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.

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.

The development of inter-well channeling pathways has become a major challenge restricting the effectiveness of the thermal recovery process for heavy oil reservoirs, which leads to non-uniform sweep and reduced oil recovery. This is especially true for the characteristics of the higher injection–production intensity in offshore operations, making the issue more prominent. In this study, a quick and widely applicable approach is proposed for channeling identification, utilizing the static reservoir parameters and injection–production performance. The results show that the cumulative injection–production pressure differential (CIPPD) over the cumulative water equivalent (CWE) exhibits a linear relationship when connectivity exists between the injection and production wells. Thereafter, the seepage resistance could be analyzed quantitatively by the slope of the linear relationship during the steam injection process. Simultaneously, a channeling identification chart could be obtained based on the data of injection–production performance, dividing the steam flooding process into three different stages, including the energy recharge zone, interference zone, and channeling zone. Then, the established channeling identification chart is applied to injection–production data from two typical wells in the Bohai oilfield. From the obtained channeling identification chart, it is shown that Well X1 exhibits no channeling, while Well X2 exhibited channeling in the late stage of the steam flooding process. These findings are validated against the field performance (i.e., the liquid rate, water cut, flowing temperature, and flowing pressure) to confirm the accuracy. The channeling identification approach in this paper provides a guide for operational adjustments to improve the effect of the thermal recovery process in the field.

Mechanism analysis and technical scheme optimization on CO₂ displacement and CO₂ storage are based on the high-pressure physical properties of CO₂-added formation oil. Oil and natural gas samples from the BZ25-1 block in the Bohai oilfield were used to conduct high-pressure physical property experiments to explore the impacts of CO₂-CH₄ mixed gas on the properties of formation oil. After injecting different amounts of mixed gas, the saturated pressure was measured by constant mass expansion test, the viscosity was measured by falling ball method, the expansion coefficient was measured by gas injection expansion test, and the gas–oil ratio and volume coefficient were obtained by single degassing test. The results show that with gas injection, the saturation pressure and dissolved gas–oil ratio of formation oil increase, the volume coefficient and expansion factor go up, while the oil viscosity reduces. With the increase in gas addition, the properties of formation oil continue to improve, but the increase in improvement becomes flat. With the increase in pressure, the amount of dissolved gas in the formation oil will also increase. High-purity CO₂ is more helpful to change the properties of formation oil, while the gas mixed with CH₄ is more beneficial to elevate the formation energy. For the BZ 25-1 block, the gas injection amount of about 80 mol% is appropriate and the CO₂ purity of 60% can well balance the oil properties improvement and the formation pressure elevation.

Deepwater sandstone reservoirs are important hydrocarbon-bearing media and are prone to pore structure reconfiguration and seepage path evolution under long-term high-rate development conditions, which can significantly affect reservoir performance. However, their dynamic response mechanisms remain insufficiently understood. To address this issue, this study investigates the responses of deepwater sandstone reservoirs with different initial pore throat structures to prolonged high-rate water injection. Reservoir samples are first classified into three classes based on pore throat characteristics and fractal parameters derived from mercury intrusion capillary pressure (MICP) data. Representative cores are then subjected to long-term water injection, with permeability and pore structure evolution monitored up to 1000 PV. In situ nuclear magnetic resonance (NMR), together with scanning electron microscopy (SEM) and X-ray diffraction (XRD) observations before and after injection, is used to relate changes in flow capacity to multiscale pore redistribution and mineralogical–microstructural alteration. Pore sizes are quantified from the T₂ spectra, and fractal dimensions are calculated to characterize multiscale structural complexity. The results show that (1) the fractal parameters correspond closely to the pore throat structure and petrophysical properties. From Class I to Class III, the macropore throat fractal dimension generally increases, whereas the median pore throat radius, porosity, and permeability decrease. (2) During long-term high-rate water injection, permeability continuously decreases by 15.8–26.3%, accompanied by mineral redistribution, localized dissolution, and pore throat filling associated with fine-particle migration and retention. (3) Over the same injection period, the micropore fraction increases by 4.1–6.0%, whereas the macropore fraction decreases by 3.2–10.9%. The micropore fractal dimension increases markedly by 63.8–212.0%, whereas the changes in the mesopore and macropore domains remain limited to no more than 2.3%. Overall, the weakening of macropores, together with increasing heterogeneity in the micropore domain, progressively constrains effective flow pathways, resulting in sustained permeability decline and differentiated responses among reservoir classes.

Deepwater sandstone reservoirs are commonly developed under high-intensity injection and production conditions because of a limited number of wells, large injector–producer spacing, and offshore processing constraints. Injection rate variations alter the balance between viscous and capillary forces, thereby affecting oil–water displacement and remaining oil mobilization. However, the pore-scale effects of injection rate and rate adjustment sequence remain insufficiently understood. Here, a two-dimensional polydimethylsiloxane (PDMS) micromodel replicating the pore structure of a real deepwater sandstone reservoir was used to investigate four regimes: constant low-rate, constant high-rate, low-to-high-rate, and high-to-low-rate waterflooding. The low-to-high-rate regime achieved the highest final oil recovery factor of 88.41%, exceeding the constant low-rate, constant high-rate, and high-to-low-rate regimes by 6.54, 3.86, and 3.97 percentage points, respectively. Constant low-rate waterflooding gave the lowest recovery factor of 81.87% and a total areal remaining oil saturation of 18.13%, compared with 15.44% under constant high-rate conditions. Under low-rate flooding, wall-attached oil, elongated ganglia, and oil droplets accounted for 90.18% of the remaining oil, indicating limited mobilization of oil retained by interfacial effects and local capillary trapping. Increasing the rate reduced the total areal remaining oil saturation from 44.04% to 11.58%, mainly by mobilizing oil clusters and elongated ganglia, whereas decreasing the rate reduced it only from 16.52% to 15.55%. At the same cumulative injected volume of 1 PV, the total areal remaining oil saturation under high-rate flooding was 27.52 percentage points lower than that under low-rate flooding, indicating faster early-stage mobilization, while the low-rate stage retained more oil available for subsequent mobilization. These results show that waterflooding performance depends on both injection rate and flow history. A low-to-high-rate sequence combined relatively stable early-stage displacement with enhanced subsequent mobilization, providing pore-scale evidence that injection-rate history can influence displacement pathways and remaining-oil mobilization in deepwater sandstone reservoirs.