This paper describes the use of the Material Point Method (MPM) for modeling the propagation and interaction of multiple hydraulic fractures (HF) with natural fractures (NF) in the Marcellus and Eagle Ford. First the method is used on a laboratory experiment involving one HF and one NF to illustrate the effect of stress anisotropy on the curving of fracture propagation. For an anisotropy equal to 1 and a NF perpendicular to the HF, the HF propagates at an angle from the maximum horizontal stress direction. The MPM simulations show that curved propagation is unlikely for higher stress anisotropy. This result can help explain the curving of microseismic events observed in many frac stages. A recently developed geomechanical workflow is applied to an anomalous Marcellus well where a seismically derived fault attribute map was used to derive a continuous Equivalent Fracture Model (EFM). The MPM geomechanical simulation of multiple hydraulic fractures propagating in the input EFM model leads to the estimation of a strain field that correlates well with microseismicity and a J integral at each frac stage which appears to be correlated to the production log in the studied well. The new workflow is used to evaluate quantitatively the benefits of an engineered completion as compared to the regularly spaced completion. It was found that the J Integral and its correlation with the production log is a reasonable measure of the impact caused by skipping a frac stage. The new workflow is applied to an Eagle Ford well that shows three regions of microseismic character supported by tracer tests. Using the coherency as structural input, nine hydraulic frac stages were added to the Equivalent Fracture Model (EFM) to simulate the strain map, which shows the same features as the interpreted microseismic. The workflow is extended to a larger area to include a well that does not have microseismic data. The large scale curvature was used as input in the geomechanical workflow over the large area and was able to reproduce the main features seen on the well that has microseismic events but most importantly was also able to predict in the well with no microseismic its main performance characteristics through the use of a strain map that acts as a good proxy for the predicted microseismicity. The field validated geomechanical workflow based on the use of MPM and a continuous natural fracture description provides the E&P industry a powerful frac design and optimization tool that will allow fast prediction of microseismicity in any shale well that has an accurate structural attribute preferably derived from 3D surface seismic.

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