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ABSTRACT 

Polymers, with their viscoelastic nature and complex molecular structure, significantly enhance oil recovery (EOR). 

This text elucidates the mechanisms underpinning their application in EOR, categorizing them into synthetic and 

natural (bio) polymers, each with distinct properties. A variety of EOR techniques employing polymers, like foam, 

alkali-polymer, surfactant-polymer, alkali-surfactant-polymer, and polymeric nanofluid flooding. Most polymers are 

pseudoplastic under shear, with biopolymers offering the benefits of salt resistance and thermal stability; however, 

plugging might result in the wellbore area, and they degrade. Despite its complexities, associative polyacrylamide 

shows promise, though hydrolyzed polyacrylamide remains the industry standard. Notably, alkali-surfactant-polymer 

flooding proves effective at various scales, and polymeric nanofluids hold potential for future EOR applications. 

KEYWORDS 

Polymers, petrochemical industries, crude oil extraction. 

INTRODUCTION

Following primary and secondary extraction, 

substantial oil often remains trapped in reservoirs 

(Gbadamosi,2018). EOR targets this residual oil 

(Agi,2022). EOR methods are primarily thermal or 

nonthermal. Thermal EOR, however, is impractical for 

deep, thin reservoirs or those with underlying aquifers 

  Research Article 

 

THE ROLE OF POLYMERS IN ADVANCING PETROCHEMICAL INDUSTRIES 

DURING CRUDE OIL EXTRACTION PROCESSES 
 

Submission Date: Aug 23, 2024, Accepted Date:  Aug 28, 2024,  

Published Date: Sep 02, 2024  

Crossref doi: https://doi.org/10.37547/ajbspi/Volume04Issue09-03 

 

 

Aymen Hasan Abdulrazzaq 
Senior Chief Chemist Health Safety and Environment Department, Oil Projects Company SCOP, Department of 

Applied Sciences, Biochemical Technology University of Technology, Baghdad, Iraq 

 

 

 

Journal Website: 

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com/index.php/ajbspi 

Copyright: Original 

content from this work 

may be used under the 

terms of the creative 

commons attributes 

4.0 licence. 

 

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due to excessive heat loss (Saboorian-Jooybari,2016). 

Moreover, its environmental impact, marked by 

substantial greenhouse gas emissions contributing to 

global warming, limits its use (Guo, K , 

2016)Consequently, nonthermal EOR has gained 

prominence for conventional or heavy oil extraction.. 

Chemical EOR, a cold ( nonthermal) technique, offers 

efficient and easily implemented oil recovery 

enhancement (Ngouangna,2020). Alkalis, surfactants, 

nanoparticles, and polymers are among the chemicals 

modifying reservoir Some of the fluid-fluid and rock-

fluid properties that can enhance oil recovery. These 

interactions enhance the displacement at the pore 

scale and increase overall sweep efficiency. Polymers, 

in particular, excel in both properties. Their 

effectiveness is evident in numerous field applications, 

including Daqing (China), Pelican Lake (Canada), and 

West Cat Canyon (USA) (Delamaide,2014). 

Polymers exhibit viscoelasticity, displaying 

pseudoplastic and shear-thickening behaviors under 

porous media stress. Their viscosity-enhancing 

properties create a favorable mobility ratio in the 

reservoir (Firozjaii,2020) reducing viscous fingering 

and recovering previously untouched oil for improved 

efficiency. The polymers' macromolecular structure 

enables oil film recovery from tight reservoir spaces 

through pulling and stripping (Sheng, 

2011).Furthermore, by swelling and reducing water 

permeability, polymers disproportionately reduce 

permeability, aiding in oil recovery( Wei,2014). 

Polymer-based EOR significantly reduces injected 

water volumes, especially beneficial in water-scarce 

onshore and desert regions. Additionally, polymer use 

lowers water cut in production wells, crucial for 

offshore operations requiring treated produced water. 

Given these advantages, A variety of polymers have 

been investigated for EOR, which can be broadly 

classified into two categories: natural polymers 

(biopolymers) and synthetic polymers. (Abidin,2012). 

Biopolymers, synthesized from naturally obtained 

plants, are eco-friendly. Composed of sugar monomers 

linked by O-glycosidic bonds, their characteristics 

depend on monomer properties, linkages, and 

chemical modifications ( Xia,2020) Known for super 

thickening and low cost (Rock ,2020) biopolymers 

benefit from abundant raw materials and inexpensive 

large-scale fermentation production. Their flexible 

macromolecular structure allows for modifications and 

diverse oil recovery applications.  

polymers based on Acrylamide are synthetic EOR 

agents known for their superior rheology and 

viscoelasticity. Containing carboxylate and amide 

groups, partially hydrolyzed polyacrylamide (HPAM) is 

the industry standard (Kamal,2015), PAM and HAPAM 

are also other types of synthetic alternatives). On the 

contrary synthetic polymers have susceptibility to 

salinity, hardness, low pH, high shear rates and high 

temperature. (Olajire,2014). 

Polymer EOR applications fall into two main 

categories: standalone polymer flooding and polymer-

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enhanced processes. The latter includes foam, alkali-

polymer, surfactant as well as polymeric nanofluid 

flooding that take advantage of exceptional 

characteristics exhibited by polymers for the purpose 

of making sure other components are stable. This text 

delves into recent polymer EOR advancements, 

covering polymer flooding mechanisms, biopolymer 

and synthetic polymer properties, critical parameter 

influences, and the evaluation of different polymer 

EOR methods. 

METHODS  

Methods of using polymers to improve oil extraction. 

Mobility Ratio 

The mobility ratio assesses the relative ease with which 

the injected fluid (water) moves compared to the oil it 

displaces. In standard water injection operations, this 

ratio (M) is calculated as follows: 

    (1) 

Where: 

• λw represents water mobility 

• λo denotes oil mobility 

• krw indicates water relative permeability 

• kro signifies oil relative permeability 

• μw is the viscosity of water 

• μo is the viscosity of oil 

 

Crucially, the mobility ratio (M) gauges the stability of 

oil displacement. In waterflooding, water seeks the 

easiest path, causing uneven displacement (viscous 

fingering, Figure 1a). This occurs due to a significant the 

difference in viscosity between water and oil (M > 1). 

