Phase diagram of quasi-static immiscible displacement in disordered porous media

Hu, Ran; Lan, Tian; Guanju, Wei; Chen, Yi‐Feng

doi:10.1017/jfm.2019.504

Cited by 84 publications

(84 citation statements)

References 63 publications

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“…To qualitatively identify the invasion patterns, we first employ the criterion that the two metrics ( S br and D f ) of CZ from CF to VF are both below their respective thresholds (Chen et al, 2017; Hu et al, 2019; Lenormand et al, 1988; Wang et al, 2013). Here, S br and D f are, respectively, the saturation of the invading fluid and the fractal dimension of the region occupied by the invading fluid at the time of breakthrough.…”

Section: Resultsmentioning

confidence: 99%

“…Here, S br and D f are, respectively, the saturation of the invading fluid and the fractal dimension of the region occupied by the invading fluid at the time of breakthrough. We calculate D f by the box‐counting method (Hu, Lan, et al, 2019), and D f increases with S br (Yu & Li, 2004) . From Figure 1d, we observe that S br and D f in such a CZ are significantly lower than the values in CF and VF.…”

Section: Resultsmentioning

confidence: 99%

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Transitions of Fluid Invasion Patterns in Porous Media

Lan

Yang

et al. 2020

Geophysical Research Letters

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Fluid invasion into porous media to displace a more viscous fluid exhibits various displacement patterns. For such unfavorable displacements, previous works overlooked the dynamic effect of viscous force on pattern transitions at low flow rates. Consequently, the crossover from compact displacement to capillary fingering under various wetting conditions remains unclear. Here, we establish a theoretical model to capture pattern transitions affected by wettability and flow rate. We rigorously quantify the dynamic effect of viscous force and find that critical contact angles for the crossover from compact displacement to capillary fingering decrease with capillary number. Our model also well describes transitions from capillary fingering to the crossover to viscous fingering. The predicted phase diagram exhibits good agreement with our pore-scale simulations and microfluidic experiments and is highly consistent with existing experiments. This work extends the classic phase diagram under unfavorable conditions and is of practical significance in subsurface applications. Plain Language Summary Fluid invasion into porous media saturated with another more viscous, immiscible fluid exhibits various displacement patterns. The patterns are controlled by the competition between capillary and viscous forces and significantly affect oil recovery and CO 2 trapping efficiency. Although invasion patterns have been studied intensively, the dynamic effect of viscous force on pattern transitions is neglected. The crossovers from compact displacement to capillary fingering are not well understood. To explore pattern transitions affected by wettability and flow rate, we perform theoretical analysis of flow behavior at the pore scale, and then establish a model to describe pattern transitions as functions of contact angle and capillary number. We rigorously consider the dynamic effect of viscous force and find that the critical contact angles for the crossover from compact displacement to capillary fingering decrease with capillary number. The model also well describes the crossover from capillary to viscous fingering. We evaluate the phase diagram using pore-scale simulations, and microfluidic experiments performed in this and previous studies, justifying that the diagram can well capture the transitions under various wetting and flow-rate conditions. This work extends the classic phase diagram and is also of practical significance in predicting displacement patterns in subsurface applications.

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Section: Resultsmentioning

confidence: 99%

Section: Resultsmentioning

confidence: 99%

Transitions of Fluid Invasion Patterns in Porous Media

Lan

Yang

et al. 2020

Geophysical Research Letters

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“…Many studies have focused on the impact of the disorder on fluid displacement, showing that increasing disorder destabilizes the displacement front (J. D. Chen & Wilkinson, 1985; King, 1987; Liu et al., 2015; Toussaint et al. 2005; Z. Wang et al., 2019) and induces the transitions of displacement patterns (Holtzman & Juanes, 2010; Hu et al., 2019). For quasistatic displacement conditions, since multiphase flow is purely controlled by the capillarity, the effect of disorder on viscous force can be neglected.…”

Section: Introductionmentioning

confidence: 99%

“…This work extends the classic phase diagram to consider the role of disorder and improves our understanding of the role of disorder from the perspective of energy dissipation. Figure 1a shows the microfluidic-visualization system, which is an improvement on our previous visualization system (Hu et al, 2019). It consists of two syringe pumps (PhD Ultra 70-3007, Harvard Apparatus, labeled as syringe pump A and syringe pump B), a microfluidic mounted on the platform, two microfluidic pressure sensors (uPS0250-T116, LabSmith), and an imaging system.…”

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confidence: 99%

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

Lan

et al. 2021

Water Resources Research

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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

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“…They investigated the impact of λ on two-phase displacements by experiments. In the study of Hu et al [10], the competing effect of disorder and wettability on the fluid displacements in porous media was investigated through microfluidic experiments and pore-scale simulations.…”

Section: Introductionmentioning

confidence: 99%

Fast Prediction of Immiscible Two-Phase Displacements in Heterogeneous Porous Media with Convolutional Neural Network

sci¹

2021

AAMM

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A convolutional neural network is developed for rapidly predicting multiphase flow in heterogeneous porous media. Some direct numerical methods can acquire accurate results of multiphase flow in porous media. However, once the geometry of the porous media changes, it takes much computational time to perform a new simulation. Here, a deep neural network model in the field of semantic segmentation is developed. It takes the two-dimensional microstructure of heterogeneous porous media as inputs and is able to predict corresponding multiphase flow fields (pressure and saturation fields). Compared to the direct lattice Boltzmann simulations, the inference time on new geometry of porous media can be reduced by several orders of magnitude. Our results show that the machine learning method is a good prediction tool in a wide range of porosity and heterogeneity. Besides, to better understand the inherent process, a visible explanation is presented on what our neural networks have learned.

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Phase diagram of quasi-static immiscible displacement in disordered porous media

Cited by 84 publications

References 63 publications

Transitions of Fluid Invasion Patterns in Porous Media

Transitions of Fluid Invasion Patterns in Porous Media

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

Fast Prediction of Immiscible Two-Phase Displacements in Heterogeneous Porous Media with Convolutional Neural Network

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