Hydrogen Storage Performance During Underground Hydrogen Storage in Depleted Gas Reservoirs: A Review

Engineering ›› 2024, Vol. 40 ›› Issue (9) :226 -242. DOI: 10.1016/j.eng.2024.03.011

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2023-07-24	2024-03-19	2024-06-14

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Abstract

Hydrogen has emerged as a promising alternative to meet the growing demand for sustainable and renewable energy sources. Underground hydrogen storage (UHS) in depleted gas reservoirs holds significant potential for large-scale energy storage and the seamless integration of intermittent renewable energy sources, due to its capacity to address challenges associated with the intermittent nature of renewable energy sources, ensuring a steady and reliable energy supply. Leveraging the existing infrastructure and well-characterized geological formations, depleted gas reservoirs offer an attractive option for large-scale hydrogen storage implementation. However, significant knowledge gaps regarding storage performance hinder the commercialization of UHS operation. Hydrogen deliverability, hydrogen trapping, and the equation of state are key areas with limited understanding. This literature review critically analyzes and synthesizes existing research on hydrogen storage performance during underground storage in depleted gas reservoirs; it then provides a high-level risk assessment and an overview of the techno-economics of UHS. The significance of this review lies in its consolidation of current knowledge, highlighting unresolved issues and proposing areas for future research. Addressing these gaps will advance hydrogen-based energy systems and support the transition to a sustainable energy landscape. Facilitating efficient and safe deployment of UHS in depleted gas reservoirs will assist in unlocking hydrogen’s full potential as a clean and renewable energy carrier. In addition, this review aids policymakers and the scientific community in making informed decisions regarding hydrogen storage technologies.

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Underground hydrogen storage / Storage performance / Hydrogen deliverability / Hydrogen trapping / Risk assessment / Techno-economic analysis

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Lingping Zeng, Regina Sander, Yongqiang Chen, Quan Xie. Hydrogen Storage Performance During Underground Hydrogen Storage in Depleted Gas Reservoirs: A Review. Engineering, 2024, 40(9): 226-242 DOI:10.1016/j.eng.2024.03.011

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1. Introduction

The International Energy Agency (IEA) [1] reports that, in order to achieve the objective of global carbon neutrality, transitioning from fossil fuels to renewable energy is a critical pathway [1], [2]. Renewable energy (e.g., solar power, wind powder, and hydropower) produces electricity from sustainable natural resources with zero emissions. The IEA has estimated that the share of renewable energy in the energy mix will increase by 60% from 2020 to 2026 to reach 4800 GW [3], which is around 95% of the newly installed global power capacity.

With the approach of the renewable energy era, the intermittent supply of renewable energy presents a challenge to the current energy distribution grid [4]. For example, solar power goes through daily cycles, while hydropower suffers from seasonal cycles [5], [6]. Wind power is unstable and undergoes constant change. The fluctuation of renewable resources results in an imbalanced energy supply that rarely matches energy consumption. Energy storage is a means of balancing the supply and consumption of renewable energy. However, large-scale energy storage has its own challenges. One way to facilitate renewable energy storage at scale is the conversion of excess renewable energy to H₂. H₂ is viewed as an effective energy carrier due to its zero-emission character and high energy density on a mass basis [7]. Excess renewable energy is converted to H₂ through H₂O electrolyzation [8] and then used during periods of low renewable energy generation [9]. Nevertheless, the produced H₂ still requires storage particularly at large scale.

One H₂ storage method is underground hydrogen storage (UHS). UHS utilizes large underground volumes to store H₂, which is perceived as a safe, scalable, economic, and long-term energy storage method [10], [11], [12], [13], [14]. Two types of underground reservoirs can be modified to store H₂: Type-1 reservoirs are artificial underground caverns, such as mined tunnels [15] and salt caverns [8], [16], [17], [18], [19], [20], [21]; type-2 reservoirs are underground porous media, including deleted gas reservoirs [22], [23], [24], [25], [26], [27], [28], [29], [30] and saline aquifers [10], [31], [32]. Among these UHS options, depleted gas reservoirs have the advantage of proven storage integrity, significant storage capacity (terawatts of energy compared with gigawatts in salt caverns or kilowatts in surface tanks; Fig. 1 [33]), and existing surface infrastructure, in addition to well-characterized geological conditions [34].

Considering the potential of UHS, this paper presents a comprehensive review of UHS in depleted gas reservoirs, focusing on the factors controlling its performance and its techno-economics. More specifically, we discuss three major factors governing the technical performance of UHS: ① H₂ deliverability, ② H₂ trapping, and ③ the H₂ equation of state (EOS; Fig. 2) [13], [35], [36]. Here, H₂ deliverability refers to the ability of H₂ to be injected in, flow through, and extracted from porous depleted gas reservoirs under in situ reservoir conditions during H₂ cycling (injection and withdrawal). We review the relevant petrophysical properties and fluid characteristics, such as porosity, permeability, pore connectivity, mineralogy, fines migration, viscous fingering, and injection/withdrawal rate—factors that play a critical role in H₂ injectivity and recoverability. H₂ trapping refers to immobilized H₂ ganglions in porous media that occur due to complex physiochemical interactions. We evaluate the critical parameters affecting H₂ trapping in depleted gas reservoirs, including wettability, capillary pressure, adsorption/desorption, and solubility. These physiochemical parameters affect UHS performance through H₂ snap-off, immobilization, and trapping. H₂ EOS is a thermodynamic equation relating state variables during UHS; it describes the state of matter (in this case, H₂) under a given set of physical conditions, such as pressure, volume, temperature, or internal energy [37]. Mixing takes place between the injected H₂ and any cushion gas injected (e.g., CH₄ and N₂), as well as the hydrocarbon fluids (i.e., oil or gas) still present in the reservoir. This reduces the purity of the stored and extracted H₂; in turn, its behavior can differ from the H₂ phase diagram. Microbial activity may also affect the efficiency of UHS due to the biotic conversion of H₂ into other types of gas through methanogenesis, acetogenesis, S and Fe reduction, and so forth. Microbial impacts on UHS operations have been extensively covered in previous works [13], [38], [39], [40], [41], [42], [43], [44] and therefore will not be further discussed as part of this review. Rock mechanics may have more impact on storage integrity compared with storage performance during UHS operations, which has been thoroughly discussed in our previous paper [34].

2. Hydrogen deliverability

2.1. Permeability

Absolute permeability (k_a) is defined as the ability of a porous medium to transmit fluid [45]. It is an intrinsic property that is not affected by the fluid properties or fluid-rock interactions [46]. In subsurface laminar flow, k_a follows Darcy’s law

(1)$ Q=\frac{k_{\mathrm{a}} A \Delta P}{\mu \Delta L}$

where Q is the volumetric flow rate, A is the cross-sectional area available for the fluid flux, ΔP is the pressure differential, ΔL is the physical distance between the injection and the withdrawal well, and μ is the fluid viscosity.