Consequently, much oil remains trapped in the 

reservoir. Ideally, water mobility should be reduced 

relative to oil. A mobility ratio below 1 (Figure 1b) 

creates a stable displacement front, curbing or 

eliminating viscous fingering. This ensures more 

injected fluid displaces oil towards the production well. 

Incorporating water-soluble polymers into the injected 

water increases its viscosity. This reduction in water 

mobility helps to limit water flow and improves the 

efficiency of oil recovery. (Figure 2) (Gbadamosi,2019). 

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Figure 1.  Waterflooding process (M > 1.0); (b) polymer flooding process (M < 1.0)  

(Olajire, 2014). 

 

Figure 2. Effect of mobility ratio on sweep efficiency (Xia,2020) 

Disproportionate Permeability Reduction (DPR) 

DPR is different technique enhancing oil recovery 

through polymer flooding. Most oil reservoirs display 

heterogeneous structures with varying permeability 

across different layers. (Mishra,2014) 

 Waterflooding preferentially channels through high-

permeability zones, accelerating water breakthrough 

and trapping oil in lower-permeability regions, 

reducing overall recovery. Polymer flooding addresses 

this issue. In water-wet reservoirs, injected polymer 

adsorbs onto the rock, forming a swollen film that 

impedes water flow while allowing oil passage. 

Additionally, polymer chains interlock, further 

restricting water flow. This induced resistance diverts 

water towards previously unswept areas, improving oil 

recovery. (Al-Sharji,2001) 

 

 

 

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Figure 3. Structure of xanthan gum  

 

Viscoelasticity 

EOR polymers typically exhibit viscoelastic behavior. 

Injected polymer solutions encounter varying shear 

rates within the reservoir. Due to viscoelasticity, 

polymer macromolecules stretch and recoil during 

flow, enhancing sweep and displacement efficiency 

(Azad,2019). ( Wang ,2001)investigated the impact of 

viscoelastic polymer solutions on oil displacement, 

demonstrating reduced residual oil compared to 

waterflooding through the pulling effect. Stronger 

viscoelasticity correlated with improved oil sweep, 

including the formation of "oil threads" for enhanced 

oil flow. 

POLYMERS EMPLOYED FOR EOR 

A range of polymers has been evaluated for EOR in 

both laboratory experiments and field trials. Typically, 

EOR polymers are classified into two main categories: 

natural and synthetic. 

Biopolymers 

Natural polymers, often referred to as biopolymers, 

are derived from plants or biological sources. Examples 

include xanthan, guar, welan, scleroglucan, cellulose, 

schizophyllan, lignin, and polysaccharides from 

mushrooms. Gums, a particular category of 

polysaccharides, form viscous solutions when 

dissolved in water at low concentrations. 

Xanthan Gum 

It is, a non-toxic, biodegradable polymer, is made by 

bacterial fermentation of sugar. Xanthomonas 

campestris is usually employed in this process. Its 

chemical structure, depicted in Figure 3, comprises 

glucose, mannose, and glucuronic acid monomers, 

with acetate groups in the side chain. Xanthan's high 

molecular weight contributes to its thickening 

properties. The rigid structure of the polymer offers 

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resistance against salinity, shear forces, and divalent 

ions. 

Xanthan gum exhibits superior stability to HPAM in 

challenging reservoir environments. In solution, it 

undergoes an order-to-disorder conformational 

change. Ionic concentration causes the structure to 

transition from a disordered to an ordered state due to 

charge screening effects. Zhong et al. (2013) 

investigated xanthan viscosity under varying ionic 

strengths and concentrations. At lower concentrations 

(600 mg/L), inorganic cations decreased the viscosity 

of the polymer solution., with divalent ions (Ca2+) 

exerting a stronger effect than monovalent ions (Na+) 

(Xu, 2016). Conversely, at higher concentrations, 

viscosity increased with cation addition. A 5000 mg/L 

xanthan solution containing 200, 500, or 1000 mg/L of 

Ca²⁺ ions exhibited a 475% increase in viscosity. (Zhong, 

2013). Xanthan thermal stability is linked to solution 

salinity. Ordered structures (high ionic concentration) 

enhance stability, while disordered structures (low 

ionic concentration) promote instability (Kamal,2015). 

Xanthan gum exhibits non-Newtonian behavior, often 

described by the Ostwald and Herschel-Bulkley 

equations. At low shear rates, high viscosity results 

from hydrogen bonding and polymer entanglement, 

creating macromolecular clusters. Conversely, 

increasing shear rates lower viscosity, a shear-thinning 

property aiding field injection. This pseudoplasticity 

stems from polymer chain alignment, 

disentanglement, and aggregate dispersion within the 

fluid (Ghoumrassi-Barr, 2016). 

Cellulose 

Cellulose, the Earth's most abundant biopolymer, 

originates in plant cell walls and certain eukaryotes. its 

molecular formula is (C6H10O5)n, where n signifies the 

degree of polymerization. This biopolymer, linked by β-

(1,4) glycosidic bonds (Figure 4), exhibits properties 

shaped by its structural arrangement. Cellulose's 

network structure offers resistance to mechanical 

stress and high temperatures (Combariza, 2021), but 

also leads to uneven swelling and insolubility. To align 

with petroleum industry demands, cellulose polymers 

often undergo surface modification (Zhu, 2021). 

Hydroxyethylcellulose, carboxymethylcellulose, and 

nanocellulose exemplify common EOR applications. 

 

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Figure 4. (a) Cellulose, (b) carboxymethylcellulose, (c) hydroxyethylcellulose, and (d) 
nanocellulose 

Hydroxyethyl cellulose, a non-ionic cellulose derivative, 

is an environmentally benign polymer. it is produced by 

chemically modifying insoluble cellulose. Its rigid 

polymer chain provides resistance to salinity, 

temperature, and shear. Hydrolysis of acetal linkages 

at low pH compromises stability, though it remains 

stable at neutral and high pH. Oxidation and 

degradation present further challenges. However, 

hydrophobically modified hydroxyethylcellulose, 

which is produced by modifying the macromolecular 

chain, provides enhanced properties for EOR. 

Intermolecular interactions between hydrophobic 

segments and the polymer backbone enhance 

rheology (Bai, nd). Liu et al. (2017) modified 

hydroxyethyl cellulose with bromo dodecane, 

observing increased viscosity, elasticity, and tolerance 

to high salinity, elevated temperatures, shear forces, 

and acidic or alkaline conditions. 

