MIDDLE EAST TECHNICAL UNIVERSITY INSTRUCTOR : Prof. Dr. Ahmet ECEVİT Phys. 471 project HELIOSTAT FIELD PRESENTED BY : Ertuğ ÖZYİĞİT Bahtiyar RUZIBAYEV INSTRUCTOR : Prof. Dr. Ahmet ECEVİT 2004-1

OUTLINE Page Central Receiver System (CRS)…………………………………………………….………..3 Components of CRS…………………………………………………………………………...8 1. Solar Concentrators (Heliostats)…………………………………………………..……..10 1.1 How Heliostats move……………..……………………………………………………13 1.2 Ideal Heliostat…………………….…………………………………………………….15 1.3 Heliostat field types……………….…………………………………………………....17 1.4 Heliostat errors……………………………………………………………………...….19 1.5 Cosine Effect………………………………………………………………………..…..23 1.6 Shadowing and Blocking………………………………………………………...…….27 2. Receiver…………………………………………………………………………………..….29 2.1 Types of receiver………………………………………………………………………31 3. Tower design……………………………………………………………………………….36 4. Beam characterization targets……………………………………………………...……..40 5. Heat transfer fluids…………………………………………………………………...……..41 6. Storage system……………………………………………………………………...………47 7. Power generator………………………………………………………………………….....49 8. Multi Tower Solar Array (MTSA)……………………………………………………….....51 References………………………………………………………………………………………56

Central Receiver System (CRS) The central receiver concept for solar energy concentration and collection is based on a field of individually sun-tracking mirrors (heliostats) that reflect the incident sunshine to a receiver (boiler) at the top of a centrally located tower. Typically 80 to 95 percent of the reflected energy is absorbed into the working fluid which is pumped up the tower and into the receiver. The heated fluid (or steam) returns down the tower and then to a thermal demand such as a thermal electrical power plant or an industrial process requiring heat [1]. In figure 1 you can see a CRS.

Figure 1. CESA-1 CRS [2].

The basic difference between the central receiver concept of collecting solar energy and the trough or dish collectors is that in this case, all of the solar energy to be collected in the entire field, is transmitted optically to a small central collection region rather than being piped around a field as hot fluid. Because of this characteristic, central receiver systems are characterized by large power levels (1 to 500 MW) and high temperatures (540 to 840°C) [1].

Central receiver technology for generating electricity has been demonstrated in the Solar One pilot power plant at Barstow, California. This system consists of 1818 heliostats, each with a reflective area of 39.9 m2 covering 291,000 m2 of land. The receiver is located at the top of a 90.8 m high tower and produces steam at 516°C at a maximum rate of 42 MW. In figure 2 you can see Solar One power plant [1].

Figure 2. Solar One Power Plant [1].

Components of CRS Central receiver consists of, Solar concentrator (heliostat field) Receiver Storage system Power generator Figure 3 shows the schematic diagram of CRS.

Figure 3. Schematic Diagram of CRS [3].

1. Solar concentrators (Heliostats) The heliostats are mirrors with solar tracking on two axes and capable of concentrating the reflected solar radiation on a focal point located at the top of a tower in which the receiver element is placed [4]. See the figure 4.

Figure 4. Heliostats [3].

Heliostats’ sizes varies according to the the receiver used on the tower. Heliostats are generally made from iron glass Heliostats made from low iron float glass have a reflectivity 0.903. However, dirt reduces reflectivity to 0.82 [1].

1.1 How heliostats move The mirrors are mounted on individual frames that are tipped up and down and rotated east to west by small motors much like those used in electric clocks. The motors are controlled by a computer which determines how to position each heliostat so that its reflection hits the receiver at any time of the day and any day of the year [4]. In figure 5 you can see an example of sun tracking heliostat design.

Figure 5. Erik Rossen’s Heliostat Design [3].

1.2 Ideal Heliostat Low cost Maximum reflection No absorbtion & transmission In table 1 you can see the reflectivity and emissivity of some surfaces.

Plate glass mirrors coated with aluminum on back 85 % E   Average Surface Reflectivity Emissivity Aluminum foil, bright 92 - 97 0.05 Reflective Mylar Film 90 - 93 Aluminum sheet 80 - 95 0.12 Plate glass mirrors coated with aluminum on back 85 Aluminum-coated paper, polished 75 - 84 0.20 Steel, galvanized, bright 70 - 80 0.25 Aluminum paint 30 - 70 0.50 Building materials: wood, paper, glass, masonry, nonmetallic paints   5 - 15 0.90 Table 1. Reflectivity and Emissivity for Different Surfaces [1].

1.3 Heliostat Field Types Surrounding the tower On one side of the tower You can see these types in figure 6.

Figure 6. One Side and Surrounding Type [3].

1.4 Heliostat Errors A perfectly flat heliostat would produce an image on the receiver the size of the heliostat (projected normal to the heliostat-receiver direction) increased by the approximately 0.5 degree of sun spread. For most applications, each mirror segment is concaved slightly and each mirror segment on a heliostat is canted toward a focal point. This produces a higher flux density at the aim point [1].

