Reliability, Availability, [600416]

RAMS
Reliability, Availability,
Maintainability, and SafetyThis is the Title of my Thesis
Your Name
December 2012
PROJECT THESIS
Department of Production and Quality Engineering
Norwegian University of Science and Technology
Supervisor 1: Professor Ask Burlefot
Supervisor 2: Professor Fingal Olsson

i
Preface
Here, you give a brief introduction to your work. What it is (e.g., a Master’s thesis in RAMS at
NTNU as part of the study program xxx and. . . ), when it was carried out (e.g., during the au-
tumn semester of 2021). If the project has been carried out for a company, you should mention
this and also describe the cooperation with the company. You may also describe how the idea
to the project was brought up.
Trondheim, 2012-12-16
(Your signature)
Ola Nordmann

ii
Acknowledgment
I would like to thank the following persons for their great help during . . .
If the project has been carried out in cooperation with an external partner (e.g., a company),
you should acknowledge the contribution and give thanks to the involved persons.
You should also acknowledge the contributions made by your supervisor(s).
O.N.
(Your initials)

iii
Summary and Conclusions
Here you give a summary of your your work and your results. This is like a management sum-
mary and should be written in a clear and easy language, without many difficult terms and with-
out abbreviations. Everything you present here must be treated in more detail in the main re-
port. You should not give any references to the report in the summary – just explain what you
have done and what you have found out. The Summary and Conclusions should be no more
than two pages.

Contents
Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i
Acknowledgment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
Summary and Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii
1 Introduction 2
1.1 Summary of the Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
2 Literature review on chemical flooding 4
2.1 Oil Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
2.2 Enhanced Oil Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
2.3 Basic mechanism of EOR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
2.3.1 Improving the Mobility Ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
2.3.2 Increasing the Capillary number . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.4 Chemical Flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.4.1 Surfactant Flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
2.5 Surfactant Flooding as EOR process . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
2.5.1 Interfacial tension reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
2.5.2 Wettability reverse mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
2.5.3 Factors affecting the efficiency of surfactant flooding . . . . . . . . . . . . . . 16
2.6 Polymer Flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
2.6.1 Types of polymers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
2.6.2 Polymer flow in porous media . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
2.7 Alkaline flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
2.8 Surfactant Polymer flooding (SP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
iv

CONTENTS 1
2.9 Alkaline Surfactant Polymer Flooding (ASP) . . . . . . . . . . . . . . . . . . . . . . . 22
3 Simulation of Chemical EOR processes: Polymer, Surfactant Flooding with Eclipse-100 24
3.1 Surfactant flood model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
3.2 Polymer flood model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
4 Heidrun oil and gas Field 26
5 3D numerical flow simulation 28
5.1 3D simulation model description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
5.2 Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
5.3 Simulation results and analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
5.3.1 Water injection rate analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
5.3.2 Potential of polymer and surfactant flooding . . . . . . . . . . . . . . . . . . . 34
5.3.3 Sensitivity analysis on EOR simulation . . . . . . . . . . . . . . . . . . . . . . 35
5.3.4 Summary of the sensitivity analysis for surfactant and polymer flooding . . 48
6 General Discussion 50
7 Conclusions and recommendations 53
A Acronyms 55
B Additional Information 56
B.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
B.1.1 More Details . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
Bibliography 57
Curriculum Vitae 60

Chapter 1
Introduction
The average oil recovery factor on the Norwegian Continental Shelf is currently 46 percent[1].
This means that more than half of the identified oil amount is left behind at the end of the
production. The recovery method commonly used is water flooding, mainly because of avail-
ability and low cost of the injection fluid. However, this method does not give an efficient oil
recovery[1].
After water flooding, the remaining oil is either residual from the area flooded by water or by
passed oil, which could not be swept during the water flooding. Enhanced oil recovery (EOR)
methods aim to recover both, the mobile oil and the immobile oil trapped in the pores of the
reservoir.
Chemical EOR involves the use of surfactants, polymers and alkali. Alkaline processes in-
duce the production of surfactants in-situ1. Chemical methods offer the recovery of more oil
by:
• Providing a mobility ratio control. Polymers are commonly used for this purpose. It is a
promising method for mobile oil recovery[1].
• Lowering the oil/water interfacial tension by the use of surfactants. Ultimately, surfactant
flooding lower the saturation of the residual oil trapped by capillary pressure.
Several laboratory experiments have been performed with polymers and surfactants, where up
to 90 per cent of the oil was produced (1). In field scale, it is not possible to achieve such a high
1See Alkaline Flooding Chapter
2

