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  1. 1. Pergamon PII: Solar Energy Vol. 68, No. 3, pp. 263–283, 2000 © 2000 Elsevier Science Ltd S 0 0 3 8 – 0 9 2 X ( 9 9 ) 0 0 0 6 8 – 7 All rights reserved. Printed in Great Britain 0038-092X / 00 / $ - see front matter / locate / solener COMPACT LINEAR FRESNEL REFLECTOR SOLAR THERMAL POWERPLANTS DAVID R. MILLS* , † and GRAHAM L. MORRISON** *School of Physics, University of Sydney, Sydney 2006, Australia **School of Mechanical and Manufacturing Engineering, University of New South Wales, New South Wales 2052, Australia Received 25 November 1998; revised version accepted 30 August 1999 Communicated by LORIN VANT-HULL Abstract—This paper evaluates Compact Linear Fresnel Reflector (CLFR) concepts suitable for large scale solar thermal electricity generation plants. In the CLFR, it is assumed that there will be many parallel linear receivers elevated on tower structures that are close enough for individual mirror rows to have the option of directing reflected solar radiation to two alternative linear receivers on separate towers. This additional variable in reflector orientation provides the means for much more densely packed arrays. Patterns of alternating mirror inclination can be set up such that shading and blocking are almost eliminated while ground coverage is maximised. Preferred designs would also use secondary optics which will reduce tower height requirements. The avoidance of large mirror row spacings and receiver heights is an important cost issue in determining the cost of ground preparation, array substructure cost, tower structure cost, steam line thermal losses, and steam line cost. The improved ability to use the Fresnel approach delivers the traditional benefits of such a system, namely small reflector size, low structural cost, fixed receiver position without moving joints, and noncylindrical receiver geometry. The modelled array also uses low emittance all-glass evacuated Dewar tubes as the receiver elements. Alternative versions of the basic CLFR concept that are evaluated include absorber orientation, absorber structure, the use of secondary reflectors adjacent to the absorbers, reflector field configurations, mirror packing densities, and receiver heights. A necessary requirement in this activity was the development of specific raytrace and thermal models to simulate the new concepts. © 2000 Elsevier Science Ltd. All rights reserved. This paper describes a new design approach that came from a realisation that trough technology was near its design limits and that fundamental changes to the absorbing surface and collector configuration were needed for large scale implementation of solar thermal power. New high temperature selective surfaces with very low emissivity for evacuated tube solar absorbers have been developed (Mills, 1991; Zhang and Mills, 1992). Mills and Keepin (1993) suggested that these surfaces could be used in new low concentration designs to reduce system costs, and increase performance as lowering the absorbing surface emissivity allows greater flexibility in geometric concentration as a design variable. Mills and Keepin used polar axis trough collectors as the example of a low concentration collector, but there are several new design configurations that could use advanced evacuated tubes. In this paper, we advocate the use of an advanced form of linear Fresnel reflector as a more cost-effective alternative to parabolic trough or parabolic dish systems. The peak solar energy radiant flux concentration of such systems can range between 50 and 150% of that used by LS2 1. INTRODUCTION The majority of direct solar electricity worldwide is generated in nine large solar thermal electric plants in California built by Luz International Limited (LIL), with design and major solar components produced by Luz Industries Israel (LII). These solar fields have achieved better than 97% availability over more than 10 years of operation and have successfully demonstrated the technology, but in a financial environment requiring substantial government subsidy. Advanced versions of the Luz LS3 collector technology may soon reduce unsubsidised electricity generation cost to about ECU0.085 per kWh (EC, 1998). However, these costs are still too high for many markets. Even in markets where there is renewable energy obligation legislation, significant cost reductions in solar thermal power systems are still needed to compete against other renewable energy grid-electricity systems using waste biomass fuel or wind energy. † Author to whom correspondence should be addressed. Fax: 161-2-9351-3577; e-mail: 263
  2. 2. 264 D.R. Mills and G.L. Morrison and LS3 systems (23:1 and 26:1, respectively). Higher concentrations are being investigated using advanced secondary reflector systems and will be reported in future publications. 2. LINEAR FRESNEL REFLECTOR TECHNOLOGY Geometrically, the ideal reflectors to use with single receivers of solar energy are continuous reflectors, usually parabolic for linear axis systems, or paraboloidal for two axis systems. Large continuous reflectors or lenses can be simulated by small elements distributed over a plane thus avoiding the problems associated with very large reflectors. Baum et al. (1957) discussed large two-axis solar tracking systems of this type, but the first to apply this principle in a reasonably large linear system for solar collection was Francia (1968), who developed both linear and twoaxis tracking Fresnel reflector systems. This work showed that elevated temperatures could be reached using such systems. Following this, Riaz (1976) developed theory associated with two-axis systems, which was soon accompanied by additional work by Vant-Hull and Hildebrandt (1976), Abdel-Monem et al. (1976), Lipps and Vant-Hull (1977), Lipps and Vant-Hull (1978), Igel and Hughes (1979) and Dudley and Workhoven (1978, 1979). The work by Riaz can be adapted to linear systems, and he discusses shadowing effects in a general way. Wei (1980, 1981) discusses simplified calculations for two-axis systems. Much of this work was associated with early modelling of the US Central Receiver programme which culminated in Solar One, a 10 MW(e) two-axis tracking solar power plant constructed in the early 1980s. However, Di Canio et al. (1979) of the FMC Corporation produced a detailed project design study for a linear plant of between 10 MW(e) and 100 MW(e), with a mirror field on one side of a 1.68-km linear cavity absorber mounted on 61 m towers. Vant-Hull (1991) suggests that the increased image size and lowered concentration for ray incident angles not perpendicular to the linear axis would permit no advantages over the Central Receiver plants. However, the FMC report itself acknowledges these optical shortcomings but says these are compensated by lower costs of manufacture and maintenance; the authors were aware of Central Receiver development going on in parallel at the time and proposed use of the same generating system. Since this report was made, substantial advances have been made in the areas of spectrally selective absorbers and secondary concentrators, both of which alleviate the requirement for a small primary image size and very high optical concentration. A more recent effort to produce a tracking Linear Fresnel Reflector was made by the Israeli Paz company in the early 1990s (Feuermann and Gordon, 1991; Feuermann, 1993). Although intended for 1508C operation, this technology is the closest in the literature to that proposed here. This array exhibited, among others, aberration difficulties caused by the movement of reflectors around an axis parallel to but displaced from the reflector optical axis. The analysis approach taken by the Paz system developers was to use an optical ray trace program for a system with finite reflector sizes. This is also the method used in the course of the current study. One fundamental difficulty with the Linear Fresnel Reflector (LFR) technology is the avoidance of shading of incoming solar radiation and blocking of reflected solar radiation by adjacent reflectors. Shading and blocking can be reduced by using higher absorber towers, which increases cost, or by increasing absorber size, which allows increased spacing between reflectors remote from the absorber. The latter leads to increased ground usage relative to collector area and also increases both thermal losses and shading by the absorber. 3. COMPACT LINEAR FRESNEL REFLECTOR (CLFR) 3.1. Basic concept Compact Linear Fresnel Reflector (CLFR) technology is, in effect, a second type of solution for the Fresnel reflector field problem which has been overlooked until now. The classical linear Fresnel system has only one linear absorber on a single linear tower, and therefore there is no choice about the direction of orientation of a given reflector. However, if one assumes that the size of the field will be large, as it must be in technology supplying electricity in the multi-MW class, it is reasonable to assume that there will be many linear absorbers in the system. If they are close enough, then individual reflectors will have the option of directing reflected solar radiation to at least two absorbers. This additional variable in reflector orientation provides the means for much more densely packed arrays, because patterns of alternating reflector inclination can be set up such that closely packed reflectors can be positioned without shading and blocking. The interleaving of mirrors between two linear absorber lines is
