Sustainable Hydrogen Production from Nuclear Energy

Abstract

The rapid increase in global warming requires that sustainable energy choices aimed at achieving net-zero greenhouse gas emissions be implemented as soon as possible. This objective, emerging from the European Green Deal and the UN Climate Action, could be achieved by using clean and efficient energy sources such as hydrogen produced from nuclear power. “Renewable” hydrogen plays a fundamental role in decarbonizing both the energy-intensive industrial and transport sectors while addressing the global increase in energy consumption. In recent years, several strategies for hydrogen production have been proposed; however, nuclear energy seems to be the most promising for applications that could go beyond the sole production of electricity. In particular, nuclear advanced reactors that operate at very high temperatures (VHTR) and are characterized by coolant outlet temperatures ranging between 550 and 1000 °C seem the most suitable for this purpose. This paper describes the potential use of nuclear energy in coordinated and coupled configurations to support clean hydrogen production. Operating conditions, energy requirements, and thermodynamic performance are described. Moreover, gaps that require additional technology and regulatory developments are outlined. The intermediate heat exchanger, which is the key component for the integration of nuclear hybrid energy systems, was studied by varying the thermal power to determine physical parameters needed for the feasibility study. The latter, consisting of the comparative cost evaluation of some nuclear hydrogen production methods, was carried out using the HEEP code developed by the IAEA. Preliminary results are presented and discussed.

1. Introduction

The increase in global warming urgently requires the rapid transformation of the energy infrastructure and the transport sectors to mitigate greenhouse gas emissions. There has been a notable change in the Earth’s global temperature: in 2023, it was about 1.36 °C warmer than at the end of the 19th century (1850–1900) [1]. This can be achieved not only through the optimization of various energy systems but also through the integration with, e.g., nuclear power plants (NPPs), creating a more efficient energy network.

The hydrogen (H₂), as a clean fuel produced by different technologies, is currently one of the promising resources and main enablers towards net-zero emissions.

It is important to remember that H₂ is ubiquitous, and to make it available, it must be extracted from the chemical compounds. The current hydrogen production, as specified in [2], is “about 7 × 10¹⁸ Joules per year, corresponding to ~52.6 million tons per year (higher heating value—HHV) or ~630 billion Nm³/yr (as of 2006), which is about 2% of the world’s total energy consumption”. These data quite accurately reflect the EU near-term forecast of the hydrogen market [3]. Hydrogen will be primarily used, e.g., in the petrochemical or fertilizer industry. However, to achieve this large-scale production, ambitious policies are needed, which will necessarily involve the use of nuclear energy. This is also the conclusion of the (first and) new NEA report, 2022 [4], which provides an in-depth analysis of the key role of nuclear energy for the production and distribution of hydrogen, in terms of cost-efficient design and operation. Hydrogen can enable the separation of energy demand from energy resources and improve the security of energy supply, although it is not always an ideal carrier for transporting energy from the point of production to the end user, due to the rather high amount of energy lost during handling, storage, and transport. Nuclear energy today seems the most promising for producing H₂ thermo-chemically in a clean, safe-to-hand, and efficient manner, especially employing nuclear-advanced very high temperature reactors (VHTRs) that are characterized by a coolant outlet temperature in the range of 550–1000 °C. This type of reactor system, hence, seems to be the most suitable for coupling with a hydrogen production process and supporting an energy district. Nuclear hydrogen production technologies will allow the transition from fossil-fuel-based energy to “low-CO₂” energy through the decarbonization of energy-intensive industrial sectors and automotive transportation, direct use as a fuel, integration with hybrid and renewable energy systems, and the possibility of large-scale storage [2,5,6]. Additionally, centralized production of large amounts of energy favours the use of nuclear reactors as baseload power plants, securing an energy supply at stable prices [7,8]. This paper describes the potential use of nuclear energy aimed at its coupling, in coordinated configurations, to plants dedicated to H₂ production, along with the operating requirements and thermodynamic performance. To this purpose, in Section 5, a feasibility study performed by using the IAEA Hydrogen Economic Evaluation Programme (HEEP) code and preliminary results are presented and discussed.

State of the Art

It is important to emphasize that, in recent decades, research efforts have been devoted to studying H₂ production from nuclear reactor systems.

The study of Agyekum [9] proposes a bibliometric approach to analyze developments of nuclear hydrogen production over the last two decades. It highlights that the countries with operating nuclear power plants are the most interested in producing nuclear hydrogen and diversifying energy resources. The study also underlines the need to develop suitable infrastructure for the integration and connection between the various energy systems. Moreover, it indicates that an efficiency of about 50% can be achieved by connecting a very high temperature reactor (VHTR) with a cycle for producing H₂ and electricity: the basic idea dates to the 1920s and refers to the use of thermochemical cycles through water splitting (also referred to as two-stage HgO/Hg cycle) [10].

Regarding H₂-nuclear coupling, the study of IAEA [2] identifies some major driving factors in, e.g., societal and governmental decisions on global climate change and CO₂ emissions, energy security of supply and independence from oil or fossil fuel use, and economic aspects. It also confirms the key role of nuclear cogeneration for many existing industries (Figure 1a) requiring electricity and steam at different pressures and temperatures (up to ~600 °C). Among all the available nuclear technologies, including the emerging ones, the use of VHTRs appears particularly favourable, since the exit coolant temperature of about 950 °C can allow the production of large quantities of H₂ necessary for the clean energy transition. Figure 1b shows how a nuclear reactor system can contribute to this transition and an integration scheme with seawater desalination and H₂ production units.

