Unconventional resources require fracture stimulation to achieve economic production rates and recoveries. However, hydraulic fracture modeling in resource plays, specifically in the Eagle Ford Shale, is challenging and often reduced to “rules of thumb” and design concepts taken from other shale plays. Although there is a place for extrapolating best practices to the Eagle Ford from other reservoirs, the calcareous makeup of the rock, the complex geology and condensate-rich environment present unique completion challenges.
Furthermore, concepts of pressure-dependent leakoff, process zone stress, hoop stress, stress-dependent Young’s modulus, and complex fracture propagation limit confidence in traditional fracture models, and can result in early job terminations and less-thanoptimal fracture stimulations. These challenges require a hydraulic fracture model and treatment design tailored specifically to the Eagle Ford.
To optimize hydraulic fracture design in the Eagle Ford, one study applied a first-order discrete fracture network (DFN) model to predict fracture geometry. In addition, an approximate analytical production solution for multiple finite conductivity for vertical transverse fractures was used to production history match the well flow streams for DFN calibration and to aid in fracture optimization. Fracture length, conductivity and spacing for multicluster, multistage completions along the horizontal well bore were varied to illustrate the impact of improved hydraulic fracture design on well production and the effect of fracture interference on the resulting geometries and production.
Author(s): Mark Chapman, Lucas W. Bazan, Sam D. Larkin, Michael G. Lattibeaudiere, Terry T. Palisch, Robert Duenckel