  3. 3. Compact Linear Fresnel Reflector solar thermal powerplants 265 Fig. 1. Schematic diagram showing interleaving of mirrors without shading between mirrors. shown in Fig. 1. This arrangement minimises beam blocking between adjacent reflectors and allows higher reflector densities and lower absorber tower heights to be used. Land or roof area cost is in many cases not a serious issue, but available area can be restricted in industrial or urban situations. Avoidance of large reflector spacing and high towers is an important cost issue when one considers the cost of ground preparation, array substructure, tower structure, steam line thermal losses, and steam line cost for installation next to an existing fossil fuel generating plant where the objective is the retrofit of a low pollution steam source. The CLFR power plant concept proposed in this paper is intended to reduce costs in all elements of the solar array. The following features enhance the cost effectiveness of this system compared with trough technology. • Flat or elastically curved glass reflectors mounted close to the ground are used to minimise structural costs. Costly sagged glass reflectors are avoided. • The heat transfer loop is separated from the reflector field and fixed in space thus avoiding the high cost of flexible high pressure lines or high pressure rotating joints required in trough and dish systems. • The heat transfer fluid is water, and passive direct boiling heat transfer is proposed to minimise parasitic pumping losses and the need for flow controllers. Steam supply may either be directly into the power plant steam drum or via a heat exchanger. Steam can also be supplied in a similar manner for power plant preheating cycles. The steam delivery conditions considered in this study are 3508C and 16 MPa wet steam. • An absorber composed of a pressure tube containing the high pressure water, mounted inside an advanced all-glass evacuated Dewar tube. The absorber of the glass evacuated tube is connected to the central steel pressure tube by a heat transfer fin. The evacuated tubes exhibit very low radiative losses and are inexpensive, the current cost of a 1.2-m long, 45-mm diameter evacuated tube is | US$15. • Low array maintenance costs due to ease of access for cleaning, and the capability to remove the single ended evacuated tubes without breaking the heat transfer fluid circuit. This paper investigates alternative versions of the CLFR concept to determine which are worthy of further development. Areas of study include field orientation, absorber orientation, absorber structure, usage of auxiliary reflectors adjacent to the absorbers, reflector packing density, and tower height. 3.2. Horizontal tracking axis arrays CLFR arrangements can include analogues of horizontal East–West axis, North–South axis and polar axis parabolic troughs. In the latter, the plane of the CLFR array is inclined toward the equator at the latitude angle, and would require an inclined support structure or favourable ground inclination. A scaled layout of a CLFR system with a 50-m tower spacing, 10-m high absorber and 48 mirrors, each 1 m wide, is shown in Fig. 2. The high-density arrangement of reflectors shown in Fig. 2 is such that the reflectors are separate but would be close to touching if all were tilted to the horizontal. Lower densities of reflectors may be more cost-effective in some cases. The scale of the moving elements is relatively small, even though the unit scale of the overall system is very large compared to other linear concentrator configurations; the pictured array is equivalent to a parabolic trough of focal length of around 10 m. In this project most of the investigation was done on a horizontal East–West axis array using a vertical absorber system consisting of a vertical
  4. 4. 266 D.R. Mills and G.L. Morrison Fig. 2. Layout to scale of a CLFR array with 48 mirror rows, 50-m absorber spacing and absorbers 10 m above the primary reflector field. Scale marks are in metres. Mirrors near each tower are trained on it alone because close packing can be achieved without blocking, mirrors in the middle of the two absorber rows have alternating directions. wall of all-glass evacuated tubes illuminated from both sides, or a horizontal absorber tube array illuminated from one side. 3.3. Inclined North–South and polar axis arrays A CLFR array can also be inclined toward the equator to increase winter and annual collection. A North–South axis array inclined at the latitude angle (a polar axis tracking array) will yield close to the optimal annual performance. Performance simulations for different tracking axis orientation and inclination are given in this study. An inclined array would be similar to that shown in Fig. 3, in which a short North–South array is tilted toward the equator. A stationary reflector at the back end of each array is used to reduce the inclination required. The stationary reflector redirects rays that have not yet hit the finite length primary mirror but would be intercepted by an infinite length primary mirror and also collects rays that have been reflected from the primary mirror but have struck the reflecting wall before striking the finite length absorber. Inclination markedly improves collected energy per m 2 of reflector for locations outside tropical latitudes. Inclining the array necessitates spacing between the inclined reflector arrays to avoid winter shading, and decreases output per m 2 of ground area occupied compared to a horizontal North–South array. Inclined North–South arrays have a flatter seasonal output profile compared to horizontal arrays, however, they require a more expensive substructure than horizontal arrays. The lower Fig. 3. Inclined CLFR field with an inverted receiver. The stationary vertical reflector wall improves winter collection.
  5. 5. Compact Linear Fresnel Reflector solar thermal powerplants input in the early morning and late afternoon due to the raised artificial horizon for an inclined array is accounted for in the analysis that follows. 4. SOLAR COLLECTOR OPTICAL MODELLING 4.1. Raytrace modelling A raytrace model was used to generate optical collection maps in terms of transverse and longitudinal incidence angles. The concentration maps and beam radiation data were used as inputs to thermal modelling routines. A two-dimensional model was used to generate concentration data for a series of slices through the array. The twodimensional solutions were then assembled to generate three-dimensional maps of the optics of the systems. Absorber angular response and interactions with the curved surfaces of the glass Dewar tubes was accurately modelled. The three dimensional map of optical concentration and absorption as a function of two orthogonal incidence angles was used in a radiation and thermal model developed in TRNSYS (Klein et al., 1996). The ray tracing model incorporated a ‘branching ray’ concept for modelling reflections in an array of evacuated absorber tubes. A complex incremental raytrace model was used to establish the optimal orientation of each mirror row for a given solar incidence angle. A model that included tracking of a ganged field of mirror rows was also used. The branching ray model was necessary to gauge the optical absorption efficiency of arrays of closely spaced all glass 267 evacuated tubes, since rays reflected from the glass cover tubes or absorber elements could find their way to other tubes. Primary, secondary and tertiary reflections were tracked in the absorber. In this study reflector slope errors were not considered. 4.2. CLFR receiver optical modelling Two primary receiver types are proposed for this technology. The first uses all-glass evacuated absorber tubes in a vertical rack illuminated from both sides. The second uses tubes in a singlesided horizontal receiver facing downward. 4.2.1. Optical modelling of vertical evacuated tube receiver rack. The first configuration considered was a receiver with a vertical absorber protected by evacuated absorber tubes that were illuminated from both sides as shown in Fig. 4. All-glass evacuated tubes having an outer cover tube diameter of 45 mm and a cover tube thickness of 1.5 mm were evaluated. The absorber surface on the outside of the inner glass tube is 1200 mm long, with a diameter of 37 mm. The University of Sydney has licensed the basic selective coating technology to a manufacturer in China (Turbosun, 1998), and large volume low cost tubes having such dimensions are available. Due to the use of single ended absorber tubes the array can only operate as a boiler and thus cannot generate super heated steam. A potential difficulty with this arrangement is that evacuated spaces between the inner and outer glass tubes allow radiation to pass through the absorber rack. Such losses could be significant. Fig. 4. Vertical Dewar-type absorber tube banks illuminated from both sides. Fluid flow occurs entirely in fixed tubing. Feedwater is introduced from the header pipe into the branch pipes enclosed by the evacuated glass tube. Boiling occurs in the branch pipe and we saturated steam leaves via the header.