Carboxymethylcellulose (CMC), a derivative of 

cellulose, is synthesized by treating insoluble cellulose 

with chloroacetic acid in an alkaline medium. (Figure 

4b). CMC structure varies according to the degree of 

hydroxyl group substitution on anhydroglucose 

linkages. The substitution pattern within (C6H10O5)n 

impacts CMC properties (Pu, 2018). Hydroxyl group 

replacement with alkali metals improves water 

solubility. CMC rheology and viscoelasticity depend on 

concentration. Above a critical concentration, elastic 

behavior predominates, while below this threshold, 

viscous properties prevail (Xia, 2020). 

Nanocellulose emerged from advancements in 

nanotechnology, focusing on materials with at least 

one dimension measuring between 1 and 100 

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nanometers. Its nanofibrillar structure, derived from 

cellulose, makes it an ideal candidate for various 

applications.    

Nanocellulose boasts high functionality due to its 

template-like structure, reduced density, extra-large 

surface area, and biodegradability. Li et al. (2015) 

classified it into three main categories: cellulose 

nanocrystals, cellulose nanofibrils, and bacterial 

nanocellulose. The abundance of surface hydroxyl 

groups enhances its solubility in polar solvents. To 

increase hydrophobicity and modify its colloidal and 

interfacial behavior, charged compounds can be 

adsorbed onto the nanocellulose surface.    

Guar Gum 

Guar gum is a hydrophilic biopolymer derived from the 

endosperms of Cyamopsis psoraloides and Cyamopsis 

tetragonolobus. It is composed of linear chains of (1-4)-

β-d-mannopyranosyl units with (1-6)-α-d-

galactopyranosyl branches (see Figure 5). Although it 

is soluble in polar solvents, it remains insoluble in 

organic solvents, showcasing its strong hydration 

properties. 

it exhibits shear-thinning behavior at increased shear 

rates (Adimule, 2022). Salinity enhances guar gum's 

viscosity, while divalent cations can induce 

precipitation at high concentrations. Temperature also 

influences its viscosity: low temperatures increase 

viscosity due to reduced solubility, while high 

temperatures decrease it. Despite its potential, guar 

gum's incomplete hydration poses a significant risk of 

plugging in reservoir formations. 

 

Figure 5. Molecular structure of guar gum  

Welan Gum 

It is a non-gelling, negatively charged polysaccharide 

synthesized via bacterial fermentation of sugar by 

Alcaligenes species. Its molecular structure is 

characterized by a repeating pentasaccharide unit 

(Figure 6), composed of: 

• β-1,3-linked D-glucopyranose 

• β-1,4-linked D-glucuronopyranose 

• β-1,4-linked D-glucopyranose 

• α-1,4-linked L-rhamnopyranose 

• A single monosaccharide side chain attached to 

the O-3 position of the 4-linked glucopyranose 

Additionally, acetyl and glyceryl groups are attached to 

the repeating units. Notably, 33% of the 

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monosaccharide side chains consist of α-L-

mannopyranose, and the remaining two-thirds are α-L-

rhamnopyranose (Xu, 2015). 

 

 

Figure 6. Molecular structure of welan gum  

Welan gum demonstrates greater viscosity compared 

to xanthan gum with the same molecular weight. in 

aqueous solutions due to its unique three-fold double-

helix chain configuration. However, the polymer's 

anionic charges make its viscosity and viscoelasticity 

susceptible to the presence of inorganic cations such 

as sodium (Na+) and calcium (Ca2+). These ions shield 

the polyelectrolyte, causing the polymer chain to 

contract and coil. While high temperatures lead to 

some chain degradation, welan gum's glyceryl groups 

contribute to maintaining the double-helix structure, 

preserving viscosity at elevated temperatures. Overall, 

The molecular structure of welan gum offers enhanced 

resistance to salt and temperature variations when 

compared to xanthan gum. 

Welan gum exhibits pseudoplastic behavior at reduced 

shear rates. This shear-thinning property arises from 

the alignment of macromolecular chains along the 

direction of flow.. At low shear, chains stretch and 

intertwine, forming flow-resistant aggregates, leading 

to high viscosity. Conversely, increasing shear rate 

disentangles and disperses these aggregates, reducing 

solution viscosity (Ji,2020). 

Schizophyllan 

it is a non-ionic biopolymer produced by fermenting 

the Shizophyllum fungus using glucose as a carbon 

source (Gunaji, 2020). Its molecular structure, as 

depicted in Figure 7, consists of a linear chain of β-(1,3)-

linked D-glucose residues with a single β-(1,6)-linked D-

glucose unit for every three main chain residues (Pu, 

2018). 

The outstanding physicochemical characteristics of 

schizophyllan solutions originate from its rigid triple-

helical structure and the intermolecular hydrogen 

bonding (Grisel, 1996). This distinctive configuration 

grants the polymer exceptional tolerance to high 

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salinity and temperature. Furthermore, schizophyllan 

displays shear-thinning properties when exposed to 

shear forces. 

 

Figure 7. Molecular structure of schizophyllan  

Synthetic Polymers 

A variety of synthetic polymers have been explored for 

enhancing oil recovery in laboratory settings. These 

polymers are primarily categorized into three main 

groups: 

 Polyacrylamide (PAM): This is the base polymer, 

known for its long molecular chains and water 

solubility. 

 Hydrolyzed Polyacrylamide (HPAM): Derived 

from PAM, HPAM has some amide groups 

replaced with carboxylate groups, improving its 

water solubility and viscosity. 

 Hydrophobically Associating Polyacrylamide 

(HAPAM): This polymer combines the properties 

of PAM and HPAM with additional hydrophobic 

groups, enhancing its ability to interact with oil 

and improve oil recovery. 

Polyacrylamide (PAM) 

it is a widely recognized thickening agent employed in 

EOR due to its substantial molecular weight (exceeding 

1 × 10^6 g/mol). In its original, unmodified structure, 

PAM is nonionic (Figure 8), which leads to considerable 

adsorption onto mineral surfaces within the reservoir. 

This adsorption greatly restricts its direct use in 

chemical EOR processes.    

However, given its inherent properties, PAM serves as 

a foundational polymer for subsequent modifications. 

