Pore-scale simulation of shale gas production considering the adsorption effect

Zhao, Jianlin; Ye, Jun; Zhang, Lei; Sui, Hongguang; Zhang, Min

doi:10.1016/j.ijheatmasstransfer.2016.08.026

Cited by 73 publications

(48 citation statements)

References 41 publications

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“…The Kn ‐related effective viscosity and slip boundary condition were introduced to account for the confinement effect (Guo et al, ; Q. Li et al, ). Later, by modifying the slip boundary condition and introducing the regularization procedure, it was also used to simulate gas flow in nanoporous media (Landry et al, ; Zhao et al, ; Zhao et al, ; Zhao et al, ). In this paper, the LB model is used to simulate gas flow in different nanoscale pore geometries to analyze the viscous dissipation and verify the accuracy of different apparent permeability calculation models.…”

Section: Introductionmentioning

confidence: 99%

Viscous Dissipation and Apparent Permeability of Gas Flow in Nanoporous Media

Zhao

Kang

Youping³

et al. 2020

JGR Solid Earth

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The nanopore confinement effect can increase the mobility for gas flow in shale rocks, and the apparent permeability is usually adopted to account for this effect. However, most of the apparent permeability calculation models are derived based on straight channels (capillaries) and neglect the influence of end effect. The end effect is caused by the bending of streamlines which yields more viscous dissipation and additional flow resistance for gas flow in nanoporous media. In this paper, for the first time the viscous dissipation for gas flow in nanoporous media is analyzed. In addition, an improved apparent permeability calculation model is proposed based on the Beskok‐Karniadakis (B‐K) model by introducing the influence of end effect, which is characterized by the ratio of the length to the width of a short channel (L/H). The accuracy of this model is validated by lattice Boltzmann simulations of gas flow in three different geometries: an infinite‐length straight channel, a finite‐length straight channel, and nanoporous media. For the infinite‐length straight channel, there is no end effect therefore both the B‐K model and the improved model can well predict the apparent permeability. However, for the finite‐length straight channel and nanoporous media, the original B‐K model overestimates the gas apparent permeability as it neglects the influence of end effect, while the improved model can still well predict the gas apparent permeability. In summary, the improved apparent permeability calculation model is more reasonable in predicting gas mobility in nanoporous media.

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Section: Introductionmentioning

confidence: 99%

Viscous Dissipation and Apparent Permeability of Gas Flow in Nanoporous Media

Zhao

Kang

Youping³

et al. 2020

JGR Solid Earth

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“…To simulate fluid flow in real pore structures, different pore‐scale simulation methods can be used, including the lattice Boltzmann method (LBM), traditional computational fluid dynamic (CFD) method based on Navier‐Stokes (N‐S) equations (Prodanović & Bryant, ; Raeini et al, ), dissipative particle dynamics (DPD) method (Groot & Warren, ), and smoothed particle hydrodynamics (SPH) method (Tartakovsky & Meakin, ). Because of its compelling advantages such as the simplicity in coding, dealing with the complex solid boundaries and parallelizing, LBM has become a very popular CFD method in many areas, such as multiphase and multicomponent flow (Chen et al, ; Liu et al, ; Martys & Chen, ; Zhang et al, ), reactive flow (Jiang & Tsuji, ; Kang et al, ), microscale and nanoscale flow (Zhao et al, ). There are different multiphase flow LB models (Huang et al, ), including the color‐gradient model (Ba et al, ; Gunstensen et al, ; Liu et al, ), pseudo‐potential model (Shan & Chen, ; Sukop, ), free‐energy model (Swift et al, ), and mean‐field model (He et al, ).…”

Section: Introductionmentioning

confidence: 99%

The Effect of Wettability Heterogeneity on Relative Permeability of Two‐Phase Flow in Porous Media: A Lattice Boltzmann Study

Zhao

Kang

et al. 2018

Water Resources Research

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123

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Relative permeability is a critical parameter characterizing multiphase flow in porous media and it is strongly dependent on the wettability. In many situations, the porous media are nonuniformly wet. To investigate the effect of wettability heterogeneity on relative permeability of two‐phase flow in porous media, a multi‐relaxation‐time color‐gradient lattice Boltzmann model is adopted to simulate oil/water two‐phase flow in porous media with different oil‐wet solid fractions. For the water phase, when the water saturation is high, the relative permeability of water increases with the increase of oil‐wet solid fraction under a constant water saturation. However, as the water saturation decreases to an intermediate value (about 0.4–0.7), the relative permeability of water in fractionally wet porous media could be lower than that in purely water‐wet porous media, meaning additional flow resistance exists in the fractionally wet porous media. For the oil phase, similar phenomenon is observed. This phenomenon is mainly caused by the wettability‐related microscale fluid distribution. According to both our simulation results and theoretical analysis, it is found that the relative permeability of two‐phase flow in porous media is strongly related to three parameters: the fluid saturation, the specific interfacial length of fluid, and the fluid tortuosity in the flow direction. The relationship between the relative permeability and these parameters under different capillary numbers is explored in this paper.

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“…In MD simulations, the fluid behaviour is described by the motion of the individual particles interacting with each other via intermolecular potentials (Koplik and Banavar 1995). As a result, it is only suitable to simulate fluid behaviours at the nanoscale owing to the limitation of computation cost (Zhao et al 2016). LBM, as an intermediate method between continuum and atomistic simulations, is considered to have tremendous potential for simulating the fluid flow at the meso-scale, and detailed information on it has been presented in Sect.…”

Section: Lb-md Multiscale Methodsmentioning

confidence: 99%

Simulation and visualization of the displacement between CO2 and formation fluids at pore-scale levels and its application to the recovery of shale gas

Hou

Gao

et al. 2016

Int J Coal Sci Technol

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This article reports recent developments and advances in the simulation of the CO 2 -formation fluid displacement behaviour at the pore scale of subsurface porous media. Roughly, there are three effective visualization approaches to detect and observe the CO 2 -formation fluid displacement mechanism at the micro-scale, namely, magnetic resonance imaging, X-ray computed tomography and fabricated micromodels, but they are not capable of investigating the displacement process at the nano-scale. Though a lab-on-chip approach for the direct visualization of the fluid flow behaviour in nanoscale channels has been developed using an advanced epi-fluorescence microscopy method combined with a nanofluidic chip, it is still a qualitative analysis method. The lattice Boltzmann method (LBM) can simulate the CO 2 displacement processes in a two-dimensional or three-dimensional (3D) pore structure, but until now, the CO 2 displacement mechanisms had not been thoroughly investigated and the 3D pore structure of real rock had not been directly taken into account in the simulation of the CO 2 displacement process. The status of research on the applications of CO 2 displacement to enhance shale gas recovery is also analyzed in this paper. The coupling of molecular dynamics and LBM in tandem is proposed to simulate the CO 2 -shale gas displacement process based on the 3D digital model of shale obtained from focused ion beams and scanning electron microscopy.

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Pore-scale simulation of shale gas production considering the adsorption effect

Cited by 73 publications

References 41 publications

Viscous Dissipation and Apparent Permeability of Gas Flow in Nanoporous Media

Viscous Dissipation and Apparent Permeability of Gas Flow in Nanoporous Media

The Effect of Wettability Heterogeneity on Relative Permeability of Two‐Phase Flow in Porous Media: A Lattice Boltzmann Study

Simulation and visualization of the displacement between CO2 and formation fluids at pore-scale levels and its application to the recovery of shale gas

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