Under subsurface conditions, k_a is affected by the effective formation pressure σ_effective, which is the difference between the overburden pressure and pore pressure [47], [48]. Usually, k_a decreases with increasing σ_effective during loading cycles and increases with decreasing σ_effective during unloading cycles [49]. Considering that a high k_a is favorable for hydrogen injection and production, storage in sandstone reservoirs with a higher k_a is more efficient than storage in tight reservoirs such as shale or coal [50], [51].

Thus far, research on hydrogen permeability is still very limited. Yekta et al. [52] measured the relative permeability and capillary pressure of a hydrogen-water-sandstone system under shallower (5.5 MPa, 20 °C) and deeper (10.0 MPa, 45 °C) reservoir conditions. They reported that the two measured relative permeability curves under the two UHS conditions were very close to each other, which was attributed to the near-constant H₂ viscosity under the tested temperatures and pressures. Under two conditions, the relative water permeability of lower Triassic sandstone (81 vol% quartz and 17 vol% K-feldspar), considering H₂ as a non-wetting fluid, ranged from 45 to 48 mD (1 mD = 9.869 × 10⁻¹⁶ m²)— is very similar to the relative permeability when only water was used (44 mD).

Flesch et al. [53] measured the permeability (nitrogen) of Tertiary, Triassic, and Permian sandstone from Germany and Austria before and after aging with pure hydrogen over six weeks. They observed that, for Permian samples with a higher fraction of carbonate (Ca/Mg/MnCO₃) and anhydrite (CaSO₄), the average nitrogen permeability increased from 48.78 to 61.53 mD after H₂ aging, due to the dissolution of cements or pore-filling materials. However, the nitrogen permeability of the Triassic samples and of Molasse sandstone and siltstone decreased from 842.72 to 748.80 mD and from 78.63 to 74.58 mD, respectively. The researchers claimed that the measured values before and after the experiments were within the tolerance range of the methods. Therefore, hydrogen experiments would not affect the sample on a plug scale.

Sakhaee-Pour and Alessa [54] characterized the single-phase flow of hydrogen and compared it with those of N₂ and CH₄. The gas flow behavior was determined by the Knudsen number (K_n), which is expressed as follows:

(2)$ K_{\mathrm{n}}=\frac{\mu}{\rho d} \sqrt{\frac{\pi}{2 R T}}$

where ρ is the fluid density, d is the characteristic size (i.e., the diameter of the channel or pore), R is the gas constant, and T is the absolute temperature. Under reservoir conditions, the Knudsen number difference between H₂ and CH₄ is logarithmically close to an order of magnitude, although the absolute difference is less than 0.00100 (e.g., 0.00016 for H₂, 0.00005 for N₂, and 0.00002 for CH₄ at a pressure of 15 MPa). Therefore, the permeability obtained from laboratory measurements using nitrogen is considered to be representative for hydrogen in the subsurface of a permeable reservoir domain (Fig. 3) [54].

2.2. Porosity

Porosity is a petrophysical parameter that affects hydrogen injectivity. The ratio of the total pore volume to the bulk volume of the rock defines the absolute porosity [45], although disconnected and dead-end pores are not relevant to H₂ flow. This means that the maximum H₂ storage capacity (C) at the reservoir scale is determined by the effective porosity (ϕ_effective), which is defined as the ratio of the connected pore volume to the bulk volume:

(3)$ C=L_{1} \times W_{1} \times T_{1} \times \phi_{\text {effective }} \times S_{\mathrm{H}_{2}}$

where L₁, W₁, and T₁ are the formation length, width, and thickness, respectively; and S_H₂ is the H₂ saturation (i.e., the pore volume filled with H₂ divided by the total pore volume). It should be noted that saturation (S) is commonly defined as the ratio of the volume occupied by a particular fluid within the pore space to the overall volume of the pore space [45], [49].

Flesch et al. [53] also compared the porosity of sandstone before and after being treated with hydrogen. For Permian sandstone, only three of the nine measured samples indicated a reduction in measured helium porosity after the experiments, with a slight shift in porosity from 13.13% to 11.90%. In the Triassic samples, an increase in the measured helium porosity from a median of 20.23% to 23.50% was reported. In Molasse sandstone and siltstone, the mean helium porosity slightly increased from 24.38% to 26.19% after the H₂ experiments, due to the dissolution of carbonate cements.

Bensing et al. [55] exposed claystone samples from the Lower Jurassic Amaltheenton Formation in Germany to hydrogen and compared the sample surface via broad ion beam (BIB)-scanning electron microscopy (SEM). They found that the porosity of samples treated with a hydrogen-brine solution noticeably increased (Figs. 4 and 5 [55]) due to calcite dissolution.

2.3. Mineralogy

Minerals that can trigger redox reactions in the presence of H₂ to cause reductive dissolution are a concern during UHS. The interactions between these minerals, stored H₂, and the formation brine can significantly reduce storage efficiency and affect injectivity/productivity by altering the porosity and permeability through in situ mineral dissolution/precipitation. In this work, four main types of sensitive minerals and their potential impacts on UHS are discussed: carbonates, sulfates, sulfides, and ferric iron oxides.

(1) Carbonates. Calcite (CaCO₃), dawsonite [NaAlCO₃(OH)₂], dolomite [CaMg(CO₃)₂], magnesite (MgCO₃), and siderite (FeCO₃) are examples of carbonate minerals that can undergo redox reactions with H₂. In these reactions, the carbonate or bicarbonate ion is reduced and CH₄ is produced [56], [57]. As a result, UHS may not be feasible in depleted carbonate reservoirs, due to significant H₂ loss [56]. In depleted sandstone reservoirs, carbonates act as cementation or infill material, and their reductive dissolution has the potential to affect porosity and permeability [58], [59].

Bensing et al. [55] used petrographic analysis with SEM to investigate the impact of H₂ on claystone samples. They found that, when exposed to H₂ and 10 wt% NaCl brine, the samples experienced significant etching and dissolution of calcite fossil fragments, as opposed to when exposed to dry H₂ or 10 wt% NaCl brine alone. Similarly, Dieter et al. [60] examined the properties of sandstone specimens with cementing carbonates under different pressure (4-200 MPa), temperature (40-120 °C), and salinity (16 000-350 000 parts per million (ppm)) conditions before and after H₂ treatment. Their results showed that the calcite dissolved partially or completely at higher pressure, temperature, and salinity levels. Zeng et al. [56] utilized geochemical modeling to analyze the kinetics of carbonate mineral dissolution and H₂ loss in the Majiagou carbonate reservoir in China. Their findings indicated that, despite only a small amount of calcite dissolution occurring over a 500-year period (0.06% of the calcite, considering its 94.00% mass fraction in the rock), a significant amount of H₂ loss would still take place due to the redox reaction with calcite. As a result, they recommended that depleted carbonate reservoirs should not be utilized for UHS. Bo et al. [61] conducted an evaluation of the UHS potential of two sandstone reservoirs—namely, Tubridgi and Mondarra—currently utilized for CH₄ storage in western Australia. Their analysis revealed that, due to the low percentage of calcite in these reservoirs, H₂ loss would be minimal, with only 0.72% H₂ loss expected in Tubridgi and 2.76% H₂ loss expected in Mondarra in 30 years. These results suggest that depleted sandstone reservoirs are more favorable for UHS in comparison with carbonate reservoirs, due to their lower degrees of H₂ conversion and mineral dissolution. Similar results were reported by Pichler [62], Amid et al. [43], Hemme and van Berk [63], and Hassannayebin et al [57].

