Dependence of gas shale fracture permeability on effective stress and reservoir pressure: Model match and insights

The Marcellus Formation, a Devonian gas shale in the Appalachian Basin, is a heterogeneous rock as the result of a complex depositional, diagenetic, and deformational history. Although it is overpressured over a large portion of its economic area, the origin and distribution of pore pressure within the gas shale are not well-understood. We have used the sonic properties of the Marcellus and statistical analyses to tackle this problem. The sonic data come from a suite of 53 wells including a calibration well in the Appalachian Basin. We first analyze the influence of various extrinsic and intrinsic parameters on sonic velocities with univariate regression analyses. The sonic velocities of the Marcellus in the calibration well generally decrease with an increase in gamma-ray american petroleum institute (API) and increase with density and effective stress. Basin-wide median sonic velocities generally decrease with an increase in median gamma-ray API and pore pressure and increase with burial depth (equivalent confining stress), effective stress, and median density. Abnormal pore pressure is verified by a stronger correlation between the median sonic properties and effective stress using an effective stress coefficient of approximately 0.7 relative to the correlation between the median sonic properties and depth. The relatively small effective stress coefficient may be related to the fact that natural gas, a “soft” fluid, is responsible for a basin-wide overpressure of the Marcellus. Following the univariate regression analyses, we adopt a multiple linear regression model to predict the median sonic velocities in the Marcellus based on median gamma-ray intensity, median density, thickness of the Marcellus, confining pressure, and an inferred pore pressure. Finally, we predict the pore pressure in the Marcellus based on median sonic velocities, median gamma-ray intensity, median density, thickness of the Marcellus, and confining pressure.

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Fractal analysis of directional permeability of gas shale fracture networks: A numerical study

Journal of Natural Gas Science and Engineering ◽

10.1016/j.jngse.2016.05.043 ◽

2016 ◽

Vol 33 ◽

pp. 1330-1341 ◽

Cited By ~ 26

Author(s):

Richeng Liu ◽

Liyuan Yu ◽

Yujing Jiang

Keyword(s):

Fractal Analysis ◽

Numerical Study ◽

Gas Shale ◽

Fracture Networks ◽

Directional Permeability ◽

Shale Fracture

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Experimental Study of Fracture Permeability With or Without Proppants on Vaca Muerta Gas Shale

Proceedings of the 7th Unconventional Resources Technology Conference ◽

10.15530/urtec-2019-998 ◽

2019 ◽

Author(s):

Kun Su ◽

Martin Santacoloma ◽

Sebastian Estrada ◽

Pierre Barlet ◽

Hamid Pourpak

Keyword(s):

Experimental Study ◽

Gas Shale ◽

Fracture Permeability ◽

Vaca Muerta

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CBM exploration: Permeability of coal owing to cleat and connected fracture

Energy Exploration & Exploitation ◽

10.1177/01445987211057195 ◽

2021 ◽

pp. 014459872110571

Author(s):

Zhigang Du ◽

Yawen Tao ◽

Xiaodong Zhang ◽

Wuxiu Ding ◽

Qiang Huang

Keyword(s):

Coalbed Methane ◽

Gas Pressure ◽

Molecular Flow ◽

Target Area ◽

Reservoir Pressure ◽

Gas Migration ◽

Fracture Permeability ◽

Klinkenberg Effect ◽

Linear Flow ◽

Cbm Production

Coalbed methane (CBM) resources cannot be efficiently explored and exploited without a robust understanding of the permeability of fracture-size heterogeneities in coal. In this study, two sister coal samples were imparted with pre-developed cleat and connected fractures, and the permeability of the coal samples was measured under different conditions of controlled confining and gas pressures. Furthermore, the implications of the results for CBM exploration and exploitation were discussed. The permeability of coal with cleat development ranged from 0.001–0.01 mD, indicating ultra-low permeability coal. The gas migration in this coal changed from a linear flow to a non-linear flow, with the increase in gas pressure (>1 MPa). Thus, the permeability of the coal initially increased and then decreased. However, the Klinkenberg effect does not exist in this ultralow-permeability coal. For the coal sample with connected fracture, permeability ranged from 0.1–10 mD, which is larger by hundred orders of magnitude than that of the sample with cleat. For this coal, with a decrease in gas pressure (<1 MPa), the Klinkenberg effect significantly increased the permeability of the coal. With an increase in the applied confining pressure, both the Klinkenberg coefficient and permeability of the coal presented a decreasing trend. It is suggested that field fracture investigation is a prerequisite and indispensable step for successful CBM production. The coal beds that cleat network is well conductive to the connected fracture can be an improved target area for CBM production. During CBM production, a variety of flow regimes are available owing to the decrease in CBM reservoir pressure. In particular, under the low CBM reservoir pressure and low in situ geo-stress conditions, the gas migration in the CBM reservoir with connected facture development exhibits remarkable free-molecular flow. Thus, the reservoir permeability and predicted CBM production will be enhanced.

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