Geological controls on matrix permeability of Devonian Gas Shales in the Horn River and Liard basins, northeastern British Columbia, Canada

Chalmers, Gareth R.L.; Ross, Daniel; Bustin, R. Marc

doi:10.1016/j.coal.2012.05.006

Cited by 402 publications

(188 citation statements)

References 33 publications

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“…Change of rock effective stress can be caused by internal pressure (i.e., gas pressure) and external pressure (i.e., confining stress) variations. The effect of effective stress on shale permeability is closely related to shale pore-fracture system (Chalmers et al, 2012). In the study by Li et al (2014), they reported that the coal with a lower permeability will have a stronger sensitivity of the permeability to the effective stress.…”

Section: Effective Stressmentioning

confidence: 99%

“…Previous experiments showed that the permeability decrease in an exponential form with the increase in the effective stress (Mckee et al, 1988;Reyes et al, 2002;Chalmers et al, 2012;Ghanizadeh et al, 2014a;2014b;Chen et al, 2015;Zhang et al, 2015a;2015b;. Change of rock effective stress can be caused by internal pressure (i.e., gas pressure) and external pressure (i.e., confining stress) variations.…”

Section: Effective Stressmentioning

confidence: 99%

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Insights on the gas permeability change in porous shale

Chen

Xu³

et al. 2017

Adv. Geo-Energ. Res.

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Due to abundant nanoscale pores developed in shale, gas flow in shale presents a complex dynamic process. This paper summarized the effects from effective stress increase, shale matrix shrinkage, gas slippage and Knudsen diffusion on the gas permeability change in shale during shale gas recovery. With the reduce in gas pressure, effective stress increase leads to the decline of the permeability in an exponential form; the permeability increases due to the shale matrix shrinkage induced by gas desorption; appearances of gas slippage and Knudsen diffusion cause an additional increase in the gas permeability particularly in small pores at low pressures. In addition, some reported models evaluating the shale permeability were reviewed preliminarily. Models considering these four effects may be potentially effective to evaluate the gas permeability change in shale.

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Section: Effective Stressmentioning

confidence: 99%

Section: Effective Stressmentioning

confidence: 99%

Insights on the gas permeability change in porous shale

Chen

Xu³

et al. 2017

Adv. Geo-Energ. Res.

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“…The lowest sensitivity to effective stress (0.006 MPa −1 ) was observed for sample P2 (5.5 wt% clay), even though sample P2 showed the highest permeability measurement. According to Chalmers et al [12], one is more likely to observe greater sensitivity to changes in effective stress in samples that have higher permeability. This, however, was not observed here, indicating that stress-dependent permeability was greatly influenced by rock mineralogy, particularly clay content.…”

Section: (D) Stress-dependent Permeabilitymentioning

confidence: 99%

“…In this work, the stress-dependent permeability was determined by measuring the permeability of the samples over a range of effective stresses. The stress dependence of permeability can be described according to the following exponential function [10][11][12][13]:…”

Section: (A) Pressure Pulse Decay Techniquementioning

confidence: 99%

Effects of rock mineralogy and pore structure on stress-dependent permeability of shale samples

Ismail¹,

Zoback²

2016

Phil. Trans. R. Soc. A.

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We conducted pulse-decay permeability experiments on Utica and Permian shale samples to investigate the effect of rock mineralogy and pore structure on the transport mechanisms using a non-adsorbing gas (argon). The mineralogy of the shale samples varied from clay rich to calcite rich (i.e. clay poor). Our permeability measurements and scanning electron microscopy images revealed that the permeability of the shale samples whose pores resided in the kerogen positively correlated with organic content. Our results showed that the absolute value of permeability was not affected by the mineral composition of the shale samples. Additionally, our results indicated that clay content played a significant role in the stressdependent permeability. For clay-rich samples, we observed higher pore throat compressibility, which led to higher permeability reduction at increasing effective stress than with calcite-rich samples. Our findings highlight the importance of considering permeability to be stress dependent to achieve more accurate reservoir simulations especially for clay-rich shale reservoirs.This article is part of the themed issue 'Energy and the subsurface'.

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“…29,30 However, by following an experimental approach, no distinction can be made between diffusion and convection and hence, the mechanism of fluid transport cannot be identified with certainty. 31 One approach implements empirical equations derived from Darcy's law. Within this approach, Darcy's equation is enriched with coefficients designed to match experimental data for systems that, e.g., exhibit slip flow.…”

Section: Introductionmentioning

confidence: 99%

A kinetic Monte Carlo approach to study fluid transport in pore networks

Apostolopoulou

Day

Hull

et al. 2017

The Journal of Chemical Physics

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The mechanism of fluid migration in porous networks continues to attract great interest. Darcy's law (phenomenological continuum theory), which is often used to describe macroscopically fluid flow through a porous material, is thought to fail in nano-channels. Transport through heterogeneous and anisotropic systems, characterized by a broad distribution of pores, occurs via a contribution of different transport mechanisms, all of which need to be accounted for. The situation is likely more complicated when immiscible fluid mixtures are present. To generalize the study of fluid transport through a porous network, we developed a stochastic kinetic Monte Carlo (KMC) model. In our lattice model, the pore network is represented as a set of connected finite volumes (voxels), and transport is simulated as a random walk of molecules, which "hop" from voxel to voxel. We simulated fluid transport along an effectively 1D pore and we compared the results to those expected by solving analytically the diffusion equation. The KMC model was then implemented to quantify the transport of methane through hydrated micropores, in which case atomistic molecular dynamic simulation results were reproduced. The model was then used to study flow through pore networks, where it was able to quantify the effect of the pore length and the effect of the network's connectivity. The results are consistent with experiments but also provide additional physical insights. Extension of the model will be useful to better understand fluid transport in shale rocks.

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Geological controls on matrix permeability of Devonian Gas Shales in the Horn River and Liard basins, northeastern British Columbia, Canada

Cited by 402 publications

References 33 publications

Insights on the gas permeability change in porous shale

Insights on the gas permeability change in porous shale

Effects of rock mineralogy and pore structure on stress-dependent permeability of shale samples

A kinetic Monte Carlo approach to study fluid transport in pore networks

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