(2) Sulfates. Sulfate minerals, including anhydrite (CaSO₄), gypsum (CaSO₄:2H₂O), anglesite (PbSO₄), barite (BaSO₄), and celestite (SrSO₄), can also undergo a redox process with stored H₂. This reaction results in the reduction of SO₄²⁻ to H₂S. While these sulfate minerals are not commonly found in significant amounts in gas or oil reservoirs, they may be present as cementation and infill materials, and their dissolution can impact formation integrity due to reductive dissolution.

Flesch et al. [53] conducted a study to examine the petrographic and petrophysical characteristics of sandstone from the Permian (Altmark) and Triassic (Emsland) Formations before and after aging with H₂ and formation brine. They observed that, when exposed to reservoir temperature and pressure conditions, specifically at temperatures above 100 °C and pressures greater than 15 MPa, a significant quantity of CaSO₄ cement dissolved. These findings were confirmed by various measurements, including micro-computed tomography (µ-CT) scans, helium porosity, nitrogen permeability, and specific surface area measurements. Henkel et al. [64] conducted an evaluation of mineralogical and geochemical variations in the target reservoirs and caprock during UHS in the German project H₂STORE. They also observed the dissolution of CaSO₄ after subjecting it to H₂ treatment under reservoir temperature and pressure conditions, as indicated by changes in mineral surface structures and an increase in the specific surface area. Similar findings were confirmed by Cozzarelli et al. [65], Lassin et al. [66], Hemme and van Berk [63], and Dieter et al. [60].

(3) Sulfides. Pyrite, which is a representative sulfide mineral, can undergo a redox reaction with stored H₂, resulting in its reduction to pyrrhotite or troilite in the form of FeS, along with H₂S as a byproduct [57], [67], [68]. Truche et al. [69] conducted a study on the reduction of pyrite to pyrrhotite in a clay-rich rock with 1-2 wt% of framboidal pyrite under temperatures ranging between 90 and 250 °C and pressures in the range of 0.3-3.0 MPa. Their observations showed that the complete replacement of pyrite with pyrrhotite occurred within three months when T > 90 °C and P(H₂) > 1 MPa. At lower temperatures (30-90 °C), pyrite is still reduced to pyrrhotite in the pH window between 8-10 (Fig. 6 [69]).

The degree of reduction of pyrite when it undergoes redox reactions with H₂ is influenced by the pH, where environments with higher pH promote the precipitation of pyrrhotite under low-temperature and -pressure conditions. This has been confirmed by several studies, including those by Wiltowski et al. [70], Lambert et al. [71], Truche et al. [67], Moslemi et al. [72], and Didier et al. [73].

(4) Ferric iron oxides. Goethite [FeO(OH)] and hematite (Fe₂O₃), which are Fe³⁺-associated minerals, can react with H₂ by reducing Fe³⁺ to Fe²⁺. However, this reduction process usually occurs under high-temperature conditions (300-700 °C) [74], [75], [76], [77], [78], which are beyond typical geological storage conditions.

It is worth noting that the aforementioned mineral dissolution as a result of redox reactions with H₂ would not be expected to occur under typical gas reservoir temperature and pressure conditions [79], [80], [81] in the absence of microbial activity. Pyrite, which reacts with H₂ to become pyrrhotite under reservoir temperature and pressure conditions, is an exception [69]. However, when bacteria are present, they can act as a catalyst to accelerate the redox reaction [39], [82]. Considering the ubiquity of microbial communities in oil/gas fields [83], it is strongly recommended to conduct experiments using rock samples, microbes, and formation brine collected from the target UHS sites to characterize mineral dissolution due to both geochemical reactions and microbial activities, in order to assess their potential impact on H₂ deliverability.

2.4. Viscous fingering

Viscous fingering refers to a phenomenon in which a less viscous fluid displaces a more viscous fluid in an unstable manner. This process can occur when an injection fluid is introduced into an in situ fluid, having a negative effect on reservoir flow dynamics and ultimately reducing the effectiveness of recovery efforts [84]. For UHS in depleted gas reservoirs, particularly those with higher residual water saturation, viscous fingering is very likely to occur as a result of large contrasts in viscosity and density between hydrogen and formation fluids [85]. Viscous fingering may also occur during the mixing of H₂ and cushion gas, such as CH₄ and N₂ as well as preexisting hydrocarbons in the reservoirs. This phenomenon can lead to hydrogen loss due to factors such as residual gas saturation, dissolution into connate water, and diffusion. Therefore, experimental investigations and numerical modeling are essential to adequately understand the significance of fingering in UHS operations, particularly when utilizing different cushion gases. It is also crucial to incorporate the impact of buoyancy and fingering accurately within numerical simulations for field projects.

Paterson [85] conducted a study on hydrogen fingering and found that it can result in losses, which are largely influenced by the rate of gas injection. The cause of viscous fingering is attributed to differences in viscosity, density, and surface tension forces. It has been observed that the fingers tend to spread perpendicular to the direction of flow. As the fingers advance into the viscous medium, the number of fingers propagating through the high-viscosity fluid (water, in this case) tends to decrease due to a phenomenon known as shielding [86]. During the gas fingering process, the contact area between the injected hydrogen and the reservoir rock and fluid increases, resulting in a higher risk of hydrogen dissolution into the water via gas diffusion and a greater likelihood of hydrogen interacting with the rock.

Hagemann et al. [87] developed a mathematical model to simulate the fluid flow behavior at different gas injection rates. They reported that, when the injection rate is low, gravitational forces are the main factor, leading to uniform water displacement. At higher injection rates, however, viscous forces take over, resulting in unstable displacement. Gas fingering occurs laterally below the cap rock toward both sides of the reservoir.

Suitably low injection rates, low-heterogeneity reservoirs, and stratified aquifers may help to control hydrogen viscous fingering. In addition, thick formations and steeply dipping structures have been found to inhibit fingering [88].

