Large-scale storage solutions play a critical role in the ongoing energy transition, with Underground Hydrogen Storage (UHS) emerging as a possible option. UHS can benefit from existing natural gas storage expertise; however, key differences in hydrogen’s behavior compared to CH4 must be characterized at the pore scale to optimize the design and the management of these systems. This work investigates two-phase (gas–water) flow behavior using microfluidic devices mimicking reservoir rocks’ pore structure. Microfluidic tests provide a systematic side-by-side comparison of H2–water and CH4–water displacement under the same pore-network geometries, wettability, and flow conditions, focusing on the drainage phase. While all experiments fall within the transitional flow regime between capillary and viscous fingering, clear quantitative differences between H2 and CH4 emerge. Indeed, the results show that hydrogen’s lower viscosity enhances capillary fingering and snap-off events, while methane exhibits more stable viscous-dominated behavior. Both gases show rapid breakthrough; however, H2’s flow instability—especially at low capillary numbers (Ca)—leads to spontaneous water imbibition, suggesting stronger capillary forces. Relative permeability endpoints are evaluated when steady state conditions are reached: they show dependence on Ca, not just saturation, aligning with recent scaling laws. Despite H2 showing a different displacement regime, closer to capillary fingering, H2 mobility remains comparable to CH4. These findings highlight differences in flow behavior between H2 and CH4, emphasizing the need for tailored strategies for UHS to manage trapping and optimize recovery.
Loffredo et al. (2026) studied this question.