Polymer Solution Flow in Porous Media

1970 ◽  
Vol 10 (02) ◽  
pp. 111-118 ◽  
Author(s):  
A. Herbert Harvey ◽  
D.E. Menzie
Keyword(s):  
Porous Media ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Polymer Solutions ◽  
Flow In Porous Media ◽  
High Molecular Weight Polymer ◽  
Molecular Weight Polymer ◽  
Rate Dependent ◽  
Polymer Flood ◽  
Prediction Techniques

Abstract A method is described for the analysis of rate-dependent effects in the flow of polymer solutions through unconsolidated porous media. Experimental data are presented for solutions of polyacrylamide, polyethylene oxide, and polyacrylamide, polyethylene oxide, and polysaccharide. polysaccharide Introduction A major obstacle to wider use of polymer flooding seems to be the lack of a satisfactory method for predicting the performance of this oil recovery predicting the performance of this oil recovery process. Although it is frequently possible to process. Although it is frequently possible to predict that a polymer flood would recover more oil predict that a polymer flood would recover more oil from a reservoir than could be produced with a waterflood, it is difficult to make a realistic economic comparison of the two processes. Waterflood prediction techniques which consider areal sweep and reservoir stratification have been used to evaluate the effect of improved mobility ratio on oil recovery. If accurate relative permeability data are available and if stratigraphic permeability data are available and if stratigraphic variations in the reservoir are known, then these prediction techniques may lead to a rough prediction techniques may lead to a rough approximation of the performance of a polymer flood. However, such prediction techniques fail to consider that the apparent flow resistance to a polymer solution depends on flow velocity as well polymer solution depends on flow velocity as well as permeability. These rate-dependent effects may be significant in a pattern flood, since fluid velocity is not constant. They may also be significant in a heterogeneous reservoir. Under favorable conditions some rate-dependent fluids will tend to even out the flood front in a stratified reservoir and thereby increase oil recovery. This effect cannot be anticipated with conventional waterflood prediction techniques. The basis for much of the difficulty in predicting the performance of a polymer flood is a lack of understanding of the behavior of high molecular weight polymer solutions flowing through porous materials. Until we are able to predict how these solutions will flow through a simple system such as a glass bead pack, it seems unlikely that we will be able to develop a realistic mathematical model to describe the much more complex problem of flow in an oil reservoir. It is the purpose of this study to develop a method for investigating the flow of these high molecular weight polymer solutions through unconsolidated porous media and to study the rheologic properties of solutions of certain polymers which, are of interest from the standpoint of possible application to polymer flooding. EQUATIONS DESCRIBING NON-NEWTONIAN FLOW IN POROUS MEDIA In analogy to the Blake-Kozeny equation for Newtonian fluids, equations have been developed to describe the flow of certain non-Newtonian fluids through porous media. These relationships are based on the assumptions that the fluid behavior may be approximated by the "power law" (Ostwaldde Waele flow model) and that the hydraulic radius concept is applicable to the porous media. If we write the power (1) lawmr  =  m y , and let N = Reynolds number for porous mediaRe f* = friction factor for porous media W = mass velocity dp = particle diameter of porous media 0 = porosity p = fluid density, the relationships may be written (2)L 2 1-0W d 3* pd pf  = (3)NRE * 1f  =  ----- , SPEJ P. 111

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 Study on Mechanism of Viscoelastic Polymer Transient Flow in Porous Media

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-8 ◽  
Author(s):  
Huiying Zhong ◽  
Weidong Zhang ◽  
Hongjun Yin ◽  
Haoyang Liu
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Pressure Difference ◽  
Transient Flow ◽  
Polymer Solutions ◽  
Polymer Flooding ◽  
Physical Models ◽  
Flow In Porous Media ◽  
Chemical Flooding ◽  
Dynamics Simulations

