Underground Hydrogen Storage Research Articles

Numerical simulation of the impact of different cushion gases on underground hydrogen storage in aquifers based on an experimentally-benchmarked equation-of-state

Underground hydrogen storage (UHS) in geological formations is a promising technology for large-scale hydrogen energy storage. In this study we focus on UHS in saline aquifers. Although lessons were learned from similar studies, including geological carbon sequestration and underground gas storage, the unique thermodynamic and physical properties of hydrogen distinguish UHS from the other subsurface storage projects. We developed a two-phase, three-component reservoir simulator, which incorporated essential physics based on the fully coupled multi-physics framework of the Delft Advanced Reservoir Simulation (DARSim). Properties of fluid mixtures were computed using the GERG-2008 equation of state (EoS), in which the parameters were determined by fitting laboratory data. The simulation results demonstrated the impact of different cushion gases (CO2, CH4, and N2) on UHS. Most hydrogen stayed in the gaseous phase at the top of the aquifer when CH4 and N2 were used as the cushion gas. Conversely, hydrogen-rich fingers were observed in the aqueous phase when CO2 was used as the cushion gas, because dissolved CO2 increased brine density, leading to density-driven downward convection which was favorable for hydrogen dissolution into the aqueous phase. The highest purity of produced hydrogen was observed when CO2 was used as the cushion gas, whereas using CH4 and N2 as the cushion gas was favorable for the hydrogen production rate and mobility. This work is the first study that utilizes an EoS-based reservoir simulator to investigate hydrogen's flow patterns and interactions with cushion gases in an underground storage system. Specifically, the productivity and retrievability of hydrogen in a two-phase, three-component UHS system were analyzed in detail. The developed reservoir simulation tool and research findings from this study will be valuable to support decision making in practical UHS projects.

Prediction of interfacial wetting behavior of H2/mineral/brine; implications for H2 geo-storage

Underground hydrogen storage (UHS) is a suitable option for large-scale and long-term storing of hydrogen (H2), which is considered a highly promising energy carrier, offering an efficient solution to replace fossil fuels and achieve net-zero carbon emission targets. The successful storage and withdrawal of H2 are highly dependent on the wettability of the H2/mineral/brine system. Despite the importance of the interfacial wetting behavior of H2/mineral/brine in sedimentary formations, no accurate and generalized model has been developed yet for a fast and valid prediction of the contact angle. In the context, three intelligent models, namely multi-layer perceptron (MLP), radial basis function (RBF), and least square support vector machine (LSSVM) have been proposed to accurately predict the contact angle of H2/mineral/brine systems. Another primary objective is to thoroughly scrutinize the extent to which various parameters influence the contact angle. Results of models approved their capability in validly predicting the contact angle for a wide range of mineral types, considering the effects of thermodynamic conditions, brine salinity, cushion gases, surface coating, and surface roughness. The results also demonstrated that the LSSVM model outperforms the MLP and RBF models with coefficients of determination (R2), root mean square error (RMSE) and average absolute relative deviation (AARD) of 0.9942, 1.6133 and 1.6924 %, respectively, indicating higher accuracy and reliability. Moreover, sensitivity analysis confirmed that the rock mineralogies, in particular the percentage of quartz and calcite, followed by the presence or absence of cushion gas, as well as surface roughness/contamination exerted a greater influence on predicting the contact angle within the H2/mineral/brine system.

Hydromechanical modelling of salt caverns subjected to cyclic hydrogen injection and withdrawal

