Storage of hydrogen,natural gas,and carbon dioxide – Geological and legal conditions

The analysis of geological and reservoir conditions of the underground storage of hydrogen, methane, and carbon dioxide, that are important when choosing rock formations for the storage of gas, was presented. Physico-chemical properties of the discussed gases, affecting underground storage, were taken into account. Aquifers, hydrocarbon reservoirs, and caverns leached in salt rocks were analyzed. Legal aspects of underground gas storage were indicated.The physico-chemical conditions of the gases considered (especially molecular mass, and dynamic viscosity) are important for the selection of geological structures for their storage. The reservoir tightness is one of the most important geological and reservoir conditions when taking the appropriate porosity and permeability of rocks building underground storage sites into account. Salt caverns should be mainly used for hydrogen storage due to the tightness of rock salt. Geochemical and microbiological interactions affecting the operation of the underground storage site and its tightness are especially important and should be taken into account. The size of the underground storage site, while not as crucial in the case of H₂ storage, is important for CO₂ storage. When it comes to reservoir conditions, the amount of cushion gas and storage efficiency are important. The legal status of gas storage sites is highly variable. While there are existing regulations regarding natural gas storage, CO₂ storage requires further legislation. In the case of H₂ storage legal regulations need to be developed based on the experience of storage of other gases. The potential competition from other entities focused on the use of underground space for gas storage should be taken into account.     

Technical potential of salt caverns for hydrogen storage in Europe

The role of hydrogen in a future energy system with a high share of variable renewable energy sources (VRES) is regarded as crucial in order to balance fluctuations in electricity generation. These fluctuations can be compensated for by flexibility measures such as the expansion of transmission, flexible generation, larger back-up capacity and storage. Salt cavern storage is the most promising technology due to its large storage capacity, followed by pumped hydro storage. For the underground storage of chemical energy carriers such as hydrogen, salt caverns offer the most promising option owing to their low investment cost, high sealing potential and low cushion gas requirement. This paper provides a suitability assessment of European subsurface salt structures in terms of size, land eligibility and storage capacity. Two distinct cavern volumes of 500,000 m³ and 750,000 m³ are considered, with preference being given for salt caverns over bedded salt deposits and salt domes. The storage capacities of individual caverns are estimated on the basis of thermodynamic considerations based on site-specific data. The results are analyzed using three different scenarios: onshore and offshore salt caverns, only onshore salt caverns and only onshore caverns within 50 km of the shore. The overall technical storage potential across Europe is estimated at 84.8 PWh_H2, 27% of which constitutes only onshore locations. Furthermore, this capacity decreases to 7.3 PWh_H2 with a limitation of 50 km distance from shore. In all cases, Germany has the highest technical storage potential, with a value of 9.4 PWh_H2, located onshore only in salt domes in the north of the country. Moreover, Norway has 7.5 PWh_H2 of storage potential for offshore caverns, which are all located in the subsurface of the North Sea Basin.     

Measurement of hydrogen dispersion in rock cores using benchtop NMR

Electrolysis followed by underground hydrogen storage (UHS) in both salt caverns and depleted oil and gas reservoirs is widely considered as a potential option to overcome fluctuations in energy provision from intermittent renewable sources. Particularly in the case of depleted oil and gas reservoirs, a denser layer of cushion gas (N₂, CH₄ or CO₂) can be accommodated in these storage volumes to allow for sufficient system pressure control as hydrogen is periodically injected and extracted. These gases/fluids are however fully soluble with hydrogen and thus with sufficient mixing can undesirably contaminate the extracted hydrogen product. Fluid mixing in a porous medium is typically characterized by a dispersion coefficient (K_L), which is hence a critical input parameter into reservoir simulations of underground hydrogen storage. Such dispersion data is however not readily available in the literature for hydrogen at relevant storage conditions. Here we have developed and demonstrated novel methodology for the measurement of K_L between hydrogen and nitrogen in a Berea sandstone at 50 bar as a function of displacement velocity (0.007–0.722 mm/s). This leverages off previous work quantifying K_L between carbon dioxide and methane in rock cores relevant to enhanced gas recovery (EGR). This used infrared (IR) spectroscopy to differentiate the two fluids, hydrogen is however IR invisible. Hence the required time-resolved quantification of hydrogen concentration emerging from the rock core is uniquely performed here using bench-top nuclear magnetic resonance (NMR). The resultant hydrogen-nitrogen dispersion data as a function of displacement velocity allows for the determination of dispersivity (α = 0.31 mm). This intrinsic rock property compares favorably with previous CO₂ dispersion measurements on similar sandstones, hence validating our methodology to some extent. In addition, at very low velocities, determination of the rock core tortuosity (τ, another intrinsic rock property) produces a value (τ = 10.9) that is similar to that measurement independently using pulsed field gradient NMR methods (τ = 11.3).     

