5
Beyond Electricity: Nuclear Power’s Potential to Play a Broader Role in the Future Energy System
Decarbonizing the electric power sector is necessary to avert the worst consequences of climate change, but it is not sufficient: energy-related carbon dioxide emissions extend to the buildings, transportation, and industrial sectors as well. Some of these sectors cannot be electrified for technical reasons, or it might be cost-prohibitive to do so. New and advanced nuclear power technologies have the potential to provide a range of energy services other than electricity. For example, they produce large amounts of heat that can be leveraged for useful purposes: either nuclear electricity or nuclear heat can be used to desalinate water or produce synthetic fuels1 like hydrogen, ammonia, and gaseous and liquid hydrocarbons. If carbon constraints tighten, and as the energy system begins transitioning to one that better values some of these other services, nuclear reactors have the potential to decarbonize non-electric but carbon-intensive sectors of the economy. However, employing nuclear power for these novel applications raises serious technical, economic, and regulatory challenges that must be resolved for any expanded deployment to be realized. This chapter will briefly describe these non-electric applications, how the reactors discussed in this report could serve them, and the significant emergent challenges that must be resolved.
APPLICATIONS BEYOND ELECTRICITY
As shown by Figure 5-1, buildings, transportation, and industrial sectors all are substantial users of energy and emitters of greenhouse gases, and some of that demand is in the form of thermal energy, which could be produced without electricity. Because nuclear reactors produce substantial amounts of heat, their services could expand beyond the electricity sector. With advanced reactor output temperatures up to 800°C, a wide range of non-electric services is possible; some are listed in Table 5-1. Broadly, these services can be clustered into three categories: industrial products, district heating, and water desalination.
Whether nuclear power can be used for a service beyond electricity, and which reactor type is most technically appropriate, depends mainly on the temperature required for the application. Figure 5-2 displays the temperature requirements for various uses of the heat from a reactor. Note that collocation of the reactor and the industrial/heat
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1 There are several different definitions of the term synthetic fuel. The more traditional definitions refer to synthetic fuels as any liquid transportation fuels produced from coal, natural gas, or biomass feedstocks through chemical conversion. Other definitions also include industrial and municipal waste as well as oil sands and oil shale as synthetic fuel sources. Depending on the context, hydrogen, ammonia, methanol, and ethanol can also be referred to as synthetic fuels.
application is necessary as heat cannot be transported over long distances and siting restrictions could impede the deployment of a nuclear reactor to serve some applications. This requires thoughtful consideration and analysis because the reactor may impose risk on the adjacent facility using the heat, and there may be a risk to the nuclear plant arising from that facility which may involve hazardous materials itself. This confluence of risks introduces additional regulatory challenges when it comes to siting, the development of emergency planning zones, and emergency response.
In principle, none of these potential industrial applications is novel: the Department of Energy had a Nuclear Hydrogen Initiative at the turn of the century, when climate change grew in prominence as a topic of public and political debate. A robust narrative was constructed around a “hydrogen economy” (Tseng et al. 2005; Scita et al. 2020); once interest in hydrogen dissipated, the interest in leveraging nuclear for hydrogen production also diminished. Moreover, some nuclear power plants (NPPs) already supply heat to district heating systems. What is new is the higher temperatures that some advanced nuclear systems could provide, the potential cost reductions that might be achieved through innovative design and manufacturing processes, and the growing interest in integrating non-electric energy services so that nuclear reactors might better compete in a power system that is increasingly served by variable renewable energy resources.
Multiple paradigms are envisioned that integrate non-electric applications into future nuclear reactor deployments. Whenever nuclear reactors are combined into larger systems that are intended to produce products other than heat or electricity, the combined systems are called integrated energy systems (IES).2 NPPs could be deployed to exclusively provide energy services to industrial customers, instead of dispatching electricity to the grid. In this scenario, they could be dedicated to heat production (e.g., for petrochemical facilities), hydrogen generation
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2 For more on integrated energy systems see Integrated Energy Systems, 2023, “What Are Integrated Energy Systems?,” ies.inl.gov.
TABLE 5-1 Possible Energy Products Provided by Nuclear Energy Systems
| Energy Service | Elaboration on Technical Readiness | Temperature Range (°C) |
|---|---|---|
| Industrial products Hydrogen | Multiple hydrogen production pathways exist, and electrolysis of water is among the most mature technological pathways for clean hydrogen production. The three most common electrolysis technologies are alkaline,a polymer electrolyte membrane (PEM) and solid oxide electrolysis cell (SOEC). PEM electrolysis requires electricity, and the systems operate at ~100°C. SOECs require both electricity and heat, and the systems operate at temperatures of between 500°C and 1000°C. Hundreds of high-temperature thermochemical splitting cycles have been proposed; they require temperatures of between 500°C and 2000°C, making them most suitable to integrate with non-LWRs. High-temperature systems also require the development of improved heat exchangers. | ~100 (PEM) 500–1,000 (SOEC) 500–2,000b (thermochemical splitting) |
| CO2 reduction to fuels | The production of carbon-neutral synthetic liquid fuels (e.g., diesel, jet fuel, motor gasoline) would entail the electrocatalytic reduction of carbon dioxide. It also requires hydrogen, water, electricity, and heat. Moreover, it requires the integration of the nuclear reactor with SOECs, a Fischer–Tropsch process or a Mobil process, and balance of plant components (such as distillation units). | 500–1,000 |
| High-temperature process heat | Required for ammonia synthesis and steam methane reforming. To meet process heat needs, materials and components such as heat exchangers must be developed that work at these temperatures. | >500 |
| Lower-temperature process heat | Required for paper and pulp manufacturing. Moreover, many chemical applications (including many separation processes) require thermal energy at temperatures below 250°C. | ~300 |
| Steel production | Thermal energy is required to preheat iron ore pellets to approximately 850°C: some advanced nuclear reactors could directly provide heat at that temperature, or power electrified steel production equipment. | ~850 |
| Cement production | Cement production is a complex process that involves three distinct steps for converting limestone-bearing feed: (1) preheating from room temperature to approximately 660°C; (2) calcination of calcium carbonate at approximately 900°C; (3) calcination completion and sintering of calcium oxide up to approximately 1450°C. Thermal output from advanced nuclear is directly suitable for preheating the limestone-bearing feed and is almost at the temperature ranges required for the calcination process. Heat augmentation is required to provide the thermal energy required to complete the calcination and sintering processes. | 660–1,450 |
| District energy | District energy network technology is mature, but proximity to the community is essential, because heat cannot be transported over long distances. All reactor concepts are suitable with a low temperature heat extraction loop. Alternatively, community space and water heating can be electrified with large amounts of low-carbon electric power from nuclear power. | 80–100 |
| Water desalination | Multiple desalination systems are technologically mature and are declining in cost. Multi-stage flash distillation (MSF) requires temperatures of 70°C to 130°C. Reverse osmosis (RO) requires electricity, rather than thermal energy: the output of RO systems is diminished at both low (<10°C) and high temperatures (>38°C). All reactor concepts are suitable with a low temperature heat extraction loop. | 70–130 (MSF) <38 (RO) |
a Alkaline water electrolysis has the longest history and is currently the cheapest among all the water electrolysis technologies for hydrogen production. However, the system efficiency and hydrogen purity deteriorate when the technology is subject to flexible operations making it harder to integrate with variable renewable sources and a future grid with substantial amounts of variable generations. Thus, it is not the focus of this chapter.