CHAPTER 1. INTRODUCTION 3
recovery rate, but the laboratory results are encouraging[1] as they give a first overview of the oil
recovery success rate.
1.1 Summary of the Project
The aim of this work was to examine efficiency of surfactant/polymer flooding in a synthetic
model of a sector from Heidrun Field. Statoil has provided the model with the data for water and
polymer flooding. Surfactant data are taken from literature. Schlumberger black oil simulator
Eclipse-100 was used for the numerical simulations.
Firstly, a water injection rate analysis was performed. The objective was to find a constant
water injection rate that would allow the comparison between the different EOR cases and water
flooding case.
Secondly, the recovery using polymers or surfactants is investigated and compared to a base
case of water flooding. Later, two sensitivity analysis were conducted: the chemical solution
concentration effect and the slug size effect on the efficiency of polymer/surfactant flooding
were studied. Finally, an overview discussion and project conclusions are presented.

Chapter 2
Literature review on chemical flooding
2.1 Oil Recovery
During the life of an oil field, several production stages are encountered. The industry aims to
sustain crude oil flow at maximum levels in all these stages. Therefore, many technologies were
developed to force oil towards the production wellhead where it can be pumped to the surface.
The oil recovery can be summarized in 3 phases.[25]
• Primary recovery: is the recovery by the drive energy naturally available in the reservoir.
This energy includes rock and fluid expansions, solution gas, water influx, gas cap and
gravity drainage.
• Secondary recovery: it consists of supplying the reservoir with external energy. The energy
is in the form of injected fluids as water or/and gas. This is done to maintain the pressure
of the reservoir constant after the depletion.
• Tertiary recovery also known as Enhanced Oil Recovery (EOR) is characterized by the in-
jection of special fluids such as chemicals, miscible gases and thermal energy injection to
recover both the mobile and immobile oil trapped in the reservoir pores.
4

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 5
2.2 Enhanced Oil Recovery
Enhanced Oil Recovery refers to the recovery of oil through the injection of fluids and energy
not normally present in the reservoir. Injecting these fluids has two purposes: First, to boost the
natural energy in the reservoir and second, to interact with the reservoir rock/oil system and
create conditions favorable for residual oil recovery[19]. The EOR methods help improve the
microscopic and macroscopic sweep efficiencies as compared to ordinary water or gas injection.
As there are different kinds of oil fields in the world, there are different EOR methods used to
improve the long-term drilling results. A few of them are listed below.
• Chemical recovery
• Thermal Methods
• Biological Methods
• Miscible injection
• Electrical and others
In the discussion of the effect of enhanced oil recovery, it is important to understand that
these technologies are adapted to the specific geological conditions of the area of application
and the physical conditions of the crude oil in the reservoir[6].
Different EOR technologies can be used in combination with each other to obtain an efficient
oil recovery.
A general classification of Enhanced Oil Recovery methods is presented in Figure 2.1.

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 6
Figure 2.1: Enhanced oil recovery technologies [23]
2.3 Basic mechanism of EOR
EOR processes target to increase the overall oil displacement efficiency, which is a function
of microscopic and macroscopic displacement efficiencies. Figure 2.2 presents a schematic of
sweep efficiencies: microscopic and macroscopic (microscopic, areal sweep and vertical sweep)[19].
The microscopic displacement relates to the mobilization of oil at the pore scale. Many
physical or/and chemical processes improve it. These include miscibility between the fluids,
decreasing the IFT and reducing oil viscosity. A high capillary number is necessary for a better
microscopic displacement.
Macroscopic displacement efficiency is improved by the choice of favorable mobility ratios
between displacing and displaced fluids during the flow.
Therefore, the oil recovery is influenced by two factors: The mobility ratio and the capillary
number.

