This document provides an overview of enhanced oil recovery (EOR) techniques, focusing on chemical EOR methods. It discusses how conventional recovery leaves behind 65-75% of original oil in place and how chemical EOR aims to recover additional oil by reducing interfacial tension and improving sweep efficiency. Alkaline-surfactant-polymer flooding is highlighted as one of the most effective chemical EOR methods, working through synergistic effects of alkalis, surfactants, and polymers to enhance oil recovery. Polymers are particularly useful for improving sweep efficiency by increasing the viscosity of the displacing fluid.

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Enhanced Oil Recovery (EOR) - Review
Chandran Udumbasseri, Technical Consultant, chandran.udumbasseri@gmail.com.
Introduction
Average oil recovery from light and medium gravity oil by conventional method (primary
and secondary) is 25-35% of Original Oil in Place (OOIP). In the case of heavy oil
deposits the average recovery is only 10% OOIP. Conventional recovery method leaves
behind 65-75% of OOIP. Chemical enhanced oil recovery is an advanced technology
that addresses the mechanisms that recover additional oil. So two thirds of the original
oil in place (OOIP) in a reservoir is not produced and is still pending for recovery by
efficient EOR method.
When oil is displaced by water, say by water flooding (secondary stage of recovery by
applying forced pressure with water injection) the oil phase disintegrates into thick
viscous residual oil. These thick viscous oil blobs are held in the pores of rock by
capillary forces (in a capillary tube if one end is open and other end immersed in a fluid,
the fluid will rise into the tube by capillary force. Capillary force in the capillary tube
sucks the fluid and holds inside the capillary pore).. If the capillary forces are reduced
then this entrapped oil can be recovered. The strength of this capillary force is related to
oil/water interfacial tension (IFT). . At high IFT the oil drops are stuck in the pores. By
reducing the IFT, oil drop becomes flexible and mobile through the reservoir
Oil trapped in the pores of the rock pebbles (High IFT)
Rock pebbles with adhered oil (oil wetted rock pebbles)

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Oil released from the rock pebbles (Low IFT). Oil droplet with low IFT elongated
and easily movable between the sand pebbles
Moving front of oil by polymer flooding
Displacement of oil by water
The displacement of oil in water flooding depends on the macroscopic sweep efficiency
of water flooding. When the viscosity of injected water is increased the relative mobility
of water compared to oil reduces. Viscosity of water (1cP at 20o
C) is usually less than
crude oil. When water is flooded in the reservoir to sweep oil, due to low viscosity of
water the flooded water finds low pressure regions in the oil and escapes to the
production direction without carrying, or sweeping, oil along with it. This process is
called fingering and channeling of water through oil.

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Water fingering through oil
Mobility ratio
This ratio is defined as the ratio of mobilty of displacing fluid ( water) behind the front to
the mobilty of displaced fluid (oil). It is expressed as,
M =
When the value of M is greater than 1 then it is not favorable for displacement process.
M less than 1 is considered as favourable. When M is higher than 1 then the speed of
water movemnt is higher than that of oil. In such situation water front seeks low
pressure area and escape. As illustrated above this is called fingering and channeling.
This breakthrough make water to move to production well instread instead of carrying
with oil.
When M=1 then speed of water and oil is the same and the displacing front of water is,
as shown below, just the water front pushing the oil without fingering or chenneling. .
Mobility ratio = 1: water moves in the speed of oil and sweeping oil in a water front.

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Oil Recovery
The oil recovery efficiency is the amount of oil displaced or recovered divided by the
total volume of oil at the beginning of the EOR process (original oil in place, OOIP)
Recovery efficiency =
Oil recovery is dependent on microscopic and macroscopic displacement efficiency.
Microscopic displacement efficiency is a measure of mobilization of residual oil
by displacing fluid. It is controlled by factors such as rock wettability, relative
permeability, IFT and capillary force. A decrease in any of these factors can increase
the displacement efficiency.
Macroscopic displacement efficiency also known as volumetric sweep efficiency,
measures the extent to which displacing fluid is in contact with oil bearing parts of the
reservoir. It is influenced by rock matrix, anisotropy, mobility ratio of displacing and
displaced fluids, injection and production well positioning.
The product of these two parameters gives the overall oil recovery. It can be expressed
as the product of microscopic efficiency (ED) and macroscopic efficiency (EV).
R (recovery) = ED . EV
Ev is the product of two types of sweep efficiencies.
EV = Ea.Ei,
where Ei is vertical sweep efficiency and Ea is areal sweep efficiency.
Recovery can be expressed as fraction of OOIP
Oil Recovery (Np) = Displacement (pore to pore) efficiency x Volume (sweep) efficiency x OOIP
Np = ED*EV*OOIP
Where:
 Np = Oil Recovery (Production)
 ED = Pore to Pore (Unit) Displacement Efficiency
 EV = Volumetric Sweep Efficiency
 OOIP = Original Oil in Place
Displacement Efficiency
It is the fraction of oil that has been recovered from a zone swept by a water flood or
other displacement process. Displacement efficiency equation:

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ED = (Voi − Vor) / Voi,
Where,
Voi = volume of oil at start of flood
Vor = volume of oil remaining after flood.
IFT and Capillary Number (NC)
One important parameter EOR methods aim at is the capillary number (NC):
Nc =
Nc expresses ratio of viscous forces to capillary forces
V is interstitial velocity (m/s)
µ is the viscosity of displacing fluid
is the IFT between crude oil and displacing fluid.
Nc expresses the ratio of viscous forces to capillary (interfacial) forces with v being the
interstitial velocity [m/s] and being the viscosity [Pa·s] of the displacing fluid and the
IFT between crude oil and displacing fluid [mN/m = dynes/cm].
Fig: Thomas, Enhanced Oil Recovery – An Overview, Oil Gas Sci Technol 2008, 63, 9-19.
High values for Nc correlate with decreasing residual oil saturations. Figure above
shows relation of residual oil saturation with capillary number. Decreasing the IFT
between displacing fluid and crude oil increases Nc, and thus lowering the residual oil
saturation. For a mature water flooding process, Nc is in the range of 10-7
to 10-6
,
while for fully miscible systems Nc approaches infinite values as IFT converges to 0
mN/m. In EOR, Nc is manipulated in terms of temperature and mostly by the

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composition of flooding liquids. Both parameters can help to decrease the IFT between
residual oil and injected fluid, thus shift the capillary number to higher values, which
positively affect oil mobilization.
Capillary number theory is regarded as the basic theory in polymer flooding, surfactant
flooding, polymer-surfactant flooding (SP), and alkali-surfactant-polymer flooding (ASP).
The basic mechanism of chemical flooding in EOR can be summarized into mobility
control based enlarging sweep efficiency and capillary number theory based improving
displacement efficiency
EOR Process
Chemical EOR method can be implemented easily because it needs fewer facilities to
add chemicals in injection water. Among the chemical methods, alkaline surfactant-
polymer (ASP) is the most prominent method because it works on the synergy of
alkaline, surfactant and polymer. This combination also has tolerance to high salinity
and gives good mobility control.
Addition of polymer increases the viscosity of water. Thus decreases permeability to
water. So mobility of aqueous phase decreases. Decrease in mobility ratio greatly
increases the sweeping efficiency.
SP/ASP injection reduces the IFT between oil and rock formation. When the viscosity of
injected water is increased, the mobility ratio decreases and interfacial tension also
decreases. When polymer is injected the sweeping efficiency increases. Also the
viscosity of water increases bringing down the mobility of water compared to oil.
In ASP method the alkali reacts with crude oil constituents and can lower water- oil IFT,
emulsify oil and water, change rock wettability and solubilize interfacial films, all of
which may lead to increased oil recovery. Surfactants can lower IFT significantly, and
change wetting property of rock stone.
Displacement by surfactant solutions is one of the important tertiary recovery processes
by chemical solutions. The addition of surfactant decreases the IFT between crude oil
and formation water, lowers the capillary forces, facilitates oil mobilization, and
enhances oil recovery
Oil recovery is enhanced greatly by decreasing IFT, increasing capillary number,
enhancing microscopic displacing efficiency, improving mobility ratio and increasing
macroscopic sweep efficiency
Surfactant
A surfactant (Surface Active Agent) is an amphiphilic molecule composed of a
hydrophobic tail and a hydrophilic head. This molecule will adsorb at the oil/water
interface and thus lower the oil-water interfacial tension (tension existing between two
immiscible fluids), leading to the mobilization of the trapped residual oil droplets. The