  6. 6. 268 D.R. Mills and G.L. Morrison Fig. 5. Double row tube arrangements of branch tubes enveloped by all-glass evacuated tube absorbers. (a) Close packed zig-zag absorber array, (b) absorber array with 2.5-cm gap between tubes. However, because the tubes are inexpensive it was possible to consider a staggered double row tube configuration (Fig. 5) with high tube density and very high optical interception. In a single row of touching evacuated tubes the gap between the inner and outer tubes amounts to 18% of the face area of the absorber. For vertical tube racks a solution to the gap loss problem is to use a ‘zig-zag’ double row of evacuated tubes (Fig. 5b). Such a receiver traps light passing through gaps between the inner and outer tubes of the vacuum tube fitted over the branch tubes. The absorber surface consists of both sides of the tube rack, as in Fig. 4. The absorptance as a function of tube spacing shown in Fig. 6 is dictated primarily by the plane aperture (face area) of the receiver, not the circumferential area of the evacuated tube Fig. 6. Angular absorptance of ‘zig-zag’ tube racks with different tube spacing compared to a flat absorber covered by a glass sheet. The acceptance of the ‘zig-zag’ rack averaged over all angles is almost identical to a flat plate absorber. absorber surface because much of the available absorber surface faces other absorber tubes. The absorptance of such an arrangement varies with the size of the gap between the tubes. A raytrace program was developed which follows primary ray paths through the tube assembly, together with ray reflections from the glass tube surfaces, as many reflections are collected on the second bounce. It was found that the absorptance of the tube array with 25-mm spacing could be approximated quite well by a flat plate receiver covered by a flat glass sheet (Fig. 6). The best configurations were about 2.5% better than a flat plate although the flat plate was the best performer at normal incidence. A tube spacing of 25 mm was chosen for analysis (equivalent to a single line spacing of 0.64 diameters), as the hemispherical absorptance for this tube spacing is almost identical to a flat plate absorber (Fig. 7). This choice also allowed use of a flat plate receiver in subsequent modelling as a convenient approximation to the evacuated tube receiver. More detailed analysis may be needed to determine tube spacing sensitivity, but a spacing of 0.64 diameters is expected to be close to the optimum. In a double row vertical absorber system the ‘tube pitch’, or interval between tube centres in each row, is 45 mm 1 25 mm 5 70 mm. The number of tubes per lineal metre of receiver using a 25-mm spacing and two rows is 28.6 / m. A second approach to the vertical evacuated tube gap loss problem is to use secondary reflectors behind the tubes. This requires two separated rows of tubes with individual non-imaging reflectors for each tube between the two rows. This will allow an increased tube spacing and a decreased tube related cost. However, the optical efficiency will always be less than that of the ‘quasi-vacuum flat plate receiver’ due to both increased ray spillage and absorption in the reflector. The benefit of increased tube spacing with secondary reflectors depends upon component costs. Costs are not presented in this paper, but our estimate is that the increased optical losses and reflector absorption would require an increase in plant size which will be in excess of the evacuated tube and pressure pipe related cost savings. Similarly, the 40% increase in tube numbers needed for a smaller tube spacing of 5 mm would cost more than the 3% performance increase gained. Therefore, for modelling of vertical receivers, a 25-mm ‘zig-zag’ spacing was assumed. 4.2.2. Optical modelling of horizontal evacuated tube receiver rack. In horizontal receiv-
  7. 7. Compact Linear Fresnel Reflector solar thermal powerplants 269 Fig. 7. Hemispherical absorptance of double row absorber relative to a flat plate absorber with a glass cover. ers, the absorber face area is 1.2 m 2 per lineal metre because it is single-sided (facing downward). One option is to use the same zig-zag tube arrangement as the vertical absorber. This would achieve the same high absorptance but would be a very expensive arrangement because only one side of the rack (the underside) is receiving solar radiation. Alternatively a backing reflector behind a single row of tubes could be used. A system with a tube pitch of 49 mm (to avoid tubes touching) requires only 20.4 tubes per lineal metre of absorber and has negligible penalty in optical efficiency. Approximately 1 / 4 of the rays find their way through the gaps in the worst case of normal incidence, but these can be reflected back with high efficiency, and rays from lower angles mostly strike the tubes directly. This absorber configuration would be less costly than the zig-zag arrangement, but optical performance and heat losses would be similar. Use of a non-imaging CPC backing reflector would also reduce the number of tubes and tube related costs. However, as this is a more open pitch tube arrangement with less direct tube absorption and increased reflector absorption the overall gain in cost-effectiveness will be minimal because the entire array must be enlarged in order to achieve the same output. In this paper we have evaluated the performance of the horizontal absorber systems using an inverted vacuum insulated flat plate receiver model which would be similar in performance to the high density, tube configuration. A secondary reflector can be used underneath the horizontal absorber to enhance optical collection and increase concentration. A schematic diagram of one such reflector design is shown in Fig. 8 without an upper backing reflector. This uses a horizontal array of tubes with a backing reflector above the tubes to collect rays passing between the absorbers. The bifurcated secondary reflector system is designed such that most rays from the primary reflector strike the absorber directly and do not incur an absorption loss on this secondary reflector. Only rays on the periphery of the reflected beam use the secondary reflector. 4.3. Field raytrace Optimisation of the mirror field requires consideration of the two possible positions of each mirror row for each solar radiation input angle, corresponding to two absorber targets. The modelling process involved beginning raytracing with an arbitrary starting configuration for the linear elements in the mirror field, then flipping the first mirror in the field and raytracing the whole field again. Having chosen the best position for the first reflector, the second reflector was flipped and the best position chosen for it. This process was repeated for the entire field, and for all incidence angles. To account for the finite size of the solar source a secondary raytrace between 60.758 was carried out, which increased the number of rays by a factor of five. The resulting raytrace computations were very large. For a 48-mirror row
  8. 8. 270 D.R. Mills and G.L. Morrison Fig. 8. Secondary reflector for a horizontal tube rack. Rays from the outer edge of the primary Fresnel reflector use the secondary reflector more because of beam spread. array, the model included 48 mirrors, two positions, 1000 rays, 19 angles and five beam spread divisions amounting to 9.12 million rays for each simulation of the field optical characteristics. The optical specifications used were: • normal incidence absorptance of the evacuated tube absorber surface 5 0.94; • refractive index of transparent coating on the mirror 5 1.47; • reflectance of mirror surfaces 5 0.95; • mirror segment width 5 1 m. In operating systems, reflectivity will be lost due to dirt deposited on the mirrors between cleaning operations. The raytrace in this study was performed on the basis of clean mirrors. Optimum performance in a CLFR is obtained by directing each tracking mirror strip to the best receiver for the time of day. This implies that each mirror row must have independent tracking. However, the simplest and cheapest mechanical arrangement is to have many mirror rows mechanically attached to each other and run from a single motor. Thus it is important to know the performance penalty associated with mirror row ganging, and this is modelled for some of the configurations. Having mirrors of identical curvature could lower the array cost, and this was also investigated. Fig. 9a and b shows optical concentration maps for two field configurations. A wide spacing (Fig. 9b) allows each mirror to gather more energy without blocking or shading, and the output is flatter throughout the day. A dense mirror configuration (Fig. 9a) approaches the 2D cosine collection characteristic of a horizontal flat plate collector. The peak interception of beam radiation for solar radiation arriving from a direction perpendicular to the CLFR array plane in the dense configuration was 84% of the total beam radiation arriving between the linear towers. The 2D interception factor increases with incidence angle because gaps between the reflectors are covered Fig. 9. Ray trace map of CLFR solar radiation flux concentration, (a) absorber 15 m above a 48-mirror array, (b) absorber 10 m above a 24-mirror array with mirror segments spaced by one mirror width.
