An experimental study of CO₂‐oil‐brine‐rock interaction under in situ reservoir conditions

Abstract

To understand the mineralogical and chemical changes in oil‐bearing reservoirs (e.g., depleted oil reservoirs) during massive CO2 injection, we have carried out a core‐flooding experimental study of CO2‐oil‐brine‐rock interactions under a simulated reservoir condition of 100°C and 24 MPa. The experimental condition is based on field data from a CO2‐EOR project in the southern Songliao Basin. This oil‐bearing CO2‐flooding experiment used the same experimental setup, reservoir conditions, and workflow as the oil‐free experiment reported by Yu et al. (). The sandstone core samples used in the experiment have similar mineralogical compositions as that used in the previous experiment. Compared with the oil‐free experiment, the presence of oil appears to substantially reduce the reaction degree between the CO2 fluid and some sensitive minerals. The dissolution rates of the K‐feldspar and carbonate minerals for the oil‐bearing experiment are 1/5 and 1/4 of that for the oil‐free experiments, respectively. For the silicate minerals represented by the K‐feldspar, the presence of oil mainly delays the dissolution during the experiment, and reduces the equilibrium dissolution rate. For the carbonate minerals, the presence of oil appears to primarily affect the dissolution at the beginning of the experiments, and reduce the maximum dissolution rate attained. The core permeabilities for the oil‐free and oil‐bearing cases are both reduced after experiments. The reduction in permeability is probably due to the precipitation of fine siliceous mineral and clay particles released by the dissolution of the carbonate cement, which may clog some pore throats. The results provide some new insights on the fluid‐rock interaction during CO2 injection in depleted oil reservoirs or during CO2‐EOR.