The present work is devoted to the study of underground hydrogen storage in salt caverns. Based on the hydromechanical characteristics of rock salts obtained from some laboratory experiments, we propose a novel model that includes short- and long-term mechanical behaviour. Specifically, the short-term part incorporates the elastoplastic and instantaneous damage mechanisms. Concerning the long-term behaviour, in addition to the primary and secondary creep phases, the tertiary phase takes into account a delayed damage mechanism.As application, we performed hydromechanical modelling of two vertical salt caverns with different depths based on existing hydrogen gas caverns, which are subjected to cyclic hydrogen injection and withdrawal (seasonal and daily scenarios). Gas transport is also modelled taking into account diffusion and advection mechanisms. Mechanical results indicate that the stability problem of a very deep cavern is more worrying in comparison with a shallow cavern, as expected. However, the gas extension is the same for both caverns because the gas flow is mainly by diffusion transport, while the permeability does not significantly increase. Since field data at very depths are limited, a sensibility analysis of material properties was carried out to provide insight into key mechanisms that may occur. Typically, a decrease in mechanical properties increases the extent of the damage around deep cavern but did not lead to significant increase in the extent of gas leakage. Under the assumptions made, these findings suggest that the use of salt caverns for green hydrogen storage, even with aggressive operating conditions to regulate variations between renewable energy production and peak power demands, should not significantly affect the stability of salt cavern nor promote an increase in hydrogen loss.

Comments: Who Holds the Rights to US Geothermal Heat Sources?

A recently enacted law in Texas, which went into effect in mid-June, declares the landowner or the owner of surface rights as the holder of subsurface geothermal energy and associated resources. If the surface and mineral rights of the land have been separated, the owner of the surface estate prevails. Senate Bill 785 amended a section of the Natural Resources Code to define heat as a byproduct of geothermal energy and associated resources, but excludes mineral, oil, gas, or any product of oil or gas. It also excludes “the ownership and use of groundwater,” including “minerals dissolved or otherwise contained in groundwater, including hot brines.” The law entitles the owner “to drill for and produce the geothermal energy and associated resources.” As with pore space rights for underground carbon storage, legislating surface and subsurface rights for geothermal energy and underground hydrogen storage is an evolving frontier. Privately held rights vs. state or federal lands contribute to the complexity of these relatively nascent efforts to advance decarbonization. Ownership of geothermal rights varies widely from state to state, often dictated by a state’s definition of what constitutes “geothermal resources.” California’s definition, for example, says “the natural heat of the earth, the energy, in whatever form, below the surface of the earth present in, resulting from, or created by, or which may be extracted from, such natural heat, and all minerals in solution or other products obtained from naturally heated fluids, brines, associated gases, and steam, in whatever form, found below the surface of the earth, but excluding oil, hydrocarbon gas, or other hydrocarbon substances.” Other states, such as Utah, define a geothermal resource by a temperature threshold (“water or steam at temperatures greater than 120°C naturally present in a geothermal system”). At that mark, a separate lease is required because the resource is no longer part of the water rights. Once geothermal resources are defined, who holds the rights may be murky. In California, Hawaii, and New Mexico, the mineral estate is the owner. Wyoming considers geothermal heat as part of the water rights—“underground water, including hot water and geothermal.” Other states consider rights as held by the surface estate unless they have been specifically transferred. Yet, many states have no clearly defined guidance about privately held ownership, and the parties involved in disputes head to the courts to hash out the ambiguity. The rules governing development of geothermal energy on federal lands are more defined. Geothermal was the first type of renewable energy that the US Department of the Interior Bureau of Land Management approved for production on public lands. The first project was given the go-ahead in 1978. A federal lease allows future exploration and development. However, it does not include the right to move ahead with any ground-disturbing activities to explore for or develop the resources. Each stage of development under the lease requires separate authorizations and compliance with the National Environmental Policy Act. Two examples of state-controlled lands are well-known geothermal fields in California, The Geysers and the Salton Sea projects. The state’s leases in The Geysers are on school lands. Revenue and royalties are deposited into the California State Teachers’ Retirement fund. Royalty rates range from 10 to 12.5% of the gross value of geothermal steam, calculated by multiplying the gross value of electric power with the agreed percentage of steam that began initially as 36% in 1999, increasing to a maximum of 42% of the value of electricity. While innovation steadily advances technologies to produce geothermal energy, the determination of clear law and regulations is playing catch-up ... state by state and case by case in courts. And until it does, scaling up of this promising energy source in the US is at risk of being hamstrung.

