Systematic Analysis of the Hydrogen Value Chain from Production to Utilization

Abstract

Hydrogen produced from renewable sources has the potential to tackle various energy challenges, from allowing cost-effective transportation of renewable energy from production to consumption regions to decarbonizing intensive energy consumption industries. Due to its application versatility and non-greenhouse gaseous emissions characteristics, it is expected that hydrogen will play an important role in the decarbonization strategies set out for 2050. Currently, there are some barriers and challenges that need to be addressed to fully take advantage of the opportunities associated with hydrogen. The present work aims to characterize the state of the art of different hydrogen production, storage, transport, and distribution technologies, which compose the hydrogen value chain. Based on the information collected it was possible to conclude the following: (i) Electrolysis is the frontrunner to produce green hydrogen at a large scale (efficiency up to 80%) since some of the production technologies under this category have already achieved a commercially available state; (ii) in the storage phase, various technologies may be suitable based on specific conditions and purposes. Technologies of the physical-based type are the ones mostly used in real applications; (iii) transportation and distribution options should be viewed as complementary rather than competitive, as the most suitable option varies based on transportation distance and hydrogen quantity; and (iv) a single value chain configuration cannot be universally applied. Therefore, each case requires a comprehensive analysis of the entire value chain. Methodologies, like life cycle assessment, should be utilized to support the decision-making process.

1. Introduction

In recent years, with the definition of national and international strategies that encourage and strengthen the energy transition, hydrogen produced from renewable resources has emerged as a potential energy vector to tackle climate change and energy dependency [1,2]. In Europe, the European Green Deal [3], the European Union Hydrogen Strategy [4], and the RePowerEU plan [5], among other initiatives, have strengthened the commitment to low-carbon hydrogen. The first is a set of policy initiatives designed to guide the European Union (EU) towards a green transition, the second defines key actions to develop a hydrogen economy, and the third outlines a plan focused on reducing Europe’s dependence on fossil fuels and accelerating the transition to green energy.

Hydrogen is particularly interesting as a pathway to decarbonize our economies for several reasons; it is light, storable, and reactive, its energy content per unit mass is high, its utilization does not generate greenhouse gas (GHG) emissions or other air pollutants, with the only byproduct being water, and it can be generated from diverse low-carbon energy sources, like renewable electricity, biomass, and nuclear energy [1].

Hydrogen produced from renewable sources has the potential to tackle various critical energy challenges. It can be used as an energy carrier to allow cost-effective transportation of renewable energy from production to consumption regions, with much lower costs than electrical transmission for long distances [6]. It can facilitate seasonal energy storage. Hydrogen can help decarbonize intensive industries and long-haul transport, among others. It can also be used as a decarbonization solution for the current natural gas system.

According to the International Energy Agency (IEA), to achieve net zero emissions by 2050, it is expected that 200 Mt of hydrogen will be produced by 2030, 130 Mt more than in 2018, of which 70% was produced from low-carbon technologies [7]. This value will further increase to 500 Mt by 2050, when almost 100% of the hydrogen will be produced by low-carbon technologies [7]. To simultaneously support the exponential growth of hydrogen production and the shift from fossil fuel-based to low-carbon technologies, the research needs to focus on the development of green hydrogen value chains.

Currently, there are some barriers and challenges that need to be addressed to create a fully renewable hydrogen economy. First, renewable hydrogen production costs (USD 3.4 to 12/kgH₂ for electrolysis with low-emission electricity) are still higher than other competing energy carriers (USD 0.2 to 1.6/kg for ammonia production) and higher than hydrogen produced from fossil fuels (USD 1.0 to 3.0/kgH₂) [8,9]. It is expected that this tendency will remain until 2030 [10]. Moreover, adding to the high production costs, storage, transportation, and delivery to end users also contribute to the increase in the hydrogen unitary cost. Secondly, current hydrogen value chains are mostly designed based on the use of fossil fuels as feedstock. To create a fully renewable hydrogen economy, new suitable pathways to design cost-effective hydrogen value chains need to be created. Due to hydrogen’s versatility of production, storage, and distribution, associated with local characteristics, such as weather and geographical conditions [11], existing infrastructures, demand sectors, and demand profile, it is not possible to define only one pathway as the most cost-effective option to design green hydrogen value chains, meaning that for each possible value chain, specific assessments and investments need to be carried out.

The hydrogen value chain is essentially composed of four different phases, namely production, storage, transportation and distribution, and end-use. Figure 1 illustrates a hydrogen energy system. Depending on the hydrogen end-use, five main value chain configurations can be defined based on the hydrogen end-use, namely power-to-gas, power-to-mobility, power-to-industry, power-to-synfuel, and power-to-power [12].

The present work aims to characterize the different hydrogen production, storage, transport and distribution technologies that compose the hydrogen value chain. Identifying the main advantages and disadvantages of each technology, as well as the main working parameters.

This study is built on the extensive existing literature on hydrogen energy systems and the respective value chain. Typically, the studies available in the literature focus on individual phases of the value chain. In the production phase, Zainal et al. [13] analyzed the main hydrogen production technologies, assessing their respective cost, maturity, and environmental impact. Chelvam et al. [14] reviewed the life cycle assessment performance of hydrogen production technologies. El-Shafie [15] analyzed and compared different commercially available water electrolysis systems, and Gomaa et al. [16] explored the challenges and advancements in system designs and electrode materials engineered for seawater electrolysis for hydrogen production. Regarding storage and transportation, Abe et al. [17] analyzed gaseous, liquid, and solid-state hydrogen storage systems, focusing on developments in hydrogen storage in metal hydrides. Lu et al. [18] performed a systematic review to identify and assess the factors that influence the storage and transportation costs. Wang et al. [19] explored the hydrogen strategies and roadmaps of different countries, highlighting the current maturity, challenges, and future directions of hydrogen storage and transportation technologies. In the end-use and hydrogen trends domain, Capurso et al. [20] reviewed and explored the developments, advantages and drawbacks of hydrogen economies and assessed the impact of these economies in various sectors, such as transport, industry, and power generation, while Tak et al. [21] explored the role of hydrogen in decarbonizing the aviation and automotive industries. This research seeks to centralize information from all phases of the value chain within a single study and aims to update the technology readiness levels of each technology used in the different phases, in comparison to previous studies [22].

To achieve this, Section 2 analyses the main hydrogen production technologies, presenting the types of hydrogen produced, the technology efficiency, readiness level, and the respective levelized cost of hydrogen. Section 3 reviews the main hydrogen storage technologies, highlighting key characteristics, such as storage pressure and temperature, gravimetric and volumetric capacities, and TRLs. Section 4 presents the main hydrogen transportation and distribution technologies, highlighting the respective transportation costs. Section 5 introduces the four main sectors where hydrogen is expected to play a central role. Finally, Section 6 discusses the key challenges associated with the implementation of a large-scale green hydrogen economy.

The conclusions obtained through this study should support researchers, decision-makers and the public in selecting hydrogen technologies, among the vast list of available technologies, that best fit the design of the specific hydrogen value chain for the case study at hand. Additionally, this study supports future research in addressing the specific challenges associated with scaling up the green hydrogen energy economy.

2. Hydrogen Production Technologies

Hydrogen production technologies can be divided into four groups, namely thermochemical processes, biological processes, electrolytic processes, and photolytic processes [23,24], as represented in Figure 2.

(i) Thermochemical processes are those where heat and chemical reactions are used to generate syngas from organic materials. (ii) Biological processes are those where microorganisms produce hydrogen through biological processes. (iii) Electrolytic processes are those where water is split into hydrogen and oxygen through one electrical current. (iv) Photolytic processes are those where solar irradiation is used to conduct the hydrolysis process.

Depending on the required feedstock, the production technology used, and the associated GHG emissions, the produced hydrogen can be classified into different categories [25,26]. Green hydrogen is produced through the electrolysis of water powered by renewable energy or through biomass gasification, resulting in no GHG emissions. Purple hydrogen is also produced through electrolysis but is powered by nuclear energy, leading to near-zero emissions. Turquoise hydrogen is produced from natural gas through pyrolysis, a process that produces low emissions and no direct GHG emissions from hydrogen itself. Blue hydrogen comes from fossil fuels but includes carbon capture and storage (CCS) to significantly reduce emissions. Gray hydrogen is also derived from fossil fuels but without any CCS, leading to high levels of GHG emissions. [25,27]. The main hydrogen production technologies are described below.

