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.

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 Transient Flow of Non-Newtonian Power-Law Fluids in Porous Media

1979 ◽  
Vol 19 (03) ◽  
pp. 164-174 ◽  
Author(s):  
Chi U. Ikoku ◽  
Henry J. Ramey
Keyword(s):  
Porous Media ◽  
Fluid Flow ◽  
Newtonian Fluid ◽  
Oil Recovery ◽  
Transient Flow ◽  
Polymer Solutions ◽  
Newtonian Fluids ◽  
Petroleum Engineering ◽  
Published Data ◽  
Well Test

Abstract The transient flow behavior of non-Newtonian fluids in petroleum reservoirs is studied. A new partial differential equation is derived. The diffusivity equation is a special case of the new equation. The new equation describes the flow of a slightly compressible, non-Newtonian, power-law fluid in a homogeneous porous medium. This equation should govern the flow of most non-Newtonian oil-displacement agents used in secondary and tertiary oil-recovery projects, such as polymer solutions, micellar projects, such as polymer solutions, micellar solutions, and surfactant solutions. Analytical solutions of the new partial differential equation are obtained that introduce new methods of well-test analysis for non-Newtonian fluids. An example is presented for using the new techniques to analyze injection well-test data in a polymer injection project. project. Graphs of the dimensionless pressure function also are presented. These may be used to investigate the error when using Newtonian fluid-flow equations to model the flow of non-Newtonian fluids in porous media. Introduction Non-Newtonian fluids, especially polymer solutions, microemulsions, and macroemulsions, often are injected into the reservoir in various enhanced oil-recovery processes. In addition, foams sometimes are circulated during drilling. Thermal recovery of oil by steam and air injection may lead to the flow of natural emulsions and foams through porous media. Some enhanced oil-recovery projects involving the injection of non-Newtonian fluids have been successful, but most of these projects either failed or performed below expectation. These results suggest the need for a thorough study of the stability of non-Newtonian fluids at reservoir conditions, and also a new look at the flow of non-Newtonian fluids in porous media. porous media. Many studies of the rheology of non-Newtonian fluids in porous media exist in the chemical engineering, rheology, and petroleum engineering literature. In 1969, Savins presented an important survey on the flow of non-Newtonian fluids through porous media. In some cases, he interpreted porous media. In some cases, he interpreted published data further and compared results of published data further and compared results of different investigators. van Poollen and Jargon presented a numerical study of the flow of presented a numerical study of the flow of non-Newtonian fluids in homogeneous porous media using finite-difference techniques. They considered steady-state and unsteady-state flows and used the Newtonian fluid-flow equation. They considered non-Newtonian behavior by using a viscosity that varied with position. No general method was developed for analyzing flow data. Bondor et al. presented a numerical simulation of polymer presented a numerical simulation of polymer flooding. Much useful information on polymer flow was presented, but transient flow was not considered.At present, there is no standard method in the petroleum engineering literature for analyzing petroleum engineering literature for analyzing welltest data obtained during injection of non-Newtonian fluids into petroleum reservoirs. However, injection of several non-Newtonian oil-displacement agents is an important oilfield operation. Interpretation of well-test data for these operations should also be important. Obviously, procedures developed for Newtonian fluid flow are not appropriate. SPEJ P. 164

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 Mathematical Model for Water Flooding and HPAM Polymer Flooding in Enhanced Oil Recovery

2021 ◽  
Vol 21 (1) ◽  
pp. 124
Author(s):  
Ahmad Tawfiequrahman Yuliansyah ◽  
Bardi Murachman ◽  
Suryo Purwono
Keyword(s):  
Mathematical Model ◽  
Porous Media ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Coming Out ◽  
Polymer Flooding ◽  
Flow In Porous Media ◽  
Water Flooding ◽  
Silica Sand ◽  
Model Parameters

The need for energy, especially the petroleum-based one, is steadily increasing along with population growth and technological advancement. Meanwhile, oil exploitation from oil reservoirs using primary and secondary techniques can only obtain about 30%-50 % out of the original oil in place. Enhanced Oil Recovery (EOR) is a method for increasing oil recovery from a reservoir by injecting materials that are not found in the reservoir, such as surfactant, polymer, etc. This research aims to develop a mathematical model representing two-phase flow through porous media in the EOR process. This model was extended from mass balance and fluid flow in porous media equations. The reliability of the model was then validated by water flooding and polymer flooding experiment. A porous media, constituted by a silica sand pack, was saturated with 2 % brine and sequentially flooded with HPAM polymer solution at various concentrations (5,000-15,000 ppm). The volume of the oil coming out from the media at any time intervals was measured. Validation of the model was carried out by optimizing the model parameters to obtain the best curve-fitting on the plot of the percentage of cumulative recovered oil against time. The results showed that the proposed mathematical model was reliable enough to express both water and polymer-flooding processes.

