Worldwide practices have proven that gas-assisted gravity drainage can obviously enhance oil recovery, and this technology can be especially effective for reservoirs with a thick formation and large inclination angle. For the successful implementation of this process, a key technology is the stable control of gas–oil interface during gas injection. For a detailed exploration of this technique, a three-stage permeable visual model was designed and manufactured, with permeability decreasing from top to bottom, thus, a reverse rhythm reservoir was effectively modeled. Then the experiment concerning CO₂-assisted gravity drainage was carried out with the adoption of a self-developed micro visual displacement device. This study mainly focused on the micro migration law of gas–oil interface and the development effects of CO₂-assisted gravity drainage. According to the experiments, CO₂ fingering somewhat happens in the same permeable layer from the beginning of gas injection. However, phenomena of “wait” and “gas–oil interface self-adjustment” occur instead of flowing into the next layer when the injected CO₂ reaches the boundary of the next lower permeability layer through the dominant channel. By the “gas–oil interface self-adjustment”, the injected CO₂ first enters into the pores of the relative higher permeability layer to the greatest extent, and thus expands the sweep volume. Futhermore, in the process of CO₂ injection, obvious gas channeling occurs in the low permeability layer directly connected to the outlet, resulting in low sweep efficiency and poor development effect. After connecting the core with lower permeability at the outlet, the development indexes of the model, such as the producing degree of the low permeability layer, the oil recovery before and after gas breakthrough, are significantly improved, and the recovery degrees of the medium permeability layer and the high permeability layer are also improved, and the overall recovery factor is increased by 12.38%. This “gas–oil interface self-adjustment” phenomenon is explained reasonably from the two scales of macroscopic flow resistance and microscopic capillary force. Finally, the enlightenments of the new phenomenon are expounded on the application of gas-assisted gravity drainage on site and the treatment of producers with gas breakthrough in gas injection development.

With its abundant reserves in the world, carbonate reservoir has become one of the main targets for future oil and gas development. Accelerating the research and development of carbonate reservoirs is thus significant to enhance the world’s energy supply capacity. However, there have been some problems in the evaluation of carbonate reservoirs for a long time, such as low description accuracy of fractured-vuggy bodies, diverse flow patterns, and difficult reservoir simulation and prediction. Compared with traditional manufacturing methods, 3D printing is an advanced manufacturing technology of rapid prototyping. It has the characteristics of short manufacturing cycle, not limited by the complexity of parts, material saving and energy saving, and thus has unparalleled advantages in reservoir rock analysis. In this paper, the carbonate core of Yingmaili region in Tarim Basin was taken as the research object, and the uniaxial compression mechanical properties of three small cores printed with different materials were designed and tested by using KINGS-600 3D photocuring printer and photosensitive resin materials. After that, UV-9400S white resin with the highest strength is selected as the printing material of the full diameter core model of the karst cave. Combined with the CT scanning of the formed samples, the control accuracy concerning the cave morphology of the 3D printed samples was tested which adequately proves that flow experiments can be carried out with 3D printed core samples. At last, the article also analyzes the shortcomings of 3D printing technology, and points out the direction for its large-scale application in the field of oil and gas exploitation. This study can especially provide a reference for the application of 3D printing technology in the field of carbonate reservoir development, and ultimately promote the sustainable supply of oil and gas resources.

Velocity sensitivity refers to the possibility and degree of reservoir permeability decline caused by the migration of various particles in the reservoir rock due to the increase in fluid flow velocity and the blockage of pore channels. To improve the development results of M reservoir in Karamay Oil field, two reservoir cores were selected to carry out velocity sensitivity experiments. The permeability of No. 1 core decreases obviously when the flow rate is greater than 0.04 mL/min. Therefore, it can be considered that the injection rate of velocity sensitivity is between 0.04 and 0.06 mL/min, and the displacement rate should be less than 0.04 mL/min in the core displacement experiment. When the flow rate is greater than 0.5 mL/min, the permeability of No. 2 core decreases significantly. This is mainly due to the high permeability and critical velocity of No. 2 core. The study can provide a basis for the selection of displacement velocity in core displacement experiments, and also provide a reference for the determination of reasonable injection-production velocity in actual production.

To address the water sensitivity of conglomerate reservoirs, a series of core sensitivity tests were conducted to evaluate the effects of varying ionic content. These findings serve as a foundation for improving reservoir fluid dynamics and optimizing the concentration of anti-swelling agents in water flooding operations. The experiments revealed a marked disparity in response between cores with differing permeabilities. In Core No. 5, characterized by low permeability, a 0.5% anti-swelling agent achieved only a modest 7.47% reduction in water sensitivity. Conversely, in the higher-permeability Core No. 8, a 5% anti-swelling agent significantly reduced the water sensitivity index by 44.84% while enhancing permeability. Further, two displacement strategies—gas flooding following water flooding and water flooding after gas injection—were tested to assess the potential of CO2 water-alternating-gas (WAG) displacement. CO2 injection after water flooding in Core No. 5 increased oil recovery by 9.24%, though gas channeling, evidenced by a sharp rise in the gas-liquid ratio, emerged as a critical concern. In Core No. 8, water flooding following gas injection failed to improve recovery, likely due to pronounced water sensitivity, reduced permeability, and the formation of dominant flow channels under high displacement pressure, which limited sweep efficiency.

With the gradually deep development of oil field, the remaining oil in reservoir become more scattered, to exploit them within the high water-cut pay become extremely difficult. Based on the characteristics of extremely high water-cut reservoir, three large scale physical models with different injection-production well patterns are designed. Through the analysis of oil production rate and the data of Computed Tomography (CT) scanning, the change law of fluid content within the core are obtained; The new calculation method of sweep efficiency for waterflooding within non-homogeneous models are set up in accordance with the CT number at different waterflooding stages. Furthermore, the development results of different plans are compared with each other, both injection and production with horizontal wells at low-permeability formation have the best recovery, because the displacement fluid can reach the places in reservoir where conventional waterflooding cannot. Therefore, this well pattern is the optimum plan for the positive rhythm model in this experiment, and the development strategy optimization is realized for high water-cut thick oil formation.

Due to the characteristics of reservoir formation, the producing level of low permeability reservoir is relatively very low. It is hard to obtain high recovery through conventional development schemes. Considering the tight matrix, complex fracture system, low production level of producers, and low recovery factor of M block in Xinjiang oilfield, it is selected for on-site pilot test of nitrogen foam flooding. Detailed flooding scheme is made and the test results are evaluated respectively both for producers and injectors. The pressure index, filling degree, and fluid injection profile are found to be all improved in injectors after injection of nitrogen foam. The oil production, water cut and liquid production file are also improved in most of the producers, with the natural decline rate in the test area become slow. Results show that nitrogen foam flooding technology can be good technical storage for enhanced oil recovery in low permeability reservoir.