The industry has explored various alterations to PAM 

to mitigate adsorption and enhance the desired 

physicochemical characteristics necessary for effective 

EOR applications. 

 

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Figure 8. Molecular structure of PAM  

 

HPAM 

Hydrolyzed Polyacrylamide (HPAM) is the preferred 

polymer for large-scale polymer flooding operations 

due to its robustness against the intense mechanical 

stresses prevalent in reservoir environments. 

Additionally, HPAM demonstrates resistance to 

bacterial degradation and offers economic viability. 

This polymer is produced either by the 

copolymerization of sodium acrylate and acrylamide or 

through the partial hydrolysis of polyacrylamide and 

polyacrylic acid, as illustrated in Figure 9. (Olajire, 

2014). 

When dissolved in water, the polymer chain stretches 

due to electrostatic repulsion along its backbone, 

leading to an increase in the viscosity of the solution. 

The viscous characteristics of HPAM are affected by 

various factors, including molecular weight, 

concentration, degree of hydrolysis, salinity, 

temperature, and shear rate. (Veerabhadrappa, 2013). 

 

Figure 9. Molecular structure of HPAM  

HPAM with lower molecular weight displays reduced 

viscosity compared to high molecular weight HPAM, 

which is characterized by high viscosity and elasticity. 

(Veerabhadrappa,2013). 

Increasing HPAM concentration leads to a higher 

solution viscosity. The ideal hydrolysis degree (DOH) of 

acrylamide lies within the range of 25-35%. A lower DOH 

produces insoluble polymers, whereas a higher DOH 

results in sensitivity to brine salinity and hardness, 

negatively affecting viscosity (Gbadamosi, 2018). 

Brines reduce HPAM's thickening ability through cation 

screening, diminishing electrostatic repulsion and 

hydrodynamic volume (Wever, 2011). HPAM solution 

viscosity is influenced by temperature, decreasing with 

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increasing temperature due to reduced intermolecular 

interactions caused by amplified polymer chain 

thermal motion (Chul, 2012). HPAM exhibits both 

shear-thinning and shear-thickening properties under 

shear stress conditions. 

HAPAM 

HAPAM was created to address the limitations of PAM 

and HPAM by incorporating comonomers into the 

acrylamide polymer backbone. These comonomers 

enhance the polymer's molecular weight, thereby 

improving its rheological properties and stability under 

high temperature and salinity conditions. A range of 

salt- and temperature-resistant comonomers has been 

utilized in the production of HAPAM. Consequently, 

HAPAM exhibits superior mobility control and 

enhances oil recovery during oil displacement. The 

improved oil recovery associated with HAPAM is linked 

to elastic turbulence generated by intermolecular 

interactions among hydrophobic comonomers within 

porous media. HAPAM's performance is defined by its 

critical aggregation concentration (CAC), which 

indicates the shift from low rheology due to 

intramolecular interactions to high rheology resulting 

from intermolecular interactions (Afolabi, 2013). 

Despite HAPAM's superior performance in numerous 

laboratory tests, its widespread field application 

remains limited. This constraint might be due to the 

reliance of synthesized HAPAM functionality on the 

specific type and characteristics of the comonomer 

used in its production process. 

Crucially, Choosing the appropriate comonomers 

necessitates careful evaluation, as their effectiveness 

is influenced by preparation techniques and essential 

reservoir conditions like salinity and temperature, 

which complicates the overall process. In conditions of 

elevated salinity and divalent ion concentrations, 

HAPAM displays varying rheological behavior that is 

affected by factors such as polymer concentration, the 

molecular structure of HAPAM, and the type of 

hydrophobe used. 

Sarsenbekuly et al. (2017) developed a new low-

molecular-weight HAPAM and examined its viscosity 

response to varying water salinity. The polymer's 

rheology displayed a non-linear pattern. Initially, 

viscosity decreased with increasing salinity up to 

20,000 mg/L NaCl, due to reduced repulsion and chain 

compression caused by electrolyte-induced hydration 

of ionic groups. Above this concentration, viscosity 

rose to 80,000 mg/L NaCl, resulting from increased 

hydrophobic association, decreased solubility, and 

promoted intermolecular aggregation, expanding the 

polymer's hydrodynamic volume. Quan et al. (2016) 

reported comparable properties for amphoteric 

HAPAM synthesized from  DOAC and sodium-4-

styrenesulfonate monomers.. 

To evaluate the impact of synthesizing procedure on 

HAPAM properties, Maia et al. (2005)  produced 

HAPAM through acrylamide and dihexylacrylamide 

micellar copolymerization, characterized using NMR 

and DLS. The polymer's rheological behavior in 

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response to varying salinity was investigated under 

different preparation conditions. At first, the 

introduction of 0.5 g/L of polymer powder into saline 

solutions (ranging from 0 to 100 g/L NaCl) resulted in a 

reduction in viscosity, attributed to cation screening of 

the charged polymer components, which caused 

intramolecular associations. Following this, the 

addition of salt powder to the polymer solution caused 

the viscosity to rise, reaching a maximum at 60 g/L NaCl 

before decreasing. Ultimately, when polymer solution 

was added to different saline solutions, the viscosity 

increased due to enhanced interactions between the 

polymer and salt.. 

Temperature impacts HAPAM rheology based on 

polymer concentration. Below the CAC, viscosity 

diminishes with increasing temperature, as observed 

by Sarsenbekuly et al. (2017) and Yang et al. (2019) with 

lower HAPAM concentrations or N-vinyl-2-pyrrolidone 

addition. Conversely, above the CAC, viscosity initially 

increases due to intermolecular hydrophobic 

aggregate formation, driven by an endothermic 

entropic process (Shi, 2013). Nevertheless, at higher 

temperatures, this structure disintegrates, reducing 

viscosity as molecular motion intensifies (Zhao, 2015). 

Quan et al. (2016) reported similar behavior with 

amphoteric HAPAM, attributing the initial viscosity 

increase to hydrophobic aggregation. 

POLYMER FLOODING 

Polymer-based enhanced oil recovery (EOR) has shown 

significant success in boosting recovery rates for 

medium, heavy, and extra-heavy oil reservoirs, 

resulting in extensive laboratory, pilot, and field-scale 

applications. However, most field implementations 

have focused on sandstone formations because of the 

complex characteristics of carbonate rocks, which 

include vugs, fractures, and various heterogeneities. 