Oil recovery, including conventional and viscous oil, can be improved significantly by flooding with polymer solutions. This chemical flooding method can increase oil production, and it can improve the macrodisplacement efficiency and microsweep efficiencies. In this study, we establish physical models that include the dead-end and complex models based on the pore-network pattern etched into glass, using the snappyHexMesh solver in OpenFOAM. These models capture the complexity and topology of porous media geometry. We establish a mathematical model for transient flows of viscoelastic polymers using computational fluid dynamics simulations, and we study the distributions of pressure and velocity for different elasticity scenarios and different flooding process. The results demonstrate that the pressure difference increases as the relaxation time decreases, before the flow reaches its steady state. For a steady flow, elasticity can give rise to an additional pressure difference, which increases with increasing elasticity. Thus, the characteristics of pressure difference vary before and after the flow becomes steady; this phenomenon is very important. Velocity contours become more widely spaced with elasticity increase. This suggests that elasticity of the polymer solutions contributes to the microsweep efficiency. The results of the study provide the necessary theoretical foundation for laboratory experiments and development of methods for polymer flooding and can be helpful for the design and selection of polymers for polymer flooding.

Can 25-cp Polymer Solution Efficiently Displace 1,600-cp Oil During Polymer Flooding?

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2260-2278 ◽  
Author(s):  
R. S. Seright ◽  
Dongmei Wang ◽  
Nolan Lerner ◽  
Anh Nguyen ◽  
Jason Sabid ◽  
...  
Keyword(s):  
Crude Oil ◽  
Polymer Solution ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Polymer Solutions ◽  
Water Saturation ◽  
Field Application ◽  
Polymer Flooding ◽  
Solution Viscosity ◽  
Polymer Flood

Summary This paper examines oil displacement as a function of polymer-solution viscosity during laboratory studies in support of a polymer flood in Canada's Cactus Lake Reservoir. When displacing 1,610-cp crude oil from field cores (at 27°C and 1 ft/D), oil-recovery efficiency increased with polymer-solution viscosity up to 25 cp (7.3 seconds−1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of this paper explores why this result occurred. Floods in field cores examined relative permeability for different saturation histories, including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1,000 cp. In field cores, relative permeability to water (krw) remained low, less than 0.03 for most corefloods. After extended polymer flooding to water saturations up to 0.865, krw values were less than 0.04 for six of seven corefloods. Relative permeability to oil remained reasonably high (greater than 0.05) for most of the flooding process. These observations help explain why 25-cp polymer solutions were effective in recovering 1,610-cp oil. The low relative permeability to water allowed a 25-cp polymer solution to provide a nearly favorable mobility ratio. At a given water saturation, krw values for 1,000-cp crude oil were approximately 10 times lower than for 1,000-cp refined oil. In contrast to results found for the Daqing polymer flood (Wang et al. 2000, 2011), no evidence was found in our application that high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) solutions mobilized trapped residual oil. The results are discussed in light of ideas expressed in recent publications. The relevance of the results to field applications is also examined. Although 25-cp polymer solutions were effective in displacing oil during our corefloods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling in a reservoir.

Rheological Properties of Pseudoplastic Fluids in Porous Media

1967 ◽  
Vol 7 (02) ◽  
pp. 149-160 ◽  
Author(s):  
W.B. Gogarty
Keyword(s):  
Porous Media ◽  
Rheological Properties ◽  
Polymer Solutions ◽  
Newtonian Fluids ◽  
Fluid System ◽  
High Molecular Weight Polymer ◽  
Molecular Weight Polymer ◽  
Maximum Percentage ◽  
The Core ◽  
Darcy Equation

Abstract With flow of non-Newtonian fluids in porous media, effective viscosities are needed for use in the Darcy equation. These viscosities depend on the rock parameters and flowing conditions. In this investigation, rheological and flow results were correlated to develop an expression for calculating effective viscosities. Surfactant-stabilized dispersions of water in hydrocarbon were used with consolidated sandstone cores of different permeabilities. The average shear rate in a core was related to the permeability and porosity of the core and the frontal velocity through the core. By using the correlation obtained for determining effective viscosity, experimental and theoretical values were compared for each fluid system by determining average and maximum errors. For the fluid system showing the largest average error, the correlation fit 38 experimental points with an average and maximum percentage error of 4.3 and 14.8, respectively. For the fluid system showing the least error, average and maximum percentage errors of 1.8 and 4.3, respectively, were calculated using 29 experimental points. Introduction Use of non-Newtonian fluids in the petroleum industry is not new. Fluids of this type have been used for many years as fracturing agents and drilling muds. Recently, attention has focused on the use of high molecular weight polymer solutions for secondary recovery. Results have been reported on studies relating to the flow behavior of polymer solutions in porous media. Each study gives the viscosity in the Darcy equation as a function of the rheological properties of the fluid, the characteristics of the porous medium and the pressure gradient. The functional forms of the reported expressions differ somewhat in each study.

