Study on Hydrogen Seepage Laws in Tree-Shaped Reservoir Fractures of the Storage Formation of Underground Hydrogen Storage in Depleted Oil and Gas Reservoirs Considering Slip Effects

ABSTRACT: Hydrogen has been identified as a key component of the clean energy economy value-chain, whose global demand is expected to significantly increase. To meet this demand, a large storage capacity is required, with underground hydrogen storage (UHS) in depleted oil and gas reservoirs projected to provide this capacity. To consider UHS in depleted reservoirs, an effective seal that overlays the reservoir rocks is necessary to prevent loss of hydrogen through leakage. Shale caprocks are recognized as effective seals which have held natural gas in place for geologic time-periods. Limited studies in the past have shown alteration of caprock properties during UHS operations. However, these studies made observations before hydrogen exposure and only one timepoint after extended duration of hydrogen exposure. Work presented here investigates how hydrogen-shale interactions alter the porosity and matrix permeability of the Marcellus shale. Experiments were carried out at 6.9 MPa pressure, which included multiple durations of hydrogen exposure. After each exposure, the porosity and matrix permeability were measured. Unprecedently, results indicated an increase in the porosity and matrix permeability due to continued hydrogen exposure. This change in pore-structure is expected to be physical in nature, driven by possible micro-fracturing at grain boundaries. 1. INTRODUCTION AND BACKGROUND Amidst the rapid global population growth and urbanization, the rising demand for energy requires a strategic shift towards cleaner energy sources, particularly as the world steers towards achieving sustainable climate goals (Dincer, 2000). Driven by their intrinsically low carbon footprint, renewable sources of energy, such as solar and wind energy are rapidly gaining traction as potential clean energy sources (Levin & Chahine, 2010). Their minimal greenhouse gas emissions offer a significant advantage in addressing the pressing challenge of climate change (Agreement, 2015). However, the inconsistent nature of renewable energy production, driven by weather and geographical factors, creates a critical bottleneck in achieving a sustainable energy future due to the mismatch between supply and demand. This necessitates the development of cost-effective and environmentally friendly energy storage solutions to bridge the gap between excess energy generation and periods of peak demand (Lehtveer et al., 2017). One promising practical solution is to convert the excess energy generated into hydrogen, an efficient and versatile energy carrier that can be stored and utilized on demand. This approach leverages diverse hydrogen production pathways, including thermochemical, electrolytic, biological, and direct solar water splitting, offering flexibility and scalability (Das & Veziroǧlu, 2001; van der Roest et al., 2020; Wang et al., 2012). Despite advancements in hydrogen production technologies, the lack of scalable, long-term storage solutions constitutes a major roadblock (Zhang et al., 2016). Existing methods, encompassing high-pressure tanks, cryogenic storage, and material adsorption, are inherently limited in capacity, and are relatively unsafe (Abdalla et al., 2018; Jain et al., 2013). Underground geological formations, including depleted oil and gas reservoirs, aquifers, and engineered caverns, present the only viable option for accommodating the vast volumes required for grid stabilization and seasonal demand buffering (Tarkowski, 2019). Implementing widespread underground hydrogen storage (UHS) is therefore paramount for unlocking the full potential of renewable energy in transitioning to a sustainable energy future.

Hydrogen-water-rock interaction from the perspective of underground hydrogen storage: Micromechanical properties and mineral content of rock

