The molecular models of nanopores for major rock constituents in deep shale were constructed. The microscopic adsorption behavior of methane was simulated by coupling the grand canonical Monte Carlo and Molecular Dynamics methods and the effect of rock constituents was discussed. Based on the illite and kerogen nanopore models, the discrepancies in microscopic water distribution characteristics were elucidated, the effects of water on methane adsorption and its underlying mechanisms were revealed, and the competitive adsorption characteristics between water and methane were elaborated. The results show a similar trend in the microscopic distribution of methane between different shale rock constituents. Illite and kerogen slit pores have no significant difference in methane adsorption capacity. The adsorption capacity per unit mass of kerogen is greater than that of illite due to the smaller molar mass of the kerogen skeleton and its large intermolecular porosity. Illite has a greater affinity for water than methane. With increasing water content, water molecules preferentially occupy the high-energy adsorption sites and then overspread the entire pore walls to form water adsorption layers. Methane molecules are adsorbed on the water layers, and methane adsorption has little effect on water adsorption. Kerogen is characterized as mix-wetting. Water molecules are preferentially adsorbed on polar functional groups and gather around to form water clusters. In kerogen with high water content, methane adsorption can facilitate water cluster fusion and suppress water spreading along pore walls. In addition to adsorption, some water molecules dissolve in the kerogen matrix.

The performance of horizontal wells in shale gas is controlled by multiple factors, and there is a difference in gas production rate between different fracturing stages. However, the mechanism of the nonuniform gas production rate is still not clear. In this paper, a typical shale gas well in the Longmaxi formation was selected to conduct the performance evaluation based on the nonradioactive gas tracer technology. The gas production profile was obtained, and the production feature of each stage was analyzed. On this basis, the production differences between fracturing stages were compared in four aspects: reservoir physical properties, distribution of natural fracture, parameters of fracturing operation, and technology of temporary plugging re‐orientation. The effect of various factors on the contribution of each stage was analyzed. And then, the mechanism of the nonuniform gas production rate was clarified. Finally, relevance analysis was performed to determine the main controlling factors, and a mathematical model for characterizing the nonuniform gas production rate feature was established by adopting the nonlinear regression method. This study provides a reliable basis for optimal fracturing designing and reasonable production planning.

The dual-porosity model has been used widely to describe the fracture network in well test or numerical simulation due to the high computational efficiency. The shape factor, which can be used to determine the capability of mass transfer between the matrix and fracture, is the core of the dual-porosity model. However, the conventional shape factor, which is usually obtained under pseudo-steady state assumption, has certain limitation in characterization of the mass transfer efficiency in a shale/tight reservoir. In this study, a new transient interporosity flow model has been established by considering the influence of nonlinear flow, stress sensitivity, and fracture pressure depletion. To solve this new model, a finite difference and Newton iteration method was applied. According to the Duhamel principle, the solution for time-dependent fracture pressure boundary condition has been obtained. The solution has been verified by using the fine-grid finite element method. Then, the influence of nonlinear flow, stress sensitivity, and fracture pressure depletion on shape factor and interporosity flow rate has been studied. The study results show that constant shape factors are not suitable for unconventional reservoirs, and the interporosity flow in the shale/tight reservoir is controlled by multiple factors. The new model can be used in test interpretation and numerical simulation, and also provides a new approach for the optimization of the perforation cluster number.