Interfacial wettability evolution in underground hydrogen storage: Key factors, multiscale effects, and challenges.

Underground hydrogen storage (UHS) has attracted increasing attention as a promising technology for the large-scale storage of renewable energy resources and the decarbonization of energy systems. This study aimed to identify critical parameters influencing UHS performance, particularly the role of hydrogen conversion via in situ methanation and hydrogen recovery during production cycles. The main focus is the Lehen field in Upper Austria, where a pilot hydrogen storage project was conducted under the leadership of RAG Austria AG. A layered reservoir model was developed on the basis of well-log data to simulate the field trials that occurred in 2016. A sensitivity analysis was performed with the one-parameter-at-a-time (OPAAT) method and the response surface methodology (RSM) to evaluate the impacts of different parameters on hydrogen methanation and hydrogen recovery. The RSM results indicate the activation energy as the most influential factor on methanation that accounts for ∼20,000 moles variation in generated methane, significantly higher than the 6000 moles variance observed in OPAAT. However, initial CO2 content contributes up to 15,000 moles of methane generation as per RSM, whereas OPAAT results in a larger impact of up to 32,000 moles. These discrepancies demonstrate the limitations of isolated parameter analyses like OPAAT, which may not accurately capture the complex interactions between factors influencing the methanation process. This research provides valuable insights for optimizing UHS performance by emphasizing the influence of reservoir parameters on storage efficiency. In addition, a robust workflow for conducting comprehensive sensitivity analyses of UHS systems is established. By understanding these key factors, the potential and predictability of large-scale UHS systems can be significantly improved. • Large-scale underground hydrogen storage assessment in a depleted gas reservoir. • Sensitivity analysis of the methanation process in underground hydrogen storage. • Analysis of the one-parameter-at-a-time (OPAAT) method and the response surface methodology (RSM). • Real-world application from the Sun Storage project in Upper Austria. • Identification of critical parameters controlling the methanation process.

Underground hydrogen storage (UHS) has been launched as a catalyst to the low-carbon energy transitions. The limited understanding of the subsurface processes is a major obstacle for rapid and widespread UHS implementation. We use microfluidics to experimentally describe pore-scale multiphase hydrogen flow in an aquifer storage scenario. In a series of drainage-imbibition experiments we report the effect of capillary number on hydrogen saturations, displacement/trapping mechanisms, dissolution kinetics and contact angle hysteresis. We find that the hydrogen saturation after injection (drainage) increases with increasing capillary number. During hydrogen withdrawal (imbibition) two distinct mechanisms control the displacement and residual trapping – I1 and I2 imbibition mechanisms, respectively. Local hydrogen dissolution kinetics show dependency on injection rate and hydrogen cluster size. Dissolved global hydrogen concentration corresponds up to 28% of reported hydrogen solubility, indicating pore-scale non-equilibrium dissolution. Contact angles show hysteresis and vary between 17 and 56° Our results provide key UHS experimental data to improve understanding of hydrogen multiphase flow behaviour.

Feasibility evaluation of large-scale underground hydrogen storage in bedded salt rocks of China: A case study in Jiangsu province

Underground hydrogen storage in a partially depleted gas condensate reservoir: Influence of cushion gas

The development of large-scale, flexible, and safe hydrogen storage is critical for enabling a low-carbon energy system. Deep saline aquifers (DSAs) offer substantial theoretical capacity and broad geographic distribution, making them attractive options for underground hydrogen storage. However, hydrogen storage in DSAs presents complex technical, geochemical, microbial, geomechanical, and economic challenges that must be addressed to ensure efficiency, safety, and recoverability. This study synthesizes current knowledge on hydrogen behavior in DSAs, focusing on multiphase flow dynamics, capillary trapping, fingering phenomena, geochemical reactions, microbial consumption, cushion gas requirements, and operational constraints. Advanced numerical simulations and experimental observations highlight the role of reservoir heterogeneity, relative permeability hysteresis, buoyancy-driven migration, and redox-driven hydrogen loss in shaping storage performance. Economic analysis emphasizes the significant influence of cushion gas volumes and hydrogen recovery efficiency on the levelized cost of storage, while pilot studies reveal strategies for mitigating operational and geochemical risks. The findings underscore the importance of integrated, coupled-process modeling and comprehensive site characterization to optimize hydrogen storage design and operation. This work provides a roadmap for developing scalable, safe, and economically viable hydrogen storage in DSAs, bridging the gap between laboratory research, pilot demonstration, and commercial deployment.