The is wide consensus that combustion of fossil fuels and rising greenhouse gas emissions in the atmosphere are accelerating global warming. To avoid the dilemma of need for fossil fuels to provide energy supply and the need to reduce fossil fuel related emissions, it is critical to promote renewable energy as a viable option to satisfy the world's energy requirements. However, employing renewables to generate power necessitates the use of bulk storage to accommodate discrepancies related to where and when renewable energy is produced versus where and when it is needed. Underground hydrogen storage has the potential to support establishment of hydrogen as a reliable source of clean energy across the planet. Where present, depleted oil and gas reservoirs, due to their existing infrastructure, can prove to be an attractive asset for underground hydrogen storage. One of the main challenges involved in the storage of hydrogen in the depleted oil and gas reservoirs is related to wellbore integrity. When hydrogen is injected or produced in the subsurface, it may get bin contact with cement around the wellbores. Hence it is necessary to investigate the effects of hydrogen interacting with the cement sheath. To study this in the laboratory, a core holder capable of simulating the wellbore conditions is used to conduct the tests. A 2" long, 1.5" diameter cement sample was placed inside the core holder and hydrogen was injected into it. Hydrogen was also injected into wet cement slurry to investigate possible stability of the cement samples. The effects of injecting hydrogen on set cement are studied using a CT Scanner which demonstrates if there is any formation of cracks and micro-annuli in the cement. The cement sample is crushed afterwards, and the presence of hydrogen particles in the structure of cement is evaluated by X -Ray Diffraction. A neat 15.5 lbs./gal Class "H" cement which is common in the industry is used in this study. Well integrity is a key success factor to establish the viability of underground hydrogen storage in the subsurface. For that we analyzed if the cement is good enough for hydrogen to be stored in depleted oil and gas reservoirs. We further studied the integrity of newly drilled wells when exposed to hydrogen.

The utilization of depleted hydrocarbon reservoirs for Underground Hydrogen Storage (UHS) presents a promising and competitive solution for addressing large-scale hydrogen storage challenges. By repurposing existing infrastructure, UHS can provide a cost-effective and sustainable approach to integrating hydrogen storage within the energy sector. This study aims to identify and quantify the dominant trapping mechanisms that contribute to hydrogen loss during UHS, offering insights for optimizing deployment and ensuring efficient integration into the energy landscape. To achieve this objective, a real-field geological model of a depleted sandstone gas reservoir with a shale cap rock was employed. The Peng Robinson equation of state as well as the viscosity and solubility models were tuned using published hydrogen properties. Recent relative permeability, capillary pressure, and hysteresis data from the literature were also integrated into the simulations to capture the reservoir's dynamic behavior during hydrogen injection, storage, and withdrawal processes. The mechanisms examined include hydrogen residual trapping and hysteresis, diffusion in water and the formation, solubility trapping, geochemical reactions, and the impact of salinity, all of which can influence hydrogen retention and recovery efficiency. The results of this comprehensive analysis revealed that residual trapping was the most dominant mechanism, accounting for majority of the hydrogen loss. This finding emphasizes the need for precise relative permeability data to accurately model and predict reservoir performance during UHS. The geochemical loss was found to be highly dependent on rock composition, with negligible impact in sandstone reservoirs. Furthermore, diffusion in the fluid and the formation contributed to less than 3% of the total hydrogen loss, while the impact of solubility trapping was minimal. This study presents an analysis of dominant trapping mechanisms during Underground Hydrogen Storage in depleted gas reservoirs within a real-field geological model. What differentiates this study is the systematic incorporation of all loss mechanisms using a tunned fluid model, providing engineers with a more holistic understanding of UHS. The findings offer practical insights into how these factors can be optimized for improved hydrogen retention and recovery efficiency. This research is pivotal for engineers seeking data-driven methodologies and best practices in UHS. By delivering actionable knowledge, this study supports the integration of hydrogen storage into the existing hydrocarbon infrastructure, contributing to the development of a sustainable energy sector.