The study of [10] provides an overview of the potential use of nuclear energy for hydrogen production, ongoing demonstration projects, and the challenges addressed in demonstrating its feasibility, such as those related to the safety, technical, and economic aspects, apart from public acceptability. In light of this and the findings of the IEA study (2023) on the clean energy progress, it is established that net-zero CO₂ emissions require a near-term energy strategy that includes both hydrogen production plants and the deployment of nuclear power plants [12]. It is also worth noting that, in the short term (by 2030), hydrogen can be produced through water electrolysis, while in the medium term, it is expected to be produced through innovative, more efficient, and advanced nuclear technologies (>700 °C). Several R&D projects aimed at demonstrating the technical and economic feasibility of integrating H₂ production with existing nuclear plants, albeit on a small scale, have been started in North America [13]. Major nuclear hydrogen projects are underway in Canada, the Russian Federation, Sweden, and the UK where such production will contribute to decarbonizing society and using electricity more efficiently, while providing new sources of revenue. The H₂ production strategy of Canada relies on making hydrogen via electrolysis at off-peak times, using inexpensive off-peak electricity from existing nuclear power plants. For Bruce Power NPP (comprising eight units), the total capacity is 6358 MWe, or more than 60% of Ontario’s electricity generation, representing a win–win situation for low-carbon hydrogen production [1]. Aiming at diversifying the electricity generation and supporting the development of an integrated energy district, intensive studies on hydrogen production through water splitting, based on HTGR technology, have started in China since 2005 [14]. One of the key projects is the Chinese High-Temperature Gas-cooled Reactor-Test Module (termed as HTR-10) [15] which has 10 MWth power and a coolant outlet temperature of 700 °C [16]. Regardless of the high-temperature reactor system, both the thermochemical cycle and high-temperature steam electrolysis are considered for H₂ production. Among research activities, the Japanese high-temperature test reactor (HTTR), shown in Figure 2, should also be mentioned, even if it is a research tool [17], and the French programme based on the hydrogen production goal from non-fossil sources via 6.5 GW of electrolysis plants by 2030 (in 2021, there were only 1 MW installed and 900 MW planned), particularly by means of nuclear energy, thanks to the actual French reactor fleet and new Gen-IV and HTGRs.

2. Production Methods for H₂

H₂ is present in water, organic matter, fossil fuels, and natural gases like methane. Generally, it can be extracted from methane or water. Extracting hydrogen from methane is cheaper but provokes the release of carbon into the environment, while the extraction from water introduces only oxygen into the environment. However, to extract hydrogen from water, a large amount of electricity might be spent. The energy required to satisfy the demand for H₂, through water electrolysis, is approximately 48.2 MWh/ton, and this implies that 4.1 TWh of electricity would be needed for its production. Therefore, considering that a standard 1 GWe nuclear power plant can produce up to 8760 GWh/yr, almost 500 large plants would be required to produce the same amount of hydrogen [19]. Moreover, since this is more than the global NPPs’ installed capacity nowadays, we certainly need to consider also a new type of reactor coupled to hydrogen plants that have operating characteristics different from the standard low-temperature water electrolysis [20].

Hydrogen Production Method Overview

Hydrogen may be produced using nuclear power (NP) and nuclear power heat (NPH) at different ranges of temperature, as indicated in [21], with the following methods: water electrolysis (NP, below 150 °C); steam electrolysis (NPH, 750 °C < T < 850 °C); chemical reforming of fossil fuels and biomass (NPH, 850 °C < T < 950 °C); and thermochemical or hybrid water-splitting cycles (NPH, 850 °C < T < 950 °C). Approximately 96% of annual hydrogen production comes from fossil fuels [21,22,23], broken down as: 48% Steam Methane Reforming; 30% Oil/Naphtha Reforming; and 18% Coal Gasification. The remaining approximately 4% is produced by water electrolysis.

Other methods can be used for such purposes, such as thermolysis, radiolysis, thermochemical cycles, photolysis, etc.; however, economics and technology readiness have prevented their large-scale application thus far. According to scholars, experts’ opinion, and current scientific literature, alkaline water electrolysis (AWE) [24,25], is the standard electrolysis technology (i.e., conventional electrolysis) that uses electricity as a unique energy input, and its water splitting technique is a typical low-temperature electrolysis process. It consists of electrochemical decomposition of water molecules, i.e., 4H₂O → 4H+ + 4OH− obtained in electrolysers, as schematized in Figure 3a, where electricity creates an electric field forcing the negative ions to move towards the anode in order to achieve 4OH− → O₂ + 2H₂O + 4e− and positive ions to move to the cathode in order to achieve 4H+ + 4e− → 2H₂. This process has low complexity and high technological maturity.

In what follows, the two most important variants of this process are briefly described. The first and principal variant of AWE is high-temperature steam electrolysis (HTSE, also known as HTE) which is a promising technique for future hydrogen production by utilizing the thermal energy released from the nuclear reactors. Unlike AWE, the total energy demand for water electrolysis in the vapour phase is reduced by the heat of vaporization which can be provided—much cheaper—by thermal rather than electric energy. A solid oxide electrolyser cell (SOC) is the standard technology for the HTSE process. Water is heated up to first evaporate; thus, it will constitute a gaseous mixture (i.e., feedstock) containing 90% water steam and 10% hydrogen (this small percentage of hydrogen in the feedstock keeps the reducing conditions at the electrolytic cathode) that enters the SOC in order to carry out the expected reactions rapidly, thanks to its very high temperature, so that the dissolution of the water occurs. In this way, hydrogen and oxygen are produced at the opposite sides of the gas-tight electrolyte. Electricity input decreases with temperature (Figure 3b): it is 35% lower than conventional electrolysis in the temperature range from 800 °C to 1000 °C. The efficiency is consequently significantly higher.

