Underground hydrogen storage in depleted gas fields is a potential solution for large-scale, seasonal storage of hydrogen, in support of the decarbonization of energy systems and other industrial activities. Its viability depends on the performance of the storage operations, which is influenced by the interaction between reservoir geology and operational strategies. However, general guidelines for development planning that account for geological uncertainty are still lacking. In addition, existing site screening criteria remain limited in that they do not account for how operational decisions can alter the suitability of a reservoir geology for hydrogen storage. Here, we employ a numerical model of flow and transport to evaluate a set of operational strategies in varying geological scenarios for depleted methane gas reservoirs of the Bunter Sandstone, an important formation in the North Sea. We investigate the following strategies for their impact on performance and interaction with geological features that are common in the Bunter sandstone: depletion level, injected hydrogen mass, cushion gas, well perforation, idle period, production rates, and methane reinjection. We found that depletion level, injected mass, and well perforation interact strongly with geology and are critical for site selection. The methane reinjection strategy provides pressure support that increases hydrogen production, though at the cost of purity in the long-term. Furthermore, cushion gas strategies show significant optimization potential but limited interaction with geology, whereas the duration of the idle period and target rates have low optimization potential. Based on these findings, we propose a site selection and development planning framework for underground hydrogen storage in depleted gas fields. The site selection phase introduces a novel screening criterion, the gravity–purity number, which integrates geological and operational considerations. The development phase provides criteria and guidelines for planning operational strategies, and establishes a hierarchy based on their optimization potential.

Dispersion is influenced by the complex interplay between rock heterogeneity, flow dynamics, and thermodynamic conditions. Previous studies have shown that factors like heterogeneity and injection rate affect how fluids mix and spread in geological formations. However, the role of system pressure and flow regime in shaping dispersion characteristics, particularly under unstable flow conditions, remains less understood. This study examines the effects of system pressure and flow rate on the dispersion of CO₂ and CH₄ in Indiana limestone and Silurian dolomite, two carbonate rocks with distinct pore structures. Experiments were conducted at pressures of 300, 600, and 900 psi, with flow rates of 1.69 × 10⁻⁴ m/s, 2.12 × 10⁻⁴ m/s, and 3.39 × 10⁻⁴ m/s, to evaluate how dispersion characteristics evolve under varying conditions. The results indicate that under stable flow, pressure has minimal impact on dispersion. However, under unstable flow, increasing pressure alters velocity distributions and enhances fluid mixing, leading to deviations in the dispersion coefficient beyond the effects of rock heterogeneity alone. In more homogeneous media, a threshold is observed where dispersion under unstable flow is lower relative to stable flow. These findings demonstrate that pressure amplifies dispersion primarily under unstable flow governed by the fluid density contrasts, and that heterogeneity can either enhance or dampen these effects.

In this work, we present a kinetic simulation model for gas hydrates in porous media using the Operator-Based Linearization (OBL) technique. The OBL approach introduces algebraic operators that represent the physical terms in the mass and energy balance equations. Operators are calculated only in supporting points comprising the discretized parameter space, and operator values and partial derivatives for linear system assembly are readily obtained through (multi-)linear interpolation. Taking advantage of this setup, the implementation of advanced thermodynamic models for hydrate formation and dissociation under kinetic assumptions is simplified. We test the assumptions for thermodynamic modelling by analysing the Gibbs energy surfaces of the fluid and hydrate phases and demonstrate that, in the limit, the thermodynamic equilibrium for both kinetic and equilibrium reaction models is equivalent. We compare the simulation results with the published experimental results for CH₄-hydrates and extend the assessment to a CO₂-hydrate formation experiment in a semi-batch, constant-pressure configuration. The model reproduces the main pressure–temperature transients and hydrate evolution for both CH₄- and CO₂-systems. We demonstrate applicability at core scale for hydrate formation and, at field scale, for gas production from CH₄-hydrates by thermal stimulation and depressurization. The interaction of thermal-compositional phenomena (phase changes, adiabatic expansion, kinetic rates, and reaction enthalpy) gives rise to highly nonlinear physics that an appropriate OBL discretization resolves. Overall, the patterns of hydrate formation and dissociation are highly sensitive to the kinetic-rate inputs; hence, the appropriate choice of the reaction model remains a key consideration from both physical and numerical perspectives.

The geological storage of hydrogen is an alternative for large-scale energy storage in support of expanding renewable energy systems. The North Sea has hundreds of depleted gas fields that are potential storage sites. Robust screening procedures are necessary to select the most suitable reservoirs in terms of geology. This study investigates the geological controls on hydrogen storage in depleted natural gas fields of the Bunter sandstone, an important formation in the North Sea. Using an ensemble of geological models and numerical simulations, we assess the impact of structural features and sedimentological heterogeneities on storage performance, as measured by metrics of recovery factor and purity. Key controlling factors include depositional cycle and reservoir thickness, dip, and the lateral continuity of mudstone and aeolian sandstone layers, which mainly influence performance through gravity-driven mechanisms. Building on this insight, a modified gravity number that incorporates heterogeneities is proposed to serve as screening criterion for the selection of top-performing depleted gad fields.