b Note that advanced reactors would require heat augmentation to provide the total thermal energy for applications that require temperatures that are higher than their outlet temperatures.
SOURCES: Committee generated using information from R.D. Boardman, M.G. McKellar, B.D. Dold, A.W. Foss, and H.C. Bryan, 2021, “Process Heat for Chemical Industry,” Encyclopedia of Nuclear Energy 3, https://doi.org/10.1016/b978-0-12-819725-7.00198-7; S.M. Bragg-Sitton, C. Rabiti, R.D. Boardman, et al., 2020, Integrated Energy Systems: 2020 Roadmap, INL/EXT-20-57708-Rev.01, Idaho Falls, ID: Idaho National Laboratory, https://doi.org/10.2172/1670434; M. Fisher, A. Constantin, and J. Liou, 2021, “The Use of Nuclear Power Beyond Generating Electricity: Non-Electric Applications,” IAEA, October 18, https://www.iaea.org/newscenter/news/the-use-of-nuclear-power-beyond-generating-electricity-non-electric-applications; M.A. Rosen, 2020, “Nuclear Energy: Non-Electric Applications,” European Journal of Sustainable Development Research 5(1):em0147, https://doi.org/10.29333/ejosdr/9305.
(e.g., to serve petrochemical, the industrial, heating, or transportation sectors), or ammonia and synthetic fuels production. Alternatively, an NPP could be deployed to produce electricity to the grid as well as other products such as hydrogen. Insofar as electricity is concerned, these integrated energy systems would provide the flexibility to dispatch electricity to the grid while taking advantage of grid price signals by ramping up and down energy supplies to the industrial processes. These load following capabilities have the potential to enhance grid reliability and could allow reactors to gain an additional revenue stream in selling another product such as hydrogen. The economic viability of these grid-integrated systems will vary significantly by location and products.
For these integrated energy system concepts to work, alignment and coordination is required among facilities, some of which might be owned and operated by different (or even competing) firms. Also, important to consider is that the investment and development cycles of different industrial facilities differ—refineries can last a century, chemical plants decades, and fuel cell stacks are short-lived—making coordinated and synergistic investment in NPPs to serve those facilities’ energy needs necessary and potentially challenging. This challenge is not insurmountable, but it is extremely serious, and efforts must be made to ensure that the interests of companies that are investing in an integrated plant are aligned and will remain so for the long lifetime of a nuclear reactor.
The following subsections briefly describe potential non-electric applications: clean hydrogen, ammonia and synthetic fuels production, industrial process heat, district heating, and water desalination. As discussed in Box 5-2
later in this chapter, there may be opportunities to reconfigure some current uses of energy in more radical ways than are discussed here to curtail carbon emissions.
Finding 5-1: In principle, nuclear power has the versatility to provide a range of non-electric services to the whole energy system. These services themselves need to be decarbonized, and the emissions of some could prove hard to abate without a high-temperature, zero-carbon energy source, such as nuclear power. Moreover, experience exists and is growing that some of these services can be provided with nuclear power.
Recommendation 5-1: Industrial applications using thermal energy present an important new mission for advanced reactors. Key research and development needs for industrial applications include assessing system integration, operations, safety, community acceptance, market size as a function of varying levels of implicit or explicit carbon price, and regulatory risks, with hydrogen production as a top priority. The Department of Energy, with the support of industry support groups such as the Electric Power Research Institute and the nuclear vendors, should conduct a systematic analysis of system integration, operation, and safety risks to provide investors with realistic models of deployment to inform business cases and work with potential host communities.
Nuclear–Hydrogen Integrated Energy Systems and Their Potential Role in Deep Decarbonization
Hydrogen has the potential to enable decarbonization in almost all sectors of the economy. It can be directly employed either in a fuel cell or combustion turbine to produce electricity or can provide long-duration energy storage that enhances the reliability and resilience of the future power system. It can be combusted to produce thermal energy or can be used as a chemical feedstock. It is already used in a variety of manufacturing processes, including petroleum refineries, chemicals, metal refining, steel, and ammonia production. More importantly, it can be applied in the future in sectors of the energy system that are difficult or expensive to electrify, such as some industrial processes and some elements of the transportation system that require a carbon-neutral synthetic fuel (e.g., heavy-duty trucks, marine transport, and aircraft).
Hydrogen could also be phased into the existing gas system, first by blending it into natural gas pipelines (up to 20 percent hydrogen by volume without any major modifications3), and then by converting pipelines and end use systems to use 100 percent hydrogen (technologies for pipelines and turbines already exist). This would allow hydrogen to contribute to decarbonization of sectors beyond electric power generation as a replacement for natural gas.
