance, renewable energy legislation has been revised only a short time ago because too many CSP projects were proposed which could have created potentially too high subsidy spending.

Why CSP is Becoming Ever More Attractive?

Figure 18: Another CSP plant example

CSP plants have very low operating costs because of their fuel independence. About 80 percent of the investment costs are spent on construction and debt pay-off. The

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302.064 - Advanced and alternative energy systems Modern ways for concentrat ing solar energy required investment for a given project, of course, depends on its scale but also on local infrastructure, grid connection and project development expenses. Finally, the solar irradiation is of great importance as it determines to a large extent the efficiency of the plant.

In order for CSP to be fully competitive, the initial investment costs have to decrease and components have to become more efficient. The same tendencies, which have been observed with other technologies in the past, can now be observed on the CSP market. Scaled up plant sizes, technological advancements and improved operation modes (such as implementation of thermal storage) increase plant efficiency. Important external factors such as market regulations and policy initiatives designed to promote renewable energies and CSP investments provide incentivising frameworks for the industry. Currently, these include long-term feed-in tariffs, government-issued investment subsidies, tax incentives and regenerative energy quotas. Put in a nutshell: CSP projects – parabolic trough plants in particular – have become bankable.

There are intrinsic costs: investments in components, construction and operation, for example. These costs must be lowered from within the industry to make CSP more attractive. But whether the price per kWh of CSP, now or in the future, is competitive with conventional generation depends not only on CSP technology.

Taking their Measure: Who Does What?

Throughout the entire region, interest in the sustainable use of regenerative energies has grown. Due to the prevailing climate, solar power obviously has the appeal of a natural choice. Several countries have either repeatedly stated serious interest in CSP projects or already have moved on to execute plant constructions.

The United Arab Emirates, Abu Dhabi especially, have started initiatives to use renewable energy. The most notable outcome of this is Masdar City. Next to the usage of other energy sources, the main power supply for the City will be delivered through a 100 MW CSP plant which is in the final phase of a tender process. Further projects are firmly planned and will support to cater for the ever growing UAE power demand, which has doubled between 1993 and 2003 and already reached a consumption of 12,000 kWh per capita and year.

While the emirate of Abu Dhabi is about to execute the first large-scale CSP power plant in the GCC region, many of her neighbours have their own projects in concrete stages of planning and development. Workgroups have been established to determine how solar power can best be integrated into grid expansion plans. Various feasibility

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302.064 - Advanced and alternative energy systems Modern ways for concentrat ing solar energy studies have detailed the economic viability of constructing CSP capacities. As a result, projects are expected in Dubai, Bahrain, Oman, Saudi Arabia and other countries within the next twelve months.

In Algeria, a national goal has been set to provide for 10 percent of the energy demand with renewable energy by 2025. Almost five years ago, in 2004, the Algerian Government introduced the first regenerative power feed-in-law of any OECD country – guaranteeing the power purchase from integrated solar combined cycle plants (ISCC) with over 20 percent solar generation for up to two times the regular tariff. At the moment, one solar thermal plant is under construction, and two more ISCC plants, each with an output of 400 MW and 70 MW CSP, will be developed between 2010 and 2015.

Morocco has contracted a 470 MW station in the northeast of the country, due to commence operation in 2009. In 2007, a Combined Cycle Power Island was contracted in Egypt, which is currently under construction and expected to start operation in the year 2010. A first 140 MW ISCC plant with a 20 MW parabolic trough solar field, in which Ferrostaal was involved, has been built in Egypt already.

On the other hand, the market in each country requires individual assessment. Countries rich in fossil resources with flourishing petrochemical industries, like Saudi Arabia, Kuwait, the United Arab Emirates, or Qatar, generate huge revenues which can be reinvested. These countries have the means to diversify with CSP and are interested in acquiring the technology in order to stay a global player in the energy sector, even when fossil fuel resources are depleted. The challenge is not only to invest in technology, but also to use it, a step which needs to be managed politically, as local power prices presently are extremely low and there is only a limited willingness to accept price increases.

Other countries like Jordan, Bahrain, Syria or Lebanon, which have less or no available fossil resources of their own, could use CSP in order to become less dependent on imported energy. These countries are relying on fuel imports or are consuming most of their own production, a production that then cannot be sold for profit on the global market. Often in these countries the financing is more challenging to structure, but the higher CSP kWh price is closer to what is being paid for fossil energy in any event. Each country is different and has individual potentials for specific CSP applications.

The United Arab Emirates demonstrate exemplarily just how immediate air- conditioning affects the overall energy demand. During the hot summer months, twice the amount of electricity is consumed than during the winter. These seasonal peaks Eric Martinez Lara 29

302.064 - Advanced and alternative energy systems Modern ways for concentrat ing solar energy are typical for many countries and urban centres in the whole region. Equally characteristic is the comparatively low energy efficiency. According to the German Energy Agency (dena), the impact of climatisation and cooling on electricity consumption is particularly great because it is caused by the largest consumer group: private households, small and mid-sized businesses, office buildings and public institutions. Hardly more than 10 percent of the demand originates with the industry.

