Fracturing flooding provides an effective approach to overcoming injection difficulties and enhancing oil recovery in high-water-cut, low-permeability sandstone reservoirs. Injecting fracturing-flooding fluids (FFFs) at high rates over short durations enables a coupled process of hydraulic fracturing and flooding, especially when the FFFs contain surfactants. In this study, two types of core experiments were conducted to elucidate the mechanisms of reservoir modification and residual oil mobilization during fracturing flooding. (1) Fracturing flooding combined with CT scanning: The effects of N₂ permeability (K_g) and FFF viscosity on fracture pressure (P_f) were investigated. Post-flooding CT scans of multiple cores were performed to visualize fracture propagation. (2) Fracturing flooding combined with NMR experiments: The recovery efficiencies of water-based and petroleum sulfonate (NPS)-based fracturing flooding were compared with conventional water flooding. The results showed a negative correlation between K_g and both P_f and the permeability enhancement factor (E_K), with E_K ranging from 1.61 to 0.43. Increasing FFF viscosity led to higher P_f values. The E_K first increased and then decreased, consistent with the fracture distribution observed in CT images. Moreover, NPS fracturing flooding exhibited superior enhanced oil recovery (EOR) performance compared with water fracturing flooding. The latter primarily improved recovery in small pores and mesopores, with recovery enhancement factors (E_R) of 0.44 and 0.36, respectively. In contrast, the NPS fracturing flooding achieved significant recovery improvements across all pore sizes, with E_R values in micropores and macropores approximately threefold and fifteenfold higher than those of water fracturing flooding. This study presents a novel investigation into the mechanisms of fracture propagation and enhanced oil recovery in fracturing flooding processes.

Deep shale gas reservoirs are characterized by high temperature, high pressure, and ultra-low permeability, making them highly susceptible to plastic deformation during hydraulic fracturing. In such cases, conventional elastic models fail to capture the complex post-fracturing rock behavior, highlighting the suitability of elastoplastic modeling. This study develops a fully coupled flow-geomechanics model incorporating elastoplastic deformation to analyze production performance in deep shale gas reservoirs. The proposed model dynamically couples post-fracturing plastic deformation with multiscale gas transport mechanisms, including slip flow, Knudsen diffusion, and surface diffusion. It incorporates governing equations that describe gas migration through the matrix, natural fractures, and hydraulic fractures, while simultaneously accounting for dynamic changes in effective stress, porosity, and permeability. Model validation is performed using the classical Mandel problem, followed by a detailed analysis of key parameters influencing elastoplastic production performance. Simulation results indicate that in elastoplastic reservoirs, production initially increases and then declines with increasing bottom-hole pressure (BHP), while elastic reservoirs show a continuous increase. When the initial reservoir pressure is 50 MPa, elastic production dominates below BHP of 31.5 MPa, whereas elastoplastic production becomes more favorable above this threshold. A critical inflection point emerges when the BHP is approximately 0.5–0.625 times the original formation pressure. Furthermore, the most important influencing factors of elastic and elastoplastic formations are BHP and original formation pressure, respectively. These findings offer valuable insights into optimizing production strategies for deep shale gas reservoirs under complex geomechanical conditions.

This report summarizes the recent findings on gas transport mechanisms in shale gas reservoir by pore network modelling. Multi-scale pore network model was developed to accurately characterize the shale pore structure. The pore network single component gas transport model was established considering the gas slippage and real gas property. The gas transport mechanisms in shale pore systems were elaborated on this basis. A multicomponent hydrocarbon pore network transport model was further proposed considering the influences of capillary pressure and fluid occurrence on fugacity balance. The hydrocarbon composition and pore structure influences on condensate gas transport were analyzed. These results provide valuable insights on gas transport mechanisms in shale gas reservoir.