Carbon dioxide diffusions in Methane-Dissolved pore Fluids: Implications for geological carbon storage and utilization in tight formations

Abstract Fluid immobilizations in tight formations augment the importance of CO2 molecular diffusions in the processes of geological carbon utilization and storage. This study, for the first time, investigates the CO2 diffusions in unconventional tight formations which are saturated with in-situ gas-dissolved pore fluids, both experimentally and theoretically. A novel high-pressure high-temperature diffusion cell was designed to reproduce the actual CO2 diffusions in extremely low-permeability on-site geological cores saturated with methane-dissolved crude oils at the reservoir conditions and various scenarios (e.g., different gas–liquid ratios). On the other hand, a comprehensive mathematical model, which consists composition and diffusion models, was developed for quick predictions and in-depth evaluations. The CO2 diffusion coefficients at the pressure of 18.5 MPa and temperature of 80 °C with varying gas–liquid ratios were obtained from a genetic algorithm-fitting of the measured and calculated data. With the gas–liquid ratios increasing from 0 to 40 sm3/m3, the CO2 diffusion coefficient was found to decrease from 7.90 × 10−9 to 3.09 × 10−9 m2/s and the average velocity of diffusion front reduced from 0.0121 to 0.0050 m/d. This finding indicates methane dissolutions into the crude oil at the reservoir conditions would be detrimental for the CO2 diffusions. Hence, the methane amount is suggested to be well controlled in the processes of geological carbon storage and utilization for oil production. This study will support the foundation of more general application pertaining to geological CO2 utilization and storage, especially in the unconventional tight or shale oil reservoirs.