The second variant is the sulphur–iodine process which is a thermochemical hydrogen production process, based on the sulphur–iodine thermochemical (S-I) cycle [24], that requires high temperatures, typically exceeding 750 °C (i.e., H₂SO₄ decomposition). This process consists of an all-fluid cycle to obtain the net reaction 2H₂O → 2H₂ + O₂. It all starts with the Bunsen reaction [25,26]:

(9I₂)_l + (SO₂)_g + (16H₂0)_l → (2HI + 10H₂O + 8I₂)_l + (H₂SO₄ + 4H₂O)_l [120 °C]

The products of this exothermal reaction are two immiscible aqueous acid phases [27], which are the hydrogen iodide (HI) and the sulfuric acid (H₂SO₄), given as a heavier HI-rich aqueous phase and a lighter H₂SO₄-rich aqueous phase. H₂SO₄ and HIx are differentiated after separation by distillation or liquid/liquid gravity separation, purification, and further concentration. The slightly endothermic decomposition (at 300–500 °C; ΔH ≈ 12 kJ/mol [28]) of hydrogen iodine HI, according to (2HI)_g → H₂ + (I₂)_l, allows hydrogen production.

A schematic diagram of hydrogen production with the S-I cycle powered by a VHTR reactor is shown in Figure 4. Although their energy needs are different, alkaline water electrolysis, high-temperature steam electrolysis, and the sulphur–iodine process require practically 1 litre of H₂O to produce 1 Nm³ of H₂. As for NP—H₂ coupling, it is worth mentioning that the primary circuit is not affected by the extraction of the heat necessary for H₂ production. More flexibility is achieved by equipping the nuclear reactor cooling circuit with an intermediate heat exchanger (IHX): different coolants as well as direct heat application can be considered [24]. Indeed, the reactor coolant and its maximum temperature are fundamental in selecting the most appropriate nuclear system.

As indicated in [19], conventional LWRs could be employed in order to deliver electricity for the low-temperature electrolysis process: electricity and hydrogen production are principally separated and could even be deployed at different locations. Other types of reactors with higher coolant outlet temperatures, ranging from 550 °C to 1000 °C, would allow the direct utilization of the hot coolant medium which transfers its heat to the thermochemical process, such as the S-I cycle. In such cases, the H₂ production site and the nuclear plant site must be close to each other.

Figure 5 shows an efficient way to produce and transfer nuclear heat from the coolant of the primary side of a hydrogen cogeneration high-temperature gas-cooled reactor GTHTR300C to the IHX, in a closed loop to the thermal hydrogen production plant. GTHTR300C is the Japanese HTGR designed by JAEA [31]. The process parameters of such a reactor concept indicate that IHX may transfer 170 MWth of the 600 MWth total thermal power: the gas turbine exploits the balance of the thermal power to achieve 206 MWe.

3. Finding the Suitable IHX

The IHX is the key component of the physical coupling between the nuclear and H₂ plant where heat is exchanged: in terms of nuclear heat applications, an indirect cycle is also realized. Under normal operation, it ensures the physical separation of the two plants, which allows us to design and maintain the conventional heat utilization system, i.e., heat management facility, without complying with nuclear standards and rules. There are, however, some disadvantages, such as the equipment cost (additional to the overall capital cost) mainly related to the design and material choice, the temperature of the heat transferred to the hydrogen production plant, which will be reduced due to additional heat losses due to the additional needs of an intermediate heat exchanger (e.g., efficiency losses, potential compression requirements), the increased number of heat exchangers resulting in a reduction in the “maximum” temperature and energy made available for the hydrogen plant, etc. It is worth pointing out that the IHX must be designed and operated for the entire life of the nuclear plant, approximately 60 years, whilst working under harsh conditions of temperature, up to 1000 °C, and pressure (and temperature and pressure gradients). For this purpose, it is, therefore, necessary to either design a new heat exchanger or improve the existing design through the introduction of advanced materials. Given equal performance, in terms of stress/strain conditions, corrosion, and dust susceptibility, the choice of IHX will depend on the cost–benefit assessment.

The design and safety requirements focused on higher-temperature NPPs like VHTR and HTGR are equally applicable to heat exchangers used in SMRs of the LWR type and MSR cogeneration designs [34]. SMRs of the LWR type are the most developed; they operate at lower temperatures up to 300 °C, and their technological philosophy is already well-developed and understood. Component research and development for SMRs of the LWR type, of course, will continue to foresee lower expected costs, especially considering their less harsh operating conditions, so material selection for the IHX is easier and far more flexible. They also allow for direct electrical power supply to potential hydrogen production facilities. However, because of their low operating temperatures, they cannot supply thermal power directly at the required operating temperatures typical of a high-temperature process, ranging from 300 °C to 1000 °C, depending on the specific thermal/thermochemical technology. However, they can always guarantee the initial heating of the feed water. Molten salt-cooled reactors (MSRs), having a higher operating temperature and potential utilization of long-distance molten salt loops, may offer a reliable and safe source of thermal energy to meet the thermal requirements for all but the highest temperature hydrogen production processes (HTSE, S-I cycle), as well as electrical power, if linked to generating equipment and suitable heat exchangers. The higher temperatures and corrosive nature of salts make the heat exchanger designs more complex than those of current reactors. Power generation or external heat supply requires at least a tertiary loop, limiting the maximum temperature. However, the potential for these reactors to provide heat and electricity to both the electrolysis and thermochemical hydrogen production processes is evident with numerous potential arrangements, noting the potential for using waste heat, as in the case of SMRs of the LWR type. There are still further developments to be made regarding the heat integration loops of MSRs, given the limited use of molten salt in the industry. To date, the IHX models proposed are either in development or (scale-up) testing to demonstrate that the nuclear requirements are fulfilled, such as the one designed for the reactor GTHTR300C [32]. Main design parameters and specifications between the High-Temperature Test Reactor–Intermediate Heat Exchanger (HTTR-IHX) and the Gas Turbine High-Temperature Reactor 300 Cogeneration–Intermediate Heat Exchanger (GTHTR300C-IHX) for different thermal power are provided in

Table 1. HTTR-IHX and GTHTR300C-IHX design parameters [32].

