Pore structure is the key factor affecting reservoir accumulation and enrichment behavior. Due to the complex mineral components and pore structure of shale oil reservoirs and strong heterogeneity, it is necessary to explore the micro-pore structure characteristics of inter-salt shale. In this study, in order to qualitatively and quantitatively analyze the pore structure of inter-salt shale reservoirs, as well as evaluate the mineral composition and its spatial distribution characteristics, three shale samples from the 10th cyclothem of the Eq3 (Eq3⁴–10 cyclothem) inter-salt shale were selected to acquire 2D and 3D grayscale images by modular automated processing system (MAPS) and X-ray micro-computed tomography (Micro-CT), respectively. The color map of the inlaid characteristics of mineral aggregates was established by Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN), and different mineral types in the grayscale image were determined. After that, the digital core technology was used to reconstruct the core in 3D, and the maximum sphere method was used to extract the pore network model, so as to realize the quantification of micron pore throats and the 3D visualization of inter-shale samples. Meanwhile, in order to compare the fractal characteristics of the pores of the samples, the two-dimensional and three-dimensional fractal dimensions of the three cores were calculated by combining the digital core technique with fractal theory. The study yielded several notable results: the pore structure of inter-salt shale reservoirs is complex and multi-scale, and the CT scanning digital core technology can effectively realize 3D visualization of rock microstructure without damage. The pore types of rock samples are mainly intergranular pores, interparticle pores, and dissolved pores, and the minerals are mainly dolomite, calcite, and glauberite. The micron pore throat radius of the rock sample is 0.5–13.9 μm, the distribution of coordination number is mainly in the range of 1–4, and the shape of the pore throat is mainly triangular and square. The pore space of inter-salt shale has suitable fractal characteristics, and the three-dimensional fractal dimension of the three cores is in the range of 2.41–2.49. In sum, this work used digital core technology to study the microscopic pore structure of inter-salt shale oil, establishing a basis for further understanding of the seepage characteristics and exploration and development of shale oil.

CO₂-soluble surfactant foam systems have gained significant attention for their potential to enhance oil recovery, particularly in tight oil reservoirs where conventional water-soluble surfactants face challenges such as poor injectability and high reservoir sensitivity. This review provides a comprehensive explanation of the basic theory of CO₂-soluble surfactant foam, its mechanism in enhanced oil recovery (EOR), and the classification and application of various CO₂-soluble surfactants. The application of these surfactants in tight oil reservoirs, where low permeability and high water sensitivity limit traditional methods, is highlighted as a promising solution to improve CO₂ mobility control and increase oil recovery. The mechanism of enhanced oil recovery by CO₂-soluble surfactant foam involves the effective reduction of CO₂ fluidity, the decrease in oil–gas flow ratio, and the stabilization of the displacement front. Foam plays a vital role in mitigating the issues of channeling and gravity separation often caused by simple CO₂ injection. The reduction in gas fluidity can be attributed to the increase in apparent viscosity and trapped gas fraction. Future research should prioritize the development of more efficient and environmentally friendly CO₂-soluble surfactants. It is essential to further explore the advantages and challenges associated with their practical applications in order to maximize their potential impact.

This paper delivers an examination of relative permeability hysteresis in porous media in the field of petroleum engineering, encompassing mathematical modeling, experimental studies, and their practical implications. It explores two-phase and three-phase models, elucidating the generation of scanning curves and their applications in various porous materials. Building on the research of traditional relative permeability hysteresis models, we have incorporated literature on forward calculations of relative permeability based on digital rock core models. This offers a new perspective for studying the hysteresis effect in relative permeability. Additionally, it compiles insights from direct relative permeability and flow-through experiments, accentuating the methodologies and key findings. With a focus on enhanced oil recovery (EOR), carbon capture, utilization and sequestration (CCUS), and hydrogen storage applications, the paper identifies existing research voids and proposes avenues for future inquiry, laying the groundwork for advancing recovery techniques in oil and gas sectors.

The Qing-1 layer of the Gulong Depression in the northern Songliao Basin is a liquid-rich shale oil reservoir that has the characteristics of nanopores, high maturity, high gas/oil ratio (GOR), etc. The production performance of wells in the Gulong shale oil reservoir shows the characteristics of “single gas production followed by oil-gas production”. It is difficult to analyze the initial occurrence state and movability of fluid in the shale nanopores using conventional methods. In this study, a comprehensive method, including phase behavior analysis, physical experiments, and molecular simulation, was established to analyze the initial occurrence state and movability of fluid in the Gulong shale oil reservoir. The phase state of the fluid was calculated by the equation of state (EOS), considering nano-confinement effects, and the initial occurrence state was quantitatively evaluated by combining two-dimensional nuclear magnetic resonance (NMR) and molecular dynamics simulation. The movable fluid saturation was quantitatively determined by centrifugal experiments. The results show that the condensate gas state was in small pores, while the volatile oil state was in large pores. The occurrence states of oil were mainly adsorbed oil and free oil. The proportion of adsorbed oil in inorganic pores was about 24.4%, while the proportion of absorbed oil in organic pores was about 57.8%. Based on the cutoff value of T₂ before and after the centrifuged laboratory experiments, the movable limit of oil was determined to be 4.5 nm, and the movable fluid saturation was about 11%. The research method proposed in this study has important guiding significance for the initial occurrence state and movability evaluation of similar liquid-rich shale reservoirs.