A number of factors tend to increase the image size from a particular heliostat. Mirror surface waviness is an important factor for heliostats as it is with parabolic collector surfaces. In addition, the gross curvature error of each mirror segment and the errors associated with accurate canting of each mirror segment on the heliostat frame further increase the image error. This last source of error can be amplified by the effects of differential thermal growth and gravity (heliostat position) on the heliostat frame. The important heliostat performance parameter is the size of the isoflux contour containing 90 percent of the total reflected power [1].

In addition to producing a high flux density, the ability of the heliostat tracking system to position the centroid of the flux profile at the center of the receiver (aim point) is critical. Positioning errors may be caused by vertical and horizontal errors in the heliostat positioning or feedback mechanisms. In addition, wind can produce structural deflections, causing position errors [1].

Most of the heliostat errors discussed become more significant (in terms of the flux “spilled” from the receiver), the farther the heliostat is located from the receiver. However, the flux contour and positioning errors are also critical for heliostats close to the tower because the projected area of the receiver is very small at that location [1].

1.5 Cosine Effect The major factor determining an optimum heliostat field layout is the cosine “efficiency” of the heliostat. This efficiency depends on both the sun’s position and the location of the individual heliostat relative to the receiver. The heliostat is positioned by the tracking mechanism so that its surface normal bisects the angle between the sun’s rays and a line from the heliostat to the tower. The effective reflection area of the heliostat is reduced by the cosine of one-half of this angle as seen in figure 7.

Figure 7. The cosine effect for two heliostats in opposite directions from the tower.  For the noontime sun condition shown, heliostat A in the north field has a much greater cosine efficiency than does heliostat B [1].

Field cosine efficiency, calculated by using equation 1. Equation 1. Field Cosine Efficiency [1] where α and A are the sun’s altitude and azimuth angles, respectively, and z, e, and n are the orthogonal coordinates from a point on the tower at the height of the heliostat mirrors as depicted in figure 8.

Figure 8. Coordinates defining the reflection of the sun’s rays by a heliostat to a single aim point. Vector H is normal to the heliostat reflecting surface [5].

1.6 Shadowing and Blocking Shadowing occurs at low sun angles when a heliostat casts its shadow on a heliostat located behind it. Therefore, not all the incident solar flux is reaching the reflector. Blocking occurs when a heliostat in front of another heliostat blocks the reflected flux on its way to the receiver. Blocking can be observed in a heliostat field by noting reflected light on the backs of heliostats. Both processes are illustrated in figure 9 [1].

Figure 9. Shadowing and Blocking Effect [1].

2. Receiver The receivers normally consist of a large number of metal tubes that contain a flowing fluid. The outer surface of the tubes are black to assure that the light is absorbed and converted to heat. The metals used for the tubes are the same as those used in other high-temperature, nonsolar processes. Central receivers are usually very large and have a capacity to generate 100 MW of useful power or more [1].

The primary limitation on receiver design is the heat flux that can be absorbed through the receiver surface and into the heat transfer fluid, without overheating the receiver walls or the heat transfer fluid within them [1].

2.1 Types of Receivers External Type Cavity type

External type: These normally consist of panels of many small (20-56 mm) vertical tubes welded side by side to approximate a cylinder.  The bottoms and tops of the vertical tubes are connected to headers that supply heat transfer fluid to the bottom of each tube and collect the heated fluid from the top of the tubes [1].

Cavity type: In an attempt to reduce heat loss from the receiver, some designs propose to place the flux absorbing surface inside of an insulated cavity, thereby reducing the convective heat losses from the absorber. The flux from the heliostat field is reflected through an aperture onto absorbing surfaces forming the walls of the cavity. Typical designs have an aperture area of about one-third to one-half of the internal absorbing surface area. Cavity receivers are limited to an acceptance angle of 60 to 120 degrees (Battleson, 198l). Therefore, either multiple cavities are placed adjacent to each other, or the heliostat field is limited to the view of the cavity aperture [1].

The aperture size is minimized to reduce convection and radiation losses without blocking out too much of the solar flux arriving at the receiver. The aperture is typically sized to about the same dimensions as the sun’s reflected image from the farthest heliostat, giving a spillage of 1 to 4 percent. For a 380 MW plant design, the aperture width for the largest of the four cavities (the north-facing cavity) is 16 m, and the flux at the aperture plane is four times that reaching the absorbing surface inside. In figure 10 you can see the two different types of receivers [1].

Figure 10. External and Cavity Type Receivers [3].

3. Tower design The height of the tower is limited by its cost. The weight and wind age area of the receiver are the two most important factors in the design of the tower. Seismic considerations are also important in some locations. Figure 11 shows a solar tower [1].

Figure 11. Solar Tower [3].

The weight and size of a receiver are affected by the fluid choice as discussed previously. Typical weights for a 380 MW receiver range from 250,000 kg for an external receiver using liquid sodium to 2,500,000 kg for a cavity air receiver. These would be placed at the top of a 140 to 170 m tower if a surrounding heliostat field is used [1].

