Abstract

High-volume (>200MBBLS/well), slickwater hydraulic fracturing operations on vertical Williams Fork wells in the Piceance Basin, CO have resulted in >2X increases in initial production rates and estimated ultimate gas recoveries. Here we present a model for the role of increased water-injection volumes in increasing well productivity. Predominantly vertical, east-west striking natural fractures, as indicated by interpreted image logs, are optimally oriented for shear failure with respect to the east-west maximum horizontal stress direction. Borehole breakout modeling of the same image log dataset suggests a large maximum horizontal stress, further critically stressing existing vertical natural fractures. Hydraulic fracturing and leakoff were modeled using commercial modeling platforms to constrain both the 2D hydraulic fracture dimensions as well as changes in reservoir pressure during and after injection. Post and syn-injection reservoir pressure distributions, natural fracture distributions, and stresses were then put into an in-house geomechanical modeling program to determine the magnitude and distribution of shear failures along natural fractures associated with changes in net effective stresses. All models worked in tandem to history match injection rates, injection pressures and microseismic event distributions. Modeling results show that an elevated reservoir pressure due to high injection rates and water volumes during hydraulic fracturing result in the stimulation of more natural fracture orientations over a greater area, thereby increasing the size and permeability of the stimulated reservoir volume. The lack of necessity for proppant in Williams Fork completions suggests that most of the fractures are failing in shear and are self propping, which allow for benefit from reactivated natural fractures that are not hydraulically connected back to the wellbore via propped tensile fractures. Therefore, injection-enhanced stimulations are likely associated with large stress anisotropies and abundant natural fractures that are chiefly oriented subparallel to the maximum horizontal stress azimuth. The ability of the rocks to "self prop" will dictate the magnitude and duration of permeability enhancement. So although only self propping rocks will see long term benefit from the shear failure of natural fractures, this model may still have utility when assessing the early-time productivity of more ductile and compliant reservoirs, which will see a degradation in productivity as the reservoir is drawn down and fractures begin to close.

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