Prediction of Polymer Flood Performance

1971 ◽  
Vol 11 (01) ◽  
pp. 72-84 ◽  
Author(s):  
J.T. Patton ◽  
K.H. Coats ◽  
G.T. Colegrove
Keyword(s):  
Numerical Model ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Single Layer ◽  
Polymer Flooding ◽  
Solution Viscosity ◽  
Flood Water ◽  
Polymer Flood ◽  
Member Aime ◽  
Quick Estimate

Patton, J.T., Member AIME, Patton, J.T., Member AIME, Computer/Bioengineering Institute, Inc., Houston, Tex. Coats, K.H., Member AIME, International Computer Applications Ltd., Houston, Tex. Colegrove, G.T., Kelco Co., Houston, Tex. Abstract This experimental and numerical study was performed to estimate the incremental oil recovery performed to estimate the incremental oil recovery by pattern polymer flooding in a California viscous-oil reservoir. Results indicate that adding 270-ppm Kelzan to the normal flood water will boost oil production by 42 percent (at 1 PV injected) and production by 42 percent (at 1 PV injected) and will reduce water handling costs sharply. This corresponds to $8.35 incremental oil/$1.00 polymer injected, taking into account the 30 percent pore volume bank of polymer solution. The 28.6 percent additional oil recovery predicted at 0.5 PV injected yields a return of $4.60 incremental oil/$1.00 polymer injected. polymer injected. The field predictions are based onlaboratory measurements of polymer solution viscosity, adsorption and dispersion upon displacement by normal water in a sand representative of the reservoir,linear laboratory oil displacement experiments using brine and polymer solution, anda numerical model developed to simulate linear or five-spot polymer floods in single-layer or stratified reservoirs. The paper presents an analytical solution to the linear polymer flood problem, which provides a check on accuracy of the numerical model and a quick estimate of additional oil recovery by line-drive polymer floods. The numerical model developed indicates that additional oil recovery by polymer flooding is sensitive to polymer bank size polymer flooding is sensitive to polymer bank size and adsorption level and is insensitive to the extent of dispersion active at the trailing edge of the polymer slug. polymer slug Introduction The benefits of improving the mobility ratio, lambda o/lambda w, on waterflood performance is well documented and research on how best to effect this improvement has been considerable. Both producers and chemical manufacturers, spurred on producers and chemical manufacturers, spurred on by the vast reserves of oil which will be otherwise abandoned, have sought to resolve the problem. Currently, two types of additives are being marketed and field tested with promising results. Both additives increase oil recovery by lowering the mobility of the flood water, lambda w. However, they effect this lowering by distinctly different mechanisms. Mobility of the flood water is given by: lambdaw = kw/ w . Hence, one may elect to either increase viscosity, mu w, or decrease effective permeability, kw. Viscosity can be increased by adding small amounts of a water-soluble polymer. To be effective at the flood front this additive should exhibit minimum adsorption on the pore surfaces. Polymers showing minimal adsorption are generally a combination nonionic-anionic type. The negative charge repels the clay platelets to reduce adsorption and the nonionic portion provides the brine tolerance required for reservoir applications. A polymer of this type, Kelzan M, was chosen for the study. The alternate method of lowering mobility is equally well known. It consists of adding to the flood water a polymer designed to adsorb on the pore surfaces, thereby physically reducing the available flow area. This study was performed to estimate the additional oil recovery by pattern polymer flooding using Kelzan in a California viscous-oil reservoir. Laboratory experiments were performed to estimate polymer solution viscosity, adsorption and polymer solution viscosity, adsorption and dispersion upon displacement by normal injection water. Waterflood and polymer flood oil recovery curves were obtained for a laboratory core packed with sand representative of the reservoir. A numerical model was developed to simulate polymer floods in linear or five-spot patterns in single-layer or stratified reservoirs. An analytical solution to the linear polymer flood problem was developed to provide a quick estimate of incremental oil provide a quick estimate of incremental oil obtainable by polymer flooding and to provide a check on the accuracy of the numerical model. SPEJ P. 72

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.

