CT Scan Study of Immiscible Foam Flow in Porous Media for Enhancing Oil Recovery

2013 ◽  
Vol 52 (18) ◽  
pp. 6221-6233 ◽  
Author(s):  
M. Simjoo ◽  
Y. Dong ◽  
A. Andrianov ◽  
M. Talanana ◽  
P. L. J. Zitha
Keyword(s):  
Porous Media ◽  
Ct Scan ◽  
Oil Recovery ◽  
Flow In Porous Media ◽  
Foam Flow

A CT Scan Study of Immiscible Foam Flow in Porous Media for EOR

2012 ◽  
Author(s):  
Mohammad Simjoo ◽  
Yufei Dong ◽  
Alexey Andrianov ◽  
Mohand Talanana ◽  
Pacelli L.J. Zitha
Keyword(s):  
Porous Media ◽  
Ct Scan ◽  
Flow In Porous Media ◽  
Foam Flow

Studies on Foam Flow in the Porous Media in the Last Decade: A Review

2012 ◽  
Vol 616-618 ◽  
pp. 257-262 ◽  
Author(s):  
Ming Ming Lv ◽  
Shu Zhong Wang ◽  
Ze Feng Jing ◽  
Ming Luo
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Flow In Porous Media ◽  
Balance Model ◽  
Sweep Efficiency ◽  
Foam Flow ◽  
New Findings ◽  
X Ray Computed ◽  
Flow Through

Foam has been used for several decades to decrease the mobility of drive gas or steam, thereby increasing the reservoir sweep efficiency and enhancing the oil recovery. The optimization of the operations requires a thorough understanding of the physical aspects involved in foam flow through porous media. The present paper aims mainly at reviewing experimental and modeling studies on foam flow in porous media particularly during the last decade, to stress the new achievements and highlight the areas that are less understood. X-ray computed tomography (CT) is a useful tool to study in-situ foam behaviors in porous media and new findings were obtained through this technology. The population-balance model was improved in different forms by researchers.

scholarly journals Impact of pertinent parameters on foam behavior in the entrance region of porous media: mathematical modeling

2020 ◽  
Vol 17 (6) ◽  
pp. 1669-1682 ◽  
Author(s):  
Fereshteh Samimi ◽  
Zahra Sakhaei ◽  
Masoud Riazi
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Oil Recovery ◽  
Local Equilibrium ◽  
Entrance Region ◽  
Flow In Porous Media ◽  
Laboratory Research ◽  
Fractional Flow ◽  
Gas Field ◽  
Foam Flow

AbstractFoam injection is a promising solution for control of mobility in oil and gas field exploration and development, including enhanced oil recovery, matrix-acidization treatments, contaminated-aquifer remediation and gas leakage prevention. This study presents a numerical investigation of foam behavior in a porous medium. Fractional flow method is applied to describe steady-state foam displacement in the entrance region. In this model, foam flow for the cases of excluding and including capillary pressure and for two types of gas, nitrogen (N2) and carbon dioxide (CO2) are investigated. Effects of pertinent parameters are also verified. Results indicate that the foam texture strongly governs foam flow in porous media. Required entrance region may be quite different for foam texture to accede local equilibrium, depending on the case and physical properties that are used. According to the fact that the aim of foaming of injected gas is to reduce gas mobility, results show that CO2 is a more proper injecting gas than N2. There are also some ideas presented here on improvement in foam displacement process. This study will provide an insight into future laboratory research and development of full-field foam flow in a porous medium.

scholarly journals Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Polymers ◽  
2018 ◽  
Vol 10 (11) ◽  
pp. 1225 ◽  
Author(s):  
Xiankang Xin ◽  
Gaoming Yu ◽  
Zhangxin Chen ◽  
Keliu Wu ◽  
Xiaohu Dong ◽  
...  
Keyword(s):  
Porous Media ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Flow Behavior ◽  
Polymer Flooding ◽  
Oil Reservoirs ◽  
Flow In Porous Media ◽  
Newtonian Flow ◽  
Heavy Oil Reservoirs

The flow of polymer solution and heavy oil in porous media is critical for polymer flooding in heavy oil reservoirs because it significantly determines the polymer enhanced oil recovery (EOR) and polymer flooding efficiency in heavy oil reservoirs. In this paper, physical experiments and numerical simulations were both applied to investigate the flow of partially hydrolyzed polyacrylamide (HPAM) solution and heavy oil, and their effects on polymer flooding in heavy oil reservoirs. First, physical experiments determined the rheology of the polymer solution and heavy oil and their flow in porous media. Then, a new mathematical model was proposed, and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed considering the non-Newtonian flow. The designed simulator was validated by comparing its results with those obtained from commercial software and typical polymer flooding experiments. The developed simulator was further applied to investigate the non-Newtonian flow in polymer flooding. The experimental results demonstrated that the flow behavior index of the polymer solution is 0.3655, showing a shear thinning; and heavy oil is a type of Bingham fluid that overcomes a threshold pressure gradient (TPG) to flow in porous media. Furthermore, the validation of the designed simulator was confirmed to possess high accuracy and reliability. According to its simulation results, the decreases of 1.66% and 2.49% in oil recovery are caused by the difference between 0.18 and 1 in the polymer solution flow behavior indexes of the pure polymer flooding (PPF) and typical polymer flooding (TPF), respectively. Moreover, for heavy oil, considering a TPG of 20 times greater than its original value, the oil recoveries of PPF and TPF are reduced by 0.01% and 5.77%, respectively. Furthermore, the combined effect of shear thinning and a threshold pressure gradient results in a greater decrease in oil recovery, with 1.74% and 8.35% for PPF and TPF, respectively. Thus, the non-Newtonian flow has a hugely adverse impact on the performance of polymer flooding in heavy oil reservoirs.

