A new metric, the Levelized Cost of Coating (LCOC), is derived in this paper to evaluate and compare alternative solar selective absorber coatings against a baseline coating (Pyromark 2500). In contrast to previous metrics that focused only on the optical performance of the coating, the LCOC includes costs, durability, and optical performance for more comprehensive comparisons among candidate materials. The LCOC is defined as the annualized marginal cost of the coating to produce a baseline annual thermal energy production. Costs include the cost of materials and labor for initial application and reapplication of the coating, as well as the cost of additional or fewer heliostats to yield the same annual thermal energy production as the baseline coating. Results show that important factors impacting the LCOC include the initial solar absorptance, thermal emittance, reapplication interval, degradation rate, reapplication cost, and downtime during reapplication. The LCOC can also be used to determine the optimal reapplication interval to minimize the levelized cost of energy production. Similar methods can be applied more generally to determine the levelized cost of component for other applications and systems.
A new metric has been developed to evaluate and compare selective absorber coatings for concentrating solar power applications. Previous metrics have typically considered the performance of the selective coating (i.e., solar absorptance and thermal emittance), but cost and durability were not considered. This report describes the development of the levelized cost of coating (LCOC), which is similar to the levelized cost of energy (LCOE) commonly used to evaluate alternative energy technologies. The LCOC is defined as the ratio of the annualized cost of the coating (and associated costs such as labor and number of heliostats required) to the average annual thermal energy produced by the receiver. The baseline LCOC using Pyromark 2500 paint was found to be %240.055/MWht, and the distribution of LCOC values relative to this baseline were determined in a probabilistic analysis to range from -%241.6/MWht to %247.3/MWht, accounting for the cost of additional (or fewer) heliostats required to yield the same baseline average annual thermal energy produced by the receiver. A stepwise multiple rank regression analysis showed that the initial solar absorptance was the most significant parameter impacting the LCOC, followed by thermal emittance, degradation rate, reapplication interval, and downtime during reapplication.
Sandia National Laboratories and Siemens Energy, Inc., examined 14 different subcritical and supercritical steam cycles to determine if it is feasible to configure a molten-salt supercritical steam plant that has a capacity in the range of 150 to 200 MWe. The effects of main steam pressure and temperature, final feedwater temperature, and hot salt and cold salt return temperatures were determined on gross and half-net efficiencies. The main steam pressures ranged from 120 bar-a (subcritical) to 260 bar-a (supercritical). Hot salt temperatures of 566 and 600ÀC were evaluated, which resulted in main steam temperatures of 553 and 580ÀC, respectively. Also, the effects of final feedwater temperature (between 260 and 320ÀC) were evaluated, which impacted the cold salt return temperature. The annual energy production and levelized cost of energy (LCOE) were calculated using the System Advisory Model on 165 MWe subcritical plants (baseline and advanced) and the most promising supercritical plants. It was concluded that the supercritical steam plants produced more annual energy than the baseline subcritical steam plant for the same-size heliostat field, receiver, and thermal storage system. Two supercritical steam plants had the highest annual performance and had nearly the same LCOE. Both operated at 230 bar-a main steam pressure. One was designed for a hot salt temperature of 600ÀC and the other 565ÀC. The LCOEs for these plants were about 10% lower than the baseline subcritical plant operating at 120 bar-a main steam pressure and a hot salt temperature of 565ÀC. Based on the results of this study, it appears economically and technically feasible to incorporate supercritical steam turbines in molten-salt power tower plants.
The breacher's training aid described in this report was designed to simulate features of magazine and steel-plate doors. The training aid enables breachers to practice using their breaching tools on components that they may encounter when attempting to enter a facility. Two types of fixtures were designed and built: (1) a large fixture incorporates simulated hinges, hasps, lock shrouds, and pins, and (2) a small fixture simulates the cross section of magazine and steel-plate doors. The small fixture consists of steel plates on either side of a structural member, such as an I-beam. The report contains detailed descriptions and photographs of the training aids, assembly instructions, and drawings.
The Boeing Company fabricated the Solar Two receiver as a subcontractor for the Solar Two project. The receiver absorbed sunlight reflected from the heliostat field. A molten-nitrate-salt heat transfer fluid was pumped from a storage tank at grade level, heated from 290 to 565 C by the receiver mounted on top of a tower, then flowed back down into another storage tank. To make electricity, the hot salt was pumped through a steam generator to produce steam that powered a conventional Rankine steam turbine/generator. This evaluation identifies the most significant Solar Two receiver system lessons learned from the Mechanical Design, Instrumentation and Control, Panel Fabrication, Site Construction, Receiver System Operation, and Management from the perspective of the receiver designer/manufacturer. The lessons learned on the receiver system described here consist of two parts: the Problem and one or more identified Solutions. The appendix summarizes an inspection of the advanced receiver panel developed by Boeing that was installed and operated in the Solar Two receiver.
Solar Two was a collaborative, cost-shared project between 11 U. S. industry and utility partners and the U. S. Department of Energy to validate molten-salt power tower technology. The Solar Two plant, located east of Barstow, CA, comprised 1926 heliostats, a receiver, a thermal storage system, a steam generation system, and steam-turbine power block. Molten nitrate salt was used as the heat transfer fluid and storage media. The steam generator powered a 10-MWe (megawatt electric), conventional Rankine cycle turbine. Solar Two operated from June 1996 to April 1999. The major objective of the test and evaluation phase of the project was to validate the technical characteristics of a molten salt power tower. This report describes the significant results from the test and evaluation activities, the operating experience of each major system, and overall plant performance. Tests were conducted to measure the power output (MW) of the each major system, the efficiencies of the heliostat, receiver, thermal storage, and electric power generation systems and the daily energy collected, daily thermal-to-electric conversion, and daily parasitic energy consumption. Also included are detailed test and evaluation reports.