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 7
Figure 2.2: Schematics of microscopic and macroscopic sweep efficiencies [19]
2.3.1 Improving the Mobility Ratio
The mobility ratio M is defined as the ratio of mobility of the displacing fluid and the mobility
of the displaced fluid.
MƸdi spl aci ng
¸di spl aced(2.1)
¸i=ki
¹i: mobility of the fluid i
ki: effective permeability of fluid i
¹i: viscosity of fluid i
i: oil, water or gas
In order to have a high volumetric sweep efficiency1M should be less than 1. When M ex-
ceeds 1, the flow becomes unstable: the displacing fluid moves more easily than the displaced
fluid. This phenomenon is called the viscous fingering. It results in low oil recovery efficiency
because most of the oil is by-passed as shown in Figure 2.3. Thus, controlling the mobility ratio
is an important parameter for an effective displacement of the oil.[8]
Favorable mobility ratio M can be obtained by:
1The volumetric sweep efficiency is the fraction of the total reservoir volume contacted by the injected fluid
during the recovery[6].

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 8
• Lowering the viscosity of the displaced fluid or increasing the viscosity of the displacing
fluid.
• Increasing the effective permeability to oil or decreasing the effective permeability to the
displacing fluid.
Figure 2.3: Illustrative cases for stable and unstable displacement [10]
2.3.2 Increasing the Capillary number
The capillary number Ncis the typical ratio of the viscous pressure drop at pore scale to the
capillary pressure[15]. It is given by:

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 9
Ncƹ£v
¾(2.2)
Where ¹the viscosity of the displacing fluid (Pa.s), ¾the surface tension (N/m) and v is the
velocity of the fluid (m/s).
A small capillary number suggests that capillary forces dominate the motion of the fluid;
inversely, a large capillary number indicates a viscous dominated regime.
The surface forces are responsible for trapping a large portion phase within the pores. A
high capillary number helps remobilize the oil trapped by surface forces and thereby reduces
the residual oil saturation. Capillary number in a miscible fluids displacement becomes infinite,
and under such conditions, residual oil saturation in the swept zone can be reduced to zero if
the mobility ratio is favorable.[30]
Favorable Capillary number can be achieved by:
• Reducing the oil viscosity
• Increasing the pressure gradient.
• Decreasing the IFT
The Figure 2.4 shows the correlation between the capillary number and residual oil satura-
tion.
2.4 Chemical Flooding
Chemical EOR processes are classified in terms of the main chemical agents used to modify the
equilibrium established in the reservoirs after recovery via conventional or physical methods.
General chemical EOR activities involve the use of polymers, surfactants, foams and certain
chemicals such as alkali or mixtures of these chemicals: polymer-alkaline, surfactant-polymer
and alkaline-surfactant-polymer (ASP) flooding mixtures[12].
After water flooding, a large amount of oil remains in the reservoir. This oil is either residual
or bypassed by water. Surfactants and alkali target to reduce the residual oil saturation by low-

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 10
Figure 2.4: Effect of Capillary number on residual oil saturation [30]
ering the IFT between water/oil interface. Polymers help obtaining a favorable mobility ratio in
order to recover the bypassed oil.
2.4.1 Surfactant Flooding
Surfactant flooding aims towards recovery of the residual oil in the water swept zones. In fact,
surfactant addition reduces the water/oil IFT and thus mobilizes the trapped crude oil. For
the movement of oil through the narrow capillary pores, a very low oil/water (IFT) is required;
preferably, ultra low IFT at 0.001 mN/m is desirable[20]. The surfactant flooding is depicted in
Figure 2.5.

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 11
Figure 2.5: Surfactant flooding [12]
The efficiency of surfactant flooding is very limited. It is mainly due to surfactant’s exorbi-
tant cost and excessive loss to the porous medium, which renders the process technically and
economically unviable [12].
Surfactants
Surfactants or surface active agents are polymeric molecules. They are made of two functional
groups, nonpolar hydrophobic tail and a polar hydrophilic head group as shown in Figure 2.6.
Due to this composition, they are soluble in both organic solvents and water[20].
Figure 2.6: Surfactant molecule and surfactant orientation in water [11][20]

