Abstract
Summary Complex fracture networks have become more evident in shale reservoirs as a result of the interaction between pre-existing natural fractures (NFs) and hydraulic fractures (HFs). Accurate characterization of fracture complexity plays an important role in optimizing fracturing design, especially for shale reservoirs with high-density NFs. In this study, we simulated simultaneous multiple-fracture propagation within a single fracturing stage by use of a complex HF-development model. The model was developed to simulate complex fracture propagation by coupling rock mechanics and fluid mechanics. A simplified 3D displacement-discontinuity method (DDM) 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 the geometry of various NF patterns on injection pressure and fracture complexity were investigated. The single-stage simulation results show 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 contact area, beyond which increasing the number of fractures actually decreases effective fracture area; and (3) fracture complexity is a function of NF patterns (various regular-pattern geometries were investigated). NFs with small relative angle to HFs are more likely to control the fracture-propagation path. Also, NF 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.
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