Download PDF Fall Issue of The Bridge on Nuclear Energy Revisited September 15, 2020 Volume 50 Issue 3 The desire to reduce the carbon intensity of human activities and strengthen the resilience of infrastructure key to economic prosperity and geopolitical stability shines a new spotlight on the value and challenges of nuclear energy. Maximizing Clean Energy Use: Integrating Nuclear and Renewable Technologies to Support Variable Electricity, Heat, and Hydrogen Demands Friday, September 18, 2020 Author: Charles W. Forsberg and Shannon M. Bragg-Sitton Fossil fuels are hard to beat: low cost, easy to store, and easy to transport. They enable the economic provision of variable electricity and heat to the customer because the capital cost of power plants, furnaces, and boilers is small relative to the cost of the fuel. It is economic to operate fossil plants at part load—the money is in the fuel. But concerns about environmental emission of carbon dioxide (CO2) may limit the continued use of fossil fuels. To reduce CO2 emissions, the primary energy options to meet electricity and heat demand are nuclear, wind, solar, hydro, and fossil fuel generators with carbon capture and sequestration (CCS). These energy sources have relatively high capital costs and relatively low operating costs. Operating high-capital-cost technologies at reduced load significantly increases the average cost of energy. Furthermore, no combination of these resources matches the variable demand for heat and electricity unless they are periodically operated at reduced capacity in a “load following” mode. The question addressed in this paper is how to leverage multiple energy sources to meet variable energy demands at the lowest cost to the consumer while simultaneously reducing CO2 emissions and meeting stringent requirements for reliability and resilience. Production of Heat and Electricity The starting point is to consider what the customer needs. Figure 1 shows energy sources (left column) and uses (brown column) in the United States adapted from a Sankey diagram (LLNL 2020) where (i) wind, solar, and hydro have been combined into a single renewable energy input and (ii) natural gas, coal, and petroleum are combined to create the fossil energy input. Fossil fuels are 80 percent and renewables 6 percent of the energy input. About half the renewable input is from hydro resources, and all of it is dependent on the weather. Most energy is consumed in the form of heat—what fossil fuels provide. The heat demand across all energy sectors far exceeds electricity use—83 percent versus 17 percent of the energy use sector demand. In the industrial sector, 88 percent of the energy use is heat (LLNL 2020). The transport sector uses heat for internal combustion engines and jet engines. The commercial and residential sectors use approximately equal amounts of heat and electricity. Figure 1 In total energy consumption across all generating technologies, the data in figure 1 reveal that two-thirds of generated energy is rejected while only one-third supports energy services (far right column). In the electricity sector the rejected heat is from the conversion of heat to electricity as a result of thermodynamic and engineering limits of heat engines. Nuclear energy, like that of fossil-fueled generators, is dispatchable, meaning that energy is available when it is needed—on demand. Wind and solar output are dependent on local wind and solar conditions; hydroelectricity is either variable (run-of-the-river hydro) or dispatchable (dam). However, of equal importance is that nuclear reactors produce heat (the primary energy product used by society), whereas hydro, wind, and solar photovoltaic (PV) produce electricity. The laws of thermodynamics dictate that several units of heat are required to produce a unit of electricity. Typical light water reactors (LWRs) have a heat-to-electricity efficiency of 33 percent, so the cost of heat is roughly a third that of electricity. As a consequence, nuclear energy and other thermal generators, such as fossil fuels, produce low-cost heat and more expensive electricity. Direct electricity sources (hydro, wind, and PV) produce heat via resistance heating, resulting in higher-cost heat. More efficient electricity-to-heat technologies such as electrically driven heat pumps have proven viable only near room temperature. Table 1 Table 1 reports the levelized cost of electricity (LCOE) and heat (LCOH). Most industrial customers want constant heat input, while other customers have relatively uniform electricity demands when averaged over several days with the exception of heating and cooling demands. The outputs of wind and solar do not match constant demand because they vary on a daily to seasonal basis. Figure 2 Figure 2 shows the smoothed wind and solar production and electricity demand in California over one year (where smoothing averages the higher-frequency daily and weekly variations). To provide significant electricity and/or heat, wind and solar technologies would need to include the additional cost of energy storage to match production to demand. Finally, the cost of transmission