The purpose of this study is to investigate the use of SiO₂ nanoparticles in assisting with surfactants and polymers for tertiary oil recovery, with the aim of enhancing oil recovery. The article characterizes the performance of SiO₂ nanoparticles, including particle size, dispersion stability, and zeta potential, evaluates the synergistic effects of nanoparticles with alpha-olefin sulfonate sodium (AOS) surfactants and hydrolyzed polyacrylamide (HPAM) on reducing interfacial tension and altering wettability, and conducts core flooding experiments in rock cores with varying permeabilities. The findings demonstrate that the particle size decreased from 191 nm to 125 nm upon the addition of SiO₂ nanoparticles to AOS surfactant, but increased to 389 nm upon the addition of SiO₂ nanoparticles to HPAM. The dispersibility experiment showed that the SiO₂ nanoparticle solution did not precipitate over 10 days. After adding 0.05% SiO₂ nanoparticles to AOS surfactant, the zeta potential was −40.2 mV, while adding 0.05% SiO₂ nanoparticles to 0.1% HPAM resulted in a decrease in the zeta potential to −25.03. The addition of SiO₂ nanoparticles to AOS surfactant further reduced the IFT value to 0.19 mN/m, altering the rock wettability from oil-wet to strongly water-wet, with the contact angle decreasing from 110° to 18°. In low-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for enhanced oil recovery increased the recovery rate by 24.5% over water flooding. The recovery rate increased by 21.6% over water flooding in low-permeability rock core experiments after SiO₂ nanoparticles were added and surfactants and polymers were utilized for oil displacement. This is because the nanoparticles blocked small pore throats, resulting in increased resistance and hindered free fluid flow. The main causes of this plugging are mutual interference and mechanical entrapment, which cause the pressure differential to rise quickly. In high-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for oil recovery increased the recovery rate by 34.6% over water flooding. Additionally, the recovery rate increased by 39.4% over water flooding with the addition of SiO₂ nanoparticles and the use of AOS surfactants and HPAM for oil displacement. Because SiO₂ nanoparticles create wedge-shaped structures inside highly permeable rock cores, they create structural separation pressure, which drives crude oil forward and aids in diffusion. This results in a comparatively small increase in pressure differential. Simultaneously, the nanoparticles change the rock surfaces’ wettability, which lowers the amount of crude oil that adsorbs and improves oil recovery.

At present, there are relatively few studies on the exploitation of geothermal resources in depleted high-temperature gas reservoirs with carbon dioxide (CO₂) as the heat-carrying medium. Taking the high-temperature gas reservoir of the Huangliu Formation in the Yingqiong Basin as the research object, we construct an ideal thermal and storage coupling model of a CO₂ plume geothermal system using COMSOL6.2 software to conduct a sensitivity analysis of geological parameters in the operation of a CO₂ plume geothermal system. The simulation results show that, compared with medium- and low-temperature reservoirs, a high-temperature reservoir exhibits higher fluid temperature in the production well and a higher heat extraction rate owing to a higher initial reservoir temperature but has a shorter system operational lifetime; the influence of the thermal conductivity of a thermal reservoir on the CO₂ plume geothermal system is relatively minor, being basically negligible; and the thinner the thermal reservoir is, the faster the fluid temperature in the production well decreases and the shorter the thermal breakthrough time. These findings form a basis for selecting heat extraction areas for CO₂ plume geothermal systems and also provide a theoretical reference for future practical CO₂ plume geothermal system projects.

CO₂ plume geothermal systems (CPGS) hold significant potential for geothermal energy extraction due to their dual benefits of carbon sequestration and efficient heat transfer. Existing studies primarily focus on macroscopic models of geothermal systems, with limited evaluation of real thermal reservoir cores in terms of CPGS heat extraction performance. This study investigates the seepage and heat transfer characteristics of CO₂ under various injection conditions through a combination of experiments and numerical simulations. Experimental results indicate that under the tested conditions, CO₂ exhibits 20–50% higher heat transfer capacity compared to distilled water. The heat transfer capacity increases with injection flow rate, while injection temperature shows a relatively limited influence under high-velocity seepage conditions. Specifically, at low injection flow rates, lower injection temperatures result in higher heat transfer capacity due to the increased thermal driving force between CO₂ and the reservoir rock. Microscale seepage-heat transfer simulations reveal that an increase in injection flow rate enhances CO₂ flow velocity within the pore network, expands the swept volume, and consequently strengthens convective heat transfer and increases the effective heat exchange area. Additionally, higher thermal reservoir temperatures establish a greater temperature gradient between the working fluid and rock, thereby enhancing heat transfer between CO₂ and the reservoir rock. The findings of this study provide valuable insights for optimizing CPGS design, particularly in understanding the impact of injection conditions on heat transfer capacity, with both practical engineering and theoretical implications.