Pore-resolved two-phase flow in a pseudo-3D porous medium: Measurements and volume-of-fluid simulations

被引：24

作者：

Ambekar, Aniket S. ^{[1
]}

Mattey, Padmaja ^{[2
]}

Buwa, Vivek V. ^{[1
]}

机构：

[1] Indian Inst Technol Delhi, Dept Chem Engn, New Delhi 110016, India

[2] Inst Reservoir Studies Oil & Nat Gas Corp Ltd, Ahmadabad 380005, Gujarat, India

来源：

CHEMICAL ENGINEERING SCIENCE | 2021年 / 230卷

关键词：

Porous media; High-speed imaging; Pore-resolved simulations; Volume-of-fluid method; Water-flooding; Interfacial tension; ENHANCED OIL-RECOVERY; CAPILLARY-PRESSURE; RELATIVE PERMEABILITY; MULTIPHASE FLOW; SCALE FLOW; HEAVY OIL; DYNAMICS; WETTABILITY; IMBIBITION; PREDICTION;

D O I：

10.1016/j.ces.2020.116128

中图分类号：

TQ [化学工业];

学科分类号：

0817 ;

摘要：

In the present work, high-speed imaging experiments are performed to measure the time-evolution of two-phase oil-water flow, water-saturation, oil ganglia number and size distribution in a pseudo-3D porous medium. The corresponding pore-resolved simulations are performed using the Volume-of-Fluid (VOF) method and predictions are validated using the aforementioned measurements. The experimentally-validated VOF model is used to understand the effects of water-flooding velocity and interfacial tension [i.e. Capillary number (Ca)] on the pore-scale oil recovery mechanisms. The pore resolved VOF simulations reveal that the drainage phenomenon is dominated by Haines-jump events at low Ca values. The increase in Ca values results in the decrease in the frequency of Haines-jump events and after the transitional Ca, the drainage phenomenon is no longer governed by Haines-jump events and is governed by viscous fingering. Finally, VOF simulations are used to analyze the effect of successive step changes in the interfacial tension on the oil recovery. (C) 2020 Elsevier Ltd. All rights reserved.

引用

页数：15

共 62 条

[1] Prediction of fluid topology and relative permeability in imbibition in sandstone rock by direct numerical simulation [J].

Alpak, F. O. ;

Berg, S. ;

Zacharoudiou, I .

ADVANCES IN WATER RESOURCES, 2018, 122 :49-59

[2]

[Anonymous], 2003, COMPUTATIONAL FLUID

[3]

[Anonymous], 2015, Reservoir Engineering: The Fundamentals, Simulation, and Management of Conventional and Unconventional Recoveries

[4] Single-phase and two-phase flow properties of mesaverde tight sandstone formation; random-network modeling approach [J].

Bashtani, Farzad ;

Maini, Brij ;

Kantzas, Apostolos .

ADVANCES IN WATER RESOURCES, 2016, 94 :174-184

[5] A CONTINUUM METHOD FOR MODELING SURFACE-TENSION [J].

BRACKBILL, JU ;

KOTHE, DB ;

ZEMACH, C .

JOURNAL OF COMPUTATIONAL PHYSICS, 1992, 100 (02) :335-354

[6] Imaging and image-based fluid transport modeling at the pore scale in geological materials: A practical introduction to the current state-of-the-art [J].

Bultreys, Tom ;

De Boever, Wesley ;

Cnudde, Veerle .

EARTH-SCIENCE REVIEWS, 2016, 155 :93-128

[7] Experimental study on imbibition displacement mechanisms of two-phase fluid using micro model [J].

Chang, Liang-Cheng ;

Tsai, Jui-Pin ;

Shan, Hsin-Yu ;

Chen, Hung-Hui .

ENVIRONMENTAL EARTH SCIENCES, 2009, 59 (04) :901-911

[8] Taxila LBM: a parallel, modular lattice Boltzmann framework for simulating pore-scale flow in porous media [J].

Coon, Ethan T. ;

Porter, Mark L. ;

Kang, Qinjun .

COMPUTATIONAL GEOSCIENCES, 2014, 18 (01) :17-27

[9] Viscoelastic effects on residual oil distribution in flows through pillared microchannels [J].

De, S. ;

Krishnan, P. ;

van der Schaaf, J. ;

Kuipers, J. A. M. ;

Peters, E. A. J. F. ;

Padding, J. T. .

JOURNAL OF COLLOID AND INTERFACE SCIENCE, 2018, 510 :262-271

[10] Viscous Crossflow in Layered Porous Media [J].

Debbabi, Yacine ;

Jackson, Matthew D. ;

Hampson, Gary J. ;

Fitch, Peter J. R. ;

Salinas, Pablo .

TRANSPORT IN POROUS MEDIA, 2017, 117 (02) :281-309

← 1 2 3 4 5 6 7 →