Microseismic events are usually located in the oil-industry applications using velocity models derived from sonic logs and perforation shots. Instead of fixing these models, as is normally done, we update them when locating the events. This added flexibility not only improves the accuracy of predicting travel-times of the recorded P- and S-waves but also provides a convincing evidence for non-negligible anisotropy of the examined shale formation. While we find that velocity heterogeneity does not need to be introduced to explain 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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