The Effect of Sulfonate/Polymer Interaction on Mobility Buffer Design

1979 ◽  
Vol 19 (01) ◽  
pp. 5-14 ◽  
Author(s):  
M.T. Szabo
Keyword(s):  
Phase Separation ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Polymer Concentration ◽  
Trade Mark ◽  
Injection Rate ◽  
Mixing Zone ◽  
Polymer Injection ◽  
Tertiary Oil Recovery

A study was made of the movement of 1-PV slugs of polymer solutions in cores that had been treated previously with sulfonate and then flushed with previously with sulfonate and then flushed with brine. The data revealed premature polymer breakthrough. These results were attributed to low polymer retention and an inaccessible pore volume polymer retention and an inaccessible pore volume to polymer flow. The shapes and absolute values of the polymer breakthrough curves depended on the type of polymer and sulfonate used. When no brine flush followed the sulfonate solution, an even earlier polymer breakthrough was observed. This phenomenon was thought to be related mainly to a phenomenon was thought to be related mainly to a polymer/sulfonate interaction. polymer/sulfonate interaction. Solutions of 10 chemically different polymers were blended with solutions of four sulfonates. After standing, these mixtures separated into two layers - a top layer highly concentrated in polymer and a bottom layer containing a higher sulfonate concentration. Viscosities, fractional volumes, and interfacial tensions to oil of the separated layers depended on the particular polymer/sulfonate system. These layers were found to be separate phases with a measurable, but very low, interfacial phases with a measurable, but very low, interfacial tension at the phase boundary. The effect of salinity and polymer concentration on phase separation also was studied. Phase separation of polymer/sulfonate systems also occurred in Berea core flow tests, resulting in differing mobilities of the separated phases. This phenomenon can result in a low recovery efficiency in low-tension surfactant flooding. An improvement in tertiary oil recovery efficiency was achieved, however by using low salinity in the mobility bank. Introduction This study discusses low-tension oil displacement, wherein an aqueous surfactant slug is driven by a polymer solution. Many papers have dealt with such systems, particularly as they relate to tertiary oil recovery; however, little attention has been devoted to polymer behavior in the polymer/sulfonate mixing zone. Recently, Trushenski et al. reported that high mobility had developed in the polymer/sulfonate mixing zone. The mechanism for this phenomenon was not proposed. They also showed that because of polymer/sulfonate incompatibility, phase separation can occur, which can lead to excessive sulfonate retention through "phase entrapment." This study investigates this phase-separation phenomenon and its effect on flow behavior in the phenomenon and its effect on flow behavior in the polymer/sulfonate mixing zone. polymer/sulfonate mixing zone. POLYMER INJECTION INTO POLYMER INJECTION INTO SULFONATE-TREATED BEREA CORES PROCEDURE PROCEDURE In one set of experiments, two sulfonate solutions [Witco TRS-18/40, (1/1) and Amoco H-4344-1 Tm] were injected into separate Berea cores. Concentrations were 2 wt % (0.02 kg/kg) in 2%. NaCl brine, volume was 2 PV, and the injection rate was 14 ft/D (4.27 m/d). Thereafter, 3 PV of 2% NaCl brine was injected at the same rate. This was followed by 1 PV of 600-ppm polymer solution in 2% NaCl brine, then by 2% NaCl brine. During the last two cycles, the injection rate was 4 ft/D (1.22 m/d). During both polymer injection and the subsequent brine flush, the inlet pressure was recorded and effluent samples were taken to analyze polymer concentration. Polymer concentrations were determined by radioactivity in the case of C14-tagged polymers (Polymers 454 and 340 trade mark) and by the viscosity measurement technique when Kelzan MF (trade mark) was used. In the second set of experiments, a polymer solution directly followed the sulfonate solution. Injection rates were the same as in the first set of experiments. Both sets of experiments used Berea cores, 5.08 cm in diameter and 14.2 cm in length. Each polymer solution was filtered through a separate Berea core disk with about 500 md permeability and with diameter and length of 5.08 and 1.4 cm, respectively. SPEJ P. 4

scholarly journals Study Rheological Behavior of Polymer Solution in Different-Medium-Injection-Tools