Underground hydrogen storage has garnered interest in recent years owing to the considerable demand for clean energy. Hydrogen is more diffusive than air and has relatively low density and viscosity. These unique properties induce distinct hydrodynamic phenomena during hydrogen storage. Cushion gas has been proven to be a potential remedy for attenuating the adverse impacts of underground hydrogen storage. To investigate the influence of the cushion gas, a microscopic numerical simulation was performed with Fluent software using the Eulerian multi-fluid model. Carbon dioxide, nitrogen, and methane are usually used as the preferred candidates for cushion gases in underground hydrogen storage systems. In this study, nitrogen was used as the cushion gas and was injected along with hydrogen into heterogeneous porous media with volume fractions ranging from 0% to 70%. A parameterization study was then performed to elucidate the influences of the injection rate and viscosity of the fluid on the fingering pattern. Two representative types of fingering, viscous fingering and capillary fingering, were observed under different gas mixtures and boundary conditions. After the simulation, an image analysis was performed to capture the evolution of the fingering pattern. The specific fingering area, number of branches, and fractal dimensions are proposed as geometric indices to describe the shape of the fingering pattern. The results showed that there was a remarkable enhancement in saturation due to the injection of the cushion gas, depending on the concentration of the gas mixture. This study offers insight on the design of gas mixture injection in underground hydrogen storage and can be further extended to the hydrochemo–mechanical coupled numerical simulation of multiphase gas injection in porous media.

<p>The Netherlands is seeking ways to integrate large amounts of renewable energy production capacity (wind/solar) into its energy system, in order to reduce CO<sub>2</sub> emissions and decrease dependency on future energy imports. Currently the Netherlands uses underground gas storage (UGS) to provide flexibility to its natural gas system, and secure supply during the winter season. However, hydrogen is considered to be a potential candidate to substitute natural gas, because it is a versatile energy carrier that can be produced from renewable electricity and be used as a CO<sub>2</sub>-neutral fuel and feedstock. It can also be stored in large amounts underground. Storage of compressed hydrogen in salt caverns is a proven technology, with single-cavern storage capacities in the range of 10-100 million m<sup>3</sup>. Yet some studies on the future Dutch energy system suggest much larger volumes of hydrogen storage may be required (1 to 50 billion m<sup>3</sup>). This large storage capacity can only be practically achieved in depleted natural gas fields. UHS in gas fields is not yet a proven technology. Only some pilot projects have successfully injected small amounts of hydrogen in some available underground reservoirs. In order to make possible future development of UHS, screening methodologies are needed for the readily identification and characterization of potential underground candidates. In this study, we develop a methodology that allows assessing UHS performances of large portfolios of underground reservoirs. As a case study we use the entire portfolio of natural gas fields in the Netherlands, including three UGSs.</p><p>In a first stage of our study, we conducted a nodal analysis of the Inflow Performance Relationship (IPR) and the vertical flow performance (outflow) curves, in order to obtain a first order estimate of the potential UHS performance for each field (e.g. rates of injection/withdrawal, working/cushion gas volumes and ranges of working pressures). Results show that withdrawal performances of wells in an UHS can be 2-3 times higher than those in an UGS. High bottom-hole drawdowns and erosional velocities in the production tubing may however significantly restrict the potential flow of hydrogen. Furthermore, the working gas volume of an UHS may contain up to four times less energy than that of an UGS, if operated at the same ranges of working pressures. Secondly, we used Eclipse 300, and the geological Petrel model of some of the best candidates, to conduct a more detail analysis of their potential UHS performances and the controlling factors. For that we ran consecutive injection/withdrawal cycles at different timescales (daily-weekly-monthly), and distinct working pressure ranges and types of cushion gas (e.g. nitrogen/hydrogen). Results allow to determine the efficiency of the different operational strategies and the number of wells required to match the expected future demands of hydrogen in the Netherlands. They also show the degree of hydrogen mixing with the residual and cushion gas during each cycle. Therefore our analytical/numerical modelling approach provides a good methodology to quantify and rank potential UHS reservoir candidates, and a means to classify the potential storage capacity of the entire portfolio.</p>