Underground storage of hydrogen and hydrogen/methane mixtures in porous reservoirs: Influence of reservoir factors and engineering choices on deliverability and storage operations

Seasonal storage of natural gas (NG), which primarily consists of methane (CH4), has been practiced for more than a hundred years at underground gas storage (UGS) facilities that use depleted hydrocarbon reservoirs, saline aquifers, and salt caverns. To support a transition to a hydrogen (H2) economy, similar facilities are envisioned for long-duration, underground H2 storage (UHS) of either H2 or H2/CH4 mixtures. Experience with UGS can be used to guide the deployment of UHS, so we identify and quantify factors (formation/fluid properties and engineering choices) that influence reservoir behavior (e.g., viscous fingering and gravity override), the required number of injection/withdrawal wells, and required storage volume, contrasting the differences between the storage of CH4, H2, and H2/CH4 mixtures. The most important engineering choices are found to be the H2 fraction in H2/CH4 mixtures, storage depth, and injection rate. Storage at greater depths (higher pressure), but with relatively lower temperature, is more favorable because it maximizes volumetric energy-storage density, while minimizing viscous fingering and gravity override due to buoyancy. To store an equivalent amount of energy, storing H2/CH4 mixtures in UHS facilities will require more wells and greater reservoir volume than corresponding UGS facilities. We use our findings to make recommendations about further research needed to guide deployment of UHS in porous reservoirs.

Underground hydrogen storage: The microbiotic influence on rock wettability

Hydrogen geo-storage could be the large-scale solution needed for a hydrogen economy. Biological factors have been considered but mainly in terms of hydrogen-metabolising microbes. We demonstrate consistently the direct influence of underground biofilm formation on the wettability of sandstone reservoirs. The biofilm, formed by incubation with cyanobacteria Geitlerinema sp. in seawater, increases the advancing and receding brine contact angles on water-wet quartz. The angles decrease only slightly on oil-wet quartz surfaces even though biomass accumulation is more significant. We formulate an explanation using Cassie's approach to heterogeneous surfaces, taking into account the predominant surface chemical groups. Wettability strongly affects the distribution, trapping and mobility of phases (brine and hydrogen) inside the rock formation. Our results, obtained at typical reservoir conditions (25–50 °C, 3–130 bar), are relevant to understanding and assessing hydrogen injectivity, withdrawal rates, storage capacity and containment security. This fundamental research supports the development of an industrial-scale decarbonized hydrogen economy.

Regional mudstone compaction trends in the Vienna Basin: top seal assessment and implications for uplift history

Seal quality assessment is not only essential in petroleum systems studies but also in the context of other geo energy applications such as underground hydrogen storage. Capillary breakthrough pressure controls top seal capacity in the absence of faults or other discontinuities. In basins that lack measured capillary pressure data (e.g., from drill cores), regional compaction-porosity trends can be used as a first prediction tool to estimate the capillary properties of mudstones. Mathematical compaction models exist but need to be calibrated for each basin. This study aims to establish a compaction trend based on theoretical models, then compare it with theoretical maximum hydrocarbon column heights inferred from true measured capillary pressure curves. Middle to upper Miocene mudstone core samples from the Vienna Basin, covering a broad depth interval from 700 to 3400 m, were investigated by X-ray diffractometry, with an Eltra C/S analyzer, and by Rock–Eval pyrolysis for bulk mineralogy, total organic carbon, and free hydrocarbon contents. Broad ion beam—scanning electron microscopy, mercury intrusion capillary porosimetry, and helium pycnometry were applied to obtain pore structural properties to compare the mathematical compaction models with actual porosity data from the Vienna Basin. Clear decreasing porosity depth trends imply that mechanical compaction was rather uniform in the central Vienna Basin. Comparing the Vienna Basin trend to global mudstone compaction trends, regional uplift causing erosion of up to ~ 500 m upper Miocene strata is inferred. A trend of increasing Rock–Eval parameters S1 and production index [PI = S1/(S1 + S2)] with decreasing capillary sealing capacity of the investigated mudstones possibly indicates vertical hydrocarbon migration through the low-permeable mudstone horizons. This observation must be considered in future top-seal studies for secondary storage applications in the Vienna Basin.

