Stochastic optimal dispatch of integrating concentrating solar power plants with wind farms
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Zhao, Shuqiang↗
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Operation of Concentrating Solar Power Plants in the Western Wind and Solar Integration Phase 2 Study
The Western Wind and Solar Integration Study (WWSIS) explores various aspects of the challenges and impacts of integrating large amounts of wind and solar energy into the electric power system of the West. The phase 2 study (WWSIS-2) is one of the first to include dispatchable concentrating solar power (CSP) with thermal energy storage (TES) in multiple scenarios of renewable penetration and mix. As a result, it provides unique insights into CSP plant operation, grid benefits, and how CSP operation and configuration may need to change under scenarios of increased renewable penetration. Examination of the WWSIS-2 results indicates that in all scenarios, CSP plants with TES provides firm system capacity, reducing the net demand and the need for conventional thermal capacity. The plants also reduced demand during periods of short-duration, high ramping requirements that often require use of lower efficiency peaking units. Changes in CSP operation are driven largely by the presence of other solar generation, particularly PV. Use of storage by the CSP plants increases in the higher solar scenarios, with operation of the plant often shifted to later in the day. CSP operation also becomes more variable, including more frequent starts. Finally, CSP output is often very low during the day in scenarios with significant PV, which helps decrease overall renewable curtailment (over-generation). However, the configuration studied is likely not optimal for High Solar Scenario implying further analysis of CSP plant configuration is needed to understand its role in enabling high renewable scenarios in the Western United States.
14 SOLAR ENERGY↗
Flexible Geothermal Power Generation utilizing Geologic Thermal Energy Storage (Final Seedling Project Report)
This report concludes that there is a cost-effective strategy for seasonal storage of heat that will provide firm, but dispatchable, electrical generating capacity in times when other renewable energy is not available to meet demand. Deployment of the technology appears to require no new technology, but instead combines solar, geothermal, and conventional oil and gas drilling technologies in a novel way. The study basis is the use of sedimentary geologic formations as a medium for thermal energy storage (TES), specifically for heat collected in concentrating solar collectors. The study identifies methodologies that could be used to transport this heat into and out of the subsurface in order to produce dispatchable electrical power, and reports on initial optimization results. The GeoTES system (heat input, storage, heat recovery, and heat to electric conversion) described in this analysis has the potential to provide a unique pathway for increasing the grid penetration of renewable energy in large blocks of power and across many states and regions. Further, the system can be used both to meet the nation’s flexible energy needs while also improving grid stability and reliability. The present study evaluated the use of a large number of dedicated wells to store and recover the heat, essentially creating a synthetic geothermal reservoir. The use of sedimentary geology allows the wells to be drilled at low cost. Dedicated hot and cold wells are used, arranged in a five-spot well pattern with each hot or cold well surrounded at an appropriate distance by the opposite type of well. In large numbers this becomes alternating rows of hot and cold wells. Each hot and cold well is operated using a push-pull strategy. This configuration provides the ability to immediately recover stored hot fluid from a GeoTES reservoir, or to store the heat over many months for recovery at low loss when needed. This is a practical approach for managing the system’s fluid inventory and reducing parasitic load. The production and injection power requirements are reduced because the rows of wells operating in “push” mode provide help to the wells operating in “pull” mode, and vice-versa. Initial charging of a GeoTES system increases the heat recovery temperature. Increasing the duration of the charging period decreases the magnitude of the temperature fluctuations that occur following prolonged system operation. Because of direct contact of the heated water with the reservoir formation, the production of both hot water and steam from the TES, and the temperature ranges of the recovered fluid (190 – 230°C or 375 – 445°F), conventional geothermal power cycles were used to convert the stored heat to electricity. A power cycle configuration for the GeoTES system was selected following a screening study of a number of flash, and flash/binary hybrid options. This analysis concluded that, of the configurations evaluated, a dual-stage flash steam cycle provides the lowest capital costs per unit net power generation with an acceptable hot brine inlet fluid flow rate. The evaluation included the power plant cost estimate, the cost and number of wells and the associated parasitic loads. Annual power generation performance was simulated to evaluate capacity factor and LCOE. The LCOE calculated for the inherently high capacity GeoTES system was $\$$0.13/kWhe. This value was calculated for the case where the solar thermal collector was sized in such a way that the solar collectors permitted an annual power plant capacity factor of up to 97%. The power cycle was able to provide power to the grid every night of the year, and flexible base-load power during the winter, if needed. This LCOE value compares favorably with reported values for solar photovoltaic plus battery energy storage (PV+BES) systems in the open literature, i.e. $\$$0.148/kWhe for a PV+BES system with 4 hours of electrochemical battery energy storage capacity. Addition of battery energy storage with more hours of storage would further increase PV+BES system LCOE and increase the separation between GeoTES and PV+BES. A GeoTES system would therefore provide superior economics for high capacity and long duration solar energy storage.