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.

scholarly journals Effect of Polymer Degradation on Polymer Flooding in Homogeneous Reservoirs

2018 ◽  
Vol 187 ◽  
pp. 01006
Author(s):  
Xiankang Xin ◽  
Gaoming Yu ◽  
Ruicheng Ma ◽  
Keliu Wu ◽  
Zhangxin Chen
Keyword(s):  
Polymer Solution ◽  
Oil Recovery ◽  
Polymer Concentration ◽  
Polymer Degradation ◽  
Polymer Flooding ◽  
Solution Viscosity ◽  
Physical Experiments ◽  
Simulation Results ◽  
The Difference ◽  
The Relationship

In this paper, physical and numerical simulations were applied to investigate the polymer degradation performance and its effect on polymer enhanced oil recovery (EOR) efficiency in homogeneous reservoirs. Physical experiments were conducted to determine basic physicochemical properties of the polymer, including viscosity, rheology, and degradation. A new mathematical model was proposed, and an in-house simulator was designed to further explore polymer degradation. The results of the physical experiments illustrated that polymer could increase polymer solution viscosity significantly, and the relationship between polymer solution viscosity and polymer concentration exhibited a clear power law relationship. However, the viscosity of a polymer solution with the same polymer concentration decreased with an increase in the shear rate, showing shear thinning performance. Moreover, the viscosity decreased with an increase in time, which was caused by polymer degradation. The validation of the designed simulator was improved when compared to the simulation results using ECLIPSE V2013.1 software. The difference between 0 and 0.1 day-1 in the polymer degradation rate showed a decrease of 6% in oil recovery after 2,000 days, according to simulation results, which demonstrated that polymer degradation had an adverse effect on polymer flooding efficiency.

scholarly journals Experimental investigation of the displacement flow mechanism and oil recovery in primary polymer flood operations

2021 ◽  
Vol 3 (5) ◽  
Author(s):  
Ruissein Mahon ◽  
Gbenga Oluyemi ◽  
Babs Oyeneyin ◽  
Yakubu Balogun
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Mobility Control ◽  
List Type ◽  
Motor Oil ◽  
Flow Mechanism ◽  
Fractional Flow ◽  
Recovery Method ◽  
Polymer Flood

Abstract Polymer flooding is a mature chemical enhanced oil recovery method employed in oilfields at pilot testing and field scales. Although results from these applications empirically demonstrate the higher displacement efficiency of polymer flooding over waterflooding operations, the fact remains that not all the oil will be recovered. Thus, continued research attention is needed to further understand the displacement flow mechanism of the immiscible process and the rock–fluid interaction propagated by the multiphase flow during polymer flooding operations. In this study, displacement sequence experiments were conducted to investigate the viscosifying effect of polymer solutions on oil recovery in sandpack systems. The history matching technique was employed to estimate relative permeability, fractional flow and saturation profile through the implementation of a Corey-type function. Experimental results showed that in the case of the motor oil being the displaced fluid, the XG 2500 ppm polymer achieved a 47.0% increase in oil recovery compared with the waterflood case, while the XG 1000 ppm polymer achieved a 38.6% increase in oil recovery compared with the waterflood case. Testing with the motor oil being the displaced fluid, the viscosity ratio was 136 for the waterflood case, 18 for the polymer flood case with XG 1000 ppm polymer and 9 for the polymer flood case with XG 2500 ppm polymer. Findings also revealed that for the waterflood cases, the porous media exhibited oil-wet characteristics, while the polymer flood cases demonstrated water-wet characteristics. This paper provides theoretical support for the application of polymer to improve oil recovery by providing insights into the mechanism behind oil displacement. Graphic abstract Highlights The difference in shape of relative permeability curves are indicative of the effect of mobility control of each polymer concentration. The water-oil systems exhibited oil-wet characteristics, while the polymer-oil systems demonstrated water-wet characteristics. A large contrast in displacing and displaced fluid viscosities led to viscous fingering and early water breakthrough.

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.

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.

Polymer in-Situ Rheology in Carbonate Reservoirs

2021 ◽  
Author(s):  
Tormod Skauge ◽  
Kenneth Sorbie ◽  
Ali Al-Sumaiti ◽  
Shehadeh Masalmeh ◽  
Arne Skauge
Keyword(s):  
Polymer Solution ◽  
Carbonate Rock ◽  
High Salinity ◽  
Polymer Flooding ◽  
Resistance Factor ◽  
Carbonate Reservoirs ◽  
Permeability Reduction ◽  
Polymer Flood ◽  
Core Flood

