Pore-scale study of counter-current imbibition in strongly water-wet fractured porous media using lattice Boltzmann method

Abstract

Oil recovery from naturally fractured reservoirs with low permeability rock remains a challenge. To provide a better understanding of spontaneous imbibition, a key oil recovery mechanism in the fractured reservoir rocks, a pore-scale computational study of the water imbibition into an artificially generated dual-permeability porous matrix with a fracture attached on top is conducted using a recently improved lattice Boltzmann color-gradient model. Several factors affecting the dynamic counter-current imbibition processes and the resulting oil recovery have been analyzed, including the water injection velocity, the geometry configuration of the dual permeability zones, interfacial tension, viscosity ratio of water to oil phases, and fracture spacing if there are multiple fractures. Depending on the water injection velocity and interfacial tension, three different imbibition regimes have been identified: the squeezing regime, the jetting regime and the dripping regime, each with a distinctively different expelled oil morphology in the fracture. The geometry configuration of the high and low permeability zones affects the amount of oil that can be recovered by the counter-current imbibition in a fracture-matrix system through transition of the different regimes. In the squeezing regime, which occurs at low water injection velocity, the build-up squeezing pressure upstream in the fracture enables more water to imbibe into the permeability zone closer to the fracture inlet thus increasing the oil recovery factor. A larger interfacial tension or a lower water-to-oil viscosity ratio is favorable for enhancing oil recovery and new insights into the effect of viscosity ratio are provided. Introducing an extra parallel fracture can effectively increase the oil recovery factor and there is an optimal fracture spacing between the two adjacent horizontal fractures to maximize the oil recovery. These findings can aid the optimal design of water-injecting oil extraction in fractured rocks in reservoirs like oil shale.

Pore‐Scale Modeling of Spontaneous Imbibition in Porous Media Using the Lattice Boltzmann Method

“…In order to be computationally admissible and thus allow for parametric studies, we, motivated by Horgue et al (2013) and Sun et al (2016), develop a quasi-3D color-gradient LBM model that is able to accurately simulate immiscible two-phase flows through a Hele-Shaw cell or micromodel. The quasi-3D model can be regarded as a variant of our previous 2D model (Xu et al, 2017), which has shown promise in simulating multiphase flows through complex porous media (Gu et al, 2019;Xu & Liu, 2018), and it is described as follows.…”

“…For the details of the wetting boundary condition, interested readers are referred to Xu et al (2017). Recent simulations showed that this wetting boundary condition is able to precisely control the contact angle for both static and dynamic problems with arbitrarily complex geometries (Akai et al, 2018;Gu et al, 2019;Xu & Liu, 2018), which is essential for accurate simulation of two-phase displacement in porous media.…”

Methods for Petrological and Petrophysical Characterization of Gas Shales

“…The LBM is a mesoscopic method based on the discretization of the Boltzmann kinetic equation. The key to this method is to treat the fluid as composed of particles with only mass but no volume and to simulate fluid flow behaviors in rocks by solving distributions of particles in time and space. ,,, With the advantages of clear physical image results, easy treatment of boundary conditions, and fully parallel algorithms, it is suitable to solve challenges that involve complicated boundary conditions and multiphase interfaces in shale imbibition. ,− For example, Zheng et al adopted modified LBM to simulate spontaneous imbibition behavior in a complicated 3D porous shale structure with intergranular pores, organic pores, and microfractures included . In comparison to the MD approach, LBM is more suitable for flow simulation in pores covering multi-scales.…”

Numerical Simulation of Pore-Scale Fluid Mobilization during Immiscible Displacement

“…However, it cannot handle complex geometries properly. Vast literature exists on the application of the Lattice Boltzmann method (LBM) to model two-phase flow in complex geometries. − The direct numerical simulations (DNS) method is a reliable approach to handle complex pore geometries by solving the Navier–Stokes equations using finite difference, finite element, and finite volume methods . The most popular interface-capturing methods include the volume of fluid (VOF), level-set, and phase-field methods .…”