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.

Despite the success of deep horizontal drilling and hydraulic fracturing in yielding large production increases from unconventional shale gas reservoirs, uncertainties associated with basic transport processes require understanding in order to improve efficiency and minimize environmental impacts. The hydraulic fracturing process introduces large volumes of water into shale gas reservoirs, most of which remains unrecoverable and interferes with gas production. In this study, the water adsorption and diffusion measurements of the Longmaxi Formation shale were conducted at 30 ℃ and 50 ℃ for relative humidities from 11.1% to 97.0%. Based on the experiment, a computational model based on the Maxwell-Stefan diffusion equation was constructed to analyze water adsorption and diffusion in shale rocks, and the Guggenheim-Anderson-de Boer (GAB) isotherm for gas adsorption was included in the model. The results show that water adsorption isotherms of shales belong to type Ⅱ curve, including the monolayer, multilayer adsorption and capillary condensation, and the GAB model can be used to describe the water adsorption process in shale rocks. With the increasing of relative pressure, the water adsorption of shale increases, and the organic carbon content and temperature strengthen the water adsorption in shale. The capillary pressure can reach the order of several hundreds of MPa after the hydraulic fracturing process, and it results in a large amount of fracturing fluid retained in shale gas reservoirs. Furthermore, the simulation of water adsorption and diffusion in shale rocks is less than the experimental value, which further indicates that capillary condensation occurs in shale rocks.