  9. 9. Compact Linear Fresnel Reflector solar thermal powerplants by adjacent reflectors for low angles of incidence. Peak flux concentration of the configurations considered without including optical losses (comparable to peak geometrical concentration for a trough) is 35:1 for the 48-mirror array. The geometrical concentration of the Luz LS2 collector was 23:1 (aperture to absorber tube circumference). Higher concentrations can be achieved with the Fresnel system, but the concentration is limited by the heat flux capacity of the Dewar tubes. 5. THERMAL MODELLING OF CFLR Solar radiation and thermal simulation models of the collectors were developed in the TRNSYS modelling environment (Klein et al., 1996). For this project a series of extensions were developed within TRNSYS to simulate the linear Fresnel concentrating collector. Due to the modular nature of TRNSYS these new routines were integrated with the existing data handling and solar radiation analysis routines that are built into TRNSYS. The primary routines that were used to simulate concentrating solar collector performance were as follows. • Radiation processor, nonisotropic radiation distribution model (TRNSYS TYPE16). • Extended optical map-based solar collector model for Fresnel concentrator (Morrison, 1997). • Nonlinear heat loss solar collector model for evacuated tube absorber (Morrison, 1997). The collector thermal mass was modelled in TRNSYS using an instantaneous collector efficiency model coupled to a zero heat-loss storage-tank (TYPE4 tank). This procedure used the proven TRNSYS tank routine and solver to include the effect of thermal capacitance, rather than developing a complex collector model with built in capacitance. This model follows the start up and shut down transients at the beginning and end of each day and transient temperature effects during cloudy periods. The transient effects, due to thermal capacitance within the absorber, were found to reduce the annual output of the collector array by 3 to 6% depending on the array concentration. To model the CLFR performance the TRNSYS collector routine was modified to include a specification of optical concentration through a biaxial incidence angle modifier map (see Fig. 9). This was implemented via an extension of the optical mode 4 option in the extended TRNSYS TYPE1 solar collector model. The new routine was 271 designed to accept an incidence angle modifier map with up to 50 incidence angles in both the longitudinal and transverse planes. The optical map data was generated using the ray tracing routine described in Section 4.1. The radiation processor in TRNSYS was used to compute beam radiation from hourly global radiation records. For analysis in locations where only hourly solar radiation was available the Reindl et al. (1990) radiation model was used to compute beam radiation in terms of the clearness index and the solar elevation. Radiation on the tracking surface was calculated using the Hay and Davies (1980) model which accounts for both circumsolar and non-isotropic diffuse radiation using an anisotropy index to quantify the portion of diffuse radiation considered as isotropic. Radiation data for various sites modelled is shown in Fig. 10. For Dubbo, 1-min time step beam radiation measurements were available. The measured data were converted to normal incidence beam radiation for the horizontal or inclined planes of the Fresnel mirror field being considered. The annual solar radiation at each of the design sites is shown in Table 1. 5.1. Heat loss from an array of evacuated tubes The absorber of the proposed linear Fresnel collector consists of a rack of evacuated tube absorbers mounted in two rows so that the absorber is equivalent to an evacuated flat plate absorber. The heat loss from the evacuated tube rack was determined from the measured characteristics of single evacuated tubes (Harding et al., 1985). The heat loss modes are as follows. • Conduction through the insulated header. • Conduction through the glass envelope at the open end of the tube. • Conduction through the metal retainer near the closed end of the absorber tube. • Radiation from the absorber. The heat loss (Q l ) from a single tube can be expressed as Q l 5 k 1 (T m 2 T a ) 1 k 2 (T s 2 T a ) 1 k 3 ´(T 4 2 T 4 ) W/ tube. s a (1) For a single tube of the Sydney University design (1.4 m long), Harding et al. (1985) have shown that k 1 50.26 W/(K m 2 ), k 2 50.039 W/(K tube) and k 3 58.5310 29 W/(K 4 tube) where k 1 is the header heat loss factor, k 2 is the conduction heat loss factor for conduction heat loss from the absorbing surface to the top of the tube and
  10. 10. 272 D.R. Mills and G.L. Morrison Fig. 10. Beam radiation at Australian design sites. through the retainer clip, k 3 is the radiation heat loss factor, ´ is the absorber emissivity ´ 5 a 1 bT s where a and b are coefficients determined from measurement of surface properties (Fig. 11), T s is the absorber surface temperature, and T m is the mean fluid temperature in the evacuated tube. The tube array proposed for the absorber of the CLFR presents a continuous outer face to the surroundings, thus the radiation heat loss is equivalent to that of a flat plate evacuated collector. The radiation heat loss per unit face area of the close packed array will be the same as the radiation heat loss per unit circumferential area of a single evacuated tube as measured by Harding et al. (1985). The header heat loss per tube will be reduced due to a closer tube spacing than considered by Harding. The header heat loss coefficient k 9 for a close 1 packed tube rack is 2p k k 9 5 ]]] 1 d2 ln ] d1 S D 5 0.343 W/(K m run of header) (2) where k is the header insulation conductivity (0.06 W/ m K), d 1 , d 2 are the inner and outer diameters of the insulation (100-mm steam tube with 100 mm insulation). The heat loss due to conduction around the top of the tube and through the retainer clip is given by Q C 5 k 2 (T s 2 T a ) W/ tube. (3) Table 1. Annual solar irradiation data for Australian design sites Location Latitude Annual irradiation MJ /(m 2 day) Climate Global Longreach Dubbo (1994) Sydney Wagga 238 328 348 358 S S S S Dry desert Dry inland Temperate coastal Temperate inland Diffuse horizontal Total at latitude angle Beam 21.8 19.4 16.9 17.7 7.6 6.5 7.0 7.1 23.1 22.6 18.6 19.3 22.2 24.6 16.3 17.2