Parameter	HTTR-IHX	GTHTR300C-IHXs
Heat exchange rate	10 MWth	170 MWth	390 MWth	170 MWth
Design features	Vertical helical tube bundle w/smooth tubes	Vertical helical tube bundle w/smooth tubes	Vertical helical tube bundle w/finned tubes	Horizontal helical tube bundle w/smooth tubes
Tube outer diameter [mm]	31.8	45.0	31.8	45.0
Tube thickness [mm]	3.5	5.0	4.0 (1.5 fin high)	5.0
Heat transfer area [m2]	215	1448	3653	1448
Shell side (from reactor outlet to turbine inlet)
Inlet He flow rate [kg/s]	3.4	324	325	325
Inlet He temperature [°C]	950	950	950	950
Outlet He temperature [°C]	389	850	719	850
Inlet He pressure [MPa]	4.06	5.00	4.98	5.00
Pressure loss [kPa]	4	31	30	< 50
Tube side (from secondary Helium IHX inlet to secondary Helium IHX outlet)
Inlet He flow rate [kg/s]	3	81	177	80.3
Inlet He temperature [°C]	237	500	475	491
Outlet He temperature [°C]	869	900	900	900
Inlet He pressure [MPa]	4.21	5.15	5.13	5.15
Pressure loss [kPa]	45	58	70	<60
Weight of main tube bundle [t]	5	50	125	50
Weight of Hastelloy XR used [t]	3	167	860	105
Expected lifetime [yr]	20	20	20	40

. Previously, only the IHXs of a compact surface geometry, such as a plate type, were thought to be economically viable for IHX. This would be correct if a small drop in temperature, i.e., 50 °C, were supposed across the IHX. However, in the case of the GTHTR300C, the Logarithmic Mean Temperature Difference (LMTD) of the IHX is about 150 °C, made possible by the location of IHX installation, where primary heat is moved to the secondary loop in a temperature range of 950–850 °C. Because LMTD is inversely proportional to the surface area required, in the present system, a compact IHX unit is obtained by helical tube-and-shell construction. In the case of GTHTR300C, the primary coolant pressure is lowered to about 5 MPa from 7 MPa of the power only GTHTR300 reactor because of the design need to: (1) reduce the total pressure difference imposed on heat exchangers between reactor and hydrogen loops so that the lifetime of the heat exchangers (IHX and process heat exchangers) can be greatly extended; (2) keep design and performance of the gas turbine system similar to that of the GTHTR300. As a result, the gas turbine system is made common in both design and performance to both the GTHTR300 and GTHTR300C. Heat transfer tubes and tube bundles are made of Hastelloy XR in both HTTR-IHX and GTHTR300C-IHX designs.

Brayton Cycle Description

In the horizontal IHX, the primary helium, exiting the core at 950 °C and 5.1 MPa, passes through the IHX shell, where thermal energy is transferred to the secondary helium circulating inside the helical tubes: the temperature of the secondary helium reaches 900 °C, and so it is sent to the thermal/thermochemical hydrogen production plant. Exiting from the IHX shell side outlet, the primary helium gas is moved towards the turbine inlet at 5 MPa and 850 °C. At the turbine outlet, the helium gas has 2.67 MPa at 619 °C because of its expansion throughout the stages of the turbine, which is needed to drive the turbine. Then, the helium gas flow is directed to the low-pressure side of the recuperator, entering at 2.66 MPa and 614 °C, to be cooled down by the recuperator by transferring its heat to the high-pressure helium gas flow from the compressor outlet. Helium gas at the recuperator low-pressure side outlet has 2.61 MPa and 159 °C, and then it has to enter the pre-cooler, at the same operating conditions, in which helium is further cooled down to 32 °C by rejecting heat to a cooling water system in a way that the helium gas exits from the pre-cooler at 2.59 MPa and 32 °C. This colder helium gas is introduced into the compressor inlet at 2.55 MPa and 28 °C to be compressed up to 5.1 MPa and 136 °C by flowing through the compressor stages. Helium exiting from the compressor outlet is then directed to the high-pressure side of the recuperator, where it enters at 5.12 MPa and 137 °C, is heated up to 597 °C and then exits from the high-pressure side of the recuperator outlet at 5.11 MPa and 597 °C. Going out of the high-pressure side of the recuperator, finally, the helium gas can flow back to the reactor core inlet, entering at 5.1 MPa and 594 °C, in order to complete a closed cycle. The gas–turbine cycle of the GTHTR300C is designed to generate 206 MW electric power for 600 MW reactor thermal power at 46.7% thermal efficiency [32].

