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Interest in the phase behavior of hydrocarbons in shale reservoirs has grown in recent years. Petroleum fluid phase behavior has been observed to differ significantly between conventional reservoirs and shale reservoirs. Within shale reservoirs, notable surface-fluid interactions can lead to non-uniform molecule distribution and an alteration in fluid phase behavior, primarily caused by the existence of nano-scale porous materials. In this work, we study the phase behavior of methane in single cylindrical pore models. We apply the gauge Gibbs ensemble Monte Carlo (gauge-GEMC) simulation technique to investigate the phase behavior of methane in 4–10 nm single nanopores and calculate the saturation pressures at various temperatures using the grand canonical Monte Carlo (GCMC) simulation technique. A shift in the phase diagram has been found for methane in nanopores. As pore size decreases, the shift becomes more significant.

As efficient technologies boost oil yields and economic benefits, horizontal wells and hydraulic fracturing are widely used in low- permeability reservoirs. To better evaluate the reserve and improve recovery, it is essential to determine fluid flow patterns and transport mechanisms. Laboratory experiments, field operations, and analytical studies have identified nonlinear flow and microfracture networks during the fluid flow in a reservoir with fractured horizontal wells. However, the interactions between nonlinear flow and microfracture networks are still not fully understood. In this study, nonlinear flow experiments and triaxial compression tests were carried out to analyze nonlinear flow characteristics in the vicinity of microfracture networks. By analyzing the effects of microfracture networks on nonlinear flow, two-phase flow, rock stress sensitivity, and artificial fractures, we found that fluid capacity in capillaries with smaller dimensions decreased along with a drop in the pressure gradient, generating a nonlinear flow pattern. The area of nonlinear flow was diminished by the presence of microfractures, which improved flow efficiency and reservoir quality. Considering the size of fracture apertures, microfractures behave more like matrix pores than natural fractures. Also, microfractures significantly increase rock stress sensitivity and reduce the threshold permeability, which enhances fluid flow capacity. This study contributes to our understanding of flow behavior, predicting production and improving recovery in low-permeability reservoirs.