Pore-scale heterogeneity, flow channeling and permeability: Network simulation and comparison to experimental data

Tang, Yong; Li, M.; Liu, X.J.; Zhang, W.S.; Qi, Tao; Wei, Mingqiang

doi:10.1016/j.physa.2019.122533

Cited by 4 publications

(6 citation statements)

References 33 publications

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“…Some scholars have found that with the increase of capillary number, the oil displacement also increases. ,,,− However, these studies do not quantitatively analyze which part of the pores the multidrive oil comes from. According to the above T 2 spectra, it has been demonstrated that the capillary number has a considerable control on advantage paths in q tight oil medium.…”

Section: Discussionmentioning

confidence: 99%

“…Their simulation results verified the appearance of viscous fingering, capillary fingering, and stable displacement of the front morphology of immiscible displacement based on variations in the capillary number. After that, Wang et al 34 and Tang et al 28,37 quantified the relationship between the dominant flow path of two-phase flow and viscosity fingering, as well as the dependence of dominant flow paths on pore-scale heterogeneity and pore connectivity. To address some of the limitations of previous works, twophase immiscible displacement experiments are performed under low, intermediate, and high Ca conditions using heavy water and oil.…”

Section: Introductionmentioning

confidence: 99%

“…In terms of the pore network method, pore network models with topological structural information need to be first extracted from the micro- or nano-CT images and then the fluid transport can be simulated by coupling flow transport equations into the pore network models. ,, The pore network simulation technique is accepted as an efficient approach to describe the immiscible displacement in three-dimensional (3D) complex porous media. This technique has been widely used in the study of immiscible flow in complex reservoirs with strong heterogeneity. − From the perspective of physics, pore-scale network simulation methods can be further subdivided into two categories: (1) quasi-static pore network simulation ,, and (2) dynamic network simulation. − In general, quasi-static pore network models are used to simulate multiphase fluids in static or near-static conditions and they ignore the influence of viscous force, whereas the static-model-derived results are reasonable under low Ca conditions when fluid seepage is mainly controlled by capillary force. In terms of the dynamic network simulation technique, it is suitable to describe the dynamic process of multiphase flow along with time transients that are simultaneously affected by viscosity, gravity, and capillary force.…”

Section: Introductionmentioning

confidence: 99%

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Control of Generalized Capillary Number on Immiscible Displacement Path: NMR Online and Network Simulation of Fluid Displacement Mechanism

Zhao

et al. 2021

Energy Fuels

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Tight sandstone has a complex pore-throat structure and usually has multiple immiscible displacement paths. Capillary number may control and affect this process, but its control mechanism is still unclear. Therefore, this work aims to study the control process of generalized capillary number on the immiscible displacement process of tight sandstone. Through nuclear magnetic resonance (NMR) online experiments, real-time monitoring of changes in remaining oil in different-radius pores was performed under the control of different generalized capillary numbers. Combined with the microscopic experimental results of a scanning electron microscope and thin-section and constant-speed mercury intrusion, the pore-throat distribution law was obtained, and a pore network model based on a real core was established. The results show that under the control of low capillary numbers, the immiscible displacement path shifts to large and medium pores, while under the control of medium and high capillary numbers, the displacement path shifts to medium and small pores. Moreover, the simulation results also showed interesting phenomena that were not realized in the experiment. When the number of capillaries increases to a certain value (Ca ≈ 6.734 × 10–2 in this study area), unfavorable viscous displacement will occur in tight sandstones, that is, the displacement efficiency will decrease rapidly.

