Investigation of Synergy Between Extended Oil Recovery and Hydrogen Storage in a Producing Field Using the Norne Reservoir Model

Abstract

Abstract This study's primary objective is to investigate the synergy of Underground Hydrogen Storage (UHS), extended oil recovery, and carbon dioxide (CO2) storage in an active oil and gas reservoir. Current studies on hydrogen (H2) storage in porous media have mainly considered depleted fields or aquifers. The current work investigates the implementation of H2 and CO2 storage in a depleting field and studies whether it will extend oil recovery, and how much continued operations will affect the storage processes. This work uses a history-matched Norne full-field model with a compositional fluid model. The field has three separate zones of oil, gas, and water; only the oil zone will be used for the study. After an established history of about nine years of water and gas injection for oil recovery, production continued towards depletion. Water flooding, CO2-WAG (water alternating gas), or continuous CO2 and water flooding are utilized in three distinct scenarios for enhanced oil recovery (EOR), CO2 storage, and cushion gas provision. After depletion, H2 is injected for cyclic storage and production. Our primary interest, however, is understanding whether CO2 and H2 injection may prolong oil production and whether the prolonged oil production will positively or negatively impact CO2 and H2 storage. The same cases are, therefore, also run where, after a short period of depletion, UHS is implemented while depletion is happening. Less productive wells will be modified to injection for more sustainable reservoir management. The impact of H2 storage on oil production was negligible, and the recovery factor declined by 0.5%. Out of all deployed EOR techniques, the CO2-WAG approach had the highest efficacy in oil recovery and could store around 60% of the injected CO2 underground. Furthermore, applying CO2-WAG resulted in the maximum efficiency for UHS during oil production, as CO2 reduced H2 dissolution in oil and residual trapping. Conversely, the water flooding method yielded the highest H2 recovery for storing H2 in the depleted reservoir, owing to a lower pressure near the H2 well and higher pressure in distant areas comparing two other cases. In addition, H2 broke through the oil wells, producing 17% of H2 via them. Consequently, the primary obstacles in UHS during oil production are the breakthrough of CO2 and H2 into the oil wells, which should be minimized by optimizing the operation parameters.