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In recent years, hydraulic fracturing has emerged as an important technique for the development of unconventional tight gas and oil reservoirs, particularly shale reservoirs. Production from a tight reservoir requires hydraulic creation of a highly fractured network for significantly improving the hydraulic conductivity of the reservoir. Field observations have empirically indicated that fracture complexity tends to be higher in the case of higher rock brittleness which is defined as the combination of the Young's modulus and Poisson's ratio of a rock. The brittleness is considered as one of the most important mechanical rock properties of unconventional tight reservoirs. However, the physical relationship between fracture complexity and the brittleness remains unclear. In this study, a series of hydraulic fracturing simulations were performed using a flow-coupled discrete element method to gain insights into the effect of the brittleness on fracture propagation. The brittleness was adjusted under different combinations of Young's modulus and Poisson's ratio for four rock models. Considering mechanical rock properties and pre-existing fractures, the effective stress in the case of lower brittleness reduced to the tension only around the tip of the hydraulic and pre-existing fractures. On the contrary, the tensile region was more widely distributed along the pre-existing fracture in the case of higher brittleness. The effective tensile stress in a wider region should induce more microcracks, thereby enhancing the possibility of the hydraulic fracture branching off from the pre-existing fracture. These considerations indicate a positive correlation between the brittleness and the complexity of a hydraulically induced fracture system. [ABSTRACT FROM AUTHOR]

The shale rock, with relatively low permeability and porosity, is usually challenging to be developed economically. Hydraulic fracturing is widely used as a stimulation technique for shale gas exploitation. Unlike tight gas reservoirs, shale gas reservoirs appear to show different characteristics under hydraulic fracturing, with a low flow-back rate leading to high productivity. This might be linked to micro-cracks generated by the clay swelling when fluid penetrates the rock, as shown in previous fracturing experiments. However, detailed failure patterns and associated permeability changes under different conditions (e.g., in-situ stress, pore pressure, and clay content) remain ambiguous. In this study, numerical simulations were adopted to address these issues. A solid model with cohesive elements based on the Finite element method was used to predict the generation of micro-cracks. Further, a permeability evaluation model considering the micro-cracks was applied to estimate the permeability changes. Our simulation results indicate that clay swelling can produce shear cracks. The number of shear cracks is substantially influenced by the swelling stress and clay contents. Tensile cracks, together with a complex fracture network, can be observed when the pore pressure or stress difference increases. The permeability increases significantly when a complex fracture network is formed. This study reveals that micro-cracks can be induced by the interaction between fracturing fluid and shale rock, which may help explain how low flow-back rate results in high productivity in shale gas reservoirs. • A numerical model including a solid model and permeability evaluation model has been developed. • Influences of different conditions on micro-cracks and permeability changes have been investigated. • A complex fracture network can be formed by fracturing, resulting in a significant increase in permeability. [ABSTRACT FROM AUTHOR]

Supercritical carbon dioxide (SC-CO 2) fracturing is a promising technology for unconventional energy development and carbon capture and storage. Experimental studies have shown that SC-CO 2 fracturing can form complex fracture networks and reduce crack initiation pressure, which are different results from those when fracturing with aqueous fluids. The complex fracture networks that form from SC-CO 2 fracturing may be the result of strong seepage effects (i.e., low capillary and viscous forces). To understand the different injection behaviors induced by SC-CO 2 and aqueous fluids in low-permeability rocks, this study develops a new two-phase steady-state model based on the pore-scale network method. Although other models consider the viscous force, our model implements the capillary and viscous forces to reproduce the seepage effect. Because of the capillary force, the flow model is nonlinear and solved by iteratively solving matrix equations until a conservation of volumetric flux is satisfied. Simulation results show that the capillary force in a two-phase flow system in small pore spaces has consequential effects on its pressure distribution. Such factors lead to discontinuous pressure drops. This study shows that the seepage effect of SC-CO 2 is stronger than that of aqueous fluids and can largely avoid the capillary blockage that arises in oil-water systems. • The seepage effect estimation model for supercritical CO 2 and water fracturing in unconventional gas reservoir is proposed. • The simulation results show that capillary force has strong effect on seepage effect. • The strong seepage effect of SC-CO2 is a key factor to form complex fractures. [ABSTRACT FROM AUTHOR]