Distribution and Properties of Faults and Fractures in Shales: Permeability Model and Implications for Optimum Flow Stimulation by Hydraulic Fracturing
- J. H. TerHeege (TNO Petroleum Geosciences)
- Document ID
- American Rock Mechanics Association
- 50th U.S. Rock Mechanics/Geomechanics Symposium, 26-29 June, Houston, Texas
- Publication Date
- Document Type
- Conference Paper
- 2016. Not subject to copyright. This document was prepared by government employees or with government funding that places it in the public domain.
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The spatial distribution of reactivated fractures and fracture permeability after stimulation are key controlling factors that determine typical drainage areas, shale to well connectivity, and hydrocarbon flow rates in fractured shales. In this paper, the influence of fault and fracture populations on the permeability of fractured shales is studied using an analytical model and field data of fault and fracture populations derived from a 3D seismic survey covering the Posidonia Shale Formation in the West Netherlands Basin. The analytical model incorporates fault and fracture populations and describes the permeability of fractured shales using 3D permeability tensors for layered shale matrix, damage zone and fault core of fault zones. A model sensitivity analysis shows that bulk permeability can vary considerably, depending on permeability anisotropy in the matrix, damage zone and fault core, the orientation of matrix layers and damage zone fractures, and the location relative to the fault core. The field data shows the distribution of fault sizes and displacements and associated model input parameters in comparison to typical fault scaling relations from literature. Implications of the analysis for optimum well planning and flow stimulation using hydraulic fracturing in naturally fractured shales are given.
In many prospective shales, hydrocarbon production is determined by the distribution and properties of natural faults and fractures (Gale and Holder, 2010; King, 2010). The spatial distribution of reactivated fractures and fracture permeability after stimulation are key controlling factors that determine typical drainage areas, shale to well connectivity, and hydrocarbon flow rates. Fault and fracture populations, orientations, and permeability have been analysed in studies of seismic surveys, outcrop analogues, core material, and laboratory experiments (Odling et al., 1999; Bonnet et al., 2001; Torabi and Berg, 2011). Data from these studies can be used to characterize fault and fracture populations, and describe permeability of fractured shales for areas with limited available data (TerHeege and DeBruin, 2015a). Also, natural faults and fractures are not generally incorporated in conventional hydraulic fracturing simulators that are based on tensile opening of induced fractures (e.g., Meyer and Bazan, 2011). Knowledge on typical distribution and properties of natural faults and fractures can therefore help optimizing flow stimulation by hydraulic fracturing.
Reservoir-scale fault zones generally exhibit a specific architecture with a fault core and damage zone, surrounded by intact reservoir rock (Caine et al., 1996).
This architecture will determine the permeability in the vicinity of fault zones (Mitchell and Faulkner, 2012). Considering the importance of the distribution of faults and fractures in determining stimulated reservoir volume and gas production, it is important to better describe permeability in faulted and fractured shales and incorporate this description in models of gas flow.
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