Polymer Solutions In Porous Media Research Articles

Enhancing heavy‐oil displacement efficiency through viscoelasticity of polymer solution by investigating the viscosity limit of crude oil: An experimental study

AbstractThe world is rich in ordinary heavy‐oil resources. Exploring the limit of the crude oil viscosity limits can further expand the application of polymer flooding technology in heavy‐oil reservoirs and improve the development efficiency of heavy‐oil reservoirs. On the basis of the polymer flooding that has been implemented in the Bohai offshore oilfield, this study characterized the in situ viscoelasticity of the polymer solution SNF3640C. We compared the polymer flooding and glycerol flooding performance in low‐viscous oil reservoirs (with a viscosity of 6.5 cp) and high‐viscous oil reservoirs (with a viscosity of 65 cp) by conducting microscopic dead‐end experiments and macroscopic core‐flooding experiments, and then analyzing the impact of polymer's viscoelasticity on the oil displacement efficiency of heavy oil. Finally, multiple crude oils with a wide range of viscosity were used to explore the crude oil viscosity limits under which the efficiency of heavy‐oil displacement could be improved through polymer viscoelasticity. The results demonstrate that: (1) the SNF3640C polymer solution can exhibit a certain degree of viscoelasticity in deep formation. At a distance of 140 m from the wellbore in the reservoir, a solution with a concentration of 1500 mg/L can still have a first normal stress difference of 2.5 Pa. Polymers can effectively improve the efficiency of heavy‐oil displacement through elastic action. (2) The viscosity limit that can improve the efficiency of heavy‐oil displacement under current experimental conditions does not exceed 5486 cp. The efficiency of polymer flooding for crude oil has decreased to 31.68%, and the contribution of elastic flooding is only 1.5%. The research method of using viscous glycerol as a comparison to demonstrate the contribution of polymer elasticity to oil displacement effectiveness effectively solves the problem of isolating the contribution by polymer solution's viscosity and elasticity, and clarifies the development direction of polymer flooding for developing heavy crude oil. Enhancing the elastic effect of polymer solution in porous media can increase the viscosity range of polymer flooding heavy oil.

Flow characteristic of polymer solutions in porous media: Influence of the molecular weight and concentration

Flow characteristic of polymer solutions in porous media: Influence of the molecular weight and concentration

Characterization of Nonlinear Viscoelastic Properties of Enhanced Oil Recovery Polymer Systems Using Steady-Shear Rheometry

SummaryEnhanced oil recovery (EOR) polymer systems such as hydrolyzed polyacrylamide (HPAM) solutions flowing in porous media at high fluxes were reported to cause shear-thickening, a nonlinear viscoelastic (NLVE) phenomenon. Bulk rheological studies are usually performed to characterize the viscous and viscoelastic behaviors of polymer solutions in porous media. To characterize the viscoelastic properties, oscillatory shear rheology based on linear viscoelastic (LVE) data and extensional rheology based on NLVE data have been used. Although both extensional flow and high-speed shear flow can stretch and thicken polymer solutions in a nonlinear fashion, steady-shear rheometry has been used to measure only the viscous and thinning behavior of HPAM systems. In this paper, (a) the thickening ability of HPAM polymer systems formulated with contrasting salinity and molecular weight (MW) concentration is characterized in bulk shear rheometry to analyze if the thickening in the pure shear field correlates with the thickening behavior reported in porous media and other rheometry and (b) the thickening intensity of the polymer solutions of varying salinity concentration in the bulk shear field is compared with the reported mechanical degradation effects in the literature.The shear-thickening index obtained by fitting a power-law model to thickening data in steady-shear rheograms is higher for the high-saline, high-MW low-concentration HPAM systems that have inherently higher nonlinear viscoelasticity. Furthermore, the thickening behavior observed due to salinity variation in bulk steady shear contrasts with linear oscillatory shear behavior but conforms to the thickening behavior observed in porous media and in the extensional field. This signifies that polymer-EOR researchers performing comparative studies on low-salinity and high-salinity polymer floods, and having a shear rheometer at their disposal, must look beyond linear oscillatory rheology and make use of nonlinear steady-shear rheology. There is a direct relation between the shear-thickening index of saline HPAM solutions and their mechanical degradation intensity. This paper shows that the high-speed data in steady-shear rheometry that are usually ignored in EOR literature have useful information and the notion that HPAM solutions are purely thinning in the bulk shear field needs to be reconsidered.