The hydrogen industry has been progressing towards increasing hydrogen transport in recent years. With the drive toward increasing hydrogen transportation, hydrogen embrittlement and parameters impacting the process have been scrutinized. While in smaller scale hydrogen projects, long-term hydrogen storage has not been a primary concern, the large-scale deployment of hydrogen demands safe and efficient long-term and high-volume storage options. Therefore, geological reservoirs, including depleted oil and gas fields have been considered for large-scale underground hydrogen storage (UHS) as they have been safely used for CH4 storage for decades. However, microbial activities in UHS are more significant compared to that of CH4 considering that molecular hydrogen is one of the main electron donors for microbial respiration in the subsurface. This demands an understanding of the subsurface microbial biosphere as well as those contaminants absorbed from the reservoir and introduced during drilling, pumping and mining. This contamination can have adverse impacts on the material integrity of both the downhole equipment as well as the above ground transport network for transporting back produced hydrogen. Since selecting resistant materials is not always economically viable, mitigation strategies – including appropriate purification processes – are likely essential for hydrogen repurposing projects. This paper discusses different impurities and how they contribute to a corrosive environment endangering material integrity of the network through a potential synergistic effect with hydrogen embrittlement. Additionally, the potential purification process that can be employed to minimize such impacts will be discussed.

Hydrogen Fueling Infrastructure Research and Station Technology (H2FIRST) is a project initiated by the DOE in 2015 and executed by Sandia National Laboratories and the National Renewable Energy Laboratory to address R&D barriers to the deployment of hydrogen fueling infrastructure. One key barrier to the deployment of fueling stations is the land area they require (i.e. "footprint"). Space is particularly a constraint in dense urban areas where hydrogen demand is high but space for fueling stations is limited. This work presents current fire code requirements that inform station footprint, then identifies and quantifies opportunities to reduce footprint without altering the safety profile of fueling stations. Opportunities analyzed include potential new methods of hydrogen delivery, as well as alternative placements of station technologies (i.e. rooftop/underground fuel storage). As interest in heavy-duty fueling stations and other markets for hydrogen grows, this study can inform techniques to reduce the footprint of heavy-duty stations as well. This work characterizes generic designs for stations with a capacity of 600 kg/day hydrogen dispensed and 4 dispenser hoses. Three base case designs (delivered gas, delivered liquid, and on-site electrolysis production) have been modified in 5 different ways to study the impacts of recently released fire code changes, colocation with gasoline refueling, alternate delivery assumptions, underground storage of hydrogen, and rooftop storage of hydrogen, resulting in a total of 32 different station designs. The footprints of the base case stations range from 13,000 to 21,000 ft2 . A significant focus of this study is the NFPA 2 requirements, especially the prescribed setback distances for bulk gaseous or liquid hydrogen storage. While the prescribed distances are large in some cases, these setback distances are found to have a nuanced impact on station lot size; considerations of the delivery truck path, traffic flow, parking, and convenience store location are also important. Station designs that utilize underground and rooftop storage can reduce footprint but may not be practical or economical. For example, burying hydrogen storage tanks underground can reduce footprint, but the cost savings they enable depend on the cost of burial and the cost land. Siting and economic analysis of station lot sizes illustrate the benefit of smaller station footprints in the flexibility and cost savings they can provide. This study can be used as a reference that provides examples of the key design differences that fueling stations can incorporate, the approximate sizes of generic station lots, and considerations that might be unique to particular designs.

