Global tight-oil reserves are abundant, but the depletion development of numerous tight-oil reservoirs remains unsatisfactory. CO₂ injection development represents a significant method of reservoir production, potentially facilitating enhanced oil recovery (EOR) alongside CO₂ storage. Currently, limited research exists on advanced CO₂ injection and well pattern adjustment aimed at improving the oil recovery and CO₂ storage within tight-oil reservoirs. This paper focuses on the examination of tight oil within the Ordos Basin. Through the employment of slim-tube experiments, long-core displacement experiments, and reservoir numerical simulations, the near-miscible pressure range and minimum miscible pressure (MMP) for the target block were ascertained. The viability of EOR and CO₂ sequestration via advanced CO₂ injection was elucidated, establishing well pattern adjustment methodologies to ameliorate CO₂ storage and enhance oil recovery. Simultaneously, the impacts of the injection volume and bottom-hole pressure on the development of advanced CO₂ injection were explored in further detail. The experimental results indicate that the near-miscible pressure range of the CO₂–crude oil in the study area is from 15.33 to 18.47 MPa, with an MMP of 18.47 MPa, achievable under reservoir pressure conditions. Compared to continuous CO₂ injection, advanced CO₂ injection can more effectively facilitate EOR and achieve CO₂ sequestration, with the recovery and CO₂ sequestration rates increasing by 4.83% and 2.29%, respectively. Through numerical simulation, the optimal injection volume for advanced CO₂ injection was determined to be 0.04 PV, and the most favorable bottom-hole flowing pressure was identified as 10 MPa. By transitioning from a square well pattern to either a five-point well pattern or a row well pattern, the CO₂ storage ratio significantly improved, and the gas–oil ratio of the production wells also decreased. Well pattern adjustment effectively supplements the formation energy, extends the stable production lives of production wells, and increases both the sweep efficiency and oil recovery. This study provides theoretical support and serves as a reference for CO₂ injection development in tight-oil reservoirs.

This study focuses on the Bozhong 25-1 oilfield formation oil as the experimental subject, systematically investigating the influence of different slim tube lengths (1 m, 12.5 m, 20 m, and 25 m) on the minimum miscibility pressure (MMP) of the CO₂ and formation oil mixture system. Through slim tube experiments, the interaction process of CO₂ with formation oil in slim tubes of different lengths was simulated, with a particular focus on analyzing how changes in slim tube length affect the MMP. The experiments revealed an important phenomenon: as the slim tube length gradually increased from shorter dimensions, the MMP showed a decreasing trend; when the slim tube length reached 12.5 m, this trend stabilized, meaning that further increasing the slim tube length no longer led to significant changes in the MMP, with its stable value determined to be 27.86 MPa. This phenomenon can be explained within the theoretical framework of fluid dynamics and interfacial science, where several key factors play a significant role. Firstly, the flow characteristics of the fluid inside the slim tube significantly influence it; secondly, the interfacial tension between phases is also a decisive factor; lastly, the impact of the internal microstructure of the slim tube cannot be overlooked. These aspects together form the basis for understanding the impact of slim tube length on MMP and reveal the underlying mechanisms. This research is significant for deeply understanding and quantifying this effect, providing a solid theoretical basis for optimizing CO₂ flooding technology and guiding more precise operational strategies in oilfield development practices to enhance oil displacement efficiency and economic benefits.

The integrity of caprock sealing is a crucial factor in guaranteeing the safety and long-term feasibility of CO₂ saline aquifer storage. In this study, we identified three principal mechanisms that give rise to topseal failure: (1) gradual CO₂ seepage through the upper cap, (2) capillary seal failure resulting from the pressure increment due to CO₂ injection, and (3) localized overpressure causing cap rupture. Through the integration of numerical simulation and geomechanics, this study offers a sealing assessment for the caprock. The thorough analysis of the sealing performance of the Guantao formation reveals that after 2000 years of CO₂ injection, the caprock would undergo intrusion by 35 m without any leakage risk. Moreover, investigations into CO₂–water–rock interactions suggest that precipitation reactions outweigh dissolution reactions, leading to a decreased permeability and an enhanced sealing performance. The most likely fracture mode identified is shear fracture with a critical caprock fracture pressure of 36.48 MPa. In addition to these discoveries, it is significant to consider ongoing research aimed at enhancing our ability to predict and manage potential risks associated with carbon capture and storage technologies.