14 SOLAR ENERGY↗
A comparison of price-taker and production cost models for determining system value, revenue, and scheduling of concentrating solar power plants
Concentrating solar power (CSP) plants convert solar energy into electricity and can be coupled with low-cost thermal energy storage to provide a dispatchable renewable resource. Maximizing the economic benefits of CSP systems requires deliberate selection of the timing of thermal energy dispatch to coincide with high-price or high-value periods. The performance and value of CSP systems have traditionally been evaluated using two distinct approaches: (1) production cost models (PCMs), which optimize commitment and dispatch schedules for an entire fleet of generators to minimize the cost of satisfying electricity demand; and (2) price-taker (PT) models, which optimize dispatch of the CSP system against historical or forecasted electricity prices to maximize revenue available to the CSP operator. The PCM approach is, in principle, superior because of the ability to capture system-level details such as transmission pathways and associated constraints, and feedback between CSP dispatch schedules and operation of other generators. The computationally simpler PT technique cannot explicitly address these concerns, but the comparative reduction in solution time is attractive for sensitivity analysis and rigorous optimization of CSP plant design and operation. In this work, we directly compare the dispatch profiles, net revenue, and operational value of CSP systems using implementations of each technique to assess how closely the solutions from the PT technique can approach those from the PCM for a specific market scenario. The PT implementation produced characteristically similar dispatch profiles as the PCM for both a large solar-multiple configuration and a small solar-multiple peaking configuration, while requiring only 1% of the computational time of the PCM. In addition, dispatching the CSP plant according to the self-scheduled PT solution - as opposed to the system-optimized PCM solution - only reduced the total CSP operational value by 1-5%, with consistent trends across CSP configurations and locations. This analysis validates the ability of the PT approach to substantially capture the economic benefits of CSP systems when pricing profiles are available, and indicates that the PT approach is suitable for initial design and optimization of CSP technologies.
14 SOLAR ENERGY↗
Dispatch optimization of a concentrating solar power system under uncertain solar irradiance and energy prices
The integration of thermal energy storage into a concentrating solar power system allows for mitigating some of the risk associated with uncertain solar irradiance and uncertain energy prices. We solve a 48 h dispatch optimization model with continually updated conditional point forecasts of both direct normal irradiance (DNI) and electricity prices with a rolling-horizon scheme at hourly resolution over the course of a year. Joint, conditional forecasts for DNI and prices are formed using an autoregressive moving-average time series model with exogenous weather predictors. We guide dispatch using a mixed-integer programming model, but in order to evaluate performance we use the System Advisor Model (SAM) of the National Renewable Energy Laboratory. SAM is a techno-economic simulation model that accounts for plant thermodynamics with higher fidelity. Our conditional DNI forecasts improve annual revenue by 4%–12% over using historical forecasts based on data from previous years. Conditional price forecasts improve annual revenue by 6%–19% in the real-time market over analogous historical forecasts. Updating these forecasts every six hours, rather than every 24 h, further improves annual revenue by 5%–6%. Here, we also investigate a method that values terminal inventory in our dispatch optimization model, again when used in a rolling-horizon scheme.