Experimental and modeling study of hydrophobic associative polyacrylamide for enhanced oil recovery in carbonate reservoir

In this study, hydrophobic associative polyacrylamide (HAPAM) was used in conjunction with the chemical flooding technique in a low-permeability carbonates reservoir. To test the efficacy of the proposed method, both a model and an experiment were created. Experiments were run to compare the relative permeability (Kr) curves, oil recovery rates, and rheological, physical, aging time, and petrophysical features of brine water and polymer flooding in a core. The purpose of these tests was to show how HAPAM can be used to boost oil recovery. Computer Modelling Group (CMG), a simulator, was then used. An oil-and-brine (or HAPAM solution) grid in three dimensions (3D) was developed. The validity of the suggested simulator was established by comparing its results to those obtained from commercial software and from the majority of brine or polymer flooding experiments. The developed simulator was used to undertake additional research into the non-Newtonian flow of brine or polymer solution in porous media. The experimental consequences indicated that the polymer solution has a shear thinning viscosity curve and flow behavior index. Shear thinning, viscosity, shear resistance, aging time, density, surface tension, and interfacial tension, and the water wet relative permeability curve are all improved by the adding 1500 ppm HAPAM to brine water. Moreover, oil recovery was about 80%. There was a strong agreement between the results of the modeling study and the experiments.

Influencing factors for effective establishment of residual resistance factor of polymer solution in porous media

Influencing factors for effective establishment of residual resistance factor of polymer solution in porous media

Effect of hydrophobic association on the flow resistance of polymer solutions

Comprehending the percolation law of polymer solutions in porous media is the basis of effective application of polymer flooding. The solution properties of partially hydrolyzed polyacrylamide (HPAM) and the hydrophobically associating polymer AP-P4 were compared, and the seepage characteristics in porous media were studied. The results showed that HPAM is a viscoelastic fluid dominated by a viscosity modulus. The smaller hydrodynamic size (≥3 µm) and low adsorption capacity (200 µg/g) caused an increase in the resistance factor of HPAM in porous media with the increase in injection velocity. Hydrophobic association greatly improved the solution properties of the polymer, with a stronger apparent viscosity, elastic modulus, hydrodynamic size (≥10 µm), and adsorption capacity (780 µg/g), showing that the viscoelastic fluid properties were dominated by the elastic modulus. The resistance factor of the polymer solution in porous media decreased with the increase in injection velocity.

Analysis and Simulation of Polymer Injectivity Test in a High Temperature High Salinity Carbonate Reservoir.

Polymer flooding has gained much interest within the oil industry in the past few decades as one of the most successful chemical enhanced oil recovery (CEOR) methods. The injectivity of polymer solutions in porous media is a key factor in polymer flooding projects. The main challenge that faces prediction of polymer injectivity in field applications is the inherent non-Newtonian behavior of polymer solutions. Polymer in situ rheology in porous media may exhibit complex behavior that encompasses shear thickening at high flow rates in addition to the typical shear thinning at low rates. This shear-dependent behavior is usually measured in lab core flood experiments. However, data from field applications are usually limited to the well bottom-hole pressure (BHP) as the sole source of information. In this paper, we analyze BHP data from field polymer injectivity test conducted in a Middle Eastern heterogeneous carbonate reservoir characterized by high-temperature and high-salinity (HTHS) conditions. The analysis involved incorporating available data to build a single-well model to simulate the injectivity test. Several generic sensitivities were tested to investigate the impact of stepwise variation in injection flow rate and polymer concentration. Polymer injection was reflected in a non-linear increase in pressure with injection, and longer transient behavior toward steady state. The results differ from water injection which have linear pressure response to rate variation, and quick stabilization of pressure after rate change. The best match of the polymer injection was obtained with complex rheology, that means the combined shear thickening at high rate near the well and moving through apparent Newtonian and shear thinning at low rate.

