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Crawford, B. R. (ExxonMobil Upstream Research Company) | Tsenn, M. C. (ExxonMobil Upstream Research Company) | Homburg, J. M. (ExxonMobil Upstream Research Company) | Freysteinson, J. A. (ExxonMobil Upstream Research Company) | Reese, W. C. (ExxonMobil Upstream Research Company)
Tensile, opening mode fractures created in a variety of low matrix permeability rocks have initial, unstressed apertures in the μm to mm range as determined from image analyses of X-ray CT scans. Subsequent hydrostatic compression of these fractured samples with synchronous radial strain and flow measurement indicates that both mechanical and hydraulic aperture reduction varies linearly with the natural logarithm of effective normal stress. These stress-sensitive single-fracture laboratory observations are upscaled to models of fracture populations displaying frequency-length and length-aperture scaling laws commonly exhibited by natural fracture arrays. Functional relationships between reservoir pressure reduction and fracture network porosity, compressibility and directional permeabilities are generated that can ultimately be exported to the reservoir simulator for improved naturally fractured reservoir performance prediction.
Many fine-grained reservoirs (clastics, carbonates and mudrocks) require the additional permeability associated with partially open natural fractures (NF's) to achieve economic flow rates. Depletion-driven matrix compaction is routinely accounted for when simulating the performance of conventional reservoirs such as deep-water sands (Guenther et al, 2005; Pourciau et al, 2005) however predicting in a similar fashion the impact of declining fluid pressure on naturally fractured reservoir (NFR) productivity is less well-established.
Uniaxial strain testing of recovered core provides direct measurement of formation compressibility and matrix permeability reduction (Crawford et al, 2011; Ewy et al, 2012) that can subsequently be incorporated in conventional reservoir simulation studies to account for compaction. Challenges in capturing analogous geomechanical effects in NFR performance prediction can in part be attributed to a paucity of hydromechanical measurements of NF response to effective stress changes appropriate to the hydrocarbon reservoir environment and difficulties in upscaling the laboratory stress-sensitivity of single fractures to in situ NF populations exhibiting frequency-size distributions in geometric attributes.
We report new measurements of stress-dependent mechanical and hydraulic aperture reduction in fractured specimens and describe a workflow for upscaling this dynamic response to discrete fracture network (DFN) models which we use to rank the influence of in situ stress orientation and magnitude, pressure depletion and fracture surface roughness on network compressibility and permeability response.
Frash, L. P. (Los Alamos National Laboratory) | Carey, J. W. (Los Alamos National Laboratory) | Ickes, T. (Los Alamos National Laboratory) | Porter, M. L. (Los Alamos National Laboratory) | Viswanathan, H. S. (Los Alamos National Laboratory)
ABSTRACT: Rock fractures in the subsurface have the potential to act as fluid flow pathways but the permeability of existing, new, or future in-situ rock fractures is difficult to characterize. We perform triaxial direct shear experiments to evaluate the permeability potential of freshly created fractures as a function of stress/depth using specimens of carbonate-rich Marcellus Shale. Applied confining stress ranged from 2 to 30 MPa, specimens were 25 mm diameter and 25 mm length, shearing displacement of at least 2 mm was imposed, and measured permeability ranged between 10−3 and 104 mD as dependent on stress and fracture conditions. Simultaneous X-ray video and computed tomography were used to directly measure fracture displacement and apertures. Results show that the stress at which fractures form is likely the most significant factor controlling fracture permeability, with higher stresses causing significant 2 to 4 orders of magnitude permeability reduction. The effect of creating fractures at high stress on permeability reduction was significantly stronger than the effect of increasing the confining stress on an existing fracture. Results included analysis of transient fracture permeability following renewed shear displacement, a process which resulted in rapid permeability enhancement followed by a slower decay in permeability.
Permeability of existing and/or potential fractures in the subsurface is a key parameter for subsurface fluid flow modeling, as relevant for a sustainable energy future and preservation of potable aquifers. Previous studies have investigated fracture permeability in relation to the so-called ‘cubic-law’ (Witherspoon et al., 1980; Zimmerman and Bovarsson, 1996) in which fracture aperture can be related to fluid conductivity if complexities arising from surface roughness and asperity contacts are adequately taken into account. This ‘effective’ hydraulic aperture is dependent upon the state of stress on the fracture (Barton et al., 1985, Brown, 1987; Cho et al., 2013; Gutierrez et al., 2000; Pyrak-Nolte and Morris, 2000; Zhang et al., 2007) and shearing displacement along the fracture (Bandis et al., 1983; Detwiler and Morris, 2014; Gentier et al., 1997; Lee and Cho, 2002; Olsson and Brown, 1993; Yeo et al., 1988). In addition there are temporal effects including chemical dissolution and precipitation (Armitage et al., 2013; Detwiler, 2010; Noriel, 2015), mobilization and filtering of fines (Oliveira et al., 2014; You et al., 2015), and mechanical self-sealing (Bastiaens et al., 2007; Elkhoury et al., 2015). No previous studies, known to the authors, have attempted to investigate the permeability of fractures that are created at in situ stress conditions. Such conditions are directly relevant for evaluating the potential for stimulation or creation of permeable fractures, whether by natural phenomena, such as faulting, or by human activity, such as fluid injection.