2.1. Thermochemical Processes

In thermochemical processes, syngas is produced, using heat and chemical reactions, from a variety of substances, such as coal, oil, natural gas, and biomass. The syngas is then upgraded, through a water–gas shift reaction and/or through separation techniques, to obtain a high yield of hydrogen. These processes have the advantage of being able to produce hydrogen at an industrial level, although they are characterized by being highly energy intensive. Steam methane reforming, partial oxidation, autothermal reforming, gasification, and pyrolysis are the main thermochemical technologies, and these are explored in more detail below.

2.1.1. Steam Reforming

Steam reforming (SR) is currently the most used process to produce hydrogen [1] and can be divided into four categories, according to the substance used as feedstock and the technology implemented, namely steam methane reforming (SMR), methanol/ethanol steam reforming, sorption enhanced-methane steam reforming, and glycerol steam reforming. For hydrogen production, SMR is the most frequently used process [28]. In SMR, natural gas and pressurized steam are used to produce carbon monoxide (CO) and hydrogen (H₂) in four steps, as represented in Figure 3.

In the first step of the SMR process, natural gas goes through a pretreatment phase to remove some of the minor elements that compose the natural gas, especially hydrogen sulfide, since sulfur compounds can cause catalyst poisoning. Then, the natural gas reacts with steam, beginning the steam reforming phase. The syngas produced in the steam reforming phase goes through a second reaction in the water–gas shift reactor [29]. The water–gas shift reaction converts carbon monoxide and steam to carbon dioxide and hydrogen. Further processing steps, such as freezing, methanization, gas scrubbing, pressure swing adsorption, selective catalytic oxidation, storage in hydrides, and membrane diffusion, depending on the application, can be implemented to remove the carbon dioxide (CO₂) and leave pure hydrogen [27,29,30].

2.1.2. Partial Oxidation

Partial oxidation is a thermochemical process, similar to SRM. The main difference between the two processes lies in the way the syngas is produced. In partial oxidation, the natural gas reacts with limited amounts of oxygen, typically from air, in a high-pressure refractory-lined reactor, producing the desired syngas [31]. After the production of the syngas, the process follows the same steps as described for SRM, as represented in Figure 4.

Unlike SMR, partial oxidation is an exothermic process. It is faster than SMR, requires a smaller reactor vessel, and could use feedstock different from natural gas, such as heavy fuel oil [31]. However, this process produces less hydrogen per unit of input fuel than SMR and has a higher hydrogen production cost.

2.1.3. Autothermal Reforming

Autothermal reforming combines the two previous processes to produce hydrogen, as represented in Figure 5. Both steam and oxygen are introduced into the reformer, and the oxidation and reforming reactions occur simultaneously. Thus, the exothermic partial oxidation provides energy to the endothermic steam reforming reaction [31].

Due to the overlapping of an endothermic and exothermic reaction, autothermal reforming demands lower energy than the SRM process, although it produces a lower hydrogen yield than SMR, but is still able to produce more hydrogen per unit of input fuel than the partial oxidation process [31].

2.1.4. Gasification

Gasification is a thermochemical process that uses heat and chemical reactions to convert carbonaceous solid fuel, in the presence of a specific gasification agent, into a synthetic gas, composed of carbon monoxide and hydrogen. Coal, heavy hydrocarbons, and biomass are frequently used as feedstocks. The entire process to obtain the desired hydrogen is composed of three phases, namely gasification, gas cleaning and upgrading, and hydrogen separation [30], as represented in Figure 6. Using coal as the feedstock results in the production of gray carbon, as a high content of CO₂ emissions is released [33]. When biomass is used as the feedstock, green hydrogen is produced, since it is considered that all CO₂ generated is absorbed by plants through the photosynthesis process, producing new biomass and making this process net zero [32]. Current research on biomass gasification focuses on assessing the effects of the reactor’s operating conditions, such as the temperature, diameter, residence time, gasifying agent, and ash effect on the quality and characteristics of the final products [34].

2.1.5. Pyrolysis

Pyrolysis is a thermochemical decomposition process, where a carbon-based product, used as feedstock, is physically and chemically decomposed into different molecules at elevated temperatures and in an inert atmosphere. In this process, represented in Figure 7, high temperatures are used to break the thermal stability of chemical bonds of the feedstock, thus leading to the formation of new molecules. Methane and biomass are frequently used as feedstock. In methane pyrolysis, methane is decomposed into gaseous hydrogen and elemental carbon. Since no direct CO₂ emission results from this process, the hydrogen produced with methane pyrolysis is classified as turquoise hydrogen [27,33,35]. Biomass pyrolysis is very similar to methane pyrolysis, but the hydrogen generated during this process is classified as green [32,36].

2.1.6. Thermochemical Water Splitting

Thermochemical water splitting is a thermochemical process that uses high-temperature heat, normally resulting from concentrated solar power or the waste heat of nuclear power reactions, to promote a series of chemical reactions with the ultimate goal of decomposing water into oxygen and hydrogen [8].

Since the direct thermal dissociation of water (thermolysis) only happens at very high temperatures, greater than 2227 °C, supplying heat to gaseous water (steam) is not an economically feasible way of carrying out this decomposition [8]. Thus, in thermochemical water splitting, chemical species are added to water to promote a set of reactions in series (a thermochemical cycle) that split water at lower temperatures (from 500 °C to 2000 °C). These intermediate species are fully recycled into their initial state by working in a closed cycle, so only water is consumed throughout the process.

Many thermochemical cycles have been investigated in the literature, with over 300 cycles examined [9], but only some have been tested and proven to be technically feasible to produce large-scale hydrogen from a thermodynamic, cost, and efficiency perspective. As the number of steps in the cycle increases, the temperature required to perform water splitting decreases. The following Equations (1)–(4) represent a four-step thermochemical cycle [37]:

$$H_{2}O+AB\to A{H}_2+BO$$

(1)

$$A{H}_2\to H_2+A$$

(2)

$$BO\to {\displaystyle \frac{1}{2}}{O}_2+B$$

(3)

$$A+B\to AB$$

(4)

2.2. Biological Processes

Microorganisms, such as microalgae and cyanobacteria, can produce hydrogen through biological processes. These processes can be carried out at low temperatures (between 30 °C to 60 °C) when compared to thermochemical processes, and at atmospheric pressure, making them less energy-consuming. Nonetheless, biological processes are more sophisticated in design and performance and present a lower hydrogen production rate [38]. Biological processes can be divided into fermentation and biophotolysis. Fermentation can be further divided into dark fermentation and photo-fermentation, and bio-photolysis can be divided into direct and indirect bio-photolysis [39].

Dark fermentation is a biological hydrogen production process where biomass is converted to hydrogen, carbon dioxide, and small amounts of methane, carbon monoxide, and hydrogen sulfide, in the absence of light [40,41,42]. Photo-fermentation is a three-step process, where photosynthetic bacteria, such as Rhodospirillum, Rhodobium, Rhodopseudomonas, and Rhodobacter, produce green hydrogen through the action of their nitrogenase in the presence of light and reduced compounds (organic acid) [39]. Bio-photolysis produces hydrogen through the dissociation of water molecules in biological photosynthetic microorganisms in the presence of solar radiation, and, as such, without external organic matter (biomass) [39].

Among the processes presented, dark fermentation is considered, simultaneously, the most well-understood and most promising among the biological processes. It requires simple reactor designs, with this being one of the reasons for its attractiveness, but nevertheless presents a relatively low hydrogen yield, with maximum values of 4 mol H₂/mol glucose and 6 mol H₂/mol sucrose [39]. Currently, dark fermentation is an extensive research area, focusing especially on determining the best reactor configuration, and on minimizing the hydrogen non-producing microorganisms’ activity and maximizing the hydrogen-producing microorganisms’ activity to increase the hydrogen yield [39]. Dark fermentation is viewed as a possibility to integrate energy production with waste management.

2.3. Electrolysis

The electrolysis process occurs within an electrolytic cell, composed of two electrodes, an ion-conducting electrolyte, and a separator/diaphragm. There are currently three main types of electrolysis technologies used to produce hydrogen, namely polymer electrolyte membrane water electrolysis (PEMEL), alkaline water electrolysis (AEL), and solid oxide water electrolysis (SOEL) [43]. These technologies differ in their electrolyte, ionic agent, operating conditions, and stage of development [44]. In addition, anion exchange membrane water electrolysis (AEMEL) is a developing technology, not yet scaled up to commercial applications, that presents good potential to be used as a way to produce hydrogen due to its low cost and high performance when compared with other electrolysis technologies.

2.3.1. Alkaline Water Electrolysis

AEL is a technology that has existed for more than two hundred years, and, as such, is now a well-established mature technology for hydrogen production at a large scale. In AEL, hydrogen and hydroxyl ions are generated by reduction at the cathode [43], as in Figure 8. The electrolysis cell is composed of nickel-coated stainless steel electrodes separated by an asbestos/zirconium dioxide gas-tight diaphragm, with an aqueous solution of potassium hydroxide as its electrolyte [44].