Modeling Monophasic Flow of Polymer Solutions in Porous Media: Assessing Relative Impact of Intrinsic Fluid Properties and Pore Microstructure

Polymer solutions are often described as viscoelastic fluids, whose rheological behavior dynamically evolves according to the flow shear rate due to successive contractions and relaxations of inner deformable components. Contrary to shear-thickening and shear-thinning fluids, viscoelastic fluids can undergo an increase in the normal stress-differences even in simple geometries, leading to counterintuitive flow patterns. In this paper, we investigate numerically the monophasic flow of viscoelastic fluids through microfluidic devices. The objective is to qualitatively assess how modification of the rheological properties and the geometry of porous media representative element affect the flow regime at microscale. Deviations from equivalent Newtonian model are analyzed to quantify the contribution of elasticity in the flow. It is demonstrated that depending on the geometry, flow of polymer solution can display anisotropic features and flow resistance at relatively low viscoelastic numbers, which is coherent with previous microscopic experimental and numerical studies. Ensued applications of the formulated microscale model are discussed.

Dynamics of viscoelastic flow through axisymmetric constricted microcapillary at high elasticity number

The fundamental understanding of pore scale flow mechanisms associated with the mobilization of trapped oil ganglia during the injection of polymer solutions in porous media requires detailed analysis of viscoelastic flow through pore throats, which can be modeled as constricted capillaries. Despite the vast literature on macroscale and, more recently, microscale viscoelastic flow through contraction–expansion channels, the range of flow parameters covered in previous work does not include the flow dynamics that occur in pore throats of a porous medium, at which the Reynolds number Re is very low and the elasticity number El, defined as the ratio of elastic to inertial forces, is very high. We extend previous analyses of viscoelastic flow through constricted planar channels to axisymmetric geometry and flow conditions closer to pore scale flows. The effects of elastic forces are isolated by comparing the flow of a viscoelastic liquid to that of a Newtonian fluid with the similar shear viscosity. The pressure difference is measured as function of imposed flow rate. The different flow regimes are characterized by measuring the instantaneous and average velocity field near the constriction using micro particle image velocimetry (μ−PIV) technique.

Investigation into mobility control mechanisms by polymer flooding in offshore high-permeable heavy oil reservoir

ABSTRACT The systematic understanding of the mobility control of polymer solution in porous media is conducive to the engineering application and development of polymer flooding technology. In this paper, two kinds of polymers (partially hydrolyzed polyacrylamide (HPAM) and MJ-10 (a hydrophobically associating polyacrylamide, HAPAM)) with different adsorption characteristics were used to build a solution system with different performance characteristics. And run a series of viscosity measurement, residual resistance factor (RRF) measurement and oil displacement experiments on man-made sand packs. The results show that the viscosity and residual resistance coefficient of polymer solution can enhance its fluidity control. The higher the viscosity of solution, the higher the RRF, and the higher the displacement efficiency. The solution system HM3 can make full use of the solution characteristics of the two polymers to obtain a moderate solution viscosity and residual resistance coefficient. Compared with a single solution H2 and M2, it can increase the oil recovery by 5% in the low permeability layer. The compound application of polymer solution will be a development direction of polymer flooding in the future.

Pore-Scale Flow Characterization of Polymer Solutions in Microfluidic Porous Media.

Polymer solutions are frequently used in enhanced oil recovery and groundwater remediation to improve the recovery of trapped nonaqueous fluids. However, applications are limited by an incomplete understanding of the flow in porous media. The tortuous pore structure imposes both shear and extension, which elongates polymers; moreover, the flow is often at large Weissenberg numbers, Wi, at which polymer elasticity in turn strongly alters the flow. This dynamic elongation can even produce flow instabilities with strong spatial and temporal fluctuations despite the low Reynolds number, Re. Unfortunately, macroscopic approaches are limited in their ability to characterize the pore-scale flow. Thus, understanding how polymer conformations, flow dynamics, and pore geometry together determine these nontrivial flow patterns and impact macroscopic transport remains an outstanding challenge. This review describes how microfluidic tools can shed light on the physics underlying the flow of polymer solutions in porous media at high Wi and low Re. Specifically, microfluidic studies elucidate how steady and unsteady flow behavior depends on pore geometry and solution properties, and how polymer-induced effects impact nonaqueous fluid recovery. This work thus provides new insights for polymer dynamics, non-Newtonian fluid mechanics, and applications such as enhanced oil recovery and groundwater remediation.