Abstract A large, untapped EOR potential may be extracted by extending polymer flooding to carbonate reservoirs. However, several challenges are encountered in carbonates due to generally more heterogeneous rock and lower permeability. In addition, high salinity may lead to high polymer retention. Here we show how in-situ viscosity varies with permeability and heterogeneity in carbonate rock from analysis of core flood results and combined with review of data available in literature. In-situ rheology experiments were performed on both carbonate outcrop and reservoir cores with a range in permeabilities. The polymer used was a high ATBS content polyacrylamide (SAV10) which tolerates high temperature and high salinity. Some cores were aged with crude oil to generate non-water-wet, reservoir representative wettability conditions. These results are compared to a compilation of literature data on in-situ rheology for predominantly synthetic polymers in various carbonate rock. A systematic approach was utilized to derive correlations for resistance factor, permeability reduction and in-situ viscosity as a function of rock and polymer properties. Polymer flooding is applied to improve sweep efficiency that may occur due to reservoir heterogeneities (large permeability contrasts, anisotropy, thief zones) or adverse mobility ratio (high mobility contrast oil-brine). In flooding design, the viscosity of the polymer solution in the reservoir, the in-situ viscosity, is an essential parameter as this is tuned to correct the mobility difference and to improve sweep. The viscosity is estimated from rheometer/viscometer measurements or, better, measured in laboratory core flood experiments. However, upscaling core flood experiments to field is challenging. Core flood experiments measure differential pressure, which is the basis for the resistance factor, RF, that describes the increased resistance to flow for polymer relative to brine. However, the pressure is also influenced by several other factors such as the permeability reduction caused by adsorption and retention of polymer in the rock, the tortuosity of the rock and the viscosity of the flowing polymer solution. Deduction of in-situ viscosity is straight forward using Darcy's law but the capillary bundle model that is the basis for applying this law fails for non-Newtonian fluids. This is particularly evident in carbonate rock. Interpretation of in-situ rheology experiments can therefore be misleading if the wrong assumptions are made. Polymer flooding in carbonate reservoirs has a large potential for increased utilization of petroleum reserves at a reduced CO2 footprint. In this paper we apply learnings from an extensive core flood program for a polymer flood project in the UAE and combine this with reported literature data to generate a basis for interpretation of in-situ rheology experiments in carbonates. Most importantly, we suggest a methodology to screen experiments and select data to be used as basis for modelling polymer flooding. This improves polymer flood design, optimize the polymer consumption, and thereby improve project economy and energy efficiency.

scholarly journals Differences of microscopic seepage mechanisms of water flooding and polymer flooding and prediction models of final oil recovery for conglomerate reservoir

2019 ◽  
Vol 74 ◽  
pp. 13
Author(s):  
Fengqi Tan ◽  
Changfu Xu ◽  
Yuliang Zhang ◽  
Gang Luo ◽  
Yukun Chen ◽  
...  
Keyword(s):  
Pore Structure ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Particle Surface ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Oil Saturation ◽  
Oil Displacement Efficiency

The special sedimentary environments of conglomerate reservoir lead to pore structure characteristics of complex modal, and the reservoir seepage system is mainly in the “sparse reticular-non reticular” flow pattern. As a result, the study on microscopic seepage mechanism of water flooding and polymer flooding and their differences becomes the complex part and key to enhance oil recovery. In this paper, the actual core samples from conglomerate reservoir in Karamay oilfield are selected as research objects to explore microscopic seepage mechanisms of water flooding and polymer flooding for hydrophilic rock as well as lipophilic rock by applying the Computed Tomography (CT) scanning technology. After that, the final oil recovery models of conglomerate reservoir are established in two displacement methods based on the influence analysis of oil displacement efficiency. Experimental results show that the seepage mechanisms of water flooding and polymer flooding for hydrophilic rock are all mainly “crawling” displacement along the rock surface while the weak lipophilic rocks are all mainly “inrushing” displacement along pore central. Due to the different seepage mechanisms among the water flooding and the polymer flooding, the residual oil remains in hydrophilic rock after water flooding process is mainly distributed in fine throats and pore interchange. These residual oil are cut into small droplets under the influence of polymer solution with stronger shearing drag effect. Then, those small droplets pass well through narrow throats and move forward along with the polymer solution flow, which makes enhancing oil recovery to be possible. The residual oil in weak lipophilic rock after water flooding mainly distributed on the rock particle surface and formed oil film and fine pore-throat. The polymer solution with stronger shear stress makes these oil films to carry away from particle surface in two ways such as bridge connection and forming oil silk. Because of the essential attributes differences between polymer solution and injection water solution, the impact of Complex Modal Pore Structure (CMPS) on the polymer solution displacement and seepage is much smaller than on water flooding solution. Therefore, for the two types of conglomerate rocks with different wettability, the pore structure is the main controlling factor of water flooding efficiency, while reservoir properties oil saturation, and other factors have smaller influence on flooding efficiency although the polymer flooding efficiency has a good correlation with remaining oil saturation after water flooding. Based on the analysis on oil displacement efficiency factors, the parameters of water flooding index and remaining oil saturation after water flooding are used to establish respectively calculation models of oil recovery in water flooding stage and polymer flooding stage for conglomerate reservoir. These models are able to calculate the oil recovery values of this area controlled by single well control, and further to determine the oil recovery of whole reservoir in different displacement stages by leveraging interpolation simulation methods, thereby providing more accurate geological parameters for the fine design of displacement oil program.