This technology presents low operating temperatures, between 30 °C to 80 °C, long-term stability, with a lifetime of about 90,000 h, and a relatively low investment cost. Nonetheless, some limitations can also be pointed out, such as the technology’s limited current densities, need for highly concentrated liquid electrolytes, and moderate hydrogen purity when compared with other electrolysis technologies due to a high crossover of gases [43,44].

The current research focuses on reducing the crossover of gases and on increasing the current density; to do so, new separators and electrode materials are being studied. In parallel, reducing the hydrogen production cost is also one of the main research focuses [44]. Recent progress in alkaline water electrolysis technology can be found in [45].

2.3.2. Polymer Electrolyte Membrane Water Electrolysis

PEMEL was first developed in the 1960s, and today it is a commercially available technology for the large-scale production of hydrogen. In PEMEL, water is oxidized on the anode to produce oxygen and protons. The protons migrate to the opposite electrode, where, by reduction, hydrogen is released, as in Figure 9. This technology operates at temperatures of around 30 °C to 80 °C, with pressures up to 30 bar, which can be higher for a small-scale production configuration, and presents a stable operation lifetime of about 40,000 to 60,000 h [27,44,46].

A PEMEL cell is composed of two electrodes, with precious metal catalysts, a solid polymer electrolyte, two porous transport layers, and two bipolar plates. A proton exchange membrane, usually made of a polymer with high proton conductivity and chemical stability, such as Nafion or Fumapem, is used as an electrolyte. This membrane enables a high proton conductivity, low crossover of the gases, high operating pressures, and a compacted system design. The two electrodes are directly coated on the proton exchange membrane, the cathode is typically made of carbon-based materials, and the anode is made of precious metals, such as platinum, with both the cathode and anode coated with a catalyst material, such as platinum or another platinum group metal alloy [27]. Information about the state of the art of PEMEL cells can be found in [47].

When compared with AEL, PEMEL presents higher operating current densities, higher hydrogen purity, a more compact design, and a quicker response [44]. Nonetheless, some disadvantages can be pointed out, such as the high cost of the components [43] and the existing acidic environment originated by the proton-conducting ionomer that contributes to the degradation of the electrodes. The research currently focuses on further increasing the current density, lowering the catalyst loading, reducing the use of expensive materials, and reducing hydrogen production costs [44].

2.3.3. Solid Oxide Water Electrolysis

SOEL development began in the 1970s in the USA. This electrolysis technology operates with steam at temperatures between 500 °C and 850 °C. By working with higher temperatures, the required energy to decompose water into hydrogen and oxygen is drastically reduced. This energy reduction increases the energy efficiency of the process [43], which in turn decreases the hydrogen production cost since energy consumption is pointed out as one of the main factors responsible for hydrogen production cost through electrolysis.

In SOEL, water is reduced at the cathode electrode, generating hydrogen and oxygen ions, which are further reduced at the anode electrode to generate oxygen, as in Figure 10. The SOEL cell is composed of two porous electrodes and a ceramic electrolyte. The cathode is typically produced from a ceramic and metal material, such as yttria-stabilized zirconia and nickel, while the anode is produced using perovskite materials, such as a mixed metal oxide composed of lanthanum, strontium, cobalt, and iron (LSCF) or a mixed metal oxide composed of lanthanum, strontium, and manganese (LSM). The most frequently used ceramic electrolyte is yttria-stabilized zirconia [44].

When compared with other electrolysis technologies, SOEL presents a higher energy efficiency, high conversion efficiencies and lower hydrogen production costs [43]. This technology is most attractive when high-temperature heat sources are available, such as nuclear energy [44]. Currently, despite these advantages, it presents low long-term stability, with a stable operation lifetime of only 20,000 h, and is still not commercially available at a large production scale [43]. The research currently focuses on further developing this technology to achieve the same commercialization stage as other electrolysis technologies, increasing the technology’s longer-term stability, and reducing the hydrogen production cost [44]. The opportunities and challenges faced by SOEL to reach a fully commercial state are further detailed in [48].

2.3.4. Anion Exchange Membrane Water Electrolysis

AEMEL is a developing technology, not yet scaled up to commercial applications, that presents good potential to be used as a way to produce hydrogen due to its low cost and high performance when compared with other electrolysis technologies. Despite presenting a similar configuration and working principle to AEL, AEMEL possesses an anion exchange membrane (such as ammonium ion exchange membranes) instead of the gas-tight diaphragm and does not require a highly concentrated electrolyte [44], as shown in Figure 11.

Researchers are working on scaling up the production capacity, increasing the operational stability, which at the moment is 35,000 h, and lowering the hydrogen production cost [44]. In [49], the state of the art of the present technology is described, as well as the challenges that it faces.

In all the previously described cases, despite not originating any process-related GHG emissions, these emissions may arise from the water and electricity supply chains, among others. The hydrogen produced through electrolysis is only classified as green hydrogen if renewable energy resources are used to generate the electricity required for the electrolysis process.

2.4. Photolytic Processes

Solar radiation can be used to split water into hydrogen and oxygen. Depending on the configuration selected to use solar energy in the water decomposition process, hydrogen production from solar-based water splitting can be divided into direct and indirect methods [50].

In the direct method category, the direct thermal method stands out as the most common. This method produces hydrogen and oxygen through the decomposition of water subjected to a great amount of heat in a single process step. The direct thermal technique is characterized by having low conversion efficiency, requiring high temperatures that result in high heat dissipation, and presenting big challenges in disassociating the obtained gases. Due to all these drawbacks, indirect methods have gained greater relevance as the go-to photolytic group of processes to generate hydrogen [50].

Photochemical water splitting is a solar-based hydrogen production method through water decomposition. This process has a similar working principle to the type of processes previously studied (electrolysis), but the power supply battery is replaced by a semiconductor material that generates an electron–hole pair when subjected to solar radiation equal or greater than the semiconductor bandgap (the gap between the valence and conduction bands) [50].

Depending on the system components that carry out the process, frequently referred to as reactors, photochemical water splitting can be divided into photocatalytic (PC) water splitting and photoelectrochemical (PEC) water splitting [51]. The main difference between the two is that powder semiconductors are used in PC water splitting, while semiconductor electrodes are used in PEC water splitting.

The PC water splitting process is composed of three main steps [51]. In the first step, photons are absorbed by the powder semiconductors, generating electron–hole pairs when the absorbed energy is higher than the bandgap. In the second step, electrons and holes are separated and migrate to the reaction sites on different sides of the surface of the material. In the third step, water is oxidized by the holes to produce oxygen and hydrogen ions, at the material surface, and the produced hydrogen ions are reduced by the electrodes, producing hydrogen at the material surface. A schematic illustration of the process operating principle can be found in Figure 12a. Depending on the reactor type, the nanoparticle semiconductors suspended in the electrolyte can be disposed of in a single-bed colloidal or in a dual-bed colloidal, where one size carries out the oxidation reaction and the other one performs the reduction reaction.

PEC water splitting has a similar working principle to PC, but in this process, planar photovoltaic cells are placed in a reservoir with an electrolyte [51]. Each cell has two photoelectrodes, taking the role of the anode and the cathode. The oxidation reaction is carried out on the anode side, while the reduction reaction is accomplished on the cathode side, as in Figure 12b.

2.5. Comparison of Hydrogen Production Technologies

For each technology previously addressed, Table 1 presents an overview of the main advantages, disadvantages, hydrogen classification, production price, and an assessment of the technology readiness, as well as an indication of whether this technology falls under the scope of the present work.

Based on the review of the current main hydrogen production technologies, it is possible to state that water splitting is one of the most interesting and promising approaches to produce low-carbon hydrogen, since only oxygen and hydrogen result as byproducts of the production process. Electrolysis is the frontrunner to produce green hydrogen at a large scale, since some of the production technologies under this category have already achieved a fully developed and commercially available state, such as AEL and PEMEL. It is seen as a user-friendly technology due to its scalability [53], environmental benefits, and compatibility with renewable energy sources [54].