A new approach for measuring rheology of polymer solutions in reservoir conditions

The simulation of flow processes under reservoir condition is a hard task. Viscosity of polymer solution in porous media depends on adsorption of polymers on mineral substrates. Specific features characterize filtration of polymer solutions in porous media. Here, we propose a new approach to evaluate the rheology of polymers that considers fluid interactions with mineral surfaces. The principle of this method is as follows: measuring viscosity of «mineral-in-polymer » suspension. Hence, this approach needs simple equipment rather than complex core flooding system. The laboratory selection of effective polymer and its optimum concentration is carried out by the proposed approach. It is crucial for primary screening of some polymers. The presence of dispersed minerals in model suspensions influences the surface tension between the polymer solution and solid surface with various chemical nature. In order to justify this method, we used minerals with different chemical nature such as dispersed calcite and dolomite, and two widely used polyacrylamide type polymers that differ in molecular masses. We observed that viscosities between various suspensions differ several times due to the surface nature. We also determined the correlation between the viscosity of model suspension and contact angle. The latter is determined by chemical nature of minerals.

Fluid flow characteristics during polymer flooding

At present the main problems of polymer flooding is the high injection pressure which could not guarantee the later injection. In this paper the analyses of polymer’s physical properties and its solution’s variable movement characteristics in porous media reveal the inevitable trend of decrease in injection capacity and liquid production due to the increase of fluid viscosity and flow rate with more flow resistance. The injection rate makes the primary contribution to the active viscosity of the polymer solution in porous media. The higher injection rate, the greater shearing degradation and the more the viscosity loss. Besides the quantitative variation, the rate also changes qualitatively as that the injection rate demonstrates composite change of injection intensity and density. Due to the different adjustment function of the polymer solution on its injection profile, there should be different adjustment model of rates in such stages. Here in combination of the on-site recognitions, several conclusions and recommendations are made based on the study of the injection pattern adjustment during polymer flooding to improve the pressure distribution system, which would be a meaningful reference for extensive polymer flooding in the petroleum industry.

A polymer flooding mechanism for mature oil fields: Laboratory measurements and field results interpretation

Although polymer flooding has been widely studied in the literature on oil recovery, many questions remain about the technique's action mechanisms. It is widely accepted that the process is based on increasing viscosity of the aqueous phase (injected fluid). The polymer can also act secondarily by reducing the relative permeability to water. Fields that are markedly heterogeneous, highly depleted or that contain fluids with strong salinity are not good candidates for the process. To overcome these restrictions, the most recent applications have used more resistant polymers, with higher molar masses, injected in larger quantities, to preserve the level of viscosity under these adverse conditions. However, a pilot test in a field under adverse conditions showed surprising results and unexpected pressure abnormality, even with small quantities of partially hydrolyzed polyacrylamide (HPAM) with relatively low molar mass (6 × 106 g/mol). This paper reports the investigation of the prevailing mechanism responsible for these unexpected results, by means of laboratory tests of flow in porous media and rheological analysis of fluids and hydrodynamic diameter of polymer molecules. The Salt effect (NaCl) on polymer solutions was researched by rheology and particle size analysis at 25 and 50 °C. The results showed that mechanical/hydrodynamic retention prevails over polymer adsorption at the rock, with the former being caused by the increase in the polymeric hydrodynamic volume in fluid dilution processes. Besides this, increased temperature was found to favor greater hydrodynamic volume under tested conditions, while salinity had little influence. The results also shed new light on the flow behavior of polymer solutions in porous media, particularly in polymer injection for enhanced oil recovery from mature fields.