  11. 11. Compact Linear Fresnel Reflector solar thermal powerplants 273 Fig. 11. Emissivity of selective surfaces. The conduction heat loss per unit face area of the rack is double sided zig-zag evacuated tube rack (28.6 tubes / m) is Q C 5 Nk 2 (T s 2 T a ) /L W/ m 2 Q 5 0.143sT m 2 T ad 1 0.93sT s 2 T ad 1 6.44 (4) where N is the number of tubes per metre length of rack (28.6 / m for the vertical tube configuration and 20.6 for horizontal tube configuration in this study), L is the length of tubes51.2 m active length. The radiation from a single tube is given by ´k 3sT 4 2 T 4d W/ tube. s a The surface area of a single tube is 0.132 m 2 hence the radiation heat loss per unit surface area of a single tube or per unit face area of a tube rack is Qr 5 ´k 3sT 4 2 T 4d / 0.132 s a 4 4 5 6.44 3 10 28 ´sT s 2 T a d W/ m 2 (5) The overall heat loss per unit face area of a 4 4 3 10 28 ´sT s 2 T a d W/ m 2 . (6) The selective surfaces investigated in this project are two formulations of a stainless steel / aluminium nitride cermet with a copper reflector layer (SS / Cu) and two formulations of a stainless steel / aluminium nitride cermet with a molybdenum reflector (SS / Mo). The temperature dependence of the emittance of the four selective surfaces being considered for this application is shown in Fig. 11. The trade off between high absorptance and low emittance is considered in the analysis. The heat loss per unit face area from the evacuated tube rack absorber for the CLFR system is shown in Table 2 for a range of absorber Table 2. Heat loss per unit face area of evacuated tube rack using stainless steel–copper selective surface (a 50.93) Absorber surface temperature 8C Header 100 200 300 400 500 10 22 34 47 59 Heat loss W/ m 2 Tube conduction 64 143 223 303 383 Tube radiation Total 32 146 423 988 2020 105 312 681 1337 2462
  12. 12. 274 D.R. Mills and G.L. Morrison Table 3. Heat loss per unit mirror area for alternative CLFR systems Absorber surface temperature 8C 100 200 300 400 500 Heat loss per unit area of mirror W/ m 2 CLFR 24 CLFR 36 CLFR 48 10.5 31.2 68.1 133 246 7.0 20.8 45.4 89.2 164.1 5.3 15.6 34.0 66.9 123 temperatures. The heat loss from the absorber per unit mirror area for three CLFR reflector packing densities is shown in Table 3. CLFR24 refers to a CLFR system using 24 mirror rows in the 50-m space between two towers, CLFR36, 36 mirrors in the same space, etc. 6. ABSORBER CONFIGURATIONS The absorbers in the CLFR systems are singleended evacuated absorber tubes mounted horizontally (Figs. 12 and 13) or vertically (Fig. 4). The steel pressure tube inside the evacuated tube can be either a single-ended tube or a flow through U-tube system. A single ended system will be better at the radiation flux levels typical of this absorber system because a U-tube of sufficient diameter to provide adequate feedwater flow could not be easily fitted inside the inner glass tube. The absorber surface of the Dewar-type evacuated tube is on the vacuum side of the inner glass tube. The absorbed energy must be conducted through the 1.5-mm wall of the inner borosilicate glass tube, then across the clearance gap between the glass tube and the pressure tube and then through the pressure tube wall, Fig. 13. The pressure tube is supplied with feed water from the header and returns steam through the same opening. To obtain separation between the liquid and gas streams a slight inclination from the vertical or horizontal is required. The flow configuration has been successfully demonstrated in a number of prototype systems (Mills, 1991). Fig. 13. Cross section through Dewar-type evacuated tube and pressure pipe, dimensions in mm. Schmid et al. (1990) have shown that a large temperature difference will occur between the absorber surface and the fluid in the pressure tube unless a fin system is used in the clearance space between the evacuated tube and the pressure tube. 6.1. Heat transfer in absorber The CLFR systems considered in this study have concentrations (mirror area / face area of the absorber surface) up to 20:1. For 900 W/ m 2 beam intensity the incident radiation flux on the absorber will be 18 kW/ m 2 . The tube density adopted for the CLFR system is 28.6 tubes / m with each tube having 1.2 m exposed length hence the maximum heat transfer will be 755 W/ tube. This maximum heat transfer will occur only when the sun is directly overhead of the mirror array. To minimise heat loss the temperature drop between the absorber surface and the inner pressure tube must be minimised. Thermal resistance between the absorber surface and the water / steam working fluid is due to • conduction through the absorber glass wall; • heat transfer across the gap between the absorber tube and the pressure tube (via an internal fin); • conduction through the pressure tube wall; • convection into the boiling water in the pressure tubes. Fig. 12. Transverse cross section through absorber rack, the evacuated absorber tube can be vertical or near horizontal and can be easily slipped off the boiler tubes.
  13. 13. Compact Linear Fresnel Reflector solar thermal powerplants The temperature drop across the absorber wall DT 1 is given by S D do Q DT 1 5 ]] ln ] 2p k g L di (7) where Q is the heat transfer 755 W/ tube maximum; d o is the outer diameter of inner tube of vacuum envelope537 mm; d i is the inner diameter of inner tube of vacuum envelope534 mm; L is the length of vacuum tube51.2 m; k g is the borosilicate glass conductivity51.1 W/ m K. The maximum temperature drop across the glass absorber tube is DT 1 57.7 K. Heat transfer between the glass absorber tube and the pressure tube wall is via conduction through the fin system and convection and radiation through the gap. The fin system could consist of a circumferential plate and radial elements as shown in Fig. 13. The fin system is a combination of two split cylindrical sections 0.5 mm thick with radial fins 0.2 mm thick and 4.5 mm long between the two cylinders. A finite element analysis of conduction in the outer ring and through the radial fin has indicated that it is equivalent to a simple 0.2-mm-thick fin that is 7.5 mm long. If the radial fins were formed from 0.2-mm copper on an 11.258 pitch the temperature drop (DT 2 ) across the fin system (assuming all heat transfer is through the fins as radiation and convection through the gap will be minimal) is given by Q DT 2 5 ]]l NLt f k f (8) where Q is the heat transfer per tube5755 W; t f is the fin thickness50.2 mm; k f is the fin conductivity5350 W/ m K (copper at 3508C); N is the number of fins around the circumference5 16; l is the equivalent length of fins between the glass wall and the pressure tube57.5 mm; L is the width of fins5length of vacuum tube51.2 m. For a copper fin system the temperature drop is DT 2 54.2 K. The temperature drop across the pressure tube wall is given by S D do Q DT 3 5 ]] ln ] 2p k w L di (9) where Q is the heat transfer per tube5755 W; d o is the outer diameter of pressure tube525.4 mm; d i is the inner diameter of pressure tube519 mm; k w is the conductivity of pressure tube520 W/ m K (chrome steel at 3508C); L is the length of pressure tube in the evacuated tube51.2 m. The 275 temperature drop across the pressure