2.5. Fines migration

Fines migration is defined as the movement of fine clay particles or similar materials within a reservoir formation. Formation damage caused by fines migration is a well-known issue that occurs in some sandstone production wells [89]. The movement of fine particles is triggered by changes in the attractive and repulsive forces on the surface, which can result from activities such as drilling, the use of completion fluid, acidizing treatments, and water injection during secondary or tertiary recovery operations [90]. Fine particles can detach from a mineral surface and become suspended in the injected fluid, eventually blocking pore throats as they move through the reservoir. This process, referred to as straining, results in formation damage, reduced formation permeability, and decreased gas injectivity [90].

To the best of our knowledge, there are no field observations or laboratory experiments on the impact of hydrogen injection and storage on fines migration during UHS to date. Most of the experience with fines migration comes from hydrocarbon production and carbon geo-sequestration projects in which CO₂ is injected into sandstone reservoirs for permanent locking [91], [92], [93], [94], [95], [96]. Fines migration is controlled by the size of the fine particles, wettability, flow rate, and relative flow of different phases, as well as by in situ formation brine chemistry such as ion concentrations, composition, and pH [97], [98], [99], [100]. Since hydrogen can react with minerals via redox reactions, leading to an increase in pH [56], [57], [61], [63], [101], [102], stored hydrogen may also affect fines migration. In addition, the surface potential of the minerals may change due to physicochemical reactions with the injected hydrogen; this would change the surface attractive and repulsive forces that determine the disjoining pressure [103], [104] and thus affect fines migration. More experiments are necessary to characterize the potential impact of hydrogen on fines migration to de-risk UHS in depleted gas reservoirs.

2.6. Hydrogen cycling

UHS is a cyclical operation that may include several injection and withdrawal cycles each year. The utilization of the storage facility depends on the market requirements (e.g., whether the H₂ is for daily, weekly, or seasonal load leveling or for export), as well as the storage scale. Depleted gas reservoirs are expected to be limited to seasonal storage with one or two cycles each year [105]. This is reflected in the length of typical injection and withdrawal periods, which are respectively 200-250 and 100-150 days for porous geological media [105]. Experience from Underground Sun Storage—the world’s first geological hydrogen storage facility, operated by RAG Austria [106], [107]—suggests that injection and withdrawal may occur over several weeks, while hydrogen may be stored for several months. The limited number of cycles for porous reservoirs is a consequence of the large storage capacity of these reservoirs, the comparatively lower deliverability, and the stress on the reservoir exerted by each cycle.

To optimize the hydrogen storage performance of a given reservoir, the well pattern, injection and withdrawal rates, and cycling frequency must be considered. The well pattern controls lateral spreading of the injected hydrogen and contact between hydrogen and in situ formation fluids. Multiple injection wells located beneath the caprock can prevent significant loss of hydrogen due to lateral spreading, dissolution, and viscous fingering [87], [108], [109].

The injection rate affects the hydrogen flow in the reservoir, especially in the near-wellbore area. Too-high injection rates can lead to fingering and lateral spreading, resulting in the loss of hydrogen. To minimize hydrogen losses, it is recommended to maintain a low and steady injection rate that ensures a stable front. Special attention is required in dip geological structures, where the injection rate and pressure should be limited to avoid exceeding the fracturing pressure and capillary entry pressure, and a safety margin should be taken into account [13].

To optimize hydrogen storage and cycling efficiency, the location of the withdrawal wells (in most scenarios, the withdrawal well is the same as the injection well) is crucial [108]. Placing several shallow extraction wells beneath the caprock can increase hydrogen recovery. It is also recommended to locate wells in highly permeable zones to enhance injectivity and withdrawal efficiency. However, a high withdrawal rate can lead to fluid coning, a high pressure drop, and reduced ultimate recovery. For example, water may be produced along with hydrogen in the case of an aquifer, leading to a sharp pressure drop and changes in gas properties. Therefore, it is recommended to control the extraction process by maintaining a constant pressure in the well [13], [110].

The cycling duration and number of cycles can affect the purity of the extracted hydrogen. As the number of cycles increases, the hydrogen purity is expected to improve [109], [111]. Longer time periods between each cycle allows for fluids—including hydrogen and in situ formation fluids—to be separated by gravitational forces. Depending on the required specifications of the produced hydrogen, the extracted gas stream may require further treatment to reduce or remove any impurities present [109], [110], [112], [113].

3. Hydrogen trapping

3.1. Wettability

Wettability is defined as the attraction of a liquid phase to a solid surface, and it is typically quantified by the contact angle of these two phases [114]. The wettability of the H₂-brine-rock system can affect the residual and structural storage capacity, as well as the injectivity and withdrawal rate during hydrogen cycling in subsurface porous media [103], [115], [116], [117]. Extensive studies on H₂ wettability in sandstone [52], [115], [118], [119], carbonates [102], [118], mica [120], [121], and clay minerals in shales [122], [123] have been conducted. The contact angle commonly increases with pressure in all tested minerals. Moreover, the hydrogen wettability tends to be weakly water-wet to intermediate-wet under representative geological storage conditions. Although measurement of the contact angle strongly depends on the sample preparation and aging procedures, especially regarding the polishing and treatment of mineral surfaces (and therefore may be less representative of wettability compared with the relative permeability measurement), the reported wettability of almost every type of mineral in caprock under typical reservoir conditions is water-wet. This is advantageous for hydrogen storage, since it provides the caprock with a stronger structure and residual trapping capacity to prevent hydrogen from migrating upward, thereby reducing the risk of hydrogen leakage and minimizing safety concerns [124].

3.2. Capillary pressure

Prior to UHS implementation, a reservoir contains formation brine, which the injected hydrogen must displace. The pressure required for this displacement is determined by the capillary pressure. Capillary pressure is defined as the pressure difference across the interface between two immiscible fluids [125]. Therefore, knowledge of the capillary pressure is important to characterize the multiphase fluid flow in geological porous media during UHS, since capillary pressure determines the pore-scale fluid configurations and fluid movement, and thus the reservoir scale flow.

Capillary pressure also has a significant impact on caprock integrity, since it affects the ability of fluids to migrate through the pore spaces within the caprock. When the capillary pressure is high, it can enhance the sealing capacity of the caprock by preventing the movement of fluids, such as hydrocarbons or injected substances, across the rock matrix. However, if the capillary pressure is exceeded, it may lead to breaching of the caprock integrity, allowing the undesired migration of fluids, potentially resulting in environmental contamination, reservoir depletion, or compromised wellbore stability. Understanding and managing capillary pressure is crucial in maintaining the effectiveness and longevity of caprock barriers in various subsurface applications, including UHS.