14 SOLAR ENERGY↗
High Energy Storage Capacity Low Cost Iron Flow Battery
A new flow battery was proposed that utilizes low cost materials: iron as the only active element, cheap aqueous electrolytes, and inexpensive separators. During charging, ferrous iron (Fe 2+ ) is oxidized to ferric iron (Fe 3+ ) at the positive electrode while it (Fe 2+ ) is reduced to form iron metal (Fe 0 ) at the negative electrode. Because iron is plated at the negative electrode during charging, conventional electrode structures couple the energy storage capacity and the power rating of the battery. In order to decouple the energy and power ratings and regain the economic advantages of a flow battery, a slurry electrode design was proposed for use as the negative electrode. The slurry electrode is made by flowing electrically conductive particles in an electrolyte containing the dissolved iron species. On charging, iron is plated onto the particles. The particles can then carry the iron metal out of the cell to be stored in external reservoirs. This project looked to develop a slurry for the negative electrode of the all-iron flow battery that can operate at 200 mA/cm 2 with <100 mV overpotential, be pumped with parasitic energy costs < 10%, and promote plating on the particles. A scalable and stackable cell design of 1100 cm 2 was developed. The project was initially under contract in mid-January 2013. The project was converted from a one-year proof of concept seedling to an additional two-year program, then extended with an 18-month plus-up, and finally with an additional 6-month approved cost-overrun. During the seeding project, the concept of plating on carbon particles in a slurry was demonstrated. However, this was accomplished with high-cost multi-walled carbon nanotubes as the slurry material. The following two-year program discovered several low-cost carbon blacks that could also be used in this application. These findings were supported by an analysis that demonstrated the effectiveness of the carbon that takes into account not just the effective electronic conductivity of the slurry, but also the surface area per volume of the slurry. It was demonstrated that stable, flowable slurries could be created with these carbons, even when the carbons where fully loaded with iron during charging. During the two-year program, laboratory-scale 50 cm 2 single-cells demonstrated charge-discharge cycling at current densities of 150 mA/cm 2 and energy efficiencies of >50%. Meanwhile, cost modeling continued to show promise for this energy storage approach. Following the conversion period, the overall objective of the nominally 18-month plus up period was to close the technical gap of a 25X scale-up and reduce risk to enable commercial investment required to develop a slurry iron flow battery product. A specific objective was to demonstrate 150 cycles of performance exceeding 70% energy efficiency with a 10-cell stack of 1156 cm 2 cells operating at 100 mA/cm 2 . The 10-cell short stack was designed to have a power delivery rating of approximately 1 kW, which represents a size commensurate with the requirements of our commercialization partner at that time. A complete battery support system for the full-size cell was designed, fabricated, and tested. This includes pumps (multiple types were considered, and constant volume hose pumps were found to be acceptable for performance and cost), electrolyte rebalance reactor, and sensors and control systems. The support system proved to be well-behaved and worked well. A new low-cost membrane was developed for this system based on a microporous polymer support with a layer of hydrogel polymer. The membrane had low resistivity, and significantly reduced pressure driven fluid flow across the membrane (as compared to the un-coated microporous support). This membrane approach was scaled-up in conjunction with a commercial toll coating company, and a large amount of membrane was manufactured to support large cell and stack testing. A new concept for an electrolyte rebalance reactor to react hydrogen gas from the negative electrolyte (from plating inefficiency) with excess ferric ion in the positive electrolyte was developed. This design was very simple, low cost, and effective. The full scale 1156 cm 2 single-cell was designed, modeled, fabricated and tested. Modeling showed that uniform flow-distribution should be obtained with the designed flow distributor. The design took into consideration the need to stack the cells, and components were fabricated for a ten-cell stack. Testing of the cell for charge and discharge demonstrated current densities of 50 mA/cm 2 with efficiencies of 50%. However, optimization and long cycling could not be accomplished because the slurry electrode would plug within the cell and block the flow. This would shut down the cell after several charge-discharge cycles. Various approaches were pursued to address this problem with some progress. However, there was not adequate time to find solutions to the problem although several promising approaches were identified for future work. The final deliverable for this proposed 18-month effort was to be a 1 kW, 6 kWh slurry flow battery, with complete balance of plant, ready for testing at an ARPA-E ‘Charges’ site with an estimated capital cost less than $\$ $45/kWh for a six-hour system (excluding power electronics). The deliverable milestone was not achieved for reasons mentioned above related to the slurry plugging. At the completion of this project, it was determined that the cost targets are achievable. The cost estimate for a 1 MW system with a one-hour capacity was estimated at $\$ $140/kWh (including power electronics) and for a six-hour system was estimated at $\$ $40/kWh (including power electronics). These costs include the battery, the balance of plant, the power conditioning and a concrete pad. This program resulted in three patents including the slurry-based iron flow battery, the rebalance reactor, and the membrane separator. At the time of this report, slurry-based iron flow battery patents have been issued in the US, China, Japan, Korea, and Europe. The other patent applications were under various stages of examination. A licensee was identified and the company initiated a scale-up and development program to take this technology to the marketplace, and CWRU staff have transferred their know-how and knowledge base to the company. This technology will enhance the economic and energy security of the United States by enabling the use of intermittent renewable energy technology, such as wind and solar power, as dispatchable resources. This report summarizes the results of this research and development program.
