Field‐scale reactive transport assessment of CO2 storage in the Farnsworth unit through enhanced oil recovery practices

Abstract

AbstractThe objective of this study was to investigate the transport and fate of CO2 injected into a sandstone reservoir in the western Farnsworth Unit, a hydrocarbon field in northern Texas. The study employed three‐dimensional multifluid‐phase numerical reactive solute and heat transport modeling. Model inputs were obtained from previous field characterization studies and calibrated to 8 years of historical production data. The CO2 in the models was injected through multiple wells for the first 25 years of the simulations according to a water‐alternating gas schedule. The simulations were carried out for a total of 1000 years in order to study the long‐term effects of CO2 injection.The results show that the largest fraction of the injected CO2 is stored in oil, followed by successively smaller amounts in the formation water, carbonate mineral phases, and as an immiscible gas phase. The small fraction of CO2 present as an immiscible gas, the most mobile phase for CO2, aids in the long‐term sequestration security of the injected CO2. The injected CO2 was found to migrate within a maximum radius of around 500 m of the injection wells. This means that changes in fluid pressure, temperature, composition, and reservoir mineralogy were also limited to occurring within this radius. This radius is very sensitive to model relative permeability and capillary pressure values, which were determined from history matching to the field production data. The models predicted dolomite to be the main mineral sink for the injected CO2. Quartz was another mineral predicted to precipitate, whereas calcite, albite, chlorite, illite, and kaolinite were predicted to dissolve. The changes in mineral abundance had minimal effect on porosity, implying that the permeability of the reservoir should also not change much because of CO2 injection. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.