Polymers ◽  
2019 ◽  
Vol 11 (2) ◽  
pp. 319 ◽  
Author(s):  
Bin Huang ◽  
Xiaohui Li ◽  
Cheng Fu ◽  
Ying Wang ◽  
Haoran Cheng
Keyword(s):  
Molecular Weight ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Injection Rate ◽  
Injection Velocity ◽  
Structural Parameter ◽  
Local Perturbation ◽  
Polymer Injection ◽  
Single Pipe

Previous studies showed the difficulty during polymer flooding and the low producing degree for the low permeability layer. To solve the problem, Daqing, the first oil company, puts forward the polymer-separate-layer-injection-technology which separates mass and pressure in a single pipe. This technology mainly increases the control range of injection pressure of fluid by using the annular de-pressure tool, and reasonably distributes the molecular weight of the polymer injected into the thin and poor layers through the shearing of the different-medium-injection-tools. This occurs, in order to take advantage of the shearing thinning property of polymer solution and avoid the energy loss caused by the turbulent flow of polymer solution due to excessive injection rate in different injection tools. Combining rheological property of polymer and local perturbation theory, a rheological model of polymer solution in different-medium-injection-tools is derived and the maximum injection velocity is determined. The ranges of polymer viscosity in different injection tools are mainly determined by the structures of the different injection tools. However, the value of polymer viscosity is mainly determined by the concentration of polymer solution. So, the relation between the molecular weight of polymer and the permeability of layers should be firstly determined, and then the structural parameter combination of the different-medium-injection-tool should be optimized. The results of the study are important for regulating polymer injection parameters in the oilfield which enhances the oil recovery with reduced the cost.

Drag Reducing Polymer in Helicoidal Flow

1981 ◽  
Vol 103 (4) ◽  
pp. 491-496 ◽  
Author(s):  
J. T. Kuo ◽  
L. S. G. Kovasznay
Keyword(s):  
Drag Reduction ◽  
Polymer Solution ◽  
Ph Value ◽  
Flow Behavior ◽  
Superposition Principle ◽  
Polymer Concentration ◽  
Second Phase ◽  
Additional Parameter ◽  
Solution Flow ◽  
Screw Pump

A novel flow configuration was explored for the study of the behavior of drag reducing polymers. A screw pump consisting of a smooth cylinder and a concentrically placed screw was used to create a strongly three-dimensional but essentially laminar flow. In the first phase of the study, the static pressure head developed by the screw pump was measured as a function of polymer concentration (polyox 10 to 100 ppm in water). A large increase of the developed head was observed that behaved in an analogous manner to drag reduction as far as concentration and straining of the polymer solution was concerned. In the second phase of the study, a new apparatus was constructed and the additional parameter of a superimposed through flow was included and the degree of failure of the superposition principle was established. Sensitivity of the phenomenon to chemicals like HCl, HNO3, and NaOH in the polymer solution was also studied. When the effect of these chemicals on the polymer solution flow behavior was presented in terms of the pH value of the polymer solution, it showed a similar trend to those observed in drag reduction.

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.

Temperature Dependence of the Shear-Thinning Behavior o Partially Hydrolyzed Polyacrylamide Solution for Enhanced Oil Recovery

2020 ◽  
Vol 143 (6) ◽  
Author(s):  
Pan-Sang Kang ◽  
Jong-Se Lim ◽  
Chun Huh
Keyword(s):  
Temperature Dependence ◽  
Polymer Solution ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Polymer Concentration ◽  
Shear Thinning ◽  
Temperature Model ◽  
Polyacrylamide Solution ◽  
Partially Hydrolyzed Polyacrylamide ◽  
Hydrolyzed Polyacrylamide

Abstract The viscosity of injection fluid is a critical parameter that should be considered for the design and evaluation of polymer flood, which is an effective and popular technique for enhanced oil recovery (EOR). It is known that the shear-thinning behavior of EOR polymer solutions is affected by temperature. In this study, temperature dependence (25–70 °C) of the viscosity of a partially hydrolyzed polyacrylamide solution, the most widely used EOR polymer for oil field applications, was measured under varying conditions of the polymer solution (polymer concentration: 500–3000 ppm, NaCl salinity: 1000–10,000 ppm). Under all conditions of the polymer solution, it was observed that the viscosity decreases with increasing temperature. The degree of temperature dependence, however, varies with the conditions of the polymer solution. Martin model and Lee correlations were used to estimate the dependence of the viscosity of the polymer solution on the polymer concentration and salinity. In this study, we proposed a new empirical model to better elucidate the temperature dependence of intrinsic viscosity. Analysis of the measured viscosities shows that the accuracy of the proposed temperature model is higher than that of the existing temperature model.

