Due to the development characteristics of low‐permeability reservoirs such as weak water absorption, slow development of water injection, and strong pressure sensitivity, the effect of water injection in low‐permeability reservoirs is quite different from that in medium and high‐permeability reservoirs. Therefore, in oilfield development, it is important to study the movement law of the waterflooding front in low‐permeability reservoirs. In this paper, taking the Jilin oilfield as an example, a geological model of Xinmin 23 Block was established for the numerical simulation analysis considering the heterogeneity of low‐permeability reservoirs. In addition, artificial cores were manufactured to conduct the physical experiment of the waterflood front advance of cores with different physical properties under the influence of various factors such as the fracture and the range by the constant‐velocity flooding. Based on the numerical simulation and the physical experiment, the movement law of the waterflood front was analyzed and a basic method for evaluating the waterflooding development in low‐permeability reservoirs was established to provide feasible insights for the waterflooding development in low‐permeability reservoirs. In this paper, numerical simulation and experimental studies were performed on the effect of the waterflooding development of Xinmin 23 Block in the Jilin oilfield. The evaluation results obtained were consistent with the actual oil production providing a theoretical basis for judging the accurate advance time from the waterflood front to the production well in actual oil production.

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.

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.

Considering the issue caused by the tail gas of viscous oil fire flooding, which carries a large amount of jeopardizing liquid, the Liaohe Oilfield No. 56 desulfurization station applies the vertical processing separator as the main dehumidification equipment for moisture elimination. However, the lack of study on the separator’s gas–liquid separation mechanism leads to unclear recognition of the equipment’s processing capability, which easily causes the desulfurization tower to water out, and the tail gas gathering network system to get frozen and blocked. To result in a solution to the problems above, numerical simulation software is applied in this paper based on the oil field’s actual operation data to establish a mathematical model for calculation, which may assist in simulating the gas–liquid separating process, in analyzing the flow field distribution within the separator, and in studying the dehumidification mechanism in terms of influencing factors and laws of equipment dehumidification efficiency. Finally, this helps optimizing the separator’s structure based on the calculation results. The research results provide a theoretical basis and technical support for the practical application of dehumidification equipment in oil fields.