4. Safety Issues

It is important to note that IHX provides a clear separation between the nuclear plant and the heat application. Under normal operating conditions, the IHX prevents the primary coolant from accessing the process plant and, on the other side, process gases from being routed through the reactor vessel. The physical separation allows conventional design of the heat application facility (i.e., a heat management facility designed independently without the need to conform to nuclear regulatory safety standards), and repair works can be executed under non-nuclear conditions, reducing costs. Potential issues can arise from material failure due to ageing or high temperatures. Failures in a helical heat exchanger from having helium as the working fluid can occur in various ways, often related to corrosion, wear, or impurity buildup within the tubes. In particular, being a noble gas, helium is non-reactive, but the presence of impurities in the system or imperfect operating conditions can lead to malfunctions. Although helium is not corrosive, the unexpected presence of other gases or impurities in the process flow could cause internal corrosion, especially if the IHX is exposed to high temperatures or repeated thermal cycling; the accumulation of impurities, such as metal oxides or scale, that can settle inside the tubes, can reduce heat exchange efficiency and lead to blockages or leaks that prevent proper helium flow and compromise heat exchange. Helium leaks could occur due to defects in materials, welds, or seals, leading to a decrease in system pressure and potential safety risks. In case of choking and dispersion hazards when the helium flowing in the pipeline leaks into the ground surface and air, helium enters the air but helium causes the slightest choking hazard because it is much lighter than air and rises very fast when departing the ground surface, so it has sufficient time to be diluted even if the leak is significant; no pressure blast due to high pressure is expected because helium is a noble gas and hence inert to most materials and no pipe clogging, or general clogging, resulting from phase change because its critical point is too low (5.19 K) to be considered condensable in engineering practice. Mechanical wear, due to vibration, pressure fluctuations, or abrasive particles in the fluid, can damage helical tubes over time; repeated thermal cycling or mechanical stress can cause helical tube deformation, reducing the efficiency of the IHX; cracks can develop due to thermal or mechanical stress, potentially leading to leaks and failures. The possibility of nuclear activation from using helium as either a coolant or a heat transfer fluid may also raise the possibility of tritium generation through neutron activation of He-3.

For these reasons, it is important to emphasize that proper maintenance and constant monitoring of operating conditions are essential for preventing or promptly identifying failures. Periodic analysis of IHX performance and process parameters can help identify early signs of malfunction and take the necessary corrective measures.

In a water-splitting hydrogen production system [35], production of H₂ and O₂ is simultaneous, so there is a possibility of an internal explosion if inadvertently mixed. On the other hand, the production of these two gases occurs in different and physically separated process steps.

To prevent internal explosions, installation of an emergency purge system is mandatory to remove hydrogen from both pipes and vessels if needed. Fire and explosion are the main consequences of hydrogen release: if ignited during leakage, jet flame formation occurs in which components may be damaged by overheating. Consequently, according to the safety design regulations for chemical plants, leak detectors and emergency shutoff valves must be put in place, detecting and stopping a leakage of hydrogen as soon as possible. To eliminate secondary failure, components have to be positioned according to appropriate separation distances. Jet flame may spread for several metres. In NPP, safety items are located a hundred metres away from the hydrogen production system: in this way, a jet flame would not directly damage any nuclear safety-related systems. If hydrogen does not ignite during leakage, a combustible hydrogen-air cloud is able to evolve, producing a delayed flash fire that provokes damage by emission of strong heat. Differently, in the case of hydrogen-air vapour cloud explosion, the resulting overpressure may damage the reactor building or components installed outside the nuclear plant. Between the nuclear plant and the hydrogen production system, densely arranged obstacles must not be put in that region, since they can accelerate the burning velocity of the hydrogen-air cloud and generate a stronger overpressure. In the hydrogen production system, vessels and pipes have to be located with suitable space to eliminate flame acceleration. Accordingly, essential requirements for coupling an NPP with a H₂ production plant are as follows:

• The assurance of NPP safety against postulated events initiated in the hydrogen plant, in order to keep the cooling of the secondary helium circuit during normal operation and the designed differential pressure between the primary and secondary helium circuits.
• The construction and operation of a H₂ production plant as a conventional non-nuclear facility, by mitigating tritium concentrations in the plant below the limits allowed by legislation (country-dependent) so as to guarantee a radioactivity-free H₂ production plant.

Co-location and connection of a H₂ production plant with an NPP imposes strong directional considerations, and the relative risk of the various possible hydrogen plant configurations is highly anisotropic. To couple a conventional electrolysis H₂ production plant to the NPP, the only requirement is the electrical connection, so these two plants can be simply located as far as it can be requested. Regarding thermal energy transfer, the highest temperature sections of the hydrogen production plants have to be put as close to the nuclear reactor as possible. Instead, the hydrogen production components and hydrogen storage vessels must be located as far away from the nuclear plant as possible. In the case of the HTSE process, the highest temperature component of the process is the hydrogen production unit, so in the hydrogen production cells, H₂ inventory must be minimized by the removal of hydrogen as quickly as it is produced. In the S-I process, there is the possibility to separate the highest temperature section of the process, i.e., the H₂SO₄ decomposition section, from the hydrogen production section, i.e., the HI decomposition section. The accidental atmospheric release of chemical compounds such as SO₂, SO₃, H₂SO₄, HI, and I₂, which are by-products of the S-I cycle, may cause the spread of these toxic materials, eventually penetrating and reaching the NPP control room through ventilation systems.

The reinforced concrete wall of the NPP reactor building and components placed outside have to be designed to withstand severe external loads including not only the above-mentioned vapour cloud explosions but also those typical environmental loads like the wind forces of a typhoon or the ground motion of an earthquake. In case of an explosion accident [35], for instance, the design limit of overpressure in German and Russian design codes on safety plant structures of the NPP is 30 kPa, and if there is a risk of exceeding this limit, a detailed analysis must be performed to verify the structural integrity of reactor building and components.