tube wall is DT 3 51.3 K. The convective heat transfer coefficient inside the pressure tube during pool boiling will be very high and the temperature drop will be small. Fouling of the inner surface of pressure tube should not significantly add to the overall thermal resistance between the absorber surface and the steam. The fin system will have additional thermal resistance due to the contact resistance between the glass tube and the fin, and between the pressure tube and the fin. The outer contact between the glass and the fin has not been a problem in low temperature tubes using a similar type of fin. The contact resistance with the pressure tube could be minimised by using a fin system consisting of a web sandwich so that there is full circumferential contact over both the glass absorber and the pressure tube. This fin system would be inserted into the evacuated tube and twisted as it is slipped over the pressure tube. The contact resistance can also be reduced by increasing the number of fins beyond the 16 fins at 11.258 pitch considered in this analysis. At the maximum beam intensity of 900 W/ m 2 when the beam is normal to the array the temperature drop across the absorber tube is 13.2 K1the contact temperature drop. In the following analysis an overall temperature drop of 20 K has been assumed for beam radiation input of 900 W/ m 2 . The development of the absorber tube will require assessment of a number of configurations to determine the most effective finning and contact arrangement. 7. COLLECTOR PERFORMANCE ESTIMATES In this section, array performance simulation is used to select optimum CLFR configurations. The basic selection calculations were carried out for Sydney, Australia, but it was found that performance relativities are maintained at all sites. This is because all of the sites in this study have low circumsolar radiation and therefore plants in these sites will operate similarly to a plant in Sydney. Because of the low circumsolar radiation in Australia, it is sensible to optimise performance on the basis of a direct beam capture half angle of 0.758. Diffuse and circumsolar radiation outside this range is ignored in the simulation, but there is little energy in this angular range in Australia. In practice there will be beam spread due to mirror irregularities and mirror tilt error and slight differences in diffuse collection between different
  14. 14. 276 D.R. Mills and G.L. Morrison absorber configurations but these factors have been ignored in this initial investigation. In addition, beam spread for rays with a significant directional component parallel to the array linear axis has not been included, but is not serious for a concentrator of this receiver aperture with minimal aiming error. However, in some climates, notably tropical regions and parts of the Northern Hemisphere, beam radiation is more forward scattered than in Australia and the amount of circumsolar radiation is greater. For such locations the acceptance angle of the collector must therefore be larger to collect both the direct and near circumsolar components. It is possible to alter the design to enlarge the absorber for this purpose. This is not done in this paper, as it leads to a relatively greater capital cost and increased thermal loss. 7.1. CLFR configuration assumptions A 50-m wide array is assumed with mirror row densities of 24, 36 and 48 rows per absorber line. Each mirror was taken as 1 m wide with 0.95 m reflecting width and 25 mm edge structure. Each configuration was evaluated for absorber heights of 10 m, 12.5 m, and 15 m. An equal spacing of mirror rows is assumed and a space 1 m wide is left clear on either side of the array centre line under the absorber for access and maintenance. Because the effective aperture does not change as a simple cosine function as in a parabolic trough (because gaps between reflectors are blocked by adjacent mirrors at high angles of incidence), a nominal peak effective aperture was selected. The peak effective apertures of the arrays were calculated on the basis of the maximum energy that could be collected by an absorber which picks up all beam ray spillage, and is 87.5% of the curved mirror surface area: for 48 m of reflector, this is 42 m of nominal peak aperture in a space of 50 m. This presentation is analogous to a parabolic trough, where the peak aperture is used as a parameter for collector attributes such as cost and energy collection. There are several options for mirror construction and mounting. For the purposes of this study the mirrors are assumed to be a self-supporting laminated structure using silvered microsheet glass as the reflector. The auxiliary reflectors adjacent to the absorber are assumed to be 2 m 2 per lineal metre of the absorber. 7.1.1. Optimal absorber length. One important issue is how large to make the absorber relative to the array field dimensions. There exists a trade off between the improved optical collection and increased thermal losses for a larger receiver surface. The receiver size that delivered maximum energy collection was evaluated for a 50-m wide array using 36 mirror rows. Annual delivered energy for different absorber tube lengths is shown in Fig. 14 for both horizontal and vertical absorbers. The operating temperature in each case was 3208C. In neither case does the energy collection vary significantly with absorber size. The size of the horizontal absorber was found to be optimal at 1.2 m tube length, and the vertical absorber at 1.0 m tube length. The available evacuated tubes are 1.2 m long but an absorber 1.0 m long can be constructed by angling the tubes in the rack. 7.1.2. Secondary reflector. Secondary reflectors can be used near the receiver to capture reflected solar radiation that would otherwise have missed the receiver. The ends of the secondary reflector reposition the edge of the receiver aperture to better face the primary reflector array. One configuration of a horizontal absorber (1.2 m wide, 12.5 m absorber height, 36 mirror rows) was chosen to test optimal secondary reflector length. After the ray trace, an annual performance calculation was performed for each secondary reflector length all using the same receiver configuration. The optimal secondary reflector is similar to that shown in Fig. 8, and is quite short. The gap between the secondary reflector and absorber allows rays to strike the absorber directly, decreasing secondary reflector absorption losses. A similar calculation was carried out for a vertical absorber with a short circular (or parabolic) section secondary reflector as shown in Fig. 15. The optimal secondary reflector lengths depend on absorber height. However, for sub- Fig. 14. Useful delivered thermal energy as a function of absorber length for a 50-m-wide array.
