Understanding the morphology and growth of hydraulic fractures is essential in the development of unconventional tight gas and shale gas resources. In this paper, we report the use of a computational tool consisting of geologic data representation, geomechanical modeling and multiphase flow simulations to predict reservoir performance. A finite element-based geomechanical module is interfaced with a control-volume finite element discrete-fracture reservoir simulator. The hydraulic fracture geometry is generated by following the fluid injection pathway in the existing fracture network and in the matrix. The permeabilities in the fractures and in the matrix are adjusted dynamically in the simulator based on coupling of the geomechanical and flow attributes. The approach described is applicable to tight gas and shale gas reservoirs. There are over 3700 active wells in the Greater Natural Buttes field in Uinta Basin, Utah with a cumulative production of 1.8 trillion cubic feet of gas. Most of this production comes from several tight gas formations (matrix permeability of less than 0.01 md). The importance of hydraulic fractures and their interaction with natural fractures in shale gas reservoirs characterized by nano-Darcy permeabilities is well known. This methodology provides a means of mapping a complex (non-planar) network of hydraulically-activated/induced fractures. The initial conductivity distribution in the fractures and the relative permeability of the matrix along with the stress tensor and mechanical properties of the matrix and the fractures control the geometry of the hydraulic fracture system and the ultimate well performance. Prediction of complex hydraulic fracture morphology and injected water balance are important in the development of tight gas and shale gas resources. Multiphase flow simulations with complex fracture networks will help delineate complex effects such as water blocks, "permeability jail" phenomena, etc.

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