The effectiveness of polymer flooding relies on a 

complicated interaction of reservoir rock and fluid 

properties, including lithology, location, depth, 

porosity, permeability, heterogeneity, oil viscosity, 

temperature, salinity, hardness, oil saturation, and the 

properties of the polymer itself (Standnes, 2014). 

BINARY COMBINATION OF POLYMERS AND OTHER 

ADDITIVES FOR EOR 

Polymer Foam Flooding 

Gas injection is an early enhanced oil recovery (EOR) 

method that involves pumping hydrocarbon or non-

hydrocarbon gases to displace residual oil (Rafati, 

2018). While gaseous at surface conditions, these 

substances become supercritical fluids under reservoir 

pressures and temperatures (Johns, 2013). Gas 

injection is categorized into two types: miscible 

flooding and immiscible flooding. Miscible flooding, 

conducted above the minimum miscibility pressure, 

utilizes mass transfer, swelling, reduced oil viscosity, 

and interfacial tension to recover oil. Conversely, 

immiscible flooding operates below this pressure, 

maintaining reservoir pressure. Nonetheless, gas 

flooding experiences issues with inadequate areal and 

vertical sweep efficiency, gravity override, gas 

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segregation, and channeling through high-

permeability areas (Adebayo, 2021). To address these 

challenges and enhance gas mobility, foamed-gas 

injection was created and tested in the field. 

The foam in missing porous media includes dispersed 

gas within a consistent liquid phase separated by thin 

films of liquids which are known as lamellae. (Majeed, 

2021). Foam forms when a liquid containing a foaming 

agent contacts gases like N2, CO2, or air with sufficient 

mechanical energy. Foam generation processes 

include leave behind, snap-off, and bubble division 

(Adebayo, 2021). In reservoirs, foam reduces gas 

relative permeability and increases apparent fluid 

viscosity, controlling gas mobility. This increased 

viscosity stems from bubble-induced drag on pore 

walls, while gas trapping decreases gas relative 

permeability. The foam diverts the subsequent fluid 

from the high- to the lower-permeability zones in 

heterogeneous reservoirs. Despite their potential, 

foams are inherently unstable due to drainage, 

coalescence, and coarsening. To improve foam 

stability for EOR, various surfactants, proteins, 

polymers, ionic liquids, and nanoparticles have been 

studied (Said, 2022). 

Polymers have been specifically studied for foam 

stabilization. Their viscoelastic nature enables effective 

foam stabilization at low concentrations, improving 

economic feasibility. Polymers increase foam viscosity 

and stability, reducing liquid drainage (Azdarpour, 

2015). Consequently, polymer-stabilized foams 

demonstrate superior mobility control during oil 

recovery. Polymers also serve as additives in 

surfactant- or nanoparticle-stabilized foams, 

preventing surfactant or nanoparticle desorption from 

lamellae interfaces, thus inhibiting foam coalescence 

and extending half-life (Figure 10). 

 

Figure 10. Schematics of polymer-stabilized nanoparticle foam 

Synthetic and biopolymers have shown exceptional 

foam stabilization capabilities. Wang et al. (2008) 

investigated HPAM's impact on alpha olefin sulfonate 

(AOS) foam stability, finding optimal foam volume and 

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stability at 0.1 wt%. HPAM enhanced surface tension 

and foam viscosity. Hernando et al. (2018) compared 

associative and PAM-stabilized foams, revealing 

amphiphilic polymers offered superior foam stability 

due to stronger surfactant interactions. These foams 

exhibited slower kinetics, higher pressure drop, and 

greater stability. Ahmed et al. (2017) contrasted a new 

associative polymer (Superpusher B 192) with HPAM, 

demonstrating superior foam strength and doubled 

apparent viscosity for the associative polymer. This 

improved rheology enhanced bulk solution properties 

and tolerance. In contrast, AOS-based foam showed 

rapid liquid drainage and decay. Associative polymer-

stabilized foam achieved 28% incremental oil recovery 

compared to 14% for polymer-free foam, highlighting 

the hydrophobic chain's contribution to foam 

performance (Hernando, 2016).    

Bashir et al. (2019) studied CO2 foam stability and 

viscosity in systems combining nanoparticles, 

polymers, and oil under harsh reservoir conditions. 

Fumed silica and rice husk ash nanoparticles, along 

with xanthan gum, were tested. Higher polymer 

molecular weight and smaller nanoparticles led to 

improved foam stability due to enhanced oil 

emulsification into tiny droplets that easily pass 

through foam lamellae without surfactant loss. Wei et 

al. (2020) explored the combined impact of xanthan 

gum and alkyl polyglycoside on oil-laden foam stability. 

Polysaccharides thickened liquid films, stabilizing 

foams through increased interfacial elasticity, denser 

adsorption layers creating pseudoemulsion films, and 

higher liquid viscosity inhibiting drainage.    

Nanocellulose grafted onto the surface acted to drain 

liquids and thicken foam films. Zhang et al. showed 

that mixing lignin-cellulose nanofibrils with cationic 

and anionic surfactants obtained firm foams, impeding 

drainage of liquids. Furthermore, it has been 

discovered that the composites formed by welan gum 

and hydroxylpropyl methylcellulose can significantly 

stabilize foams via their shear-thinning properties and 

physical interactions.. 

Polymer foam efficiency and effectiveness are 

influenced by factors beyond polymer type, including 

oil phase viscosity, salinity, and temperature. Higher oil 

phase viscosity increases foam vulnerability to 

destruction, while elevated temperature destabilizes 

foams. Conversely, increased salinity enhances foam 

stability by reducing liquid drainage and coalescence. 

Dehdari et al. (2020) compared the impact of light and 

heavy oil on PVA-stabilized foams with surfactants and 

nanoparticles, finding heavy oil to be more 

destabilizing. They also observed that increased 

aqueous phase salinity enhanced foam stability with 

PVA. However, polymer-stabilized foams generally 

exhibit better temperature stability. Fu and Liu (2020) 

investigated CO2 foam stability with nanoparticles, 

surfactants, and hydroxyethylcellulose under varying 

salinity and temperature. Increased temperature 

reduced CO2 foam apparent viscosity and accelerated 

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film drainage, while the polymer enhanced thermal 

resistance. 