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 12
When surfactants are injected in the reservoir, the hydrophilic head interacts with water
molecules and the hydrophobic tail interacts with the residual oil. The amphiphilic nature of
the surfactants allows them to adsorb effectively to interfaces and thus contribute to remark-
able reductions of the interfacial energy [20][17]. Adsorption onto rock surface, in some cases,
can also alter the wettability of the reservoir rock [31].
Surfactants are widely used in oil industry. Table 2.1 gives some examples of surfactant ap-
plications in Petroleum industry.
Table 2.1: Surfactant applications in petroleum industry[21]
Gas/Liquid Systems Liquid/Liquid Systems Liquid/Solid Systems
Producing oil well and
well head foams
Oil flotation process froth
Distillation and fractionation
tower foams
Foam drilling fluid
Foam acidizing fluid
Foam fracturing fluid
Blocking and diverting foams
Gas-mobility control foams.Emulsion drilling fluids
Enhanced oil recovery
in situ emulsion.
Oil sand flotation process slurry
Oil sand process froth
Wellhead emulsions
Heavy oil pipeline emulsion
Fuel oil emulsion
Asphalt emulsion
Oil spill emulsion
Tanker bilge emulsionReservoir wettability modifiers
Reservoir fines stabilizers
Tank/vessel sludge dispersants
Drilling mud dispersants
Surfactant Classification
Surfactants are classified depending on their polar moieties: anionic, nonionic, cationic and
zwitterionic. These different surfactants ionize differently in aqueous solutions [25][11]:
•Anionic surfactants: they have negatively charged head groups. Anionic surfactants dis-
sociate in water to form an anion and a cation. They are often used in the chemical EOR
processes because they efficiently reduce IFT. They are also used due to their low adsorp-
tion on reservoir rocks compared to other surfactants. Sulfonate is the most popular an-
ionic surfactant used in EOR processes.

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 13
•Cationic surfactants: The head group of cationic surfactant has a positive charge. The
surfactant molecule contains also an inorganic anion. Cationic surfactants are highly ab-
sorbed in sandstone rocks because sandstone has a negative charge on its surfaces. Their
use is very limited in sandstone [25][11]. However, they can be used in carbonate reser-
voirs to alter their wettability because they bear the same charge as the surface of the
carbonate minerals [22].
•Nonionic surfactants: Nonionic surfactant head group has no charge. Nonionic surfac-
tants have highly polar groups; they are highly soluble in water. They are used as co-
surfactants in addition to other surfactants. They are tolerant to high salinity but their
performance in lowering IFT is poor as compared to anionic surfactants.
•Amphoteric or zwitterionic surfactants. They can have two active groups, an ionic group
and a nonpolar group. They are tolerant to salinity and temperature.
Critical micelle concentration
Irrespective of the nature of surfactants, their phase behavior is characterized by a certain con-
centration called Critical Micelle concentration (CMC). CMC is the surfactant concentration
above which micelles2are formed spontaneously. It is an important parameter as it defines the
concentration above which the physico/chemical properties of the surfactant solution are al-
tered. The change affects the properties such as the surface tension, the conductivity, and the
turbidity of the solution [21]. Figure 2.7 shows that at low surfactant concentration, surfactant
has no effect on the surface tension (zone 1 in the figure). When the concentration is increased,
the surface tension starts to decrease due to the effect of surfactant (Zone 2) until the CMC is
reached (Zone 3). An increase of the surfactant concentration above CMC yields the increase of
the micelles in solution, but will not have any effect on the surface tension.
In EOR projects, the concentrations of the surfactant are kept above CMC considering the
surfactant loss by adsorption during flooding.
2Micelles: Aggregate of surfactant molecules formed because of the thermodynamics between the solvents.