scholarly journals Numerical Simulation of Two-Phase Flows in Heterogeneous Porous Media

2020 ◽  
Vol 21 (2) ◽  
pp. 339
Author(s):  
I. Carneiro ◽  
M. Borges ◽  
S. Malta
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Water Injection ◽  
Heterogeneous Porous Media ◽  
Flow In Porous Media ◽  
High Porosity ◽  
Two Phase ◽  
Recovery Method ◽  
Porosity And Permeability

In this work,we present three-dimensional numerical simulations of water-oil flow in porous media in order to analyze the influence of the heterogeneities in the porosity and permeability fields and, mainly, their relationships upon the phenomenon known in the literature as viscous fingering. For this, typical scenarios of heterogeneous reservoirs submitted to water injection (secondary recovery method) are considered. The results show that the porosity heterogeneities have a markable influence in the flow behavior when the permeability is closely related with porosity, for example, by the Kozeny-Carman (KC) relation.This kind of positive relation leads to a larger oil recovery, as the areas of high permeability(higher flow velocities) are associated with areas of high porosity (higher volume of pores), causing a delay in the breakthrough time. On the other hand, when both fields (porosity and permeability) are heterogeneous but independent of each other the influence of the porosity heterogeneities is smaller and may be negligible.

Transport Modelling of Multi-Phase Fluid Flow in Porous Media for Enhanced Oil Recovery

2020 ◽  
Vol 400 ◽  
pp. 38-44
Author(s):  
Hassan Soleimani ◽  
Hassan Ali ◽  
Noorhana Yahya ◽  
Beh Hoe Guan ◽  
Maziyar Sabet ◽  
...  
Keyword(s):  
Porous Media ◽  
Fluid Flow ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Constitutive Relations ◽  
Mobility Control ◽  
Flow In Porous Media ◽  
Wettability Alteration ◽  
Adsorption Effect ◽  
Phase Fluid

This article studies the combined effect of spatial heterogeneity and capillary pressure on the saturation of two fluids during the injection of immiscible nanoparticles. Various literature review exhibited that the nanoparticles are helpful in enhancing the oil recovery by varying several mechanisms, like wettability alteration, interfacial tension, disjoining pressure and mobility control. Multiphase modelling of fluids in porous media comprise balance equation formulation, and constitutive relations for both interphase mass transfer and pressure saturation curves. A classical equation of advection-dispersion is normally used to simulate the fluid flow in porous media, but this equation is unable to simulate nanoparticles flow due to the adsorption effect which happens. Several modifications on computational fluid dynamics (CFD) have been made to increase the number of unknown variables. The simulation results indicated the successful transportation of nanoparticles in two phase fluid flow in porous medium which helps in decreasing the wettability of rocks and hence increasing the oil recovery. The saturation, permeability and capillary pressure curves show that the wettability of the rocks increases with the increasing saturation of wetting phase (brine).

scholarly journals Coupling of two-phase flow in fractured-vuggy reservoir with filling medium

Open Physics ◽  
2017 ◽  
Vol 15 (1) ◽  
pp. 12-17 ◽  
Author(s):  
Haojun Xie ◽  
Aifen Li ◽  
Zhaoqin Huang ◽  
Bo Gao ◽  
Ruigang Peng
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Two Phase Flow ◽  
Water Injection ◽  
Free Flow ◽  
Flow In Porous Media ◽  
Free Fluid ◽  
Phase Flow ◽  
Fluid Exchange ◽  
Two Phase

AbstractCaves in fractured-vuggy reservoir usually contain lots of filling medium, so the two-phase flow in formations is the coupling of free flow and porous flow, and that usually leads to low oil recovery. Considering geological interpretation results, the physical filled cave models with different filling mediums are designed. Through physical experiment, the displacement mechanism between un-filled areas and the filling medium was studied. Based on the experiment model, we built a mathematical model of laminar two-phase coupling flow considering wettability of the porous media. The free fluid region was modeled using the Navier-Stokes and Cahn-Hilliard equations, and the two-phase flow in porous media used Darcy's theory. Extended BJS conditions were also applied at the coupling interface. The numerical simulation matched the experiment very well, so this numerical model can be used for two-phase flow in fracture-vuggy reservoir. In the simulations, fluid flow between inlet and outlet is free flow, so the pressure difference was relatively low compared with capillary pressure. In the process of water injection, the capillary resistance on the surface of oil-wet filling medium may hinder the oil-water gravity differentiation, leading to no fluid exchange on coupling interface and remaining oil in the filling medium. But for the water-wet filling medium, capillary force on the surface will coordinate with gravity. So it will lead to water imbibition and fluid exchange on the interface, high oil recovery will finally be reached at last.

Modeling Polymer Enhanced Foam Flow in Porous Media Using An Improved Population-Balance Foam Model

2018 ◽  
Author(s):  
Haishan Luo ◽  
Kun Ma ◽  
Khalid Mateen ◽  
Guangwei Ren ◽  
Gilles Bourdarot ◽  
...  
Keyword(s):  
Porous Media ◽  
Population Balance ◽  
Flow In Porous Media ◽  
Foam Flow ◽  
Foam Model

Effect Of Gas Type On Foam Film Permeability And Its Implications For Foam Flow In Porous Media

2010 ◽  
Author(s):  
Rouhollah Farajzadeh ◽  
RM Muruganathan ◽  
Rumen Krastev ◽  
William Richard Rossen
Keyword(s):  
Porous Media ◽  
Flow In Porous Media ◽  
Foam Flow ◽  
Foam Film
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