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main criteria to select the appropriate surfactant are its temperature stability, its
resistance to salinity and hardness and its adsorption on rocks which must be as low as
possible.
Alkali
Carboxylate soaps are created when a crude oil with acidic components reacts with
hydroxide ions in alkaline solution. These petroleum soaps are capable of adsorbing at
the oil-water interface and lowering the interfacial tension.
The combination of Alkali, Surfactants and Polymers leads to synergistic effects
between the chemicals. The key roles of each component are summarized below.
Functional contribution
Polymer
 Increase viscosity of water
Surfactant
 Lower IFT between oil and water
 Change the wettability of the rock
 Generate emulsions
Alkalis
 Reacts with crude oil to generate soaps
 Increase pH and adjust salinity
 Alter rock wettability
 Alter rock chemistry reducing adsorption
Polymer flooding
Polymers used in polymer flooding are partially hydrolyzed polyacrylamide and
hydrophobically modified products.
Chemical structure of partially hydrolyzed polyacrylamide
Higher viscosity of the polymer solution, causes a liquid phase with high viscosity of oil
emulsion, Increased viscosity of the liquid phase promotes a stable oil emulsion;
Partially hydrolyzed polyacrylamide contains a lot of -COO -Na + groups which are
strongly hydrophilic groups, Strongly hydrophilic groups are adsorbed on the oil-water
interface which increases the thickness and strength of the oil-water interface.
Hydrophobically modified polymer, owing to its amphiphilic structure, is easily

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adsorbed on the oil-water interface and thus reduces the oil-water interfacial tension
and improve the stability of the emulsion.
The mechanism of enhanced recovery involved in polymer flooding is based on
decreasing the mobility difference between displacing and displaced fluids, in order to
reduce fingering effects
The displacing phase should have mobility equal to or lower than the mobility of the oil
phase.
When the water/oil mobility ratio (M) is 1 or slightly less, the displacement of the oil by
the water phase will occur in a piston-like fashion
If M is greater than 1, the more mobile water phase will finger through the oil, causing a
breakthrough and poor recovery
Since the mobility is inversely proportional to the viscosity, the polymer should act as an
effective viscosifier for the aqueous phase
The main features of such polymers are: very high molecular weight, resistance to
mechanical degradation in shear and, of course, complete solubility in water.
Additionally, they should be inexpensive, non-toxic and able to tolerate high salinity and
high temperatures
The polymer flooding efficiency ranges from 0.7 to 1.75 lb of polymer per barrel of
incremental oil production
The process usually starts with pumping water containing surfactants to reduce the
interfacial tension between the oil and water phases and to alter the wettability of the
reservoir rock to improve the oil recovery (usually the surfactant with wetting ability is
also added).
Polymer is then mixed with water and injected continuously for an extended period of
time (can take several years).
When about 30% to 50% of the reservoir pore volume in the project area has been
injected, the addition of polymer stops and the drive water is pumped into the injection
well to drive the polymer slug and the oil bank in front of it toward the production wells
Criteria for Viscosifiers ( Mobility control agent)
 should have high cost effectiveness,
 and allow high injectivity,
 should be resistant to mechanical (up to 1000 m3
/m2
-d flux when entering
porous rock) and microbial degradation,
 should sustain high reservoir temperatures (up to 200°C) for extensive periods of
time (5 to 10 years),
 should be effective when mixed with reservoir brines,
 should have low retention properties in porous rock,
 should be effective in presence of oil and gas, and not sensitive to acidity (pH) or
various chemicals present at the oilfield

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Types of polymers
There are two types of polymer used, synthetic and biopolymers.
Most commonly used polymers are given below and every polymer has its own
advantage and disadvantage based on the reservoir.
1. Partially hydrolyzed polyacrylamide (PHPAM)
2. Polysaccharide
3. Xanthan gum
4. Hydroxyl ethyl cellolose
5. Sodium carboxymethyl cellulose
PAM (Polyacrylamide) with its high molecular weight (> 1.0 × 106
g/mol) was the first
thickening agent used for aqueous solutions. PAM is stable up to 90°C at normal salinity
and up to 62°C at seawater salinity. Therefore, it is somewhat restricted to on-shore
operations only. But high salinity can reduce viscosity properties of this compound.
Partially hydrolyzed polyacrylamide (HPAM) is one of the most popular polymer used
today. HPAM is obtained by partial hydrolysis of PAM or by copolymerization of sodium
acrylate with acrylamide. HPAM's advantages include its tolerance to high mechanical
forces present during the flooding of a reservoir, low cost, and its resistance to bacterial
attack. This polymer can be used for temperatures up to 99°C depending on brine
hardness. A few of its modifications, such as HPAMAMPS co-polymers and
sulphonated polyacrylamide can withstand 104°C and 120°C respectively. But the
disadvantage of HPAM is in its high sensitivity to the brine salinity, hardness and
presence of surfactants or other chemicals. This makes it very ineffective in reservoirs
containing salts
Xanthan gum, a polysaccharide, is produced by different bacteria (one of which is
Xanthomonas campestris) through fermentation of glucose or fructose. The molecule
generally has very high molecular weight (2 - 50 × 106
g/mol) and very rigid polymer
chains. This makes Xanthan gum relatively insensitive to high salinity and hardness.
The polymer is compatible with most surfactants and other injection fluid additives used
in tertiary oil recovery formulations. Xanthan gum is usually produced as broth in
concentrated form that can be easily diluted to working concentrations without any
complex mixing equipment. Xanthan is thermally stable in the range from 70°C to 90°C.
But, this compound is very sensitive to bacterial degradation when injected into the field
containing low-temperature regions in the reservoir. Furthermore, this product has some
debris of cellulose which plugs the rock cavities and reduce flow rate.

