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Hydrogen (H 2 ) will play a key role in low-carbon energy transitions, and it is vital to implement hydrogen storage technologies to enable its safe and economic use at industrial scale. Underground hydrogen storage (UHS) in porous media such as aquifers, depleted hydrocarbon fields, and coal seams has been proposed as widely available long-term and large-scale storage options (Iglauer et al., 2021;Muhammed et al., 2022). As for underground natural gas storage (UGS), UHS involves cyclic gas injection at peak supply (known as cushion gas) and withdrawal at peak demand (working gas). Despite the increasing attention to the topic worldwide, the fundamentals of multiphase hydrogen flow in porous media are still not well described. In particular, relative permeability hysteresis has not been addressed, although its impact has been previously assessed for UGS and CO 2 storage (Colonna et al., 1972;Juanes et al., 2006). The cyclic nature of the UHS suggests that distinct relative permeability functions must be implemented for hydrogen injection (drainage) and withdrawal (imbibition).Relative permeability is a crucial input parameter for the UHS numerical modeling at field scale (Kanaani et al., 2022;Lysyy et al., 2021;Wang et al., 2022). Laboratory gas-water relative permeability curves often have low endpoint gas saturations (<65%) and relative permeabilities (<40%) due to the rock heterogeneity, capillary end effects, gravity segregation, and/or maximum experimental capillary pressure (Krevor et al., 2012;Muller, 2011). Numerical and/or analytical methods are therefore required to validate and extrapolate relative permeabilities in a wider saturation range.Hydrogen-water relative permeability measurements are scarce in the open literature. Steady state drainage experiments resulted in low endpoint gas saturation (∼60%) and relative permeability (∼4%) (Yekta et al., 2018). The authors used experimental capillary pressure to analytically expand the relative permeability curves to higher

In this paper, we report the growth pattern and the rate of CH 4 hydrate in sandstone pores. A high-pressure, water-wet, transparent micromodel with pores resembling a sandstone rock was used to visualize CH 4 hydrate formation at reservoir conditions (P = 35−115 bar and T = 0.1−4.9 °C). The CH 4 hydrate preferably formed and grew along the gas−water interface until the gas phase was completely encapsulated by a hydrate film. Two different growth rates were identified on the gas−water interface: CH 4 hydrate film growth along the vertical pore walls (∼1200 μm/s) was more than 100 times faster than the film growth toward the pore center (∼8 μm/s). CH 4 hydrate crystal growth directly in the water phase was slow and the rate was less than 0.5 μm/s. The film growth rate along the gas−water interface was independent of the pore size, gas saturation, and gas distribution, but the pore wall growth rate displayed a power law dependency on the applied subcooling temperature, ΔT, with a power law exponent equal to 2. The results of this study can be used as input to numerical models aiming to simulate pore-scale CH 4 hydrate growth behavior.

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