Oil extraction is shifting towards high-temperature and high-pressure environments, which leads to the deterioration of the rubber material used in packer rubber cylinders, ultimately resulting in sealing failure. Hence, we propose enhancing the configuration of the rubber cylinder by incorporating a composite material consisting of metal and rubber. Additionally, we suggest integrating springs at the shoulders to fabricate a spring-embedded shoulder protection packer rubber cylinder. ABAQUS 2023 software was employed to simulate the packer setting process, investigating the variations in compression distance between a conventional packer rubber cylinder and a spring-embedded shoulder protection packer rubber cylinder. The results showed that at 25 °C and 177 °C, the compression distance of the fully seated spring-embedded shoulder protection packer rubber cylinder was reduced by 3% compared to the traditional packer rubber, Mises stress was reduced by 14%, and the sealing performance evaluation coefficient K of the rubber cylinder was increased by 2% to 10%.The stress in the spring-embedded shoulder protection packer rubber cylinder is primarily concentrated between the spring and the wire mesh, effectively ensuring the performance of the rubber cylinder and mitigating any potential decrease in sealing performance caused by internal stress concentration. The spring-embedded protective rubber cylinder will not experience shoulder protrusion during the sealing process. The incorporation of a spring-embedded shoulder protection mechanism in the packer rubber cylinder enhances the contact stress between the rubber cylinder and casing tube, mitigates stress concentration within the rubber cylinder, resolves shoulder protrusion issues, and ultimately improves both sealing performance and service life.

The fracture-cavity carbonate reservoir in Tahe oilfield is buried deep (more than 5000 m). The reservoir has low permeability, strong heterogeneity, large size, diverse forms of connectivity, and complex spatial distribution. In conventional water flooding, it is difficult to improve oil recovery effectively because of small water flood sweep and large injection pressure. Pressure flooding is a new water injection technique that can change the reservoir pore space. Combined with an oil displacement agent, pressure flooding is expected to improve the recovery rate of carbonate reservoirs. In this paper, the influence factors of pressure flooding technology are studied, and a set of surfactant systems suitable for high-temperature and high-salt reservoirs is developed. The results show that only an appropriate injection flow can produce microfractures. Only an appropriate displacement rate can optimize the effects of pressure flooding. With an increase in crude oil viscosity, the recovery rate after pressure flooding decreases gradually. A complex fracture network is formed in reservoirs after pressure flooding. The new surfactant system has good interfacial tension reduction properties and excellent stability. Pressure flooding experiments with the addition of a surfactant showed that the system can help to improve the recovery of pressure flooding.

Multi-scale fractures in Northwest Oilfield are extremely developed. Fractures in both oil flow channels and water channels lead to the phenomenon of water channeling in the later stages of reservoir development, which may be affected by the bottom water cone. Gel plugging agents are widely used in the treatment of this phenomenon because of their low cost and high-water plugging efficiency. However, because there is often residual oil in small-scale fractures, the pressure law of different grades of differential fractures on gel is not clear, thus leading to low gel application efficiency and low oil recovery. There is still a lack of effective means through which to understand the regularity of shielding the remaining oil with gel strength and fractures of different grades. In this study, we conducted a novel analysis of the law of shielding oil production in fractured reservoirs. The gelling and rheological properties of anti-temperature gels (ATGs) with different strengths were studied. The plugging rate of oil phase was 96.39%, and that of water phase was 25.37%. ATG showed good oil–water selectivity. The influences of different grades of differential fractures on the production law of shielding the remaining oil were also studied, as well as the corresponding influence law chart. When the gel strength was in the range of 2.0–28.1 Pa and the fracture grade difference was 5–10, the recovery ratio was increased by 10.6–24%. The enhanced oil recovery can be quantitatively predicted by the scale of reservoir fractures and the strength of gel used. It has a certain guiding role for the field application of gel to efficiently shield residual oil in differential fractures.

Low-permeability near-critical volatile reservoirs are characterized by light oil, complex fluid phase, and strong reservoir inhomogeneity, etc. Purely injecting CO₂ will create a series of problems, such as serious gas channeling, low sweep efficiency, and low oil recovery. Therefore, in this paper, through a combination of experiments and simulations and in the process of studying the problem from simple to complex, we carried out phase equilibrium experiments for CO₂-near-critical volatile oil and CO₂-near-critical volatile oil-formation water, as well as experiments for minimum miscible pressure of slim-tube with pure CO₂ and CO₂–water co-injection to the comparative study of the miscible characteristics and displacement oil efficiency between pure CO₂ injection and CO₂–water co-injection. It provides an important reference for improving oil recovery by CO₂–water co-injection in low-permeability near-critical volatile reservoir. The results of CO₂-near-critical volatile oil/CO₂-near-critical volatile oil-formation water phase equilibrium experiments show that the saturation pressure, density, and gas–oil ratio of the system increase, and the viscosity decreases with the increase in CO₂ injection. In the three-phase system of CO₂-near-critical volatile oil-formation water, the CO₂ content in the flash gas of crude oil, gas–oil ratio, and gas–water ratio are negatively correlated with the water saturation. The results of slim-tube experiments and simulations on the miscible characteristics and displacement oil efficiency of pure CO₂ injection and CO₂–water co-injection show that the recovery degree of crude oil under CO₂–water co-injection is higher than that of pure CO₂ injection, and the CO₂ dissolved transition section in oil and gas is shorter and the gas breakthrough time is later under CO₂–water co-injection, which effectively increases the sweep efficiency and improves the degree recovery of crude oil. When CO₂–water co-injection, the ratio of water is higher, the later the gas–oil ratio rises, the later the CO₂ breakthrough, and the higher the degree of crude oil recovery. It indicates that when CO₂–water co-injection, the ratio of water is higher, the more CO₂ is dissolved in water, which effectively inhibits the occurrence of gas channeling and increases the sweep area, thus improving the degree recovery of crude oil. The research results of this paper provide an experimental basis and theoretical foundation for CO₂–water co-injection for enhanced crude oil recovery in low-permeability near-critical volatile reservoirs.