Utilizing spreadsheets for analyzing solar thermal central receiver power plant designs

This report presents the preliminary design of a molten salt receiver subsystem for application to solar thermal central receiver power plants. The design is applicable to a repowered utility electric plant or to a stand-alone plant. The receiver subsystem consists of an elevated quad-cavity receiver, a concrete tower to support the receiver, riser and downcomer piping within the tower to transport the salt to and from the thermal storage sub-system, heat adsorption panels within the receiver cavities to absorb the incident radiant energy, and the pumps, tanks, piping systems, valves, controls and instrumentation necessary to provide safe and efficient operation of the receiver subsystem. Incident energy is concentrated on the receiver cavity openings by a surround heliostat field. The design is based on a 320 MWt receiver sited at Barstow, California. The report provides the design requirements necessary to detail the design of the receiver subsystem, a detailed description of the subsystem components, and the design methods employed to produce the design. A development plan highlights the areas of technical uncertainty along with the required development effort to resolve these uncertainties. Manufacturing processes were developed to establish the fabricability of the heat absorption panels. The cost and schedule from design through start up for the receiver subsystem are also provided.

Offshore wind energy development along the East Coast of the US is proceeding quickly as a result of large areas with an excellent wind resource, low water depths and proximity to large electricity markets. Careful planning of wind turbine deployments in these offshore wind energy lease areas (LA) is required to maximize power output and to minimize wake losses between neighboring wind farms as well as those internal to each wind farm. Here, we used microscale wind modeling with two wake parameterizations to evaluate the potential annual energy production (AEP) and wake losses in the different LA areas, and we developed and applied a levelized cost of energy (LCoE) model to quantify the impact of different wind turbine layouts on LCoE. The modeling illustrated that if the current suite of LA is subject to deployment of 15 MW wind turbines at a spacing of 1.85 km, they will generate 4 to 4.6% of total national electricity demand. The LCoE ranged from $68 to $102/MWh depending on the precise layout selected, which is cost competitive with many other generation sources. The scale of the wind farms that will be deployed greatly exceed those currently operating and mean that wake-induced power losses are considerable but still relatively poorly constrained. AEP and LCoE exhibited significant dependence on the precise wake model applied. For the largest LA, the AEP differed by over 10% depending on the wake model used, leading to a $10/MWh difference in LCoE for the wind turbine layout with 1.85 km spacing.

A numerical solution of turbulent, two-dimensional, natural convection heat transfer for a high temperature, vertical surface is presented in this work. This is relevant to heat transfer from the receiver of a solar central receiver power plant on a calm day (no wind). It is the lower bound of convective loss from an external receiver. Application of wall suction to the receiver surface is also examined as a means of reducing convective loss. In the Appendix an analysis of the economic impact of energy loss from a receiver is presented. It demonstrates the importance of receiver performance with regard to solar central receiver plant cost. (MOW)

Optimization of the Levelized Cost of Energy (LCoE) in wind farms helps ensure profitability and competitiveness of the project. Recent work has explored driving down LCoE by allowing multiple wind turbines in a single wind farm - with different hub heights, rotor diameters, and rated powers. In this work, we performed optimization of the Lillgrund wind farm with continuously varying hub-heights to mitigate wake interference, improve annual energy production (AEP) and reduce LCoE. The optimization converged to a configuration where the turbines were vertically staggered, resulting in an improvement in both AEP and internal rate of return (IRR) - a financial metric related to LCoE. Reducing the number of turbines to a discrete set of 2 or 3 retained nearly all the benefits of staggering but is more aligned with limitations related to manufacturing and logistics.

The purpose of this study was to quantify the impact of the Solar Thermal Central Receiver (STCR) tax incentives and commercialization on the federal treasury revenues. The initial STCR market penetration was assumed to take place in California, because of favorable local conditions. The initial financing was assumed to be underwritten by intermediary partnerships under long-term avoided cost contracts with the local utility companies with subsequent sale of the plants to utilities at competitive prices. To estimate the impacts of these various tax incentives associated with the commercialization of the STCR technology, the tax revenues and costs for the STCR plants were compared with the tax revenues and costs for the displaced conventional power plants. This differential analysis takes into account the different operating expenses, as well as the different depreciation charges, financing costs, and tax credits associated with STCR and conventional plants. The study also evaluated the impact of both the previous (1983) and current (1984) proposed federal energy tax credits. The resulting total annual tax cash flows were subsequently cumulated to determine the aggregate tax revenues and costs throughout the 1985 to 2034 time period. The results of this analysis indicate that the initial federal tax revenues are negative. With increasing market penetration, the installed costs of the STCR plants decrease rapidly and the net present values of the tax revenue cash flows associated with plants constructed after 1995 are positive, and become significantly larger than those for the corresponding displaced conventional plants.