When the nuclear reactor is coupled with a conventionally designed plant or chemical plant for hydrogen production, to ensure NP safety, appropriate separation distances between the reactor building control room and the hydrogen plant against combustible gas leakages and against toxic gas leakages must be provided. In addition, thanks to the IHX in case of thermochemical production processes, like HTSE or S-I, or thanks to the lack of a need for IHX and the simple electrical connection to AWE, the H₂ production plant and the H₂ storage facility can be conventionally designed. Generally, H₂ storage facilities are made up of the following:

• Tanks for hydrogen storage;
• Pressure regulation and stabilization system;
• Refuelling station (i.e., loading bays);
• Connection pipes for hydrogen transfer;
• Parking area for gas cylinder trailers;
• Rooms intended for ancillary services.

Materials used to manufacture, e.g., the H₂ distribution system, must be compatible with hydrogen at the operating temperatures and pressures and account for hydrogen embrittlement and permeability, porosity, etc.

5. Feasibility Study of Small Modular Reactors and H₂ Production Plant Process Coupling

In this section, the feasibility study carried out by means of the IAEA HEEP software version 2021 (structured in pre-processing, executing, and post-processing modules) via coupling one SMR, such as NuScale or GTHTR300/GTHTR300C reactors, and the H₂ production process is described. To this aim, alkaline water electrolysis (CE04 plant), high-temperature steam electrolysis (HTSE04 plant), and the sulphur–iodine cycle (SI04 plant) have been considered. The main challenges were as follows: to identify the most appropriate hydrogen production process; to determine the number of modules/reactor units guaranteeing the thermal and electrical power for a specific H₂ production plant, assuming an annual H₂ production of 126,000 tons/yr, which requires 4000 m³/day of H₂O, whatever the selected method is. This annual H₂ production is equal to one eightieth of the global steam methane-reforming production of H₂ [36], to about one sixteenth of the German steam methane-reforming production of H₂, to about one tenth of the Italian steam methane-reforming production of H₂ (similar to that of both French and Spanish production), to one fourth of the Greek steam methane-reforming production of H₂, and to about one half of the Swedish steam methane-reforming production of H₂ (similar to that of both Finnish and Austrian production).

The HEEP analysis of NuScale was performed only by coupling it to the CE04 plant, as the NuScale reactor (just like other LWRs) cannot achieve the operational high temperatures needed for both thermal and thermochemical processes, while the analysis of the GTHTR300C reactor was carried out considering all three different H₂ production processes. The HEEP starting data for both GTHTR300C and NuScale analysis are provided in

Table 2. Starting H₂ generation data for HEEP analysis.

	NuScale	GTHTR300/GTHTR300C
	CE04	CE04	HTSE04	SI04
Nuclear H2 plant operating time [yr]	40	40	40	40
Discount Rate [%]	5	5	5	5
Nuclear plant
Construction cost [USD/unit]	2.2 × 108	5.47 × 108	5.68 × 108	5.68 × 108
Decommissioning cost [% of capital cost]	10	10	10	10
O&M cost [% of capital cost]	3	3	3	3
Fuel cost [USD/kg]	1400	5600	5600	5600
Initial amount of fuel [kg]	9250	7090	7090	7090
Annual amount of fuel [kg]	4625	1773	1773	1773
H2 Plant
Construction cost [USD/unit]	4.23 × 108	4.23 × 108	7.06 × 108	1.02 × 109
O&M cost [% of capital cost]	4	4	17.23	6.68
Decommissioning cost [% of capital cost]	10	10	10	10
Number of units of H2 generation plant	1	1	1	1
Rated annual H2 generation capacity per unit [kg]	1.26 × 108	1.26 × 108	1.26 × 108	1.26 × 108
Maximum thermal energy/process [MWth/unit]	0	0	320	1280
Maximum electricity required [MWe/unit]	719	719	480	140
Cost of energy usage (part of O&M cost)	0	0	0	0
H2 Transportation and Storage
500 km pipeline Transportation cost [USD]	4.3 × 108	4.3 × 108	4.3 × 108	4.3 × 108
Compressed Gas Storage cost [USD]	1.64 × 109	1.64 × 109	1.64 × 109	1.64 × 109

. They are the typical costs of individual nuclear and H₂ production plants, widely available in the literature, taking into account the IHX cost inside the NPP construction cost in the case of the GTHTR300C reactor. The 5% discount rate is chosen because this is the typical rate for NPP (and generally plants) in regulated markets with guaranteed revenues, based on the most favourable conditions that can be expected, considering the need to implement these systems to meet the need to produce H₂ cleanly and in large quantities, in a consistent way year after year, shifting the focus of future earnings to the optimal selling price rather than to the LCOH.

If all the energy needed for the H₂ generation comes from NPP, there is no need to supply further electricity. Therefore, the maximum electricity required considers all the electrical needs required by the process, including those of electrical devices, such as pumps, process fluid pumps, helium gas circulator, etc.

The counting of the reactor units is performed starting from the concept that the electricity produced by the NPP must be sufficient for the energy needs of the H₂ production plant, storage, and transportation. For this reason, it is necessary to install the following: 13 NuScale modules for the CE04 plant, 3 GTHTR300 reactors for the CE04 plant, 3 GTHTR300C reactors in the case of HTSE04 plant, and 8 GTHTR300C reactors in the case of SI04 plant.

Table 3. HEEP analysis main results.

HEEP Analysis Results	CE04	HTSE04	SI04
NuScale # reactor units	13	/	/
LCOH [USD/kg]	4.34
H2 plant efficiency [%]	24
Total cost [billions of USD]	26.2
GTHTR300/GTHTR300C # reactor units	3	3	8
LCOH [USD/kg]	2.71	3.57	3.39
H2 plant efficiency [%]	36	43	36
Total cost [billions of USD]	16.4	22.4	41.6

shows that the most efficient coupling can be obtained with HTSE04 plant (Figure 6) because, from a comparison with the other thermal processes, the following findings emerge:

• The HTSE process does not involve the use of chemicals, and its readiness is higher than that of the S-I process;
• The HTSE process requires energy (heat) from the reactor by IHX in order to optimize the process, and this heat is already produced by the core; therefore, it is not necessary to purchase it from external source, so a specific site made of GTHTR300C nuclear reactor coupled to HTSE, at which only hydrogen production is expected (i.e., hydrogen production island), can be built;
• Upon request, GTHTR300C + HTSE04 could also be able to dispatch its residual part, in excess, of produced electrical energy to the electrical grid.