Polymer Flow Through Porous Media: Numerical Prediction of the Contribution of Slip to the Apparent Viscosity

The flow of polymer solutions in porous media is often described using Darcy’s law with an apparent viscosity capturing the observed thinning or thickening effects. While the macroscale form is well accepted, the fundamentals of the pore-scale mechanisms, their link with the apparent viscosity, and their relative influence are still a matter of debate. Besides the complex effects associated with the rheology of the bulk fluid, the flow is also deeply influenced by the mechanisms occurring close to the solid/liquid interface, where polymer molecules can arrange and interact in a complex manner. In this paper, we focus on a repulsive mechanism, where polymer molecules are pushed away from the interface, yielding a so-called depletion layer in the vicinity of the wall. This depletion layer acts as a lubricating film that may be represented by an effective slip boundary condition. Here, our goal is to provide a simple mean to evaluate the contribution of this slip effect to the apparent viscosity. To do so, we solve the pore-scale flow numerically in idealized porous media with a slip length evaluated analytically in a tube. Besides its simplicity, the advantage of our approach is also that it captures relatively well the apparent viscosity obtained from core-flood experiments, using only a limited number of inputs. Therefore, it may be useful in many applications to rapidly estimate the influence of the depletion layer effect over the macroscale flow and its relative contribution compared to other phenomena, such as non-Newtonian effects.

Application of binding theory for seepage of viscoelastic fluid in a variable diameter capillary

The polymer solution for polymer flooding is a viscoelastic fluid. There exist both shear flow and elongational flow when the polymer solution flows in a porous medium, where an additional dissipation is involved. The additional dissipation caused by elongational deformation is often ignored while studying the flow of the fluid in a porous medium. For a complex polymer solution, the generated elongational pressure drop cannot be ignored. In a capillary of fixed diameter, the polymer solution is only impacted by the shear force, and its rheological property is pseudoplastic. Therefore the variable diameter capillary and the converging-diverging flow model with different cross sections are required to describe the flow characteristics of the polymer solution in porous media more accurately. When the polymer solution flows through the port, we have the elongational flow and the polymer molecules undergo elongational deformation elastically. By using the mechanical energy balance principle and the minimum energy principle, a mathematical model of non-Newtonian fluid inlet flow was established by Binding. On the basis of the Binding theory, with the application of the theory of viscoelastic fluid flow in the circular capillary and the contraction – expansion tube, the relations between the viscoelastic fluid flow rate and the pressure drop are obtained.

Statement of Removal

ABSTRACTPolymer flooding is an attractive branch of chemical enhanced oil recovery techniques. Regrettably, chemical and mechanical degradation reduces the effectiveness of polymer flooding. This paper explores the effects of silica nanoparticles on flow behavior of polymer solution in porous media by employing both rheological experiments and numerical simulations. Experimental results indicate that dispersed silica nanoparticles in polymer solution are responsible for polymer adsorption reduction and the solution viscosity improvement. Simulation results revealed that if the injectant has some dispersed silica nanoparticles, the cumulative heavy oil recovery and breakthrough time will be bettered compared to the conventional polymer flood.

An Investigation of Polymer Adsorption in Porous Media Using Pore Network Modelling