25 ENERGY STORAGE↗
High-efficiency, air-stable manganese–iron oxide nanoparticle-pigmented solar selective absorber coatings toward concentrating solar power systems operating at 750 °C
Solar selective absorber coating with long-term thermal stability at high temperatures ≥750 °C in air is an important component to reduce the levelized cost of energy (LCOE) of concentrating solar power (CSP) systems toward 50% power efficiency and dispatchable solar electricity. Conventionally, solar spectral selectivity requires multilayer-interference coatings implemented by stringently controlled vacuum deposition, and these coatings degrade significantly at >700 °C in air. Herein, we established a quantitative design approach and demonstrated a proof-of-concept air-stable, manganese–iron oxide nanoparticle (NP)-pigmented solar selective coatings with a high solar absorptance of ~93%, a relatively low thermal emittance of ~52%, and an optical-to-thermal energy conversion efficiency >89% under 1,000× solar concentration at 750 °C toward Generation 3 CSP systems. These coatings demonstrate spectral selectivity using cost-effective spray coating approach, a notable improvement over conventional vacuum-deposited, multilayer solar selective coatings for low-cost, high-efficiency solar thermal receivers. In contrast to the thermal degradation of spectrally non-selective benchmark Pyromark 2500 coatings at 750 °C in air, the solar absorptance of the MnFe 2 O 4 -pigmented coatings on stainless steel 310 (SS 310) substrates is increased to ~92.9% and the optical-to-thermal energy conversion efficiency is improved to 89.7% after serving at 750 °C in air for 700 h. X-ray diffraction results reveal that this improvement is due to the transformation of MnFe 2 O 4 NPs into more thermodynamically stable, non-stoichiometric manganese-rich manganese ferrite and iron-rich manganese–iron oxide phases after 500 h aging at 750 °C. For >1,000 h-endurance testing at 750 °C in air and the subsequent 19 day-night thermal cycling between 750 °C (12 h/cycle) and 25 °C (12 h/cycle) on SS 310 substrates, the thermal degradation is mainly due to the CrO x microflake formation from SS 310 substrates rather than the coatings, which can be suppressed by preoxidizing the surface of SS 310. With lower emittance matrix material and further optimization of pigment NP stoichiometry, concentration, and coating thickness, it is promising to achieve an optimized thermal efficiency ≥92.5% with long-term thermal stability at 750 °C for Generation 3 CSP systems.
14 SOLAR ENERGY↗
Hybridizing a geothermal power plant with concentrating solar power and thermal storage to increase power generation and dispatchability
Geothermal power plants often deploy less than their full power capacity due to declining geothermal resources. Integrating heat from a concentrating solar power (CSP) collector field increases the power output at low cost. This article considers five methods of solar heat addition in a double-flash geothermal plant. The most promising solution converts solar heat into electrical work with an efficiency of 24.3%. The economic feasibility and optimal sizing of the solar field and thermal stores are evaluated. A hybrid plant that increases power generation from 22 to 24 MWe has a Levelized Cost of Electricity (LCOE) of 0.07 +/- 0.01 $/kWhe. Adding three hours of storage increases the LCOE to 0.08 +/- 0.01 $/kWhe. Photovoltaic systems are considered to be a low-cost renewable technology, but an equivalent photovoltaic system with battery storage costs 0.15 +/- 0.07 $/kWhe due to the high cost and replacement rate of batteries compared to thermal storage. The hybrid plant also has a lower LCOE than a conventional CSP plant. If the dispatchability that thermal storage provides is rewarded with higher electricity prices, calculations indicate storage becomes an attractive investment when discharged power receives 1.75 times the typical price of electricity.
