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.

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.

This report summarizes the reservoir characterization [Wang et al., J. Hydrol., 2022] and multiphase flow property [Kou et al., J. Hydrol., 2021] in a target deep saline aquifer, upper Minnelusa sandstone in Wyoming. Multiscale petrophysical characterization and flow unit classification were carried out to identify two different facies groups: cross-bedded and massive sandstone. Based on the rock typing results, two representative core samples were selected accordingly to conduct coreflooding experiments. Results illustrate that the sub-core scale heterogeneity significantly affects CO₂-brine multiphase flow properties. As a result, the sub-core scale heterogeneity should be considered during CO₂ injection to reduce the uncertainties in storage and fluid flow.