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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:
https://theusajournals.
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:
•
λ
w
represents water mobility
•
λ
o
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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