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Fingering instabilities and rock fractures strongly influence fluid displacement in subsurface reservoirs, such as during groundwater remediation and enhanced oil recovery. Yet, their coupled behaviour—especially in three-dimensional (3D) flows—remains poorly understood. Prior studies show that the channelling of the less viscous fluid limits fluid mixing. Here, we demonstrate that tilted, high-permeability fractures can overcome this limitation. By examining the topology of viscous fingers in longitudinal and transverse sections, we show how fracture orientation and viscosity contrast jointly govern tip-splitting, channelling and overall mixing. Our 3D simulations reveal that when a fracture is aligned with the flow direction, fingers converge more effectively into it. Enhanced mixing within the conductive fracture delays interfacial stretching, suppressing channel formation and generating a well-mixed plume downstream. We introduce a new method for characterizing channelling based on the probability density function (PDF) of the fluid–fluid interface length. Non-stationarity of this PDF emerges as a clear statistical marker of channelling. We extend the PDF framework to quantify how fracture orientation alters the concentration PDF shape and modifies channelling. These results provide insights into fracture–fingering interactions, with broad implications for improving fluid mixing in microfluidic systems and managing flow in fractured rocks.
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Scalar transport during miscible viscous fingering experiments in consolidated porous media
Miscible viscous fingering, driven by the viscosity contrast between displacing and displaced fluids, significantly impacts subsurface processes in energy and environmental applications. Prior experimental studies that relied on synthetic porous media, such as sand packs or Hele–Shaw cells, do not fully represent the impact of fingering on pressure and concentration distribution in three-dimensional geological media. In this study, we perform experiments of scalar transport during viscous fingering in consolidated Berea Sandstone cores to capture fingering dynamics. Pressure profiles are monitored using high-resolution transducers along the core length. Scalar concentrations are measured using inductively coupled plasma optical emission spectroscopy, enabling ultra-sensitive detection of fingering-induced effects in the scalar breakthrough curve. Impacts of viscosity contrast and injection flow rate on the pressure drop profile through the domain and the scalar breakthrough profile at the outlet are analyzed. Channeling of the less viscous fluid at high viscosity contrasts is identified as the primary reason for deviations between classical models and the experimental results. A numerical model calibrated with experimental data of breakthrough and pressure profiles reproduces in situ finger dynamics, enabling further investigation of mixing and spreading processes and the synthesis of an effective transverse diffusivity in terms of the transverse variance and dissipation rate of the scalar. We propose a novel workflow utilizing temporal, longitudinal, and transverse spatial moments of the concentration distribution, previously unexplored in viscous fingering studies, to systematically quantify stochastic dispersive characteristics. Ultimately, this work improves predictive modeling capabilities essential for efficient management of subsurface resources.
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- PAR ID:
- 10667367
- Publisher / Repository:
- AIP Publishing
- Date Published:
- Journal Name:
- Physics of Fluids
- Volume:
- 37
- Issue:
- 11
- ISSN:
- 1070-6631
- Format(s):
- Medium: X
- Sponsoring Org:
- National Science Foundation
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null (Ed.)Abstract We conduct pore-scale simulations of two-phase flow using the 2D Rothman–Keller colour gradient lattice Boltzmann method to study the effect of wettability on saturation at breakthrough (sweep) when the injected fluid first passes through the right boundary of the model. We performed a suite of 189 simulations in which a “red” fluid is injected at the left side of a 2D porous model that is initially saturated with a “blue” fluid spanning viscosity ratios $$M = \nu _\mathrm{r}/\nu _\mathrm{b} \in [0.001,100]$$ M = ν r / ν b ∈ [ 0.001 , 100 ] and wetting angles $$\theta _\mathrm{w} \in [ 0^\circ ,180^\circ ]$$ θ w ∈ [ 0 ∘ , 180 ∘ ] . As expected, at low-viscosity ratios $$M=\nu _\mathrm{r}/\nu _\mathrm{b} \ll 1$$ M = ν r / ν b ≪ 1 we observe viscous fingering in which narrow tendrils of the red fluid span the model, and for high-viscosity ratios $$M \gg 1$$ M ≫ 1 , we observe stable displacement. The viscous finger morphology is affected by the wetting angle with a tendency for more rounded fingers when the injected fluid is wetting. However, rather than the expected result of increased saturation with increasing wettability, we observe a complex saturation landscape at breakthrough as a function of viscosity ratio and wetting angle that contains hills and valleys with specific wetting angles at given viscosity ratios that maximize sweep. This unexpected result that sweep does not necessarily increase with wettability has major implications to enhanced oil recovery and suggests that the dynamics of multiphase flow in porous media has a complex relationship with the geometry of the medium and the hydrodynamical parameters.more » « less
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- Free Publicly Accessible Full Text
-
Accepted Manuscript
- Journal Article:
- https://doi.org/10.1063/5.0285498
