Modeling Multiple Hydraulic Fractures Interacting with Natural Fractures Using the Material Point Method

Abstract

Abstract This paper describes use of the Material Point Method (MPM) for modeling the propagation and interaction of multiple hydraulic fractures (HF) with natural fractures (NF). First the method is used on a laboratory experiment involving one HF and one NF positioned at different angles from the maximum horizontal stress. Various geomechanical simulations are performed by varying the stress anisotropy and the angle of the NF to study the remote impact of the HF on the NF. The results show the various levels of influence a HF has on a NF with a general trend being a higher influence for lower anisotropy ratio and lower NF angles. For an anisotropy equal to 1 and a NF with angle of 90 degrees, the detailed NF opening mechanism before, during and after the HF crosses a NF is studied in detail. The MPM simulations show that under the influence of the HF, the NF opening starts before the HF reaches it and even before the HF propagation. This result could help better understand the microseismic events recorded farther from the HF tip. Finally, a new workflow that integrates geophysics, geology, geomechanical simulations using MPM and completion engineering is described and validated with a real and complex Marcellus gas shale well. The workflow uses a seismically derived fault attribute map as input into the Continuous Fracture Modeling (CFM) approach to generate an Equivalent Fracture Model (EFM). The MPM geomechanical simulation of multiple hydraulic fractures propagating in the input EFM model leads to estimation of a strain field and J integral at each frac stage with a computation time not exceeding a few hours. The application of this workflow to an anomalous Marcellus gas well, shows that the estimated strain model has many striking similarities with the interpreted microseismic. The shape and the extent of the geobodies seen in the simulated strain field are very similar to those seen in the microseismic. Furthermore, the predicted J integral at each frac stage is correlated well with the density of the microseismic events at the same frac stage. The entire workflow takes only few hours thus making it suitable for any completion engineer designing his well. The new workflow brings improved and realistic geomechanics into the G&G world by providing new insights into the complex behavior of multiple hydraulic fractures propagating in a naturally fractured reservoir. This new insight will provide an additional powerful tool for an integrated approach that combines G&G, geomechanics and engineering for the imaging of sweet spots and reliable estimates of well performance thus allowing improved and economical fracing and development of shale reservoirs.