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.

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.