From a cost perspective, gray hydrogen stands out as the most economical option among current hydrogen production methods. The cost of gray hydrogen ranges from USD 0.7–2.08/kgH₂ for steam methane reforming, and USD 1.24/kgH₂ for partial oxidation and autothermal reforming. In comparison, blue hydrogen produced by methane pyrolysis ranges from USD 1.59–3.20/kgH₂, and green hydrogen produced via electrolysis powered by utility-scale PV in EU and Norway ranges from USD 2.90–14.4/kgH₂ and powered by offshore wind in EU and Norway ranges from USD 2.2–9.4/kgH₂. This means that a trade-off between economic and environmental constraints needs to be made. Green hydrogen prices are influenced by the cost of the renewable energy and of the electrolyzers used in the process [55]. Regulatory frameworks can help reduce the existing gap between green and gray hydrogen. As higher penalties for GHG emissions are imposed, the production cost of gray hydrogen will increase, making low-carbon hydrogen production processes a more competitive technology. Additionally, to ensure a progressive transition from gray to green hydrogen, balancing the economic and environmental dimensions, technologies, like SRM-CCS and methane pyrolysis, that have lower emissions than conventional fossil fuel thermochemical processes, and that are cheaper than green hydrogen processes, can be considered as bridging technologies. It is also important to highlight that, according to the Global Hydrogen Review report released by the IEA in October 2022 [56], in regions with simultaneously good renewable resources and large imports of fossil fuels, green hydrogen production cost is already competitive with gray hydrogen production cost.

Table 1. Comparison of hydrogen production technologies.

Technology	Feedstock	Energy Source	Advantages	Disadvantages	Hydrogen Classification	Efficiency (%)	LCOH (USD/kgH2)	TRL	REF
Steam reforming	Fossil fuels	Thermal	- Developed technology with technology readiness to produce hydrogen at a large scale - Infrastructure already exists	- High energy requirements - GHG emissions	Gray	69–85	0.7–2.08	9	[12,23,41,57,58]
Steam reforming + CCS	Fossil fuels	Thermal	- Lower GHG emissions than steam reforming - Can be used as a bridging technology from gray to green hydrogen	- Lower efficiency than steam reforming	Blue	55–80	1.2–2.27	8–9	[23,27,59]
Partial oxidation	Fossil fuels	Thermal	- Fully developed technology - Capable of using less noble feedstock - Cost-effective method	- Slow hydrogen production when compared with technologies of the same category - GHG emissions (but less than SMR)	Gray	60–75	1.24	9	[12,31,41,58]
Autothermal reforming	Fossil fuels	Thermal	- Requires lower energy than SMR and is still capable of producing H2 at an industrial scale - Higher efficiency than SMR	- Complex process, when compared with technologies of the same category - GHG emissions (but less than SMR)	Gray	60–75	1.24	9	[12,31,58]
Gasification	Fossil fuels	Thermal	- Low H2 production cost - Abundant and cheap feedstock	- Emission of pollutants and harmful particles - GHG emissions (but much less than the above technologies) - Fluctuating H2 yields	Gray	74–85	1.34–2.5	9	[12,24,32,41,57,58,59]
	Biomass	Thermal	- Net-zero emission process - Capable of producing a great amount of hydrogen - Synergies with waste management - Cheap feedstock	- Biomass unavailability - Complex logistics transportation for decentralized sites - Complex H2 CO2 separation process - High investment cost - Fluctuating H2 yields - Tar formation	Green	35–50	1.77–2.77	7	[23,24,32,33,41,57,60,61]
Gasification + CCS	Fossil fuels	Thermal	- Lower GHG emissions than gasification - Can be used as a bridging technology from gray to green hydrogen	- Lower efficiency than gasification	Blue	60–80	1.63–2.60	8–9	[24,59]
Pyrolysis	Fossil fuels	Thermal	- Lower emissions than any other process with fossil fuel feedstock - Similar efficiency to SMR + CCS - Consumes less energy when compared with the most common thermochemical processes - Simple operation principle	- Despite consuming less energy than SMR and other processes it is still an energy intensive process - Still not at a maturity level that enables large-scale hydrogen production	Turquoise	~58	1.59–3.20	7	[24,27,33,57,62]
	Biomass	Thermal	- Same advantages as biomass gasification	- There are some challenges in scaling up the technology (e.g., a continuous biomass feeding system needs to be implemented) - Fluctuating H2 yields - Tar formation	Green	35–50	1.25–2.20	7	[12,24,32,36,60,61]
Thermochemical cycles	Water	Thermal (solar)	- Very low environmental impact	- Not yet cost-effective - Requires a solar irradiance-exposed area	Green	20–55	7.98–8.40	1–3	[23,24,37,63]
Thermochemical cycles	Water	Thermal (nuclear)	- High efficiency - Takes advantage of residual/waste heat from nuclear reactors - Low emissions	- Generation of nuclear waste - Safety concerns regarding the operation of the nuclear reactor	Purple	20–55	2.17–2.63	1–3	[23,24,37,63]
Dark fermentation	Biomass	Organic matter	- Low operating temperatures and pressure - Simple method	- Requires a large reactor - Low H2 yield	Green	60–80	2.15–2.57	5	[12,24,39,60,61]
Photo-fermentation	Biomass	Solar radiation	- Low operating temperatures and pressure - Carbon-neutral with low carbon emissions during the process	- Requires a large reactor and solar radiation - Requires hydrogen reoxidation - Slow process with low efficiency - Low H2 yield	Green	10	2.37–2.83	4	[12,24,39,60,61]
Bio-photolysis	Water	Solar radiation	- Low operating temperatures and pressure - Consumes CO2 and produces O2 - Waste or non-drinkable water can be used as feedstock	- Not ready to produce hydrogen at a large scale - Requires a large reactor and solar radiation - Low H2 yield	Green	10	1.42–2.13	1–3	[12,24,39,60]
Electrolysis (AEL)	Water	Electric (RES)	- Simple process - Low operating temperatures - Zero GHG emissions (if RESs are used to generate the required energy) - Fully developed and commercially available - Long-term stability	- Limited current densities - Requires a highly concentrated liquid electrolyte - Moderate hydrogen purity	Green	50–78	2.90–14.40 (utility-scale PV in the EU and Norway) 2.20–9.40 (on and offshore wind in the EU and Norway)	9	[10,44,60,62,64]
Electrolysis (PEM)	Water	Electric (RES)	- Simple process - Low operating temperatures - Zero GHG emissions (if RESs are used to generate the required energy) - Fully developed and commercially available - High H2 purity - Compact design and a quick response	- Requires the use of noble metals, resulting in a high investment - Short lifetime	Green	50–83		9	[10,44,60,62,64]
Electrolysis (AEM)	Water	Electric (RES)	- Simple process - Low operating temperatures - Zero GHG emissions (if RESs are used to generate the required energy) - Lower H2 cost and high performance when compared with other electrolysis technologies	- Not commercially available on a large production scale	Green	45–55		6	[10,44,60,62,64]
Electrolysis (SOEL)	Water	Electric (RES)	- Zero GHG emissions (if RESs are used to generate the required energy) - Favorable electrolysis thermodynamics and kinetics - High energy efficiency - Less electricity consumption than other electrolysis processes - High conversion efficiencies and lower hydrogen production costs than AEL and PEM	- Low long-term stability - Not commercially available on a large production scale	Green	57–69		7	[10,44,60,62,64]
Photolysis	Water	Solar radiation	- Production of O2 as a byproduct - Zero GHG emissions - Long operating life span	- Low efficiency process - Requires solar radiation - High H2 production cost - Challenges to scale up technology to reach large-scale hydrogen production	Green	<12	10.36–18.98	1–3	[12,24,41,50,51,60]

Table 1. Comparison of hydrogen production technologies.