Proposed tower designs are of either steel frame construction, using oil derrick design techniques, or concrete, using smokestack design techniques. Cost analyses indicate that steel frame towers are less expensive at heights of less than about 120 m and that concrete towers are less expensive for higher towers [1].

4. Beam characterization targets Prominent on any photograph or drawing of a central receiver tower are the white targets located just below the receiver. These are beam characterization system (BCS) targets used to aid in periodic calibration and alignment of individual heliostats. They are coated with a diffusely reflecting white paint, and are not designed to receive the flux of more than one or two heliostats. Instrumentation within the target area is used to determine the centroid and flux density distribution of the beam from a selected heliostat. If the centroid of the beam is not located where the field tracking program predicts it to be, tracking program coefficients are modified appropriately [1].

5. Heat transfer fluids The choice of the heat transfer fluid to be pumped through the receiver is determined by the application.  The primary choice criterion is the maximum operating temperature of the system followed closely by the cost-effectiveness of the system and safety considerations.  Five heat transfer fluids have been studied in detail for application to central receiver systems [1].

The heat transfer fluids with the lowest operating temperature capabilities are heat transfer oils. Both hydrocarbon and synthetic-based oils may be used, but their maximum temperature is around 425°C. However, their vapor pressure is low at these temperatures, thus allowing their use for thermal energy storage. Below temperatures of about -10°C, heat must be supplied to make most of these oils flow. Oils have the major drawback of flammable and thus require special safety systems when used at high temperatures. Heat transfer oils cost about $0.77/kg [1].

Steam has been studied for many central receives applications and is the heat transfer fluid used in the Solar One power plant. Maximum temperature applications are around 540°C where the pressure must be about 10 MPa to produce a high boiling temperature. Freeze protection must be provided for ambient temperatures less than 0°C. The water used in the receiver must be highly deionized in order to prevent scale buildup on the inner walls of the receiver heat transfer surfaces. However, its cost is lower than that of other heat transfer fluids. Use of water as a high-temperature storage medium is difficult because of the high pressures involved [1].

Nitrate salt mixtures can be used as both a heat transfer fluid and a storage medium at temperatures of up to 565°C. However, most mixtures currently being considered freeze at temperatures around 140 to 220°C and thus must be heated when the system is shutdown. They have a good storage potential because of their high volumetric heat capacity. The cost of nitrate salt mixtures is around $0.33/kg, making them an attractive heat transfer fluid candidate [1].

Liquid sodium can also be used as both a heat transfer fluid and storage medium, with a maximum operating temperature of 600°C. Because sodium is liquid at this temperature, its vapor pressure is low. However, it solidifies at 98°C, thereby requiring heating on shutdown. The cost of sodium-based systems is higher than the nitrate salt systems since sodium costs about $0.88/ kg [1].

For high-temperature applications such as Brayton cycles, it is proposed to use air or helium as the heat transfer fluid.  Operating temperatures of around 850°C (1560°F) at 12 atm pressure are being proposed.  Although the cost of these gases would be low, they cannot be used for storage and require very large diameter piping to transport them through the system [1].

6. Storage System A storage system makes it possible to run the steam turbine under constant conditions even during periods of varying insolation (clouds) or after sunset. It consists of two main parts which are hot and cold storage tanks. In figure 12, you can see these tanks [3].

Figure 12. Storage Tanks [3].

7. Power Generator An electric generator is a device that converts mechanical energy to electric energy. See figure 13.

Figure 13. Power Generator [3].

8. Multi Tower Solar Array (MTSA) The Multi Tower Solar Array (MTSA) is a new concept of a point focusing two-axis tracking concentrating solar power plant (Fig.14). The MTSA consists of several tower-mounted receivers which stand so close to each other that the heliostat fields of the towers partly overlap. Therefore, in some regions of the total heliostat field the heliostats are alternately directed to different aiming points on different towers. Thus the MTSA uses radiation which would usually remain unused by a conventional solar tower system due to mutual blocking of the heliostats [6].

Figure 14. MTSA [6].

In an urban environment small MTSAs can be installed on the flat roofs of big buildings such as industrial halls or shopping complexes or over open areas like parking sites. Even in central Europe, parking sites do have the problem that the cars can overheat on hot and sunny days. Therefore an MTSA reflector field, serving as a sun protecting roof at a height of 3 to 6 m, could be advantageous. The solar radiation would be utilized and additionally the cars would be protected from overheating. In figure 15 and 16 you can see visualizations [6].

Figure 15. A visualization of an MTSA field over a parking site at the Munich Trade Centre [6].

Figure 16. Impression of conditions in a parking lot topped by an MTSA solar array [6].

References Web page: http://www.powerfromthesun.net/Chapter10/Chapter10new.htm Web page: http://www.ciemat.es/eng/instalacion/psa-cesa-1.html Şengul Topcu, phys471 project. 20/04/2004. Web page: http://www.eia.doe.gov/kids/energyfacts/sources/renewable/solar.html Web Page: http://www.powerfromthesun.net/Chapter8/Chapter8new.htm Web Page: http://www.physics.usyd.edu.au/app/research/solar/mtsa.html