Methanogenic conversion of hydrogen to methane in reservoir rocks: An experimental study of microbial activity in water-filled pore space

Underground hydrogen storage can lead to the activation of methanogenic Archaea, demanding to quantify microbial activities within the pore space to evaluate potential hydrogen conversion rates. This study presents a method to determine microbial activities within various water-saturated reservoir rocks, inoculated media containing sand particles and rock fragments as well as bulk solution, by monitoring pressure and gas composition. Measured activities in water-saturated rock specimens with identical bulk volumes varied between 0.15 and 1.28 mM H2/h correlating with pore volume. Additionally, the results reveal that activities within intact rocks are 8–10 times higher than in corresponding bulk solutions. This observation demonstrates that the surface area available for microorganism colonization is another potential factor controlling microbial activity when the substance amount is held constant. This notion is supported by activities measured in inoculated media containing sand particles and rock fragments, as well as in rocks with similar pore volumes.

Experimental studies of well integrity in cementing during underground hydrogen storage

Underground Hydrogen Storage (UHS) in the subsurface is an alternative to overcome limitations associated with a fluctuating production of renewable energy sources. The excess energy produced can be converted to hydrogen and stored in porous media. Hydrogen is injected and produced from geological formations via wells. There are several concerns regarding the interactions of hydrogen with the different well components responsible for maintaining proper well integrity, such as cement. This experimental study investigates the interaction between molecular hydrogen and cement Class H by characterizing samples using different physical and chemical tests. Results showed samples exposed to molecular hydrogen exhibited a greater compressive strength in both the short and long terms. Porosity and permeability were found to be lower in samples exposed to molecular hydrogen. NMR distributions showed a reduction of larger pores and an increase of smaller pore spaces. Acoustic velocities showed an increase of Young's Modulus, Shear's Modulus and a slight decrease in Poisson's ratio. The compositional analysis demonstrated that hydrogen presence increases the amount of portlandite and ettringite formed. The crystalline needle-shaped structure observed in the SEM confirmed the presence of portlandite and ettringite within some of the larger pores. This experimental study showed that molecular hydrogen present could increase the formation of portlandite and ettringite, causing a shift in the porosity distribution increasing the mechanical strength of the cement.

Experimental Study: The Effect of Pore Shape, Geometrical Heterogeneity, and Flow Rate on the Repetitive Two-Phase Fluid Transport in Microfluidic Porous Media.

Geologic subsurface energy storage, such as porous-media compressed-air energy storage (PM-CAES) and underground hydrogen storage (UHS), involves the multi-phase fluid transport in structurally disordered or heterogeneous porous media (e.g., soils and rocks). Furthermore, such multi-phase fluid transport is likely to repeatedly occur due to successive fluid injections and extractions, thus, resulting in cyclic drainage-imbibition processes. To complement our preceding study, we conducted a follow-up study with microfluidic pore-network devices with a square solid shape (Type II) to further advance our understanding on the effect of the pore shape (aspect ratio, Type I: 5-6 > Type II: ~1), pore-space heterogeneity (coefficient of variation, COV = 0, 0.25, and 0.5), and flow rates (Q = 0.01 and 0.1 mL/min) on the repetitive two-phase fluid flow in general porous media. The influence of pore shape and pore-space heterogeneity were observed to be more prominent when the flow rate was low (e.g., Q = 0.01 mL/min in this study) on the examined outcomes, including the drainage and imbibition patterns, the similarity of those patterns between repeated steps, the sweep efficiency and residual saturation of the nonwetting fluid, and fluid pressure. On the other hand, a higher flow rate (e.g., Q = 0.1 mL/min in this study) appeared to outweigh those factors for the Type II structure, owing to the low aspect ratio (~1). It was also suggested that the flow morphology, sweep efficiency, residual saturation, and required pressure gradient may not severely fluctuate during the repeated drainage--imbibition processes; instead, becoming stabilized after 4-5 cycles, regardless of the aspect ratio, COV, and Q. Implications of the study results for PM-CAES and UHS are discussed as a complementary analysis at the end of this manuscript.