15 GEOTHERMAL ENERGY↗
Constructing probabilistic scenarios for wide-area solar power generation
Optimizing thermal generation commitments and dispatch in the presence of high penetrations of renewable resources such as solar energy requires a characterization of their stochastic properties. In this study, we describe novel methods designed to create day-ahead, wide-area probabilistic solar power scenarios based only on historical forecasts and associated observations of solar power production. Each scenario represents a possible trajectory for solar power in next-day operations with an associated probability computed by algorithms that use historical forecast errors. Scenarios are created by segmentation of historic data, fitting non-parametric error distributions using epi-splines, and then computing specific quantiles from these distributions. Additionally, we address the challenge of establishing an upper bound on solar power output. Our specific application driver is for use in stochastic variants of core power systems operations optimization problems, e.g., unit commitment and economic dispatch. These problems require as input a range of possible future realizations of renewables production. However, the utility of such probabilistic scenarios extends to other contexts, e.g., operator and trader situational awareness. Finally, we compare the performance of our approach to a recently proposed method based on quantile regression, and demonstrate that our method performs comparably to this approach in terms of two widely used methods for assessing the quality of probabilistic scenarios: the Energy score and the Variogram score.
14 SOLAR ENERGY↗
Collaboration to Enable Higher Penetrations of Solar Power Generation Using the Natural Gas Pipeline System for Energy Storage (CRADA CRD-14-00567)
This unique project explored one possible solution for photovoltaic (PV) generation to become a reliable and dispatchable energy resource similar to conventional baseload fossil fuel electricity generation. Solar power generation is a renewable resource that varies naturally from day-to-day as well as seasonally. To use solar power as a baseload generation asset requires a flexible storage system that can recover power on both a daily and seasonal basis. Converting solar power to natural gas (i.e., first to hydrogen and then to methane) and having access to utility-scale storage in the natural gas network has the potential to make solar power generation a baseload asset. This will: 1) Increase the net energy yield from solar resources by increasing the effective capacity factor and maximize the energy produced during the assets’ lifetimes. 2) Improve the economics of energy storage for solar project developers, thereby accelerating the deployment of new solar generation. 3) Reduce the impact of increasing solar penetration on congestion of the electrical transmission system by shifting power delivery in time using the gas pipeline network for long-duration storage. 4) Reduce the impact of increasing solar generation on electrical distribution system control. 5) Offer alternative revenue sources for solar power generation beyond electricity including: hydrogen (H 2 ) production for stationary fuel cells and fuel cell electric vehicles, conversion of carbon dioxide (CO 2 ) to methane (CH 4 ) as a direct drop-in replacement for fossil natural gas use, and transmission as high volumetrically-dense CH 4 for use in transportation, heating, power generation, chemical production or conversion back to H2 at the point of use. Additional work was added to this CRADA in modification 4 having a primary objective to characterize the performance of the electrolyzer, Southern California Gas (SoCalGas) bioreactor and balance of plant to demonstrate production of renewable natural gas (RNG) from renewable H 2 and CO 2 using single-cell, self-replicating organisms. The additional scope of work allowed researchers to ramp up gas flowrates and pressure of the system over the designed range to grow the cells and begin to show the load-following capabilities of this anaerobic gas fermentation process. These activities enabled the research team to predict system performance at much greater scales; namely 10’s of mega-watts (MWs) of electrolyzer nameplate capacity.
14 SOLAR ENERGY↗
Using Concentrating Solar Power to Create a Geological Thermal Energy Reservoir for Seasonal Storage and Flexible Power Plant Operation
Abstract We propose a hybrid renewable energy system—a geothermal energy storage system (GeoTES) with solar—to provide low-cost dispatchable power at various timescales from daily, to weekly, to seasonally. GeoTES with solar uses a concentrating solar power collector field to produce hot water that is injected into a sedimentary basin to create a synthetic geothermal resource. The stored geothermal heat can then be dispatched when required by the electrical grid. GeoTES is particularly valuable for a grid with a high penetration of non-flexible renewable technologies such as photovoltaic and wind power. In this work, a sophisticated hybrid model is developed to assess the technical and economic potential of GeoTES by combining IPSEpro, which is a power-cycle simulation tool, and SAM, an economic analysis tool by National Renewable Energy Laboratory (NREL). The analysis shows with proper initial charging period that the heat loss in storage is almost negligible and is a suitable technology for long-term energy storage. Various power-cycle options are evaluated, and the most suitable power cycle is selected for further study. Annual calculations of the GeoTES system indicate that a levelized cost of storage (LCOS) of 12.4 ¢/kWh e can be achieved for seasonal storage of 4000 h; this value is much lower than the existing long-term storage. The LCOS of GeoTES is insensitive to the storage duration above 8 h, unlike battery and molten-salt thermal storage systems. This result demonstrates that GeoTES can be a competitive seasonal storage technology in the future electricity market. The levelized cost of electricity of the GeoTES system is also carefully analyzed and can vary between 10.0 and 16.4 ¢/kWh e , depending on solar-collector prices.