Elemental hydrogen (H2) does not occur naturally in the earth. Rather, it is chemically bound to other elements, and energy must be used to break chemical bonds such as those forming methane (CH4) or water (H2O) to obtain elemental hydrogen. Currently, most hydrogen worldwide is produced using steam methane reforming, a process in which natural gas is heated in the presence of steam and a catalyst to produce carbon monoxide and hydrogen. The carbon monoxide is then converted to CO2 and emitted into the atmosphere. According to the IEA, currently the global hydrogen production releases 830 million tons of CO2 per year, which accounts for 2.2 percent of total energy-related emissions. For hydrogen to contribute to the net-zero transition, it must be produced at much lower carbon intensities than this. Fortunately, there are multiple low-carbon hydrogen production pathways (see Table 5-1 for some of the most promising clean hydrogen production technologies enabled by nuclear energy): this versatility makes nuclear production of hydrogen a promising means for decarbonizing industry, transportation, and buildings.
Driven by their long-term decarbonization goals, major economies such as the United States, Canada, and the European Union have envisioned an overarching role for hydrogen in low-carbon energy systems by mid-century, reflected in their governmental hydrogen roadmaps (DOE 2020a; EC 2020; NRC 2020). Indeed, the global hydrogen market is expected to grow from around 90 MT to more than 500 MT by 2050 (IEA 2021a). Table 5-2 presents some key hydrogen demand streams that are being envisioned.
Hydrogen produced by NPPs could potentially meet some of these demands. Hydrogen may be produced at an NPP at a central location and delivered to its end users through dedicated pipelines or other means of transport.
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3 Hydrogen blends above 5 percent could cause pipeline degradation and leaks.
TABLE 5-2 Potential Hydrogen Use Cases and Demand Trends in a Decarbonized United States
| Use Case | Description |
|---|---|
| Fuel cell electric vehicles (FCEVs) | FCEVs could witness some level of market penetration, alongside battery electric vehicles (BEVs). Compared to BEVs, FCEVs could enable longer-range travel, higher powera and faster recharge rates. Medium and heavy-duty vehicles could transition to hydrogen use before light-duty vehicles. |
| Blending hydrogen with natural gas | Hydrogen can be injected into existing natural gas pipelines to reduce the fuel’s carbon intensity. Up to 20 percent hydrogen (by volume) can be mixed with natural gas in existing pipelines without major modifications to the pipelines. There are ongoing R&D efforts to develop combustion turbines and appliances that can handle hydrogen concentrations of up to 100 percent—some of these technologies are already available—which would require hydrogen-compatible pipeline infrastructure. According to the IEA’s net-zero scenario, the demand for hydrogen blended in natural gas sees the greatest growth among all sectors between 2020 and 2030 (IEA 2021a). However, there are different views on this potential hydrogen uptake in the literature: its evolution could depend on the success of demonstration projects (FCH JU 2019). |
| Petroleum refineries | Petroleum refineries are the most significant users of hydrogen today. About two-thirds of the hydrogen needed at U.S. petroleum refineries is produced onsite using steam methane reforming. Hydrogen is primarily used for hydrocracking and hydrotreating to upgrade crude oil to distillates like gasolines, diesel fuels, or jet fuels. This use of hydrogen could decline in the future if fossil fuel use declines. |
| Direct reduced iron for metal refining and steel production | The direct reduction of iron (DRI) uses natural gas as a reducing agent and then converts the high-purity iron to steel in an electric arc furnace (EAF). However, up to 30 percent hydrogen by energy can be blended with natural gas without major modification to plant design, reducing CO2 emissions. Also, DRI designs exist which use 100 percent hydrogen as the reducing agent (Hybrit n.d.). In the United States, the amount of steel produced by DRI-EAF in 2017 already accounted for 68 percent of its total production. The iron and steel sectors are expected to grow (IEA 2019), and the provision of clean hydrogen for DRI-EAF could help decarbonize these sectors. |
| Ammonia and fertilizers | Ammonia is produced by the Haber-Bosch process, which reacts hydrogen and nitrogen at high temperatures and pressures. The hydrogen is derived through steam methane reforming. Currently, most domestic ammonia is intended for fertilizers, and this demand stream is not expected to grow in the coming years, thanks to increases in nitrogen fertilizer efficiency. However, there could also be a potential market for ammonia as a hydrogen energy carrier, as it is more easily stored and transported in liquid form than hydrogen. Ammonia’s toxicity and the production of criteria air pollutants from its emission or combustion are significant concerns to be addressed. |
| Carbon-neutral synthetic fuels | Currently, high-demand synthetic fuels like methanol, transportation fuels (diesel, jet fuel, motor gasoline), and dimethyl ether (DME) are predominantly produced using fossil fuels as the feedstock and energy source. Gasification or steam methane reforming first converts fossil fuels into syngas (a mix of carbon monoxide and hydrogen), which is then converted to synthetic fuels through processes such as Fisher-Tropsch. Co-electrolysis can produce hydrogen using high-purity CO2, water, electricity and possibly heat powered by clean energy sources to reduce the carbon emissions of the synthetic fuel manufacturing process. The global market for synthetic fuels is expected to grow, and methanol alone has potential growth in multiple uses such as petrochemicals and fuel blending. Carbon-neutral synthetic fuels could help decarbonize parts of the transportation sector. Synthetic fuels represent medium- to long-term opportunities. For example, the European Union’s hydrogen roadmap expects them to reach mass-market penetration by 2040 in its ambitious scenario (FCH JU 2019). |
a Liquid hydrogen is approximately 100 times more energy dense than lithium-ion batteries (Airbus 2021).
Nuclear reactors may also be co-located with the industrial customer to produce hydrogen on-site, for example to replace the steam methane reforming process (Nuclear Newswire 2022). Given the smaller footprint and potentially reduced cost of future reactors, the latter deployment scenario may be promising.
