LAUSR

Abstract In this paper, four different injection schemes, i.e., CO2 continuous gas injection (CGI), gas injection (GI) + soaking, pulse injection, and injection-alternating-production (IAP), for the high-temperature and pressure CO2 immiscible flooding in low-permeability formations are experimentally studied. A series of comprehensive and optimum practical strategies with respect to the four immiscible CO2 injection processes in the low-permeability formations can be determined from this study. More specifically, a total of 10 immiscible coreflood tests are conducted at the injection pressure of 20.0 MPa and reservoir temperature of 130.0 °C by means of the four different injection schemes. The oil viscosity and density are experimentally measured to be reduced with the temperature increase and the minimum miscibility pressure is measured to be 30.0 MPa at 130.0 °C from the vanishing interfacial tension (VIT) technique. Among Tests No. 1–10 with the same experimental conditions, the measured oil recovery factor (ORF) of Test No. 9, which is the CO2 IAP with the injection rates of 0.5 cm3/min, is the highest at 69.06%. In Test No. 4, the CO2 GI + soaking at the injection rate of 0.5 cm3/min has the second highest ORF of 65.21%. Tests No. 1, 4, 7, and 9 at the injection rate of 0.5 cm3/min outperform other tests with the same injection scheme in terms of the ORF under the same experimental conditions but at larger injection rates. Thus, a small CO2 injection rate is beneficial to increase the ORF for all schemes except for the CO2 pulse injections. It is found that soaking is an important step for CO2 enhanced oil recovery at the immiscible conditions. Moreover, the smaller injection rate also contributes to the delay of CO2 breakthrough so that a higher ORF can be reached at a lower cost. Finally, the measured asphaltene and wax contents in the produced oil are found to reduce in the percentages of 33–51% and 14–25% from the beginning period to the end of the oil production.