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Transport in Porous Media

, Volume 108, Issue 2, pp 393–411 | Cite as

Anisotropy and Stress Dependence of Permeability in the Barnett Shale

  • Athma R. Bhandari
  • Peter B. Flemings
  • Peter J. Polito
  • Michael B. Cronin
  • Steven L. Bryant
Article

Abstract

We document vertical permeability of \(2.3 \times 10^{-21}\, \hbox {m}^{2}\) (2.3 nd) and horizontal permeability of \(9.5 \times 10^{-20}\, \hbox {m}^{2}\) (96.3 nd) in two Barnett Shale samples. The samples are composed predominantly of quartz, calcite, and clay; have a porosity and a total organic content of \(\sim \)4 % each; and have a thermal maturity of 1.9 % vitrinite reflectance. Both samples exhibit stress-dependent permeability when the confining pressure is increased from 10.3 to 41.4 MPa. We measure a permeability anisotropy, the ratio of the horizontal to the vertical permeability, of \(\sim \)40. We find that the permeability anisotropy does not vary with effective stress. Multiscale permeability, as demonstrated by pressure dissipation, is related to millimeter-scale stratigraphic variation. We attribute the permeability anisotropy to preferential flow along more permeable layers and attribute the stress dependence to pore closure. A determination of permeability anisotropy allows us to understand flow properties in horizontal and vertical directions and assists our understanding of upscaling. Characterization of stress dependency allows us to predict permeability evolution during production.

Keywords

Mudrocks Pulse-decay permeability Anisotropy Stress dependence Heterogeneity 

List of symbols

\(\alpha \)

Pressure-sensitivity factor (\(\hbox {Pa}^{-1}\))

\(\mu \)

Gas viscosity (Pa s)

\(\phi \)

Porosity of core plug

\(a\)

Ratio of sample pore volume to volume of upstream reservoir

\(b\)

Ratio of sample pore volume to volume of downstream reservoir

\(b_\mathrm{k}\)

Klinkenberg’s gas slippage factor (Pa)

\(c\)

Gas compressibility (\(\hbox {Pa}^{-1}\))

\(s\)

Semilog slope of the differential pressure decay (at 90 % decay)

\(f (a, b)\)

\((a +b + ab) - (1/3)(a+b + 0.4132 a\,b)^{2 }+ 0.0744 (a+b + 0.0578 a\, b)^{3}\)

\(k_\mathrm{a}\)

Apparent gas permeability (\(\hbox {m}^{2}\))

\(k_{0}\)

Apparent gas permeability at \(P_\mathrm{c} - P_\mathrm{p} = 0\) \((\hbox {m}^{2})\)

\(k_{\infty }\)

Absolute (Klinkenberg’s corrected) permeability

\(k_{h}\)

Horizontal permeability (\(\hbox {m}^{2}\))

\(k_{v}\)

Vertical permeability (\(\hbox {m}^{2}\))

\(L\)

Length of core plug (m)

\(P\)

Pressure in sample (Pa)

\(P_{1}\)

Upstream reservoir pressure (Pa)

\(P_{2}\)

Downstream reservoir pressure (Pa)

\(P_\mathrm{c}\)

Confining pressure (Pa)

\(P_\mathrm{D}\)

Dimensionless pressure

\(P_\mathrm{p}\)

Average pore pressure (Pa)

\(\varDelta P\)

Differential (upstream – downstream) pressure at time t (Pa)

\(\varDelta P_{0}\)

Initial differential pressure (Pa)

\(t\)

Time elapsed (s)

\(x\)

Distance along the sample (m)

Notes

Acknowledgments

This research project is funded by Shell under the Shell–UT Unconventional Research (SUTUR) program. We thank Julia Reece for her help during the early stages of this research, Patrick Smith for taking the backscattered electron images, and Jessica Maisano for taking the microscale X-ray computed tomography images. Publication authorized by the Director of the Bureau of Economic Geology, The University of Texas at Austin\(^{\mathrm{TM}}\).

Supplementary material

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Copyright information

© Springer Science+Business Media Dordrecht 2015

Authors and Affiliations

  • Athma R. Bhandari
    • 1
  • Peter B. Flemings
    • 2
  • Peter J. Polito
    • 1
  • Michael B. Cronin
    • 2
  • Steven L. Bryant
    • 3
  1. 1.Bureau of Economic Geology, Jackson School of GeosciencesThe University of Texas at AustinAustinUSA
  2. 2.Jackson School of GeosciencesThe University of Texas at AustinAustinUSA
  3. 3.Schulich School of EngineeringUniversity of CalgaryCalgaryCanada

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