Modeling Flow and Transport in Saline Aquifers and Depleted Hydrocarbon Reservoirs for Hydrogen Energy Storage

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Summary Hydrogen (H2) is an attractive energy carrier, and its true potential is in decarbonizing industries, such as for providing heat for buildings and being a reliable fuel for trains, buses, and heavy trucks. Industry is already making tremendous progress in cutting costs and improving the efficiency of hydrogen infrastructure. Currently, heating is primarily provided by using natural gas and transportation by gasoline with a large carbon footprint. Hydrogen has a similarly high energy density, but there are technical challenges preventing its large-scale use as an energy carrier. Underground geologic storage of hydrogen in porous media (aquifers and hydrocarbon reservoirs) could offer substantial storage capacity at low cost as well as buffer capacity to meet changing seasonal electricity demands or possible disruptions in power supply. Underground geologic storage must have adequate capacity and ability to inject/extract high volumes with a reliable caprock. A thorough study is essential for a large number of site surveys to locate and fully characterize the subsurface geological storage sites both onshore and offshore. An isothermal compositional reservoir simulator was used to evaluate hydrogen storage and withdrawal from saline aquifers and depleted oil/gas reservoirs. The phase behavior, fluid properties, and petrophysical models were all calibrated against published laboratory data for density, viscosity, relative permeability, and capillary pressure for a given site. History-matched dynamic models of two CO2 injection field projects in saline aquifers and one natural gas storage in a depleted oil reservoir were considered as hypothetical hydrogen seasonal storage sites. A wide range of working gas volume/cushion gas volume ratios was observed, meaning that careful optimization is required for a successful storage project. For the aquifer cases, the range was 0.292 to 1.883 and a range of 1.045 to 4.4 was observed for the depleted hydrocarbon reservoir scenarios. For the saline aquifer cases, a higher injection rate, longer injection/withdrawal (I/W) cycles, and the use of pump wells to control the hydrogen plume spreading were all beneficial for improving the working gas/cushion gas ratio and the working gas volume. Plume control was important for storage in the oil reservoir in which changes in the well length location and orientation showed high sensitivity in the working and cushion gas volumes. Sensitivities to the initial gas saturation in the depleted gas reservoir scenarios suggested that both cushion and working gas volumes increased with the initial gas saturation while the ratio of working to cushion gas volumes decreased with the initial gas saturation. Finally, when comparing the ratios of working to cushion gas volumes, it was the highest for the depleted oil reservoir, followed by the depleted gas reservoir, and the aquifer.