Technology	Feedstock	Energy Source	Advantages	Disadvantages	Hydrogen Classification	Efficiency (%)	LCOH (USD/kgH2)	TRL	REF
Steam reforming	Fossil fuels	Thermal	- Developed technology with technology readiness to produce hydrogen at a large scale - Infrastructure already exists	- High energy requirements - GHG emissions	Gray	69–85	0.7–2.08	9	[12,23,41,57,58]
Steam reforming + CCS	Fossil fuels	Thermal	- Lower GHG emissions than steam reforming - Can be used as a bridging technology from gray to green hydrogen	- Lower efficiency than steam reforming	Blue	55–80	1.2–2.27	8–9	[23,27,59]
Partial oxidation	Fossil fuels	Thermal	- Fully developed technology - Capable of using less noble feedstock - Cost-effective method	- Slow hydrogen production when compared with technologies of the same category - GHG emissions (but less than SMR)	Gray	60–75	1.24	9	[12,31,41,58]
Autothermal reforming	Fossil fuels	Thermal	- Requires lower energy than SMR and is still capable of producing H2 at an industrial scale - Higher efficiency than SMR	- Complex process, when compared with technologies of the same category - GHG emissions (but less than SMR)	Gray	60–75	1.24	9	[12,31,58]
Gasification	Fossil fuels	Thermal	- Low H2 production cost - Abundant and cheap feedstock	- Emission of pollutants and harmful particles - GHG emissions (but much less than the above technologies) - Fluctuating H2 yields	Gray	74–85	1.34–2.5	9	[12,24,32,41,57,58,59]
	Biomass	Thermal	- Net-zero emission process - Capable of producing a great amount of hydrogen - Synergies with waste management - Cheap feedstock	- Biomass unavailability - Complex logistics transportation for decentralized sites - Complex H2 CO2 separation process - High investment cost - Fluctuating H2 yields - Tar formation	Green	35–50	1.77–2.77	7	[23,24,32,33,41,57,60,61]
Gasification + CCS	Fossil fuels	Thermal	- Lower GHG emissions than gasification - Can be used as a bridging technology from gray to green hydrogen	- Lower efficiency than gasification	Blue	60–80	1.63–2.60	8–9	[24,59]
Pyrolysis	Fossil fuels	Thermal	- Lower emissions than any other process with fossil fuel feedstock - Similar efficiency to SMR + CCS - Consumes less energy when compared with the most common thermochemical processes - Simple operation principle	- Despite consuming less energy than SMR and other processes it is still an energy intensive process - Still not at a maturity level that enables large-scale hydrogen production	Turquoise	~58	1.59–3.20	7	[24,27,33,57,62]
	Biomass	Thermal	- Same advantages as biomass gasification	- There are some challenges in scaling up the technology (e.g., a continuous biomass feeding system needs to be implemented) - Fluctuating H2 yields - Tar formation	Green	35–50	1.25–2.20	7	[12,24,32,36,60,61]
Thermochemical cycles	Water	Thermal (solar)	- Very low environmental impact	- Not yet cost-effective - Requires a solar irradiance-exposed area	Green	20–55	7.98–8.40	1–3	[23,24,37,63]
Thermochemical cycles	Water	Thermal (nuclear)	- High efficiency - Takes advantage of residual/waste heat from nuclear reactors - Low emissions	- Generation of nuclear waste - Safety concerns regarding the operation of the nuclear reactor	Purple	20–55	2.17–2.63	1–3	[23,24,37,63]
Dark fermentation	Biomass	Organic matter	- Low operating temperatures and pressure - Simple method	- Requires a large reactor - Low H2 yield	Green	60–80	2.15–2.57	5	[12,24,39,60,61]
Photo-fermentation	Biomass	Solar radiation	- Low operating temperatures and pressure - Carbon-neutral with low carbon emissions during the process	- Requires a large reactor and solar radiation - Requires hydrogen reoxidation - Slow process with low efficiency - Low H2 yield	Green	10	2.37–2.83	4	[12,24,39,60,61]
Bio-photolysis	Water	Solar radiation	- Low operating temperatures and pressure - Consumes CO2 and produces O2 - Waste or non-drinkable water can be used as feedstock	- Not ready to produce hydrogen at a large scale - Requires a large reactor and solar radiation - Low H2 yield	Green	10	1.42–2.13	1–3	[12,24,39,60]
Electrolysis (AEL)	Water	Electric (RES)	- Simple process - Low operating temperatures - Zero GHG emissions (if RESs are used to generate the required energy) - Fully developed and commercially available - Long-term stability	- Limited current densities - Requires a highly concentrated liquid electrolyte - Moderate hydrogen purity	Green	50–78	2.90–14.40 (utility-scale PV in the EU and Norway) 2.20–9.40 (on and offshore wind in the EU and Norway)	9	[10,44,60,62,64]
Electrolysis (PEM)	Water	Electric (RES)	- Simple process - Low operating temperatures - Zero GHG emissions (if RESs are used to generate the required energy) - Fully developed and commercially available - High H2 purity - Compact design and a quick response	- Requires the use of noble metals, resulting in a high investment - Short lifetime	Green	50–83		9	[10,44,60,62,64]
Electrolysis (AEM)	Water	Electric (RES)	- Simple process - Low operating temperatures - Zero GHG emissions (if RESs are used to generate the required energy) - Lower H2 cost and high performance when compared with other electrolysis technologies	- Not commercially available on a large production scale	Green	45–55		6	[10,44,60,62,64]
Electrolysis (SOEL)	Water	Electric (RES)	- Zero GHG emissions (if RESs are used to generate the required energy) - Favorable electrolysis thermodynamics and kinetics - High energy efficiency - Less electricity consumption than other electrolysis processes - High conversion efficiencies and lower hydrogen production costs than AEL and PEM	- Low long-term stability - Not commercially available on a large production scale	Green	57–69		7	[10,44,60,62,64]
Photolysis	Water	Solar radiation	- Production of O2 as a byproduct - Zero GHG emissions - Long operating life span	- Low efficiency process - Requires solar radiation - High H2 production cost - Challenges to scale up technology to reach large-scale hydrogen production	Green	<12	10.36–18.98	1–3	[12,24,41,50,51,60]

3. Hydrogen Storage Technologies

Despite having a higher energy density per unit mass than other energy carriers, hydrogen is the lightest molecule in the universe, presenting a volumetric density of 0.08376 kg/m³ (at 20 °C and 1 atm) and being in the gaseous state under ambient conditions. These characteristics make the hydrogen storage process much more complex than other energy carriers, such as natural gas, oil, and coal. To make this process economically feasible, hydrogen’s volumetric density needs to be increased so that the volumetric energy density of the stored hydrogen is at least comparable to other energy carriers [65]. Hydrogen storage technologies are classified as physical-based or material-based technologies [66]. In Figure 13, an overview of the main hydrogen storage technologies can be found [66].

Two main parameters are considered to characterize each storage technology, namely the system gravimetric capacity, which represents the ratio of the mass of the stored hydrogen to the mass of the system (hydrogen + container), as a percentage, and the volumetric capacity, which represents the mass of hydrogen that can be stored in one unit of volume of the container, expressed in kg/m3 (or g/L) [67]. Furthermore, the storage technologies can be distinguished between short-scale and large-scale storage, long-term and short-term storage, and mobile and static storage [68].

3.1. Physical-Based Storage Technologies

Hydrogen storage technologies are classified as physical-based or material-based technologies. Physical-based storage technologies consist of changing the hydrogen state, by increasing the pressure, decreasing the temperature, or changing both simultaneously, to reduce the volume and, consequently, increase the volumetric energy density. Compressed hydrogen, liquid hydrogen, and cryo-compressed hydrogen are the most common technologies used to physically store hydrogen [66].

In compressed gas storage, hydrogen is compressed (up to 700 bar) to increase its volumetric density and energy content per unit volume, and then stored in aboveground or underground containers [69]. In aboveground compressed gas hydrogen storage, hydrogen is stored in cylindrical vessels [66,70,71]. It is the most established way to store hydrogen; nonetheless, this process presents high development and manufacturing costs, especially in producing carbon fiber composite containers, and it requires a great deal of energy [66]. In addition, due to its small molecular size and high diffusivity, hydrogen leakage from high-pressure steel or aluminum vessels is a significant concern, making the development of materials resistant to hydrogen leakage and the integration of advanced hydrogen detection sensors essential for safe storage [72]. In underground compressed gas hydrogen storage, hydrogen can be stored in natural caverns, aquifers, underground containers, or underground pipes [73].

In liquid hydrogen storage, hydrogen is cooled below its boiling point (−253 °C at atmospheric pressure). Liquid hydrogen presents a greater volumetric density than that achieved by compressing it to a pressure of 700 bar (70.9 kg/m³ vs. 39.1 kg/m³) and has a gravimetric density of up to 20%wt [74,75]. Nonetheless, this process presents the big disadvantage of consuming a great amount of energy, equivalent to about 30 to 35% of the energy content of the stored hydrogen, as well as high boil-off losses [66,70].

Cryo-compressed hydrogen storage technology combines compression with cryogenic technologies. This storage approach is based on the optimization of the pressure and temperature conditions simultaneously [66].

3.2. Material-Based Storage Technologies

In material-based storage technologies, hydrogen is bonded to materials that are capable of reversibly storing hydrogen in either hydrides or in molecular hydrogen form. The storage process can either result from adsorption, a surface phenomenon where hydrogen molecules accumulate at the surface of a material, or absorption, a bulk phenomenon where hydrogen molecules are broken into hydrogen atoms that penetrate the storage material and are incorporated into the volume of the material [71].

Adsorption consists of a surface interaction process between a gas and a solid material, mostly reversible, where, depending on the gas component and the temperature and pressure conditions, a physical binding between the two is formed. This bond results from Van der Waals forces and, unlike absorption, there are no chemical bonds formed [66], [71]. Carbon-based materials, such as porous carbons and carbon nanotubes, metal–organic frameworks (MOF), and zeolites, are the most frequently mentioned adsorption materials in the literature.