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Selection of polymer for a particular reservoir
Each reservoir needs particular polymer to perform well. Polymers tend to work better or
worse in different conditions, due to their different properties. One should take into
account several factors to select the optimal polymer used. It is necessary to consider
reservoir permeability and oil viscosity. The cloud point of the polymer solution should
be considered. This parameter can give information on polymer thermal stability in high
salt brine and high temperature. The polymer retention should be studied as it
influences the mechanisms responsible for the reduction of mean velocity of polymer
molecules during their flow through porous media. Retention is related to polymer
adsorption, but some polymers can be mechanically entrapped in porous medium or
hydrodynamically trapped in stagnant zones. Thus, it is necessary to know the rock
composition and polymer adsorption level to determine the best degree of hydrolysis.
General Summary
The research works that were conducted at various organizations can be summarized
as explained below
Polymers play major role in the Enhanced Oil Recovery; they help extract up to 30% of
the original oil in place. Polymers increase the viscosity of the displacing liquid (water)
to drive the displaced liquid (oil) to the production well. A variety of polymers is used in
different oil fields depending on working conditions of that field. Before the right polymer
is chosen, a careful analysis should be conducted to ensure that the polymer is effective
during an extensive period of time.
Polymer can increase the viscosity of injected fluid, decrease the mobility ratio of water
and oil, and then expand the sweep coefficient
As the polymer is visco-elastic, it can also improve the oil displacement efficiency

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The IFT between the oil and the polymer solution is quite high; it possesses no oil
solubility and emulsifiability. This is the limitation of polymer solubility.
The alkali-surfactant-polymer (ASP) system can reduce both the mobility ratio and the
IFT,
The alkali in ASP system can react with the organic acid in the oil to generate
surfactant. So the IFT can be reduced to a larger extent due to the synergy between
surfactant added and generated. The alkali can also reduce the surfactant absorption in
the reservoir.
The alkali will react with the clay mineral in the reservoir and produce the precipitate.
It will result in the reservoir damage, difficulty demulsification, and the reduction of the
ASP system viscosity.
The SP system without alkali can solve the above problems. It can play the
viscoelasticity of polymers to the maximum degree and erase the corrosion and scaling
caused by alkali.
SP flooding could enhance oil recovery because polymer can increase sweep efficiency
and surfactant can improve the oil displacement efficiency. The polymer viscosity
influences the sweep efficiency and the displacement efficiency.
The viscosity is influenced by the salinity, temperature, absorption and shearing action.
The IFT is influenced by the reservoir temperature, the composition of crude oil, and the
concentration change caused by the action between the injection fluid and the rock tion,
and shearing action.
The oil recovery varies from reservoir to reservoir. If the injection can reduce the IFT to
10−3
mN/m, the highest recovery can be reached in homogeneous reservoirs (capillary
equation).
In heterogeneous reservoir, the mobility ratio plays an important role in spreading to the
middle-low permeability layer
Salinity and shearing have a negative effect on both viscosity of polymer solution and oil
recovery, so increasing the concentration of the polymer to maintain high viscosity is
necessary
The improving recovery efficiency of SP (Surfactant + Polymer combined) flooding is
higher than the sum of improving recovery of the polymer and surfactant.
The polymer carries surfactant into more pore volume and the oil displacing action gets
full play, forming synergistic effect.

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The main factor of SP flooding in the heterogeneous reservoir is the mobility
control action. When choosing the SP system, the viscosity should be considered
first and the IFT then comes second
When the system reaches the ultralow IFT, the emulsion is easy to form and it is
advantageous to extract residual oil.
When a surfactant is added to the immiscible phases of water and oil, they form
micelles which convert the immiscible phases into a single solution. The single solution
formed can either be water in oil type or oil in water type. This helps in increasing the
microscopic sweep efficiency. Microscopic sweep efficiency as the name suggests
increases the mobility of the oil bank formed by the surfactant micelles on the scale of
pore spaces. This simply means that the solution of water and oil moves with more ease
in the pore spaces of the reservoir.