scholarly journals A New Empirical Model for Viscosity of Sulfonated Polyacrylamide Polymers

Polymers ◽  
2019 ◽  
Vol 11 (6) ◽  
pp. 1046 ◽  
Author(s):  
Saeed Akbari ◽  
Syed Mohammad Mahmood ◽  
Hosein Ghaedi ◽  
Sameer Al-Hajri
Keyword(s):  
Polymer Solution ◽  
Oil Recovery ◽  
Empirical Model ◽  
Linear Regression Analysis ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Solution Viscosity ◽  
Operational Variables ◽  
Reservoir Conditions ◽  
Sulfonated Polyacrylamide

Copolymers of acrylamide with the sodium salt of 2-acrylamido-2-methylpropane sulfonic acid—known as sulfonated polyacrylamide polymers—had been shown to produce very promising results in the enhancement of oil recovery, particularly in polymer flooding. The aim of this work is to develop an empirical model through the use of a design of experiments (DOE) approach for bulk viscosity of these copolymers as a function of polymer characteristics (i.e., sulfonation degree and molecular weight), oil reservoir conditions (i.e., temperature, formation brine salinity and hardness) and field operational variables (i.e., polymer concentration, shear rate and aging time). The data required for the non-linear regression analysis were generated from 120 planned experimental runs, which had used the Box-Behnken construct from the typical Response Surface Methodology (RSM) design. The data were collected during rheological experiments and the model that was constructed had been proven to be acceptable with the Adjusted R-Squared value of 0.9624. Apart from showing the polymer concentration as being the most important factor in the determination of polymer solution viscosity, the evaluation of the model terms as well as the Sobol sensitivity analysis had also shown a considerable interaction between the process parameters. As such, the proposed viscosity model can be suitably applied to the optimization of the polymer solution properties for the polymer flooding process and the prediction of the rheological data required for polymer flood simulators.

Experimental Investigation of the Heterogeneity Limit for the Application of Polymer Flooding in Reservoirs

2020 ◽  
Vol 143 (2) ◽  
Author(s):  
Mingchen Ding ◽  
Yugui Han ◽  
Yefei Wang ◽  
Yigang Liu ◽  
Dexin Liu ◽  
...  
Keyword(s):  
Experimental Investigation ◽  
Oil Recovery ◽  
Polymer Concentration ◽  
Experimental Information ◽  
Polymer Flooding ◽  
Polymer Injection ◽  
Low Concentration ◽  
Visual Models ◽  
Combined Use

Abstract It is generally accepted that polymer flooding gets less effective as the heterogeneity of a reservoir increases. However, very little experimental information or evidence has been collated to indicate which levels of heterogeneity correspond to reservoirs that can (and cannot) be efficiently developed using polymer flooding. Therefore, to experimentally determine a heterogeneity limit for the application of polymer flooding to reservoirs, a series of flow tests and oil displacements were conducted using parallel sand packs and visual models possessing different heterogeneities. For low-concentration polymer flooding (1.0 g/l), the limit determined corresponds to permeability contrasts (PCs) of 10.8 and 10.2, according to the parallel and visual tests, respectively. A significant increase in oil recovery can be achieved by polymer injection within these limits. Increasing the polymer concentration to 2.0 g/l increased these limiting PCs to 52.8 and 50.0, respectively. Additionally, within or beyond these limits, the combined use of polymer and gel may be the best.

scholarly journals THE EFFECT OF ELECTROLYTES ON POLYMER VISCOSITY FOR EFFECTIVENESS OF POLYMER INJECTION

2020 ◽  
Vol 42 (2) ◽  
pp. 59-63
Author(s):  
Yani Faozani Alli
Keyword(s):  
Sodium Chloride ◽  
Calcium Chloride ◽  
Oil Recovery ◽  
Polymer Chains ◽  
Formation Water ◽  
Sweep Efficiency ◽  
Polymer Injection ◽  
Lower Viscosity ◽  
Tertiary Oil Recovery ◽  
Hydrolyzed Polyacrylamide

