Underground hydrogen storage in depleted shale gas reservoirs has emerged as a promising option for large-scale energy storage, with feasibility assessments relying on compositional simulations. The fidelity of such simulations hinges on accurate representation of key physicochemical processes, particularly gas adsorption, which governs phase partitioning in shale formations. However, adsorption is often treated deterministically in large-scale simulations, while optimization efforts emphasize operational and geological parameters. This minireview summarizes prevailing compositional simulation workflows and key performance metrics for shale and further synthesizes recent advances and gaps in H₂/CH₄ competitive adsorption, highlighting the scarcity and experimental difficulty of multicomponent adsorption data. The propagation of adsorption-related uncertainty to large-scale predictions is further discussed. An illustrative scenario demonstrates that different multicomponent adsorption models can significantly alter the predicted fraction of adsorbed H₂ and the recovery factor. The magnitude of these variations can be comparable to or even exceed improvements achieved through typical operational optimizations. Such discrepancies indicate that adsorption representation is not a non-significant modeling input but a central factor influencing evaluation outcomes. These findings underscore the need to explicitly account for competitive adsorption in assessing underground hydrogen storage in shales. Furthermore, adsorption uncertainty should be systematically quantified and integrated into modeling workflows to secure the high-fidelity of compositional modeling underground hydrogen storage in shales.

Fractional wettability is common in oil and gas reservoirs, resulting in complex fluid distribution and transport phenomena. A precise understanding of capillary pressure behavior and characterization in fractional-wet reservoirs, including the two-phase flow mechanisms within pores and relationship between capillary pressure and saturation in porous media, is significant to enhanced oil recovery strategies. In this paper, an in-depth review of the two-phase flow mechanisms in fractional-wet pores and capillary entry pressures in various displacement processes was conducted. Furthermore, the effects of oil-wet proportion and contact angle on capillary pressure characterization were summarized, highlighting the emergence of similar capillary pressure curves under conditions of low oil-wet proportions. The prediction models for capillary pressure, containing empirical equations and physics-based models were discussed, with the aim of clarifying the most effective prediction methodologies. Finally, the review was finalized by outlining key findings and future directions for both experimental and theoretical studies in the realm of capillary pressure behavior and characterization.

Shale gas and coalbed methane are energy sources that mainly consist of methane stored in an adsorbed state in the pores of the organic-rich rock and coal seams. In this study, the graphene nanoslit model is employed to model the nanometer slit pores in shale and coal. Grand canonical Monte Carlo and molecular dynamics modeling methods are used to investigate the mechanisms of adsorption and displacement of methane in graphene-based nanoslit pores. It is found that as the width of the slit pore increases, the adsorption amount of gas molecules increases, and the number density profile of adsorbed methane molecules alters from monolayer to multilayer adsorption. The minimum slit pore width at which methane molecules can penetrate the slit pore is determined to be 0.7 nm. Moreover, it is demonstrated that by lowering the temperature, the adsorption rate of the methane increases since the adsorption is an exothermic process. Enhancing methane recovery was investigated by the injection of gases such as CO₂ and N₂ to displace the adsorbed methane. The comparison of adsorption isotherms of gas molecules provides the following order in terms of the amount of adsorption, CO₂>CH₄>N₂, for the same slit pore width and the same temperature and pressure conditions.

This report summarizes our recent implementation of a crossover formulation in the lattice Boltzmann method and its application in modeling transcritical CO₂ sequestration in water-saturated porous media. A crossover enhancement of the Peng-Robinson equation of state increases the accuracy in predicting fluid properties in transcritical conditions, which is relevant in modeling CO₂ sequestration. The crossover formulation leads to the prediction of liquid-vapor coexistence curves closer to experimental data. The formulation was validated with several tests and applied to model the displacement of H₂O with CO₂ in a homogeneous porous medium in multiple conditions. This investigation provides a promising strategy for improving the accuracy of the lattice Boltzmann method in modeling transcritical CO₂ sequestration in aquifers using realistic transcritical conditions.

Injection of CO₂ and subsequent desorption of CH₄ is considered to be the most efficient enhanced coalbed methane (ECBM) recovery technique to date. Meanwhile, CO₂-ECBM is an excellent option for CO₂ geo-sequestration for an extended period. Despite ongoing research efforts and several field applications of this technology, the mechanisms of the process have yet to be fully understood. The coalbed heterogeneity, the fluid interactions with coal, the CO₂ induced swelling, and the continuous pressure and composition changes require outright insights for optimal application of the technique. Furthermore, intermolecular interactions of CO₂ and CH₄, their competitive adsorption on the dry/wet coal surface, and the dispersion and advection processes play an important role in defining the CO₂-ECBM recovery process. An attempt has been made here to understand the key mechanisms of CO₂-ECBM recovery in coalfields, particularly the adsorption of CO₂ in the supercritical state at the recommended sequestration depth.

In shale gas reservoir development, determination of hydraulic fracture geometry for horizontal wells is a demanding yet challenging task. One type of approach for hydraulic fracture optimization is based on reservoir simulation. To improve optimization efficiency and accuracy, an automatic and robust procedure integrating the gradient descent method with gas reservoir simulation has been developed. Fractured reservoir models were constructed using the "Multiple INteracting Continua" method, whereby an in-house shale gas reservoir simulator was implemented to model multiple gas transport mechanisms including non-Darcy flow, gas desorption, Klinkenberg effect, and geomechanical effect. The optimization procedure was first validated against two ideal cases and then applied to two realistic cases to optimize fracture spacing, half-length, and dimensionless fracture conductivity. It showed that the optimization results depend on optimization objective, reservoir property, natural fractures, economics and termination criteria. This gradient descent assisted fracture optimization procedure can achieve significant computational reduction and high prediction accuracy for various shale gas reservoir cases.