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 Properties of Biodegradable Polymer from Terrestrial Mushroom for Potential Enhanced Oil Recovery

2020 ◽  
Vol 20 (6) ◽  
pp. 1382
Author(s):  
Tengku Amran Tengku Mohd ◽  
Shareena Fairuz Abdul Manaf ◽  
Munawirah Abd Naim ◽  
Muhammad Shafiq Mat Shayuti ◽  
Mohd Zaidi Jaafar
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Biodegradable Polymer ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Mobility Control ◽  
Sweep Efficiency ◽  
Reservoir Conditions ◽  
Infrared Spectrometer ◽  
Original Oil In Place

Polymer flooding could enhance the oil recovery by increasing the viscosity of water, thus, improving the mobility control and sweep efficiency. It is essential to explore natural sources of polymer, which is biologically degradable and negligible to environmental risks. This research aims to produce a biodegradable polymer from terrestrial mushroom, analyze the properties of the polymer and investigate the oil recovery from polymer flooding. Polysaccharide biopolymer was extracted from mushroom and characterized using Fourier Transform Infrared Spectrometer (FTIR), while the polymer viscosity was investigated using an automated microviscometer. The oil recovery tests were conducted at room temperature using a sand pack model. It was found that polymer viscosity increases with increasing polymer concentration and decreases when increase in temperature, salinity, and concentration of divalent ions. The oil recovery tests showed that a higher polymer concentration of 3000 ppm had recovered more oil with an incremental recovery of 25.8% after waterflooding, while a polymer concentration of 1500 pm obtained incremental 22.2% recovery of original oil in place (OOIP). The oil recovery from waterflooding was approximately 25.4 and 24.2% of the OOIP, respectively. Therefore, an environmentally friendly biopolymer was successfully extracted, which is potential for enhanced oil recovery (EOR) application, but it will lose its viscosity performance at certain reservoir conditions.

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.

Key Aspects of Project Design for Polymer Flooding at the Daqing Oilfield

2008 ◽  
Vol 11 (06) ◽  
pp. 1117-1124 ◽  
Author(s):  
Dongmei Wang ◽  
Randall S. Seright ◽  
Zhenbo Shao ◽  
Jinmei Wang
Keyword(s):  
Molecular Weight ◽  
Polymer Concentration ◽  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
Polymer Injection ◽  
Polymer Flood ◽  
Daqing Oil Field ◽  
Water Cut ◽  
Injection Rates