Technical Considerations of Nuclear–Hydrogen Integrated Energy Systems
Hydrogen production is an ongoing topic of investigation in DOE’s Light Water Reactor Sustainability program (Hallbert 2020). These research efforts have concluded that the most technically mature and cost-effective nuclear hydrogen production method is water electrolysis (either low or high temperature)
(Boardman et al. 2019).4 The main technology considered for low temperature electrolysis (LTE) is the PEM electrolyzer, while high-temperature steam electrolysis (HTSE) employs SOECs. Electrolyzers are both capital-intensive and energy intensive. LTE only requires electricity from the NPP while HTSE requires both electricity and heat and the system operates at temperatures of between 500°C and 1000°C. LTE does not require the system integration that HTSE entails, where diverting the thermal energy from the NPP necessitates more complicated engineering design and sometimes complex system integration. However, PEM electrolyzers rely on expensive catalysts to drive the hydrogen production process. Currently, the SOEC-based HTSE process sits at a lower level of technical readiness than PEM-based LTE processes. Hydrogen production with HTSE is more efficient (greater than 90 percent, versus 65 percent for LTE) however, leveraging its higher temperatures. If the technology becomes reliable, costs decline, and system integration issues are resolved, it is likely that the advantages of the HTSE process will encourage its deployment over LTE in integrated facilities using nuclear reactors.
Box 5-1 highlights a possible design for a nuclear–hydrogen system that uses existing light water reactors; it also outlines safety considerations for these facilities.
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4 Electrolysis of water is an electrochemical process to split water into hydrogen and oxygen gas using electricity.
Future advanced reactors are even better suited to integrate with HTSE-based hydrogen production from a technical standpoint. As discussed earlier, the HTSE process requires both electricity and heat. The combination of higher temperatures (above 500°C) and higher efficiency of electricity production from future advanced reactors will further improve the overall efficiency of HTSE-based hydrogen production compared to LWRs. Coupling advanced reactors with SOECs for hydrogen production initially will not be cost-competitive compared to LWRs because the capital cost of existing reactors has been recovered long ago. However, cost reductions in advanced reactors and performance improvement of the SOEC process may make this pathway competitive in comparison with other low-carbon hydrogen production pathways.
Another promising low-carbon hydrogen pathway enabled by advanced nuclear is via thermochemical splitting cycles, which only require heat from nuclear reactors and thus result in reduced integration effort and potentially overall cost reduction compared to the SOEC route. There are efforts to develop and learn from pilot-scale facilities that employ advanced nuclear reactors for hydrogen production through the sulfur-iodine (SI) process. For example, in 2019, the Japanese Atomic Energy Agency (JAEA) has successfully demonstrated continuous hydrogen production using its 30 MW(t) gas-cooled High Temperature Engineering Test Reactor (HTTR) through the SI process. In China, the Institute of Nuclear and New Energy Technology has also been planning to demonstrate coupling their HTR-10 (a high-temperature gas cooled reactor) with the SI plant for hydrogen production before 2025. (Suppiah 2020).
DOE Initiatives to Enable a Nuclear–Hydrogen Commercial Pathway
As the interest in hydrogen has grown again, so too have DOE’s investments in projects that aim to increase the likelihood of successful commercialization of integrated energy systems that involve nuclear power. In recent years, DOE has awarded contracts to a few commercial nuclear utilities (Xcel Energy, Constellation Energy,5 Energy Harbor, Arizona Public Service) to demonstrate the potential for nuclear plants to devote more of their operations to hydrogen production. The Xcel Energy project comprises, in Phase I, a techno-economic analysis of product diversification options that could help sustain the Monticello and Prairie Island NPPs in Minnesota (Knighton et al. 2021). Phase II will involve a demonstration that integrates a 150 kW HTSE with the Prairie Island nuclear plant. The initial hydrogen generation is expected to begin in 2024. Constellation Energy is seeking to demonstrate the integration of a 1.25 MW LTE with its Nine-Mile Point NPP in New York. This project has been ongoing since 2019 and is scheduled to produce hydrogen in 2023. Similarly, Energy Harbor is seeking to integrate a 2 MW LTE with its Davis-Besse nuclear power station in Ohio, with hydrogen production slated to commence in 2023 or 2024. In October 2021, Arizona Public Service received an award for a hydrogen demonstration project at the Palo Verde NPP. This project is still in contract negotiation stage and if successful, it would start producing hydrogen as early as 2024 through the integration of a 15–20 MW LTE. These pilot-scale nuclear plus hydrogen systems revolve around demonstrating flexible plant operations during times of peak wind or solar generation, enabling their dynamic participation in an organized electricity market, or for clean hydrogen production to be used for local public transportation or local industrial customers. These demonstrations will employ a system design that can be scaled up and used for other hydrogen production applications and could meet regulatory requirements (Vedros et al. 2020).
These demonstrations will enable much better understanding of the interface between the NPP and the electrolyzers, how plant operations unfold in practice, and how to manage the storage and transport of hydrogen. More importantly, they will enable a more comprehensive understanding of the regulatory, financial, and safety issues surrounding such concepts. These lessons could be used to scale up hydrogen production via NPPs and ensure that vendors of advanced nuclear reactors understand what these integrated systems require in the real world.
Augmenting these developments, DOE launched its “Hydrogen Shot” in June 2021,6 an initiative aimed at reducing the cost of clean hydrogen production by 80 percent to $1 per 1 kilogram in 1 decade (“1 1 1”). The 2021
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5 The contract was originally awarded to Exelon Corporation. Following the reorganization of its nuclear plants from Exelon Corporation in 2022, the project is now carried out by Constellation Energy.
6 Hydrogen Shot is part of the DOE Energy Earthshots Initiative and was the first Earthshot to launch.
Infrastructure Investment and Jobs Act (IIJA) earmarked about $8 billion to establish at least 4 regional clean hydrogen hubs to improve clean hydrogen production technologies from production to processing, delivery, storage, and end use. These hubs will pursue several technology pathways to achieve this ambitious goal and enable the widespread use of hydrogen as a clean fuel and chemical feedstock. The IIJA mandates that one hydrogen hub shall be dedicated to nuclear generation resources, which reaffirms DOE’s support for nuclear–hydrogen commercialization pathways. More recently, the IRA has established a clean hydrogen tax credit, that ranges from 1.2 to 60 cent per kilogram, depending on the carbon intensity of the hydrogen production pathway that is employed. Significantly, this credit is stackable, meaning that it could be used in conjunction with other credits: for example, on top of a tax credit for the use of low-carbon electricity to produce the hydrogen (IRA 2022).
