AAPG Southwest Section

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Prediction of hydraulic fracture damaged zone geometries in the Woodford Shale in Arkoma Basin using discrete fracture network models

Abstract

Understanding natural fracture stimulation patterns in highly fractured shale reservoirs is important for determining drainage volume. In the absence of image logs, natural fracture parameters studied at Woodford Shale and Hunton Group Limestone outcrops/quarries were used to understand artificial hydraulic fracture propagation in an Arkoma Basin well located 20-25 miles to the east of the outcrops. The outcrop fracture parameters were used as input into FracManTM discrete fracture network simulator to match the microseismic geometry from three hydraulic fracture stages. The simulations and matched microseismic geometry provide insights into the mechanical effect and average fracture permeabilities of the Woodford Shale and bounding formations.

The simulator predicts a lower than 2% fluid efficiency (i.e., > 98% leak off) in the stimulated area. Reducing the number of natural fractures leads to high fluid efficiency (lower leak-off ratio) in areas where fluid flow is restricted to only dilatable fractures. In stages where flow through non-dilatable fractures was allowed, high efficiency was not obtainable. With increased fluid efficiency (using fluid loss additives or increasing fluid viscosity), a larger parent hydraulic fracture is created, though with more out of zone natural fracture stimulation. By setting a higher-pressure drop slope, which might result from using a high viscosity/high-density fluid or fine proppants, smaller stimulated volumes with larger inflated storage apertures were obtained.

Pumping at a higher net pressure was found to reduce the overall stimulation volume and open more, previously non-dilatable, fractures closer to the wellbore. Higher net pressure also caused more stimulation downward and out of the target zone. These observations suggest limiting the slurry rate. However, when a high slurry rate is applied for better proppant placement, the simulations indicate that the horizontal well should be placed high in the Woodford Shale due to downward reactivation of natural fractures. Shifting the well locations within the Woodford Shale in the simulator did not affect the overall microseismic cloud dimensions considerably. However, increasing lateral strain (i.e., stress shadow effect) with successive stages limited the stimulation to the formations closer to the wellbore and corresponding lengthening of the microseismic could in these formations.