Velocity models for locating microseismic events recorded in the oil-industry applications are usually derived from sonic logs and perforation shots. Instead of fixing these models, as is conventionally done, we update them when locating the events. This added flexibility not only improves the accuracy of predicting traveltimes of the recorded P- and S-waves but also provides a convincing evidence for anisotropy of the examined gas-bearing shale formation. While we find that velocity heterogeneity does not need to be introduced to explain the data acquired at each stage of hydraulic fracturing, the obtained models suggest time-lapse changes in the anisotropy parameters characterizing the stimulated reservoir volume.


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