Preliminary assessment of underground hydrogen storage sites in Ontario,Canada

The replacement of coal-fired power plants with increasing proportions of renewable and nuclear energies in the province of Ontario highlights the need to balance seasonal energy demands. This can be achieved through power-to-gas technology, where excess energy is used to generate hydrogen gas through electrolysis, and the generation is coupled with underground hydrogen storage. This article presents a preliminary assessment regarding the potential for underground hydrogen storage in geological formations including salt and hard rock caverns, depleted oil and gas fields, and saline aquifers in Ontario, highlighting potential locations where future storage could be feasible. Southern Ontario presents many potential storage options, including Silurian bedded salts, depleted Ordovician natural gas reservoirs, saline aquifers in Cambrian sandstone and hard rock caverns in argillaceous limestones. Hard rock caverns in Precambrian crystalline rocks of the Canadian Shield are also discussed, in addition to the potential for the use of lined rock caverns. This work aims to provide a basis for further research regarding the appropriate location of underground hydrogen gas storage facilities in Ontario.     

Bulk storage of hydrogen

The technical aspects and economics of bulk hydrogen storage in underground pipes, lined rock caverns (LRC) and salt caverns are analyzed. Hydrogen storage in underground pipes is more economical than in geological caverns for useable amounts <20-t-H₂. However, because the pipe material is a major cost factor, the capital and operating costs for this storage method do not decrease appreciably with an increase in the amount of stored H₂. Unlike underground pipes, the installed capital cost of salt caverns decreases appreciably from ~$95/kg-H₂ at 100 t-H₂ stored to <$19/kg-H₂ at 3000 t-H₂ stored. Over the same scale, the annual storage cost decreases from ~$17/kg-H₂ to ~$3/kg-H₂. Like salt caverns, the installed capital cost of lined rock caverns decreases from ~$160/kg-H₂ at 100 t-H₂ stored to <$44/kg-H₂ at 3000 t-H₂ stored. Storing >750-t useable H₂ requires multiple caverns. The cost of salt caverns scales more favorably with size because the salt caverns are larger than lined rock caverns and need to be added at a slower rate as the storage capacity is increased.     

Experimental simulations of hydrogen migration through potential storage rocks

In the framework of future decarbonization of the energy industry, the safe and effective storage of hydrogen is an important approach to add to a climate-friendly energy system. Until the development of sufficiently large electrical storage systems, the storage of hydrogen in the order of GWh to TWh is envisaged in salt caverns or porous geological formations with a gas-tight covering of salt or claystone. In order to calculate gas losses from these H₂ storage facilities, the H₂ diffusivity of the storage and cap rocks must be known. To determine the hydrogen diffusion rates in these rocks, an experimental set-up was designed, constructed and tested. The set-up comprises two gas chambers, separated by the rock sample under investigation with an exposed area of approximately 7 cm². The driving force for gas migration through the rock sample from the hydrogen-containing feed gas chamber to the hydrogen-free permeate chamber is the chemical potential (concentration) gradient. With respect to hydrogen migration behaviour, hydrogen breakthrough times and hydrogen diffusion coefficients were determined for dry and wet Bentheimer sandstone, Werra rock salt and Opalinus clay samples. Breakthrough times varied between less than 1 h and 843 h. Based on concentration changes at the permeate side, hydrogen diffusion coefficients were derived ranging from 10⁻⁹ to 10⁻⁸ m²/s. The differences between the materials and the effect that wetted or water-saturated samples have higher hydrogen retention due to closed pores and microcracks were clearly shown. The experimental set-up proves to be a suitable approach to determine site-specific rock characteristics such as hydrogen diffusion coefficients and breakthrough times for natural geomaterials.     