Cyclic steam stimulation (CSS) is successfully applied to increase heavy oil recovery in heavy oil reservoirs in Bohai Bay, China. However, during the CSS processes, hydrogen sulfide (H₂S) was detected in some heavy oil reservoirs. The existing literature mainly focused on the H₂S generation of onshore heavy oil. There is no concrete experimental data available, especially about the level of H₂S generation during CSS of offshore heavy oil. In addition, there is still a lack of effective reaction kinetic models and numerical simulation methods to simulate H₂S generation during the CSS of offshore heavy oil. Therefore, this paper presents a case study from Bohai Bay, China. First, the laboratory aquathermolysis tests were conducted to simulate the gases that are produced during the CSS processes of heavy oil. The effects of the reaction temperature and time on the H₂S generation were studied. Then, a one-dimensional CSS experiment was performed to predict H₂S generation under reservoir conditions. A kinetic model for the prediction of H₂S generation during the CSS of heavy oil was presented. The developed model was calibrated with the experimental data of the one-dimensional CSS experiment at a temperature of 300 °C. Finally, a reservoir model was developed to predict H₂S generation and investigate the effects of soaking time, steam quality, and steam injection volume on H₂S generation during CSS processes. The results show that the H₂S concentration increased from 0.77 ppm in the first cycle to 1.94 ppm in the eighth cycle during the one-dimensional CSS experiment. The average absolute error between the measured and simulated H₂S production was 12.46%, indicating that the developed model can accurately predict H₂S production. The H₂S production increase with soaking time, steam quality, and steam injection volume due to the strengthened aquathermolysis reaction. Based on the reservoir simulation, the H₂S production was predicted in the range of 228 m³ to 2895 m³ within the parameters of this study.

Cyclic steam stimulation is an effective thermal recovery method for heavy oil recovery. The key potential mechanism is the growth of the steam chamber after steam injection. Taking the LD5X heavy oil reservoir as an example, besides the interlayer developed in this area, the top water and bottom water distribute above and below the interlayer. These factors may have adverse effects on the development of the steam chamber, thus affecting the final heavy oil exploitation. In this work, our goal is to study the effects of interlayer permeability and well–interlayer distance on CSS performance (in the presence of top and bottom water). We developed a high-temperature-resistant interlayer. Based on the simulated interlayer, the field scale model was converted into a laboratory element model through the similarity criterion. In order to quantitatively evaluate the performance of steam stimulation, a thermal detector was used to measure the dynamic growth of the steam chamber and record the production data. The experimental results show that the self-made interlayer has high-temperature resistance, adjustable permeability, and little difference between the physical parameters and the target interlayer. During the cyclic steam stimulation process, the steam chamber presents two different stages in the presence of the top water area, namely the normal production stage and the top water discharge stage. The bottom water has little effect on the growth of the steam chamber. The small interlayer permeability, the increase in horizontal well–interlayer distance, and the existence of the interlayer will delay the top water leakage during steam stimulation. This study has reference significance for us to develop heavy oil resources with a top water barrier when implementing steam stimulation technology.

Research into condensate gas reservoirs in the oil and gas industry has been paid much attention and has great research value. There are also many deep condensate gas reservoirs, which is of great significance for exploitation. In this paper, the seepage performance of deep condensate gas reservoirs with natural fractures was studied. Considering that the composition of condensate gas changes during the production process, the component model was used to describe the condensate gas seepage in the fractured reservoir, modeled using the discrete fracture method, and the finite element method was used to conduct numerical simulation to analyze the seepage dynamic. The results show that the advancing speed of the moving pressure boundary can be reduced by 55% due to the existence of threshold pressure gradient. Due to the high-speed flow effect in the near wellbore area, as well as the high mobility of oil, the condensate oil saturation near the wellbore can be reduced by 42.8%. The existence of discrete natural fractures is conducive to improving the degree of formation utilization and producing condensate oil.