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Section: Discussionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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Control of Generalized Capillary Number on Immiscible Displacement Path: NMR Online and Network Simulation of Fluid Displacement Mechanism

Zhao

et al. 2021

Energy Fuels

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“…Once a full series of microscopic rock images is acquired, the image series undergoes a sequence of processing steps with regards to noise, segmentation and morphology, producing a data cube (digital rock) containing voxels that either represent solid or void space of the imaged rock [18]. Here, the spatial discretization method -such as meshes and grids, used by Finite-Element, Finite-Volume and Lattice Boltzmann; or nodes and edges, used by network-based methods -depends on the flow simulation algorithm to be used for performing subsequent permeability predictions [19][20][21][22][23][24].…”

Section: Introductionmentioning

confidence: 99%

High accuracy capillary network representation in digital rock reveals permeability scaling functions

Neumann

Barsi-Andreeta

Lucas-Oliveira

et al. 2021

Sci Rep

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Permeability is the key parameter for quantifying fluid flow in porous rocks. Knowledge of the spatial distribution of the connected pore space allows, in principle, to predict the permeability of a rock sample. However, limitations in feature resolution and approximations at microscopic scales have so far precluded systematic upscaling of permeability predictions. Here, we report fluid flow simulations in pore-scale network representations designed to overcome such limitations. We present a novel capillary network representation with an enhanced level of spatial detail at microscale. We find that the network-based flow simulations predict experimental permeabilities measured at lab scale in the same rock sample without the need for calibration or correction. By applying the method to a broader class of representative geological samples, with permeability values covering two orders of magnitude, we obtain scaling relationships that reveal how mesoscale permeability emerges from microscopic capillary diameter and fluid velocity distributions.

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“…Marchand et al (2020) evaluated the geometrical properties of channels concerning shear displacements of the opposing fracture surfaces. Tang et al (2019) evaluated the channeling characteristics and transport-related properties in pore-scale heterogeneous media. Javanmard et al (2022) compared different channel connectivity indicators regarding their applicability under normal stress conditions.…”

mentioning

confidence: 99%

Spatial Characterization of Channeling in Sheared Rough‐Walled Fractures in the Transition to Nonlinear Fluid Flow

Egert,

Nitschke,

Gholami Korzani

et al. 2023

Water Resources Research

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Accurate quantification of spatially resolved fluid flow within fractures is crucial for successful reservoir development, such as Enhanced Geothermal Systems. This study presents an innovative workflow designed to model and characterize preferential flow paths (channels) within rough‐walled shear fractures. A set of 30 rough‐walled self‐affine fractures, all possessing identical roughness characteristics, is stochastically generated. By solving the nonlinear Navier‐Stokes equations in 420 individual realizations, the transition from linear to nonlinear flow regimes and the two extreme flow directions perpendicular and parallel to the shearing are numerically captured. A distinguishing feature of this approach is its comprehensive statistical analysis, which encompasses both the geometric and transport properties of flow paths in the non‐simplified three‐dimensional fractured void space under typical geothermal flow conditions. In a perpendicular orientation of flow and shearing, fluid flow exhibits pronounced localization, with more than one‐third of the volumetric flow concentrated within 15% of the fracture volume. In contrast, parallel to the shearing, a complex pattern of individual tortuous channels emerges, with flow occurring in 22% of the void space. Nonlinear effects primarily manifest outside these channels, suggesting that complex flow phenomena may dominate irregular fracture structures, such as contact zones or asperities. In the parallel case, increased flow rates lead to an amplification of channeling processes resulting in less affected volume and diminished tortuosity of the main flow path, while in perpendicular orientation nonlinear effects are only of minor importance. The small‐scale flow regime of both extreme cases tends to converge with increasing flow rates.

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Pore-scale heterogeneity, flow channeling and permeability: Network simulation and comparison to experimental data

Cited by 4 publications

References 33 publications

Control of Generalized Capillary Number on Immiscible Displacement Path: NMR Online and Network Simulation of Fluid Displacement Mechanism

Control of Generalized Capillary Number on Immiscible Displacement Path: NMR Online and Network Simulation of Fluid Displacement Mechanism

High accuracy capillary network representation in digital rock reveals permeability scaling functions

Spatial Characterization of Channeling in Sheared Rough‐Walled Fractures in the Transition to Nonlinear Fluid Flow

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