Heat exchange with surrounding formations and Joule–Thomson cooling during CO2 injection into deep saline aquifers and depleted hydrocarbon reservoirs can lead to substantial declines in well injectivity. This work addresses these challenges by introducing an analytical model for non-isothermal CO2 injection that accounts for both JT cooling and inter-formation heat exchange, assuming that heat transfer begins upon arrival of the temperature front rather than the gas–water front, as adopted in earlier models. An exact 1D solution is derived, providing closed-form expressions for temperature and pressure profiles. Model performance is evaluated through comparison with an exact 2D solution obtained from reservoir energy conservation. The new formulation demonstrates markedly improved accuracy over the previous model. The solution predicts a temperature drop from the injection temperature at the wellbore to a minimum at the temperature front, followed by a rapid rise back to the initial reservoir temperature. Mapping the evolving temperature and pressure profiles onto a (T, p) phase diagram enables assessment of hydrate-formation risk and identification of the distance from the injection well where hydrates may form.

This study investigates the directional dependence of gas dispersion in porous media with varying lithology and macroscopic heterogeneity. Eight rock samples, including three carbonates and five sandstones, were examined through CH₄–CO₂ core-flooding experiments at 300 psi and 65 °C. Each core was first flooded with CO₂ displacing CH₄, then the core was inverted 180° to quantify the dispersion coefficient in both core orientations. Across most samples, gas dispersion showed directional dependence, with fitted K_L values differing by up to 60%. The directional difference depended on the sequence in which the gas mixing front encountered visible heterogeneity. Carbonates exhibited higher dispersion coefficients and smaller directional differences than most sandstone samples, whereas visibly layered sandstones showed larger directional differences. Directional differences decreased with increasing permeability for homogeneous cores but showed no consistent trend in heterogeneous ones, where macroscopic structure dominated flow behavior. Rocks with pronounced macroscopic heterogeneity, such as the Nugget sandstone, experienced the greatest directional differences. These findings indicate that dispersion directionality is governed by a hierarchy of controls, in which lithology, macroscopic heterogeneity, and permeability influence the extent of gas mixing. Rock-dependent in situ fluid mixing can therefore have important implications for subsurface systems engineering in geologic gas storage, particularly in well placement and operational strategy design.

CO₂ injection into depleted reservoirs is a promising strategy for carbon storage, but it poses operational risks from hydrate formation, which can result in injectivity impairment. Concurrently, the injection of dry CO₂ drives a reservoir dry-out process by vaporizing formation water, which is counteracting the hydrate formation. This study uses numerical simulation to systematically investigate the competition between these two phenomena and to determine the conditions under which dry-out can mitigate or prevent hydrate formation. A five-phase, thermal-compositional model was developed to analyze the interplay between the advancing dry-out front and the thermal (cold) front. The results reveal two distinct regimes. A rapid and extensive leading dry-out front that outpaces the cold front and completely removes water before the reservoir cools. Conversely, a slow trailing dry-out front , where dry-out occurs within the already-cooled region. The leading dry-out front completely prevents hydrate formation. Even in the trailing-front scenario, the partial water removal ahead of the cold front significantly reduces the resulting hydrate saturation. Sensitivity analysis identifies initial reservoir temperature and initial water saturation as the most critical parameters governing this behavior. This work demonstrates that reservoir dry-out is an inherent mechanism for mitigating hydrate risk.

Fluid dispersion directly influences the transport, mixing, and efficiency of hydrogen storage in depleted gas reservoirs. Pore structure parameters, such as pore size, throat geometry, and connectivity, influence the complexity of flow pathways and the interplay between advective and diffusive transport mechanisms. Hence, these factors are critical for predicting and controlling flow behavior in the reservoirs. Despite its importance, the relationship between pore structure and dispersion remains poorly quantified, particularly under elevated flow conditions. To address this gap, this study employs pore network modeling (PNM) to investigate the influence of sandstone and carbonate structures on fluid flow properties at the micro-scale. Eleven rock samples, comprising seven sandstone and four carbonate, were analyzed. Pore network extraction from CT images was used to obtain detailed pore structure parameters and their statistical measures. Pore-scale simulations were conducted across 60 scenarios with varying average interstitial velocities and water as the injected fluid. Effluent hydrogen concentrations were measured to generate elution curves as a function of injected pore volumes (PV). This approach enables the assessment of the relationship between the dispersion coefficient and pore structure parameters across all rock samples at consistent average interstitial velocities. Additionally, dispersivity and n-exponent values were calculated and correlated with pore structure parameters.

The gas displacement in porous media is a crucial process with extensive industrial and environmental applications. A notable example is underground hydrogen storage, where it is important to understand hydrogen mixing with cushion gas. The current paper explores anomalies in dispersion behaviour of gas mixtures under opposing flow directions (injection and production) from a modelling perspective. Due to the gaseous nature of the system, it presents significant complexities due to non-ideal mixing, compressibility, and higher diffusivity compared to Newtonian fluid transport. The findings reveal distinct dispersion behaviour during injection and production, where augmenting the mixture non-ideality enhanced the non-unique behaviour. In contrast to the dispersivity seen in Newtonian fluid flow in porous media, our research identifies that dispersivity in gas displacement depends not only on the porous medium but also on the gaseous components’ properties.