The use of polymer for tertiary oil recovery has been known to be important as viscosity modifier to increase sweep efficiency of water flood and chemical flood. The most common polymer used for chemical flood is hydrolyzed polyacrylamide (HPAM) that owing large number of charges along the polymer chains. However, formation water as dissolution water contain high electrolytes that has a great effect on polymer viscosity, as well as responsible to generate the efficiency of polymer flooding. In this study, the effect of electrolytes from saline and cation divalent to the viscosity of polymer was investigated. Three studied polymers were dissolved in various concentration of saline and cation divalent by analyzing the compatibility, viscosity, and the filtration ratio of polymers. The results showed that the presence of electrolytes in every concentration of water did not impact the compatibility and filtration ratio of polymers. Whereas, the addition of sodium chloride as saline ionic and calcium chloride as cationic divalent were both reducing the viscosity of polymers. The lower viscosity of polymer related to the ability of polymer to expand the hydrodynamic which limited by the neutralization of internal repulsion of the electrolytes.

Laboratory Investigations of Factors Influencing Polymer Flood Performance

1975 ◽  
Vol 15 (04) ◽  
pp. 338-346 ◽  
Author(s):  
M.T. Szabo
Keyword(s):  
Oil Recovery ◽  
Polymer Solutions ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Mobility Control ◽  
Sweep Efficiency ◽  
Experimental Conditions ◽  
Polymer Injection ◽  
Polymer Flood

Abstract Numerous polymer floods were performed in unconsolidated sand packs using a C14-tagged, cross-linked, partially hydrolyzed ployacrylamide, and the data are compared with brine-flood performance in the same sands. performance in the same sands. The amount of "polymer oil" was linearly proportional to polymer concentration up to a proportional to polymer concentration up to a limiting value. The upper limit of polymer concentration yielding additional polymer oil was considerably higher for a high-permeability sand than for a low-permeability sand. It is shown that a minimum polymer concentration exists, below which no appreciable polymer oil can be produced in high-permeability sands. The effect of polymer slug size on oil recovery is shown for various polymer concentrations, and the results from these tests are used to determine the optimum slug size and polymer concentration for different sands. The effect of salinity was studied by using brine and tap water during polymer floods under similar conditions. Decreased salinity resulted in improved oil recovery at low, polymer concentrations, but it had little effect at higher polymer concentrations. Polymer injection that was started at an advanced stage of brine flood also improved the oil recovery in single-layered sand packs. Experimental data are presented showing the effect of polymer concentration and salinity on polymer-flood performance in stratified reservoir polymer-flood performance in stratified reservoir models. Polymer concentrations in the produced water were measured by analyzing the radioactivity of effluent samples, and the amounts of retained polymer in the stratified models are given for each polymer in the stratified models are given for each experiment. Introduction In the early 1960's, a new technique using dilute polymer solutions to increase oil recovery was polymer solutions to increase oil recovery was introduced in secondary oil-recovery operations. Since then, this new technique has attained wide-spread commercial application. The success and the complexity of this new technology has induced many authors to investigate many aspects of this flooding technique. Laboratory and field studies, along with numerical simulation of polymer flooding, clearly demonstrated that polymer additives increase oil recovery. polymer additives increase oil recovery. Some of the laboratory results have shown that applying polymers in waterflooding reduces the residual oil saturation through an improvement in microscopic sweep efficiency. Other laboratory studies have shown that applying polymer solutions improves the sweep efficiency in polymer solutions improves the sweep efficiency in heterogeneous systems. Numerical simulation of polymer flooding, and a summary of 56 field applications, clearly showed that polymer injection initiated at an early stage of waterflooding is more efficient than when initiated at an advanced stage. Although much useful information has been presented, the experimental conditions were so presented, the experimental conditions were so variable that difficulties arose in correlating the numerical data. So, despite this good data, a systematic laboratory study of the factors influencing the performance of polymer flooding was still lacking in the literature. The purpose of this study was to investigate the effect of polymer concentration, polymer slug size, salinity in the polymer bank, initial water saturation, and permeability on the performance of polymer floods. The role of oil viscosity did not constitute a subject of this investigation. However, some of the data indicated that the applied polymer resulted in added recovery when displacing more viscous oil. The linear polymer-flood tests were coupled with tests in stratified systems, consisting of the same sand materials used in linear flood tests. Thus, it was possible to differentiate between the role of polymer in mobility control behind the flood front in each layer and its role in mobility control in the entire stratified system through improvement in vertical sweep efficiency. A radioactive, C14-tagged hydrolyzed polyacrylamide was used in all oil-recovery tests. polyacrylamide was used in all oil-recovery tests. SPEJ P. 338