scholarly journals An evaluation of the enhanced oil recovery potential of the xanthan gum and aquagel in a heavy oil reservoir in Trinidad

2020 ◽  
Vol 10 (8) ◽  
pp. 3779-3789 ◽  
Author(s):  
Tina Coolman ◽  
David Alexander ◽  
Rean Maharaj ◽  
Mohammad Soroush
Keyword(s):  
Trinidad And Tobago ◽  
Adsorption Capacity ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Xanthan Gum ◽  
Polymer Solutions ◽  
Concentration Level ◽  
Polymer Flooding ◽  
Soil Types ◽  
Polymer Flood

Abstract The economy of Trinidad and Tobago which mainly relies on its energy sector is facing significant challenges due to declining crude oil production in a low commodity price environment. The need for enhanced oil recovery (EOR) methods to meet the current and future energy demands is urgent. Studies on the use of polymer flooding in Trinidad and Tobago are limited, especially in terms of necessary data concerning the characterization of the adsorption of polymer flooding chemicals such as xanthan gum and aquagel polymers on different soil types in Trinidad and the viscosity characteristics of the polymer flooding solutions which affect the key attributes of displacement and sweep efficiency that are needed to predict recovery efficiency and the potential use of these flooding agents in a particular well. Adsorption and viscosity experiments were conducted using xanthan gum and aquagel on three different soil types, namely sand, Valencia clay (high iron) and Longdenville clay (low iron). Xanthan gum exhibited the lowest adsorption capacity for Valencia clay but absorbed most on sand at concentrations above 1000 ppm and Longdenville clay below 1000 ppm. At concentrations below 250 ppm, all three soil-type absorbent materials exhibited similar adsorption capacities. Aquagel was more significantly absorbed on the three soil types compared to xanthan gum. The lowest adsorption capacity was observed for Valencia clay at concentration levels above 500 ppm; however, the clay had the highest adsorption capacity below this level. Sand had the highest adsorption capacity for aquagel at concentrations above 500 ppm while Longdenville clay was the lowest absorbent above 500 ppm. Generally, all three soil types had a similar adsorption capacity for xanthan gum at a concentration level of 250 ppm and for aquagel at a concentration level of 500 ppm. The results offered conclusive evidence demonstrating the importance that the pore structure characteristics of soil that may be present in oil wells on its adsorption characteristics and efficiency. Xanthan gum polymer concentration of 2000 ppm, 1000 ppm and 250 ppm showed viscosities of 125 cp, 63 cp and 42 cp, respectively. Aquagel polymer concentrations of 2000 ppm, 1000 ppm and 250 ppm showed viscosities of 63 cp, 42 cp and 21 cp, respectively. Aquagel polymer solutions were found to generally have lower viscosities than the xanthan gum polymer solutions at the same concentration. Adsorption and viscosity data for the xanthan gum and aquagel polymers were incorporated within CMG numerical simulation models to determine the technical feasibility of implementing a polymer flood in the selected EOR 44 located in the Oropouche field in the southwest peninsula of the island of Trinidad. Overall, aquagel polymer flood resulted in a higher oil recovery of 0.06 STB compared to the xanthan gum polymer flood, so the better EOR method would be aquagel polymer flood. Additionally, both cases of polymer flooding resulted in higher levels of oil recovery compared to CO2 injection and waterflooding and therefore polymer flooding will have greater impact on the EOR 44 well oil recovery.

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