The Lunnan Oilfield in the Tarim Basin is known for its abundant oil and gas resources. However, the marine clastic reservoir in this oilfield poses challenges due to its tightness and difficulty in development using conventional water drive methods. To improve the recovery rate, this study focuses on the application of carbon dioxide flooding after a water drive. Indoor experiments were conducted on the formation fluids of the Lunnan Oil Formation, specifically investigating gas injection expansion, thin tube, long core displacement, oil and gas phase permeability, and solubility. By injecting carbon dioxide under the current formation pressure, the study explores the impact of varying amounts of carbon dioxide on crude oil extraction capacity, high-pressure physical parameters of crude oil, and phase characteristics of formation fluids. Additionally, the maximum dissolution capacity of carbon dioxide in formation water is analyzed under different formation temperatures and pressures. The research findings indicate that the crude oil extracted from the Lunnan Oilfield exhibits specific characteristics such as low viscosity, low freezing point, low-medium sulfur content, high wax content, and medium colloid asphaltene. The measured density of carbon dioxide under the conditions of the oil group is 0.74 g/cm³, which closely matches the density of crude oil. Additionally, the viscosity of carbon dioxide is 0.0681 mPa·s, making it well-suited for carbon dioxide flooding. With an increase in the amount of injected carbon dioxide, the saturation pressure and gas-oil ratio of the crude oil also increase. As the pressure rises, carbon dioxide dissolves rapidly into the crude oil, resulting in a gradual increase in the gas-oil ratio, expansion coefficient, and saturation pressure. As the displacement pressure decreases, the degree of carbon dioxide displacement initially decreases slowly, followed by a rapid decrease. Moreover, an increase in the injection rate of carbon dioxide pore volume leads to a rapid initial improvement in oil-displacement efficiency, followed by a slower increase. Simultaneously, the gas-oil ratio exhibits a slow increase initially, followed by a rapid rise. Furthermore, as the displacement pressure increases, the solubility of carbon dioxide in water demonstrates a linear increase. These research findings provide valuable theoretical data to support the use of carbon dioxide flooding techniques for enhancing oil recovery.

The Lunnan oilfield, nestled within the Tarim Basin, represents a prototypical extra-low-permeability sandstone reservoir, distinguished by high-quality crude oil characterised by a low viscosity, density, and gel content. The effective exploitation of such reservoirs hinges on the implementation of carbon dioxide (CO₂) flooding techniques. This study, focusing on the sandstone reservoirs of Lunnan, delves into the mechanisms of CO₂-assisted oil displacement under diverse operational parameters: injection pressures, CO₂ concentration levels, and variations in crude oil properties. It integrates analyses on the high-pressure, high-temperature behaviour of CO₂, the dynamics of CO₂ injection and expansion, prolonged core flood characteristics, and the governing principles of minimum miscible pressure transitions. The findings reveal a nuanced interplay between variables: CO₂’s density and viscosity initially surge with escalating injection pressures before stabilising, whereas they experience a gradual decline with increasing temperature. Enhanced CO₂ injection correlates with a heightened expansion coefficient, yet the density increment of degassed crude oil remains marginal. Notably, CO₂ viscosity undergoes a substantial reduction under stratigraphic pressures. The sequential application of water alternating gas (WAG) followed by continuous CO₂ flooding attains oil recovery efficiency surpassing 90%, emphasising the superiority of uninterrupted CO₂ injection over processes lacking profiling. The presence of non-miscible hydrocarbon gases in segmented plug drives impedes the oil displacement efficiency, underscoring the importance of CO₂ purity in the displacement medium. Furthermore, a marked trend emerges in crude oil recovery rates as the replacement pressure escalates, exhibiting an initial rapid enhancement succeeded by a gradual rise. Collectively, these insights offer a robust theoretical foundation endorsing the deployment of CO₂ flooding strategies for enhancing oil recovery from sandstone reservoirs, thereby contributing valuable data to the advancement of enhanced oil recovery (EOR) technologies in challenging, low-permeability environments.

The Lunnan oilfield in the Tarim Basin, one of China’s major onshore oilfields with substantial geological reserves, faces particular challenges due to the complexity of its reservoir environment and the dispersion of remaining oil. Carbon dioxide, a greenhouse gas, presents an opportunity for enhanced oil recovery (EOR) and geological storage. In this context, the use of carbon dioxide for EOR can simultaneously address environmental concerns and improve oil recovery rates. This study focuses on the TI reservoir in the No. 2 well area of the Lunnan oilfield, employing advanced techniques to analyze the micro- and macro-characteristics of carbon dioxide flooding. Results: From the microscopic point of view, carbon dioxide flooding is mainly miscible with crude oil, which has a strong component exchange effect and can be displaced in the form of full pores, and the microscopic displacement efficiency is close to 100%. Macroscopically, under the combined injection and production of different injected hydrocarbon pore volume multiples (HCPVs), it is injected at the upper and lower layers of the interlayer and produced far away from the lower layer of the interlayer, with a total recovery rate of 52.83%. With the increase in the HCPV, the recovery increased rapidly at first and then slowly, and the HCPV at the demarcation point was 0.5, while the oil production rate increased in a wave-like manner and then decreased rapidly, and the HCPV at the breakthrough point of TI gas was 0.5. However, when the upper and lower layers far away from the interlayer are injected at the same time, the upper and lower layers of the interlayer are produced at the same time, and the total recovery rate can reach 83.02%. With the increase in the HCPV, the recovery rate increases rapidly at first and then slowly, and the HCPV at the turning point is 6.52. The oil production rate increases in a wave-like manner, then decreases rapidly, rises rapidly, and then decreases slowly in a wave-like manner. The HCPV at the breakthrough point of TI gas is 0.63, and the HCPV at the injection–production transition point is 0.63. The total recovery rate of carbon dioxide miscible displacement can reach 88.68% under the condition of separate injection and combined production with different injected hydrocarbon pore volume multiples. With the increase in the HCPV, the recovery increased rapidly at first and then slowly. The HCPV at the demarcation point was 6.5, the oil production rate increased in a wave-like manner, then decreased rapidly, increased rapidly, and then decreased slowly in a wave-like manner. The HCPV at the breakthrough point of TI gas was 0.63, and the HCPV at the injection–production transition point was 6.5. The research results provide data support for the physical reality of the microscopic and macroscopic sweep characteristics of carbon dioxide flooding in the Lunnan oilfield, Tarim Basin.

The evaluation of fault sealing is important research content in the early evaluation of underground gas storage construction. To accurately predict the pressure limit of the fault, a new method involving the analysis of fault lateral sealing and a comprehensive evaluation of mechanical stability is proposed in this paper. The results show that the Shale Gouge Ratio values of the faults in the reservoir building area are all greater than the critical value, which can ensure the lateral sealing of this area. After reservoir development, pressure failure causes the horizontal principal stress to decrease, but the effective normal stress and shear stress on the cross section increase, the fault stability index increases to 0.8, and the risk of fault reactivation risk increases. The simulation results show that when the pressure decreases to 35.5 MPa or increases to 65.5 MPa, the Fault F1 stability index first approaches the critical value of 1, and the fault appears to fall into slip instability. This study shows that the safe operating pressure range of this reconstructed gas storage reservoir is 35.5~65.5 MPa. The quantitative evaluation results are given in this paper, and it also gives early warning of potential risks.