Two-phase flow of CO2-brine in a heterogeneous sandstone: Characterization of the rock and comparison of the lattice-Boltzmann, pore-network, and direct numerical simulation methods

Kohanpur, Amir H.; Rahromostaqim, Mahsa; Valocchi, Albert J.; Sahimi, Muhammad

doi:10.1016/j.advwatres.2019.103469

Cited by 36 publications

(15 citation statements)

References 53 publications

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“…Immiscible fluid-fluid displacement in porous media has been widely observed in various settings, such as CO2 sequestration [1][2][3], liquid drainage in polymer-based fuel cells [4], enhanced oil/gas recovery [5,6]. With the displacement proceeding, fingering phenomena induced by the interface instability may occur leading to a significant reduction of displacement efficiency and a ramified fluid morphology compared with a compact displacement.…”

Section: Introductionmentioning

confidence: 99%

Tuning capillary flow in porous media with hierarchical structures

Suo

Gan

2021

Physics of Fluids

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Immiscible fluid-fluid displacement in porous media is of great importance in many engineering applications, such as enhanced oil recovery, agricultural irrigation, and geologic CO2 storage. Fingering phenomena, induced by the interface instability, are commonly encountered during displacement processes and somehow detrimental since such hydrodynamic instabilities can significantly reduce displacement efficiency. In this study, we report a possible adjustment in pore geometry which aims to suppress the capillary fingering in porous media with hierarchical structures. Through pore-scale simulations and theoretical analysis, we demonstrate and quantify combined effects of wettability and hierarchical geometry on displacement patterns, showing a transition from fingering to compact mode. Our results suggest that with a higher porosity of the 2 nd -order porous structure, the displacement can keep compact across a wider range of wettability conditions. Combined with our previous work on viscous fingering in such media, we can provide a complete insight into the fluid-fluid displacement control in hierarchical porous media, across a wide range of capillary number from capillary-to viscous-dominated modes. The conclusions of this work can benefit the design of microfluidic devices, as well as tailoring porous media for better fluid displacement efficiency at the field scale.

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Section: Introductionmentioning

confidence: 99%

Tuning capillary flow in porous media with hierarchical structures

Suo

Gan

2021

Physics of Fluids

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“…This sample has a fairly high porosity and is more heterogeneous with respect to typical well-studied sandstones in the literature such as Berea and Bentheimer. Since the sample is from the reservoir that has been used in a pilot CO2 sequestration project in Illinois (Finley 2014), its CO2-brine flow properties are extensively studied recently by different numerical pore-scale models (Kohanpur et al 2020). We use subsample S2 from that study, labeled MH in Table 1 and shown in Fig.…”

Section: Validationmentioning

confidence: 99%

Pore-network stitching method: A pore-to-core upscaling approach for multiphase flow

Kohanpur¹,

Valocchi²

2020

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Pore-network modeling is a widely used predictive tool for pore-scale studies in various applications that deal with multiphase flow in heterogeneous natural rocks. Despite recent improvements to enable pore-network modeling on simplified pore geometry extracted from rock core images and and its computational efficiency compared to direct numerical simulation methods, there are still limitations to modeling a large representative pore-network for heterogeneous cores. These are due to the technical limits on sample size to discern void space during X-ray scanning and computational limits on pore-network extraction algorithms. Thus, there is a need for pore-scale modeling approaches that have the natural advantages of pore-network modeling and can overcome these limitations, thereby enabling better representation of heterogeneity of the 3D complex pore structure and enhancing the accuracy of prediction of macroscopic properties. This paper addresses these issues with a workflow that includes a novel pore-network stitching method to provide large-enough representative pore-network for a core. This workflow uses micro-CT images of heterogeneous reservoir rock cores at different resolutions to characterize the pore structure in order to select few signature parts of the core and extract their equivalent pore-network models. The space between these signature pore-networks is filled by using their statistics to generate realizations of pore-networks which are then connected together using a deterministic layered stitching method. The output of this workflow is a large pore-network that can be used in any flow and transport solver. We validate all steps of this method on different types of natural rocks based on single-phase and two-phase flow properties such as drainage relative permeability curves of carbon dioxide and brine flow. Then, we apply the stochastic workflow on two large domain problems, connecting distant pore-networks and modeling a heterogeneous core. We generate multiple realizations and compare the average results with properties from a

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“…There are several ways to simulate non-wetting fluid invasion into volumetric images of porous materials, each with their pros and cons. The volume of fluid method (Kohanpur et al, 2020;Raeini et al, 2012;Tranter et al, 2015) (VOF) monitors the surface between immiscible fluids, while applying a single set of momentum equations to both phases and tracking the volume fraction of both fluids in each cell of the domain. Because the fluids are immiscible, the interfaces between phases display capillary effects.…”

Section: Introductionmentioning

confidence: 99%