Therefore, GTHTR300C + HTSE04 is the most efficient coupling since it better exploits the electrical and thermal energy resources produced by the reactor.

From a financial point of view, the selling price will be slightly higher than that of already consolidated production methods (e.g., SMR, renewable by wind, solar, etc.); however, they present drawbacks in terms of atmospheric emissions or a lower capacity factor. In order to choose the better way to achieve the most favourable financial scenario, the choice of the selling price is entrusted to dedicated decision makers (stakeholders, regulatory and political commissions of each country, etc.), so

Table 4. Estimated financial results of HEEP case scenarios for 5% discount rate.

	Sale Price [USD/kg]	NPV	IRR	Payback Time [yr] 5% Discount Rate
NuScale + CE04	6	Negative	Negative	Beyond Operating Life
	10	Negative	0%	Beyond Operating Life
	14	Negative	3%	Beyond Operating Life
GTHTR300 + CE04	6	Negative	0%	Beyond Operating Life
	10	Slightly Negative	5%	Slightly Beyond Operating Life
	14	Positive	8%	18
GTHTR300C + HTSE04	6	Negative	Negative	Beyond Operating Life
	10	Negative	2%	Beyond Operating Life
	14	Positive	5%	39
GTHTR300C + SI04	6	Negative	Negative	Beyond Operating Life
	10	Negative	Negative	Beyond Operating Life
	14	Negative	1%	Beyond Operating Life

and

Table 5. Estimated financial results of HEEP case limit scenarios for 0% discount rate.

	Sale Price [USD/kg]	NPV	IRR	Payback Time [yr] 0% Discount Rate
NuScale + CE04	6	Negative	Negative	Beyond Operating Life
	10	Positive	1%	37
	14	Positive	4%	21
GTHTR300 + CE04	6	Positive	0%	38
	10	Positive	5%	18
	14	Positive	8%	12
GTHTR300C + HTSE04	6	Negative	Negative	Beyond Operating Life
	10	Positive	2%	28
	14	Positive	5%	17
GTHTR300C + SI04	6	Negative	Negative	Beyond Operating Life
	10	Negative	Negative	Beyond Operating Life
	14	Positive	1%	31

show two different evaluations of the payback time as a function of two different discount rate and of three different sale prices in order to have the focus on what is the trend of the main financial parameters. In short, decision makers are responsible for the financial sustainability of these projects.

Essential financial parameters, i.e., NPV, IRR, Payback Time, dictate that GTHTR300C + HTSE04 is a more feasible project solution than GTHTR300 + SI04, especially when the foreseen sale price of H₂ produced exceeds 10 USD/kg. In addition, the higher the market sale price is, and the lower the discount rate is, the shorter the payback time will be (see Table 4 and Table 5). Furthermore, the simpler connection mode (i.e., by installing CE plant) should be carried out by considering the GTHTR300 reactors rather than the NuScale ones, due to the following: the cost of the latter, which is almost double compared to the former, because of the higher number of reactor modules required; the better financial parameters of GTHTR300 + CE04, particularly when the sale price is set beyond 10 USD/kg.

6. Conclusions

The main findings state that the innovative nuclear hydrogen production plant using two types of Gen-IV reactor designs can be declared feasible after a preliminary analysis of the most relevant economic and technical aspects. To this aim, starting from the sum of all the total and annual investment costs expected for the construction, operation, and maintenance of the H₂ production plant from nuclear sources, as well as the costs expected for the storage and transport of gaseous hydrogen, it can be concluded that the installation of either GTHTR300 + CE04 or GTHTR300C + HTSE04 is much more feasible than the other options. In addition, according to the criteria for the best exploitation of energy produced by the nuclear reactor, it can be stated that the GTHTR300C + HTSE04 is the most efficient scheme of coupling.

Furthermore, the preliminary results coming from these case studies can be compared to the actual results of different methods and energy sources dedicated to H₂ production. In 2023 [36], the Levelized Costs Of Hydrogen (LCOH) generated through steam methane reforming (SMR) in Europe averaged approximately 3.76 EUR/kg. When incorporating a carbon capture system (CCS), the average LCOH via SMR in Europe increased to 4.41 EUR/kg. Additionally, the LCOH in Europe for 2023 by water electrolysis, utilizing grid electricity, averaged 7.94 EUR/kg. Hydrogen production costs through electrolysis with a direct connection to a renewable energy source (thermochemical methods are not directly feasible for these sources) had an average estimated cost of 6.61 EUR/kg. The LCOHs that come from the analyzed cases of study, particularly from those that are considered the most valuable from a financial point of view, are equal to less than 3.6 USD/kg: GTHTR300 + CE04 has LCOH equal to 2.71 USD/kg, while GTHTR300C + HTSE04 has LCOH equal to 3.57 USD/kg.

Regarding GHG emission, typical values reported in the literature show the following GHG emissions: from 11.6 kgCO₂e/kgH₂ to 20 kgCO₂e/kgH₂ for hydrogen production from fossil fuels, just like steam methane reforming (SMR), down to 6.5 kgCO₂e/kgH₂ in case of SMR with carbon capture; 2.1 kgCO₂e/kgH₂ for water electrolysis using solar power; 0.6 kgCO₂e/kgH₂ for water electrolysis using wind power; 0.4 kgCO₂e/kgH₂ for water electrolysis using hydro power; when using nuclear power, 0.3 kgCO₂e/kgH₂ in case of water electrolysis, 0.8 kgCO₂e/kgH₂ in case of high temperature steam electrolysis, and 1.2 kgCO₂e/kgH₂ in case of S-I cycle.