The metal hydride storage process is based on the interaction between hydrogen and metals or metal alloys, usually in solid powder, to form metal hydrides through absorption. The hydrogen molecules, at the surface of the material, are dissociated into atomic hydrogen, which is then diffused into the interior of the metallic material and stored in the interstitial space of the metal lattice, forming ionic, metallic, or covalent bonds with the metallic material [71].

In chemical hydrogen storage, hydrogen forms strong covalent bonds with other elements, generating chemical compounds containing hydrogen that can be used to store hydrogen or as hydrogen carriers [76]. Different substances are frequently mentioned as chemical hydrogen storage materials, among which ammonia, methanol, and liquid organic hydrogen carriers (LOHC) are the most commonly highlighted [75,77].

Regarding material-based storage technologies, recent research has focused on improving both hydride and porous material systems to enhance hydrogen storage performance [78]. Regarding hydrides, efforts have been made to develop novel metal hydrides through alloying strategies and nanostructuring techniques intended to improve hydrogen absorption and desorption kinetics. A follow-up approach involves nanoconfinement, where hydrides are embedded into porous scaffolds. This approach has produced ammonia borane, borohydrides, and magnesium hydrides within mesoporous silicas, nanoconfined alanates, nanostructured carbons, and MOFs [78]. Complex hydrides have attracted growing interest due to their high hydrogen content and favorable thermodynamics. Regarding porous materials, enhancements to MOFs, including the incorporation of polymers, nanoparticles, and electron-rich functional groups, or the introduction of oxygen, nitrogen, or any other electron-rich group, have been explored [78]. Carbon-based materials have also gained particular attention [78].

The main characteristics of each of the storage techniques mentioned are summarized in Table 2.

Table 2. Comparison of hydrogen storage technologies.

Technology		Advantages	Disadvantages	Storage Pressure (bar)	Storage Temperature (K)	Gravimetric Capacity (%wt)	Volumetric Capacity (kg/m3)	TRL	REF
Compressed gas hydrogen storage		- Commercially available - Underground storage potentially allows the storage of H2 at a large scale - Does not need any hydrogen conversion process - High speed of injection/withdrawal	- High energy intensity (10% to 18% of the H2 stored energy) - High pressure - Aboveground low storage capacity - Safety and leakage issues	200–700	Ambient	1–5	39 (For 700 bar)	8–9	[65,66,67,70,71,74,75]
Liquid hydrogen storage		- Commercially available - Does not need any hydrogen conversion process - High speed of injection/withdrawal	- Very high energy intensity (up to 35% of the H2 stored energy) - High boil-off losses	Ambient	20.3	Up to 20	71	6–9
Cryo-compressed hydrogen storage		- High volumetric density - Does not need any hydrogen conversion process	- High energy intensity - Hydrogen embrittlement effect - Low technology maturity	50–700	35–110	5–8	60–72	4–5
Adsorption technologies	Carbon-based	- Good storage potential at low temperatures and/or high pressure, avoiding the safety concerns related to physical storage technologies	- Low storage capacity, at room temperature and/or ambient pressure	59 to 340	77 to Ambient	1–10	16–18	7–8
	MOF			15 to 80	77 to Ambient	2–10	12–45	2–4
Metal hydrides	Elemental hydrides	- High volumetric and gravimetric capacities - Long-lasting thermodynamic stability - Full dehydrogenation	- Low kinetics and high dehydrogenation temperature conditions	Ambient to 313	Ambient	7 (Mg) 10 (Al)	86–109 (Mg) 148 (Al)	7–9
	Intermetallic hydrides			Ambient to 313	Ambient	Up to 5.4	90–105	5–7
	Complex hydrides			Ambient to 313	Ambient	19 (Borohydrides)	46–121	4–6
Chemical hydrogen storage	Ammonia	- High energy-storage capacity - Light materials - Easy to transport - Relatively low cost	- High hydrogen reaction temperatures for dehydrogenation - Low hydrogen releasing speed	Ambient	240	18	108–120	7–9
	Methanol			Ambient	Ambient	12	95–99	7–9
	LHOC			Ambient	Ambient	1.7–17.8	47–65	4–7

Table 2. Comparison of hydrogen storage technologies.

Technology		Advantages	Disadvantages	Storage Pressure (bar)	Storage Temperature (K)	Gravimetric Capacity (%wt)	Volumetric Capacity (kg/m3)	TRL	REF
Compressed gas hydrogen storage		- Commercially available - Underground storage potentially allows the storage of H2 at a large scale - Does not need any hydrogen conversion process - High speed of injection/withdrawal	- High energy intensity (10% to 18% of the H2 stored energy) - High pressure - Aboveground low storage capacity - Safety and leakage issues	200–700	Ambient	1–5	39 (For 700 bar)	8–9	[65,66,67,70,71,74,75]
Liquid hydrogen storage		- Commercially available - Does not need any hydrogen conversion process - High speed of injection/withdrawal	- Very high energy intensity (up to 35% of the H2 stored energy) - High boil-off losses	Ambient	20.3	Up to 20	71	6–9
Cryo-compressed hydrogen storage		- High volumetric density - Does not need any hydrogen conversion process	- High energy intensity - Hydrogen embrittlement effect - Low technology maturity	50–700	35–110	5–8	60–72	4–5
Adsorption technologies	Carbon-based	- Good storage potential at low temperatures and/or high pressure, avoiding the safety concerns related to physical storage technologies	- Low storage capacity, at room temperature and/or ambient pressure	59 to 340	77 to Ambient	1–10	16–18	7–8
	MOF			15 to 80	77 to Ambient	2–10	12–45	2–4
Metal hydrides	Elemental hydrides	- High volumetric and gravimetric capacities - Long-lasting thermodynamic stability - Full dehydrogenation	- Low kinetics and high dehydrogenation temperature conditions	Ambient to 313	Ambient	7 (Mg) 10 (Al)	86–109 (Mg) 148 (Al)	7–9
	Intermetallic hydrides			Ambient to 313	Ambient	Up to 5.4	90–105	5–7
	Complex hydrides			Ambient to 313	Ambient	19 (Borohydrides)	46–121	4–6
Chemical hydrogen storage	Ammonia	- High energy-storage capacity - Light materials - Easy to transport - Relatively low cost	- High hydrogen reaction temperatures for dehydrogenation - Low hydrogen releasing speed	Ambient	240	18	108–120	7–9
	Methanol			Ambient	Ambient	12	95–99	7–9
	LHOC			Ambient	Ambient	1.7–17.8	47–65	4–7

4. Hydrogen Transportation and Distribution Technologies

After the production and storage processes, hydrogen needs to be transported from the site where it was produced to the site where it will be used. This process is composed of two phases, namely the transportation phase, where large volumes of hydrogen are transported from the production plants to a city gate, and the distribution phase, which follows the transportation phase and guarantees that the hydrogen is delivered to the demand sites.

There are three main options to transport and distribute hydrogen, namely by road, by pipeline, or by ship. Transporting and distributing hydrogen by road, using trucks, can be attractive for small volumes and short distances [79,80,81]. With further increases in volume or distance, pipelines present the most cost-effective way to transport hydrogen [82]. Depending on the desired volume, distribution pipelines with smaller or larger diameters can be used [82]. When considering long distances, especially transportation across water, ships become the most attractive option [82,83].

According to the International Renewable Energy Agency (IRENA) [82], it is not possible to highlight only one specific technology as the most cost-effective, either now or based on the predicted pathway to 2050. This is because this consideration not only depends on the technology performance but also on the specific volume to be transported and on the desired distance to be covered.

4.1. Transport and Distribution by Road

For small distances and small volumes, trucks can be used to transport hydrogen in either compressed or liquid form. Compressed hydrogen can be transported in compressed gas hydrogen tube trailers at a pressure of 350 bar [79]. The amount of hydrogen transported depends on the tubes’ volume and transportation pressure, which consequently depends on the pressure resistance of the vessel. Transporting small amounts of hydrogen in compressed hydrogen tube trailers is considered the most suitable option for small distances, below 100 km [80]. To increase the transportation capacity, hydrogen can be transported in the liquid phase by cryogenic trailers. However, this approach is very capital and energy intensive, making it only feasible for very large-scale hydrogen production plants, and also presents boil-off losses. Transporting hydrogen via LOHC is another alternative that is presented in the literature as a cost-effective option to enhance long-distance road transportation [79]. Currently, researchers are focusing more on carrying out techno-economic studies to compare the three hydrogen delivery options. According to [80], LOHC is a better option to deliver for demands greater than 3600 kg/day and distances greater than 100 km than compressed hydrogen. This is due to the costs of LOHC delivery being mainly related to the processing costs, while for compressed hydrogen delivery, the transportation costs are more significant. According to [81], the transportation cost is EUR 2.69/kgH₂ for compressed hydrogen, EUR 0.73/kgH₂ for liquid hydrogen, and EUR 0.99/kgH₂ for LOHC, although, if the entire supply chain costs are considered, compressed hydrogen is the most feasible option for short distances, while liquid hydrogen is suitable for distances greater than 130 km.