25 ENERGY STORAGE↗
Geologic Thermal Energy Storage of Solar Heat to Provide a Source of Dispatchable Renewable Power and Seasonal Energy Storage Capacity
This paper concludes that there is a cost-effective strategy for seasonal storage of heat that will provide firm, but dispatchable, electrical generating capacity in times when other renewable energy is not available to meet demand. Deployment of the technology appears to require no new technology, but instead combines solar, geothermal, and conventional oil and gas drilling technologies in a novel way. The study basis is the use of sedimentary geologic formations as a medium for thermal energy storage (TES), specifically for heat collected in concentrating solar collectors.
40 EE - Geothermal Technologies Office (EE-4G)↗
A hybrid data-driven and model-based approach for computationally efficient stochastic unit commitment and economic dispatch under wind and solar uncertainty
Stochastic unit commitment (UC) and economic dispatch (ED) are imperative in dealing with uncertainty in renewable forecast for power system operation and planning such that the overall expected production cost is minimized over the planning horizon. However, accurate calculation of the expected production cost requires assessment of a very large number of different scenarios of uncertain renewable resources, such as solar and wind, which is practically infeasible to simulate in real time. This article proposes a hybrid datadriven and physics-based model-predictive paradigm to efficiently solve for stochastic unit commitment and economic dispatch considering uncertainty in wind and solar power forecasts. Here, the novelty of the approach lies in decoupling the production cost estimation from the unit commitment and economic dispatch optimization problems under uncertainty without compromising on the fidelity of the solutions. A data-driven machine learning model is first developed to predict the mean optimal production cost. A physics-based inverse problem is then solved to get the stochastic UC and ED profiles from the expected cost. The presented approach considers, for the first time, solar uncertainty in UC/ED determination and enables efficient and accurate propagation of wind and solar uncertainty to estimate the statistics of the production cost. The effectiveness of the developed approach is demonstrated systematically on a stylized RTS-GMLC single-node system. The overall framework predicts the expected cost 62.5% more accurately than the existing state-of-the-art, on unforeseen days during the entire year, and yields, for the first time, the associated physically consistent UC and ED profiles. The solutions are also shown to be flexible in providing adequate daily reserves to address any statistical deviations from probabilistic power forecasts. The computational time associated with the presented method is only about 10 s compared to over 24 h needed for a conventional stochastic UC/ED determination under uncertainty on an Intel Core i9 processor with 32 GB of RAM.
29 ENERGY PLANNING, POLICY, AND ECONOMY↗
Demonstration of a multi-channel fluidized bed particle–supercritical carbon dioxide heat exchanger for concentrating solar applications
High-temperature thermal energy storage in oxide particles at temperatures above 600°C can couple concentrated solar energy with high-efficiency thermal power cycles to provide dispatchable solar-driven electricity. Challenges remain in developing cost-effective primary heat exchangers, which require expensive alloys, to extract the high-temperature thermal energy from the particles to power cycle fluids, such as supercritical CO 2 (sCO 2 ) in recuperated Brayton cycles. To explore one pathway for cost-effective, high-temperature particle heat exchangers, the current study demonstrates a shell-and-plate, particle–sCO 2 heat exchanger with narrow- channel fluidized beds coupled with micro-channel sCO 2 flows in the heat exchanger walls. This study evaluates the feasibility of multiple parallel, narrow-channel fluidized beds in shell-and-plate particle–sCO 2 HXs, to achieve high bed-wall heat fluxes at elevated temperatures. A reduced-order model simulates the narrow- channel, fluidized-bed particle–sCO 2 heat exchanger to design the fluidized bed geometry, in terms of depth, height, and number of channels,for a nominal 40-kWth heat exchanger at particle and sCO 2 inlet temperatures up to 600 °C and 400 °C respectively. The resulting shell-and-plate heat exchanger design operates with bubbling fluidization of the downward-flowing oxide particles to enhance bed-wall heat transfer. The heat exchanger core is fabricated with etched sCO 2 micro-channels in thin wall plates that are diffusion bonded to spacer frames to form the shell-and-plate structure with 12 parallel, fluidized bed channels, 10.4 mm deep. The heat exchanger is tested at the National Solar Thermal Test Facility at Sandia National Laboratories with CARBOBEAD HSP particles at design particle flow rates of 0.20 kg s –1 and inlet temperatures up to 525 °C. Results show that fluidization across multiple parallel channel beds can maintain uniform particle inventory with a common freeboard zone above the heat exchanger core. Bubbling fluidization improves particle–wall heat transfer coefficients but also increases axial dispersion of particle thermal energy, which lowers the log- mean temperature difference such that total heat transfer remains relatively constant to within ±10% over a broad range of fluidization gas velocities. The axial dispersion required particle and sCO 2 flow rates to be increased by 25% over model-designed conditions to achieve the targeted 40 kWth, which indicates the importance of incorporating axial dispersion into heat exchanger design models and of deploying bed structures to suppress it. Furthermore, this study demonstrates the feasibility and preferred fluidizing gas conditions for particle heat exchangers for releasing high-temperature thermal energy storage systems.
