Multiphase Hydraulic Properties of Reservoir Rock in Geologic H2 Storage

ABSTRACT: The feasibility of geologic hydrogen (H2) storage in saline aquifers necessitates a thorough analysis of multiphase fluid flow and fluid distribution. This study investigates Berea sandstone as a proxy for hydrogen injection into porous rock. An experimental setup has been developed to examine the water-hydrogen flow mechanism under representative in-situ stress conditions. The direct measurements demonstrate an exponential decrease in fluid permeability with saturation, with exponent values of 2.0 for water and 3.3 for hydrogen. The tests under different effective mean stresses reveal that the hydrogen relative permeability significantly changes, whereas the water permeability remains unaffected. Moreover, the relative permeability is predicted based on the capillary pressure curve and semi-empirical relative permeability models, indicating an underestimation of the fluid permeability at a given saturation. This research contributes unique insights into water and hydrogen relative permeability in potential reservoir for H2 storage. Although the pore structure-based estimation serves as a valuable pre-assessment tool, the direct measurements are crucial for accurately assessing the multiphase flow mechanism. 1. INTRODUCTION Hydrogen (H2) is increasingly recognized as a promising low-carbon energy carrier due to its high energy density, abundance, versatility, and renewable potential. Large-scale subsurface storage of hydrogen has emerged as a viable solution to address the primary challenges related to renewable energy generation, including seasonal and geographical limitations, as well as intermittency. Saline aquifers, among various potential reservoir formations, are particularly attractive for geologic H2 storage due to their abundance and substantial storage capacity. When H2 is injected into saline aquifer, it displaces the in-situ pore fluids, typically brine, and spreads out beneath low permeable formations, called caprock (Figure 1). Several unique aspects of geologic H2 storage should be considered, encompassing fluid properties, geochemical reaction, and microbial activity (Heinemann et al., 2021). The density of hydrogen is significantly lower than that of carbon dioxide (CO2) (e.g., ρH2 = 6.89 kg/m3 and ρCO2 = 289.95 kg/m3 at 10 MPa; Linstrom and Mallard, 2024), leading to a buoyancy force approximately three times greater at a reference depth of 1000m (Heinemann et al., 2021). The low solubility of H2 in pure water results in inconsiderable losses within the operation timescale (Feldmann et al., 2016). The injection of H2 into reservoir causes complex multiphase fluid displacement patterns, controlled by rock and fluid properties such as porosity, viscosity, compressibility, as well as fluid saturation and intrinsic/relative permeability (Heinemann et al., 2021). The relative permeability and capillary pressure directly influence fluid distribution within the reservoir, with particular importance being put on determining residual hydrogen saturation for economical feasibility during operations. Moreover, in contrast to the permanent CO2 storage, H2 is stored seasonally (≈ one full injection and production cycle per year), leading to changes in capillary pressure-related behavior over operational timescale due to multiple injection-withdrawal cycles.