Polymer-enhanced foam provides multiple benefits for 

EOR, effectively extracting both conventional and 

heavy oil from diverse reservoir types. Beyond oil 

production, recent research indicates its superior 

potential for gas sequestration and storage compared 

to traditional foams. Optimizing polymer 

characteristics is essential for successful polymer foam 

flooding, and incorporating nanoparticles can improve 

performance. While some studies suggest minimal 

impact of polymer molecular weight on foaming 

ability, others report enhanced foam stability with 

higher molecular weight. 

Alkali–Polymer Flooding 

Alkali-polymer flooding synergistically combines 

alkaline and polymer solutions for enhanced oil 

recovery. This approach addresses the limitations of 

standalone alkaline flooding. Alkali injection alters 

fluid-fluid and rock-fluid properties, including 

interfacial tension and wettability. Alkali reacts with 

crude oil naphthenic components, generating in-situ 

surfactants that reduce interfacial tension and create 

stable emulsions. However, alkalis' limited mobility, 

especially in heavy oil reservoirs, necessitates polymer 

addition for improved oil displacement. 

Alkali influence on polymer behavior varies based on 

alkali concentration, pH, and polymer type, potentially 

altering solution ionic strength or pH (Sheng, 2017). 

With synthetic polyacrylamide, alkalis accelerate 

hydrolysis. Low alkali concentrations yield low-

viscosity polymers, This is attributed to the tight coil 

conformation.. Increasing alkali concentration elevates 

pH, inducing electrostatic repulsion, expanding the 

hydrodynamic radius, and increasing viscosity. Chul et 

al. (2012) observed HPAM viscosity increases with 

NaOH addition in brine and temperature, but high alkali 

concentrations reduce viscosity due to increased ionic 

strength. This lower viscosity can enhance polymer 

injectivity in tight formations. Reintroducing 

waterflooding decreases ionic strength, expanding the 

polymer and increasing resistance to flow, diverting 

water to unswept zones, and improving sweep 

efficiency. Similar alkali effects on biopolymers 

(xanthan gum) have been reported (Medica, 2020). 

Surfactant–Polymer Flooding 

Surfactants, with their hydrophobic groups, enhance 

pore-scale displacement efficiency by reducing 

interfacial tension, altering wettability, and stabilizing 

emulsions. This approach proves effective for 

recovering capillary-trapped oil but may fall short in 

heavy oil reservoirs. Polymers, conversely, increase 

injectant viscosity, improve mobility ratio, and enhance 

volumetric sweep efficiency without significantly 

influencing microscopic processes. Achieving optimal 

recovery necessitates combining surfactant and 

polymer flooding to address both microscopic and 

macroscopic displacement inefficiencies (Liu,2017). 

Careful chemical selection is crucial for surfactant-

polymer (SP) flooding efficiency, as incompatible 

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surfactant and polymer properties can induce phase 

separation. Injection slug design varies based on 

flooding objectives. Competitive adsorption between 

chemicals reduces pore space availability for 

subsequent chemicals, potentially impacting recovery. 

Polymer pre-injection can minimize surfactant 

adsorption and enhance conformance control. 

Conversely, polymer as a secondary slug addresses 

viscous fingering during water and surfactant flooding 

(Gbadamosi,2019). Despite sequential injection, 

surfactant-polymer interactions via diffusion and 

dispersion must be considered in screening criteria 

development. 

Numerous studies have investigated the reciprocal 

influence of surfactants and polymers . Interfacial 

tension (IFT) measurements as a function of polymer 

and surfactant concentrations highlight this 

interaction. Polymer addition introduces two critical 

concentration points, replacing the system's CMC, as 

illustrated in Figure 11. The initial critical aggregation 

concentration (CAC) precedes the CMC, marking 

surfactant molecule adsorption and polymer chain 

interaction. The subsequent polymer saturation 

concentration exceeds the CMC, characterized by 

surfactant micelle formation around polymer 

molecules (Druetta,2018). 

 

Figure 11  

Depending on surfactant and polymer charges, 

interactions are attributed to electrostatic or 

hydrophobic effects. Afolabi (2019) examined sodium 

dodecyl sulfate (SDS) impact on poly(acrylamide-co-N-

dodecylacrylamide) rheology, observing increased 

viscosity until SDS reached CMC, followed by a 

decrease. This behavior resulted from surfactant-

polymer hydrophobic interactions. Similarly, Yusuf et 

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al. (2021) investigated sodium dodecyl benzene 

sulfonate's influence on carboxymethyl cellulose 

(CMC) rheology, emulsion, and wettability, noting 

viscosity increase until CMC, followed by a decrease. 

Hydrophobic microdomain formation at high 

surfactant concentrations disrupted surfactant-

polymer intermolecular forces, reducing viscosity. 

Moreover, Kalam et al. (2020) explored spacer nature 

and counterions in a new polyoxyethylene cationic 

surfactant on the rheology of cationic polyacrylamide 

polymers.. Increasing surfactant concentration 

reduced shear viscosity and elasticity, while elevated 

temperature decreased storage and complex viscosity. 

Introducing a phenyl ring into the Gemini surfactant 

spacer enhanced viscosity and storage modulus. 

Chloride counterions outperformed bromide 

counterions in improving polymer rheology. Ge et al. 

(2021) investigated the effect of betaine surfactant 

structure on surfactant-polymer (SP) mixture 

rheology. Short-chain betaine surfactants negatively 

impacted polymer solution viscosity due to 

electrostatic shielding. Conversely, high 

concentrations of long-chain betaine surfactants 

positively influenced surfactant-polymer flooding 

viscosity. 

To minimize chemical injection volumes, recent studies 

have developed polymeric surfactants by merging 

amphiphilic surfactants with polymer macromolecules 

into a single compound. These novel chemicals exhibit 

surface activity, influencing fluid-fluid and rock-fluid 

interactions. While not achieving ultralow interfacial 

tension (IFT) like conventional surfactants, polymeric 

surfactants reduce IFT to approximately 10-1 mN/m, 

facilitating stable microemulsion formation . These 

surfactants also demonstrate favorable rheological 

properties, reducing injectant mobility and exhibiting 

advantageous for field applications. In essence, While 

on the other hand, polymeric surfactants combine 

interfacial properties typical of classic surfactants with 

the viscoelastic properties of a polymer. (Raffa,2016). 

