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

Zhao, Jianlin; Kang, Qinjun; Yao, Jun; Viswanathan, Hari S.; Pawar, Rajesh J.; Zhang, Lei; Sun, Hai

doi:10.1002/2017WR021443

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

Journal Article · Tue Feb 27 00:00:00 EST 2018 · Water Resources Research

DOI:https://doi.org/10.1002/2017WR021443· OSTI ID:1422921

Zhao, Jianlin ^[1]; Kang, Qinjun ^[2]; Yao, Jun ^[3]; Viswanathan, Hari S. ^[2]; Pawar, Rajesh J. ^[2]; Zhang, Lei ^[3]; Sun, Hai ^[3]

China University of Petroleum, Qingdao (China); Los Alamos National Lab. (LANL), Los Alamos, NM (United States)
Los Alamos National Lab. (LANL), Los Alamos, NM (United States)
China University of Petroleum, Qingdao (China)

Abstract 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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Research Organization:: Los Alamos National Laboratory (LANL), Los Alamos, NM (United States)

Sponsoring Organization:: USDOE Office of Fossil Energy (FE); USDOE Office of Science (SC), Basic Energy Sciences (BES)

Grant/Contract Number:: AC52-06NA25396; DE‐AC52‐06NA25396

OSTI ID:: 1422921

Alternate ID(s):: OSTI ID: 1422841

Report Number(s):: LA-UR-17-25407

Journal Information:: Water Resources Research, Vol. 54, Issue 2; ISSN 0043-1397

Publisher:: American Geophysical Union (AGU)Copyright Statement

Country of Publication:: United States

Language:: English

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