Geologic storage of hydrogen: Scaling up to meet city transportation demands

Over the last decade, there has been a growing interest in large-scale use of hydrogen in the transportation and renewable energy sectors. Relatively cost-effective storage options at scale are essential to realize the full potential of hydrogen as an energy carrier. Underground geologic storage of hydrogen could offer substantial storage cost reductions as well as buffer capacity to meet possible disruptions in supply or changing seasonal demands. Several geologic storage site options are being considered including salt caverns, depleted oil and/or gas reservoirs, aquifers, and hard rock caverns. This paper describes an economic analysis that addresses the costs entailed in developing and operating a geologic storage facility. The analysis focuses on salt caverns to illustrate potential city demand for hydrogen using geostorage options because (1) salt caverns are known to successfully contain hydrogen, and (2) there is more geotechnical certainty involved with salt storage as compared to the other three storage options. The main findings illustrate that geologic limitations rather than city demand cause a larger disparity between costs from one city to the next. For example Detroit hydrogen storage within salt caverns will cost approximately three times more than Los Angeles with its larger population. Detroit is located near thinly bedded salt formations, whereas Los Angeles has access to more massive salt formations. Los Angeles requires the development of larger and fewer caverns and therefore has lower costs.     

Structural analysis of microbiomes from salt caverns used for underground gas storage

Salt caverns are a safe and well-proven reservoir for large-scale natural gas storage and hence, a potential hydrogen storage. Contrary to natural gas, hydrogen is a favorable energy source for many microorganisms. Microorganisms are ubiquitously abundant in the upper lithosphere and therefore expected to be present also in subsurface geological formations potentially selected for H₂ storage, such as salt caverns. Thus, future salt cavern hydrogen storage requires monitoring of the cavern microbiome, to evaluate and prevent unwanted microbial activities. In this study, we analyzed the microbiomes of brines sampled from the bottom of five German natural gas storage caverns. All brines were colonized by microorganisms in considerable cell numbers ranging from 2 × 10⁶ cells ml^?1 to 7 × 10⁶ cells ml^?1. The structures of the microbiomes were characterized by 16S rRNA gene amplicon sequencing. A core community detected in all five studied caverns consists of members affiliated to the Halobacteria, Halanaerobiales and Balneolales. Further, a phylotype belonging to the extremely halophilic, lithoautotrophic and sulfate-reducing genus Desulfovermiculus was found. Examination of microbial activity also included measuring hydrochemical parameters in order to assess the salt concentrations and the availability of nutrients and potential microbial carbon sources or metabolites. NaCl (4.7 M) was the main salt and sulfate (at average 40.8 mM) the main electron acceptor; methanol (up to 37.5 mM) and ethanol (up to 6.9 mM) were of anthropogenic origin and found in higher concentrations. Some putative microbial metabolites were found in lower concentrations (butyrate, ≤0.7 mM; formate, ≤0.08 mM; acetate, ≤0.5 mM; lactate, ≤0.06 mM); their potential relation to microbial activity is discussed. We propose a guideline for sampling and subsequent chemical and molecular biological analysis for future characterization of microbial communities of salt cavern brines.     