Onset of transition in the flow of polymer solutions through microtubes

2018 ◽  
Vol 844 ◽  
pp. 1052-1083 ◽  
Author(s):  
Bidhan Chandra ◽  
V. Shankar ◽  
Debopam Das
Keyword(s):  
Reynolds Number ◽  
Polymer Solution ◽  
Polymer Solutions ◽  
High Molecular Weight Polymer ◽  
Molecular Weight Polymer ◽  
Micro Piv ◽  
Turbulent Transition ◽  
Newtonian Case ◽  
High Concentrations ◽  
Different Diameters

Experiments are performed to characterize the onset of laminar–turbulent transition in the flow of high-molecular-weight polymer solutions in rigid microtubes of diameters in the range $390~\unicode[STIX]{x03BC}\text{m}{-}470~\unicode[STIX]{x03BC}\text{m}$ using the micro-PIV technique. By considering flow in tubes of such small diameters, the present study probes higher values of elasticity numbers ($E\equiv \unicode[STIX]{x1D706}\unicode[STIX]{x1D708}/R^{2}$) compared to existing studies, where $\unicode[STIX]{x1D706}$ is the longest relaxation time of the polymer solution, $R$ is the tube radius and $\unicode[STIX]{x1D708}$ is the kinematic viscosity of the polymer solution. For the Newtonian case, our experiments indicate that the natural transition (without the aid of any forcing mechanism) occurs at Reynolds number ($Re$) $2000\pm 100$. As the concentration of polymer is increased, initially there is a delay in the onset of the transition and the transition Reynolds number increases to $2500$. Further increase in concentration of the polymer results in a decrease in the Reynolds number for transition. At sufficiently high concentrations, the added polymer tends to destabilize the flow and the transition is observed to happen at $Re$ as low as $800$. It is also observed that the addition of polymers, regardless of their concentration, reduces the magnitude of the velocity fluctuations after transition. Dye-stream visualization is further used to corroborate the onset of transition in the flow of polymer solutions. The present work thus shows that addition of polymer, at sufficiently high concentrations, destabilizes the flow when compared to that of a Newtonian fluid, thereby providing additional evidence for ‘early transition’ or ‘elasto-inertial turbulence’ in the flow of polymer solutions. The data for the transition Reynolds number $Re_{t}$ from our experiments (for tubes of different diameters, and for two different polymers at varying concentrations) collapse well according to the scaling relation $Re_{t}\propto 1/\sqrt{E(1-\unicode[STIX]{x1D6FD})}$, where $\unicode[STIX]{x1D6FD}$ is the ratio of solvent viscosity to the viscosity of the polymer solution.

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.

Visco-Elastic Property Studies on Polymer Flooding Systems with High Concentrations

2012 ◽  
Vol 550-553 ◽  
pp. 834-837
Author(s):  
Ji Gang Wang ◽  
Quan Qing Du ◽  
Peng Wu ◽  
Shao Li Hu ◽  
Pan Niu
Keyword(s):  
Elastic Property ◽  
Oil Recovery ◽  
Elastic Characteristic ◽  
Polymer Flooding ◽  
Oil Field ◽  
High Concentration ◽  
Improved Oil Recovery ◽  
High Molecular Weight Polymer ◽  
Molecular Weight Polymer ◽  
Asp Flooding

Keywords: Visco-elastic property; polymer flooding; oil recovery Abstract. Polymer flooding and ASP flooding has improved oil recovery a lot in Daqing oil field. In ASP flooding, the existence of alkali decreases the visco-elastic characteristic of polymer, which decreases the oil recovery of polymer flooding. The aim of this paper was to study the visco-elastic characteristic, shear resistance in high concentration and high molecular weight polymer flooding, and analyzed the suitable parameter of it .They can provide the theory of polymer flooding development and application research.

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).

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