Figure 19: Example of private household CSP

A CSP solution can address the demand, generating cold from heat. A solar thermal collector can generate sufficient process steam to power an absorption chiller, providing an ecological alternative to conventional cooling systems. The advantage of using the sun itself for cooling is, of course, obvious. At present Ferrostaal markets a commercially feasible technology in this area. The system has been scaled for large buildings – hotels, shopping malls, airports – and can provide air conditioning in the summer months, heating and warm water in winter, or process steam for industrial applications. While several plants are presently planned in Turkey, the UAE and Latin America, the “Iberotel Sarigerme Park” hotel at the Turkish Aegean has been using the system since 2004.

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302.064 - Advanced and alternative energy systems Modern ways for concentrat ing solar energy

Figure list

Figure 1: Ioannis Sakkas experiment ...... 3 Figure 2: CSP example ...... 4 Figure 3: Solar/Rankine parabolic trough system schematic ...... 6 Figure 4: Incident solar rays are concentrated on insulated steam tubes to heat working thermal fluid ...... 12 Figure 5: LFR solar systems alternate the inclination of their mirrors to focus solar energy on multiple absorbers, improving system efficiency and reducing overall cost.12 Figure 6: Solar dish System ...... 13 Figure 7: Schematic of a dish/engine system with stretched-membrane mirrors ...... 15 Figure 8: Schematic which shows the operation of a heat-pipe solar receiver...... 15 Figure 9: Schematic showing the principle of operation of a Stirling engine ...... 16 Figure 10: power tower solar plant ...... 18 Figure 11: Dispatchability of molten-salt power towers...... 19 Figure 12: Power tower hybridized with combined cycle plant. Power is produced in the gas turbine (fossil only) and from the steam turbine (fossil and solar). Steam from the solar steam generator is blended with fossil steam from the heat recovery steam generator (HRSG) before entering a steam turbine...... 20 Figure 13: Heliostat price as a function of annual production volume...... 22 Figure 14: Two-tank direct molten-salt thermal energy storage system at the Solar Two power plant ...... 23 Figure 15: Two-tank indirect thermal energy storage system ...... 24 Figure 16: Single-tank thermocline thermal energy storage system ...... 24 Figure 17: Concentrating Solar Power plant example ...... 26 Figure 18: Another CSP plant example ...... 27

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References list

[1]. Status Report on Solar Thermal Power Plants, Pilkington Solar International: 1996. Report ISBN 3-9804901-0-6. [2]. Assessment of Solar Thermal Trough Power Plant Technology and Its Transferability to the Mediterranean Region - Final Report, Flachglas Solartechnik GMBH, for European Commission Directorate General I External Economic Relations, and Centre de Developpement des Energies Renouvelables and Grupo Endesa, Cologne, Germany: June 1994. [3]. O&M Cost Reduction in Solar Thermal Electric Power Plants - Interim Report on Project Status, KJC Operating Company, for Sandia National Laboratories: September 1, 1994. [4]. O&M Cost Reduction in Solar Thermal Electric Power Plants - 2nd Interim Report on Project Status, KJC Operating Company, for Sandia National Laboratories: July 1, 1996. [5]. Texas Renewable Energy Resource Assessment: Survey, Overview & Recommendations, Virtus Energy Research Associates, for the Texas Sustainable Energy Development Council, July, 1995, ISBN 0-9645526-0-4. [6]. http://en.wikipedia.org/wiki/Parabolic_trough [7]. http://en.wikipedia.org/wiki/Linear_fresnel_reflector [8]. http://www.nrel.gov/docs/fy12osti/54758.pdf [9]. Montes Pita, M.J. Analisis y Propuestas de Sistemas Solares de Alta Exergia Que Emplean Agua como Fluido Calorifero. Universidad Politécnica de Madrid (ES) : Master thesis, 2008. [10]. Washom, B., “Parabolic Dish Stirling Module Development and Test Results,” Paper No. 849516, Proceedings of the IECEC, San Francisco, CA (1984). [11]. Lopez, C.W., and K.W. Stone, Performance of the Southern California Edison Company Stirling Dish , Sandia National Laboratories, Albuquerque, NM: 1993. Report SAND93-7098. [12]. Kolb, G.J., “Evaluation of Power Production from the Solar Electric Generating Systems at Kramer Junction: 1988 to 1993,” Solar Engineering 1995, Proceedings of the ASME Solar Energy Conference, Maui, HI (1995). [13]. http://en.wikipedia.org/wiki/Dish_Stirling#Dish_designs

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[14]. Central Receiver Commercialization Plan, Bechtel National Inc., for the California Energy Commission: June 1995. Report 01-0444-35-3027-2777. [15]. Strachan, J.W., and R.M. Houser, Testing and Evaluation of Large-Area Heliostats for Solar Thermal Applications, Sandia National Laboratories, Albuquerque, NM: February 1993. Report SAND92-1381. [16]. Kolb, G.J., “Economic Evaluation of Solar-Only and Hybrid Power Towers Using Molten Salt Technology”, Proceedings of the 8th International Symposium on Solar Thermal Concentrating Technologies, Cologne, Germany (October 6-11, 1996). Accepted for publication in the journal Solar Energy. [17]. http://en.wikipedia.org/wiki/Solar_power_tower

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