The imbibition process plays a crucial role in the development of shale reservoirs, particularly during the volume fracturing and water injection development phases. This process significantly influences the production capacity of shale and also serves as a essential parameter for assessing reservoir performance. Clay minerals contribute to the formation of numerous micro-pores and micro-fractures, exhibit strong plasticity and are prone to swelling. The unique structures and properties of clay minerals have a profound impact on shale imbibition. This review analyzes the effects of clay minerals on imbibition from different perspectives, finding that the effect is closely related to the total amount of clay minerals, as well as to specific mineral types and content. Clay minerals exhibit a dual impact on imbibition, which can either facilitate imbibition by promoting micro-fractures formation or hinder it by reducing pore throats and migrating to block flow paths due to swelling. While capillary action is usually considered the main mechanism for fluid displacement during the imbibition, the osmotic pressure formed by clay minerals can also serve as a driving force for imbibition, positively contributing to shale oil and gas recovery. This review aims to provide a comprehensive understanding of the role of clay minerals on the imbibition, providing a theoretical foundation and practical guidance for future research and efficient development of shale reservoirs.

Adsorbed gas confined in nanopores is a significant component of shale gas, and understanding the mechanisms of gas adsorption in shale nanopores is crucial for enhancing shale gas recovery and carbon dioxide geological sequestration. Due to the nanoscale pore sizes, complex pore structures, and diverse mineral types, adsorption experiments have a limited capacity to elucidate the microscopic mechanisms of gas adsorption. Compared to expensive adsorption experiments, molecular simulation methods can not only simulate reservoir in-situ conditions but also reveal the adsorption mechanisms from the molecular scale perspective. This work provides a brief review for the characteristics of methane adsorption in shale inorganic minerals and organic matter. Additionally, the competitive adsorption behavior of methane and carbon dioxide in shale is introduced to clarify the potential of shale reservoirs for carbon dioxide geological storage. Finally, the challenges faced by molecular simulation methods in gas adsorption research are discussed.

Due to the existence of fracturing fluid and formation water in shale gas reservoirs, the coexistence of gas and water in nanopores is prevalent. The pore water in the reservoir, on the one hand, affects gas flow behavior and permeability. On the other hand, it blocks pore throats and occupies adsorption sites on the pore surface, consequently reducing the gas adsorption capacity. The occurrence of pore water in shale reservoirs holds significant importance for shale gas resources exploration and development. In this paper, the shale from the Longmaxi Formation, Sichuan Basin was selected as the research target. The content and micro-distribution behavior of pore water were evaluated through centrifugation-nuclear magnetic resonance experiment and theoretical model. The results demonstrated that the content of free water would be underestimated by the experiment, with 2.55%-6.80% lower than that calculated by theoretical model. Moreover, due to the limitations of nuclear magnetic resonance experiment, the adsorbed water in mesopores and macropores might be mistakenly identified as that in smaller pores. As a result, the theoretical model is more applicable for characterizing the micro-distribution behavior of pore water than the origin nuclear magnetic resonance data.

Acidification is crucial to oil and gas development, which effectively improves reservoir development by reacting acid with some minerals in the rock. There are a large number of minerals that react with acid in carbonate and shale reservoirs. Acidification has a good effect in these two reservoirs, so it is necessary to conduct multi-scale research on the acidification process. This work briefly introduces the evolution characteristics and factors affecting acidification on reservoir pore structure and physical properties, and also analyzes their similarities and differences. Meanwhile, the application status of the acidification method is also discussed. Finally, the challenges and opportunities faced by shale acidification are discussed, aiming to provide new insights into the development of acidizing technology.

Fluids flow within microporous and nanoporous rocks involves several industrial processes such as enhanced oil recovery, geological CO₂ sequestration, and hydraulic fracturing. However, the pore structure of subsurface rocks is complex, and fluid flow is influenced by strong fluid-fluid and fluid-solid interactions, including wettability, interfacial tension, and slip effects. Characterizing this flow processes is costly and challenging through experimental techniques. At meanwhile, pore-scale simulations have been widely employed to investigate complex flow behaviors within microporous and nanoporous media. This work investigates the applications of pore-scale simulation methods for characterizing flow processes in porous rocks considering microscale and nanoscale effects. Two mainstream simulation methods, pore network modeling and direct numerical simulation, are introduced. Their application scenarios encompass immiscible flow, as well as miscible and near-miscible flow involving CO₂ enhanced recovery. Additionally, some explorations of single-phase and multiphase flow processes within nanoporous media are described. Finally, future development of pore-scale simulations is discussed, with a focus on complex transport phenomena involving diffusion, reactions, and dissolution.

The capillary pressure curve is a crucial basis for studying the pore structure and multiphase flow characteristics in oil and gas reservoirs. Due to the loose and unconsolidated nature of the clayey-silt sediment of natural gas hydrate reservoirs in the South China Sea, conventional methods such as mercury intrusion and centrifugation struggle to obtain capillary pressure curves for these sediments. In this study, X-ray diffraction analysis, scanning electron microscopy, nitrogen adsorption, and water-gas contact angle measurements are utilized to characterize the mineral composition, pore structure, pore size distribution, and wettability of the clayey-silt sediment. Subsequently, the filter paper method from soil mechanics is employed to determine the capillary pressure curve for the clayey-silt samples. The results indicate that the capillary pressure curve obtained through the filter paper method exhibits a saturation range of 18.39%-80.31% and a capillary pressure range of 19.04 to 46,481.42 kPa. It exhibits a distinct two-stage characteristic, where capillary pressure changes rapidly with water saturation below 61.05% and slowly above 61.05%. The pore radius calculated from the capillary pressure curve ranges from 2.41 nm to 5.91 μm. This alignment with the pore ranges obtains from nitrogen adsorption and Scanning Electron Microscopy confirms the accuracy of the obtained capillary pressure curve. Furthermore, in comparison with a literature capillary pressure curve obtained through centrifugation, the paper filtration method covers a broader range, providing better representation of capillary pressure in the multiscale pores of clayey-silt samples.