14 SOLAR ENERGY↗
CSP ELEMENTS: High-Temperature Thermochemical Storage with Redox-Stable Perovskites for Concentrating Solar Power
This project was motivated by the potential of reducible perovskite oxides for high-temperature, thermochemical energy storage (TCES) to provide dispatchable renewable heat for concentrating solar power (CSP) plants. This project sought to identify and characterize perovskites from earth-abundant cations with high reducibility below 1000 °C for coupling TCES of solar energy to super-critical CO2 (s-CO2) plants that operate above temperature limits (< 600 °C) of current molten-salt storage. Specific TCES > 750 kJ/kg for storage cycles between 500 and 900 °C was targeted with a system cost goal of $15/kWhth. To realize feasibility of TCES systems based on reducible perovskites, our team focused on designing and testing a lab-scale concentrating solar receiver, wherein perovskite particles capture solar energy by fast O2 release and sensible heating at a thermal efficiency of 90% and wall temperatures below 1100 °C. System-level models of the receiver and reoxidation reactor coupled to validated thermochemical materials models can assess approaches to scale-up a full TCES system based on reduction/oxidation cycles of perovskite oxides at large scales. After characterizing many Ca-based perovskites for TCES, our team identified strontium-doped calcium manganite Ca1-xSrxMnO3-δ (with x ≤ 0.1) as a composition with adequate stability and specific TCES capacity (> 750 kJ/kg for Ca0.95Sr0.05MnO3-δ) for cycling between air at 500 °C and low-PO2 (10-4 bar) N2 at 900 °C. Substantial kinetic tests demonstrated that resident times of several minutes in low-PO2 gas were needed for these materials to reach the specific TCES goals with particles of reasonable size for large-scale transport (diameter dp > 200 μm). On the other hand, fast reoxidation kinetics in air enables subsequent rapid heat release in a fluidized reoxidation reactor/ heat recovery unit for driving s-CO2 power plants. Validated material thermochemistry coupled to radiation and convective particle-gas transport models facilitated full TCES system analysis for CSP and results showed that receiver efficiencies approaching 85% were feasible with wall-to-particle heat transfer coefficients observed in laboratory experiments. Coupling these reactive particle-gas transport models to external SolTrace and CFD models drove design of a reactive-particle receiver with indirect heating through flux spreading. A lab-scale receiver using Ca0.9Sr0.1MnO3-δ was demonstrated at NREL’s High Flux Solar Furnace with particle temperatures reaching 900 °C while wall temperatures remained below 1100 °C and approximately 200 kJ/kg of chemical energy storage. These first demonstrations of on-sun perovskite reduction and the robust modeling tools from this program provide a basis for going forward with improved receiver designs to increase heat fluxes and solar-energy capture efficiencies. Measurements and modeling tools from this project provide the foundations for advancing TCES for CSP and other applications using reducible perovskite oxides from low-cost, earth-abundant elements. A perovskite composition has been identified that has the thermodynamic potential to meet the targeted TCES capacity of 750 kJ/kg over a range of temperatures amenable for integration with s-CO2 cycles. Further research needs to explore ways of accelerating effective particle kinetics through variations in composition and/or reactor/receiver design. Initial demonstrations of on-sun particle reduction for TCES show a need for testing at larger scales with reduced heat losses and improved particle-wall heat transfer. The gained insight into particle-gas transport and reactor design can launch future development of cost-effective, large-scale particle-based TCES as a technology for enabling increased renewable energy penetration.
