Lattice Boltzmann Simulation of Immiscible Two-Phase Displacement in Two-Dimensional Berea Sandstone

Gu, Qingqing; Liu, Haihu; Zhang, Yonghao

doi:10.3390/app8091497

Cited by 14 publications

(4 citation statements)

References 41 publications

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“…Then, the contact angle θ(ψ) is enforced through the wetting boundary condition developed by Xu et al This wetting boundary condition uses the idea of predictor–corrector to estimate ∇ρ N at three-phase contact lines, which can deal with arbitrarily complicated geometries while having high accuracy. Thus, it has been widely adopted in pore-scale two-phase simulations ,− and was extended to three-dimensional simulations . Interested readers are advised to refer to Xu et al for more details.…”

Section: Methodsmentioning

confidence: 99%

Pore-Scale Modeling of Two-Phase Flows with Soluble Surfactants in Porous Media

et al. 2021

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In this paper, a lattice Boltzmann method is developed to simulate two-phase flows with soluble surfactants in complex porous media. This method not only can recover the Langmuir adsorption isotherm when the bulk surfactant concentration is relatively low but also allows the surfactant concentration to exceed the critical micelle concentration. Thanks to its versatility, this method is used to study the influence of surfactants on steady-state fluid distributions, specific interfacial lengths (SILs), and relative permeabilities under different wetting fluid (WF) saturations (S w) and viscosity ratios (M) of WF to non-WF (NWF). Regardless of the values of S w and M, the SIL between two fluids and the SIL between a grain surface and WF are always higher in a surfactant-laden system than in a clean system, while the SIL between a grain surface and NWF is always lower in a surfactant-laden system. For M = 1, we find that the addition of surfactants dramatically increases the relative permeability (RP) of NWF but slightly decreases the RP of WF. By adjusting M at S w = 0.5, the RP of NWF is always higher in a surfactant-laden system than in a clean system, while the relative magnitude of the WF relative permeabilities in both systems depends on M: for M < 1, the RP of WF in a surfactant-laden system is higher, whereas for M ≥ 1, the RP of WF in a clean system is higher.

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Section: Methodsmentioning

confidence: 99%

Pore-Scale Modeling of Two-Phase Flows with Soluble Surfactants in Porous Media

et al. 2021

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“…Studies have shown that the interfacial tension (IFT) of the displacement phase strongly influences flooding effects [10,11]. A low IFT system refers to a system with an IFT between 10 −2 and 1 mN/m; in ultra-low IFT systems, the IFT is below 10 −2 mN/m.…”

Section: Introductionmentioning

confidence: 99%

Ultra-Low Interfacial Tension Foam System for Enhanced Oil Recovery

Liu

Luo

et al. 2019

Applied Sciences

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The liquid phase of foam systems plays a major role in improving the fluidity of oil, by reducing oil viscosity and stripping oil from rock surfaces during foam-flooding processes. Improving the oil displacement capacity of the foam’s liquid phase could lead to significant improvement in foam-flooding effects. Oil-liquid interfacial tension (IFT) is an important indicator of the oil displacement capacity of a liquid. In this study, several surfactants were used as foaming agents, and polymers were used as foam stabilizers. Foaming was induced using a Waring blender stirring method. Foam with an oil-liquid IFT of less than 10–3 mN/m was prepared after a series of adjustments to the liquid composition. This study verified the possibility of a foam system with both an ultra-low oil-liquid IFT and high foaming properties. Our results provide insight into a means of optimizing foam fluids for enhanced oil recovery.

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“…Among various multiphase LB models (see the reviews by Huang et al 25 and Liu et al 26 ), the color-gradient model has its own advantages such as high numerical accuracy, strict mass conservation for each fluid and numerical stability for a broad range of viscosity ratios 24 . Especially, it produces relatively thin interface and is able to control the interfacial diffusion and adjust the interfacial tension and viscosity independently to facilitate the numerical investigation 27 . Therefore, the color-gradient model has been extensively used for modeling immiscible two phase flow in porous media, e.g.…”

Section: Introductionmentioning

confidence: 99%

“…Therefore, the color-gradient model has been extensively used for modeling immiscible two phase flow in porous media, e.g. Tolke et al 28 , Huang et al 29 , Chen et al 30 , Gu et al 27 and Xu et al 31 .…”

Section: Introductionmentioning

confidence: 99%

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

Gu,

Zhu,

Zhang

et al. 2019

Physics of Fluids

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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.

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Lattice Boltzmann Simulation of Immiscible Two-Phase Displacement in Two-Dimensional Berea Sandstone

Cited by 14 publications

References 41 publications

Pore-Scale Modeling of Two-Phase Flows with Soluble Surfactants in Porous Media

Pore-Scale Modeling of Two-Phase Flows with Soluble Surfactants in Porous Media

Ultra-Low Interfacial Tension Foam System for Enhanced Oil Recovery

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

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