Understanding the Cost of Low-Carbon Hydrogen Production Pathways
To achieve DOE’s “1 1 1” goal, it is important to understand the cost of hydrogen production for various low-carbon technologies. The $1 per kg-H2 goal refers to the levelized cost of hydrogen (LCOH), which is used to account for all the capital and operating costs of producing hydrogen and to indicate how much it costs to produce 1 kg of hydrogen over the assumed lifetime of the hydrogen production plant. LCOH allows different production pathways to be compared on a similar basis and is determined by the capital cost of energy supply, the capacitor factor of energy supply (90 percent for nuclear versus 20 percent for solar), among others. Factors unique to the LCOH of electrolytic hydrogen production pathway include the hydrogen plant capital cost, the efficiency of electrolyzers, and so on.
When it comes to the nuclear–hydrogen route, it is likely that the goal set by the Hydrogen Shot initiative can only be realized by the existing fleet of nuclear reactors, rather than one of the advanced reactors. This is because existing LWRs operate at high-capacity factors and have already recovered their costs; the electricity they produce is relatively cheap, and they already exist. Analyses have shown that it costs $1.93 (in 2020 dollars)7 to produce 1 kg of hydrogen for an integrated LWR/HTSE plant starting operations in year 2027 and there is a pathway to achieve the goal of $1 per kg-H2 (Knighton et al. 2021). Nuclear-generated hydrogen could be made cost-competitive with steam methane reforming by 2030, as costs decline, performance improves, and carbon emission restrictions are enforced. In fact, it is crucial for electrolytic hydrogen production to be cost competitive with the incumbent technology—steam methane reforming retrofitted with carbon capture, utilization, and storage (CCUS)—within a decade or so, for it to be widely adopted to play a meaningful role in deep decarbonization. The LCOH for the steam methane reforming technology before the recent high natural gas price scenario was on average as low as $1 per kg-H2. Because this technology is tied to natural gas prices, its cost can be volatile, as witnessed in certain regions of the world in 2022. In a recent Nuclear Energy Agency (“NEA”) study, the LCOH for steam methane reforming with CCUS in the year 2035 is estimated to be between $2 per kg-H2 and $5.87 per kg-H2, bounded by a low natural gas price of $20 per MWh (or ~6 $/MMBTU) and a high natural gas price of $100 per MWh (or ~30 $/MMBTU). With the natural gas price in 2022 at approximately $45/MWh, which is still below the prices in certain regions of the world in 2022, steam methane reforming with CCUS is the least affordable option compared to nuclear or renewable pathways (NEA 2022). Deployment of steam methane reforming with CCUS is also geographically limited given the geologic constraints for CO2 sequestration.
Renewables and nuclear are two major clean energy resources considered in the electrolytic hydrogen pathways. There is a consensus among industry that PEM and SOEC will be the main electrolyzer technologies replied on to scale up renewable and nuclear-based hydrogen production in the next two to three decades (NEA 2022; Ingersoll and Gogan 2020). Breaking down the LCOH of electrolytic pathways is key to understand how the nuclear option compares to renewables.
The LCOH of electrolytic technologies is composed of the levelized cost of energy and the levelized cost of the electrolyzer. The levelized cost of electricity, as a major part of the levelized cost of energy, stands out as the
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7 This is estimated for a nth-of-a-kind LWR/HTSE plant approximately 4–5 years in the future when a 95 percent learning curve and at-scale SOEC supplies can be assumed.
single most important factor in influencing LCOH for all options. Electricity price from depreciated LWRs and the cheapest renewable resources, such as solar in Middle East and North America, are much more competitive than other low-carbon resources, such as solar in Europe or offshore wind. The levelized cost of the electrolyzer consists of both capital cost and operating cost, which are heavily affected by three factors: the cost and performance of the hydrogen plant itself, the capacity factor of the energy source, and the efficiency of the electrolyzer. The engineering and capital costs for SOEC plants are more than those of PEM plants. Currently, PEM plants have a longer lifespan and lower degradation rate compared to SOECs. However, these are just part of the picture in determining the levelized cost of electrolyzers. A high-capacity factor of the energy source powering the hydrogen plant can lead to a better utilization of the electrolyzer and thus a positive impact in the overall levelized cost of hydrogen. For example, it has been shown that with other factors held constant, the LCOH triples when moving from a 90 percent capacitor capacity factor electric source (e.g., nuclear) to 20 percent capacity factor (e.g., solar) (Ingersoll and Gogan 2020). Last, the efficiency of the electrolyzer also plays a role in the levelized cost. By using some thermal energy (less than 10 percent of the overall energy required), SOEC uses less electricity than PEM and can achieve hydrogen production at above 95 percent efficiency. This is a very important aspect as it provides a favorable prospect for the nuclear electrolytic hydrogen pathway. Moreover, because renewables cannot provide heat (at least not directly or efficiently), it makes sense to use nuclear power (both existing fleet and future advanced reactors) to integrate with SOECs.
In conclusion, the factors that affect electrolytic hydrogen LCOH are complex and interrelated. Renewables may be able to provide the cheaper electricity in certain scenarios compared to nuclear power but suffer lower capacity factors in general and do not have the SOEC integration option. As such, most studies show that renewable hydrogen LCOH is higher than that of depreciated LWRs for both the current scenario and the year 2030. According to Bloomberg New Energy Finance (BNEF), the current cost of renewable-driven electrolytic hydrogen production is above $4 per kg-H2 (BNEF 2020). In year 2030, the best-case wind and solar will produce hydrogen at $2–$3 per kg-H2 using cost projections from NREL (Ingersoll and Gogan 2020). Besides cost constraints, the renewable-hydrogen pathway also faces other constraints at the scale required to match the global hydrogen demand, such as land constraints and the associated ecological as well as social and political concerns related to “energy sprawl.” Regional resources endowment (e.g., access to large amounts of cheap electricity, low natural gas prices) will likely play a role in determining the cost of hydrogen production and the future clean hydrogen technology landscape.