14 SOLAR ENERGY↗
Parametric analysis on optimized design of hybrid solar power plants
There is increasing interest in utility-scale solar power plants with storage which can flexibly dispatch renewable energy to the grid. However, plant design possesses many degrees of freedom and non-obvious trade-offs in performance. Software tools can estimate or optimize the performance of a specific plant configuration under market and weather conditions of interest; the associated cost parameters and operating assumptions strongly influence estimates of plant performance and decisions regarding optimal sizing. We employ the National Renewable Energy Laboratory's Hybrid Optimization and Performance Platform, which incorporates optimal dispatch when evaluating plant performance, and investigate the sensitivity to weather and market conditions, operating limitations, and the presence of a capacity-based incentive. We demonstrate changes in plant performance and optimal sizing with respect to these inputs and discuss implications. Here results show that PV-with-battery designs are more profitable under our assumptions, but that designs including a concentrated solar power (CSP) system produce significantly greater annual energy; and that CSP-with-thermal energy storage designs maximizing the benefit-to-cost ratio have an input-dependent linear relationship between the CSP field solar multiple and the hours of storage as the project budget varies.
14 SOLAR ENERGY↗
Ceramic–metal composites for heat exchangers in concentrated solar power plants
The efficiency of generating electricity from heat using concentrated solar power plants (which use mirrors or lenses to concentrate sunlight in order to drive heat engines, usually involving turbines) may be appreciably increased by operating with higher turbine inlet temperatures, but this would require improved heat exchanger materials. By operating turbines with inlet temperatures above 1,023 kelvin using closed-cycle high-pressure supercritical carbon dioxide (sCO 2 ) recompression cycles, instead of using conventional (such as subcritical steam Rankine) cycles with inlet temperatures below 823 kelvin, the relative heat-to-electricity conversion efficiency may be increased by more than 20 per cent. The resulting reduction in the cost of dispatchable electricity from concentrated solar power plants (coupled with thermal energy storage) would be an important step towards direct competition with fossil-fuel-based plants and a large reduction in greenhouse gas emissions. However, the inlet temperatures of closed-cycle high-pressure sCO 2 turbine systems are limited by the thermomechanical performance of the compact, metal-alloy-based, printed-circuit-type heat exchangers used to transfer heat to sCO 2 . We present a robust composite of ceramic (zirconium carbide, ZrC) and the refractory metal tungsten (W) for use in printed-circuit-type heat exchangers at temperatures above 1,023 kelvin. This composite has attractive high-temperature thermal, mechanical and chemical properties and can be processed in a cost-effective manner. We fabricated ZrC/W-based heat exchanger plates with tunable channel patterns by the shape-and-size-preserving chemical conversion of porous tungsten carbide plates. The dense ZrC/W-based composites exhibited failure strengths of over 350 megapascals at 1,073 kelvin, and thermal conductivity values two to three times greater than those of iron- or nickel-based alloys at this temperature. Corrosion resistance to sCO 2 at 1,023 kelvin and 20 megapascals was achieved by bonding a copper layer to the composite surface and adding 50 parts per million carbon monoxide to sCO 2 . Finally, techno-economic analyses indicate that ZrC/W-based heat exchangers can strongly outperform nickel-superalloy-based printed-circuit heat exchangers at lower cost.
36 MATERIALS SCIENCE↗
FY19-FY21 Concentrating Solar Power Systems Analysis Final Report
This technical report summarizes work done by NREL over a 3-year period for the Concentrating Solar Power (CSP) Systems Analysis project for fiscal years 2019-2021 (FY19-FY21) in support of the Solar Energies Technology Office of the U.S. Department of Energy. The goal of the CSP Systems Analysis project is to provide timely and accurate CSP cost data to the U.S. Department of Energy's (DOE's) Solar Energy Technologies Office (SETO) and to project the performance and cost of emerging CSP technologies to inform research directions and industry investment.
14 SOLAR ENERGY↗