In contrast to permanent CO₂ storage in the subsurface, for which a small residual brine saturation is favorable to maximize CO₂ storage capacity, the characteristic injection-withdrawal cycle of UHS benefits from a small residual hydrogen saturation to improve the storage performance and cycling efficiency. To the best of our knowledge, the only experimental capillary pressure data for a hydrogen-water-rock system comes from Yekta et al. [52], who measured the capillary pressure of Triassic sandstone during drainage (i.e., decreasing water saturation) under “shallower” (5.5 MPa, 20 °C) and “deeper” (10.0 MPa, 45 °C) conditions. The researchers found that the capillary pressure increased from about 65 to 110 kPa as the water saturation decreased from 15% to 11% (Fig. 7 [49]). However, changing the temperature and pressure had only a minimal impact on the capillary pressure for the H₂-water-rock system (Fig. 7 [49]). This finding is in contrast to observations made for a CO₂-water-rock system [126], [127]. The insensitivity to temperature and pressure suggests that the capillary pressure may have been essentially constant for the range of pressure and temperature conditions tested, which were representative of UHS. Nonetheless, for future tests, a broader range of pressure/temperature conditions, more complex compositions, different concentrations of formation brines, and different types of minerals—particularly carbonates and clays—should be considered to expand on Yekta et al.’s observations [52].

3.3. Interfacial tension

Interfacial tension (i.e., surface tension) is defined as the partial derivative of the surface free energy with respect to the dividing area between the gas and liquid phases [128]. The interfacial tension between hydrogen and brine impacts the displacement and flow of fluids in the reservoir and the caprock, and consequently affects the H₂ storage performance. Hosseini et al. [129] conducted experiments to determine the interfacial tension between H₂ and a solution of KCl and NaCl at different pressures, temperatures, and salinities. The interfacial tension was found to range from 45 to 80 mN·m⁻¹, decreasing with increasing pressure and temperature but increasing with decreasing salinity. Similar results were reported by Chow et al. [130], Ali et al. [120], Higgs et al. [118], and Yekeen et al. [131].

In terms of hydrogen-rock interfacial tension, Pan et al. [132] calculated the solid-fluid interfacial tension γ_gas-rock on a quartz and basalt surface. They reported that γ_gas-rock decreased with increasing pressure, temperature, organic acid concentration, and carbon number. γ_gas-rock was found to first increase and then decrease with increasing nanofluid concentration. Compared with methane and carbon dioxide, hydrogen presented higher γ_gas-rock values.

To represent the ratio between the viscous force and interfacial tension, a dimensionless parameter known as the capillary number is defined. The capillary number can be used to evaluate the performance of hydrogen storage in porous media in comparison with other gases, such as methane. In porous media, the capillary number is described by Eq. (4) [133]:

(4)$ N_{\mathrm{c}}=\frac{v \mu}{\gamma}$

where N_c is the capillary number, ν is the Darcy velocity, and γ is the interfacial tension. It is worth noting that, due to the large interfacial tension γ_H₂-water between H₂ and water, γ_H₂-water may not have a significant impact on the capillary number. The capillary number may exceed the critical capillary number only near the well due to high gas injection rates.

A comparison between hydrogen and methane storage processes can be conducted through laboratory experiments and/or numerical simulation by analyzing the respective viscous and capillary forces involved. When injected at the same rate (with the same Darcy velocity), the lower viscosity of hydrogen compared with methane leads to a lower sweep efficiency. When stored in a depleted gas reservoir with an active aquifer, this can result in lower water production, as less water is swept by the hydrogen. In addition, a low sweep efficiency can lead to less space being available for hydrogen storage. However, due to the higher interfacial tension [134] and lower viscosity of H₂ compared with CH₄ [34], the capillary forces are lower and there is less capillary trapping of H₂. This ultimately increases the volume of recoverable hydrogen [13].

3.4. Diffusion

Diffusion is a concentration-driven transport mechanism in which molecules migrate from a region of lower concentration to a region of comparatively higher concentration until an equilibrium is established. Hydrogen has a lower molecular weight than other gases, making it more diffusive. The diffusion coefficient of hydrogen in pure water at standard pressure and temperature (298 K) is approximately 5.13 × 10^-9 m²·s⁻¹ [135], which is higher than those of CO₂ (1.60 × 10^-9 m²·s⁻¹ [136]) and CH₄ (1.85 × 10^-9 m²·s⁻¹ [137]). Increasing temperature and decreasing pressure can further increase hydrogen diffusivity. The impact of hydrogen diffusivity can be divided into two categories: upward diffusion through caprock, and interphase diffusion into other in situ fluids. Interphase diffusion mainly results in the mixing of stored hydrogen with preinjected cushion gas or residual natural gas, leading to hydrogen contamination and reduced cycling efficiency and H₂ recovery [138]. Hydrogen losses due to upward diffusion have been estimated by Carden and Paterson [50], who investigated H₂ storage in a dormant reservoir. They found that 1% of H₂ may be lost over 15 years due to diffusion into an overlying aquifer, indicating that H₂ losses due to hydrogen diffusion are likely to be insignificant. Nevertheless, experimental data on hydrogen diffusion in low-permeability porous media in the presence of aqueous and non-aqueous liquids under reservoir conditions is still limited, and further investigation is needed to minimize the risk of hydrogen-diffusion-related inefficiencies.

3.5. Adsorption and desorption

Gas adsorption-desorption is a phenomenon that occurs in high-surface-area systems such as coal or shale [49]. Although CO₂, CH₄, and N₂ adsorption-desorption processes are well understood, limited data is available for H₂. Didier et al. [73] investigated the adsorption capacity of H₂ (A_H₂) on dry Na-montmorillonite via gas chromatography at 373 K and 0.045 MPa. After an exposure time of 30-45 days, A_H₂ reached 0.1 wt%, which was similar to the amounts of CH₄ [139] and CO₂ [140] adsorbed under comparable conditions. The researchers also found that A_H₂ decreased with an increase in temperature (e.g., to 0.07 wt% at 403 K and 0.045 MPa [73]). More recently, molecular dynamics simulations of H₂ adsorption on calcite predicted by López-Chávez et al. [141] showed that A_H₂ could be as high as 0.42 wt% at 0.1 MPa and 400-600 K. Similar results were reported by Ziemiański and Derkowski [142], who used the Langmuir isotherm to fit H₂ adsorption experimental data in order to normalize the excess adsorption. More research on A_H₂ on rocks can be found in Refs. [142], [143], [144].

Gas adsorption can have adverse effects on rocks, such as deformation, changes in permeability and surface area, and mechanical weakening. As a result, further research is necessary to investigate hydrogen adsorption and desorption on rocks such as clays, which have a high specific surface area and thus greater potential for gas adsorption under the conditions present in UHS reservoirs, in order to provide confidence in storage performance over time.

3.6. Solubility

When hydrogen is stored underground, it comes into contact with the formation brine, and a fraction of the hydrogen dissolves into the brine. Knowledge of the solubility of hydrogen in brine is crucial to monitor the mobility and reactivity of the aqueous H₂, which is not in a free state during storage in subsurface porous media. Hydrogen is a non-polar gas with limited solubility in water. At standard atmospheric pressure and a temperature of 298 K, the solubility of hydrogen in pure water is about 7.900 × 10^-4 mol⋅(kg water (kgw))⁻¹, which is slightly lower than that of CH₄ (1.400 × 10^-3 mol⋅kgw⁻¹ [145]) and much lower than that of CO₂ by more than one order of magnitude (0.033 mol⋅kgw⁻¹ [146]). Hydrogen solubility increases with pressure but decreases with temperature and salinity [61], [147], [148], [149]. The very low solubility of hydrogen in formation brine suggests that the loss of hydrogen due to hydrogen dissolution is negligible. However, more data is required to improve the accuracy of storage performance predictions.