ABSTRACT: The transition to renewable energy systems necessitates large-scale hydrogen storage solutions, with depleted oil and gas reservoirs emerging as promising candidates. This study investigates the geomechanical effects of underground hydrogen storage (UHS) on reservoir rocks and caprocks from the Madison Formation in North Dakota. Core samples were subjected to hydrogen exposure under realistic reservoir conditions (1600 psi, 200°C) over 30-day periods. Comprehensive analyses of mechanical and petrophysical properties revealed distinct responses between carbonate reservoir rocks and anhydrite caprocks. Carbonate samples exhibited increased porosity (0.74-5.79%) and permeability (4.32-8.70%), alongside decreased Young's modulus (2.10-3.67%) and increased Poisson's ratio (5.16-6.85%). Conversely, anhydrite caprocks showed more stable behavior with modest increases in Young's modulus (1.32-2.28%) and smaller changes in Poisson's ratio (2.69-3.66%). These findings indicate that while hydrogen exposure may weaken carbonate reservoir rocks, anhydrite caprocks maintain their sealing integrity. The study provides crucial insights for UHS implementation, highlighting the importance of rock-specific responses in storage system design and risk assessment. The results contribute to the development of safety protocols and optimization strategies for large-scale hydrogen storage in depleted reservoirs. These findings provide crucial insights into the geomechanical processes that occur during UHS and their potential impacts on the integrity of hydrogen storage in the depleted oil and gas reservoirs. This study underscores the importance of detailed geomechanical analysis for UHS and offers a comprehensive methodological framework for future investigations in similar geological settings.

Key aspects of underground hydrogen storage in depleted hydrocarbon reservoirs and saline aquifers: A review and understanding

As hydrogen assumes an increasingly strategic role in the global energy transition, the development of efficient, safe, and cost‐effective large‐scale hydrogen storage systems has become a critical enabler for the hydrogen economy. Underground hydrogen storage (UHS), particularly in depleted oil and gas reservoirs, is gaining traction as a promising solution for seasonal energy balancing and the integration of intermittent renewable energy sources. This review provides a comprehensive synthesis of current international progress in pilot projects, experimental investigations, and numerical simulations related to UHS in depleted reservoirs. Key scientific challenges are examined, including reservoir suitability, caprock integrity, wellbore sealing performance, material durability, and coupled geochemical–microbial processes. Hydrogen’s high diffusivity, mobility, and chemical reactivity present unique risks in the subsurface, thereby increasing the likelihood of leakage and reservoir destabilization. To date, no commercial‐scale project has successfully demonstrated pure hydrogen storage in depleted reservoirs, and most current studies remain at the modeling or laboratory scales, lacking standardized risk assessment protocols and monitoring frameworks. This review provides critical insights for assessing the feasibility of UHS in depleted reservoirs and underscores the urgent need for integrated research on coupled hydro‐biogeochemical‐mechanical processes, hydrogen‐compatible materials, site selection criteria, and long‐term monitoring technologies.

The transition to a sustainable energy future hinges on the development of reliable large-scale hydrogen storage solutions to balance the intermittency of renewable energy and decarbonize hard-to-abate industries. Underground hydrogen storage (UHS) in salt caverns emerged as a technically and economically viable strategy, leveraging the unique geomechanical properties of salt formations—including low permeability, self-healing capabilities, and chemical inertness—to ensure safe and high-purity hydrogen storage under cyclic loading conditions. This review provides a comprehensive analysis of the advantages of salt cavern hydrogen storage, such as rapid injection and extraction capabilities, cost-effectiveness compared to other storage methods (e.g., hydrogen storage in depleted oil and gas reservoirs, aquifers, and aboveground tanks), and minimal environmental impact. It also addresses critical challenges, including hydrogen embrittlement, microbial activity, and regulatory fragmentation. Through global case studies, best operational practices for risk mitigation in real-world applications are highlighted, such as adaptive solution mining techniques and microbial monitoring. Focusing on China’s regional potential, this study evaluates the hydrogen storage feasibility of stratified salt areas such as Jiangsu Jintan, Hubei Yunying, and Henan Pingdingshan. By integrating technological innovation, policy coordination, and cross-sector collaboration, salt cavern hydrogen storage is poised to play a pivotal role in realizing a resilient hydrogen economy, bridging the gap between renewable energy production and industrial decarbonization.