Polymer injection in hydrocarbon reservoirs has been of great interest in petroleum engineering as an enhanced oil recovery method. In order to have a reliable injection plan, an accurate estimation of polymer behaviour is required to control the fluid flow in porous media. However, it is difficult to calculate the flow properties of polymer solutions—known as non-Newtonian fluids—in porous media, due to variable viscosity at different shear rates. Adsorption of polymer molecules onto the rock surface decreases the available cross-sectional area of polymer solution, therefore at a constant rate, the shear rate increases. As a result, it is important to investigate how polymer adsorption can affect the polymer solution flow behaviour in porous media. Moreover, prior to any polymer injection plan, the amount of adsorbed polymer should be calculated, due to the high cost of polymers. In the present study, pore network modelling was used to investigate the effect of polymer adsorption on flow behaviour of polymer solutions in porous media. To achieve this goal, a simple pore was constructed to adequately represent the real structure of the porous medium. It was then validated by simulation of Newtonian fluid flow in the network and comparison of the calculated flow properties with the experimental data. After validation, the pore network was used for simulation of non-Newtonian fluid flow in porous media. The experimental apparent viscosity of non-Newtonian fluid was used for verification of the procedure and the developed network. The apparent viscosity of non-Newtonian was calculated successfully using macroscopic properties of the rock sample and measured bulk properties of non-Newtonian fluid. The effect of polymer adsorption on calculation of non-Newtonian fluid apparent viscosity was then investigated. It was shown that the polymer adsorption process plays an important role in calculation of polymer solution apparent viscosity. The results reveal that polymer adsorption cannot be neglected, especially in near well-bore areas where the adsorption is high. Finally, the effect of wettability in calculating the total amount of adsorbed polymer volume was studied. The results suggest that neglecting the rock’s wettability can result in an overestimation or underestimation of the amount of adsorbed polymer.

Study on Flow Parameters Measurement Experiment of Polymer Solution in Porous Media

Due to the complexity of porous media and viscoelasticity of polymer solution, the flow behavior of polymer solution in porous media is more complex than that in the rheometer, and the flow regular pattern of polymer solution in porous media directly affects the formulation of polymer flooding projects. This paper designs experiment on flow parameters measurement of polymer solution (partially hydrolyzed polyacrylamide) in porous media, and the regular pattern of influence on resistance factor, residual resistance factor and flow viscosity in porous media caused by core permeability, polymer concentration, polymer molecular weight and polymer injection rate was given. The followings are the results: even for the same batch core with similar parameters, due to reasons such as natural fractures which could lead to comparatively large difference of core parameters between the same batch of core, thus in order to ensure the reliability of experiment data, it is necessary to detect core quality before core flooding experiment. Core end effect has significant effect on the results of core flooding experiment, it suggests that we should eliminate the effect of core end effect when carry out core flooding experiment, otherwise it is difficult to obtain valid experiment data. There exists a critical polymer concentration, when polymer concentration is lower than critical concentration, resistance factor is basically equal to apparent viscosity; when polymer concentration is higher than critical concentration, resistance factor is far less than apparent viscosity and the difference value increases with the increase of polymer concentration. Flow viscosity of polymer solution in porous media is far less than apparent viscosity in the rheometer and when polymer concentration increases, the increase extent of flow viscosity is far less than the increase of apparent viscosity. Results of this research are of great importance for enhancing flooding effect and guiding oilfield production.

Characterizing the Role of Clay and Silica Nanoparticles in Enhanced Heavy Oil Recovery During Polymer Flooding

Polymer flooding as one of the most effective methods for enhancing oil recovery has a significant effect on tertiary production of reservoirs with poor vertical sweep efficiencies and those which are extremely heterogeneous. Water-soluble polymers are used to both increase the viscosity of water and decrease the mobility ratio of the displaced and displacing fluids. However, due to high amount of polymer adsorption, presence of divalent cations and mechanical degradation, polymer molecules may lose their properties. Hence it is necessary to further improve the displacement effectiveness of polymer flooding. Despite the fact that several ways have been suggested to enhance the performance of polymer flooding, application of nanoparticles in the improvement of rheological properties of the polymer solution used in enhanced oil recovery has not been reported previously and is still an ongoing subject. This paper investigates the effects of nanoparticles on flow behavior of polymer solution in porous media by employing both experimental studies and numerical simulations. The simulation model first is validated against well-controlled laboratory experiment to have reliable predictions of the full-field implementations. The results show that the amount of polymer adsorption and viscosity of polymer solution will improve when the clay or silica nanoparticles is present in the injectant, and accordingly, the cumulative oil recovery and breakthrough time will be bettered. The result of sensitivity analysis demonstrates that polymer molecules are more degradable during polymer flooding compared to nanoparticles-assisted polymer flooding. Based on the validated model, 3D simulations of nanoparticles-assisted polymer field pilot were performed and the results revealed that the cumulative oil recovery, water cut and breakthrough time will improve when the injectant has some dispersed nanoparticles.