and delivery (NEA 2019) must be included, approximately doubling the cost of electricity to the consumer relative to the production cost. Hence, use of grid electricity to support thermal energy demands is about six times the cost of natural gas–derived heat. The large cost differences between heat and electricity have significant implications. The industrial superpowers of the 21st century will likely be those countries that successfully integrate industrial heat demand with nuclear energy or fossil fuels with CCS. Large heat consumers could be supported by nuclear reactors. Smaller industrial facilities, however, may shift to industrial parks in which heat is provided by common nuclear or fossil systems with CCS. Only some locations are suitable for CO2 sequestration. Thus, low-carbon futures without nuclear energy imply industry movement to locations with low-cost natural gas and CO2 sequestration sites (e.g., Texas). Recent studies indicate large differences in the capital cost of nuclear power with location: low costs in China, South Korea, and Japan and much higher costs in western countries (Buongiorno et al. 2018; Gogan et al. 2018). Capital cost differences primarily reflect the differences between serial production in Asian countries versus low rates of nuclear plant construction in western countries where each new plant essentially is a first-of-a-kind plant. For western countries to remain industrial powers in a low-carbon world, a secure nuclear power supply chain is a priority to lower energy costs. A low-carbon world also favors deployment of high-temperature reactors (e.g., high-temperature gas-cooled reactors [NGNP 2011] and salt-cooled reactors [Forsberg 2020]) that can meet a larger fraction of industrial heat demand and can operate at higher thermal-to-electric efficiencies. Integrating Energy Sources with Heat Storage Modeling studies of low-carbon electricity grids (Sepulveda et al. 2018) show that the lowest-cost systems are some mixture of dispatchable (nuclear and fossil with CCS) and nondispatchable (wind and solar PV) systems. These models include electricity storage and methods of demand management. If an electrical system primarily comprised wind and solar PV, it would typically double the cost of electricity because of the high costs of overbuilding renewable capacity and associated electricity storage systems required to meet demand. Similarly, the high capital cost of nuclear reactors creates incentives for steady-state operation that may not match the demand for heat and electricity. The question is then how to create a low-cost energy storage system that enables efficient use of nuclear and renewable technologies. There are three primary options for large-scale storage media: electricity storage (e.g., pumped hydroelectric facilities and batteries), heat storage, and chemical storage (e.g., hydrogen and its derivatives, such as ammonia) that can be stored in tanks or geological formations. Heat storage couples to heat-generating technologies (e.g., nuclear), whereas electricity storage technologies couple to wind, solar PV, and the grid. Figure 3 A system design that incorporates nuclear-coupled heat storage while supporting peak demand is shown in figure 3. The nuclear reactor operates at baseload to minimize the cost of energy production with heat output that can go in several directions: upward to the power conversion block that converts heat to electricity, downward to the industrial heat market, and to the right into heat storage. Solar PV and wind produce electricity that goes to the grid. The central box, heat storage, can receive heat from several sources. Most of the heat comes from the nuclear reactor at times of low demand for electricity and industrial heat. If there is low-price electricity, grid electricity can be converted into stored heat using resistance heaters coupled to the heat storage system. Last, if heat storage is depleted, a combustion heater can produce heat as needed by burning natural gas or low-carbon hydrogen/biofuels. The stored heat can be used for three purposes: it can be converted to electricity at times of high demand—adding to the electricity from the nuclear reactor heat-to-electricity power cycle, wind, and PV; it can be sent to industrial or commercial customers; or it can be used for hydrogen production (discussed later). Heat storage makes it possible to balance production with demand while the relatively high-capital-cost nuclear, wind, and solar facilities operate near full capacity—their most economic operating mode. Cogeneration of electricity and heat directly links the industrial heat market to electricity markets. Coupling the industrial sector with the electricity sector via storage adds a new dimension to balancing production with demand. Unlike traditional cogeneration where one must match production with demand on a second-by-second basis, the requirement is to match production with demand over a period of several days. Many industrial processes have the capability to vary their heat input over a period of hours or days but not over short periods of time. Storage enables industrial