Modeling phase equilibrium of hydrogen and natural gas in brines: Application to storage in salt caverns

In this work, the e-PPC-SAFT equation of state has been parameterized to predict phase equilibrium of the system H₂ + CH₄ + H₂O + Na⁺Cl^? in conditions of temperature, pressure and salinities of interest for gas storage in salt caverns. The ions parameters have been adjusted to match salted water properties such as mean ionic coefficient activities, vapor pressures and molar densities. Furthermore, binary interaction parameters between hydrogen, methane, water, Na⁺ and Cl^? have been adjusted to match gas solubility data through Henry constant data. The validity ranges of this model are 0–200 °C for temperatures, 0–300 bar for pressures, and 0 to 8 mol_NaCl/kg_H2O for salinities. The e-PPC-SAFT equation of state has then been used to model gas storage in salt caverns. The performance of a storage of pure methane, pure hydrogen and a mixture methane + hydrogen have been compared. The simulations of the storage cycles show that integrating up to 20% of hydrogen in caverns does not have a major influence on temperature, pressure and water content compared to pure methane storage. They also allowed to estimate the thermodynamic properties of the system during the storage operations, like the water content in the gaseous phase. The developed model constitutes thus an interesting tool to help size surface installations and to operate caverns.     

Assessment of the potential for underground hydrogen storage in bedded salt formation

Salt formations of an appropriate thickness and structure, common over the globe, are potential sites for leaching underground caverns in them for storage of various substances, including hydrogen. Underground hydrogen storage, considered as underground energy storage, requires, in first order, an assessment of the potential for underground storage of this gas at various scales: region, country, specific place.The article presents the results of the assessment of the underground hydrogen storage potential for a sample bedded salt formation in SW Poland. Geological structural and thickness maps provided the basis for the development of hydrogen storage capacity maps and maps of energy value and heating value. A detailed assessment of the hydrogen storage capacity was presented for the selected area, for a single cavern and for the cavern field; a map of the energy value of stored hydrogen has also been presented. The hydrogen storage potential of the salt caverns was related to the demand for electricity and heat. The results show the huge potential for hydrogen storage in salt caverns.     

Review on using the depleted gas reservoirs for the underground H2 storage: A case study in Niigata prefecture,Japan

Underground hydrogen storage (UHS) in depleted hydrocarbon reservoirs is a prospective choice to store enormous volumes of hydrogen (H₂). However, these subsurface formations must be able not only to store H₂ in an effective and secure manner, but also to produce the required volumes of H₂ upon demand. This paper first reviews the critical parameters to be considered for geological analysis and reservoir engineering evaluation of UHS. The formation depth, the interactions of rock-brine-H₂, the caprock (seal) and well integrity are the most prominent parameters as far as UHS is concerned. In respect of these critical parameters, tentative H₂ storage is screened from the existing gas storage fields in the Niigata prefecture of Japan, and it was revealed that the Sekihara gas field is a suitable candidate for UHS with a storage capacity of 2.06 × 10⁸ m³ and a depth of 1000 m. Then, a series of numerical simulations utilizing CMG software was conducted to find out the extent to which critical parameters alter H₂ storage capacity. The results demonstrated that this field, with a recovery factor of 82.7% in the sixth cycle of production is a prospective site for H₂ storage.     

Large-scale storage of hydrogen in salt caverns for carbon footprint reduction

This article presents a geomechanical appraisal of green hydrogen (H₂) storage in salt caverns opened by solution mining as a technical contribution to carbon footprint reduction. The location of the salt cavern is speculative, within possible limits to be found in the salt deposits in the Gulf of Mexico of the USA, as the aim is to demonstrate the technical feasibility of the concept. It presents the conceptual design of the wells used for the solution mining of the caverns and the operation cycle of injection and withdrawal of hydrogen. The contribution of the study presented stems from the methodology adopted in the simulation of the geomechanical structural behavior of the salt cavern and in its design for storing hydrogen, which has thermomechanical properties more complex than natural gas. The numerical simulation considers the nonlinear physical viscoelastic and elastoplastic phenomena, with different constitutive laws for representing the geomechanical behavior of geomaterials. The constitutive laws based on deformation mechanisms are used (multi-mechanisms of deformation – M.D.) to simulate the creep of the salt rock. The article also presents a protocol for sizing the caverns, considering more than 40 years of experience in the design of conventional and solution mining of rock salt. It presents the concept of admissible halite creep strain and safety factors necessary to establish a stress belt that avoids hydrogen leaks at all stages of cavern construction and hydrogen storage. Using this methodology, the authors found that the cavern studied (220 m in height and 95 m in diameter) can hold 11,968,000 kg of working hydrogen.     

