Complex fracture networks have become more evident in shale reservoirs due to the interaction between pre-existing natural and hydraulic fractures. Accurate characterization of fracture complexity plays an important role in optimizing fracturing design, especially for shale reservoirs with high-density natural fractures.
In this study, we simulated simultaneous multiple fracture propagation within a single fracturing stage using a complex hydraulic fracture development model. The model was developed to simulate complex fracture propagation by coupling rock mechanics and fluid mechanics. A simplified three-dimensional displacement discontinuity method was implemented to more accurately calculate fracture displacements and fracture-induced dynamic stress changes than our previously developed pseudo-3d model. The effects of perforation cluster spacing, differential stress (SHmax - Shmin) and various geometry natural fracture patterns on injection pressure and fracture complexity were investigated.
The single stage simulation results shown that (1) higher differential stress suppresses fracture length and increases injection pressure; (2) there is an optimal choice for the number of fractures per stage to maximize effective fracture surface area, beyond which increasing the number of fractures actually decreases effective fracture area; and (3) fracture complexity is a function of natural fracture patterns (various regular pattern geometries were investigated). Natural fractures with small relative angle to hydraulic fractures are more likely to control fracture propagation path. Also, natural fracture patterns with more long fractures tend to increase the likelihood to dominate the preferential fracture trend of fracture trajectory. Our numerical model can provide a physics-based complex fracture network that can be imported into reservoir simulation models for production analysis. The overall sensitivity results presented should serve as guidelines for fracture complexity analysis.