The presence of natural fractures will usually result in a complex fracture network due to the interactions between hydraulic and natural fracture. The reactivation of natural fractures can generally provide additional flow paths from formation to wellbore which play a crucial role in improving the hydrocarbon recovery in these ultra-low permeability reservoir. Thus, accurate description of the geometry of discrete fractures and bedding is highly desired for accurate flow and production predictions. Compared to conventional continuum models that implicitly represent the discrete feature, Discrete Fracture Network (DFN) models could realistically model the connectivity of discontinuities at both reservoir scale and well scale. In this work, a new hybrid numerical model that couples Discrete Fracture Network (DFN) and Dual-Lattice Discrete Element Method (DL-DEM) is proposed to investigate the interaction between hydraulic fracture and natural fractures. Based on the proposed model, the effects of natural fracture orientation, density and injection properties on hydraulic-natural fractures interaction are investigated.


It has been widely inferred from numerical modelling[1], [2], laboratory experiments[3], [4] and microseismic monitoring [5], [6] that hydraulically-induced fractures in shale reservoirs often deviate from a simplistic biwinged fracture geometry. Complex fracture networks generically occur. Some complexity may be caused by stress shadowing resulting from multiple hydraulic fractures interfering during propagation or by interaction with pre-existing natural fractures. It has been widely accepted that in reservoir with ultra-low permeability such as Barnett, the natural fractures which are widely distributed [7]–[9] may result in hydraulic fractures branching and merging at the Hydraulic Fracture (HF) – Natural Fractures (NF) interface and consequently lead to the creation of the complex fracture network. Therefore, understanding the interaction between hydraulic fracture and natural fracture is important for quantifying the extent of the conductive fracture network and optimizing well completion strategies.

The fracture interactions depend on a variety of parameters including the in-situ stress magnitude and orientation, formation mechanical properties and degree of anisotropy, the existence of so-called dry zone or process zone, the natural fracture's mechanical and fluid transport properties and orientations, as well as treatment characteristics such as fracturing fluid viscosity, local injection rate, and proppant concentration. A number of methods have been used and attempted to understand the combined effects of these parameters on the morphology of the generated fracture network [10]–[13].

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