GIS-based analysis of rock salt deposits’ suitability for underground hydrogen storage

The paper discusses the suitability of bedded salt deposits for underground hydrogen storage facilities. The presented research is an example of multi-criteria decision analysis coupled with spatial data analysis undertaken using GIS (Geographic Information System). The aim of this study is to develop a methodology for selecting the best locations for hydrogen storage in salt caverns. In the analysis, we take into account the results of previous studies of the storage capacity of rock salt deposits. The presented methodology allows the creation of rock salt deposit suitability maps for underground hydrogen storage. The results show that the applied method significantly influences the resulting map image, helping to identify optimal locations for hydrogen storage facilities. The presented approach may be of value to governmental institutions considering underground hydrogen storage, geological services, power plants producing electricity from renewable energy sources, and chemical and petrochemical plants.     

Evaluating the hydrogen storage potential of shut down oil and gas fields along the Norwegian continental shelf

The underground hydrogen storage (UHS) capacities of shut down oil and gas (O&G) fields along the Norwegian continental shelf (NCS) are evaluated based on the publicly available geological and hydrocarbon production data. Thermodynamic equilibrium and geochemical models are used to describe contamination of hydrogen, loss of hydrogen and changes in the mineralogy. The contamination spectrum of black oil fields and retrograde gas fields are remarkably similar. Geochemical models suggest limited reactive mineral phases and meter-scale hydrogen diffusion into the caprock. However, geochemical reactions between residual oil, reservoir brine, host rock and hydrogen are not yet studied in detail. For 23 shut down O&G fields, a theoretical maximum UHS capacity of ca. 642 TWh is estimated. We conclude with Frigg, Nordost Frigg, and Odin as the best-suited shut down fields for UHS, having a maximum UHS capacity of ca. 414 TWh. The estimates require verification by site-specific dynamic reservoir models.     

The potential of metal hydrides paired with compressed hydrogen as thermal energy storage for concentrating solar power plants

Concentrating solar power (CSP) plants require thermal energy storage (TES) systems to produce electricity during the night and periods of cloud cover. The high energy density of high-temperature metal hydrides (HTMHs) compared to state-of-the-art two-tank molten salt systems has recently promoted their investigation as TES systems. A common challenge associated with high-temperature metal hydride thermal energy storage systems (HTMH TES systems) is storing the hydrogen gas until it is required by the HTMH to generate heat. Low-temperature metal hydrides can be used to store the hydrogen but can comprise a significant proportion of the overall system cost and they also require thermal management, which increases the engineering complexity. In this work, the potential of using a hydrogen compressor and large-scale underground hydrogen gas storage using either salt caverns or lined rock caverns has been assessed for a number of magnesium- and sodium-based hydrides: MgH₂, Mg₂FeH₆, NaMgH₃, NaMgH₂F and NaH. Previous work has assumed that the sensible heat of the hydrogen released from the HTMH would be stored in a small, inexpensive regenerative material system. However, we show that storing the sensible heat of the hydrogen released would add between US$3.6 and US$7.5/kWh_th to the total system cost for HTMHs operating at 565 °C. If the sensible heat of released hydrogen is instead exploited to perform work then there is a flow-on cost reduction for each component of the system. The HTMHs combined with underground hydrogen storage all have specific installed costs that range between US$13.7 and US$26.7/kWh_th which is less than that for current state-of-the-art molten salt heat storage. Systems based on the HTMHs Mg₂FeH₆ or NaH have the most near term and long term potential to meet SunShot cost targets for CSP thermal energy storage. Increasing the operating temperature and hydrogen equilibrium pressure of the HTMH is the most effective means to reduce costs further.     

