Evolution of Crude Oil Properties Under Supercritical CO2 and Its Implications for Field-Scale Enhanced Recovery in the Mabei Shale Oil Reservoir

Supercritical CO2 injection can mitigate depletion-induced deterioration of shale oil, but the relationship between laboratory-scale fluid-property changes and field-scale recovery remains insufficiently understood. This study integrates time-lapse produced-oil characterization, high-pressure PVT experiments, whole-hydrocarbon gas chromatography, and compositional reservoir simulation for the Mabei shale oil reservoir. From October 2023 to October 2025, the viscosity of dehydrated and degassed produced oil at 80 °C increased from 20.93 to 56.8 mPa·s, accompanied by depletion of light hydrocarbons and enrichment of heavy components, indicating progressive compositional deterioration during depletion. At 106.75 °C and 65.07 MPa, increasing the added CO2/oil molar ratio from 0 to 80% reduced live-oil viscosity from 9.7841 to 3.8470 mPa·s and density from 0.8326 to 0.7897 g/cm3. Most viscosity, density, and oil-phase compositional changes occurred within the first 6 h in the closed, continuously stirred PVT cell. CO2 contact preferentially transferred C3–C7 hydrocarbons out of the analyzed oil-rich phase, resulting in relative enrichment of C15–C37 components in the residual oil. The history-matched compositional model showed that CO2 improved reservoir pressure maintenance and expanded low-viscosity regions primarily along fracture-connected flow paths, although the incremental response became limited between the 20 and 25% cases. Regional compositional analysis further demonstrated that strongly CO2-contacted residual oil became heavier, whereas the produced oil was enriched in mobilized light and intermediate hydrocarbons. These results establish a consistent laboratory-to-field interpretation of CO2-induced compositional redistribution and provide a basis for optimizing CO2-assisted development in deeply buried shale oil reservoirs. CO2-induced asphaltene precipitation/deposition and the associated permeability impairment were not measured or represented in the numerical model. Therefore, the reported recovery response reflects CO2–oil property and transport effects in the absence of solid-phase formation damage.