Greater reliability, capacity factor beyond 90% in every season of the year, and all those typical characteristics that make an NPP much more reliable than conventional renewable energy production method (wind and solar are intermittent in nature, making them unsuitable for providing electricity to applications that require a steady source of electricity to function) and the possibility of producing H₂ without releasing significant amounts of carbon in atmosphere are strong points of merit that favour the choice of a nuclear plant coupled to H₂ plant systems in order to produce H₂.

Hydrogen having 99.9% purity without additional purification processes can be sufficiently employed for general industrial applications [37,38], while for sensitive processes, like PEM fuel cell or electronic manufacturing, post-purification is mandatory, according to international standards [39,40] (for instance, ISO 21087:2019—Analytical methods for hydrogen purity; ISO 14687:2025—Purity requirements for hydrogen used in fuel cells; SAE J2719—Specific guidelines for PEM fuel cell vehicles). Almost all global ammonia production occurs through the Haber–Bosch process, which exploits the reaction between molecular nitrogen and hydrogen: for this purpose, the hydrogen must have a purity generally greater than 99.9% to prevent impurities from poisoning the iron-made catalyst used in the reaction. To assess purity, the following methods can be used: Gas Chromatography, to detect hydrocarbons and other small molecules; Mass Spectrometry, which is highly sensitive and suitable for detecting multiple different contaminants; Cavity Ring-Down Spectroscopy, ideal for detecting trace levels of moisture or complex organics.

Table 6. Different purity levels demanded by different industries.

Industry	Required Hydrogen Purity	Risks Due to Impurities
PEM Fuel Cells	>99.97%	Catalyst degradation (CO, NH3)
Semiconductors	>99.9999%	Particle contamination, O2 traces
Pharma	>99.999%	Wrong chemical products; contamination of final products
Industrial Heat	99.5 < % < 99.99	Combustion inefficiency, corrosion

shows that if a manufacturing process needs absolute consistency, like in chip fabrication, oxygen or water vapour levels must be close to zero. Even minor contaminants can disrupt delicate chemical or electrical balances. High-purity hydrogen may cost more upfront but ensures consistent reaction kinetics, higher product yield, and longer catalyst life. Over time, these savings in process efficiency far outweigh the cost of purer hydrogen.

Typical post-purification processes involve: Temperature Swing Adsorption (TSA), suited for applications requiring deep purification; Pressure Swing Adsorption (PSA), being the most widespread method for large-scale purification; Palladium Membrane Filtration, allowing only hydrogen to pass through, extremely high purity is obtained but has higher operational costs; Cryogenic Distillation, separating gases because of their boiling points, suitable for bulk operations; Electrochemical Purification, still under development for broader use.

Table 7. Summary of the main outcomes.

	NuScale + CE04	GTHTR300 + CE04	GTHTR300C + HTSE04	GTHTR300C + SI04
Temperature Range	<150 °C	<150 °C	750 °C < T < 850 °C	Up to 850 °C
Coupling Mode	Electrical connection	Electrical connection	Thermal connection through IHX	Thermal connection through IHX
Safety Considerations	H2 plant close to reactor is not mandatory No chemicals	H2 plant close to reactor is not mandatory No chemicals	H2 plant close to reactor Thermal energy only No chemicals	H2 plant close to reactor Thermal energy and use of chemicals that are recycled within the S-I system
Hydrogen Purity	Up to 99.9%	Up to 99.9%	Up to 99.9%	>99%
Efficiency [%]	24	36	43	36
LCOH [USD/kg]	4.34	2.71	3.57	3.39

shows that the hydrogen production methods here analyzed constitute excellent methods for producing H₂ for common industrial uses, which typically require H₂ with a purity of no more than 99.9%. To obtain H₂ for specific industrial sectors requiring higher purity, hydrogen produced in this way requires the use of a specific purification process.

Gen-IV SMRs are receiving considerable attention for the several advantages they offer over large reactors (e.g., moderate space for installation, shorter time for construction, economical construction, and safe operation).

Connecting the existing NPP to the AWE plant is the most immediate solution, until it does not divert energy intended to cover existing and future energy needs for necessary uses. Therefore, installing these types of dedicated nuclear hydrogen facilities can help meet the H₂ needs of specific sectors without diverting energy intended to cover traditional energy needs. The main industrial, economic, and political players strongly interested in these kinds of plants should include the following: countries aiming to build new reactors; developing countries; policy makers who are oriented towards the development of innovative low-emission technologies or to the reconversion of obsolete production sectors in order to build factories made of these kinds of plants, only dedicated to hydrogen production. In more detail, countries showing interest in these kind of technologies include the following: European countries with historical expertise in gas-cooled graphite-moderated reactors (England) and HTSE technology (i.e., the German company Sunfire is a leader), while France is mainly interested in implementing H₂ plants in their existing NPP fleet; the U.S.A., as a leader in pressurized water SMRs (i.e., NuScale), Brazil, the UAE, Russia, Canada, and the Netherlands are very interested in new NPP supporting H₂ production; China and Japan, as leading countries in developing gas-cooled graphite-moderated small modular reactors, are interested for establishing their commercial leadership in this sector for years to come.

So, it is expected that Gen-IV SMRs may be considered first for new installations to obtain the production of a large amount of hydrogen in a sustainable way.