The solution properties of polymeric surfactants are far 

better than conventional polymers due to the 

presence of hydrophobic units in them. Intramolecular 

hydrogen and van der Waals tensile bonds in the 

functional group formed enhance the bulk viscosity 

and viscoelasticity. Kumar et al. studied the anionic 

polymeric surfactant derived from Jatropha and found 

that the viscosity increased with concentration along 

with the pseudoplastic behavior at higher shear rates. 

Babu et al. (2015) synthesized a polymeric surfactant 

based on castor oil, and non-Newtonian behavior was 

developed, which exhibited viscosities from 10 to 40 

cP, much superior to the viscosities shown by normal 

or conventional surfactants. Pal et al. (2016) measured 

the rheological performance of synthesized polymeric 

methyl ester sulfonate for EOR and found higher 

storage and loss moduli with increasing concentration 

of the surfactant. 

Polymeric surfactants exhibit superior IFT reduction 

and wettability alteration compared to conventional 

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surfactants . Kumar et al. (2016) reported a 10-fold IFT 

reduction from 22.4 to 2.4 mN/m at 6 g/L, altering oil-

wet quartz to water-wet conditions. Babu et al. (2015) 

observed a contact angle reduction to below 20° after 

720 s using a castor oil-based polymeric surfactant. 

Mehrabianfar et al. (2021)  demonstrated a contact 

angle reduction from 146° to 64° on oil-wet carbonate 

rock using an Acanthephyllum-derived polymeric 

surfactant. Co et al. (2015)  achieved an IFT of 0.15 

mN/m at 2000 ppm functionalized polymeric 

surfactant, forming stable water-in-oil emulsions. 

Nowrouzi et al. (2020) synthesized a Tragacanth gum-

based polymeric surfactant, reducing IFT from 25.145 

to 2.329 mN/m at 2000 ppm in 0.02 wt.% NaCl brine. Li 

et al. (2021) synthesized a polymeric surfactant via 

micellar polymerization, achieving an IFT of ~0.6 mN/m 

at higher concentrations due to hydrophobic chain 

adsorption at the oil-water interface. This surfactant 

also exhibited superior emulsion stability compared to 

conventional SP systems. 

Alkali–Surfactant–Polymer (ASP) Flooding 

ASP flooding integrates alkalis, surfactants, and 

polymers to make the recovery of oil more efficient. 

Combinations between alkali and surfactant improve 

the pore-scale displacement efficiency through 

lowering residual oil interfacial tension and capillary-

trapped interfacial tension, thus altering wettability 

toward more water-wet conditions. Macroscopic 

sweep efficiency, key to heavy oil recovery, is 

enhanced by incorporating polymer into the mixture.. 

Polymers also reduce water cut, with overall ORE 

represented by Equation (2). 

(2) 

In this equation, Ero signifies the overall ORE, 

controlled by the combined effects of pore-scale 

displacement (Edo), areal sweep (Ea), vertical 

displacement (Ev), oil saturation (So), permeability 

variation (Vp), and oil formation volume factor (Bo). 

ASP flooding involves a synergistic interplay of alkali, 

surfactant, and polymer to enhance oil recovery. Alkali 

generates in-situ soap, combining with the injected 

surfactant to achieve ultralow interfacial tension 

across a wide salinity range, surpassing the limitations 

of individual components (Olajire,2014). Alkali 

minimizes surfactant and polymer adsorption on 

reservoir rock.  The formed in-situ soap and surfactant 

stabilize emulsions, with polymer enhancing stability 

through increased viscosity. This combination 

improves sweep efficiency by reducing mobility ratio. 

The injection sequence includes a brine preflush, 

followed by an alkali-surfactant slug and a polymer 

slug, with a chase water concluding the process (Figure 

12). This synergistic approach elevates capillary 

number, Improved pore-scale displacement and 

consequently, sweep efficiency. 

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Figure 12.  

Laboratory studies confirm the efficacy of alkaline-

surfactant-polymer (ASP) flooding in improving oil 

recovery from reservoirs. Sui et al. (2020) reported a 

44.5% increase in oil recovery compared to 

waterflooding when using ASP on active oil under 

conditions of 62 °C and 1700 psig. Zhapbasbayev et al. 

(2018) noted an additional oil recovery of 19-37% when 

applying ASP to viscous oils (407.4 and 300 cP) from 

Russian fields. Panthi et al. (2017) achieved incremental 

oil recoveries of 47.8% and 44.9% over waterflooding by 

utilizing ASP as a secondary and tertiary recovery 

method for viscous oil, incorporating sodium 

metaborate, propoxy sulfate surfactant, and HPAM 

polymer. Fu et al. (2016) reported a 20% increase in oil 

recovery through the use of a combination of organic 

alkali and petroleum sulfonate surfactant in ASP 

flooding. Liu et al. (2008) successfully extracted 98% of 

residual oil from dolomite and silica sandpacks via ASP 

flooding. Ghosh et al. (2019) explored ASP in low-

permeability tight carbonate reservoirs, achieving 

recovery rates of 77-87% of the original oil in place 

through tertiary ASP flooding while modeling 

geochemical interactions. Panthi et al. (2016) 

demonstrated that secondary surfactant flooding 

reduced oil saturation to 3.1% and raised cumulative oil 

recovery to 95.6% in a carbonate reservoir. 

To investigate the environmental concerns related to 

the toxicity of conventional surfactants used in ASP 

flooding, recent research has focused on developing 

and evaluating natural and biosurfactants as 

alternatives. Kesarwani et al. (2021), From karanj oil, 

synthesized a biodegradable surfactant., resulting in a 

32% increase in oil recovery during sandpack flooding. 

Nowrouzi et al. (2020) developed a natural surfactant 

derived from soapwort, achieving ultralow interfacial 

tension and altering wettability in sandstone cores. An 

ASP slug composed of sodium hydroxide, soapwort 

surfactant, and HPAM led to a 32.1% incremental oil 

recovery. In another study, Nowrouzi et al. (2020) 

utilized hollyhock mucilage as a natural polymer and a 

waste chicken fat-based anionic surfactant for ASP, 

resulting in a 27.9% incremental oil recovery in 

sandstone reservoirs. 