Geochemical modelling on the role of redox reactions during hydrogen underground storage in porous media

Underground Hydrogen Storage (UHS) in porous media appears to be a promising means for large-scale hydrogen storage, underpinning the full-scale of hydrogen supply chain development. Hydrogen-brine-rock interactions play an important role in hydrogen conversion and contamination during hydrogen cycling process. While the redox reaction triggered by injected H2 and pre-existing O2 is unique in UHS compared to other types of gas subsurface storage, few research have been done to understand the role of redox reactions in hydrogen solubility, pH, and fewer works have looked beyond its process on hydrogen conversion and contamination, which may affect the stored H2 purity and storage efficiency. In this context, we examined the redox reactions on hydrogen-brine-minerals (e.g., calcite, siderite, quartz and pyrite) reactions as a function of dissolved oxygen concentration (from 5.5 to 5500 ppm), temperature, and pressure through geochemical modelling using geochemical solver PHREEQC.Our results showed that increasing dissolved oxygen concentration from 5.5 to 5500 ppm resulted in negligible impact on hydrogen solubility and pH for all tested minerals. As the sensitive minerals, siderite and calcite can react with H2 through the redox process, leading up to a certain hydrogen loss at the pressure of 20 MPa, respectively. Meanwhile, quartz and pyrite are insensitive minerals to hydrogen, causing less than 0.2% hydrogen loss at the same pressure condition. Our results indicate that the mineral oxidation due to the pre-existing O2 dissolved in formation brine played a negligible role in H2-brine-rock interactions. The results also showed that carbonate minerals such as siderite and calcite may act as electron acceptors, which triggered hydrogen dissociation and thus formed a strong reduction environment based on PHREEQC geochemical database. This process likely causes measurable hydrogen loss associated with abiotic geochemical reactions for the lifetime of the underground hydrogen storage operation. Taken together, we suggest that clean standstone reservoirs will signifcantly reduce the hydrogen conversion and contamination during underground hydrogen storage from abiotic geochemical perspective.

Numerical Simulation of Hydrogen Diffusion in Cement Sheath of Wells Used for Underground Hydrogen Storage

The negative environmental impact of carbon emissions from fossil fuels has promoted hydrogen utilization and storage in underground structures. Hydrogen leakage from storage structures through wells is a major concern due to the small hydrogen molecules that diffuse fast in the porous well cement sheath. The second-order parabolic partial differential equation describing the hydrogen diffusion in well cement was solved numerically using the finite difference method (FDM). The numerical model was verified with an analytical solution for an ideal case where the matrix and fluid have invariant properties. Sensitivity analyses with the model revealed several possibilities. Based on simulation studies and underlying assumptions such as non-dissolvable hydrogen gas in water present in the cement pore spaces, constant hydrogen diffusion coefficient, cement properties such as porosity and saturation, etc., hydrogen should take about 7.5 days to fully penetrate a 35 cm cement sheath under expected well conditions. The relatively short duration for hydrogen breakthrough in the cement sheath is mainly due to the small molecule size and high hydrogen diffusivity. If the hydrogen reaches a vertical channel behind the casing, a hydrogen leak from the well is soon expected. Also, the simulation result reveals that hydrogen migration along the axial direction of the cement column from a storage reservoir to the top of a 50 m caprock is likely to occur in 500 years. Hydrogen diffusion into cement sheaths increases with increased cement porosity and diffusion coefficient and decreases with water saturation (and increases with hydrogen saturation). Hence, cement with a low water-to-cement ratio to reduce water content and low cement porosity is desirable for completing hydrogen storage wells.