systems to optimize heat consumption in a way that maximizes electricity and product revenue, in parallel with decarbonization of the industry and electricity sectors. Heat Storage Technologies There are many heat storage technologies that could couple to nuclear reactors (Forsberg 2019; Forsberg et al. 2019). Many were first developed for concentrated solar power (CSP) systems. The largest CSP storage systems store heat in liquid nitrate salts where the temperature varies from 285°C to 565°C. Cold nitrate salts enter the CSP system, are heated, and are then sent to the hot-salt storage tank, such that there is no efficiency penalty in charging the storage system—unlike what is experienced for pumped hydro or battery storage. Hot nitrate salt is sent to steam generators where water is converted into steam to drive the power cycle. The resulting cold salt is sent to the cold-salt storage tank and ultimately back to the CSP system to be reheated. Multiple hot and cold nitrate salt storage tanks are in use, capable of storing several gigawatt hours (GWh) of heat, with typical dimensions of 40 meters in diameter and 12 meters high. If such heat storage systems are coupled to high-temperature reactors, the nitrate salt loop that incorporates storage replaces the intermediate heat transfer loop that separates the reactor from the power cycle. As in CSP plants, there is no efficiency loss in adding heat storage to such a system—only slow small losses through insulated storage system components, as would be inherent to any thermal system (although insulation minimizes losses due to heat transit through the component and piping walls, it is not possible to fully eliminate heat loss). Other CSP systems use heat transfer oils with operating temperatures below 400°C. These heat storage systems are compatible with existing LWRs with peak temperatures of ~300°C. Today CSP plants store hot and cold nitrate salt or oil in large tanks. Second-generation systems (under development) fill the storage tanks with crushed rock or other lower-cost fill materials to provide lower-cost heat capacity and thereby reduce the required quantities of nitrate salts (Odenthal et al. 2019) or oils (Amuda and Field 2020; Kluba and Field 2019) in the tanks. Proposed third-generation systems for heat storage capacities up to 100 GWh (Forsberg 2020) store heat in crushed rock in insulated trenches up to 60 meters wide, 20 meters high, and a kilometer long with insulated roofs. Hot oil or hot salt from the reactor is sprayed over and heats sections of crushed rock as it flows down to the collection pan under the crushed rock. The oil or salt is then cycled back to the reactor to be reheated. At times of high electricity demand, cold oil or salt is sprayed on the hot rock, flows through the rock to the collection pan, and is sent to the power block or industrial customer. The US Department of Energy goal for the capital cost of heat storage systems is $15/kWh of heat. Commercial nitrate salt storage systems cost ~$20/kWh (Forsberg et al. 2019), with the goal to reduce capital costs by an order of magnitude with third-generation systems (Forsberg 2020). Current commercial heat storage system costs per unit of electricity are a factor of 3 to 4 less than electricity storage technologies, reflecting lower-cost materials of construction (i.e., crushed rock and thermal salts versus lithium, cobalt, or steel). The cost difference reflects the fundamental difference between storing heat versus work (electricity). The largest deployed energy storage technology today is hydro pumped storage; however, the cost and availability of this technology is strongly dependent on location. Advanced heat storage technologies may be economic for periods of a week or more, but not for seasonal heat storage. Geothermal heat storage (Forsberg 2012) enables seasonal storage. In a geothermal storage system hot water or steam is used to heat rock ~1000 meters underground. This technology depends on appropriate geology and is in the early stages of development. Hydrogen Systems: The Other Energy Carrier The United States consumes 10 million tons of hydrogen per year to produce liquid fuels, chemicals, and fertilizer. The hydrogen market could reach 18 percent of energy consumption by 2050 (Miller et al. 2020). In a low-carbon world hydrogen is a chemical reagent in the production of fertilizer, metals, and biofuels; for example, it replaces fossil fuels as a chemical reducing agent in the production of steel (Millner et al. 2017) and other materials. Future markets may include hydrogen use in fuel cells for vehicle transport and hydrogen combustion as a high-temperature heat source for industry (e.g., for cement production), although in these markets there are competitive alternatives. There are two primary hydrogen production options: reforming and water splitting. Steam methane reforming (SMR) of fossil fuels (where inclusion of CCS, currently not used, would reduce carbon emissions) is the predominant method of hydrogen production. Hydrogen is in a chemically reduced form as a component of methane (CH4), whereas for water-splitting