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changing out broken receiver tubes. The changes from the baseline systems are highlighted in Table 18. The overall effect is that evacuated receivers appear to reduce the cost of power by about 2.7%. The benefit is relatively small and replacement of broken receivers adds complexity to the plant O&M. Other factors might dictate whether or not evacuated receivers were to be used. Increased Mirror Wash: The baseline assumes that the mirror cleanliness is maintained at 90% of new mirror reflectivity. The SEGS plants claim that they can maintain mirror reflectivity at a 95% cleanliness factor. The 90% was selected to reduce the annual O&M expenses by reducing the frequency of mirror wash. Data from the SEGS plants (Cohen et al., 1999) indicates that the cost of washing mirrors is about $0.013/m2 of mirror. This works out to $260 to wash the baseline system field. Assuming a 90% cleanliness factor, the solar field is washed approximately once a month for an annual cost of $3,120 or 0.07¢/kWh. Increasing the cleanliness factor to 95% means the solar field must be washed every 12 days. This increases the annual wash cost to about 0.18¢/kWh. The output from the plant increases by approximately 7%. From Table 18, we can see that accounting for increased performance and increased mirror washing costs result in a 3% reduction in cost of power. Note, the analysis is based on the conditions at the SEGS plants. Washing requirements could vary dramatically at different sites. In the case considered, increasing mirror washing frequency appears to make economic sense. However, this will be very sensitive to actual mirror wash costs experienced at individual sites, the rate of mirror soiling, and the effectiveness of cleaning. Improved Power Cycle Efficiency: The MTPP evaluated has a relatively low thermal-to-electric conversion efficiency compared to the trough steam power plants. The ORC cycle considered here was intentionally very simple to reduce cost and minimize O&M requirements. More efficient power cycles can be designed that include multiple turbine stages, reheat turbines, or regenerative heating. Wet cooling can also be used to improve power cycle efficiency. All of these variations increase the complexity of the cycle and will result in increased system capital and O&M costs. Although a detailed design study has not been conducted to evaluate variations, we evaluated the potential benefit of a substantially improved power cycle that would have the same efficiency as the more efficient steam power cycles. To account for the increased complexity, we assume a 20% increase in capital and O&M costs. We also assume the solar field must operate at the higher temperatures of the current steam trough plants (293-391°C). The results of this case are shown in Table 18. Because of the higher operating temperature, the solar field heat losses are increased by 67%, resulting in an 18% drop in solar field thermal efficiency due to the use of non-evacuated receivers. The power cycle efficiency is increased by 69%, overall resulting in a 33% increase in thermal-to-electric performance. However, the increased capital and O&M costs nearly offset the increased thermal-to-electric efficiency. The resulting reduction in cost is minimal from the baseline system, 3.5%. It doesn’t appear that improvements to the power cycle efficiency are warranted if they result in increased capital and O&M costs. A second case was considered with the advanced power plant that also included the evacuated receivers in the solar field. In this case, because of the higher average solar field temperatures, the reduction in cost resulting from including the evacuated receivers is greater than for the lower temperature case. Thus, the evacuated receiver will be more attractive if higher solar field temperatures are used. 43PDF Image | Modular Trough Power Plant Cycle and Systems Analysis
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