Hydraulic fracturing is a common tool to increase the productivity of hydrocarbon reservoirs, which suffer of decreasing hydrocarbon pressure and permeability of gas/oil-bearing sediments. We analyzed a microseismic data set from hydraulic fracture stimulation of the gas field in West Texas. The data were recorded by an array of 8 three-component geophones deployed in a nearby vertical borehole. We used an automated wave-picking algorithm and obtained a high-density image of induced microearthquakes accompanying the hydraulic fracture growth. The event locations delineated a planar fracture growing predominantly in the horizontal direction; the vertical growth was limited by shale layers. The eastern and western wings of the fracture reached the lengths of 200 and 100 m, indicating an asymmetric fracture growth with 80% of the events located east from the injection. We find that the length of the hydraulic fracture increased, for different depth intervals, both linear and nonlinear in time. We use hydraulic fracture models to explain the spreading of the microseismic front, whose nonlinear time dependence could indicate either a diffusive fluid flow or a two-dimensional growth of the hydraulic fracture. By the maximum-likelihood fitting of the observed fracture growth and by inverting for its parameters, we find that the fracture was 7-10 mm wide and that nearly the whole injected volume was used for creating the new fracture, that is a negligible diffusive infiltration of the injected fluid into the reservoir rock occurred. We performed a limited moment tensor inversion to find the type of focal mechanism of the events accompanying the fracture growth. We show that a non-shear component is necessary to explain the observed seismograms which indicates that the micro-earthquakes are accompanied by some volumetric changes.

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