  15. 15. Compact Linear Fresnel Reflector solar thermal powerplants 277 Fig. 15. Vertical evacuated tube receiver using secondary reflector above the absorber rack. sequent analysis the secondary reflector was scaled with absorber size. 7.2. Performance optimisation for Sydney Having sized the secondary reflectors and the absorber length, it is now possible to determine the optimum absorber and mirror field configurations. North–South axis and polar axis versions were used as the basic configurations. The performance of East–West systems was also investigated as a variation on the basic design. The primary cases calculated are described in Sections 7.2.1–7.2.4 using Sydney solar radiation data. The selective surface of the tubes was taken as stainless / copper with normal incidence absorptance of 0.93. 7.2.1. Vertical evacuated tube absorber with overhead secondary reflector and horizontal North–South primary reflector field. This configuration was found to perform better than a vertical absorber without a secondary reflector, Fig. 4. The secondary reflector is circular (or parabolic, they are almost indistinguishable) in curvature as shown in Fig. 15 and is sized according to results of a large number of annual simulation runs determining optimal solar radiation capture. The top secondary reflector effectively angles the receiver aperture toward the array, reducing ray spillage at the image boundary. Mirror rows close to the absorber line deliver a smaller image and would be aimed at the receiver itself, avoiding secondary reflector losses. Mirror rows underneath the absorber would use the secondary reflector. Table 4 shows the annual thermal energy delivery. As tower height increases, performance also increases due to reduced mirror row shading. Having fewer field mirror rows allows more collection by each row, but reduces energy collected by the fixed size absorber array. This is the original configuration proposed, but it is outperformed both by horizontal primary reflector fields having horizontally oriented absorbers as shown in Fig. 8, and polar inclined fields, Fig. 3. 7.2.2. Vertical evacuated tube absorber with overhead secondary reflector and polar axis tracking North–South primary reflector field. This is a version of the vertical absorber array placed upon a North–South structure inclined at the latitude angle to improve winter performance (Figs. 3 and 16). If an end reflector is used at the upper end of each segment of the array the system Table 4. Performance of vertical evacuated tube absorber with overhead secondary reflector and horizontal North–South primary reflector field, output per unit area of mirror Number of mirror rows in the primary array Thermal energy delivery MJ /(m 2 day) 10 m tower 24 36 48 12.5 m tower 15 m tower 5.54 5.31 4.64 5.61 5.32 4.80 5.57 5.32 4.91
  16. 16. 278 D.R. Mills and G.L. Morrison Fig. 16. Polar axis CLFR array. would closely approximate the performance of a segment of an infinite array. Table 5 shows that the annual thermal energy delivery of this system is substantially better than for the horizontal reflector configuration (Section 7.2.1). 7.2.3. Horizontal evacuated tube absorber with underneath secondary reflector and horizontal North–South primary reflector field. This arrangement yields substantially improved performance (Table 6) compared to the horizontal mirror field with a vertical absorber, since fewer rays are missed due to a larger total receiver aperture. The tubes would be tilted slightly off horizontal to ensure natural circulation of feedwater into the tubes. 7.2.4. Horizontal evacuated tube absorber with underneath secondary reflector and polar axis tracking North–South primary reflector field. This is a polar version of the NS horizontal evacuated tube absorber array placed upon a structure inclined at the latitude angle facing the equator. This configuration delivers the highest collection per unit aperture area (Table 7) of all the CLFR configurations considered and is equivalent to about 70% of a two-axis tracking paraboloidal dish. 7.3. Design variations There are a number of design variations that have the capability of improving performance or lowering cost. In the following, each variation is evaluated for Sydney. 7.3.1. Use of more sophisticated secondary reflector design to decrease absorber size. The configuration shown in Fig. 17 uses a short horizontal absorber and an upper secondary semicircular reflector to provide a horizontal aperture for a bifurcated lower secondary reflector. In this case, the absorber rack width is reduced to half the size of that for the previously described horizontal case. Losses are similar, because loss can take place from both sides of the receiver, but Table 5. Vertical evacuated tube absorber with overhead secondary reflector and polar axis primary reflector field Number of mirror rows in primary array Thermal energy delivery MJ /(m 2 day) 10 m tower 24 36 48 12.5 m tower 15 m tower 7.07 6.82 5.99 7.16 6.83 6.22 7.11 6.88 6.40 Table 6. Performance of horizontal evacuated tube absorber with secondary reflector and horizontal North–South primary reflector field Number of mirror rows in primary array Thermal energy delivery MJ /(m 2 day) 10 m tower 24 36 48 12.5 m tower 15 m tower 6.56 6.15 5.22 7.06 6.65 5.86 7.35 6.96 6.23 Table 7. Performance of horizontal evacuated tube absorber with secondary reflector and polar axis tracking primary reflector field Number of mirror rows in primary array Thermal energy delivery MJ /(m 2 day) 10 m tower 24 36 48 12.5 m tower 15 m tower 8.26 7.76 6.59 8.82 8.36 7.41 9.16 8.71 7.88
  17. 17. Compact Linear Fresnel Reflector solar thermal powerplants Fig. 17. Schematic of an upper and lower secondary reflector arrangement for a horizontal tube rack. the absorber cost is halved. However, optical efficiency is reduced because of increased optical losses in the dual secondary reflectors, which now intercepts a greater fraction of incoming rays. The main disadvantages of this approach are the very large unit size of the collector field — 100-m wide fields would be required for a 1.2-m long tube — and the high solar radiation flux on each tube. There are several methods for using reflectors in this way, however, at this stage, no definitive avenue for improving cost-effectiveness has been identified. 7.3.2. Use of a larger receiver to increase acceptance angle. A simulation was performed on the standard array with the absorber doubled in size. The net result was a 3% decrease in delivered energy due to increased thermal losses from the larger absorber. However, increasing the absorber size also increases cost. Hence it is important to find the smallest receiver assembly size suitable for the radiation conditions applying at the location of interest. Adoption of increased absorber size may allow this technology to be used in climates with a high circumsolar fraction, as it increases the acceptance angle at a minor cost in shading and reflector absorption. Note that in place of varying the receiver size, one may simply vary the field size for a given absorber width for different locations. 7.3.3. Use of a standard mirror curvature. The curvatures required in the field mirrors are small but important in their effect on performance. An optimisation calculation was carried out using the 15-m tower and 48 mirror row configuration modified for use with constant curvature mirrors in all sections of the array. Table shows results for a constant focal length of 30 m for a 50-m wide array. A 30-m focal length was selected since the outer field mirrors are approximately this distance 279 from the absorber and it is these mirror elements that produce most of the beam spread at the absorber. The envelope of rays diverge from the mirror because of the finite angular size of the solar disk. If the mirror is moved closer to the absorber, fewer rays are ‘spilled’ even if the focal length of the mirror is incorrect. This means that a curvature correct for the outer mirrors should also work for mirrors closer to the absorber and explains why the results for beam collection for the constant curvature are almost the same as for variable curvature. The question arises as to whether flat mirrors can be used for the field to further simplify production and cleaning. Because the mirror has a physical width of 0.95 m, the half image of the sun at the absorber will fall outside 0.95 by 0.738, or by about 0.32 m for a mirror at the centre of the field. This means the total image extent is 0.95 m1(230.32 m)51.59 m, about 0.39 m greater than the absorber aperture size. The situation is worse for mirrors far from the receiver. Therefore, in spite of the small curvature, it is necessary to curve the mirrors to capture all of the beam radiation, or else increase the absorber size by the order of 50% if flat mirrors are to be used. The performance of horizontal and polar mirror fields using optimised fixed curvature and flat mirrors are compared to those of variable curvature in Table 8. The optimised constant curvature performs only 0.5–0.6% lower than the variable curvature, but the flat mirror is 13% lower. The net result is that constant curvature elastically formed mirrors will be used because of high performance and simplicity in production. Large concentrating systems typically require mirror elements with different curvature in different sections of the mirror field. In the proposed constant curvature system, all reflector elements are identical, and moulding or sagging of glass is not required. This represents a very low cost and practical option. Due to the very slight curvature required (|30 m radius) the mirrors will be as easy to clean as flat mirrors. 7.3.4. Ganging of mirror rows. The mirror rows in the primary array can be constrained since Table 8. Average daily delivered energy for different mirror shapes Mirror shape Delivered energy MJ /(m 2 day) Horizontal array Variable curvature Constant curvature Flat Polar array 6.23 6.20 5.40 7.88 7.84 6.85
