CCUS technologies for enhanced oil and gas recovery rely on the unique properties of CO₂ to enable efficient displacement and secure geological storage, presenting a cost-effective and practical approach to mitigate greenhouse gas emissions and support global carbon neutrality objectives. This study systematically evaluates the development effects of different CO₂ flooding methods in low-permeability reservoirs through 1 m artificial long-core physical simulation experiments and reveals the synergistic enhancement mechanisms of foam-CO₂ alternating flooding. The core model is constructed by the harmonic permeability sorting method (permeability 2.6–3.9 mD, porosity 6.35–11.13%), and the displacement characteristics of four schemes are compared and analyzed, including continuous CO₂ gas flooding, water–gas alternating flooding, foam-assisted continuous flooding, and foam-CO₂ alternating flooding. The results show that the foam-CO₂ alternating flooding (0.15 PV slug) performs optimally, with a recovery efficiency of 60.75%, which is 23.69 and 7.49% higher than that of continuous gas flooding and water–gas alternating flooding, respectively, and the gas channeling breakthrough time is delayed to 0.48 PV (29.7% later than traditional gas flooding). Its synergistic enhancement mechanisms include: (1) the Jamin effect of foam reduces gas mobility by 73%, forcing the fluid to divert to medium-low permeability regions; (2) the compound surfactant (0.5% AEO-9 + 0.3% CHSB) works synergistically with CO₂ to significantly enhance the microscale oil displacement efficiency; (3) the coupling analysis of pressure response and production dynamics confirms a three-level synergistic mechanism of “mobility control-interfacial regulation-sweep volume expansion”. Furthermore, the core construction method based on harmonic permeability effectively reduces the interference of heterogeneity on experimental results, providing an experimental basis for the optimization of CO₂ flooding injection parameters in low-permeability reservoirs and the adaptability evaluation of CCUS technologies. The research results provide theoretical support and technical paths for the dual goals of efficient development of low-permeability reservoirs and carbon emission reduction.

To overcome the production bottleneck induced by the high viscosity of extra-heavy oil and resolve the issues of limited efficiency in traditional thermal oil recovery methods (including cyclic steam stimulation (CSS), steam flooding, and steam-assisted gravity drainage (SAGD)) as well as the fragmentation of existing viscosity reducer evaluation systems, this study establishes a multi-dimensional evaluation system for the effectiveness of viscosity reducers, with stage-averaged remaining oil saturation as the core benchmarks. A “1D static → 2D dynamic → 3D synergistic” progressive sequential experimental design was adopted. In the 1D static experiments, multi-gradient concentration tests were conducted to analyze the variation law of the viscosity reduction rate of viscosity reducers, thereby screening out the optimal adapted concentration for subsequent experiments. For the 2D dynamic experiments, sand-packed tubes were used as the experimental carrier to compare the oil recovery efficiencies of ultimate steam flooding, viscosity reducer flooding with different concentrations, and the composite process of “steam flooding → viscosity reducer flooding → secondary steam flooding”, which clarified the functional value of viscosity reducers in dynamic displacement. In the 3D synergistic experiments, slab cores were employed to simulate the SAGD development process after multiple rounds of cyclic steam stimulation, aiming to explore the regulatory effect of viscosity reducers on residual oil distribution and oil recovery factor. This novel evaluation system clearly elaborates the synergistic mechanism of viscosity reducers, i.e., “chemical empowerment (emulsification and viscosity reduction, wettability alteration) + thermal amplification (steam carrying and displacement, steam chamber expansion)”. It fills the gap in the existing evaluation chain, which previously lacked a connection from static performance to dynamic displacement and further to multi-process synergistic adaptation. Moreover, it provides quantifiable and implementable evaluation criteria for steam–chemical composite flooding of extra-heavy oil, effectively releasing the efficiency-enhancing potential of viscosity reducers. This study holds critical supporting significance for promoting the efficient and economical development of extra-heavy oil resources.

This study investigates the acid–rock reaction kinetics and their implications for enhancing tight limestone reservoir stimulation through systematic experiments. Using 14 tight limestone cores, we evaluate the dynamic behavior of single-phase and gelled acids (12%, 15%, and 20% HCl) under controlled reservoir conditions (80 °C; 10–180 min). Three key findings emerge: (1) gelled acids initially exhibit higher reaction rates (0.897%/min) compared to single-phase acids (0.453%/min at 10 min), but their efficiency converges over extended durations; (2) reaction rates for both acid types follow the quadratic decay pattern over time (R² > 0.95), contrasting with conventional linear assumptions; and (3) reaction time is identified as the primary factor governing permeability enhancement (up to 29,200% improvement), outweighing acid concentration and type. The results demonstrate that concentrations above 15% significantly enhance etching efficiency, while single-phase acids with moderate reaction rates achieve an optimal balance between penetration depth and surface integrity. By integrating gravimetric analysis with permeability–porosity mapping, this work provides a predictive framework for acidizing process design in low-permeability reservoirs. The findings offer practical insights for optimizing acid fracturing operations, emphasizing time-controlled strategies over traditional concentration-focused approaches.

CO₂ flooding technology has been established as a key technique that is both economically viable and environmentally sustainable, achieving enhanced oil recovery (EOR) while advancing CCUS objectives. This study addresses the challenge of optimizing CO₂ flooding well patterns in tight oil reservoirs through a geological–engineering integrated approach. A semi-analytical model incorporating startup pressure gradients and miscible/immiscible two-phase flow was developed to dynamically adjust injection intensity. An effective driving coefficient model considering reservoir heterogeneity and fracture orientation was proposed to determine well pattern boundaries. Field data from Blocks A and B were used to validate the models, with the results indicating optimal injection intensities of 0.39 t/d/m and 0.63 t/d/m, respectively. Numerical simulations confirmed that inverted five-spot patterns with well spacings of 240 m (Block A) and 260 m (Block B) achieved the highest incremental oil production (3621.6 t/well and 4213.1 t/well) while reducing the gas channeling risk by 35–47%. The proposed methodology provides a robust framework for enhancing recovery efficiency in low-permeability reservoirs under varying geological conditions.