Hydraulic fracturing in shale gas reservoirs has often resulted in complex fracture network growth, as evidenced by microseismic monitoring. The nature and degree of fracture complexity must be clearly understood to optimize stimulation design and completion strategy. Unfortunately, the existing single planar fracture models used in the industry today are not able to simulate complex fracture networks.
A new hydraulic fracture model is developed to simulate complex fracture network propagation in a formation with preexisting natural fractures. The model solves a system of equations governing fracture deformation, height growth, fluid flow, and proppant transport in a complex fracture network with multiple propagating fracture tips. The interaction between a hydraulic fracture and pre-existing natural fractures is taken into account by using an analytical crossing model and is validated against experimental data. The model is able to predict whether a hydraulic fracture front crosses or is arrested by a natural fracture it encounters, which leads to complexity. It also considers the mechanical interaction among the adjacent fractures (i.e., the "stress shadow" effect). An efficient numerical scheme is used in the model so it can simulate the complex problem in a relatively short computation time to allow for day-to-day engineering design use.
Simulation results from the new complex fracture model show that stress anisotropy, natural fractures, and interfacial friction play critical roles in creating fracture network complexity. Decreasing stress anisotropy or interfacial friction can change the induced fracture geometry from a bi-wing fracture to a complex fracture network for the same initial natural fractures. The results presented illustrate the importance of rock fabrics and stresses on fracture complexity in unconventional reservoirs. They have major implications on matching microseismic observations and improving fracture stimulation design.