4. Hydrogen EOS

The EOS is a thermodynamic equation relating state variables; it describes the state of matter under a given set of physical conditions, such as pressure, volume, temperature, or internal energy [37]. During UHS, the EOS is essential to predict the flow behavior of gas mixtures. Gas flow during UHS is very complex: The injected hydrogen is not the only component in the gas phase; other gases such as the cushion gas (e.g., methane or nitrogen), residual methane, and potentially newly generated gases such as CO₂ or H₂S (from abiotic geochemical reactions or biotic microbial activity) may also affect the thermodynamic properties of the fluid, which then impact transport processes [150].

The development of an appropriate EOS permits accurate and efficient modeling of the thermodynamic equilibrium properties of gas mixtures and brines over a large range of pressure, temperature, and salinity conditions. Specific models with the ability to simulate the thermal, multiphase, and multicomponent flow of gas mixtures found in underground hydrogen projects are still scarce [151]. A range of commercial/open-access simulators are available for modeling UHS or CO₂ geo-sequestration with consideration of other gas phases [108], [152], [153], [154], [155], [156], [157]. Despite the availability of numerical simulators for subsurface flow processes, none have been specifically designed or verified for UHS simulations. As these simulators were originally developed for other applications, they may not accurately account for key factors in UHS, such as the solubility of hydrogen and gas mixtures in water/saline solutions; they also lack thermodynamic models for estimating flow parameters such as density and viscosity [151]. Therefore, it is necessary to calibrate the current EOS commonly used in commercial reservoir simulators, such as the Peng-Robinson EOS, rather than using the default values [109]. Previous attempts [29], [151], [158] to use simulators for UHS have yielded poor results, highlighting the need for new numerical simulators that can account for multiphase/multicomponent flow within a heterogeneous reservoir, including solving equations of heat, multiphase (gas and aqueous), and multicomponent flow at various temperatures and pressures.

5. Risk assessment of hydrogen storage performance

To rank the storage performance of UHS in depleted gas reservoirs based on the parameters outlined above, we established a framework for evaluating the likelihood and consequence of an event, the combination of which yields a risk assessment matrix with risk levels ranging from low to high (Table 1) [159].

In this risk assessment matrix, “likelihood” indicates the probability of an event occurring and is usually rated on a five-point scale: very likely (80%), likely (10%), possible (1%), unlikely (0.1%), and very unlikely (0.01%). “Consequence” refers to the most probable outcome of a potential incident and is also categorized on a five-point scale: negligible, minor, moderate, severe, and critical. By combining different likelihood and consequence levels, we established five risk levels:

High risk. This level pertains to elements or scenarios that demand immediate attention and stringent monitoring. Such scenarios have a high likelihood of failure and could result in severe consequences that pose a significant threat to UHS projects.

Medium-high (med-hi) risk. Elements falling into this category require careful consideration. While they are less risky than high-risk factors, they still merit a thorough review to identify potential improvement strategies and ensure adequate management.

Medium risk. These elements possess a moderate level of risk that could potentially compromise storage performance. They should be subject to further analysis and appropriate measures to mitigate their impact.

Low-medium (low-med) risk. Elements in this category have a lower level of risk compared with those in higher risk categories. However, they still require attention to prevent any potential issues that might affect storage performance.

Low risk. Elements categorized as low risk are not expected to significantly impact storage performance based on current knowledge and understanding. They necessitate minimal immediate concern but may warrant periodic review to ensure that their risk level remains low.

Table 2 summarizes the variables identified above that affect the performance of UHS in depleted gas reservoirs in terms of hydrogen deliverability (Section 2), hydrogen trapping (Section 3), and EOS (Section 4). The variables are ranked by applying the risk matrix from Table 1. For hydrogen injectivity, the reservoir’s permeability, porosity, and viscous fingering are identified as the primary variables, as they are expected to have the greatest impact on H₂ deliverability. Clearly, sandstone reservoirs with high permeability, porosity, and connectivity are favorable with regard to hydrogen injectivity. For reservoirs with low relative permeability, porosity, and connectivity, the injection of hydrogen may require greater energy and a higher bottom-hole pressure, which requires more compression work and may cause storage integrity problems, typically near the wellbore. Viscous fingering is likely to occur due to large contrasts in viscosity, density, and surface tension forces between hydrogen and preexisting formation fluids. The consequence of hydrogen viscous fingering is mainly reflected in unstable flow patterns and lateral migration, which can eventually affect the withdrawal efficiency. Hydrogen viscous fingering may be controlled by the selection of appropriate injection rates and by identifying a reservoir with low heterogeneity or with stratified aquifers for storage projects. It has also been reported that steeply dipping structures and thick formations help to reduce fingering [13].

Mineralogy, fines migration, and the hydrogen cycling strategy are identified as secondary parameters affecting hydrogen injectivity. Sensitive minerals, such as the carbonate and sulfate minerals discussed before, can react with injected hydrogen through redox reactions and lead to reductive dissolution. The dissolved minerals and generated particles can affect the in situ formation permeability and porosity and thus the injectivity. Therefore, sandstone reservoirs with a low fraction of sensitive minerals are preferable candidates for UHS. Fines migration is another process that may affect injectivity, in which fine particles move with the injected gas and may block pore throats, resulting in formation damage. Since this process is mainly controlled by attractive and repulsive forces (or the so-called “disjoining pressure”) on particle and mineral surfaces, it would theoretically be determined by the reservoir brine chemistry, such as ion concentrations, composition, and pH. However, there is a lack of experimental evidence to elucidate the role of fines migration on injectivity in the presence of hydrogen. We thus tentatively rank it as a low-med risk.

An appropriate strategy for hydrogen cycling can improve hydrogen injectivity and cycling efficiency. Well patterns with several injection wells located beneath the caprock can mitigate the impact of hydrogen lateral spreading, dissolution, and viscous fingering. From a technical perspective, low injection rates are preferred—not only to reduce the effect of viscous fingering and hydrogen losses during injection but also to decrease fluid coning during hydrogen withdrawal and pressure fluctuation, which increases the risk of formation instability. However, the injection/withdrawal rate must also meet commercial demands. Therefore, a comprehensive simulation of hydrogen injection/withdrawal cycles for the specific geological setting of the depleted gas reservoir, while considering the commercial requirements and technical limitations, is essential in to plan an optimum operational strategy for UHS.

