Chemical flooding technology has been widely applied in medium- and high-permeability reservoirs. However, it is rarely applied in low-permeability reservoirs, which is mainly limited by reservoir physical properties, chemical agents, injection capacity, and so forth. In this paper, a novel chemical formula used in low-permeability reservoirs was developed. In response to the low-permeability reservoir geological characteristics, fluid properties, and water flooding development of the target block, some experimental studies and field project studies of polymer–surfactant flooding were carried out. The surfactant structure and polymer molecular weight were determined from laboratory experiments. The polymer–surfactant binary system was synthesized. It had good injectivity in low-permeability reservoirs, and its oil recovery efficiency increased over 10% in the laboratory experiment. The result was higher than that of single chemical flooding. After field implementation, initial results have been achieved with an increase in injection pressure. The chemical formula can effectively alleviate intra-layer and inter-layer contradictions in the reservoir. The project has increased oil output by 77,700 t and the recovery factor by 3.5%. The experience and lessons were of great significance for the development of chemical flooding in high-temperature, high-salinity, and low-permeability reservoirs.

In order to meet the requirements of tertiary oil recovery technology in a low-permeability, dense, and high-salt reservoir, gaseous SiO₂ nanoparticles were modified with trichloro(octyl)silane and aminopropyl triethoxysilane by interface protection modification, and amphiphilic Janus-SiO₂ nanoparticles with hydrophobic carbon chain and hydrophilic amino group were prepared. The basic properties of amphiphilic nanoparticle dispersion were evaluated by surface interfacial tension and wettability tests, and the oil displacement effect of amphiphilic nanoparticle dispersion was investigated. The results show that the size distribution of Janus-SiO₂ nanoparticles with n-octyl as the hydrophobic carbon chain and amino group as the hydrophilic headgroup is uniform, and they have good dispersion in mineralized water. The change of salinity has little effect on the interfacial activity. The interfacial tension between the amphiphilic nanoparticle dispersion and crude oil is always on the order of 10^-2 mN/m, and the amphiphilic nanoparticle dispersion has good interfacial activity. Amphiphilic nanoparticles adsorbed on the rock surface can enhance the hydrophilicity of the rock surface. Amphiphilic nanoparticle dispersion liquid has a certain effect of improving oil recovery in the environment of high-salt and low-permeability reservoir. Under the condition of 65 °C and salinity of 8000 mg/L, injection of 0.5 PV 0.05% amphiphilic nanoparticle dispersion can enhance oil recovery by 14.6% on the basis of water flooding. The mechanism of amphiphilic nanoparticles to improve the recovery efficiency of low-permeability tight high-salt reservoir mainly includes reducing the oil-water interfacial tension, changing the rock wettability, and enhancing the shear viscosity of oil and water interface and the interfacial film strength, which has excellent potential application prospect in the development of low-permeability tight high-salt reservoir.

CO₂ flooding has been successfully used in numerous oil fields as a strategy to improve oil recovery. However, several issues, including gas channeling, profile control, CO₂ sweep efficiency, oil displacement efficiency, etc., have been revealed in the development of CO₂ flooding, particularly in a fractured reservoir. In this paper, in view of the focus issues, a novel multistage plugging system is investigated, mainly including the polymer-gel system. The static and dynamic polymer-gel system performances are comprehensively evaluated. Based on the features of a fractured reservoir, a multiscale fracture model is built, and the applicable limits of the polymer-gel system are proposed. When the fracture width is greater than 0.65 mm, the plugging effect of the polymer gel becomes worse. However, the plugging effect is clearly strengthened by the use of polymer gel, foam, and bulk particles, which also significantly improves the injection-production profile. The experimental results show that CO₂ flooding could increase the ultimate recovery by 7.67%.

Carbon capture, utilization, and storage (CCUS) technology has emerged as a pivotal measure in mitigating global climate change. Notably, CO₂-EOR is esteemed for its dual function of sequestering CO₂ and enhancing oil recovery. However, this process presents challenges related to asphaltene deposition during CO₂ flooding, leading to reservoir damage, such as pore plugging. This study systematically manipulated the factors inducing CO₂-induced asphaltene deposition, elucidating the mechanisms and magnitudes of asphaltene precipitation. Additionally, the study investigated the efficacy of carbon quantum dots (CQDs) in mitigating asphaltene deposition. Experimental findings indicated a positive correlation between asphaltene deposition and level of asphaltene content, CO₂ injection ratio, and temperature. Moreover, with an increase in experimental pressure, the asphaltene deposition rate demonstrated an initial increase followed by a subsequent decline. Leveraging their favorable compatibility with asphaltene, CQDs effectively suppressed the aggregation behavior of asphaltene. In the presence of CQDs, the onset of asphaltene precipitation was delayed from 45 V% to 55 V%, with the highest inhibition rate reaching approximately 36% at an optimal CQD concentration of 20 mg/L. This study proposes a novel approach to address asphaltene deposition issues in CO₂-EOR processes, contributing to the enhancement of recovery rates in low-permeability reservoirs.