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Shale formations are prone to hydration phenomena, such as clay mineral expansion and dispersion, when exposed to water. Conventional water-based drilling and fracturing fluids often lead to wellbore instability or poor fracturing stimulation effects. CO2 can effectively prevent the hydration of clay minerals and damage formation properties, making it widely used in shale reservoirs. The physical properties of CO2 vary greatly with temperature and pressure, and the physical properties of shale also undergo significant changes after CO2 interaction. Previous numerical models describing water-based fluid flow are not suitable for CO2 seepage research. In this work, a new model for describing the dynamic seepage in CO2 fracturing/storage processes is established by the displacement discontinuity method (DDM) with the classical point source seepage equation. This model uses the mass conservation of fracturing fluid flow in fractures and seepage into the rock matrix as a bridge. The correctness of the model is verified through analytical solutions and fracturing experiments. The results indicate that for problems without crack opening and propagation, the seepage range of CO2 is larger than that of water, but the pore pressure is lower. When cracks do open, the pore pressure from hydraulic fracturing is consistently lower than that from CO2 and CO2 fracturing generates higher pore pressure and seepage rates compared to water. During the process of approaching natural fractures (NFs), CO2 fracturing seepage generates higher pore pressure, effectively reducing the difficulty of NFs' failure and making it easier to induce NFs failure and form complex fracture morphology.
Tian et al. (Sat,) studied this question.