Hydrogen Relative Permeability Hysteresis in Underground Storage

Abstract

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

Effect of Cushion Gas on Hydrogen/Brine Flow Behavior in Oil-Wet Rocks with Application to Hydrogen Storage in Depleted Oil and Gas Reservoirs

“…The crossover saturations of the relative permeabilities were roughly less than 50% indicator of oil-wet system . One characteristic of the relative permeability curves compared with water-wet cases obtained previously in the literature − is that the gas relative permeabilities appeared to be smaller in this study. The k rg value for minimum brine saturation of 26.9% and maximum H 2 –CH 4 saturation of 61.1% at the end of gas flooding was 0.013 as opposed to the range of 0.05–0.3 for water-wet cases. − , This observation is in agreement with the literature and is attributed to the oil wetness of the rock and also the existence of 11.97% immobile oil with relatively high viscosity, hindering the flow of gas inside the porous medium partitioned between the three phases.…”

“…The observation of lower gas relative permeability values in oil-wet rocks, in contrast to those reported in the literature for water-wet rocks, − , provides essential insights into the potential risk of hydrogen escape from depleted oil and gas reservoirs compared to aquifers. Relative permeability refers to the fractional flow of hydrogen in comparison to the total fluid flow within a porous medium . The obtained lower gas relative permeability values in oil-wet rocks indicate that hydrogen has relatively lower mobility or ease of flow through formations compared to that in water-wet rocks.…”

“…Core-flow experimental data play a pivotal role in the achievement of successful and efficient hydrogen storage in subsurface formations. Its significance lies in providing crucial insights into various aspects, including predicting flow behavior, storage efficiency, safety considerations, simulation and modeling, and the development of effective storage strategies. − However, there are scarce experimental attempts to evaluate the possibilities of hydrogen storage in geologic formation through core flood experiments at both macro- and microscales in the literature.…”

“…Lysyy et al used a steady-state technique to measure hysteresis in hydrogen–water relative permeability in a Berea sandstone core sample under shallow storage conditions. They performed primary drainage, imbibition, and secondary drainage to measure the relative permeability.…”

“…Analyses of their data revealed a strong hysteresis in the gas–water relative permeabilities. Repeating the primary drainage relative permeability measurement with nitrogen resulted in a greater relative permeability, which was interpreted as a possible effect of greater viscosity ratio and methodological uncertainties . Boon and Hajibeygi performed H 2 –water multiphase flow experiments at the core scale under a medical X-ray computed tomography (CT) scanner.…”