  18. 18. 280 D.R. Mills and G.L. Morrison Table 9. Annual energy delivery of alternative tracking systems (vertical absorber) Table 10. Annual delivered energy for different evacuated tube selective surfaces, 24 mirror CLFR system in Sydney Tracking mode Selective surface Annual energy delivery MJ /(m 2 day) SS / Cu a 50.93 SS / Cu ha 50.95 SS / Mo a 50.93 SS / Mo a 50.95 7.35 7.30 7.04 7.07 Delivered energy MJ /(m 2 day) Horizontal array Row tracked Optimal ganged Polar array 6.20 6.18 7.84 7.83 they all move together through the same tracking angle, even though the absolute angle of each mirror row is different from the others. The advantage of this is that the cost of the tracking system may be reduced. The disadvantage is that performance is also reduced due to shading between some of the fixed mirror lines, because the optimal allocation of mirror rows to the alternative towers changes throughout the year. Thus, there is a cost / performance trade off that has to be assessed. A ganged mirror field configuration was optimised for annual collection and compared against the standard configuration with mirrors switching between absorbers to minimise shading. The annual energy delivery of the ganged field is only 0.2% less than the independently row-tracked case (Table 9). The mirror arrangement of the ganged configuration used was approximately the optimal arrangement of the unganged configuration at equinox (in unganged fields some mirrors change absorbers to optimise performance on a seasonal basis). The mirror arrangement was fine-tuned by trial and error with each change being evaluated by an annual performance calculation. Although a ganged field might lead to lower capital cost, a non-ganged configuration has practical advantages, since focusing can be finely tuned, and all mirrors can be aligned vertically in hailstorms, or horizontally in high winds. Independently tracked mirror lines can also be aligned or inverted for cleaning. During absorber maintenance, arbitrary sections of the mirror array can be realigned to other absorbers, maintaining output, and individual rows can be aligned vertically to provide walk-through paths. A single control system could control many hundred drive motors of this slowmoving tracking system. The issue of ganging of mirrors must therefore rest as a minor issue that needs to be resolved during detailed equipment and operation design. In the remainder of this study it is assumed that the unganged system is used. 7.3.5. Effect of selective surface properties. The performance of the 24-mirror CLFR system with different evacuated tube selective surface treatments is shown in Table 10 for Sydney conditions. Annual performance is shown for the four new selective surfaces. The new high temperature selective surfaces developed by Sydney University all have significantly better performance than the cermet surface used in the Luz LS3 SEGS plant (earlier SEGS systems used chrome black selective surfaces). The stainless steel and copper surface with a slightly lower absorptance delivered more energy than the surface with the higher absorptance. This shows that a small decrease in absorptance can be traded off for a significant decrease in emissivity. For the stainless steel molybdenum surface the loss of performance due to a lower absorptance was not compensated by a matching heat loss reduction due to lower emissivity, but the performance of the two formulations is very close. For a higher concentration system with 36 or 48 mirrors per tower, higher absorptance will be preferred. 7.4. Performance for different climatic conditions The performance of the horizontal absorber with a 15-m tower and 24- or 48-mirror array in both horizontal field and polar field configurations was evaluated for a range of climatic conditions in Australia (Table 11). The sites ranged from cloudy coastal conditions (Sydney), dry and clear inland sites (Dubbo) and latitudes ranging from the dry tropics to 358 S. Surprisingly good performance was obtained for Dubbo, however it must be noted that the weather data for Dubbo are based on one particular year (1994) of measured 1-min data. The performance for other locations is based on 1-h time step typical meteorological year weather data, which gives a good estimate of the long term performance. Thus, Table 11 shows the performance during 1994 in Dubbo and the long term average performance for the other locations. The variation of annual output in Dubbo as a function of array slope for a North–South alignment is shown in Fig. 18. The effect of the shortening of the solar day on an inclined receiver was accounted for in the system analysis. A polar axis array has 22% higher output than a horizontal array. It can be seen that the performance is not
  19. 19. Compact Linear Fresnel Reflector solar thermal powerplants 281 Table 11. Annual average delivered thermal energy for different locations Location Latitude Annual average delivered energy MJ /(m 2 day) Horizontal 24 mirrors Longreach Dubbo Sydney Wagga 238 328 348 358 S S S S Polar 24 mirrors Horizontal 48 mirrors Polar 48 mirrors 11.3 11.4 7.35 7.95 12.6 14.1 9.16 9.49 9.49 9.49 6.23 6.70 10.7 11.9 7.88 8.12 therefore conceivable that both array types may find geographical niches. 8. CONCLUSIONS Fig. 18. Annual energy delivery as a function of array slope to the North, for Dubbo, latitude 328 S. sensitive to inclination within 5 degrees of the latitude. 7.5. Seasonal variation of CLFR performance Polar and horizontal arrays can have markedly different seasonal performance variation, with the polar type having much better winter performance at high latitudes. The improved winter performance of polar arrays at high latitudes (Figs. 19 and 20) may ensure its adoption, but for dry semitropical locations such as Longreach (Fig. 21), the winter performance of the horizontal array is reasonable as the sun is higher in winter. It is This paper has evaluated Compact Linear Fresnel Reflector (CLFR) concepts suitable for large scale solar thermal electricity generation plants, and recommends the concepts most suitable to pursue. In the CLFR, it is assumed that there will be many parallel linear receivers that are close enough for individual mirror rows to have the option of directing reflected solar radiation to two linear receivers on separate towers. This additional degree of freedom in mirror orientation can allow closely packed mirror rows to be positioned so that shading and blocking are almost eliminated. The avoidance of large mirror spacings and tower heights is an important issue in determining the cost of ground preparation, array substructure cost, tower structure cost, steam line thermal losses, and steam line cost. The improved ability to use the Fresnel approach still delivers the normal benefits of such a system, namely small reflector size, low structural cost, fixed receiver position without moving joints, and non-cylindrical receiver geometry. The modelled array uses Fig. 19. Seasonal performance of 48 mirror arrays in Sydney, latitude 348 S.
  20. 20. 282 D.R. Mills and G.L. Morrison Fig. 20. Seasonal performance of 48 mirror arrays in Dubbo, latitude 328 S. advanced all glass evacuated tubular absorbers with low emittance selective coatings. The CLFR concepts evaluated in this study included absorber orientation, absorber structure, the use of secondary reflectors adjacent to the absorbers, mirror field configurations, mirror packing densities, and tower heights. A necessary requirement in this activity was the development of specific raytrace and thermal models to simulate the new concepts. The primary results of the evaluations together with discussion of implications are as follows. (a) A new absorber tube configuration has been developed using a purpose designed multibranched raytrace model. It was important to have high absorber efficiency because rays lost between tubes necessitate enlargement of the entire array to compensate. The best orientation of the planar absorber (a rack of evacuated Dewar-type absorber tubes) was found to be horizontal rather than vertical as originally proposed. The optimum size of the absorber for vertical and horizontal configurations was determined. (b) For optimum receiver performance a small secondary reflector is required to reorient the receiver aperture to a more favourable angle to receive rays from the outer edge of the mirror field, and also to provide a slight degree of concentration. The size of the secondary reflector is limited when the increased reflection and shadowing losses outweigh additional collection. (c) A North–South polar field option was also evaluated. This configuration has a high efficiency and good unit aperture collection but lower ground usage efficiency than the horizontal mirror field collectors, because spaces must be left between rows to avoid shading. Quite large structures will be required (at least 20 m along the slope) and maintenance will be more difficult than with the horizontal configuration. However, seasonal performance is more uniform than with the Fig. 21. Seasonal performance of 48 mirror arrays in Longreach, latitude 238 S.
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