Work is broken down in the following areas: solar thermal central receiver systems analysis; advanced solar thermal systems analysis and engineering; thermal power systems support; total energy systems mission analysis; irrigation and small community mission analysis; photovoltaics mission analysis; Solar Thermal Test Facility and Central Receiver Pilot Plant systems engineering. (LEW)

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 600°C were evaluated, which resulted in main steam temperatures of 553 and 580°C, respectively. Also, the effects of final feedwater temperature (between 260 and 320°C) 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 600°C and the other 565°C. 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 565°C. Based on the results of this study, it appears economically and technically feasible to incorporate supercritical steam turbines in molten-salt power tower plants.

Floating offshore wind, far less constrained by water depths than bottom-fixed, has great potential in the Mediterranean Basin. The levelised cost of energy (LCOE) is arguably the single most reliable metric to measure the viability of energy projects. In this work, the levelised cost of energy for floating offshore wind is mapped for the first time in the European and Eastern Mediterranean with a detailed cost breakdown and a focus on semi-submersible platforms. A multi-parameter analysis is conducted in a case study to discern the effects of specific elements on the LCOE. Expressions are formulated as functions of site-specific variables: distance to shore, water depth and annual energy production. The latter is estimated accurately by combining the power curve of an exemplar wind turbine with hindcast, site-specific wind data. The mapping shows the paramount importance of the wind climate, i.e., the resource, for the LCOE. The lowest values (~95 €/MWh) occur where the wind resource is most abundant, i.e., the Gulf of Lion and the Aegean Sea. The highest values (>250 €/MWh) are found where the resource is scarce, i.e., around the Balearic Islands and in the North Adriatic, Tyrrhenian and Levantine Seas. Moderate values of the LCOE (130–180 €/MWh) occur off South Spain (Alboran Sea), Sardinia, Sicily and Malta, and in the South Adriatic. In addition to the local wind resource, other parameters that play a relevant role in the LCOE are those related to the production of energy (number of turbines in the wind farm and installed power), on the one hand, and to substantial sources of costs (cost of turbines and substructure), on the other, as well as the project lifetime and discount rate. These results identify hotspots for the deployment of floating offshore wind in the Mediterranean and opportunities for cost reductions, and contribute to decision-making in a region much in need of renewable energy.

The results of a review of the MDAC/Rocketdyne solar central receiver designs for both the 100 MWe commercial plant and the 10 MWe pilot plant are presented. The major objective of this design review was to assess the adequacy of the design in meeting the requirements of the solar central receiver (boiler) over a commercial lifetime of 30 years. The MDAC/Rocketdyne design consists of an external solar heated receiver, composed of a multiple of modular panels arranged in parallel and operating on the once-through steam generation principle. Each panel is composed of welded tangent tubes, connected between inlet and outlet headers. Subcooled water enters the bottom headers, flows upward, absorbs heat, produces saturated steam throughout the two phase region, and exits at the top as superheated steam. Tube size and material are the same for both the commercial and pilot plants. Panel sizes are different between the two plants. Commercial plant heat flux is approximately 2.8 times that of the pilot plant. Structural supports and attachments of both designs are similar. Control of final superheat temperature is maintained by varying the water flow to each of the panels, according to the thermal absorption of each panel. The pilot and commercial plant receiver designs are therefore similar in construction and mode of operation. They differ significantly, however, in thermal loading (heat flux).

