Utilizing macroscopic areal permeability heterogeneity to enhance the effect of CO2 flooding in tight sandstone reservoirs in the Ordos Basin

Abstract

Carbon dioxide-enhanced oil recovery (CO2-EOR) technology has been proven to be effective approach for enhancing oil recovery and has been used in conventional reservoirs since 1970s. Tight sandstone reservoir has poor petrophysical properties, and the complex diagenetic processes that make the reservoir highly heterogeneous resulted in posing significant challenges to CO2-EOR technology. This paper investigated the effects of macroscopic permeability heterogeneity on the efficiency of CO2-EOR by laboratory experiments and field data analysis. The permeability heterogeneity of the reservoir matrix in the study area was evaluated. The results reveal that the matrix permeability range from 0.001 mD to 15 mD, with a mean approximant 1 mD, Beside common thin bedding laminations, the areal permeability varies significantly in a short distance, which is typical for a tight sandstone reservoir. The Triassic Yanchang Formation (200–1400 m thick) is a major petroliferous stratigraphic section in the Ordos Basin. It consists of complete lacustrine sedimentary cycles with clastic sediments. From bottom to top, it can be divided as Chang 10 to Chang 1 members. The low porosity, low permeability, low oil saturation, anomalously low reservoir pressure, and high reservoir heterogeneity makes application of enhanced oil recovery techniques in this formation challenging. The submerged distributary channel core sample with various permeability from the Chang 4+5 sandstone reservoir in Shanbei area of the Ordos Basin were utilized in the laboratory CO2-EOR experiments to study the impact of heterogeneity on CO2 flooding. The results show that the mode of high–low permeability (i.e., the injection well located in the higher permeability area and the production well located in the low permeability area) can ensure the gas injection capacity, maintain a high pressure level throughout the production period, and increase the oil displacement efficiency, which breaks the conventional understanding. Conventional understanding holds that high permeable pore path or fractures developed on the injection area are prone to CO2 channeling, and high permeable pore path or fractures developed on the production area are conducive to oil flow and output increase. Therefore, oil well fracturing is often carried out in the field, and fracturing of injection well is not recommended. However, our experimental research and field application found that the traditional guiding ideology is not conducive to improve oil recovery, but the high–low permeability model which is put forward in this paper can not only enhance CO2 injectivity, but also is beneficial to high formation pressure level and full interaction between gas and crude oil. It also can be confirmed from oilfield that the application of high-low permeability model with high-heterogeneity reservoir could effectively improve the effect of CO2 flooding in tight sandstone reservoirs.