A pore network modelling approach to investigate the interplay between local and Darcy viscosities during the flow of shear-thinning fluids in porous media

Castro, Antonio Rodríguez de; Goyeau, Benoı̂t

doi:10.1016/j.jcis.2021.01.081

Cited by 11 publications

(3 citation statements)

References 55 publications

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“…For a deeper understanding of these processes, researchers use modern modeling techniques for the computation of micro and macro parameters of porous medium. One such technique is fluid flow simulation based on pore network modeling, which allows for the analysis of fluid flow behavior in porous media at the pore scale [9][10][11][12]. Confirmation of the importance of these studies can be found in research that utilizes 3D pore models of samples and numerical modeling to investigate the influence of pore geometry on fluid flow in porous media.…”

Section: Introductionmentioning

confidence: 99%

Effect of Rock Dissolution on Two-Phase Relative Permeabilities: Pore-Scale Simulations Based on Experimental Data

Bolysbek,

Kuljabekov,

Uzbekaliyev

et al. 2023

Applied Sciences

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Relative phase permeability is an important characteristic of multiphase flow in porous media. Its assessment is an urgent issue when the pore structure changes due to rock dissolution. This article examines the effect of carbonate rock dissolution on two-phase flow based on images obtained by X-ray microcomputed tomography with a spatial resolution of ~18 µm. The characteristics of the two-phase flow were calculated through pore network modeling. The studies were conducted on 20 sub-volumes, which were extracted from cylindrical samples A and B with permeabilities of 0.72 and 0.29 D. HCl solutions (12% and 18%) were injected into samples A and B at a rate of 8 and 2 mL/min, respectively. Due to rock dissolution, the porosity and absolute permeability of the sub-volumes increased by 1.1–33% and 44–368%, respectively. Due to dissolution, the residual oil and water saturations decreased by 20–46% and 25–60%, respectively. These results showed that an increase in absolute permeability led to a significant reduction in residual oil and water saturations. These results also demonstrated that rock dissolution resulted in a change in the spatial heterogeneity of the relative phase permeabilities. The spatial heterogeneity increased in sample A after rock dissolution, while in sample B, it decreased.

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Section: Introductionmentioning

confidence: 99%

Effect of Rock Dissolution on Two-Phase Relative Permeabilities: Pore-Scale Simulations Based on Experimental Data

Bolysbek,

Kuljabekov,

Uzbekaliyev

et al. 2023

Applied Sciences

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“…is of great significance for understanding the fluid flow patterns of shale reservoirs. The commonly used methods for characterizing the complex pore-throat structure of porous media are digital cores [5][6][7][8][9][10] and pore network models [11][12][13][14][15][16][17]. Direct flow simulation methods based on digital cores (such as the lattice Boltzmann method [18][19][20][21], computational fluid dynamics method [22,23], and Monte Carlo simulation [24,25]) take a long time to calculate, require a large amount of memory, and are powerless for large-scale flow simulation and parameter sensitivity analysis.…”

Section: Introductionmentioning

confidence: 99%

Characterization of Flow Parameters in Shale Nano-Porous Media Using Pore Network Model: A Field Example from Shale Oil Reservoir in Songliao Basin, China

et al. 2023

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The pore-throat radius of the shale oil reservoir is extremely small, and it is difficult to accurately obtain the absolute permeability and oil–water two-phase relative permeability of the actual oil reservoir through conventional core experiments. However, these parameters are very important for reservoir numerical simulation. In this paper, a method for characterizing flow parameters based on a pore network model that considers differential pressure flow and diffusion flow is proposed. Firstly, a digital core was reconstructed using focused ion beam scanning electron microscopy (FIB-SEM) from the Gulong shale reservoir in the Songliao Basin, China, and a pore network model was extracted. Secondly, quasi-static single-phase flow and two-phase flow equations considering diffusion were established in the pore network model. Finally, pore-throat parameters, absolute permeability, and oil–water two-phase permeability curves were calculated, respectively. The results show that the pore-throat distribution of the Gulong shale reservoir is mainly concentrated in the nanometer scale; the mean pore radius is 87 nm, the mean throat radius is 41 nm, and the mean coordination number is 3.97. The calculated permeability considering diffusion is 0.000124 mD, which is approximately twice the permeability calculated without considering diffusion. The irreducible water saturation of the Gulong shale reservoir is approximately 0.4, and the residual oil saturation is approximately 0.35. The method proposed in this paper can provide an important approach for characterizing the flow parameters of similar shale oil reservoirs.

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“…is of great significance for understanding the fluid flow patterns of shale reservoirs. The commonly used methods for characterizing the complex pore-throst structure of porous media are digital cores [5][6][7][8][9][10] and pore network models [11][12][13][14][15][16][17]. Direct flow simulation methods based on digital cores (such as lattice Boltzmann method [18][19][20][21], computational fluid dynamics method [22,23] and Monte Carlo simulation [24,25]) take a long time to calculate, require a large amount of memory, and are powerless for largescale flow simulation and parameter sensitivity analysis.…”

Section: Introductionmentioning

confidence: 99%

Characterization of Flow Parameters in Shale Nano-Porous Media Using Pore Network Model: A Field Example from Shale Oil Reservoir in Songliao Basin, China

Wang¹,

Jia²,

Cheng³

et al. 2023

Preprint

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The pore-throat radius of shale oil reservoir is extremely small, and it is difficult to accurately obtain the absolute permeability and oil-water two-phase relative permeability of actual oil reservoir through conventional core experiments. However, these parameters are very important for reservoir numerical simulation. In this paper, a method for characterizing flow parameters based on pore network model that considers differential pressure flow and diffusion flow is proposed. Firstly, a digital core was reconstructed using focused ion beam scanning electron microscopy (FIB-SEM) from the Gulong shale reservoir in the Songliao Basin, China, and a pore network model was extracted. Secondly, quasi-static single-phase flow and two-phase flow equations considering diffusion were established in the pore network model. Finally, pore throat parameters, absolute permeability, and oil-water two-phase permeability curves were calculated, respectively. The results show that the pore throat distribution of Gulong shale reservoir is mainly concentrated in the nanometer scale, the mean pore radius is 87 nm, the mean throat radius is 41 nm, and the mean coordination number is 3.97; The calculated permeability considering diffusion is 0.000124mD, which is approximately twice the permeability calculated without considering diffusion; The irreducible water saturation of the Gulong shale reservoir is approximately 0.26, and the residual oil saturation is approximately 0.73. The method proposed in this paper can provide an important approach for characterizing the flow parameters of similar shale oil reservoirs.

show abstract

A pore network modelling approach to investigate the interplay between local and Darcy viscosities during the flow of shear-thinning fluids in porous media

Cited by 11 publications

References 55 publications

Effect of Rock Dissolution on Two-Phase Relative Permeabilities: Pore-Scale Simulations Based on Experimental Data

Effect of Rock Dissolution on Two-Phase Relative Permeabilities: Pore-Scale Simulations Based on Experimental Data

Characterization of Flow Parameters in Shale Nano-Porous Media Using Pore Network Model: A Field Example from Shale Oil Reservoir in Songliao Basin, China

Characterization of Flow Parameters in Shale Nano-Porous Media Using Pore Network Model: A Field Example from Shale Oil Reservoir in Songliao Basin, China

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