This study examines the geomechanical effects of depleted oil and gas reservoir rocks during underground hydrogen storage (UHS), with a specific focus on the Red River Formation in North Dakota. As the transition to renewable energy sources accelerates, hydrogen storage in geological formations presents a promising solution for large-scale energy storage. However, numerous challenges and barriers exist that prevent this technology from becoming a widely available decarbonization solution. The UHS process comprises multiple cycles of injection and withdrawal. These cycles may elevate the risk of fracturing or seal integrity failure in certain reservoirs. Furthermore, it is crucial to assess the potential alteration of rocks caused by hydrogen exposure to understand its impact on the mechanical properties of the reservoir rock and caprock. This study investigates the effect of geomechanical change in the mechanical and petrophysical properties of reservoir rock and caprock rocks (Carbonate + Anhydrite), crucial factors for securing subsurface hydrogen containment. Core samples from three wells in the Red River Formation's Zone B were subjected to high-pressure, high-temperature (HPHT) conditions simulating underground storage environments, including 30-day hydrogen exposure at 2000 psi and 140°C. Advanced analytical techniques including Nuclear Magnetic Resonance (NMR) porosity measurements, pulse-decay permeability analysis, and ultrasonic velocity measurements were employed to assess geomechanical changes before and after hydrogen exposure. The results revealed distinct lithological control on hydrogen-rock interactions with favorable implications for storage integrity. Carbonate reservoir samples demonstrated systematic porosity increases ranging from 9.7% to 23.1%, with corresponding permeability enhancements of 12.7% to 25.8%. Despite these petrophysical changes, mechanical properties showed improvement, with dynamic Young's modulus increasing by 1.7% to 11.4% and compressional wave velocities enhancing by 8.6% to 30.1%. Poisson's ratio increased by 3.6% to 13.7%, indicating altered deformation characteristics that remain within acceptable operational ranges. Anhydrite caprock samples exhibited exceptional stability and enhanced sealing capacity under hydrogen exposure. Porosity changes were negligible (±2%), while permeability remained ultra-low with minimal variations (±4.5%). Remarkably, caprock mechanical properties showed significant strengthening, with Young's modulus increasing by 10.4% to 18.3% and compressional wave velocities improving by up to 22.1%. These enhancements indicate improved structural integrity and resistance to deformation under operational pressures. The systematic mechanical property improvements in both reservoir and caprock formations create a geomechanically favorable environment for hydrogen storage operations. These findings advance the understanding of geomechanical processes in UHS and provide crucial insights supporting the safe and efficient implementation of hydrogen storage in depleted carbonate reservoirs with anhydrite seals, particularly in similar geological settings throughout the Williston Basin.

Climate change, and the contribution of greenhouse gases like carbon dioxide and methane towards intensifying this issue have prompted many countries to identify cleaner and greener forms of energy. Hydrogen has risen as a promising alternative stop-gap fuel in this energy transition given that it is cleaner, as well as being an effective energy carrier. Though the use of hydrogen as a fuel is not a new concept, the widespread use of this has been limited by several technological and reliability limitations - including issues in storage and production. Underground storage of hydrogen in depleted oil and gas reservoirs has been considered as a feasible solution, and an alternative to aboveground storage. Significantly large quantities of hydrogen gas can be stored relatively easily, safely and cheaply in such depleted reservoirs, until the hydrogen is needed - when it can be pumped out. However, the innovative idea of storing hydrogen in depleted petroleum reservoirs is also fraught with difficulties and challenges. Several integrity issues need to be considered, especially in the near wellbore region owing to the small size and the relatively high reactivity of the hydrogen molecule. Casing, tubing and the cement layer in the injection/production wells are of particular concern, especially while utilizing existing wells and depleted reservoirs. From the standpoint of subsurface containment, underground hydrogen storage and production is generally feasible, especially by utilizing our knowledge from prior CO2 sequestration initiatives. However, the properties of hydrogen, particularly its small size and reactivity, increase the complexity of underground storage and introduce new challenges and limitations. Casing, Tubulars and other OCTG components are prone to crack and deform when exposed to hydrogen, by a process known as hydrogen embrittlement. Isolation using cement plugs is also challenging since cement is known to degrade in the presence of hydrogen, while the small size of the hydrogen molecule makes containment in older wells difficult. All these need to be evaluated in detail to develop injection and storage criteria, as well as determining the need for cushion gas, and the ultimate recovery when the gas is eventually pumped back to the surface. With increased emphasis on hydrogen as an energy source, it is important to study and identify potential issues associated with its underground containment and storage. Injection/production wells will play a major role in enabling this and properly understanding potential integrity issues with the cement and casing are essential to ensure safe and sustained operations.