scholarly journals Optimal Control of Polymer Flooding Based on Maximum Principle

2012 ◽  
Vol 2012 ◽  
pp. 1-20 ◽  
Author(s):  
Yang Lei ◽  
Shurong Li ◽  
Xiaodong Zhang ◽  
Qiang Zhang ◽  
Lanlei Guo
Keyword(s):  
Optimal Control ◽  
Maximum Principle ◽  
Oil Recovery ◽  
Polymer Concentration ◽  
Inequality Constraint ◽  
Polymer Flooding ◽  
Polymer Injection ◽  
Flow Equations ◽  
Optimal Injection ◽  
Injection Strategies

Polymer flooding is one of the most important technologies for enhanced oil recovery (EOR). In this paper, an optimal control model of distributed parameter systems (DPSs) for polymer injection strategies is established, which involves the performance index as maximum of the profit, the governing equations as the fluid flow equations of polymer flooding, and the inequality constraint as the polymer concentration limitation. To cope with the optimal control problem (OCP) of this DPS, the necessary conditions for optimality are obtained through application of the calculus of variations and Pontryagin’s weak maximum principle. A gradient method is proposed for the computation of optimal injection strategies. The numerical results of an example illustrate the effectiveness of the proposed method.

A Microvisual Study of the Displacement of Viscous Oil by Polymer Solutions

2011 ◽  
Vol 14 (03) ◽  
pp. 269-280 ◽  
Author(s):  
M.. Buchgraber ◽  
T.. Clemens ◽  
L. M. Castanier ◽  
A. R. Kovscek
Keyword(s):  
Polymer Solution ◽  
Oil Recovery ◽  
Polymer Solutions ◽  
Pore Space ◽  
Polymer Concentration ◽  
Water Injection ◽  
Sweep Efficiency ◽  
Improved Oil Recovery ◽  
Associative Polymers ◽  
Displacement Front

Summary Of the various enhanced-oil-recovery (EOR) polymer formulations, newly developed associative polymers show special promise. We investigate pore and pore-network scales because polymer solutions ultimately flow through the pore space of rock to displace oil. We conduct and monitor optically water/oil and polymer-solution/oil displacements in a 2D etched-silicon micromodel. The micromodel has the geometrical and topological characteristics of sandstone. Conventional hydrolyzed-polyacrylamide solutions and newly developed associative-polymer solutions with concentrations ranging from 500 to 2,500 ppm were tested. The crude oil had a viscosity of 450 cp at test conditions. Our results provide new insight regarding the ability of polymer to stabilize multiphase flow. At zero and low polymer concentrations, relatively long and wide fingers of injectant developed, leading to early water break-through and low recoveries. At increased polymer concentration, a much greater number of relatively fine fingers formed. The width-to-length ratio of these fingers was quite small, and the absolute length of fingers decreased. At a larger scale of observation, the displacement front appears to be stabilized; hence, recovery efficiency improved remarkably. Above a concentration of 1,500 ppm, plugging of the micromodel by polymer and lower oil recovery was observed for both polymer types. For tertiary polymer injection that begins at breakthrough of water, the severe fingers resulting from water injection are modified significantly. Fingers become wider and grow in the direction normal to flow as polymer solution replaces water. Apparently, improved sweep efficiency of viscous oils is possible (at this scale of investigation) even after waterflooding. The associative- and conventional-polymer solutions improved oil recovery by approximately the same amount. The associative polymers, however, showed more-stable displacement fronts in comparison to conventional-polymer solutions.

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