Hydraulic fracturing is often the most effective option to stimulate production in unconventional reservoirs to economic levels. Results of stimulation can be mixed unless the hydraulic fracture design correctly interprets the geological and geomechanical setting of the field. In fields with naturally fractured reservoirs, the interpretation is particularly critical because natural fractures strongly influence the final stimulated rock volume. An accurate description of the natural fracture network and the geomechanical properties and stresses of the rock provide the information to optimize stimulation treatment in naturally fractured unconventional reservoirs. However, the uncertainty in some of this information can jeopardize the value of the modeling and the success of the stimulation. One of the key geomechanical parameters, which are often poorly constrained, is the maximum horizontal stress magnitude. Microseismic data are able to map the stimulated rock volume during hydraulic fracturing operations. These data can be used to verify the accuracy of the fracturing treatment modeling.

Here, we present a case study characterizing geomechanical parameters of an unconventional reservoir using a novel technique that includes calibrated mechanical earth models. The technique reduces uncertainty in the geological and geomechanical parameters used to design hydraulic fracture operations, improving the prediction of the final stimulated rock volume.

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