Underground hydrogen storage in depleted gas reservoirs with hydraulic fractures: Numerical modeling and simulation

This study's primary objective is to investigate the synergy of Underground Hydrogen Storage (UHS), extended oil recovery, and carbon dioxide (CO2) storage in an active oil and gas reservoir. Current studies on hydrogen (H2) storage in porous media have mainly considered depleted fields or aquifers. The current work investigates the implementation of H2 and CO2 storage in a depleting field and studies whether it will extend oil recovery, and how much continued operations will affect the storage processes. This work uses a history-matched Norne full-field model with a compositional fluid model. The field has three separate zones of oil, gas, and water; only the oil zone will be used for the study. After an established history of about nine years of water and gas injection for oil recovery, production continued towards depletion. Water flooding, CO2-WAG (water alternating gas), or continuous CO2 and water flooding are utilized in three distinct scenarios for enhanced oil recovery (EOR), CO2 storage, and cushion gas provision. After depletion, H2 is injected for cyclic storage and production. Our primary interest, however, is understanding whether CO2 and H2 injection may prolong oil production and whether the prolonged oil production will positively or negatively impact CO2 and H2 storage. The same cases are, therefore, also run where, after a short period of depletion, UHS is implemented while depletion is happening. Less productive wells will be modified to injection for more sustainable reservoir management. The impact of H2 storage on oil production was negligible, and the recovery factor declined by 0.5%. Out of all deployed EOR techniques, the CO2-WAG approach had the highest efficacy in oil recovery and could store around 60% of the injected CO2 underground. Furthermore, applying CO2-WAG resulted in the maximum efficiency for UHS during oil production, as CO2 reduced H2 dissolution in oil and residual trapping. Conversely, the water flooding method yielded the highest H2 recovery for storing H2 in the depleted reservoir, owing to a lower pressure near the H2 well and higher pressure in distant areas comparing two other cases. In addition, H2 broke through the oil wells, producing 17% of H2 via them. Consequently, the primary obstacles in UHS during oil production are the breakthrough of CO2 and H2 into the oil wells, which should be minimized by optimizing the operation parameters.

As the world transitions to clean energy sources, Underground Hydrogen Storage (UHS) has emerged as a leading solution for large-scale hydrogen storage. While the depleted oil or gas reservoirs are ideal for UHS, the effect of geochemical reactions among injected hydrogen, wellbore, and cement is not documented. This study aims to assess cement and well integrity by examining the geochemical interaction between API cement and hydrogen near the wellbore under varying temperature and pressure conditions. The numerical simulation was carried out to study the geochemical reaction between hydrogen and API class G/H cement minerals using the PHREEQC version 3 simulator. The dissolution reactions of hydrogen with the initial cement components, namely calcium tetra calcium alumino-ferrite (C4AF), tricalcium aluminate (C3A), tricalcium silicate (C3S), and dicalcium silicate (C2S) were modelled at various pressure and temperature conditions. The simulation assumed continuous cement hydration over an infinite time to assess the long-term effects of hydrogen-cement interactions and its impact on cement integrity near the wellbore. Based on this numerical simulation, we found that at 56.2oC, the formation of calcium silicate hydrate(CSH), portlandite, C3AH6, Mackinawite, magnetite, and hydrotalcite. At 95°C, similar minerals were formed with slightly higher amounts of CSH and slightly less portlandite, while others did not exhibit a noticeable difference. At 119°C, it was observed that a noticeable increase in CSH and a noticeable reduction in portlandite amount. Additionally, the formation of ettringite was observed at elevated temperatures. These findings highlight the temperature- dependent changes in mineral composition near the wellbore, which may have implications for the long-term integrity of the cement matrix in hydrogen-affected environments. Based on comprehensive numerical simulation studies, this paper highlights critical insights for a better understanding of hydrogen-cement interactions in the context of underground hydrogen storage, and its impact on the long-term-integrity of wellbores in hydrogen storage application, essential for enhancing the knowledge base for safe and effective implementation of underground hydrogen storage technologies.

