Predicting equivalent permeability in fractured reservoirs requires an understanding of the fracture geometry and aperture, which cannot be fully sampled from subsurface data. We quantify for a range of aperture-size scaling models and the Barton-Bandis conductive shear model the
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Predicting equivalent permeability in fractured reservoirs requires an understanding of the fracture geometry and aperture, which cannot be fully sampled from subsurface data. We quantify for a range of aperture-size scaling models and the Barton-Bandis conductive shear model the fractures that are critically stressed at in-situ stress conditions as defined by either Coulomb friction or Barton-Bandis peak shearing. These models are applied to realistic large-scale fracture networks. (Sub-)linear length scaling predicts the largest average aperture, and subsequent equivalent permeability exceeds 1 Darcy in a 10mD matrix. In contrast, Barton-Bandis aperture predicts an equivalent permeability of 60mD. Application of critical stress criteria results in a decrease in the fraction of open fractures. For the applied stress conditions, Coulomb predicts that 50% of the network is critically stressed, compared to 80% for Barton-Bandis peak shear. The impact of the reactivated fracture network on equivalent permeability depends on the matrix properties, as in a low-permeable matrix, fracture connectivity controls equivalent permeability, while for a more permeable matrix, large absolute apertures are more important than network connectivity. Quantification of fracture flow regimes using only the ratio of fracture versus matrix permeability is insufficient, as these regimes also depend on fracture connectivity, controlled by aperture. @en