Modern system of multiphase flow in porous media and its development trend

Ye, Jun; Sun, Hai; Li, Aifen; Yang, Yongfei; Huang, Zhaoqin; Wang, Yueying; Zhang, Lei; Kou, Jianlong; Xie, Heping; Zhao, Jianlin; Zhang, Qingfu; Ren, Xiaoxia; Han, Wencheng; Liu, Piyang; Zhu, Guangpu; Song, Wenhui; Sui, Hongguang; An, Senyou; Wang, Zhen; Liu, Wenzheng; Zhang, Xu; Li, Zheng

doi:10.1360/n972017-00161

Cited by 26 publications

(22 citation statements)

References 22 publications

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“…In recent years, the exploration and development of unconventional reservoirs, especially the shale gas reservoirs, are drawing more and more attention around the world (Yao et al, ; Yao et al, ). The pores in shale matrix are quite small, usually in nanoscale (Yang et al, ; Yang et al, ; Zeng et al, ).…”

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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“…As a supplement, the pore‐scale numerical simulation methods can be used to investigate the flow dynamics in porous media, although they are usually conceptual models of reality. Due to the high computational efficiency, the pore‐network model has been widely used to simulate multiphase flow in simplified porous media (Blunt, ; Yao et al, ). With certain treatment, the pore‐network model can also deal with multiphase flow in NUWPM (Valvatne & Blunt, ; Zhao 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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124

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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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“…Assuming that the study area node number is N p , the node pressure of matrix system and natural fracture system can be written by P m = [P m,1 , P m,2 ,..., P m,Np ] T and P n = [P n,1 , P n,2 ,..., P n,Np ] T . The equivalent integral transformation for control Equations (10), (12), and 14is carried out by using the equilibrium condition and variation principle, and the characteristic matrix equation of the system element can be obtained. The element characteristic matrix of the network fracture system can be expressed [38] as…”

Section: Finite Element Solutionmentioning

confidence: 99%

“…It has been commonly recognized that tight oil reservoirs have threshold pressure gradient and medium deformation characteristics because of their great lithologic compaction, fine pore-throat, and high flow resistance [1][2][3][4][5][6][7]. In recent years, stimulated reservoir volume (SRV) fracturing has become the most efficient technology in tight reservoir formation treatment [8][9][10][11][12][13][14][15]. To enhance well production as much as possible, it is necessary to create complex fracture networks with a multiporosity medium by connecting hydraulic fractures with natural fractures away from the well bore, and then increasing the contact area with formations and reservoir stimulated volume [16][17][18][19][20][21][22][23].…”

Section: Introductionmentioning

confidence: 99%

Multiporosity and Multiscale Flow Characteristics of a Stimulated Reservoir Volume (SRV)-Fractured Horizontal Well in a Tight Oil Reservoir

Ren

Wang

et al. 2018

Energies

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There are multiporosity media in tight oil reservoirs after stimulated reservoir volume (SRV) fracturing. Moreover, multiscale flowing states exist throughout the development process. The fluid flowing characteristic is different from that of conventional reservoirs. In terms of those attributes of tight oil reservoirs, considering the flowing feature of the dual-porosity property and the fracture network system based on the discrete-fracture model (DFM), a mathematical flow model of an SRV-fractured horizontal well with multiporosity and multipermeability media was established. The numerical solution was solved by the finite element method and verified by a comparison with the analytical solution and field data. The differences of flow regimes between triple-porosity, dual-permeability (TPDP) and triple-porosity, triple-permeability (TPTP) models were identified. Moreover, the productivity contribution degree of multimedium was analyzed. The results showed that for the multiporosity flowing states, the well bottomhole pressure drop became slower, the linear flow no longer arose, and the pressure wave arrived quickly at the closed reservoir boundary. The contribution ratio of the matrix system, natural fracture system, and network fracture system during SRV-fractured horizontal well production were 7.85%, 43.67%, and 48.48%, respectively in the first year, 14.60%, 49.23%, and 36.17%, respectively in the fifth year, and 20.49%, 46.79%, and 32.72%, respectively in the 10th year. This study provides a theoretical contribution to a better understanding of multiscale flow mechanisms in unconventional reservoirs.

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Modern system of multiphase flow in porous media and its development trend

Cited by 26 publications

References 22 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

Multiporosity and Multiscale Flow Characteristics of a Stimulated Reservoir Volume (SRV)-Fractured Horizontal Well in a Tight Oil Reservoir

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