Characterization and simulation of underground hydrogen storage across scales

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

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.

ABSTRACT: Real-time continuous monitoring provides high-resolution spatial and temporal data for tracking fluid migration. In this study, we numerically investigate the temperature, pressure, strain and displacement responses in potential monitoring wells locations during cyclic hydrogen injection into saline aquifers. A coupled thermohydromechanical flow model was used to mimic the injection and withdrawal of hydrogen. Potential locations for injection and monitoring wells are mapped. The primary focus of the analysis was to determine the temperature, pressure, strain and displacement responses and what they could inform about hydrogen distribution. The study shows that pressure, temperature, displacement and seismicity are key parameters to track the cyclic behavior of hydrogen in the subsurface. The recommended locations for such measurements include for Pressure, Temperature, and Displacement, monitoring tools are best placed at the above-storage reservoir. For Strain, and induced seismicity – in or near the storage reservoir. These insights have practical implications for the design of monitoring wells equipped with monitoring sensors and for enhancing data interpretation practices. 1. INTRODUCTION Underground hydrogen storage in porous media has the potential to complement renewable energy resources by storing excess energy from these resources during low demand and releasing the energy during peak demand. Hydrogen can be produced via electrolysis. Excess energy can be stored as hydrogen in geological media like salt caverns or porous media. However, there are few experiences with hydrogen storage in porous media (summarized in Zivar et al., 2021), and the few cases are not hydrogen stored with 100% purity. There have been instances of the application of numerical modeling to understand the behavior of hydrogen in porous media (summarized in Okoroafor et al., 2023), but few of these works discuss or capture the geomechanical implications of hydrogen storage in porous media. The storage integrity of underground hydrogen storage in porous media remains a critical concern, especially regarding potential losses during the cyclical processes of hydrogen injection and withdrawal. Current understanding lacks insights into the geomechanical implications of hydrogen storage in porous media, making it imperative to address this gap. Thus, the primary objective of this study is to investigate and enhance storage integrity during hydrogen storage within porous media. Specifically, the study aims to anticipate and mitigate potential integrity issues by analyzing various parameters, including pressure, temperature, displacement, strain, stress, and fluid composition, throughout different hydrogen storage and withdrawal phases.

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.

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>

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.

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.

Underground hydrogen storage (UHS) plays a critical role in ensuring the stability and security of the future clean energy supply. However, the efficiency and reliability of UHS technology depend heavily on the careful and criteria-driven selection of suitable storage sites. This study presents a hybrid multi-criteria decision-making framework integrating the Analytical Hierarchy Process (AHP) and Preference Ranking Organisation Method for Enrichment of Evaluations (PROMETHEE) to identify and select the best hydrogen storage sites among depleted gas reservoirs in the UK. To achieve this, a new set of site selection criteria is proposed in light of the technical and economic aspects of UHS, including location, reservoir rock quality and tectonic characteristics, maximum achievable hydrogen well deliverability rate, working gas capacity, cushion gas volume requirement, distance to future potential hydrogen clusters, and access to intermittent renewable energy sources (RESs). The framework is implemented to rank 71 reservoirs based on their potential and suitability for UHS. Firstly, the reservoirs are thoroughly evaluated for each proposed criterion and then the AHP-PROMETHEE technique is employed to prioritise the criteria and rank the storage sites. The study reveals that the total calculated working gas capacity based on single-well plateau withdrawal rates is around 881 TWh across all evaluated reservoirs. The maximum well deliverability rates for hydrogen withdrawal are found to vary considerably among the sites; however, 22 % are estimated to have deliverability rates exceeding 100 sm3/d, and 63 % are located within a distance of 100 km from a major hydrogen cluster. Moreover, 70 % have access to nearby RESs developments, with an estimated cumulative RESs capacity of approximately 181 GW. The results highlight the efficacy of the proposed multi-criteria site selection framework. The top five highest-ranked sites for UHS based on the evaluated criteria are the Cygnus, Hamilton, Saltfleetby, Corvette, and Hatfield Moors gas fields. The insights provided by this study can contribute to informed decision-making, sustainable development, and the overall progress of future UHS projects within the UK and globally.

