In a producing shale reservoir, in-situ stress redistribution depends on the fluid drainage rates controlled by the complex hydraulic-natural fracture networks. Due to the ubiquitous occurrence of natural fractures, the pressure and stress changes from a fully-connected fracture network significantly differ from a less connected network. Thus, this work investigates the impacts of complex natural fracture distributions on the spatial-temporal stress reorientation in a multi-layer shale gas reservoir, providing insights into the associated infill-well completion. The complex natural fractures are generated stochastically by varying fracture density, length, height, aperture, and orientation within ranges of property values and incorporated into the coupled simulation with an embedded discrete fracture model (EDFM). The geomechanics response is captured by the finite element method (FEM), while iteratively coupled with the fluid flow model until convergence.

Simulation results show that a more complex fracture network accelerates stress reorientation, particularly at the prospective infill-well location in the producing layer. An increase in the total number of natural fractures leads to quicker stress orientation in the producing layer due to more hydraulic-natural fracture intersections. More extended natural fractures induce faster and more severe stress rotation in the producing layer. Due to enhanced fracture conductivity, natural fractures with wider apertures introduce larger stress reorientation. Moreover, when natural fracture orientations are more parallel to the hydraulic fractures, the fracture network connectivity is improved and thus leads to faster in-situ stress changes.

This work recognizes the individual contribution of each natural fracture property to the stress reorientation in a multi-layer shale reservoir. The results from the numerical studies provide more instructive suggestions on infill drilling of highly fractured reservoirs.

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