Anisotropy and Stress Dependence of Permeability in the Barnett Shale

Bhandari, A. R.; Flemings, Peter B.; Polito, P. J.; Cronin, Michael; Bryant, Steven L.

doi:10.1007/s11242-015-0482-0

Cited by 176 publications

(50 citation statements)

References 47 publications

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“…Permeability is highest along the bedding which is in good agreement with the results of Ghanizadeh et al (2014) and others (see Table 1) although they demonstrated that the parallel permeability is 3 orders of magnitude higher. Bhandari et al (2015) on the other hand find only 1 order of magnitude difference. Their observations on the Barnett Shale -a shale similar to the mineralogical composition and TOC content of the Posidonia shale -indicate directional differences of only 1 order of magnitude (⊥ 2.3 × 10 −21 m 2 , 9.5 × 10 −20 m 2 ).…”

Section: Permeabilitymentioning

confidence: 84%

Porosity and permeability determination of organic-rich Posidonia shales based on 3-D analyses by FIB-SEM microscopy

et al. 2016

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Abstract. The goal of this study is to better understand the porosity and permeability in shales to improve modelling fluid and gas flow related to shale diagenesis. Two samples (WIC and HAD) were investigated, both mid-Jurassic organic-rich Posidonia shales from Hils area, central Germany of different maturity (WIC R 0 0.53 % and HAD R 0 1.45 %). The method for image collection was focused ion beam (FIB) microscopy coupled with scanning electron microscopy (SEM). For image and data analysis Avizo and GeoDict was used. Porosity was calculated from segmented 3-D FIB based images and permeability was simulated by a Navier Stokes-Brinkman solver in the segmented images.Results show that the quantity and distribution of pore clusters and pores (≥ 40 nm) are similar. The largest pores are located within carbonates and clay minerals, whereas the smallest pores are within the matured organic matter. Orientation of the pores calculated as pore paths showed minor directional differences between the samples. Both samples have no continuous connectivity of pore clusters along the axes in the x, y, and z direction on the scale of 10 to 20 of micrometer, but do show connectivity on the micrometer scale. The volume of organic matter in the studied volume is representative of the total organic carbon (TOC) in the samples. Organic matter does show axis connectivity in the x, y, and z directions. With increasing maturity the porosity in organic matter increases from close to 0 to more than 5 %. These pores are small and in the large organic particles have little connection to the mineral matrix. Continuous pore size distributions are compared with mercury intrusion porosimetry (MIP) data. Differences between both methods are caused by resolution limits of the FIB-SEM and by the development of small pores during the maturation of the organic matter. Calculations show no permeability when only considering visible pores due to the lack of axis connectivity. Adding the organic matter with a background permeability of 1×10 −21 m 2 to the calculations, the total permeability increased by up to 1 order of magnitude for the low mature and decreases slightly for the overmature sample from the gas window. Anisotropy of permeability was observed. Permeability coefficients increase by 1 order of magnitude if simulations are performed parallel to the bedding. Our results compare well with experimental data from the literature suggesting that upscaling may be possible in the future as soon as maturity dependent organic matter permeability coefficients can be determined.

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Section: Permeabilitymentioning

confidence: 84%

Porosity and permeability determination of organic-rich Posidonia shales based on 3-D analyses by FIB-SEM microscopy

et al. 2016

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“…This range of the rock permeability agrees with many shale gas reservoirs. In Barnett shale, which contains the largest shale gas reserves in USA, permeability ranges from 5 × 10 −21 m 2 to 2 × 10 −18 m 2 (Vermylen 2011;Bhandari et al 2015).…”

Section: Simulation Results and Analysismentioning

confidence: 99%

Effect of Poroelasticity on Hydraulic Fracture Interactions

et al. 2017

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This study investigates, by performing finite element-based simulations, the influence of fluid leak-off and poroelasticity on growth of multiple hydraulic fractures that initiate from a single horizontal well. In this research, poroelastic deformation of the matrix is coupled with fluid flow in the fractures, and fluid flow in the rock matrix, in three dimensions. Effects of the fluid leakoff and poroelasticity on the propagation of the neighboring fractures are studied by varying the matrix permeability, and the Biot coefficient. Simulation results show that the stress induced by the opening of the fractures, and the stress induced by the fluid leak-off, each have the effect of locally altering the magnitudes and orientations of the principal stresses, hence altering the propagation direction of the fractures. The stress induced by the opening of the fractures tends to propagate both of the fractures away from each other in a curved trajectory, whereas the effects of fluid leak-off and poroelasticity (i.e., a higher Biot coefficient) tend to straighten the curved trajectory.

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“…In terms of the dynamic behaviors of porosity and permeability for the shale matrix, some researchers accepted the fact that the permeability is not a constant when the effective stress changes [10][11][12][13] and many experiments supported this conclusion. However, they did not consider the impact of flow regimes on the permeability of shale matrix.…”

Section: Introductionmentioning

confidence: 99%