Hydrogen is expected to play a significant role in the process of decarbonizing the global energy sector where Underground Hydrogen Storage (UHS) may be the only option for large-scale seasonal energy storage. Studies conducted so far to investigate the economic feasibility of UHS in porous reservoirs focus on the levelized cost of energy (LCOE) while the other economic indicators are left unattended. To better assess the techno-economic feasibility of UHS, we built a knowledge-based net cash flow model to estimate the net present value (NPV) and internal rate of return (IRR) of UHS projects under different hydrogen price assumptions. Specifically, we incorporate expected green and blue hydrogen prices by 2030 in Australia into our model to evaluate the resulting project economic performance. Our model calculated net cash flows illustrate the inherent technical and economic disadvantages of UHS in Australia compared to alternative technologies such as underground gas storage (UGS). Under current expectations, both the storage of hydrogen-methane mixtures and pure hydrogen cannot make considerable economic profits without policy support in the near future. The commercialization of UHS is in need of support measures such as an Australian carbon credit unit (ACCS) of at least $18.17 AUD.

Underground hydrogen storage, compared to surface storage, offers a higher capacity, provides long-term storage, and requires fewer surface installations. Underground hydrogen storage site selection is affected by various factors, including availability of energy sources to produce hydrogen from fossil fuels and renewables, energy consumption in a specific area, accessibility to the existing infrastructure, and availability of underground storage media. These factors vary in different locations. Wyoming, as the second largest energy supplier in the U.S., has a significant share of the influencing factors. This study ranks Wyoming counties based on fossil fuels supply, renewables, energy consumption, and underground storage facilities as well as different type of media for storage such as depleted hydrocarbon reservoirs, abandoned coal mines, and potential trona caverns. Depending on the preferred factors, different counties can be prioritized for underground hydrogen storage site selection. This study is beneficial for storage site selection in Wyoming; however, individual sites should be further investigated for optimal site selection.

The technical and economic feasibility of storing hydrogen in underground storage reservoirs is evaluated. The past and present technology of storing gases, primarily natural gas is reviewed. Four types of reservoirs are examined: salt caverns, excavated caverns, aquifers, and depleted fields. A technical investigation of hydrogen properties reveals that only hydrogen embrittlement places a limit on the underground storage by hydrogen. This constraint will limit reservoir pressures to 1200 psi or less. A model was developed to determine economic feasibility. After making reasonable assumptions that a utility might make in determining whether to proceed with a new storage operation, the model was tested and verified on natural gas storage. A parameteric analysis was made on some of the input parameters of the model to determine the sensitivity of the cost of service to them. Once the model was verified it was used to compute the cost of service of storing hydrogen in the four reservoir types. The costs of service for hydrogen storage ranged from 26 to 150% of the cost of the gas stored. The study concludes that it is now both safe and economic to store hydrogen in underground reservoirs.

Underground hydrogen storage in geological formations: A review

ABSTRACT: Hydrogen is gaining traction on a global scale as a future low-carbon energy carrier. Underground Hydrogen Storage (UHS) is critical to successfully implementing the hydrogen economy. UHS requires many lab-scale and large-scale studies to understand the behavior of hydrogen in the subsurface before they can be incorporated into the energy system. So far, most of the experimental investigations conducted on UHS focus on the microbial, hydrogeological, and geochemical effects of hydrogen storage in the subsurface. However, studies focused on the geomechanical effects are scarce. In this work, eight Berea sandstone cores were exposed to brine, pure hydrogen, and hydrogen in the presence of brine for 90 days at reservoir conditions of 10 MPa and 60°C to study the geomechanical effects of hydrogen on the samples. Tests for the Berea sandstone's properties for petrophysical (permeability and porosity) and geomechanical (strength, Young's modulus, and Poisson's ratio) properties. The results demonstrate that long-term interactions with hydrogen cause changes in all the properties of the cores. The results also demonstrate changes in the geomechanical properties of the reservoir after three months of hydrogen exposure, which has not been extensively studied, and the results can be used in simulation, site selection, and risk assessment studies. 1. INTRODUCTION Renewable energy production is viewed as an alternative to environmentally detrimental fossil fuel energies (coal, oil, and natural gas), contributing to global net-zero carbon emissions by 2050(Perera, 2023; Ugarte et al., 2023). According to a study by the International Renewable Energy Agency (IRENA), renewable energy will become the primary energy source, increasing worldwide share from 16% in 2020 to 77% by 2050 (IRENA, 2023). While there is a rising global interest in renewable energy, wind and solar energy have limitations: they depend on unpredictable factors such as weather. Renewable energy's intermittent generation creates a supply-demand imbalance, making renewable energies unreliable since they cannot maintain a continuous supply (Abdellatif et al., 2023; Heinemann et al., 2021; Kanaani & Sedaee, 2022; Muhammed et al., 2022; P. & P.G., 2023). To balance supply and demand, surplus energy from wind and solar energies can be converted to hydrogen through electrolysis, stored in the energy storage system, and subsequently utilized when demand arises (Okoroafor et al., 2022; Zamehrian & Sedaee, 2022).