The LWR/HTSE pathway has strong potential to reach the $1 per kg-H2 goal in one decade. At the moment, not only are these stacks expensive (SOEC stack capital costs are currently at $155/kW-dc), but also, they are relatively short-lived (SOEC stacks have a service life of 4 years, after which their production capacity falls to 67 percent, eventually necessitating capital outlays for replacement) (Peterson et al. 2020). However, some analyses project that a cost of $27/kW-dc could be achieved by 2030 as large-scale SOEC manufacturing capacity continues to expand in the coming years (Tang et al. 2018), and that the stack degradation rates might be halved in the next few years. Lower SOEC degradation rates impact both its service life and replacement schedule, ultimately contributing to lower costs. For the nuclear–hydrogen pathway to be cost competitive in general, the costs of both nuclear reactors and electrolytic cells must fall drastically. If new and advanced reactors are commercialized in the coming decades, their availability might coincide with that of cheaper, better performing SOEC stacks, improving the economic viability of the plant. Some transformative manufacturing methods such as a hydrogen gigafactory or existing world-class shipyards have been proposed that might significantly reduce the cost of future advanced reactors as well as hydrogen production to $0.9 per kg-H2 by 2030 (Ingersoll and Gogan 2020; EPRI 2021b).
LCOH is a key indicator for investors and policymakers who seek to choose among different options for hydrogen production. However, LCOH applies at the individual production unit level and thus only tells part of the story. For example, co-locating hydrogen production with cheap electricity resources may reduce the cost of hydrogen production itself but may lead to substantial costs for the hydrogen delivery system to a customer. A comprehensive analysis of the economic costs of various hydrogen production options needs to consider the costs across the entire value chain, including those associated with hydrogen storage, transportation, and distribution. A recent NEA analysis argues that nuclear energy could help sustain a competitive hydrogen
production pathway (NEA 2022). This analysis shows that a mismatch in hydrogen production and consumption profiles is likely to cause inefficient infrastructure design. In the short term, most of the demand will likely come from industry, which requires a steady flow of hydrogen. For meeting the unremitting industrial demand, the low-capacity factor associated with renewable-powered hydrogen production facilities would likely require over-sizing the infrastructure, including hydrogen storage and transportation and distribution systems, reducing the competitiveness of this pathway. As an energy source with a high-capacity factor, nuclear power would enhance co-location synergies with large-scale industry demand, minimizing infrastructure costs for hydrogen storage, transportation, and distribution.
The hydrogen value chains are likely to be designed on a case-by-case basis, and this complexity renders evaluating the cost of hydrogen delivery a serious challenge. Nonetheless, such assessments are valuable because frequently, the total cost of value chain will determine the competitiveness of different business models for hydrogen production.
One additional complexity arises from proposals to coproduce electricity with production of a non-electricity product. For example, the vision of an advanced NPP serving the electric grid when necessary and then switching to hydrogen production when electric power supply exceeds demand, requires the reactor operator to incur substantial capital investments in the engineering systems, infrastructure, and regulatory compliance that is necessary for frequent switching between the two services. If clean hydrogen commands a premium—as it is likely to—a reactor operator might well choose instead to design a plant that is dedicated to its production, perhaps even if that entails investment in hydrogen storage in order to exploit its higher revenue stream. In such a case, a reactor operator might only resort to selling electric power if the market operator or another regulatory body demands that it does so, either in the form of a hard constraint or a substantial economic incentive. Clearly, calculating the levelized cost of the different products for such “hybrid” operational paradigms is highly site-specific, dependent as it is on the power system in which the reactor operates, the regulatory context, and other factors. Without certainty in how the electricity and energy markets are likely to evolve, investing in the infrastructure necessary to exploit hybrid operations incurs an economic and regulatory risk.
Hydrogen-Based Liquid Fuels Enabling Long-Distance Transportation Decarbonization
Without significant investments, economies will continue to rely heavily on liquid hydrocarbon fuels to power the transportation sector (from surface transportation to aviation to marine shipping). Battery electric vehicles will play a significant role in replacing conventional internal combustion engine vehicles, but heavy-duty freight, aviation, and ocean shipping require vastly greater energy densities than batteries can offer. Liquid hydrogen, despite its high gravimetric energy density, has a lower volumetric energy density8 than liquid hydrocarbon fuels. The liquefaction of hydrogen is also energy intensive: it requires high pressures and cryogenic temperatures of < −253°C for storage.
Chemical compounding—combining hydrogen into other, denser molecules—offers a solution to address some of the difficulties associated with liquid hydrogen. Liquid fuels such as ammonia and synthetic hydrocarbons have the potential to solve both the energy density and fuel distribution challenges that face liquid hydrogen.
Ammonia is produced using the century-old Haber-Bosch process, where hydrogen and nitrogen are reacted at high temperatures and pressures. Ammonia can remain in liquid form at near atmospheric pressure and at temperatures of < −33.34°C, making it easier to store and transport than liquid hydrogen. In addition, liquid ammonia is approximately 1.5 times as energy dense as liquid hydrogen. These attributes mean that ammonia lends itself for use in ocean shipping and remote, off-grid applications. For example, minor modifications are required for some existing ship engines to combust ammonia and building a distribution network is easier for ammonia than it is for liquid hydrogen. There are significant concerns regarding ammonia’s toxicity and nitrous oxide and NOx formation upon combustion or as a result of leakage NOx-reduction technologies are widely available and intensive capacity building to ensure that fuel handling meets high safety standards.
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8 In this chapter, the terms energy density and volumetric energy density are used interchangeably; they refer to the amount of energy stored in a given system or region of space per unit volume.
The Haber-Bosch based ammonia synthesis process is energy intensive: it operates at temperatures between 400°C and 500°C and at pressures of up to approximately 200 bar. Nuclear power could be a primary low-carbon energy source for ammonia production. For example, both the nuclear heat and electricity could produce hydrogen using the HTSE process. The hydrogen and nitrogen could then be fed into an ammonia synthesis plant, powered by nuclear electricity. Because the ammonia synthesis process is exothermic, the heat produced in ammonia production can be recycled back to the hydrogen plant to supplement the high thermal energy requirements of the SOEC stacks.
