Hydraulic fracturing is performed in tight gas shales in order to create extensive fracture networks throughout the reservoir. Often the distance between injection zones is selected in order to maximize the fracturing of the reservoir and minimize the amount of reservoir that remains untreated. Recently, the deployment of three dimensionally distributed geophone arrays allows for Seismic Moment Tensor Inversion (SMTI). Using SMTI, the rock failure mechanisms can be examined both spatially and temporally, showing how the hydraulic fracture treatments interact with each other.

When events from a hydraulic fracture stage grow into previously fractured zone, there are three possible interactions: the fracture network in the previously fractured zone can dialate; the fracture network in the previously fractured zone can experience equal opening and closing result in little to no increase the effective fracture network; or the previously activated fracture network can experience more closure than opening, resulting in reduced productivity in the reservoir. One parameter that can be calculated from the SMTI is the cumulative volumetric strain which provides a parameter that reflects whether the fracture network is dominantly opening or closing over the course of the injection program.

In this study, we examined microseismicty from three stages of a multistage hydraulic fracture treatment in a shale gas reservoir in North America. The SMTI analysis is performed and failure mechanisms are calculated for events over the course of three subsequent stages. From the failure mechanisms, the cumulative volumetric strain is calculated and plotted versus time over the duration of each of the stages. For each of the three stages, the cumulative volumetric strain is compared and the dominant fracture state (opening or closing) is determined. The results suggest that interconnectivity of the hydraulic fracture treatments is complex and can lead to increases or decreases in the effective fracture network.

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