Editorial: Microbiology of underground hydrogen storage

Editorial: Microbiology of underground hydrogen storage

Potential of Salt Caverns for Hydrogen Storage in Southern Ontario, Canada

Salt caverns produced by solution mining in Southern Ontario provide ideal spaces for gas storage due to their low permeability. Underground hydrogen storage (UHS) is an important part of the future renewable energy market in Ontario in order to achieve global carbon neutrality and to fill the gap left by retiring nuclear power plants. However, large-scale hydrogen storage is still restricted by limited storage space on the ground’s surface. In this study, hydrogen’s physical and chemical properties are first introduced and characterized by low molecular weight, high diffusivity, low solubility, and low density. Then, the geological conditions of the underground reservoirs are analyzed, especially salt caverns. Salt caverns, with their inert cavity environments and stable physical properties, offer the most promising options for future hydrogen storage. The scales, heights, and thicknesses of the roof and floor salt layers and the internal temperatures and pressures conditions of salt caverns can affect stabilities and storage capacities. Finally, several potential problems that may affect the safe storage of hydrogen in salt caverns are discussed. Through the comprehensive analysis of the influencing factors of hydrogen storage in salt caverns, this study puts forward the most appropriate development strategy for salt caverns, which provides theoretical guidance for UHS in the future and helps to reduce the risk of large-scale storage design.

Microbial risk assessment for underground hydrogen storage in porous rocks

Geological hydrogen storage, e.g. in depleted gas fields (DGF), can overcome imbalances between supply and demand in the renewable energy sector and facilitate the transition to a low carbon emissions society. A range of subsurface microorganisms utilise hydrogen, which may have important implications for hydrogen recovery, clogging and corrosion. We gathered temperature and salinity data for 75 DGF on the UK continental shelf and mapped their suitability for hydrogen storage in terms of the risk of adverse microbial effects, based on a novel collection of microbial growth constraints. Data on wind and solar operational capacities as well as offshore gas and condensate pipeline infrastructure were overlaid on the microbial risk categorization to optimize geographical centers of green hydrogen production, transport infrastructure and underground storage. We recommend storing hydrogen in 9 DGF that are at no microbial risk due to temperatures > 122 °C, or in the 35 low-risk DGF with temperatures > 90 °C. We recommend against utilising high-risk DGF with temperatures < 55 °C (9 DGF). Alignment with centers for renewable energy production and out-of-use pipelines suitable for repurposing to transport hydrogen suggests that no-risk and low-risk DGF in the Southern North Sea are the most suitable candidates for hydrogen storage. Our results advise site selection choices in geological hydrogen storage in the UK. Our methodology is applicable to any underground porous rock system globally.

Simultaneous enhanced oil recovery, CCUS and UHUS in shale oil reservoirs

The objective of this paper is to put forward some ideas related to CO2 and H2 utilization and storage while simultaneously conducting huff and puff (H&P) gas injection to increase oil recovery. The discussed utilization (U) and storage (S) are important parts of carbon capture, utilization and storage (CCUS). However, the CO2 capture (C) is beyond the scope of this study. Underground hydrogen storage (UHS) has been studied in the past. However, this is the first paper that investigates the possibility of H&P H2 injection in shale oil reservoirs. Hence, for simplicity we are introducing the acronym UHUS to signify underground hydrogen utilization and storage. It is anticipated that the simultaneous underground utilization and storage of CO2 and H2 will contribute to achieving the goal of net zero emissions.The paper involves the analysis of a real H&P CH4 injection pilot well in the Eagle Ford shale of Texas. The procedure includes history matching the primary and H&P history of the pilot well, and then forecasting oil recovery if the H&P is continued with CH4, or if the H&P is switched to CO2 or H2 in the reservoir simulator. The success of this method relies on geologic containment, which occurs when significant hydrocarbon volumes remain over geologic time in the same general location where they were generated. The Eagle Ford shale exemplifies this phenomenon, with hydrocarbons showing an inverted distribution - oil at the top, condensate in the middle, and dry gas at the bottom of the structure. Geologic containment enables the implementation of H&P CH4, CO2 or H2 injection and simultaneous storage of any of the injection fluids in the shale reservoir with negligible risk of unwanted leakage.The results demonstrate that H&P CH4, CO2 or H2 gas injection can considerably boost oil recovery to 25–30% of the original oil in place (OOIP), depending on the injected gas, as compared to only 5–10% with primary recovery methods. The advantages of H&P gas injection described in this paper also have potential application in other shale reservoirs with an inverted distribution of oil, condensate and dry gas, such as the Duvernay shale in Canada, the La Luna shale in Colombia and Venezuela and the Vaca Muerta shale in Argentina. Geologic containment ensures safe and appropriate storage of CO2 and H2 with negligible possibilities of leakage at the conclusion of the H&P project. Additionally, this paper also supports a previous conclusion by Olusola et al. (2021) indicating that gas injection at higher rates for shorter durations of time (as opposed to smaller gas injection rates for longer periods of time) can result in substantial improvements in oil recovery. This finding holds true for CH4, CO2 and H2 injection.The novelty of this research is demonstrating the effectiveness of combining H&P CO2 or H2 injection with the underground storage of such fluids in shale reservoirs characterized by geologic containment. This combination provides a win-win situation, as it not only enhances oil recoveries significantly, but also allows for safe storage of CO2 and H2 with negligible possibilities of potential leaks.

