Seeing the Big Picture – How to Use Stress Shadowing to Drive Stage Spacing

Abstract

Microseismic data were collected during the treatment of a four-well pad in the Williston Basin. After five months of producing hydrocarbons from the first pad, a second pad was also treated and monitored proximal to the first. Microseismic events recorded during the second pad treatment extended toward and accelerated across the first pad due to the enhanced permeability of the recently fractured first pad. We defined multiple pressure-diffusion fronts which were used to classify events associated with injected slickwater, injected gel, the offset pad, and depleted portions of the reservoir. Stress inversions of microseismic focal mechanisms were then performed to identify spatial and temporal changes in the stress field with respect to proximity of the injection location and elapsed time after start of the injection. Results suggest that the initial maximum and minimum horizontal stresses (SH and Sh respectively) are close in absolute magnitude and are subject to flipping relative magnitudes during the treatment and during depletion of the reservoir. Stress shadowing theory suggests that the induced stress profile proximal to a hydraulic fracture is anisotropic and is reversed in sign during the depleted state. Induced stress intensity is dependent on net pressure while induced stress extent is dependent upon fracture height. The anisotropic effects could be responsible for flipping the relative magnitudes of SH and Sh causing the observed focal mechanisms to shift from normal dip-slip movement to oblique slip (rake between dip-slip and strike-slip). Stress inversion results were combined with induced stress effects as a function of fracture height to identify the optimal stage spacing when SH=Sh. The goal is to take advantage of stress shadowing effects to grow complex fractures in more of a radial fashion rather than producing long linear fractures. Stress shadowing effects are dependent upon time between shut down and pressuring up of the following stage which is related to the hydraulic diffusivity of the newly fractured system permeability which was calculated from the pressure-diffusion back front observed after shutting down the pumps. In addition, we identified focal mechanisms that are characteristic of the depleted reservoir state which allows for an easier distinction between fluid-induced microseismicity and microseismicity associated with the depleted reservoir.

AAPG Datapages/Search and Discovery Article #90291 ©2017 AAPG Annual Convention and Exhibition, Houston, Texas, April 2-5, 2017