Underground hydrogen storage in geological formations: A review

Off-grid hydrogen supply from solar or wind sources to hydrogen-based steelmaking can reduce CO₂ emissions. However, the techno-economic feasibility of different supply chain configurations remains uncertain. This study evaluates 61 off-grid hydrogen supply chains for a 15 Mt. steel/year plant in 2030, considering renewable energy sources (onshore/offshore wind, solar, and overseas options), transmission technologies (cables, pipelines, trucks, and ships), storage technologies (compressed gaseous hydrogen, liquid hydrogen, ammonia, methanol, and liquid organic hydrogen carriers), and seasonal storage locations (at the energy source or steelmaking plant). Onshore truck transmission of hydrogen is found to be unpromising due to the significantly higher cost compared to alternative transmission technologies. When the transmission technology is not truck, chains with underground compressed hydrogen storage achieve the lowest levelized cost of hydrogen (LCOH) at 3.8–5.6 € 2020 /kg H₂, outperforming other options. When underground hydrogen storage is not feasible, liquid organic hydrogen carriers present the next lowest cost. Chains utilizing ammonia, methanol, and liquid hydrogen exhibit lower efficiency, higher renewables capacity requirement, and consequently higher LCOH, making them less attractive. Electricity transmission lowers the LCOH of compressed hydrogen chains compared to hydrogen pipeline transmission, but for other chains the trend is reversed. Hydrogen storage near the steelmaking plant reduces costs by enabling the reuse of boil-off hydrogen in liquid hydrogen chains, but for other chains storing hydrogen near the renewable energy source lowers the cost. Impacts of input uncertainties on the LCOH, limitations of this study, and suggestions for future studies are also presented. • Techno-economic evaluation of 61 off-grid hydrogen supply chains for steelmaking. • Compressed hydrogen chains with underground storage have the lowest cost. • Liquid organic hydrogen carrier chains have the second lowest cost. • Methanol- or ammonia-based chains are not cost-effective due to low efficiency. • Storage should be near demand in liquid hydrogen chains but near supply in other chains.

In response to Governor Brown’s January 2016 state of emergency proclamation regarding the Aliso Canyon gas leak, SB 826 (Leno, 2016) requested that the California Council on Science and Technology (CCST) provide the State with up-to-date information on all currently operating underground natural gas storage fields in California. CCST was instructed to provide an independent technical assessment answering three key questions about: The risks California’s underground gas storage facilities pose to health, safety, environment, and infrastructure; Whether California needs underground gas storage to provide for energy reliability through 2020; and How implementation of California’s climate policies changes the future need for underground gas storage. From a statewide field of leading energy researchers, CCST selected Jens T. Birkholzer, PhD, and Jane C.S. Long, PhD, to serve as co-chairs of the 12-member CCST Report Steering Committee – which supervised 21 Report Authors with expertise spanning hydrogeology and reservoir engineering, risk assessment, public and occupational health, greenhouse gas (GHG) emissions, and energy analysis and economics. Each report chapter was subject to a peer review process by independent experts, while another independent expert served as Report Monitor to oversee the process, ensuring that peer review comments were sufficiently addressed in the final report. An additional Oversight Committee reviewed the entire process, including conflict-of-interest declarations. The report’s findings and conclusions are based on a review of published literature and official and voluntary databases, which the Report Authors compiled between January through September 2017, and delivered to the California Public Utilities Commission in January 2018. Key findings and conclusions include: Safety: The risks associated with underground storage (UGS) facilities can be managed, and, with appropriate regulation and safety management, may become comparable to risks in other types of energy facilities found acceptable in California, such as oil refineries and natural gas power plants. At each UGS facility, the State should ensure timely and thorough implementation of the new regulations coming into force in 2018 set by the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR). Those regulations emphasize new and safer well completions, risk and safety management plans, and requirements for well integrity testing and monitoring. The report recommends that the State go further and require more quantitative risk assessment activities, including consideration of human and organizational factors affecting risk. The State should also implement an independent and mandatory review program to evaluate the effectiveness of these new regulations and the rigor of their application in practice, with opportunity for public comment and public dissemination of the review results. Facility-by-Facility Evaluation: Any industrial operation involves some risk to health, safety, and environment. This report assessed various risk-related characteristics across UGS facilities in California, and found a small list of facilities had relatively higher potential risk compared to others. Reliability of Natural Gas Supply: California’s energy system currently requires natural gas and UGS facilities to run reliably, primarily because many residential and commercial buildings in California rely on natural gas for heating during the winter, and because natural gas provides electricity when solar and wind power are not available. The peak demand for natural gas during the winter currently exceeds the ability of pipelines to bring natural gas into the State of California, so natural gas must be stored during periods of low demand in order to have it available to meet peak demand. Near-Term Alternatives to UGS: Closing any or all UGS facilities in the near term would involve replacing UGS facilities with new pipelines or natural gas storage capacity, and require very large investments. Such new natural-gas-related infrastructure would bring its own risks and would further obligate the State to the use of natural gas for decades. The risks, costs, and benefits associated with alternatives to UGS storage should be evaluated accordingly. Long-Term Need for Underground Gas Storage: California’s climate policies in future decades could still necessitate the continued use of natural gas. Also, energy systems that meet the climate goals may require underground storage of natural gas, biogas, or hydrogen, as well as sequestration of carbon dioxide. The State should develop a more complete and integrated plan to understand how the role of natural gas might evolve; assess possible energy portfolios that both meet GHG emission constraints and achieve energy reliability; and consider the potential need for UGS facilities in the future.