Reduced-order models for mesoscale current energy converter (CEC) modeling allow for tractable computation times for investigations of array configurations on power performance and environmental effects to support design optimization. The CEC representation in these models take the form of actuator discs in codes such as SNL-Delft3D-CEC-FM treating the rotating CEC blades as momentum sinks. In the first-of-its-kind, whole-plant optimization software, DTOcean, the hydrodynamic modelling of CECs is reduced one step further by superimposing wake models based on normalized CFD simulations onto a set of pre-computed velocity fields, to provide power estimates. DTOcean is a new tool and the amount of verification and validation evidence gathered is presently limited. To gain additional confidence and industry buy-in to the software penetration, this study investigated a primary component of levelized cost of electricity (LCOE) calculation, annual energy production (AEP), through an analytic calculation of power using the results of an identical simulation in SNL-Delt3D-CEC-FM. Three configurations of an 8-turbine array are studied with DTOcean where two rows of 4-turbines are spaced (unstaggered) 5-, 10-, and 20-Diameters apart and the AEP was calculated; The energy calculation in SNL-Delft3D-CEC-FM were more computationally expensive for the mesoscale domain making the optimization of solely an arrays power production using the wake superposition method implemented DTOcean attractive. The codes however are complementary as SNL-Delft3D-CEC-FM simultaneously investigates environmental effects of varying array configurations while DTOcean considers all aspects of array costs through its lifetime to optimize LCOE from a whole-plant perspective.

The primary goal of this research is to create a new billboard-style central spherical solar receiver with varying header and tube diameter, for which two spiral central receiver designs and a new circular central solar receiver with varying pipe radius and varying mass circulation are utilized. The exhaust temperature of the water was determined employing a computational fluid dynamics assessment employing ANSYS Fluent. Following the verification of the standards models, a novel central solar receiver project was made that accomplishes computational fluid dynamics assessment with almost the same boundary condition.The heat export fluid is water, and the spiral coil tube is copper. The mass circulation rate varies among 0.1 LPM, 0.2 LPM, and 0.3 LPM, with the inlet temperature of water being 299K at continuous solar irradiation. The findings demonstrate that at 0.1 LPM, the redesign of the central solar receiver produces a temperature of 383.9 K, which is 28.39 percent higher than the inlet temperature and 7.32 percent higher than the spiral central receiver. As a consequence, the circular central solar recipient to varying pipe radius is suggested and considered in upcoming usages

Influence of Technological Changes on the Energy Yield of PV Modules: An Outdoor Study

The Solar One Pilot Plant successfully demonstrated the feasibility of solar central receiver power plants. During its operating years many data were collected regarding the efficiency and availability of the various plant systems. The author summarizes these statistics and compares them with goals developed by the Department of Energy. On the basis of this comparison, design and operation improvements are recommended. >

Concentrated solar power (CSP) is a cutting-edge method of conserving renewable energy. The concentrated solar power is utilized as a heating source to increase the temperature of heat transfer fluid circulating in the piping of the central solar receiver. The solar central receiver is the most crucial part in solar tower power plants. In this study, a Computational Fluid Dynamics (CFD) framework was developed for analyzing four designs of the central tower receiver, namely, a conventional uniform tube diameter solar receiver (UTD), vertical variable tube diameter solar receiver (VTD), a circular solar variable tube diameter (CVTD) receiver and a leaf type circular solar receiver (LTSR). This analysis studied the solar radiation heat transfer efficiency, temperature distribution, and fluid outlet temperature; pressure and velocity distributions for the designs using CFD. It was found that the CVTD design helped achieve a higher rise in temperature of the heat transfer fluid (HTF) when the mass flow rate was in the range of 0.1 to 0.2 liter per minute. The CVTD and LSTR models of receiver were more efficient heat transfer receiver designs compared with other designs for same surface area and strength of beam radiations.

This article presents a framework to integrate and optimize the design of large-scale wind turbines. Annual energy production, load analysis, the structural design of components and the wind farm operation model are coupled to perform a system-level nonlinear optimization. As well as the commonly used design objective levelized cost of energy (LCoE), key metrics of engineering economics such as net present value (NPV), internal rate of return (IRR) and the discounted payback time (DPT) are calculated and used as design objectives, respectively. The results show that IRR and DPT have the same effect as LCoE since they all lead to minimization of the ratio of the capital expenditure to the energy production. Meanwhile, the optimization for NPV tends to maximize the margin between incomes and costs. These two types of economic metrics provide the minimal blade length and maximal blade length of an optimal blade for a target wind turbine at a given wind farm. The turbine properties with respect to the blade length and tower height are also examined. The blade obtained with economic optimization objectives has a much larger relative thickness and smaller chord distributions than that obtained for high aerodynamic performance design. Furthermore, the use of cost control objectives in optimization is crucial in improving the economic efficiency of wind turbines and sacrificing some aerodynamic performance can bring significant reductions in design loads and turbine costs.