Understanding methane adsorption behavior on deep shales is crucial for estimating the original gas in place and enhancing gas recovery in deep shale gas formations. In this study, the methane adsorption on deep shales within the lower Silurian Longmaxi formation from the Sichuan Basin, South China was conducted at pressures up to 50 MPa. The effects of total organic carbon (TOC), temperatures, clay minerals, and moisture content on the adsorption capacity were discussed. The results indicated that the methane excess adsorption on deep shales increased, then reached its peak, and finally decreased with the pressure. The excess adsorption data were fitted using the adsorption models, and it was found that the Dubinin–Radushkevich (D–R) model was superior to other models in predicting the methane adsorption behavior. The methane adsorption capacities exhibited strong positive correlations with the TOC content and negative relationships with clay minerals. The methane excess adsorption decreased with the temperature, while the opposite trend would occur once it exceeded some pressure. The presence of the moisture content on deep shales sharply decreased the methane adsorption capacities, and the reduction of the adsorption capacity decreased with the pressure. The moisture would occupy the adsorption sites in the shale pores, which could result in the methane adsorption capacity that decreased.

Efficiently and accurately understanding the fluid flow behavior in ultra-deep natural gas reservoirs is very challenging due to the complex geological environment and the intricate gas properties at high pressure. In this study, a fully coupled fluid flow and geomechanical model was developed to simulate complex production phenomena in ultra-deep natural gas reservoirs. Stress-dependent porosity and permeability models were applied, and then the governing equations of the model were incorporated into COMSOL Multiphysics. Furthermore, the model was verified by the reservoir depletion from the Keshen gas field in China, and the effects of reservoir properties and geomechanics on gas production were discussed. The results showed that the reservoir pressure and water saturation exhibited a significant funnel-shaped decline during the reservoir depletion. The higher relative permeability of the gas phase results in more methane gas production, thereby reducing the average pore pressure and gas saturation near the wellhead. When considering geomechanical effects, the production behavior significantly changes. The predictive value of gas production was higher when the reservoir rock deformation was ignored. The gas production exhibited strong positive correlations with reservoir porosity, fracture permeability, elastic modulus, and Poisson's ratio. Larger porosity, elastic modulus, and Poisson's ratio resulted in smaller deformation, while a smaller fracture permeability leads to larger deformation in ultra-deep natural gas reservoirs.

The understanding of water adsorption and desorption behavior in the shale rocks is of great significance in the reserve estimation, wellbore stability and hydrocarbon extraction in the shale gas reservoirs. However, the water sorption behavior in the shales remains unclear. In this study, water vapor adsorption/desorption isotherms of the Longmaxi shale in the Sichuan Basin, China were conducted at various temperatures (30 °C, 60 °C) and a relative pressure up to 0.97 to understand the water sorption behavior. Then the effects of temperature and shale properties were analyzed, and the water adsorption, hysteresis, saturation and capillary pressure were discussed. The results indicate that water adsorption isotherms of the Longmaxi shale exhibit the type II characteristics. The water molecules initially adsorb on the shale particle/pore surfaces at low relative pressure while the capillary condensation dominates at high relative pressure. Temperature favors the water sorption in the shales at high relative pressure, and the GAB isotherm model is found to be suitable for describe the water adsorption/desorption behavior. The high organic carbon and full bedding are beneficial to water adsorption in the shales while the calcite inhibits the behavior. There exists the hysteresis between water adsorption and desorption at the whole relative pressure, which suggests that the depletion of condensed water from smaller capillary pores is more difficult than that from larger pores, and the chemical interaction contributes to the hysteresis loop for water sorption. The capillary pressure in the shales can be up to the order of several hundreds of MPa, and thus the desorption of water from the shales may not be as easy as the water adsorption due to the high capillary pressure, which results in water retention behavior in the shale gas reservoirs. These results can provide insights into a better understanding of water sorption behavior in the shale so as to optimize extraction conditions and predict gas productivity in the shale gas reservoirs.

The pore structure of shale oil reservoirs is complex, and the microscale and nanoscale effect is obvious in the development of shale oil reservoirs. Understanding the oil flow mechanism in shale reservoirs is essential for optimizing the development plan and enhancing the recovery rate of shale oil reservoirs. In this review, we briefly introduce the occurrence status of shale oil and shale oil flow in the inorganic matrix and the organic matrix (including the shrinkage of kerogen, oil diffusion in kerogen, oil transport in the organic pore channels, coupling of diffusion, and fluid transport in the organic matrix). Then, the shale oil microflow simulation and a coupling model of double-porous media for microflow and macroflow in the production process of shale oil are discussed. Finally, we summarize the main conclusions and perspectives on the oil flow mechanism and numerical simulations in shale oil reservoirs. An accurate description of shale oil occurrence status and shale oil flow in the inorganic and organic matrices is crucial for the numerical simulation of shale oil reservoirs. It can provide a basis and reference for the future directions of shale oil flow and numerical simulations during the development of shale oil reservoirs.