Polymeric Nanofluid Flooding 

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Although polymers boost oil recovery, their efficiency 

is curtailed by adsorption, retention, and chemical, 

mechanical, or thermal degradation. While 

temperature and salt-resistant polymers exist, cost and 

complexity impede their widespread use. Combining 

inexpensive nanoparticles with polymers produces 

Innovative materials with enhanced characteristics for 

improved oil recovery (EOR) have emerged. 

Nanoparticles engage with polymers via hydrogen 

bonding, electrostatic interactions, van der Waals 

forces, and steric repulsion. These polymeric 

nanofluids demonstrate salt tolerance, temperature 

resistance, and improved rheology. Decreased 

adsorption and increased stability within porous media 

enhance their oil recovery efficiency. Additionally, 

these nanofluids modify fluid-fluid and rock-fluid 

interactions (Agi, 2020). 

Enhanced rheology of PNFs under HTHS conditions 

arises from hydrogen bonding and nanoparticle-

induced shielding of polymer chains (Figure 13). Agi et 

al. (2020) showed starch-based PNFs outperform 

xanthan gum in rheological properties. Rezaei et al. 

(2016) modified montmorillonite nanoclay, resulting in 

improved rheology, shear resistance, and oil recovery 

when combined with HPAM. Maurya and Mandal 

(2016) observed increased viscosity in polyacrylamide 

upon SiO2 nanoparticle addition. Hu et al. (2017) 

reported enhanced rheological and thermal stability 

for silica nanoparticle-seeded acrylamide polymer, 

explaining this by a hydrogen-bonded 3D network that 

protects the polymer and reduces degradation (Figure 

14). Li et al. (2017) highlighted the excellent rheology of 

nanocellulose-based PNFs, while Agi et al. (2020) 

reported good rheological behavior of okra mucilage-

derived PNFs in brine. Corredor-Rojas et al. (2019) 

showed enhanced rheological properties, salt 

tolerance, thermal stability, and shear resistance in 

modified silica nanoparticle-xanthan gum polymer 

nanofluids (PNFs). 

 

Figure 13.   

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Figure 14.  

Beyond enhanced rheology, salinity, and thermal 

resistance, polymeric nanofluids demonstrate reduced 

adsorption and improved stability within porous 

media. Bagaria et al. (2013) observed lower adsorption 

and greater stability of iron oxide nanoparticle (IONP). 

steric repulsion-induced stability of IONP-acrylamide 

polymer nanofluids on silica.. Cheraghian and co-

workers, 2014, reported reduced adsorption of silica 

and clay nanoparticle-based polymeric nanofluids on 

sandstone cores. Xue et al., 2014, confirmed the 

stability and transport properties of IONP-poly(AMPS-

co-AA) copolymer nanofluid under high temperature 

high shear conditions. Iqbal et al., 2017, reported iron 

oxide nanoparticle stability at 120 °C using poly(AMPS-

co-AA) copolymer. Zhao et al., 2017 observed starch-

graphene nanoparticle PNF stability. Vasconcelos et al. 

(2022) reported the ethylenediamine-modified 

graphene oxide nanoparticles to be stable up to 90 

days, with a viscosity increase of 146% compared to 

HPAM. 

Additionally, nanoparticles within polymers reduce IFT, 

altering wettability and stabilizing emulsions. 

Nanofluids stabilized by polymers have very excellent 

properties. Corredor and co-workers (2019) reported a 

66.7% IFT reduction using polymeric nanofluids. 

Sharma et al. (2016) observed reduced oil-water IFT 

with nanoparticle-doped polyacrylamide. Bera et al. 

(2020) demonstrated nanoparticle-induced guar gum 

polymer's ability to alter wettability from oil-wet (115°) 

to water-wet (72°) conditions. Gbadamosi et al. (2019) 

reported aluminum nanoparticle-HPAM's wettability 

alteration. Saha et al. (2018) observed xanthan gum 

and silica nanoparticle-based foam's long-term 

stability. Pal et al. (2019) demonstrated improved 

emulsion packing and stability with HPAM and SiO2 

nanoparticle-stabilized emulsions. Kumar et al. (2017) 

reported carboxymethylcellulose and SiO2 

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nanoparticle-stabilized emulsions' stability over a wide 

temperature range and reduced IFT. 

FINANCIAL IMPLICATIONS OF POLYMER USE IN EOR 

Polymer injection for chemical EOR provides economic 

advantages by boosting oil production and curtailing 

water production. Incremental oil recovery enhances 

project profitability, while lower water cut minimizes 

treatment costs and compared waterflooding and 

polymer flooding costs in Daqing oilfield, finding 

polymer flooding costs of approximately 9 USD/bbl, 

equivalent to waterflooding costs. Water cut reduction 

from 90-95% to 70% with quadrupled oil recovery 

through polymer injection highlights its economic 

viability, especially with current high oil prices. China 

leads in polymer flooding applications with over 3000 

wells and 300 million barrels of cumulative oil 

production (Keykhosravi,2021). The USA and Canada 

also utilize polymer flooding, particularly in heavy oil 

reservoirs. 

CONCLUSIONS 

This review assessed the utilization of polymers in 

enhancing oil recovery through chemical methods. The 

review encompassed a detailed examination of 

polymer types and their underlying mechanisms, along 

with binary polymer-additive combinations for EOR. 

Recent polymer flooding studies were summarized. 

While HPAM remains prevalent, other polymers show 

promise. Careful reservoir rock and fluid property 

screening is essential for successful polymer 

applications. Polymer-additive combinations yielded 

positive results, with EOR types benefiting from 

incremental oil recovery. Most studies focused on 

sandstone reservoirs, necessitating further research 

on carbonate reservoir applications. Scaling issues 

persist in ASP flooding. Optimal injection sequence 

configuration for surfactant-polymer flooding needs 

improvement. Rock-fluid interactions for surface-

active agents are still poorly understood, and 

polymeric nanofluid phase equilibrium behavior 

remains unclear. 

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Volume 04 Issue 09-2024 45 

                 

 
 

   
  
 

American Journal Of Biomedical Science & Pharmaceutical Innovation    
(ISSN – 2771-2753) 
VOLUME 04 ISSUE 09 PAGES: 15-45 

OCLC – 1121105677     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Publisher: Oscar Publishing Services 

Servi 

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