Screening and ranking Japanese gas fields for underground H2 storage potential: Impact of the reservoir drive mechanism

To accomplish the net-zero goal, Japan intends to increase its reliance on renewable energies such as solar power (36–38 % in 2030). However, considering the intermittent nature of solar power, the resulting energy must be transformed to a secondary energy carrier such as H2. Japan, on the other hand, is expected to import 20 × 106 tons of H2 each year by 2050. Because of these large volumes, new H2 storage techniques must be developed, in particular underground hydrogen storage (UHS). This paper ranks eight gas reservoirs out of 106 oil and gas fields in four Japanese prefectures regarding their suitability for UHS, and then suggests a H2 injection and withdrawal scheme based on the history of electricity consumption and solar power curtailment. Then, a reservoir simulation study was performed to investigate the effects of factors such as hysteresis, repeated cycles and cushion gas on the performance of these fields. The outcomes for water-drive and volumetric gas reservoirs were compared to better understand the effects of an aquifer on the long-term performance of a gas reservoir when used for UHS. Finally, it was demonstrated that the technology sought for the conversion of H2 back to electricity after withdrawal from a UHS site governs the overall efficiency of a power-H2-power process.

Host-rock and caprock wettability during hydrogen drainage: Implications of hydrogen subsurface storage

Underground hydrogen storage (UHS) is an integral part of H2 economy value chain, essential for industrial-scale actualization of global decarbonization objectives. UHS in depleted hydrocarbon reservoirs is considered a safer and promising storage technique due to presence of large porous formation and impermeable seal, but its effectiveness depends on precise estimation of rock wettability, a crucial parameter in reservoir characterization, which controls pore-scale gas distribution, H2 containment safety and withdrawal efficiency. Several recent studies have provided contact angles data for host rock-water-H2 (quartz and sandstone) and caprock-water-H2 (mica and shale) measured through sessile drop method. However, the contact angle datasets for carbonate rock-water-H2 measured via captive bubble method, which can reflect the wettability of the rock during imbibition and drainage are largely unknown. The present work characterized the wettability of carbonate-water-H2 systems for various rock types, prepared from five different lithologies with different mineral assemblages. The contact angle θ was measured using the captive bubble method at two different temperatures of 303 K and 348 K, and three different pressures (3.44, 10.34, and 17.23 MPa). Experimental results showed that all rocks remained intrinsically strongly water-wet (θ ranged between 17° – 30°) at all experimental conditions. Furthermore, no significant change in contact angles occurred with changing temperature and pressure. For instance, at 17.23 MPa, contact angle of H2/brine on anhydrite (S-4) rock were measured as 19° and 20° at 303 K and 348 K respectively, suggesting that H2 remains the non-wetting phase with increasing storage depth and at warmer reservoirs. The study suggests that the pore-scale flow and fluid connectivity of H2 may not be influenced by changing wettability in pure storage rocks/caprocks. Thus, the wettability of carbonates storage rocks and caprocks may not be over-predicted by assuming strongly water-wet conditions for the non-contaminated rock surfaces during UHS.

