The development of natural gas in tight sandstone gas reservoirs via CH₄-CO₂ replacement is promising for its advantages in enhanced gas recovery (EGR) and CO₂ geologic sequestration. However, the degree of recovery and the influencing factors of CO₂ flooding for enhanced gas recovery as well as the CO₂ geological rate are not yet clear. In this study, the tight sandstone gas reservoir characteristics and the fluid properties of the Sulige Gasfield were chosen as the research platform. Tight sandstone gas long-core displacement experiments were performed to investigate (1) the extent to which CO₂ injection enhanced gas recovery (CO₂-EGR) and (2) the ability to achieve CO₂ geological storage. Through modification of the injection rate, the water content of the core, and the formation dip angle, comparative studies were also carried out. The experimental results demonstrated that the gas recovery from CO₂ flooding increased by 18.36% when compared to the depletion development method. At a lower injection rate, the diffusion of CO₂ was dominant and the main seepage resistance was the viscous force, which resulted in an earlier CO₂ breakthrough. The dissolution of CO₂ in water postponed the breakthrough of CO₂ while it was also favorable for improving the gas recovery and CO₂ geological storage. However, the effects of these two factors were insignificant. A greater influence was observed from the presence of a dip angle in tight sandstone gas reservoirs. The effect of CO₂ gravity separation and its higher viscosity were more conducive to stable displacement. Therefore, an additional gas recovery of 5% to 8% was obtained. Furthermore, the CO₂ geological storage exceeded 60%. As a consequence, CO₂-EGR was found to be feasible for a tight sandstone gas reservoir while also achieving the purpose of effective CO₂ geological storage especially for a reservoir with a dip angle.

Polymer microspheres with temperature and salt resistance were synthesized using the anti-suspension polymerization method, incorporating the functional monomers AMPS, AM, and AA. To enhance their self-gelling properties, the microspheres were designed with a core–shell structure. The shell is composed of a polymeric surfactant, fatty alcohol polyoxyethylene ether methacrylate (AEOMA), which serves as a thermosensitive crosslinking agent, enabling self-crosslinking upon shell decomposition, addressing compatibility with reservoir pore throat dimensions. Comprehensive characterizations including infrared spectroscopy, scanning electron microscopy, optical microscopy, and laser particle size analysis were conducted. The microspheres exhibited successful synthesis, a nanoscale size, and regular spherical morphology. They demonstrated excellent temperature and salt resistance, making them suitable for high-temperature, high-salinity reservoir profile control. With a stable three-dimensional network structure, the microspheres displayed good expansion behavior due to hydrophilic groups along the polymer chains, resulting in favorable water affinity. Even after aging, the microspheres maintained their gelling state with a distinct and stable microscopic network skeleton. They exhibited superior plugging performance in low-permeability reservoirs, while effectively improving water absorption profiles in reservoirs with permeability contrasts of 10 to 80, thereby enhancing oil recovery.