Summary This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding in the Daqing oil field. Special emphasis is placed on some new design factors that were found to be important on the basis of extensive experience with polymer flooding. These factors include (1) recognizing when profile modification is needed before polymer injection and when zone isolation is of value during polymer injection, (2) establishing the optimum polymer formulations and injection rates, and (3) time-dependent variation of the molecular weight of the polymer used in the injected slugs. For some Daqing wells, oil recovery can be enhanced by 2 to 4% of original oil in place (OOIP) with profile modification before polymer injection. For some Daqing wells with significant permeability differential between layers and no crossflow, injecting polymer solutions separately into different layers improved flow profiles, reservoir sweep efficiency, and injection rates, and it reduced the water cut in production wells. Experience over time revealed that larger polymer-bank sizes are preferred. Bank sizes grew from 240-380 mg/L·PV during the initial pilots to 640 to 700 mg/L·PV in the most recent large-scale industrial sites [pore volume (PV)]. Economics and injectivity behavior can favor changing the polymer molecular weight and polymer concentration during the course of injecting the polymer slug. Polymers with molecular weights from 12 to 35 million Daltons were designed and supplied to meet the requirements for different reservoir geological conditions. The optimum polymer-injection volume varied around 0.7 PV, depending on the water cut in the different flooding units. The average polymer concentration was designed approximately 1000 mg/L, but for an individual injection station, it could be 2000 mg/L or more. At Daqing, the injection rates should be less than 0.14-0.20 PV/year, depending on well spacing. Introduction Many elements have long been recognized as important during the design of a polymer flood (Li and Niu 2002; Jewett and Schurz 1970; Sorbie 1991; Vela et al. 1976; Taber et al. 1997; Maitin 1992; Koning et al. 1988; Wang et al. 1995; Wang and Qian 2002; Wang et al. 2008). This paper spells out some of those elements, using examples from the Daqing oil field. The Daqing oil field is located in northeast China and is a large river-delta/lacustrine-facies, multilayer, heterogeneous sandstone in an inland basin. The reservoir is buried at a depth of approximately 1000 m, with a temperature of 45°C. The main formation under polymer flood (i.e., the Saertu formation) has a net thickness ranging from from 2.3 to 11.6 m with an average of 6.1 m. The average air permeability is 1.1 µm2, and the Dykstra-Parsons permeability coefficient averages 0.7. Oil viscosity at reservoir temperature averages approximately 9 mPa·s, and the total salinity of the formation water varies from 3000 to 7000 mg/L. The field was discovered in 1959, and a waterflood was initiated in 1960. The world's largest polymer flood was implemented at Daqing, beginning in December 1995. By 2007, 22.3% of total production from the Daqing oil field was attributed to polymer flooding. Polymer flooding should boost the ultimate recovery for the field to more than 50% OOIP--10 to 12% OOIP more than from waterflooding. At the end of 2007, oil production from polymer flooding at the Daqing oil field was more than 11.6 million m3 (73 million bbl) per year (sustained for 6 years). The polymers used at Daqing are high-molecular-weight partially hydrolyzed polyacrylamides (HPAMs). During design of a polymer flood, critical reservoir factors that traditionally receive consideration are the reservoir lithology, stratigraphy, important heterogeneities (such as fractures), distribution of remaining oil, well pattern, and well distance. Critical polymer properties include cost-effectiveness (e.g., cost per unit of viscosity), resistance to degradation (mechanical or shear, oxidative, thermal, microbial), tolerance of reservoir salinity and hardness, retention by rock, inaccessible pore volume, permeability dependence of performance, rheology, and compatibility with other chemicals that might be used. Issues long recognized as important for polymer-bank design include bank size (volume), polymer concentration and salinity (affecting bank viscosity and mobility), and whether (and how) to grade polymer concentrations in the chase water. This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding in the Daqing oil field.

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 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.

Design of an Economical Polymer Flood Pilot Addressing Field Development Uncertainties in the Sabriyah Upper Burgan Reservoir of North Kuwait

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Dawood Kamal ◽  
Najres Al-Mahmeed ◽  
Anfal Al Kharji ◽  
Hadeel Baroon ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Polymer Flooding ◽  
Mobility Control ◽  
Field Development ◽  
Reservoir Volume ◽  
Polymer Flood ◽  
Incremental Oil Recovery ◽  
Commercial Size

Abstract The Sabriyah Upper Burgan is a major oil reservoir in North Kuwait with high oil saturation and is currently considered for mobility control via polymer flooding. Although there is high confidence in the selected technology, there are technological and geologic challenges that must be understood to transition towards phased commercial field development. Engineering and geologic screening suggested that chemical flood technologies were superior to either miscible gas or waterflood technologies. Of the chemical flood technologies, mobility control flooding was considered the best choice due to available water ion composition and total dissolved solids (TDS). Evaluation of operational and economic considerations were instrumental in recommending mobility control polymer flooding for pilot testing. Laboratory selected acceptable polymer for use with coreflood incremental oil recovery being up to 9% OOIP. Numerical simulation recommended two commercial size pilots, a 3-pattern and a 5-pattern of irregular five spots, with forecast incremental oil recovery factors of 5.6% OOIP over waterflood. Geologic uncertainty is the greatest challenge in the oil and gas industry, which is exacerbated with any EOR project. Screening of the Upper Burgan reservoirs indicates that UB4 channel sands are the best candidates for EOR technologies. Reservoir quality is excellent and there is sufficient reservoir volume in the northwest quadrant of the field to justify not only a pilot but also future expansion. There is a limited edge water drive of unknown strength that will need to be assessed. The channel facies sandstones have porosities of +25%, permeabilities in the Darcy range, and initial oil saturations of +90%. Pore volume (PV) of the two recommended pilot varies from 29 to 45 million barrels. A total of 0.7 PV of polymer is expected to be injected in 5.6 and 7.9 years for the 3-pattern pilot and the 5-pattern pilot, respectively, with a water drive flush to follow for an additional 5 to 7 years. Incremental cost per incremental barrel of oil of a mobility control polymer flood which includes OPEX and CAPEX costs is $20 (USD). This paper evaluates the (commercial size) pilot design and addresses field development uncertainties.