Synthetic liquid hydrocarbons offer another important opportunity to decarbonize parts of the transportation sector that are difficult to electrify. Synthetic liquid hydrocarbons, also commonly referred to as drop-in fuels, are chemically identical to the distillates that are derived from petroleum (e.g., gasoline, diesel, or jet fuel). These substitute fuels could leverage well-established fuel storage and transportation systems and standards, not to mention the utilization of the existing fossil fuel infrastructure. For synthetic liquid hydrocarbons to be carbon neutral, they must be produced from CO2 that is already in the atmosphere—direct air capture of carbon dioxide is an area of growing interest and investment—and the additional inputs to the manufacturing process (e.g., electricity, hydrogen) must also be emission-free.9
There are several pathways to produce syngas (a mix of carbon monoxide and hydrogen) using CO2 as a feedstock, employing clean energy resources such as nuclear to eliminate the emissions associated with the synthetic liquid fuel manufacturing process. One such possibility is co-electrolysis. In co-electrolysis, CO2 is reacted with water in a SOEC system to produce syngas, which can be subsequently converted to transportation fuels through the Fischer–Tropsch or Mobil processes.
One of the main obstacles to electrolytic ammonia and synthetic hydrocarbons is the cost and performance of the SOECs themselves, as discussed previously. Like advanced nuclear reactors, these components will need to demonstrate that they are economically competitive, durable, and reliable. The other components required to make the CO2-to-fuel supply chain a reality are complex and capital-intensive, but technologically mature. They include Fischer–Tropsch reactors and a combination of distillation, upgrading, cracking, and reforming units—units that have been employed in the petroleum refining industry in some cases for a century. The same can be said for the ammonia synthesis process itself, which is a very proven technology. Even if the performance of SOECs improves—ongoing research is making great strides in this field (Hauch et al. 2020)—these integrated systems to produce low-carbon ammonia and synthetic hydrocarbons will require large amounts of emissions-free electricity and heat to run the combined electrochemical and thermochemical synthesis processes: small nuclear reactors could conceivably provide that energy.
Other Process Heat Applications
Many industrial facilities rely on thermochemical processes—chemical processes that employ heat to distill, separate, desorb, or otherwise recover specific substances. The temperatures required depend on specific chemical processes (see Figure 5-2 and Box 5-2). Because nuclear reactors provide heat, the chemical industry has interest in potentially acquiring reactors as carbon constraints tighten, or fossil fuel supplies dwindle or become expensive. Ongoing concerns regarding climate change have revivified this interest (Nuclear Newswire 2022; Goetzke et al. 2022). A recent study employed 6 years of steam demand data to explore how four generic nuclear reactor options (small modular light water reactor, high-temperature gas reactor, liquid metal fast reactor, and fluoride-salt cooled reactor) might serve Eastman Chemical’s Kingsport facility, which produces specialty chemicals (Greenwood et al. 2020). It evaluated their ability to meet Eastman’s demand, the operational reliability of their steam and electric supply, and their potential costs compared to status quo, natural gas fired supply. While drawing no specific conclusions, the report indicated that an SMR could potentially meet the existing process heat needs of the Kingsport facility but noted that the required capital investment would be substantial and present a major hurdle. Efforts to electrify thermochemical processes could reduce the need for siting nuclear reactors near industrial facilities,
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9 Currently, synthetic liquid hydrocarbons are predominantly produced using feedstocks and energy derived from fossil fuels, and generate net CO2 emissions. Refer to Table 5-2 for the conventional synthetic fuel process.
although the reactors would have to compete with other sources of low-carbon electricity and heat, such as natural gas with carbon capture and storage.
Other possible industrial integrations include using nuclear power for running a cryogenic refrigerant cycle, the chlor-alkali process, and formic acid production. A cryogenic refrigerant cycle could be powered by NPPs when the electricity price is low or there is grid over-generation. The cryogenic refrigerant can be regarded as a form of energy storage and can be used onsite as needed or transported short distances to the point of use.
Chlor-alkali electrolysis plants show strong technical potential for integration with an NPP from both heat and electricity-demand perspectives. The chlor-alkali process electrochemically converts NaCl-rich brine (i.e., sodium chloride solutions) into chlorine gas and sodium hydroxide (i.e., NaOH or caustic soda), both of which are commodity chemicals commonly required by industry. For example, chlorine is used for producing polyvinyl chloride (PVC), water treatment, pharmaceuticals, and other chemicals. NaOH is widely employed in industrial process to manufacture soaps, paper, dyes, petroleum products, and so on. The chlor-alkali industry is projected to grow in the next decade with possibility to use a low-carbon energy source such as nuclear power to reduce CO2 emissions.10
Formic acid can be produced by co-electrolysis of CO2 and water using the electricity and possibly heat from NPPs (Lu et al. 2014). Formic acid is relatively nontoxic and allows easy long-term storage. Currently, formic acid is used to produce natural and synthetic leathers, textiles, cleaning products, and rubber. Formic acid has been widely used abroad as an antimicrobial additive in animal feed, an application of increasing interest in the United States as the use of antibiotics in farming has been under increasing scrutiny (Tullo 2015). In addition to its traditional uses, formic acid could serve as an energy-dense hydrogen carrier that is liquid at ambient conditions (BMT 2009; Yang et al. 2017). One manufacturer, OCO Chemicals, has reported that its licensed process boasts a 78 percent efficiency with a high selectivity of 99 percent in reducing CO2 to formic acid or formate salts (OCO Chemicals 2021).
The domestic and global demand for formic acid is projected to grow (Transparency Market Research 2018). Low-carbon baseload nuclear power is well suited to provide the energy to decarbonize the formic acid production process. In addition to energy costs, other key cost drivers to make formic acid cheaper than alternative chemicals are the performance and cost of co-electrolysis cells, which can reduce both capital and operating costs, as well as the feedstock price of CO2.
Finding 5-2: Process heat applications exist at a variety of temperature ranges. Higher-temperature applications are likely going to be more difficult to electrify, because there are fewer available low-carbon heat options. Reactor systems with higher outlet temperatures could conceivably serve processes requiring temperatures between 300°C and 800°C. These reactors would need to demonstrate a high degree of safety with minimal reactivity feedbacks between the reactor and the process heat application. These are necessary attributes for siting a nuclear plant near a facility for industrial heat applications.
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10 Currently the chlor-alkali process accounts for 4 percent of total industrial CO2 emissions.
