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

Kwon, Ohmyoung; Kronenberg, A. K.; Gangi, Anthony F.; Johnson, Brann; Herbert, Bruce

doi:10.1029/2004jb003052

Cited by 205 publications

(115 citation statements)

References 80 publications

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“…Several studies have shown the existence of anisotropy in the shale formations (McCarthy 1991;Ayan et al 1994;Kwon et al 2004;Burton 2011). In fact, anisotropy exists in the scale of micrometer or nanometer under microstructural observations using transmission electron microscopy (TEM) (Kwon et al 2004). To take into account such anisotropy into the model, the permeability has to be represented as a full tensor.…”

Section: Introductionmentioning

confidence: 99%

Numerical Simulation of Natural Gas Flow in Anisotropic Shale Reservoirs

Negara

Salama

Sun

et al. 2015

Day 3 Wed, November 11, 2015

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Shale gas resources have received great attention in the last decade due to the decline of the conventional gas resources. Unlike conventional gas reservoirs, the gas flow in shale formations involves complex processes with many mechanisms such as Knudsen diffusion, slip flow (Klinkenberg effect), gas adsorption and desorption, strong rock-fluid interaction, etc. Shale formations are characterized by the tiny porosity and extremely low-permeability such that the Darcy equation may no longer be valid. Therefore, the Darcy equation needs to be revised through the permeability factor by introducing the apparent permeability. With respect to the rock formations, several studies have shown the existence of anisotropy in shale reservoirs, which is an essential feature that has been established as a consequence of the different geological processes over long period of time. Anisotropy of hydraulic properties of subsurface rock formations plays a significant role in dictating the direction of fluid flow. The direction of fluid flow is not only dependent on the direction of pressure gradient, but it also depends on the principal directions of anisotropy. Therefore, it is very important to take into consideration anisotropy when modeling gas flow in shale reservoirs. In this work, the gas flow mechanisms as mentioned earlier together with anisotropy are incorporated into the dual-porosity dual-permeability model through the full-tensor apparent permeability. We employ the multipoint flux approximation (MPFA) method to handle the full-tensor apparent permeability. We combine MPFA method with the experimenting pressure field approach, i.e., a newly developed technique that enables us to solve the global problem by breaking it into a multitude of local problems. This approach generates a set of predefined pressure fields in the solution domain in such a way that the undetermined coefficients are calculated from these pressure fields. In other words, the matrix of coefficients is constructed automatically within the solver. We ran a numerical model with different scenarios of anisotropy orientations and compared the results with the isotropic model in order to show the differences between them. We investigated the effect of anisotropy in both the matrix and fracture systems. The numerical results show anisotropy plays a crucial role in dictating the pressure fields as well as the gas flow streamlines. Furthermore, the numerical results clearly show the effects of anisotropy on the production rate and cumulative production. Incorporating anisotropy together with gas flow mechanisms in shale formations into the reservoir model is essential particularly for predicting maximum gas production from shale reservoirs.

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Section: Introductionmentioning

confidence: 99%

Numerical Simulation of Natural Gas Flow in Anisotropic Shale Reservoirs

Negara

Salama

Sun

et al. 2015

Day 3 Wed, November 11, 2015

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show abstract

“…We assume that maximum permeability is five times larger than minimum permeability parallel to bedding, and permeability parallel to bedding (red arrows in Figure 8) is 10 times larger than permeability perpendicular to bedding, since Kwon et al [4] proposed that permeabilities (Wilcox shale) measured parallel to bedding are about 1 order of magnitude greater than permeability measured perpendicular to bedding.…”

Section: Effect Of Permeability Anisotropy On Production Ratementioning

confidence: 99%

“…Some researchers have studied the permeability anisotropy of shales. Kwon et al [4] reported that the permeabilities of Wilcox shale measured parallel to bedding are about one order of magnitude greater than those measured perpendicular to bedding. Other researchers mainly focused on seismic or log data [5][6][7], Research and practice show that permeabilities are not the same in different directions, so permeability has vector characters.…”

Section: Introductionmentioning

confidence: 99%

Effect of Permeability Anisotropy on the Production of Multi-Scale Shale Gas Reservoirs

Huang

Tao

et al. 2017

Energies

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Shales or mudstones are fine grained and layered reservoirs, which leads to strong shale permeability anisotropy. Shale has a wide pore-size distribution, and pores with different diameters contribute differently to the apparent permeability of shales. Therefore, understanding the anisotropy of multiscale shale gas reservoirs is an important aspect to model and evaluate gas production from shales. In this paper, a novel model of permeability anisotropy for shale gas reservoirs is presented to calculate the permeability in an arbitrary direction in three dimensional space. A numerical model which is valid for the entire Knudsen's range (continuum flow, slip flow, transition flow and free molecular flow) in shale gas reservoirs was developed, and the effect of gas-water flow and the simulation of hydraulic fracturing cracks were taken into consideration as well. The simulation result of the developed model was validated with field data. Effects of critical factors such as permeability anisotropy, relative permeability curves with different nanopore radii and initial water saturation in formation on the gas production rate of multi-stage fractured horizontal well were discussed. Besides, flow regimes of gas flow in shales were classified by Knudsen number, and the effect of various flow regimes on both apparent permeability of shales and then the gas production has been analyzed thoroughly.

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“…Pressure conditions within the host rock will be thoroughly assessed once more specific details of the argillaceous host formation become available. Soeder (1988) 3e-15 to 3e-12 Wilcox Louisiana Kwon et al (2004) Specific storativity (m -1 )…”

Section: Hydraulic Conditions In the Argillaceous Formationmentioning

confidence: 99%