Characterization of Hydraulically-Induced Fracture Network Using Treatment and Microseismic Data in a Tight-Gas Sand Formation: A Geomechanical Approach

Large amount of gas are being produced from unconventional tight-gas sand reservoirs (e.g., Cotton Valley Fm., Lobo Fm., Taylor Sand Fm. and, Wilcox Fm., etc.) and shale gas-bearing formations (e.g, Barnett, Fayetteville, Marcellus, Woodford, etc.). These plays are partly technology driven and partly economics driven. Modern well log evaluation techniques and completion methods are required to yield economic wells. In some cases microseismic monitoring campaigns are performed in these various low permeability environments to improve the understanding of the induced fracture network and to go beyond the simple assumption of a symmetric bi-wing fracture system. To better characterize the induced fracture network, a semi-analytical pseudo 3-D geomechanical model was developed based on considerations of the conservation of injected fluid mass and the mechanic interactions both between fractures and injected fluid as well as among the fractures. The hydraulically stimulated volume is represented by a horizontally expanding ellipse containing a simplified fracture network consisting of two sets of vertical planar fractures perpendicular to one another. This model provides a mathematically-equivalent description of the process of hydraulic fracture propagation and the characteristics of the induced fractures. Using microseismic datasets obtained during hydraulic treatments in several tight formations together with measured wellbore pressure and treatment parameters as the input, the modeling analysis yields information of the induced fracture network including fracture spacing and associated confining stress contrast. The results indicate a vertically contained developping fracture network with anisotropic spacing and moderate confining stress contrast. The fracture network extension toward the maximum horizontal stress is however limited. This information is then used as the input of the model to carry out forward simulations and provide detailed information of time-dependent fracture propagation including front location, fluid pressure, fracture width, induced porosity and permeability.