Numerical Simulation of Shale Reservoir Fluid-Driven Fracture Network Morphology Based on Global CZM

Abstract

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There are a large number of natural fractures in shale reservoirs, which create great challenges to hydraulic fracturing. Activating the natural fractures in reservoirs can form a complex fracture network, enhance fracturing effects, and increase shale gas production. Reservoir geological conditions (low in situ stress, natural fracture distribution, and cement strength) and operation parameters (fracturing fluid viscosity and injection rate) have an important influence on fracture network propagation. In this article, a two-dimensional hydraulic fracturing fluid-mechanic coupling numerical model for shale reservoirs with natural fractures was established. Based on the global cohesive zone model, the influence of geological conditions and operation parameters on the propagation of the hydraulic fracture network and fracturing process is investigated. The numerical simulation results show that when the horizontal in situ stress difference, approach angle, and cement strength are low, it is easier to form a complex fracture network. Research on the construction parameters indicated that when the viscosity of the fracturing fluid is low, it is easier to form a complex network of fractures, but the length of the fractures is shorter; in contrast, the fractures are straight and long. In addition, increasing the injection rate is beneficial for increasing the complexity of the fracture network while increasing the initiation pressure and width of the principal fracture reduces the risk of sand plugging. This article also proposes an optimization solution for hydraulic fracturing operations based on numerical simulation results.

Keywords

• fluid-driven fracture
• fracture network morphology
• global cohesive zone method
• numerical study
• fracture properties