processes it is in its oxidized form—water (H2O). In SMR, natural gas and steam are converted to hydrogen and CO2, taking less energy than electrolytic processes. In a low-carbon world, SMR is expected to be the economic option in locations with low natural gas prices and good carbon sequestration sites. Water splitting for hydrogen production is accomplished via low-temperature electrolysis of water using electricity, high-temperature electrolysis (HTE) of steam, or thermochemical hydrogen production from water with heat input. These processes are less technically mature than SMR (Dinh et al. 2017). However, HTE has an economic advantage because part of the energy input is in the form of steam that costs less than electricity, no expensive catalyst is required, and the process is more efficient in converting water to hydrogen and oxygen. While one cannot predict technological futures, the expectation is that HTE will become the low-cost electrolytic route. Hydrogen production facilities are capital intensive with large economies of scale. Because it is uneconomic to operate them at low capacity factors, they may need to operate more than 80 percent of the time (Boardman et al. 2019). Figure 3 shows a hydrogen plant embedded in a system that includes nuclear and renewable generators and heat storage. At times of low electricity prices, electricity from the grid can be used for HTE while lower-value heat from the nuclear plant is directed to storage and the HTE unit. At times of high electricity prices, heat from the reactor and heat storage produce peak electricity with no hydrogen production. This system has several characteristics: Hydrogen storage. Large-scale hydrogen storage, on an hourly to seasonal basis, is inexpensive through use of the same underground storage facilities used for natural gas. Hence, stopping hydrogen production does not disrupt the hydrogen supply to the customer. Electricity sink. The system design allows wind and solar electricity at times of low prices to produce, with nuclear heat, higher-value hydrogen while excess heat from the nuclear plant is directed to lower-cost heat storage. Capital-intensive nuclear, wind, solar, and hydrogen facilities are all operated at high capacity factors. Seasonal mismatch. Seasonal mismatch between generation and demand (figure 2) can be partly addressed by nuclear-renewable-hydrogen production systems where the nuclear plant produces hydrogen most of the year but can be redirected to provide electricity when needed. Nuclear-driven hydrogen production facilities show technical and economic potential in some US markets (Boardman et al. 2019; Frick et al. 2019), and US utilities are working to demonstrate these technologies at existing LWR power plants (Dillon and Klump 2019; Wald 2019). Conclusions There has been less than a decade of work to understand how to deploy a low-carbon energy system. Work is underway to develop integrated system approaches (Bragg-Sitton et al. 2020a,b). While the details depend on technology developments, three factors will drive system design and the roles of nuclear, wind, and solar: Heat versus work. Nuclear reactors produce heat that couples to low-cost heat storage technologies, whereas wind and solar PV produce electricity that couples to higher-cost electricity storage technologies. This implies different roles in a low-carbon energy system. Low-carbon fossil fuel systems with CCS generate heat and thus play the same role as nuclear in this system. Capital cost. All low-carbon energy production systems have relatively high capital costs and low operating costs. Operating these systems at low capacity factors results in expensive energy. Low-cost storage (heat and hydrogen) may enable these energy production technologies to operate at high capacity factors to minimize energy production costs. Energy transport. Fossil fuels are inexpensive to transport, resulting in relatively flat worldwide energy prices. Heat can be transported efficiently over short distances, but suffers significant losses over longer distances. Electricity and hydrogen have high transport costs relative to fossil fuels, but can be efficiently moved over longer distances. Wind and solar are location dependent, while nuclear energy systems can be deployed almost anywhere. These differences imply a future low-carbon energy world with large differences in energy production methods as a function of location, as well as large geographical differences in energy costs. The fundamental characteristics of different energy generation and storage technologies cannot be changed by technological advances. 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Heat storage systems using latent or thermochemical heat are under development, but most of this work is in the research phase (Barnes and Levine 2011). About the Author:Charles Forsbrg is principal research scientist in the Department of Nuclear Science and Engineering at the Massachusetts Institute of Technology. Shannon Bragg-Sitton is the lead for integrated energy systems in the Nuclear Science and Technology Directorate at Idaho National Laboratory.