Quantitative Effects of Pressure and Gas-Water Slug Ratio on Microscopic Remaining Oil Morphology in CO2 Water-Alternating-Gas Fracturing Flooding: A Micromodel Study

Summary

CO2 water-alternating-gas (WAG) fracturing flooding, a typical fracturing flooding technique, has been tentatively applied to enhance oil recovery in low-permeability oil reservoirs in China. This method exhibits clear advantages in expanding drainage area and improving displacement efficiency by maintaining a constant high pressure that keeps fractures continuously open. However, the influences of pressure and gas-water slug ratio on remaining oil occurrence and the underlying mechanisms during this fracturing flooding process remain insufficiently understood. In this study, a micromodel embedded with a tree-shaped fracture structure was used to investigate diverse remaining oil occurrence and mobilization mechanisms under CO2 WAG fracturing flooding conditions. Specifically, the effects of pressure and gas-water slug ratio on remaining oil distribution and oil recovery performance were systematically investigated. Meanwhile, the morphological evolution and emulsification behaviors of remaining oil during the fracturing flooding process were explored. And CO2 WAG fracturing flooding experiments were conducted under varying pressures (20 MPa, 40 MPa, and 60 MPa) and gas-water slug ratios (1:3, 1:1, and 3:1). The results indicated that within the tested ranges, pressure increment primarily affected the waterflooding stage of fracturing flooding by enhancing the stripping and redistribution of cluster oil, with a contribution of 88.8% to oil recovery at 60 MPa. Additionally, high pressure was observed to promote the transformation of remaining oil from continuous to dispersed phases under fracturing flooding conditions, resulting in an approximately 70% reduction in cluster oil. It should be noted that different performance criteria were found to peak at different pressures during the process. Among all tested combinations, at a constant pressure of 40 MPa and a gas-water slug ratio of 3:1, the most pronounced effect of CO2 on remaining oil was observed, and a 27.4% increase in oil recovery was achieved. Gas-water slug ratio optimization was shown to control the amount of CO2 interaction during the gas stage of fracturing flooding, which, in turn, determined the mobilization of blind-end oil. A larger CO2 slug was found to directly influence the morphological distribution, converting cluster oil into columnar and blind-end oil. Water-in-oil emulsion was observed to expand sweep coverage, targeting columnar and membrane oil at 40 MPa. A water- and CO2-in-oil emulsion at a gas-water slug ratio of 1:3 was seen to divert flow for cluster oil, whereas a CO2-in-oil emulsion at a gas-water slug ratio of 3:1 facilitated the mobilization of island and blind-end oil. Within the tested pressure and gas-water slug ratio ranges, the combination of 40  MPa and 3:1 yielded the highest contribution from emulsification, which was estimated to account for 20–25% of the total incremental oil recovery. This research can provide a theoretical foundation for parameter optimization of CO2 WAG fracturing flooding schemes in low-permeability oil reservoirs.