For hydrogen trapping, the wettability, capillary number, and hydrogen diffusion have been identified as the primary variables. However, their risks are ranked as low-med. For wettability, although experiments have demonstrated that a change in temperature, pressure, or organic acid concentrations may alter the contact angle among hydrogen gas, brine, and minerals, current experimental observations from independent research groups indicate that, under typical reservoir conditions, almost every type of mineral is water-wet (albeit varying from strong water-wet to weak water-wet or near intermediate-wet). Yekta et al.’s [52] capillary pressure measurements suggest that the capillary pressure is almost constant across the range of pressure and temperature conditions representative of UHS. For diffusion, although the low molecular weight of hydrogen makes it more diffusive than other gases such as methane and carbon dioxide, current numerical simulations suggest that the fraction of trapped hydrogen due to hydrogen diffusion is less than 1% [50], [82], indicating a low risk of hydrogen loss during UHS.

Further development of the EOS is essential to improve the capacity and accuracy of numerical simulations of the flow behavior of gas mixtures. This is particularly relevant for UHS, where the system consists of injected H₂, cushion gas, and potentially other in situ gases (trapped CH₄, CO₂, etc.). Existing models are incapable of performing simulations of UHS, since they fail to consider the solubility of hydrogen and gas mixtures in water/saline solutions and the thermodynamics for estimating key flow parameters such as the density and viscosity of hydrogen and gas mixtures. Therefore, a new EOS needs to be developed that considers the multiphase/multicomponent flow within a heterogeneous reservoir by solving equations of heat, multiphase (gas and aqueous), and multicomponent flow over a wide range of temperatures and pressures.

6. Techno-economics of UHS in depleted gas reservoirs

The technical performance of H₂ storage will directly impact its economic performance. However, since the technical performance is still largely uncertain in the absence of field experience, so are the costs. Only a limited number of estimates are currently available for UHS in depleted gas reservoirs. The first cost estimates for UHS were presented some 40 years ago by Carpentis [160], [161], followed by Taylor et al. [162] and Amos [163]. More recently, Steward et al. [164], Lord et al. [165], Papadias and Ahluwalia [40], and Chen et al. [33] presented cost estimates for different types of underground storage. For UHS in depleted gas reservoirs, many published estimates and analyses still rely on the numbers presented by Lord et al. [165] and Taylor et al. [162] (e.g., Refs. [33], [166], [167], [168], [169]). More recently, however, Yousefi et al. [170] presented a detailed techno-economic assessment of UHS in a depleted gas field in the Netherlands.

The key capital cost components of depleted gas reservoirs in comparison with other geological hydrogen storage options are compared in Table 3 [162] to highlight their respective economic benefits and disadvantages.

Amos [163] described UHS as a special case of compressed gas storage in which the vessel cost is very low. For hydrogen storage in depleted gas reservoirs, the existing pore space represents the available storage volume; the capital investment is thus expected to be smaller than for hard rock caverns or salt caverns, which require cavern construction (Table 3 [162]). Thus, storage in porous geological formations is often assumed to be the cheapest option, since the storage volume is readily available [160], [161], [165], [171].

However, when the available pore volume is very large and the storage volume is comparatively small, the cushion gas requirements to enable deliverability may become excessive and the costs prohibitive [163]. In depleted gas reservoirs, the fraction of cushion gas to total stored gas is expected to be around 50% (Table 3 [162]), based on experience with natural gas storage [162]. However, the actual ratio will depend on the specific delivery requirements for H₂ and can be estimated via numerical modeling for a given well field. Cushion gas is the largest investment item, followed by compressors. In their assessment, Taylor et al. [162] found that 80% of the total investment was attributable to the stored hydrogen, including both the cushion and working gas. Very similar findings were reported by Chen et al. [33] and Yousefi et al. [170]. This cost could be reduced if (some) cushion gas was already present in the form of natural gas [162]. Chen et al. [33] and Yousefi et al. [170] investigated the use of cushion gases other than hydrogen—namely, N₂ and CH₄. The lower price of these gases makes them attractive alternatives, although post-extraction purification is likely to be required, with the costs depending on the level of contaminants, the contaminant itself, and the required H₂ purity. Chen et al. [33] reported that, for purification costs below 3.40 USD·kg⁻¹ (all costs presented in this review have been adapted to 2022 USD), using CH₄ or N₂ as cushion gas was more cost-effective than using H₂. Yousefi et al. [170] also found that using 100% N₂ as cushion gas yielded the lowest levelized storage cost despite the cost of gas treatment to 99.999% purity.

The production history from depleted reservoirs provides an indication of the reservoir’s H₂ storage performance, including H₂ storage capacity, containment, and achievable injection and withdrawal rates. Still, additional characterization work is required—in part due to the differences in the properties of natural gas and hydrogen [165], but even more so to understand potential interactions with the microbes and minerals present in the reservoir. As outlined above, such interactions could lead to degradation of the stored H₂, resulting in a loss of H₂ and impurities in the extracted gas and potentially requiring purification.

In depleted gas reservoirs, existing wells may be used for cycling, although workovers are likely to be required; moreover, depending on the deliverability, additional wells may be needed. The integrity of the cement barrier over time must also be ensured to prevent hydrogen diffusion into the cement [172]. Austenitic stainless steel may be used to extend the service time of the wellbore [172], which increases the cost of the completion.

Cost items at the surface consist of compressors (including for the compression of the cushion gas), flowlines, and any necessary gas treatment, monitoring, and other infrastructure. After the cushion gas, compressors are the second largest cost item contributing to the capital cost for depleted gas storage [33], [165], [170].

The operating costs of UHS include the cost of energy and maintenance related to gas compression for storage, and possibly boosting the pressure after withdrawal [163]; and the working gas losses, which are estimated at 1%-3% per year. Depending on the type and utilization of the storage facility, operating costs can dominate the cost of hydrogen storage. Taylor et al. [162] noted that, for depleted gas reservoirs, storage is very sensitive to the cost of electricity. When most of the costs associated with underground storage are incurred by electricity for gas compression, long-term underground storage (i.e., with few injection-withdrawal cycles) becomes increasingly favorable [163]. The operating costs of long-term storage may only constitute a small fraction of the total cost of storage [160], [161], [165], [171].

The utilization of the storage facility has a considerable impact on the levelized cost of hydrogen storage. As outlined in Chapter 2.6, depleted gas reservoirs are likely limited to seasonal storage, undergoing one or two cycles each year [105]. The utilization of the storage reservoir can be captured in terms of static and dynamic storage cost; the static cost only accounts for one cycle, while the dynamic cost considers full utilization (i.e., multiple cycles). The static cost is therefore higher than the dynamic storage cost. This is demonstrated in the analysis presented by Yousefi et al. [170], who investigated the effect of the number of cycles per year on the levelized cost of H₂ storage; they reported a decrease from 0.87 USD·kg⁻¹ for one cycle to 0.53 USD·kg⁻¹ for two cycles, and then down to 0.28 USD·kg⁻¹ for six cycles.