Compositional reservoir simulation of underground hydrogen storage in depleted gas reservoirs

The unstable supply of renewable energy due to seasonal dependency contradicts the periodic energy demand. As hydrogen presents high energy density and flow mobility, and low solubility and residual saturation, underground hydrogen storage (UHS) is a promising solution of scalable energy storage to rebalance energy demand and supply. Depleted gas reservoirs (DGR) are a suitable option for UHS due to their demonstrated integrity. In this study, we developed a numerical simulation model based on Tough + RealGasBrine (T + RGB) simulator to evaluate the feasibility of UHS in DGR. We calibrated different Equation-of-State (EOS) models for modeling the phase behavior of hydrogen-included mixtures with experimental data, and this further helps to examine the impact of various cushion gas pre-injection strategies on pressure maintenance and potential hydrogen leakage through cap-rock. After comparison among three EOS models, we adopted the Soave-Redlich-Kwong (SRK) EOS in our simulations as its high accuracy and computational efficiency. Afterward, we simulated one hydrogen injection-idle-withdrawal operation in a high-resolution mesh based on a synthetic heterogeneous anticline DGR. We observed that hydrogen displaces pre-existing methane and resides at the top of the storage zone due to gravity segregation. The average pressure and gas saturation of the whole simulation domain increase with the hydrogen injection. With regard to the hydrogen leakage, when the cap-rock permeability ranges from 10−5 to 10−3 mD, 0.05% of the injected hydrogen at maximum leaks into the cap-rock while about 1% of injected hydrogen is dissolved into the aqueous phase. Those results demonstrate that DGR is a viable option for UHS. However, only about 73% of injected hydrogen can be recovered if the bottom-hole pressure of the production well is 2 MPa below the reservoir pressure. The cushion gas becomes necessary for the UHS project to increase hydrogen recovery. Injecting cushion gas of nitrogen and carbon dioxide increases hydrogen recovery from the initial 73%–91% and 81%, respectively. The simulation results demonstrate that nitrogen exhibits better performance, in terms of higher hydrogen recovery factor and purity of producing gas, as the cushion gas. In this work, we quantitatively evaluated the hydrogen leakage problem, including leakage into cap-rock, dissolution in water, and mixing with other gas components, which is the first-of-its-kind analysis in literature to the author's best knowledge. The simulation results support the feasibility of UHS in the DGR.

Liquid Permeability Determination from Vacuum Imbibition in Tight/Shale Core Plugs

Liquid permeability is a key petrophysical parameter that quantifies the ability of a liquid to flow through porous rock/soil and can be used in determining the efficiency of many subsurface processes, including enhanced hydrocarbon recovery, groundwater transport, carbon dioxide geostorage, underground hydrogen storage, etc. However, it is time-consuming (usually >16–240 h) and challenging to measure the liquid permeability for tight/shale rocks, particularly when the permeability is 100 nD or lower. The objective of this study is to develop a rapid and simple approach to determine liquid (brine or oil) permeability in tight siltstones/shales. Specifically, the developed method is based on the combination of one-dimensional (1D) vacuum imbibition experiments in tight/shale core plugs and a modified Lucas–Washburn model. For our proof-of-concept study, the results have demonstrated that (1) only 44–116 h are required to determine the liquid permeability (98–608 nD) for the analyzed samples from the Montney and Yanchang Formations; and (2) the acquired brine permeability was 28.3–28.5% lower than the slip-corrected nitrogen (N2) permeability derived from the pulse-decay permeability tests. This is the first attempt to determine the absolute permeability of a liquid according to a 1D vacuum imbibition experiment and theory. This study provides a promising technique for the fast characterization of ultratight formation permeability of around 100 nD.