A geometric contribution to the active-medium gain is estimated for laser tubes of circular, rectangular, and elliptic cross sections. The gain averaged over an elliptic cross section is found to decrease with increasing ellipse eccentricity and this gain is intermediate between those obtained for circular and rectangular cross sections (the gain on the axis is assumed to be the same in all cases). A smoother distribution of the gain over elliptic and rectangular cross sections and lower diffraction losses suggest that tubes with these cross sections should be used in ring lasers.

The global shift toward sustainable energy solutions has intensified interest in large-scale energy storage systems, with Underground Hydrogen Storage (UHS) in depleted oil and gas reservoirs has emerged as a viable option. A critical challenge in UHS is understanding the geochemical and petrophysical interactions between hydrogen, reservoir rock, and brine, which directly impact the safety and efficiency and long-term stability of storage operations. This study investigates the effects of hydrogen exposure on the geochemical and petrophysical properties of carbonate reservoirs through experimental analysis of core samples from the Red River Formation. Core samples from three wells (W13756, W13927, and W14075) were exposed to hydrogen at 2500 psi and 150°C for 30 days to simulate reservoir conditions. Core samples from three wells (W13756, W13927, and W14075) were subjected to hydrogen at 2500 psi and 150°C for 30 days to simulate reservoir conditions. The experiments revealed significant porosity and permeability changes. NMR relaxometry indicated porosity increases of 133.6% (3.39% to 7.92%) for Well 13756, 18.2% (9.25% to 10.93%) for Well 13927, and 20.6% (9.14% to 11.02%) for Well 14075. Correspondingly, permeability increased by 25.76% (0.66 mD to 0.83 mD) for Well 13756, 12.71% (0.80 mD to 0.9017 mD) for Well 13927, and 25.4% (0.05 mD to 0.0627 mD) for Well 14075. Mineralogical analysis via X-ray diffraction (XRD) highlighted significant transformations. For Well W14075, dolomite content decreased from 69.6% to 29.91%, accompanied by the formation of 43.14% vaterite and 25.10% calcite. Well W13927 exhibited a reduction in dolomite from 31.98% to 26.90%, with 3.78% calcite, 0.50% vaterite, and 0.42% aragonite emerging. In contrast, Well W13756 showed an increase in dolomite from 49.33% to 84.24%, alongside 6.31% vaterite and 0.67% calcite formation. These mineralogical changes indicate precipitation-dissolution dynamics, further corroborated by SEM observations of newly formed carbonate phases and distinct pore structure modifications.The results underscore the significant impact of hydrogen-rock interactions on the geochemical, petrophysical, and mechanical characteristics of carbonate formations. Increased porosity and permeability improve hydrogen injectivity and flow, while mineralogical changes and enhanced mechanical properties suggest improved structural stability under UHS conditions. These findings highlight the suitability of carbonate reservoirs, like the Red River Formation, for long-term hydrogen storage while providing critical insights into optimizing storage performance. This study advances the understanding of hydrogen storage dynamics in carbonate formations, offering valuable implications for developing safe, efficient, and sustainable UHS systems.