In addressing the issue of poor control over gas permeability during the CO₂ flooding process in ultra-low permeability reservoirs, this study proposes the use of a low interfacial tension viscosity-increasing system as a substitute for water in CO₂–water alternating flooding to enhance CO₂ mobility control and increase oil recovery. The performance of the system was evaluated through tests of viscosity, interfacial tension, wettability, and emulsification properties, and the injection behavior and gas channeling prevention effect of the viscosity-increasing system with CO₂ alternate flooding were investigated. The results indicate that the low interfacial tension viscosity-increasing fluid exhibits good thickening properties, interfacial activity, hydrophilic wettability, and oil–water emulsification performance, also demonstrating strong environmental adaptability. The CO₂–low interfacial tension viscosity-increasing fluid alternate flooding shows good injectivity in ultra-low permeability cores (1.085 mD). Following water flooding in heterogeneous ultra-low permeability cores, the implementation of CO₂ low interfacial tension viscosity-increasing fluid alternate flooding can lead to a 15.91% increase in overall recovery compared to water flooding, outperforming CO₂ flooding and CO₂–water alternating flooding. The mechanisms by which the CO₂ low interfacial tension viscosity-increasing fluid enhances oil recovery include reducing interfacial tension, improving mobility ratio, altering rock surface wettability, and emulsification effects. The low interfacial tension viscosity-increasing systems demonstrate effective mobility control and oil displacement capabilities and synergistically enhance the efficiency of CO₂, presenting potential application prospects in the development of CO₂ flooding in ultra-low permeability reservoirs.

During gas production, the wellbore operates under high temperature and high pressure conditions, where gas–liquid two-phase flow is commonly present. Thus, it is important to understand the holdup of different flow patterns of gas–liquid two-phase flow in the wellbore. Currently, prediction models for flow patterns and holdup are mainly based on experimental data obtained under normal temperature and pressure, judged by researchers’ subjective observations, resulting in the lack of a unified flow pattern boundary so far. This article uses CFD simulation to study the characteristics of high temperature and high pressure gas–liquid two-phase flow in wellbores and obtains data such as flow pattern, probability density distribution of gas content, and liquid holdup. The results indicate that pressure is the dominant factor affecting the transition of gas–liquid two-phase flow patterns in wellbores. Under high temperature and pressure, each flow pattern has unique probability density distribution characteristics of gas content, which can be used as a basis for flow pattern identification. Flow pattern diagrams of gas–liquid two-phase flow at room temperature and pressure as well as high temperature and high pressure were drawn, and a boundary model for the transition of gas–liquid two-phase flow patterns in wellbores under the influence of variable pressure was established, verifying the rationality of the flow patterns’ transition boundaries. Based on the simulation of high temperature and high pressure gas–liquid two-phase flow in the wellbore, a calculation model for gas–liquid two-phase flow in the wellbore was established. The absolute percentage error between this model and the Fluent simulation results is within 10%, which can achieve the calculation of gas–liquid two-phase flow in the wellbore under different temperature and pressure conditions.

This study investigates the use of fly ash to mitigate the long-term performance degradation of Portland cement-based sealing materials in high-salinity environments, such as those found in gas storage reservoirs. We systematically evaluated the evolution of material properties under different temperatures and curing periods. Our integrated methodology combining mechanical tests, microstructural analysis, and chloride migration assessment, reveals a multi-faceted mechanism by which fly ash enhances chloride resistance. The key findings demonstrate that reactive Al₂O₃ in fly ash promotes the formation of Friedel’s salt, increasing chemical chloride binding and reducing the chloride ingress rate in the Portland cement–Fly ash system (PFS) to only 26.6% of that in the Portland Cement system (PCS). Concurrently, the pozzolanic reaction consumes portlandite (Ca(OH)₂), forming stable C-A-S-H gel and refining the pore structure by filling interconnected channels. This nanoscale pore refinement decreased permeability by nearly an order of magnitude. After 90 days of curing in 90 °C saline solution, PFS achieved a compressive strength of 28.2 MPa and maintained an exceptionally low internal chloride content of 0.08 wt.%, demonstrating superior long-term durability. This work clarifies the synergistic mechanisms of fly ash modification and temperature effects, providing a theoretical basis for optimizing sealing materials for deep geological reservoirs and experimental support for the application of fly ash in high-temperature, high-salinity engineering environments.

Tight-oil reservoirs are abundant but characterized by poor physical properties and strong heterogeneity. CO₂ flooding is an important technique for enhanced oil recovery (EOR) and carbon storage, yet CO₂ channeling remains a critical issue due to its high mobility, and existing anti-channeling methods have limitations. In this work, a low-interfacial-tension viscoelastic fluid containing amphiphilic nanoparticles (LFNA) was formulated by combining a small-molecule viscosifier (LFLM) with amphiphilic nanoparticles (LQNA). Its performance and synergistic effect with CO₂ flooding were systematically evaluated. The LFNA formulation is simple (0.4 wt% LFLM + 0.01 wt% LQNA-3), exhibiting a viscosity of 5.82 mPa·s, an interfacial tension of 0.0296 mN/m, and predominantly elastic behavior (tan δ = 0.791). It shows good tolerance to temperature, salinity, and pH variation, favorable injectivity in tight cores (Kg = 0.45 − 1.07 mD), and selective plugging capability. Core-flooding experiments in both homogeneous and heterogeneous models demonstrate that CO₂–LFNA alternating injection after waterflooding outperforms continuous CO₂ flooding in EOR. In heterogeneous models, the LFNA slug preferentially plugs high-permeability channels, expands sweep volume, and effectively mobilizes residual oil in low-permeability zones, with incremental recoveries of 12.49% and 15.74% for low- and high-permeability cores, respectively. Overall, the combined incremental recovery of CO₂–LFNA alternating flooding (14.26%) exceeds that of water–LFNA alternating flooding (11.49%) and continuous CO₂ flooding (9.85%). These results confirm that LFNA provides a synergistic effect of plugging, oil-washing, and sweep improvement. Using LFNA for CO₂ channeling control is feasible and effective, and it also benefits CO₂ storage and carbon reduction.