A summary of the levelized cost of storage for depleted gas reservoirs from two United States, one Canadian, and one Dutch case study are summarized in Table 4. For depleted hydrocarbon reservoirs in the United States, Lord et al. [165] estimated the levelized cost of H₂ storage to be 1.90 USD·kg⁻¹ H₂, while Taylor et al.’s [162] estimated costs were more than twice as high, at 4.79 USD·kg⁻¹ H₂ for a depleted gas reservoir in Canada (Table 4). This difference may be a result of the underlying project assumptions, the components included in the analysis, and the 20-year difference between the assessments (Lord et al.’s study was published in 2014 and uses 2007 USD). Lord et al.’s analysis included the cost of cushion gas, compressors, and even a 16-km pipeline, accounting for all major cost items apart from post-withdrawal gas processing, while Taylor et al.’s estimate also included the cost of working gas. Taylor et al.’s estimate was very case-specific, and H₂ storage was assumed to occur at a very low pressure range of 0.19-0.75 MPa (in comparison, the formation pressure in Lord et al.’s assessment was assumed to be close to 14 MPa); thus, it required less compression work but involved large storage volumes, resulting in a large number of wells, which was reflected in the high capital-to-operating-cost ratio.

Using Lord et al.’s [162] cost data, Chen et al. [33] arrived at an estimate of 1.56 USD·kg⁻¹ for the levelized cost of H₂ storage in the Wattenberg gas field in the United States. Yousefi et al. [170] presented the lowest cost range of 0.55-0.90 USD·kg⁻¹ for storing H₂ in the depleted Roden gas field in the Netherlands.

It should be remembered that the geographic distribution and type of available UHS is controlled by the underlying geology. The suitability of a storage site must be considered in the context of the H₂ value chain, as the commercial viability of a geological storage site will be largely affected by its location relative to the point of hydrogen production and the point of use. A concurrent assessment of storage economics and transport economics is required to determine the most cost-effective hydrogen supply chain. For example, a comparatively low-cost storage reservoir may become unattractive due to excessive transport costs when the generation and uptake points are hundreds of kilometers away. Similarly, an expensive storage solution may become commercially attractive in the context of the complete H₂ supply chain when the source of hydrogen and the end user are located in close proximity.

While the literatures review above demonstrated that the costs of UHS in depleted gas reservoirs vary, such sites are typically expected to be the most cost-effective UHS option. In general, UHS constitutes a comparatively small fraction of the whole hydrogen value chain. An analysis presented by Schoenung [173] emphasizes that the cost of UHS in a hydrogen energy-storage system consisting of electrolyzers, a bulk storage subsystem, and fuel cells for power generation contributes only a very small fraction to the total cost of the hydrogen system. The HyUnder Project [42] also found that electrolysis dominates the total specific hydrogen plant-to-gate costs of an integrated hydrogen storage facility with a share of over 80%. The same observation was made by Le Duigou et al. [174], who found that, for UHS in salt caverns, the development of UHS is a significant upfront investment but makes a comparatively small contribution to the levelized cost of hydrogen. Samsatli et al. [175] and Reuß et al. [176] came to the same conclusion.

Importantly, the value of UHS in the supply chain can be considerable. Samsatli et al. [175] found that the cost of an optimized integrated renewable electricity network without UHS is 25% higher than with UHS, as wind turbines, conversion, storage, and transmission all become more expensive (29%, 23%, 32%, and 20%, respectively). Le Duigou et al. [174] reported that investment in storage is more economical than investment in more renewable energy capacity to meet demand when the proportion of renewables is already high.

7. Conclusions

Hydrogen storage performance is determined by the ability to economically inject, extract, and store hydrogen. In this work, the key processes, state-of-the-art understanding, gaps, and impact of storage performance during UHS were reviewed and discussed in three main sections: hydrogen deliverability, hydrogen trapping, and the EOS. An overview of the techno-economic considerations of UHS in depleted gas reservoirs was also provided.

The major variables that affect H₂ deliverability are formation permeability, porosity, viscous fingering, mineralogy, fines migration, the injection/withdrawal rate, well patterns, the reservoir structure, and the initial pressure to support H₂ injectivity. Sandstone reservoirs with high permeability/porosity, connectivity, inactive aquifers (to minimize viscous fingering), and a low percentage of reactive minerals are ideal candidates for UHS operations.

Several factors are known to potentially influence hydrogen trapping in depleted gas reservoirs, including in situ wettability, interfacial tension, capillary pressure, and hydrogen solubility. State-of-the-art knowledge of wettability from both experimental tests (particularly contact angle measurement) and numerical simulations (e.g., surface complexation modeling and molecular dynamics modeling) suggests that, under representative formation temperature and pressure conditions, the wettability of almost all minerals ranges from strongly water-wet to weakly water-wet with hydrogen. This indicates that strong residual trapping is likely to occur in areas with high water saturation, causing significant hydrogen loss. Therefore, depleted gas reservoirs with inactive aquifers or closed boundaries are favorable for hydrogen storage.

The presence of reactive minerals leads to hydrogen conversion and contamination, although this process will not lead to significant hydrogen loss within a short-term period (e.g., a couple of years). However, the reactions can progress over time, likely causing measurable hydrogen conversion and contamination with impurities such as CH₄, CO₂, and H₂S. Therefore, it is important to improve the EOS due to the impurity buildup, which is a time-dependent process associated with kinetics. Also, it is important to measure hydrogen dispersion in methane in depleted gas reservoirs, including cushion gas, to accurately predict the storage performance. A new numerical feature or module needs to be developed that considers the kinetics of hydrogen conversion and contamination, the EOS, and hydrogen dispersion in porous reservoirs to model and predict reservoir performance.

Equally important is the progression of techno-economic assessments to provide further confidence in the costs that maybe expected, enable the definition of screening criteria for UHS and identify optimum UHS operational strategies. The value of UHS in the supply chain could be considerable, having the potential to significantly lower the cost of electricity supply.

Acknowledgment

Lingping Zeng and Quan Xie are thankful to Future Energy Export CRC and Beach Energy Limit for supporting this work and funding research through the project Enabling Large-Scale Hydrogen Underground Storage in Porous Media (21.RP2.0091). Lingping Zeng and Regina Sander are thankful to CSIRO Energy and Hydrogen Industry Mission for the support of this work. The authors also gratefully acknowledge the discussions with Mohammad Sarmadivaleh, Ali Saeedi, Chris Elders, Mauricio Di Lorenzo, and Qun Lin from Curtin University and Alex Kaiko, Alexandra Bennett, Michael Roberts, Jason Storey, and Glen Buick from Beach Energy Ltd. for the constructive comments to improve the quality of this work.

Compliance with ethics guidelines

Lingping Zeng, Regina Sander, Yongqiang Chen, and Quan Xie declare that they have no conflict of interest or financial conflicts to disclose.

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