Impact of experimentally measured relative permeability hysteresis on reservoir-scale performance of underground hydrogen storage (UHS)

Underground Hydrogen Storage (UHS) is an emerging large-scale energy storage technology. Researchers are investigating its feasibility and performance, including its injectivity, productivity, and storage capacity through numerical simulations. However, several ad-hoc relative permeability and capillary pressure functions have been used in the literature, with no direct link to the underlying physics of the hydrogen storage and production process. Recent relative permeability measurements for the hydrogen-brine system show very low hydrogen relative permeability and strong liquid phase hysteresis, very different to what has been observed for other fluid systems for the same rock type. This raises the concern as to what extend the existing studies in the literature are able to reliably quantify the feasibility of the potential storage projects. In this study, we investigate how experimentally measured hydrogen-brine relative permeability hysteresis affects the performance of UHS projects through numerical reservoir simulations. Relative permeability data measured during a hydrogen-water core-flooding experiment within ADMIRE project is used to design a relative permeability hysteresis model. Next, numerical simulation for a UHS project in a generic braided-fluvial water-gas reservoir is performed using this hysteresis model. A performance assessment is carried out for several UHS scenarios with different drainage relative permeability curves, hysteresis model coefficients, and injection/production rates. Our results show that both gas and liquid relative permeability hysteresis play an important role in UHS irrespective of injection/production rate. Ignoring gas hysteresis may cause up to 338% of uncertainty on cumulative hydrogen production, as it has negative effects on injectivity and productivity due to the resulting limited variation range of gas saturation and pressure during cyclic operations. In contrast, hysteresis in the liquid phase relative permeability resolves this issue to some extent by improving the displacement of the liquid phase. Finally, implementing relative permeability curves from other fluid systems during UHS performance assessment will cause uncertainty in terms of gas saturation and up to 141% underestimation on cumulative hydrogen production. These observations illustrate the importance of using relative permeability curves characteristic of hydrogen-brine system for assessing the UHS performances.     

Capacity assessment and cost analysis of geologic storage of hydrogen: A case study in Intermountain-West Region USA

Hydrogen is an integral component of the current energy transition roadmap to decarbonize the economy and create an environmentally-sustainable future. However, surface storage options (e.g., tanks) do not provide the required capacity or durability to deploy a regional or nationwide hydrogen economy. In this study, we have analyzed the techno-economic feasibility of the geologic storage of hydrogen in depleted gas reservoirs, salt caverns, and saline aquifers in the Intermountain-West (I-WEST) region. We have identified the most favorable candidate sites for hydrogen storage and estimated the volumetric storage capacity. Our results show that the geologic storage of hydrogen can provide at least 72% of total energy consumption of the I-WEST region in 2020. We also calculated the capital and levelized costs of each storage option. We found that a depleted gas reservoir is the most cost-effective candidate among the three geologic storage options. Interestingly, the cushion gas type plays a significant role in the storage cost when we consider hydrogen storage in saline aquifers. The levelized costs of hydrogen storage in depleted gas reservoirs, salt caverns, and saline aquifers with large-scale storage capacity are approximately $1.15, $2.50, and $3.27 per kg of H₂, respectively. This work provides essential guidance for the geologic hydrogen storage in the I-WEST region.     

Experimental investigation of hydrogen-carbonate reactions via computerized tomography: Implications for underground hydrogen storage

The underground hydrogen storage (UHS) in depleted hydrocarbon reservoirs, aquifers, and saline caverns is regarded as a vital component of hydrogen economy value-chains, meant to tackle carbon emissions and global warming. The caprock integrity and storage capacity of the carbonate formations can be altered by the reaction between the injected hydrogen and the calcite/dolomite minerals during UHS. However, experimental investigations of hydrogen-calcite/dolomite reactions at underground storage temperature are rarely reported in literature. Thus, we conducted X-ray computed micro-tomography (μCT) scans of limestone and dolomite cores before and after pressurization with hydrogen for 75 days at 700 psi and 75 °C. For the first time, a significant calcite expansion was observed and led to reduction in storage capacity (i.e., effective porosity) by 47%. However, the storage capacity of the dolomite rock slightly increased (～6%) because the grain expansion effects canceled out the dissolution effects. The study suggests that reduction in storage capacity of carbonate formation due to hydrogen reactivity with calcite is possible during UHS in carbonate formations. Thus, hydrogen reactivity with carbonate minerals should be evaluated to de-risk hydrogen storage projects in carbonate formations.     