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 14
Figure 2.7: Critical Micelle Concentration [2]
CMC values varies from 10¡5to 10¡1mol/l for different types of surfactants [21].
2.5 Surfactant Flooding as EOR process
2.5.1 Interfacial tension reduction
Surfactants are used to recover the trapped oil after water flooding. The residual oil is trapped
by capillary pressure between oil and water. During the water flooding, the water pressure is
often not sufficient to overcome this high capillary pressure required to move oil out from the
pore throats.
The consequence of surfactant injection in the reservoir is a reduction of the IFT between
the water and the residual oil. For the movement of oil through narrow neck of pores, a very low
oil/water interfacial tension is desirable (0.001 dynes/cm). Drops of residual oil merge together
and locally the oil saturation raises and oil bank is formed. This oil bank flow and recover the

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 15
residual oil as it moves forward. The surfactant flow following prevent the mobilized oil to be
trapped again as it flows. The ultimate residual oil saturation is therefore determined by the
interfacial tension between oil and surfactant solution behind the oil bank.[24]
2.5.2 Wettability reverse mechanism
Wettability is the tendency of a fluid to spread on, or adhere to, a solid surface in the presence of
other immiscible fluids. This is a major factor controlling the location, flow, and distribution of
fluids in a reservoir . [31]
Reservoir wettability varies from strongly water-wet to oil-wet. This property is not always
homogenous within the reservoir. Some reservoirs have heterogeneous wettability; they exhibit
different affinities for oil or water. The oil recovery is closely related to the wettability. Many lab-
oratory experiments have shown that oil recovery decreases with decreased water wetness.[31]
Addition of some specific surfactants to the reservoir can alter this property. The contact an-
gle between the oil and rock can be increased and the rock surface changes from oil-wet to water
-wet. This yields a decrease in the adherence of oil droplet in the rock surface. Consequently,
the oil recovery is enhanced.[31]
The wettability alteration is beneficial for carbonate reservoirs because they are generally
oil-wet or very less water-wet. The wettability alteration is more complex for sandstone reser-
voirs because theirs wettability varies usually from strongly water-wet to strongly oil-wet states.[31]
Finally, the surfactant induced wettability alteration for EOR is still in the stage of laboratory
investigation[31].
Figure 2.8: Shape of oil drop in water-wet or oil-wet reservoir [14]

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 16
2.5.3 Factors affecting the efficiency of surfactant flooding
Surfactant retention in reservoir rock is a major factor limiting the effectiveness of this EOR pro-
cess. In fact, when the surfactant retention is excessive, only a small amount of surfactant will
act in reducing the IFT. The mechanism responsible for surfactant retention is complicated and
is dependent on several factors such as surfactant structure, mineralogy, salinity, clay content,
pH, co-solvent, micro emulsion viscosity and others. For example, the surfactant retention in-
creases in high salinity water.[25]
Retention occurs by precipitation, phase trapping, and adsorption. Phase trapping and ad-
sorption can be prevented by the use of salt tolerant surfactants or by the co-injection of other
chemicals that reduce the hardness of the brine. The adsorption at the rock/fluid interface is
difficult to avoid. Thus, injection of sacrificial chemicals is done in order to block active sites on
the rock that could encourage adsorption of the surfactants. This injection occurs prior to the
surfactant flooding.[25][27]
2.6 Polymer Flooding
When water is injected into a reservoir, it follows the path of least resistance (usually the layers
of highest permeability) to the lower pressure region of the offset producing wells. If the oil in
the reservoir has a higher viscosity than the displacing fluid, it will finger through the oil and
result in a low sweep efficiency. In other terms, the injected fluid will bypass oil[7].
Polymers are then used to achieve favorable mobility ratio during water or surfactant/alkali
flooding. Adding polymers results in an increase of the apparent viscosity of the injected fluid
and a decrease of the rock permeability to water. Both effects combine to reduce the water mo-
bility [26][27]. Low mobility ratio enhances the poor volumetric sweep caused by permeability
contrasts and gravity segregation. Thus, the volumetric sweep under polymer flooding is more
efficient and oil is recovered over shorter time period and at lower water cut[27].
Generally, polymers are injected continuously until 1/3 to 1/2 of the reservoir pore volume is
filled. This polymer injection is then followed by long-term water flooding to push the polymer
slug and the oil bank, toward the production wells[7].
Polymers solutions are also used with surfactant and alkali to assure the same purpose: re-