4.2. Transport and Distribution by Pipelines

A pipeline system is composed of inlet stations, transmission and distribution pipelines, compression stations, valve stations, pig launcher and receiver stations and pipeline monitoring and control systems [79,84]. Pipelines are constructed from different materials, depending on their application. Most transmission pipelines are made of carbon steel or stainless steel, due to their exceptional strength and cost-effectiveness compared to other materials, with diameters typically ranging from 4 to 48 inches [85]. Distribution pipelines are usually built with either low-strength steel or high-strength polyethylene, with diameters typically ranging between 0.5 and 8 inches [85]. The steel used to build the pipelines can be classified into four categories based on its microstructure, namely ferrite–pearlite steels (typically grades X70 and below), acicular ferrite steels (grades X60 to X100), bainite–martensite steels (such as X100 and X120), and tempered sorbite steels [86].

This transportation and distribution approach is considered the most attractive option as the volume of hydrogen increases, since increasing the diameter of the pipe results in a capacity increase greater than the increase in the amount of material needed. It presents a cost below USD 1/kgH₂ for pipelines with a length of 5000 km and a diameter of 120 cm [82], and is considered the most environmentally friendly option, has a long service life (between 30 and 50 years [85]), and low maintenance costs.

There are two options to build a hydrogen pipeline system [87], either building a completely new hydrogen network, which presents high investment costs, or adapting existing natural gas pipeline systems to accommodate hydrogen through blending with natural gas [86] or fully replacing it. Nevertheless, transporting hydrogen in systems of pipelines presents various technical challenges, as presented below.

Hydrogen embrittlement: Hydrogen molecules may dissociate at the surface of the surrounding material, forming hydrogen atoms that may then diffuse to the interior of the material. These atoms accumulate at defects or discontinuities in the crystal lattice of the material and form localized pressure zones which can cause cracks [85]. This results in a decrease in the material’s ductility and tensile resistance. The severity of hydrogen embrittlement depends on such factors as exposure time, operating temperature and pressure, diffusion velocity, and defects on the microstructure of the pipeline material, among others [84,86,88]. Hydrogen embrittlement is more severe in high-stress steels with high carbon content, while low-grade steels, like API 5L Grade A, Grade B, X42, and X46, are less vulnerable to this phenomenon [85,88,89]. Nevertheless, this second type of steel withstands lower operating pressures, so thicker walls are needed to match the operating conditions of high-stress steel. The pipeline joints are most susceptible to this phenomenon, especially when defects are present on welds [85]. This degradation phenomenon also occurs in polymers and composite materials used in sealing applications or lining applications (e.g., epoxy resin composites), as hydrogen penetrates the macromolecular network of polymer chains [84].

Hydrogen leakages and safety: The smaller molecular size of hydrogen, when compared to natural gas, increases the leakage potential of the gas transported by the pipelines, especially through fittings, joints, and seals [87]. This increased leakage raises safety concerns. There are three major risk factors to consider. Hydrogen presents wide flammability limits (from 4% to 76% by volume at 1 bar and 20 °C), it requires a low ignition energy of only 0.017 mJ ignition energy (about 16 less than methane), and hydrogen burns in an almost invisible flame [85]. Together, these characteristics make hydrogen leaks not only more likely but also more difficult to detect and control.

Hydrogen corrosion: When blended with natural gas, hydrogen may contribute to the corrosion of the piping systems [88]. Impurities, such as H₂S, CO₂, and water, cause electrochemical corrosion and the generation of products, such as FeS and FeCO₃, resulting in corrosion failure of the pipelines [88]. The corrosion rate depends on various factors, such as the hydrogen blending ratio, material strength, and partial pressure ratio of H₂S and CO₂ impurities [88]. Hydrogen embrittlement and corrosion of steel pipelines have coupling and competing effects, further explored in [88].

Design of compressor devices: Due to the hydrogen’s low molecular weight, to match the volumetric energy density of methane, compressors need to be able to deliver high flows at high pressures. Two main compressor typologies may be considered, namely reciprocating and centrifugal compressors. Reciprocating compressors can deliver high pressures but not high flows. In the case of centrifugal compressors, the impeller tip speed needs to be three times higher than that of natural gas to match the mass flow [85], increasing the complexity of designing this equipment.

To prevent some of the previously mentioned challenges, especially hydrogen embrittlement, two main approaches are presented in the literature. The first approach consists of applying protective coatings on the pipeline surface that is in direct contact with hydrogen. An example of this coating material is GALVA-LUME, composed of aluminum, zinc, and silicon [76]. The second approach consists of adding minimal amounts of gases that are more electronegative than hydrogen, such as carbon monoxide or oxygen, that inhibit hydrogen adsorption and dissociation on the pipeline metal surface [90]. Depending on the end-use of the transported hydrogen, this approach may require an additional purification step [85].

4.3. Transport and Distribution by Ship

Hydrogen transportation by ship is ideal when long distances, with possible routes across water, are considered [91]. According to [82,91], three options to transport hydrogen by ship are the most viable, namely liquid hydrogen, ammonia and LOHC. In [82], it is stated that ammonia is the most cost-effective option of the three. Liquid hydrogen presents the advantage of already being a commercial technology for ship transportation, as well as not needing purification systems at the destination; nonetheless, boil-off and high energy losses occur during the transportation phase. LHOC present the advantages of being easily stored and presenting low capital costs, although its production needs to be scaled up to become a feasible transportation option.

As previously mentioned, it is not possible to highlight only one specific technology as being the most cost-effective, since the transportation cost depends on two major parameters, namely distance covered, and volume transported. Figure 14 presents a systematic comparison between the most suitable transportation options for different distance and volume ranges [82].

5. Hydrogen Applications in End-Use Sectors

Hydrogen produced from renewable sources has the potential to tackle various critical challenges. The four main sectors where hydrogen is expected to play a central role in the decarbonization process are the power, transportation, industry, and heating sectors.

5.1. Decarbonizing the Power Sector

Hydrogen can help decarbonize the power sector by supporting the integration of variable renewable energy (VRE) in the power system [1]. Hydrogen can help both in reducing the curtailment of excess VRE generation, by using the excess renewable energy when generation surpasses the demand to produce green hydrogen through water electrolysis, and by helping to mitigate the imbalances caused by VRE generation [92] by providing a medium with long-term storage capacity that, in contrast with electric batteries, could allow seasonal storage [1,93]. Hydrogen can also be used as a backup and off-grid power supply, with power generation through fuel cells or micro gas turbines. While micro gas turbines are reliable, capable of load-following and can be used for heat and power applications, fuel cells present higher efficiency, lower emissions and noise, and greater modularity [94,95].

These technologies can be used in microgrids and remote power applications as the main power source as an alternative to conventional diesel generators [1,93]. Examples of prospective hydrogen energy communities can be found in the literature [96,97].

In addition, hydrogen has been identified as a potential option to support the transportation of renewable energy from production to consumption regions, with lower investments and adaptation costs than electrical transmission for long distances [6,98].

5.2. Decarbonizing the Transport Sector

In the road transportation sector, fuel cell electric vehicles (FCEVs) can expand the scope of electric mobility to high duty cycle segments, due to their driving range and refueling time being similar to conventional vehicles. Long-range and high-utilisation vehicles, where today’s batteries face limitations, can find in hydrogen a green alternative to fossil fuels [99]. According to the IRENA and the Hydrogen Council, FCEVs and battery electric vehicles will collaborate in decarbonizing the road transport sector [99,100].

In addition to the possibility of being used in FCEVs, hydrogen can also be used to produce synthetic hydrocarbons, like methane, methanol, or diesel/petrol/jet fuel [1]. These fuels can be used to supply internal combustion engine vehicles instead of using fossil fuels, generating lower GHG emissions [101]. Hydrogen can, thus, work as a bridging technology between today’s scenario, where the majority of the world’s vehicle fleet is composed of internal combustion vehicles with a lifespan that can reach up to 15 years and which, consequently, needs to find an alternative to fossil fuels, and an ideal scenario where the entire world fleet would be composed by electric vehicles.

