Underground hydrogen (H₂) storage is a potentially viable solution for large-scale cyclic H₂ storage; however, the behavior of H₂ at subsurface pressure and temperature conditions is poorly known. This work investigates if the pore-scale displacement processes in H₂-brine systems in a porous sandstone can be sufficiently well defined to enable effective and economic storage operations. In particular, this study investigates trapping, dissolution, and wettability of H₂-brine systems at the pore-scale, at conditions that are realistic for subsurface H₂ storage. We have performed in situ X-ray imaging during a flow experiment to investigate pore-scale processes during H₂ injection and displacement in a brine saturated Bentheimer sandstone sample at temperature and pressure conditions representative of underground reservoirs. Two injection schemes were followed for imbibition: displacement of H₂ with H₂-equilibrated brine and with non-H₂-equilibrated brine. The results from the two cycles were compared with each other. The sandstone was found to be wetting to the brine and non-wetting to H₂ after both displacement cycles, with average contact angles of 54° and 53° for H₂-equilibrated and non-H₂-equilibrated brine respectively. We also found a higher recovery of H₂ (43.1%) when displaced with non-H₂-equilibrated brine compared to that of H₂-equilibrated brine (31.6%), indicating potential dissolution of H₂ in the unequilibrated imbibing brine at reservoir conditions. Our results suggest that underground H₂ storage may indeed be a suitable strategy for energy storage, but considerable further research is needed to fully comprehend the pore-scale interactions at reservoir conditions.

Pore-scale two-phase flow modeling is an important technology to study a rock's relative permeability behavior. To investigate if these models are predictive, the calculated pore-scale fluid distributions which determine the relative permeability need to be validated. In this work, we introduce a methodology to quantitatively compare models to experimental fluid distributions in flow experiments visualized with microcomputed tomography. First, we analyzed five repeated drainage-imbibition experiments on a single sample. In these experiments, the exact fluid distributions were not fully repeatable on a pore-by-pore basis, while the global properties of the fluid distribution were. Then two fractional flow experiments were used to validate a quasistatic pore network model. The model correctly predicted the fluid present in more than 75% of pores and throats in drainage and imbibition. To quantify what this means for the relevant global properties of the fluid distribution, we compare the main flow paths and the connectivity across the different pore sizes in the modeled and experimental fluid distributions. These essential topology characteristics matched well for drainage simulations, but not for imbibition. This suggests that the pore-filling rules in the network model we used need to be improved to make reliable predictions of imbibition. The presented analysis illustrates the potential of our methodology to systematically and robustly test two-phase flow models to aid in model development and calibration.