scholarly journals Impact of Mechanical Degradation on Polymer Injectivity in Porous Media

2018 ◽  
Author(s):  
Badar Al-Shakry ◽  
Tormod Skauge ◽  
Behruz Shaker Shiran ◽  
Arne Skauge
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Polymer Solutions ◽  
Shear Thickening ◽  
Economic Cost ◽  
High Viscosity ◽  
Polymer Flooding ◽  
Mechanical Degradation ◽  
Thickening Behavior

Polymer flooding is an established enhanced oil recovery (EOR) method, still many aspects of polymer flooding are not well understood. This study investigates the influence of mechanical degradation on flow properties of polymers in porous media. Mechanical degradation due to high shear forces may occur in the injection well and at the entrance to the porous media. The polymers that give high viscosity yields at a sustainable economic cost are typically large, MW > 10 MDa, and have wide molecular weight distributions. Both MW and the distributions are altered by mechanical degradation, leading to changes in the flow rheology of the polymer. The polymer solutions were subjected to different degrees of pre-shearing and pre-filtering before injected into Bentheimer outcrop sandstone cores. Rheology studies of injected and produced polymer solutions were performed and interpreted together with in-situ rheology data. The core floods showed a predominant shear thickening behavior at high flow velocities which is due to successive contraction/expansion flow in pores. When pre-sheared, shear thickening was reduced but with no significant reduction in in-situ viscosity at lower flow rates. This may be explained by reduction in the extensional viscosity. Furthermore, the results show that successive degradation occurred which suggests that the assumption of the highest point of shear which determines mechanical degradation in a porous media does not hold for all field relevant conditions.

An Easy Calculation Method on Sweep Efficiency of Chemical Flooding

2013 ◽  
Vol 275-277 ◽  
pp. 496-501
Author(s):  
Fu Qing Yuan ◽  
Zhen Quan Li
Keyword(s):  
Oil Recovery ◽  
Orthogonal Design ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Solution Viscosity ◽  
Chemical Flooding ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Easy Calculation ◽  
Polymer Compound

According to the geological parameters of Shengli Oilfield, sweep efficiency of chemical flooding was analyzed according to injection volume, injection-production parameters of polymer flooding or surfactant-polymer compound flooding. The orthogonal design method was employed to select the important factors influencing on expanding sweep efficiency by chemical flooding. Numerical simulation method was utilized to analyze oil recovery and sweep efficiency of different flooding methods, such as water flooding, polymer flooding and surfactant-polymer compound flooding. Finally, two easy calculation models were established to calculate the expanding degree of sweep efficiency by polymer flooding or SP compound flooding than water flooding. The models were presented as the relationships between geological parameters, such as effective thickness, oil viscosity, porosity and permeability, and fluid parameters, such as polymer-solution viscosity and oil-water interfacial tension. The precision of the two models was high enough to predict sweep efficiency of polymer flooding or SP compound flooding.

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.

scholarly journals SURFACTANT-POLYMER FLOODING PERFORMANCE IN HETEROGENEOUS TWO-LAYERED POROUS MEDIA

2011 ◽  
Vol 12 (1) ◽  
pp. 31-38 ◽  
Author(s):  
Muhammad Taufiq Fathaddin ◽  
Asri Nugrahanti ◽  
Putri Nurizatulshira Buang ◽  
Khaled Abdalla Elraies
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Reservoir Heterogeneity ◽  
Residual Oil Saturation ◽  
Layered Porous Media ◽  
Multiple Porosity

In this paper, simulation study was conducted to investigate the effect of spatial heterogeneity of multiple porosity fields on oil recovery, residual oil and microemulsion saturation. The generated porosity fields were applied into UTCHEM for simulating surfactant-polymer flooding in heterogeneous two-layered porous media. From the analysis, surfactant-polymer flooding was more sensitive than water flooding to the spatial distribution of multiple porosity fields. Residual oil saturation in upper and lower layers after water and polymer flooding was about the same with the reservoir heterogeneity. On the other hand, residual oil saturation in the two layers after surfactant-polymer flooding became more unequal as surfactant concentration increased. Surfactant-polymer flooding had higher oil recovery than water and polymer flooding within the range studied. The variation of oil recovery due to the reservoir heterogeneity was under 9.2%.

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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