District Heating
District heating systems have been used to provide heating to networks of buildings across the world for the past 150 years. More than 900 installations in the United States and Canada use such systems, in some cases coupling them with steam-turbine-driven chillers to provide district cooling as well. These applications use heat produced at the relatively low temperatures that LWRs could provide (<125°C). Several existing NPPs supply such heat via hot water or low-pressure steam (IAEA 2003; Leppanen 2019) and are connected to municipal heat distribution systems to provide district heating services. The typical system extracts non-radioactive steam from the secondary circuit of the LWR, which is then fed to an on-site heat exchange station connected to a separate water loop. This heat is then fed to an off-site heat exchange station, which allows hot water to flow through municipal heating pipes to consumers.
China has been exploring the use of small nuclear reactors as alternative heating systems in smog-prone regions, thereby avoiding the use of coal- or gas-fired boilers (Zhang et al. 2017). Recently, the Haiyang NPP (an AP1000 LWR) in Shandong province has started providing district heat to the surrounding area. A trial of the project—the country’s first commercial nuclear heating project—was carried out in winter 2019, providing heat to 700,000 square meters of housing, including the plant and local residents (World Nuclear News 2020a). As of late 2021, the Haiyang system is providing district heating to the entire city of Haiyang, a city of approximately 200,000 (Kraev 2021). Additionally, Finland is studying the use of a set of small nuclear reactors for district heating (World Nuclear News 2020b).
While the cost and technology readiness for district heat provided by nuclear energy are promising, major issues would need to be addressed for it to play a role in the future U.S. energy system, including increased commitments to district heating (which itself requires substantial investments in laying the necessary infrastructure), greater public acceptance of nuclear plant sites in relative proximity to populated centers, and the regulatory issues associated with siting reactors that serve hybrid electric-thermal or thermal needs.
Water Desalination
Desalinated water is an essential commodity in arid regions of the world that have limited access to freshwater resources, such as the Middle East. Desalination can be achieved through any one of several proven technologies, such as reverse osmosis, which uses only electricity, or a variety of low temperature (75°C) heat-based processes that use distillation (Shatilla 2020). The current global market for desalinated water is relatively modest (Grand View Research 2022); however, water pollution, urbanization, and water scarcity are issues that could increase the market for desalinated water by the time advanced nuclear reactors begin to come online. The Middle East and North Africa have the greatest potential market for desalinated water owing to growing populations and existing water scarcity issues (Ahn et al. 2021).
As shown in Figure 5-3, nuclear desalination plants today produce between 1,000 and 160,000 m3 of water per day. Two issues limit the likelihood of expanded deployment of nuclear power for water desalination. The first, highlighted throughout this report, is cost. A recent study (Rath 2020) compared hybrid systems that employ either SMRs or natural gas with carbon capture and storage to desalinate water. It found that the cost of carbon emissions would have to rise to $200/tCO2 for the SMR solution to clearly dominate the natural gas option. The second issue is water pricing: even in water-scarce regions, water is severely underpriced. Absent a change in policy governing the pricing of either water or carbon, this means that, outside of a very small subset of locations, like the Monterrey Peninsula or the Middle East, this market is unlikely to expand to a level that would enable the mass deployment of nuclear power, although any location that employs SMRs for other reasons could certainly opt to integrate water desalination into its plans.
A 2019 review of the literature found the cost of water production using nuclear desalination was estimated to range from $0.4/m3 to $1.8/m3 depending on the type of reactor and the desalination process used (Al-Othman et al. 2019). The World Nuclear Association reports the cost of water production using nuclear desalination to be similar to fossil-fueled plants today, around $0.7/m3 to $0.9/m3 (World Nuclear Association 2020). A study of California’s Diablo Canyon nuclear reactor found that if the reactor were reoriented around coordinated electricity generation, hydrogen production, and desalination, water would cost $0.79/m3 to $0.98/m3 (Aborn et al. 2021; see Table 5-3).
TABLE 5-3 Key Results from Technoeconomic Analysis of Two Proposed Combined Hydrogen, Desalination, and Electricity Generation Projects at Diablo Canyon Compared to the Estimates for the Carlsbad Desalination Planta
| Large Scale at Diablo | Mega Scale at Diablo | Carlsbad Estimated | ||
|---|---|---|---|---|
| Capacity (m3/d) | 189,270 | 4,752,000 | 189,270 | |
| Total Capex ($ million) | 599 | 11,571 | 1,235 | |
| Energy consumption (kWh/m3) | 3.5 | 3.5 | 3.5 | |
| Electricity price ($/kWh) | $0.054 | $0.054 | $0.139 | |
| Water cost breakdown ($/m3) | Capital costs and amortization | $0.53 | $0.41 | $1.10 |
| Operating costs (excluding energy) | $0.26 | $0.19 | $0.26 | |
| Energy costs | $0.19 | $0.19 | $0.49 | |
| Water price at plant outlet ($/m3) | $0.98 | $0.79 | $1.84 | |
a The Claude “Bud” Lewis Carlsbad Desalination Plant is a desalination plant that opened on December 14, 2015, in Carlsbad, California, north of the Encina Power Station. Its output constitutes approximately 7 percent of the water supply for San Diego County.
SOURCE: Committee generated with data from J. Aborn, E. Baik, S. Benson, et al., 2021. An Assessment of the Diablo Canyon Nuclear Plant for Zero-Carbon Electricity, Desalination, and Hydrogen Productions, Stanford University Precourt Institute of Energy, https://drive.google.com/file/d/1RcWmKwqgzvIgllh0BB2s5cA6ajuVJJzt/view.
Using Diablo Canyon as a power source for desalination could substantially augment fresh water supplies to the state as a whole and relieve withdrawal from critically over drafted basins regions such as the Central Valley, producing freshwater volumes equal to or substantially exceeding those of the proposed Delta Conveyance Project, but at significantly lower investment cost.
Finding 5-3: Several proposed non-electric services, such as low-temperature heat and desalination, currently cost very little and likely would not be compensated at a level that encourages new nuclear deployment. Hydrogen provides perhaps the most credible non-electric revenue stream for nuclear reactors, because it is likely that hydrogen will have value across the industrial, power, and transportation sectors for deep decarbonization.
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