The application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations. However, due to the complexity of fracture network propagation, simulation of such reservoirs is challenging and associated with uncertainties. In order to minimize the uncertainty of modeling, we correlate first-hand pumping schedule data with the reservoir performance directly through coupling a fracking process with a reservoir simulator. This provides us an integrated way to characterize a well trajectory, hydraulic fracture configurations and shale gas reservoir performance. In addition, a geomechanical effect on the reservoir performance under certain fracture configurations is studied using a geomechanics module developed by CMG Ltd.

GOHFER is widely used in a hydraulic fracking analysis. In this work, we couple GOHFER simulation output with the CMG module to determine the hydraulic fracture configuration. Thus, a method to correlate the first-hand pumping data (a slurry rate, slurry concentration and pumping pressure) with the reservoir simulator is given. Because of the stress sensitivity of a shale formation, we employ a linear-elastic constitutive law to depict the rock behavior with Young's modulus of 5,000,000 psi and Poisson's ratio of 0.2. Moreover, a Barton-Bandis model is used to describe the tensile opening of natural fractures for the dual-permeability reservoir model.

From a series of numerical simulation studies, we find that the effective normal stress will increase with the development of a shale gas reservoir which will lead to a decrease in porosity and permeability. For the base case without a geomechanics effect, it will produce higher cumulative gas production than the case with the geomechanics effect. When producing for six months, the difference of the cumulative gas production between the two cases is 14.3%. The integrated process provides insights about shale gas reservoir performance with available data and handy tools.

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