Measurements and predictive models of high-pressure H2 solubility in brine (H2O+NaCl) for underground hydrogen storage application

In the context of Underground Hydrogen Storage (UHS), the stored gas is in direct contact with brine (residual brine from the cavern or formation water of deep aquifers). Therefore, knowledge of the phase equilibria (solubility of hydrogen in brine and water content in the hydrogen-rich phase) in the geological reservoir is necessary for the study of hydrogen mobility and reactivity, as well as the control, monitoring and optimization of the storage. The absence of measured data of high-pressure H₂ solubility in brine has recently led scientists to develop predictive models or to generate pseudo-data using molecular simulation. However, experimental measurements are needed for model evaluation and validation. In this work, an experimental apparatus based on the “static-analytic” method developed and used in our previous work for the measurement of gas solubility in brine was used. New solubility data of H₂ in H₂O+NaCl were measured more or less under the geological conditions of the storage, at temperatures between 323 and 373 K, NaCl molalities between 0 and 5m, and pressures up to 230 bar. These data were used to parameterize and evaluate three models (Geochemical, SW, and e-PR-CPA models) tested in this work. Solubility and water content tables were generated by the e-PR-CPA model, as well as a simple formulation (Setschenow-type relationship) for quick and accurate calculations (in the fitting range) of H₂ solubility in water and brine was proposed. Finally, the developed models estimate very well the water content in hydrogen-rich phase and capture and calculate precisely the salting-out effect on H₂ solubility.     

Thermodynamic characterization of H2-brine-shale wettability: Implications for hydrogen storage at subsurface

Large-scale underground hydrogen storage (UHS) appears to play an important role in the hydrogen economy supply chain, hereby supporting the energy transition to net-zero carbon emission. To understand the movement of hydrogen plume at subsurface, hydrogen wettability of storage rocks has been recently investigated from the contact angles rock-H₂-brine systems. However, hydrogen wettability of shale formations, which determines the sealing capacity of the caprock, has not been examined in detail. In this study, semi-empirical correlations were used to compute the equilibrium contact angles of H₂/brine on five shale samples with various total organic content (TOC) at various pressures (5–20 MPa) and at 343 K. The H₂ column height that can be securely trapped by the shale and capillary pressures were calculated. The shale's H₂ sealing capacity decreased with increasing pressure, increasing depth and TOC values. The CO₂/brine equilibrium contact angles were generally higher than H₂/brine equilibrium, suggesting that CO₂ could be used as favorable cushion gas to maintain formation pressure during UHS. The utmost height of H₂ that can be safely trapped by shale 3 (with TOC of 23.4 wt%) reduced from 8950 to 8750 M while that of shale 5 (with TOC of 0.081 wt%) reduced slightly from 9100 M to 9050 M as the pressure was increased from 5 to 20 MPa. The capillary entry pressure decreased with increasing depth and shale TOC, implying that the capillary trapping effect, as well as the over-pressure required to move brines from the pores by hydrogen displacement, reduces with increasing depth, and shale TOC. However, the shales remained at strongly water-wet conditions, having an equilibrium contact angles of not more than 17° at highest pressure and TOC. The study suggests that the increasing contact angles with increasing pressure and shale TOC, as well as decreasing column height and capillary pressure with increasing depth for H₂-brine-shale systems might not be sufficient to exert significant influence on structural trapping capacities of shale caprocks due to low densities of hydrogen.