Numerical investigation of fluid-driven near-borehole fracture propagation in laminated reservoir rock using PFC2D

Hydraulic fracturing is a useful tool for enhancing permeability for shale gas development, enhanced geothermal systems, and geological carbon sequestration using high-pressure injection of a fracturing fluid into tight reservoir rocks. Mechanisms of fluid injection-induced fracture initiation and propagation should be well understood to take full advantage of hydraulic fracturing. In this paper, hydraulic fracturing modeling work was developed using discrete particle modeling based on two-dimensional particle flow code (PFC2D). Firstly, the developed model is validated against the analytical solutions of the breakdown pressure for the hydraulic fracturing process under varied in-situ stress conditions. Secondly, the model is tested using the microscopic parameters optimized from laboratory Uniaxial Compressive Test for laminated reservoir rock. Lastly, a series of hydraulic fracturing simulation work was performed to study the influence of weak layers, in-situ stress ratio, fluid injection rate and fluid viscosity on the borehole pressure history, the geometry of hydraulic fractures and the pore-pressure field. It is found that the hydraulic fracture propagation in laminated reservoir is controlled by both in situ stress state and strength anisotropy of the reservoir rock. With fluid injection rate increasing, higher breakdown pressure is required for fracture propagation and complex fracture geometry will develop. Furthermore, low viscosity fluid can more easily penetrate from the borehole into the surrounding rock, causing a reduction of the effective stress and leading to a lower breakdown pressure. Moreover, the geometry of the fractures is found to be sensitive to the fluid viscosity, and the major fractures propagate more easily along the maximum principle stress direction.