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 17
duce channeling and give mobility control at the low IFT front. Figure 2.9 gives a comparison
between a water injection and polymer injection. The effect of fingering is clearly reduced in
presence of polymers.
Figure 2.9: polymer flooding [3]
2.6.1 Types of polymers
There are two main types of polymers used in EOR processes. Synthetic polymers and biopoly-
mers.
•Synthetic polymers such as Hydrolyzed polyacrylamide HPAM. They exhibit high vis-
coelasticity. Polyacrylamide adsorbs strongly on mineral surfaces. Thus, the polymer is
partially hydrolyzed to reduce adsorption. The polyacrylamide reacts with a base, like
sodium or potassium hydroxide or sodium carbonate. Hydrolysis converts some of the
amide groups (CONH2) to carboxyl groups (COO), as shown in the following structure
(Figure 2.10). The degree of hydrolysis is the mole fraction of amide groups that are con-
verted by hydrolysis. It ranges from 15 to 35 percent in commercial products.[25] They are
relatively cheap and they increase significantly the viscosity of the water. However, they
are sensitive to high temperature and their performance is deteriorated by high salinity
water and by high shear rates. They are also degraded by chemical oxidation.[27]

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 18
Figure 2.10: Partially Hydrolyzed polyacrylamide [27]
•Biopolymers . They are formed from polymerization of saccharide molecules in a fermen-
tation processes. They are extremely pseudoplastic. Their performance is insensible to
salinity and the shear degradation is absent for these polymers. Yet, they are sensitive to
bacterial attacks in low temperature regions of the reservoir. The use of an appropriate
biocide solves this problem. Xanthan gum is an example of biopolymer widely used. The
structure of Xantham is shown is figure 2.11.[25][27]
Figure 2.11: Molecular stucture of Xantan [25]
2.6.2 Polymer flow in porous media
Polymer Retention
Poor performance of polymer flooding can be caused by the failure of the polymer to propagate
over long distances. This poor polymer propagation could be attributed to the retention of the

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 19
Figure 2.12: Polymer retention in porous media [28]
polymer in the reservoir. Polymer retention occurs by precipitation, hydrodynamic entrapment,
adsorption on the surfaces of large pores and by mechanical entrapment in small pores[13][28].
Figure 2.12 shows the different mechanisms of polymer retention. Retention level depends upon
the lithology, the rock permeability, the brine salinity, the rock surface, the polymer type, molec-
ular weight of the polymer, polymer concentration and temperature[25][28].
Inaccessible Pore Volume
A fraction of the connected pore volume in porous media is occupied by water without polymer,
in equilibrium with polymer solution. The entrance radii of these pore spaces are too tiny to
allow the polymer molecules to flow through it[25].
The volume of those pores that cannot be accessed by polymer molecules is called inacces-
sible pore volume (IPV). IPV varies from 1 to 30 percent PV [25].
IPV is dependent upon the medium permeability, porosity, salinity, polymer molecular weight
and pore size distribution.

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 20
Polymer Rheology in porous media
The viscosity ¿define the resistance of a fluid to shear or tensile stress. It is given by the following
equation where ¿is the shear stress and °the shear rate.
¹Æ¿
°(2.3)
Fluids are either Newtonian or non-Newtonian. When the viscosity is independent of the
flow rate the fluid is called Newtonian. For synthetic polymer solutions used in polymer flood-
ing, the viscosity is dependent on shear rate. Figure 2.13 presents the experimental results where
the relationship between the viscosity of the polymer solution and the shear rate was investi-
gated. The apparent viscosity3of the solution decreases with increasing shear rate[27]. The
fluids that exhibit this characteristic are said to be shear thinning.
Figure 2.13: Apparent viscosity vs shear rate at fixed salinity for different xanthan concentrations
[27]
High shear rates will appear at injections wells. This behavior is desirable from the stand-
point of injection. Yet, it is undesirable in terms of sweep and recovery ¡especially in hetero-
geneous media. The share rate declines with distance from the injection well, and polymer
solutions get back their high viscosity as they flow in the reservoir[27].
Permeability reduction
The polymer retention and absorption causes the reduction of the apparent permeability. The
rock permeability reduction can be defined as the ratio of water to polymer solution permeabil-
3The apparent viscosity ´is used to describe the polymer solution viscosity in porous media (15)

