Key points are not available for this paper at this time.
Summary Miscible gas injection is the most widely applied enhanced oil recovery (EOR) method in light oil carbonate reservoirs as a tertiary and secondary method. Miscible gas has high displacement efficiency and usually results in a low residual oil saturation (Sorm) in the parts of the reservoirs that are in contact with the gas. Accurate determination of Sorm and understanding the parameters that affect displacement efficiency are crucial for successful miscible gas EOR projects. In this paper, we present a comprehensive experimental program designed to investigate the effect of a number of parameters on oil recovery, displacement efficiency, and Sorm of miscible and near-miscible carbon dioxide (CO2) injection. The parameters investigated in this study are the experimental pressure, pore volume (PV) injected, injection rate, rock type, and initial water saturation (Swi). The coreflood experiments were performed using live crude oil at pressures starting below the minimum miscibility pressure (MMP) to pressure well above the MMP, using reservoir core samples of up to 1 ft long and 2 in. diameter. All CO2 injection experiments were performed using vertically oriented cores, with gas injection from the top to ensure stable displacement. The experimental results show that (1) Oil recovery decreases as pressure decreases with Sorm increasing by more than 20 saturation units as the pressure decreases from 4,250 psi to 2,700 psi; (2) CO2 breakthrough was much earlier at lower pressure, which leads to more CO2 recycling and potentially lower CO2 sequestration volume; (3) the recovery factor (RF) is strongly affected by the PV injected, and this effect is much more significant for the experiments performed at lower pressure; (4) the injection rate has an insignificant impact on oil recovery and Sorm for miscible or near-miscible CO2, due to the low interfacial tension (IFT) between oil and CO2; (5) rock heterogeneity has a strong effect on oil recovery and CO2 breakthrough and hence on CO2 recycling and economy of the projects; and (6) the presence of mobile water at the beginning of CO2 injection resulted in lower displacement efficiency and increased Sorm. However, this water blocking effect should be determined experimentally for a given reservoir rock/fluid system. The results of this study cannot be generalized for other reservoirs. The results of this study have important implications for the design and performance predictions of CO2 injection in the reservoirs under study. Starting CO2 injection at reservoir pressure, which, in some cases, is more than 1,500 psi above MMP, is recommended due to its superior displacement efficiency and less CO2 recycling due to later breakthrough. However, a higher pressure may negatively impact the required CO2 volume, the compression cost, and project economics.
Masalmeh et al. (Mon,) studied this question.