Wettability Effects on Primary Drainage Mechanisms and NAPL Distribution: A Pore‐Scale Study

Molnar, Ian L.; Gerhard, Jason I.; Willson, Clinton S.; O'Carroll, D. M.

doi:10.1029/2019wr025381

Cited by 12 publications

(6 citation statements)

References 124 publications

(247 reference statements)

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Multiphase flow through porous media has a crucial importance in applications as diverse as groundwater resources [1][2][3], geothermal fields [4], chemical transport [5][6][7], gas diffusion in fuel cells [8], oil recovery [9], environmental remediation [10], and CO 2 sequestration [11]. The most important macroscopic parameters that describe multiphase flow through porous media are capillary pressure (P c ) and relative permeability (k r ) [9,12].…”

Section: Introductionmentioning

confidence: 99%

Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks

et al. 2020

View full text Add to dashboard Cite

A pore-network model is an upscaled representation of the pore space and fluid displacement, which is used to simulate two-phase flow through porous media. We use the results of pore-scale imaging experiments to calibrate and validate our simulations, and specifically to find the pore-scale distribution of wettability. We employ energy balance to estimate an average, thermodynamic, contact angle in the model, which is used as the initial estimate of contact angle. We then adjust the contact angle of each pore to match the observed fluid configurations in the experiment as a nonlinear inverse problem. The proposed algorithm is implemented on two sets of steady state micro-computed-tomography experiments for water-wet and mixed-wet Bentheimer sandstone. As a result of the optimization, the pore-by-pore error between the model and experiment is decreased to less than that observed between repeat experiments on the same rock sample. After calibration and matching, the model predictions for capillary pressure and relative permeability are in good agreement with the experiments. The proposed algorithm leads to a distribution of contact angle around the thermodynamic contact angle. We show that the contact angle is spatially correlated over around 4 pore lengths, while larger pores tend to be more oil-wet. Using randomly assigned distributions of contact angle in the model results in poor predictions of relative permeability and capillary pressure, particularly for the mixed-wet case.

show abstract

Section: Introductionmentioning

confidence: 99%

Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks

et al. 2020

View full text Add to dashboard Cite

show abstract

“…

Multiphase flow in porous media is related to various natural and industrial processes, such as geological CO 2 sequestration (Middleton et al, 2012;Pentland et al, 2011), enhanced oil/gas recovery (Lake, 1989;Orr & Taber, 1984), and groundwater contamination by D(L)NAPL (Dawson & Roberts, 1997;Molnar et al, 2020). When a less viscous fluid invades into the porous media to displace another more viscous one, it always causes interfacial instability and generates different displacement patterns.

…”

mentioning

confidence: 99%

Role of Pore‐Scale Disorder in Fluid Displacement: Experiments and Theoretical Model

Lan

et al. 2021

Water Resources Research

View full text Add to dashboard Cite

Multiphase flow in porous media is related to various natural and industrial processes, such as geological CO 2 sequestration (Middleton et al., 2012; Pentland et al., 2011), enhanced oil/gas recovery (Lake, 1989; Orr & Taber, 1984), and groundwater contamination by D(L)NAPL (Dawson & Roberts, 1997; Molnar et al., 2020). When a less viscous fluid invades into the porous media to displace another more viscous one, it always causes interfacial instability and generates different displacement patterns. In geological CO 2 sequestration, the stages of CO 2 injection and postinjection give rise to complex flow behaviors in geological media and result in fingering flow that significantly increases the efficiency of storage by improving capillary/residual trapping (Bachu, 2015; Y. Wang et al., 2012; Yamabe et al., 2014). In enhanced oil recovery, due to the unstable water-oil displacement interface, the sweep efficiency of water-flooding is greatly reduced and more than 80% native oil is left in reservoirs (Orr & Taber, 1984; Veld & Phillips, 2010). Understanding the fundamental mechanism and controlling displacement patterns of multiphase flow in porous media is therefore, critical for optimizing subsurface resources management. Fluid-fluid interfacial instability is a central issue for immiscible multiphase flow in permeable media. Numerous experimental, numerical and theoretical efforts have been devoted in the past semi-century (Arm

show abstract

“…Multiphase flow in porous media is of great importance for many scientific and industrial fields, including enhanced oil recovery [1,2], geologic carbon sequestration [3] and groundwater flow in soil [4], etc. Wettability plays an important role in multiphase flow in porous media [5,6] and is the main factor in the control of the fluid location and spatial distribution in porous media [7].…”

Section: Introductionmentioning

confidence: 99%

Characterization of Two-Phase Flow from Pore-Scale Imaging Using Fractal Geometry under Water-Wet and Mixed-Wet Conditions

Zou

Xie

et al. 2022

Energies

View full text Add to dashboard Cite

High resolution micro-computed tomography images for multiphase flow provide us an effective tool to understand the mechanism of fluid flow in porous media, which is not only fundamental to the understanding of macroscopic measurements but also for providing benchmark datasets to validate pore-scale modeling. In this study, we start from two datasets of pore scale imaging of two-phase flow obtained experimentally under in situ imaging conditions at different water fractional flows under water-wet and mixed-wet conditions. Then, fractal dimension, lacunarity and succolarity are used to quantify the complexity, clustering and flow capacity of water and oil phases. The results show that with the wettability of rock surface altered from water-wet to mixed-wet, the fractal dimension for the water phase increases while for the oil phase, it decreases obviously at low water saturation. Lacunarity largely depends on the degree of wettability alteration. The more uniform wetting surfaces are distributed, the more homogeneous the fluid configuration is, which indicates smaller values for lacunarity. Moreover, succolarity is shown to well characterize the wettability effect on flow capacity. The succolarity of the oil phase in the water-wet case is larger than that in the mixed-wet case while for the water phase, the succolarity value in the water-wet is small compared with that in the mixed-wet, which show a similar trend with relative permeability curves for water-wet and mixed-wet. Our study provides a perspective into the influence that phase geometry has on relative permeability under controlled wettability and the resulting phase fractal changes under different saturations that occur during multiphase flow, which allows a means to understand phase geometric changes that occur during fluid flow.

show abstract

Wettability Effects on Primary Drainage Mechanisms and NAPL Distribution: A Pore‐Scale Study

Cited by 12 publications

References 124 publications

Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks

Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks

Role of Pore‐Scale Disorder in Fluid Displacement: Experiments and Theoretical Model

Characterization of Two-Phase Flow from Pore-Scale Imaging Using Fractal Geometry under Water-Wet and Mixed-Wet Conditions

Contact Info

Product

Resources

About