Permeability of illite‐bearing shale: 2. Influence of fluid chemistry on flow and functionally connected pores

Kwon, Ohmyoung; Herbert, Bruce; Kronenberg, A. K.

doi:10.1029/2004jb003055

Cited by 39 publications

(23 citation statements)

References 75 publications

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“…Marcellus shale has very low natural intrinsic permeability, on the order of 10 −16 Darcies (Kwon et al 2004a, 2004b; Neuzil 1986, 1994). Schulze‐Makuch et al (1999) described Devonian shale of the Appalachian Basin, of which the Marcellus is a major part, as containing “coaly organic material and appear either gray or black” and being “composed mainly of tiny quartz grains <0.005 mm diameter with sheets of thin clay flakes.” Median particle size is 0.0069 ± 0.00141 mm with a grain size distribution of <2% sand, 73% silt, and 25% clay.…”

Section: Methods Of Analysismentioning

confidence: 99%

Potential Contaminant Pathways from Hydraulically Fractured Shale to Aquifers

2012

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Hydraulic fracturing of deep shale beds to develop natural gas has caused concern regarding the potential for various forms of water pollution. Two potential pathways-advective transport through bulk media and preferential flow through fractures-could allow the transport of contaminants from the fractured shale to aquifers. There is substantial geologic evidence that natural vertical flow drives contaminants, mostly brine, to near the surface from deep evaporite sources. Interpretative modeling shows that advective transport could require up to tens of thousands of years to move contaminants to the surface, but also that fracking the shale could reduce that transport time to tens or hundreds of years. Conductive faults or fracture zones, as found throughout the Marcellus shale region, could reduce the travel time further. Injection of up to 15,000,000 L of fluid into the shale generates high pressure at the well, which decreases with distance from the well and with time after injection as the fluid advects through the shale. The advection displaces native fluids, mostly brine, and fractures the bulk media widening existing fractures. Simulated pressure returns to pre-injection levels in about 300 d. The overall system requires from 3 to 6 years to reach a new equilibrium reflecting the significant changes caused by fracking the shale, which could allow advective transport to aquifers in less than 10 years. The rapid expansion of hydraulic fracturing requires that monitoring systems be employed to track the movement of contaminants and that gas wells have a reasonable offset from faults.

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Section: Methods Of Analysismentioning

confidence: 99%

Potential Contaminant Pathways from Hydraulically Fractured Shale to Aquifers

2012

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“…Accompanying these measurements, we use electron microscopy to examine relationships between clay mineral fabrics and intergranular pores and make interpretations of permeability anisotropy and observed changes in k upon cyclic loading. All results reported here apply to the flow of 1 M NaCl solution; effects of fluid composition on permeability of Wilcox shale are addressed in a companion study [Kwon et al, 2004].…”

Section: Introductionmentioning

confidence: 99%

Permeability of illite‐bearing shale: 1. Anisotropy and effects of clay content and loading

et al. 2004

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[1] Permeability of illite-rich shale recovered from the Wilcox formation and saturated with 1 M NaCl solution varies from 3 Â 10 À22 to 3 Â 10 À19 m 2 , depending on flow direction relative to bedding, clay content (40-65%), and effective pressure P e (2-12 MPa). Permeability k is anisotropic at low P e ; measured k values for flow parallel to bedding at P e = 3 MPa exceed those for flow perpendicular to bedding by a factor of 10, both for low clay content (LC) and high clay content (HC) samples. With increasing P e , k becomes increasingly isotropic, showing little directional dependence at 10-12 MPa. Permeability depends on clay content; k measured for LC samples exceed those of HC samples by a factor of 5. Permeability decreases irreversibly with the application of P e , following a cubic law of the form k = k 0 [1 À (P e /P 1 ) m ] 3 , where k 0 varies over 3 orders of magnitude, depending on orientation and clay content, m is dependent only on orientation (equal to 0.166 for bedding-parallel flow and 0.52 for flow across bedding), and P 1 (18-27 MPa) appears to be similar for all orientations and clay contents. Anisotropy and reductions in permeability with P e are attributed to the presence of crack-like voids parallel to bedding and their closure upon loading, respectively.

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“…Their permeability also exhibits a higher degree of anisotropy (Zhang, 2005). For example, the ratios of the permeability measured parallel to bedding over those measured perpendicular to bedding for the Wilcox shale are greater than 10 (Kwon et al, 2004), whereas this ratio is only 4 for Berea sandstone (Zoback and Byerlee, 1976) and 2.2 and 1.2 for Crab Orchard sandstone and Bentheim sandstone, respectively (Benson et al, 2005;Louis et al, 2005).…”

Section: Properties Of Clayey Rockmentioning

confidence: 95%