Nanoconfinement effects in shale reservoirs reduce CO 2 -oil minimum miscibility pressure (MMP) and interfacial tension, thereby influencing phase behavior and controlling the dynamic evolution of the miscible zone along the displacement path. To address this, we incorporated critical property shifts, capillary pressure, and fluid–solid interactions into the phase equilibrium model by modifying the Peng–Robinson equation of state. This confined phase equilibrium model was coupled with a multicomponent flow model to simulate CO 2 displacement under nanoconfined conditions. Using local compositional distributions, interfacial tension serves as the criterion to determine miscibility states and classify along-course zones. Results show that nanoconfinement narrows the two-phase region, and MMP decreases with pore size (13.5% reduction in 10 nm pores vs bulk). The relative velocity between compositional front and gas front is controlled by pore size and pressure; small pores suppress premature gas exsolution. Nanoconfinement enhances sweep efficiency─under near-miscible pressure, the sweep coefficient in 10 nm pores is approximately twice that of bulk─and increases the peak miscible zone area by 10%–14% relative to bulk, while delaying postbreakthrough decline. The along-course miscible zone area increases with injection pressure, and nanoconfinement enables low-pressure injection to achieve miscible development comparable to high-pressure bulk conditions. In summary, nanoconfinement reduces MMP, enhances vaporization-condensation mass transfer, accelerates frontal advancement, and expands the miscible zone, thereby improving CO 2 miscible displacement performance. This study provides a theoretical basis for CO 2 enhanced oil recovery in shale oil reservoirs.
Qi et al. (Sun,) studied this question.
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