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.

scholarly journals Effect of Polymer Adsorption on Permeability Reduction in Enhanced Oil Recovery

2014 ◽  
Vol 2014 ◽  
pp. 1-9 ◽  
Author(s):  
Saurabh Mishra ◽  
Achinta Bera ◽  
Ajay Mandal
Keyword(s):  
Oil Recovery ◽  
Polymer Concentration ◽  
Polymer Adsorption ◽  
Mobility Control ◽  
Special Focus ◽  
Permeability Reduction ◽  
Solution Ph ◽  
Residual Resistance ◽  
Polymer Injection ◽  
Hydrolyzed Polyacrylamide

In order to reduce the permeability to water or brine, there is a possibility of polymer injection into the reservoir. In the present work, special focus has been paid in polymer [partially hydrolyzed polyacrylamide (PHPA)] injection as a part of chemical method. Tests were conducted in the laboratory at the ambient temperature to examine the reduction in permeability to water or brine in the well-prepared sand packed after the polymer injection. The experiments were performed to study the effect of polymer adsorption on permeability reduction by analyzing residual resistance factor values with different concentrations of polymer solutions. The rheological behavior of the polymer has also been examined. The experimental results also indicate that the adsorption behavior of polymer is strongly affected by salinity, solution pH, and polymer concentration. To investigate the effect of polymer adsorption and mobility control on additional oil recovery, polymer flooding experiments were conducted with different polymer concentrations. It has been obtained that with the increase in polymer concentrations, oil recovery increases.

scholarly journals Investigation of an Improved Polymer Flooding Scheme by Compositionally-Tuned Slugs

Processes ◽  
2020 ◽  
Vol 8 (2) ◽  
pp. 197 ◽  
Author(s):  
Ryan Santoso ◽  
Victor Torrealba ◽  
Hussein Hoteit
Keyword(s):  
Oil Recovery ◽  
Polymer Flooding ◽  
Solution Viscosity ◽  
Design Parameters ◽  
High Concentration ◽  
Sweep Efficiency ◽  
Polymer Injection ◽  
Low Salinity ◽  
Injection Scheme ◽  
Vertical Heterogeneity

Polymer flooding is an effective enhanced oil recovery technology used to reduce the mobility ratio and improve sweep efficiency. A new polymer injection scheme is investigated that relies on the cyclical injection of low-salinity, low-concentration polymer slugs chased by high-salinity, high-concentration polymer slugs. The effectiveness of the process is a function of several reservoir and design parameters related to polymer type, concentration, salinity, and reservoir heterogeneity. We use reservoir simulations and design-of-experiments (DoE) to investigate the effectiveness of the proposed polymer injection scheme. We show how key objective functions, such as recovery factor and injectivity, are impacted by the reservoir and design parameters. In this study, simulations showed that the new slug-based process was always superior to the reference polymer injection scheme using the traditional continuous injection scheme. Our results show that the process is most effective when the polymer weight is high, corresponding to large inaccessible pore-volumes, which enhances polymer acceleration. High vertical heterogeneity typically reduces the process performance because of increased mixing in the reservoir. The significance of this process is that it allows for increased polymer solution viscosity in the reservoir without increasing the total mass of polymer, and without impairing polymer injectivity at the well.

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