When considering rail and maritime transportation, hydrogen can have a big impact on lowering these sectors’ emissions. Hydrogen can be used to replace diesel trains on non-electrified lines. Fuel cells can be integrated into short-distance ships, such as ferries and shuttles, and liquefied hydrogen is seen as a potential option to reduce greenhouse gas emissions for long-distance ships [1]. In addition, hydrogen-based fuels, such as ammonia and methanol, can also significantly contribute to decarbonizing the maritime sector [102].

In the aviation sector, fuel cells are being considered as a potential application for some propeller-driven regional aircraft and unmanned aerial vehicles [103]. For jet aircraft, which are difficult to electrify due to their high energy density demands, sustainable aviation fuels (SAFs) offer a promising pathway to decarbonize the sector. SAFs can replace conventional aviation fuels while significantly reducing GHG emissions. SAFs include both biofuels and power-to-liquid fuels [104]. While biofuels present challenges related to biomass availability, power-to-liquid fuels are produced using a mixture of CO₂ and H₂. The produced e-fuels present greater volumetric density than H₂, remaining in the liquid state under standard conditions, and can be used as a drop-in fuel in existing aircraft engines [105].

5.3. Decarbonizing Industry

Hydrogen produced from renewable energy plays a crucial role in decarbonizing industry. Three separate hydrogen applications can be identified in this end-use sector [106]. First, hydrogen can be used as a chemical feedstock for the synthesis of other products where hydrogen is a molecular component. Examples of this application are the production of ammonia and methanol. Second, hydrogen can be used as a raw material for chemicals or fuel production in a chemical reaction that results in a final component that does not possess hydrogen in its chemical composition. One example of this application is the production of steel, where oxygen is reduced by hydrogen in the iron ore, replacing the coking coal carbon source largely used in steel making. The development trends and technical challenges of hydrogen-based direct reduced iron production as an important decarbonization strategy for the iron and steel industry were explored by Shen et al. [107]. Arras et al. [108] presented a strategic policy framework for China that highlights the decentralized adoption of hydrogen in the steel industry. Third, hydrogen can be used as a heating source, replacing natural gas and other fossil fuels, to produce high-grade heat (temperatures above 650 °C). Hydrogen combustion in hydrogen-specific burners can be used in industries that require significant amounts of high-temperature process heat, like cement, iron, glass, and ceramic production [106].

The utilisation of fossil fuel produced hydrogen as a feedstock to produce ammonia, methanol and other chemicals and the usage of hydrogen as a reducing agent to produce direct reduced iron constitute, together with the usage of hydrogen in the refining industry, the traditional hydrogen applications [8]. Recently, research has focused on proving the benefits of using hydrogen as a decarbonization path in a wide variety of industry sectors [109,110,111].

5.4. Decarbonizing the Heating Sector

Green hydrogen can play an important role in decarbonizing the heating sector, not only for industrial processes, as previously seen, but also for meeting heating needs at the level of residential and commercial buildings. Hydrogen can be used to reduce the GHG emissions related to space heating, hot water production, and cooking in the building sector, where fossil fuels are currently the go-to option. To reduce the consumption of these fuels, especially natural gas, hydrogen can be blended with it, taking advantage of the already existing gas infrastructure and equipment, or can be used as a direct replacement for conventional natural gas [1].

5.5. Overview of Hydrogen Use

According to the Global Hydrogen Review from IEA [8], hydrogen use in 2022 reached 95 Mt, representing an increase of 3% from the value estimated by the same organization for 2021. This increase is not a consequence of hydrogen policies but rather of global energy trends [8]. Refining and industry were the two major sectors that contributed to hydrogen use in 2022 (with 41 Mt and 53 Mt of hydrogen, respectively) [8]. Beyond its traditional use, the adoption of hydrogen in new applications, such as in heavy industry, transport, the production of hydrogen-based fuels, or the production and storage of electricity, is still minimal, accounting for less than 0.1% of the global demand [8]. This trend will have to change to meet the climate and energy goals set for 2050. According to the IEA, hydrogen use by 2030 should be more than 150 Mt, with nearly 40% coming from the new applications previously explored and 70 Mt corresponding to low-carbon hydrogen. Figure 15 presents a schematic representation of hydrogen use by sector in 2022 and the projected hydrogen use for 2030, according to the Net Zero Emissions by 2050 scenario, based on the values presented in [8].

6. Challenges to the Implementation of a Green Hydrogen Economy

Pleshivtseva et al. [112] conducted a comparative analysis of world trends in hydrogen production. The study used the information presented in the IEA database, which considered information on hydrogen projects completed, ongoing, or in the planning phase until October 2021, and expanded it to October 2022. In total, 789 projects across 61 countries were considered. Most projects were established in Europe, with electrolysis as the dominant production method (722 projects). Completed projects were mostly experimental and laboratory installations, presenting a delay in the transition to industrial implementation. While electrolysis leads the future planning, most configurations are power-to-X with unspecified uses, and no new projects using alkaline or solid oxide electrolysis are planned post-2028, likely due to limited industrial-scale research.

The previous study highlights the early-stage maturity of the green hydrogen economy, which remains largely focused on localized case studies, often limited to laboratory-scale implementations. There is a delay in scaling up the green hydrogen economy to achieve the energy objectives for hydrogen and strengthen the role of this energy vector as one of the cornerstones of the planned energy transition. The main challenges that condition this scale-up process are as follows:

• The investment needed to support the transition from conventional hydrogen production methods to renewable methods, as green hydrogen production technologies require high initial capital expenditures [113].
• The complexity and expenditure of the storage process resulting from hydrogen’s low volumetric density [92]. Physical-based storage is energy intensive and requires high-strength materials to handle the high-pressure values and/or cooling systems capable of achieving and maintaining low-temperature values [113,114]. Although material-based storage has shown some potential to tackle this limitation, the technology remains at a low TRL.
• The development of hydrogen transporting infrastructure requires significant upfront investment [92]. The existing natural gas pipeline systems cannot be directly converted to transport pure hydrogen [114].
• The fragmentation of the current hydrogen market, which is lacking infrastructure and a consolidated regulatory framework [113]. Effective development of hydrogen economies also requires coordination and collaboration among the different players across the value chain. A purely free market approach may not foster such collaborations and could increase the risk of underinvestment in early-stage hydrogen projects and research activities, as these areas typically offer medium to long-term financial returns [113].
• The public perception of hydrogen safety may affect its acceptance [115].

To overcome the main challenges pointed out and strengthen the advantages of building hydrogen value chains, future research should prioritize improving production, storage, and transportation technologies’ efficiencies, reducing costs through technological innovations, and developing robust infrastructure solutions. This technological improvement should be accompanied by a greater focus on industrial-scale applications. At the same time, long-term policy and strategic frameworks should be developed to define clear pathways to design and deploy hydrogen value chains, offer certainty to investors, and promote cooperation between different stakeholders [55,115]. Public education on the advantages and safety and security features of green hydrogen is also essential to increase public acceptance and foster public–private partnerships [55].

7. Conclusions

Based on this review of the current main hydrogen production technologies, it is concluded that electrolysis, powered by renewable energy resources, is the most interesting and promising approach to produce green hydrogen at a large scale. At the moment, gray hydrogen still presents lower production costs than any other type of hydrogen. To ensure a progressive transition from gray to green hydrogen while balancing the economic and environmental dimensions, technologies, like SMR-CCS and methane pyrolysis, that have lower emissions than conventional fossil fuel thermochemical processes and that are cheaper than green hydrogen processes, can be considered as bridging technologies.

The low volumetric density presented by hydrogen, in comparison to natural gas, oil, and coal, makes the hydrogen storage process much more complex than the storage of other energy carriers. For this reason, it is not possible to highlight a single option to store hydrogen. Depending on the amount of hydrogen to be stored, the projected end-use of the energy carrier, and the storage period, different technologies can be recommended as the most suitable.

When considering hydrogen transportation and distribution, there are three main options to transport and distribute hydrogen: by road, by pipeline, or by ship. The three cannot be seen as competitors, but rather as complementary, since depending on the distance to be covered and the amount of hydrogen, the most suitable option will be different.

Currently, hydrogen value chains are mostly designed based on the use of fossil fuels as feedstock and green hydrogen projects are mainly experimental and laboratory-scale. To overcome the current challenges to the implementation of a green hydrogen economy, future efforts should focus on improving the efficiency and cost-effectiveness of production, storage, and transport technologies, while also scaling up industrial applications. Further investment in electrolyzers is needed to enhance efficiency, increase durability, and reduce production costs. In parallel, continued research into hydrogen storage and transportation is essential to address material integrity and safety concerns [72]. This must be supported by long-term policy frameworks, investor confidence, stakeholder collaboration, and public education to enhance acceptance and foster partnerships.