To utilize the full potential of hydrogen energy in the UK a number of economic, technical and environmental factors must be considered. An important factor in replacing fossil fuels with hydrogen will be the practicality of storing a sufficient quantity to smooth out fluctuations in demand and provide a strategic reserve. This paper investigates the potential for large-scale underground hydrogen storage in the UK by considering the technical, geological and physical issues of storage, the locations of salt deposits, legal and economic aspects. In addition, reference is made to the equations of state applicable to this type of storage. The results of this investigation show that the UK has a number of potential locations where underground storage would provide a strategic reserve of hydrogen.

The global energy system is transitioning to low-carbon solutions, with an increasing proportion of renewable energy sources. The intermittency of renewable energy generation, e.g. from wind and solar power, however, leads to a rising demand for large-scale and seasonal energy storage. Hydrogen is regarded as a vital energy carrier, and underground hydrogen storage (UHS) in porous geological media is considered a promising option due to its substantial storage capacity, relatively low cost, and potential safety benefits. Nonetheless, hydrogen leakage through caprock formations and hydrogen–rock–brine interactions remain critical uncertainties that require further research.This study aims to investigate the impact of hydrogen injection on the sealing integrity of shale caprocks. High-pressure, constant-temperature batch reactor tests are employed to simulate gas–brine–rock interactions under reservoir-relevant conditions. Shale samples with three distinct mineralogical compositions (carbonate-, pyrite-, and clay mineral-rich) are selected to represent different types of caprock lithologies. Experiments are conducted using various gas compositions, including hydrogen and potential cushion gases, to evaluate how mineralogical heterogeneity influences geochemical reactions and caprock performance.The ongoing experiments aim to identify the most suitable (i.e. hydrochemically stable) caprock composition for underground hydrogen storage, as well as gas compositions that are more favorable as cushion gases to enhance storage safety. The results are expected to provide insights into caprock stability and sealing behavior during future hydrogen storage operations.

While the share of renewable energy sources increased within the last years with an ongoing upward trend, the energy sector is facing the problem of storing large amounts of electrical energy properly. To compensate daily and seasonal fluctuations, a sufficient storage system has to be developed. The storage of hydrogen in the subsurface, referred to as Underground Hydrogen Storage (UHS), shows potential to be a solution for this problem. Hydrogen, produced from excess energy via electrolysis, is injected into a subsurface reservoir and withdrawn when required. As hydrogen possesses unique thermodynamic properties, many commonly used correlations can not be simply transferred to a system with a high hydrogen content. Mixing processes with the present fluids are essential to be understood to achieve high storage efficiencies. Additionally, in the past, microbial activity, e.g. by methanogenic archaea, was observed, leading to a changing fluid composition over time. To evaluate the capability of reservoir simulators to cover these processes, the present study establishes a benchmark scenario of an exemplary underground hydrogen storage scenario. The benchmark comprises of a generic sandstone gas reservoir and a typical gas storage schedule is defined. Based on this benchmark, the present study assesses the capabilities of the commercial simulator Schlumberger ECLIPSE and the open-source simulator DuMux to mimic UHS related processes such as hydrodynamics but also microbial activity. While ECLIPSE offers a reasonable mix of user-friendliness and computation time, DuMux allows for a better adjustment of correlations and the implementation of biochemical reactions. The corresponding input data (ECLIPSE format) and relevant results are provided in a repository to allow this simulation study’s reproduction and extension.