Microseismic data is evaluated with surface seismic and analyzed in addition to treatment data to understand the variance in performance of frac stages at three wells drilled in the Longmaxi formation, China. In well H1, the microseismic is dominated by fault reactivations, and is of little use in analyzing the performance of individual frac stages. In the wells H2 and H3, the use of maximum curvature derived from surface seismic showed strong qualitative correlation with microseismicity. To quantify the effects of shale properties on the frac stage performances, seismic attributes were used to derive geologic models of porosity, total gas, fracture density and Poisson's Ratio which were combined to form the Shale Capacity. The comparison of the Shale Capacity with the production log of H1 demonstarates how the model explains the performance of the frac stages away from the faults. The same observations could be made using the extent of good Shale Capacity away from the faults to explain the important difference in production between H2 and H3. Given the importance of the faults and their geomechanical impact on the performance of the frac stages, a geomechanical workflow able to simulate the interaction between the hydraulic and natural fractures is applied to the H1 well. The resulting strain and J Integral are able to explain the performance of the frac stages in H1 thus confirming the importance of the natural fractures and the need to account for their geomechanical effects.

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