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 21
ities at same flowing conditions, the permeability reduction Rkis:
RkÆkw
kp(2.4)
kw: rock permeability when water flows
kp: rock permeability when polymer flows
Permeability Reduction factor R is often used to estimate quality of the polymer solution.
The permeability reduction depends on polymer concentration, salinity, permeability of the
medium, molecular weight of the polymer and pore structure of the medium[25].
Relative permeabilities in polymer flooding
The irreducible oil saturation in polymer flooding is equal to the irreducible oil saturation in
water flooding. Moreover, the change in solution viscosity do not affect relative permeabilities
of the displacing and displaced fluids. Thus, the relative permeabilities in polymer flooding are
the same as those measured in water fooding.[25][27]
2.7 Alkaline flooding
Alkaline flooding is the injection of alkaline chemicals such as hydroxides, carbonates or or-
thosilicates of sodium. These chemicals react with petroleum acids and form in-situ surfac-
tants. IFT reduction and rock surface wettability alteration are the EOR mechanism in alkaline
flooding.[30]
Combined with surfactant, the addition of alkali lowers the surfactant adsorption. This is
because the alkali increases pH in the reservoir[25].
2.8 Surfactant Polymer flooding (SP)
Owing to the surfactants cost, only a small surfactant slug is injected with water in order to mo-
bilize the residual oil. However, this slug can finger into the oil bank causing a poor volumetric
sweep.

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 22
A possible solution is to use a subsequent polymer slug. The polymer slug has high viscosity
and enhance the sweep efficiency. The combination of surfactant and polymer decreases both
mobility ratio and interfacial tension of the process which ultimately increases the oil recovery
[24]. Figure 2.14 shows the phases and positions in a surfactant polymer flooding.
Figure 2.14: Surfactant polymer flooding [14]
2.9 Alkaline Surfactant Polymer Flooding (ASP)
Alkaline-Surfactant ¡Polymer (ASP) flooding is the combination of polymer, surfactant and al-
kaline flooding. The synergy of alkali, surfactant, and polymer floods makes ASP flooding the
most efficient chemical EOR technique. The oil recovery using ASP process can be summarized
as follows[25]:
• The main role of alkali is to limit the polymer and surfactant adsorption at the rock in-
terface. Furthermore, alkali convert the acidic component of the oil to soaps and reduce
IFT.
• The polymer flooding improves the macroscopic sweep efficiency.
• Surfactant’s addition results in an increase of the capillary number and subsequent de-
crease of the residual saturation oil.

CHAPTER 2. LITERATURE REVIEW ON CHEMICAL FLOODING 23
Figure 2.15: ASP flooding process [4]

Chapter 3
Simulation of Chemical EOR processes:
Polymer, Surfactant Flooding with
Eclipse-100
3.1 Surfactant flood model
The ECLIPSE surfactant model does not aim to model the detailed chemistry of a surfactant pro-
cess, but rather to model the consequences of the injection of surfactants in the aqueous phase. In
ECLIPSE 100 the distribution of injected surfactant is modeled by solving a conservation equation
for surfactant within the water phase. The surfactant concentrations are updated fully-implicitly
at the end of each timestep after the flows of water, oil and gas have been computed. The surfac-
tant is assumed to exist only in the water phase, and the input to the reservoir is specified as a
concentration at a water injector . [26]
The presence of surfactant can affect reservoir performances in different ways:
• Change of the oil-water surface tension change: surfactants affects the capillary pressure
and the oil and water relative permeabilities.
• Surfactants may modify the water properties.
• The adsorbed surfactant can affect the wettability of the rock.
24

CHAPTER 3. SIMULATION OF CHEMICAL EOR PROCESSES: POLYMER, SURFACTANT FLOODING WITH ECLIPSE-100 25
Eclipse Surfactant Model does not allow a chemical injection simulation, it only reproduce
the effect of surfactant flooding by changing the parameters above.
3.2 Polymer flood model
The flow of the polymer solution through the porous medium is assumed to have no influence
on the flow of the hydrocarbon phases. The standard black oil equations are used to describe
the hydrocarbon phases in the model. Five -component model (oil/ water/ gas/polymer/ brine) is
used. [26]
The detailed descriptions of the surfactant and polymer models are presented in Appendix
A.

Chapter 4
Heidrun oil and gas Field
Introduction and geology of Heidrun Field
Heidrun field was discovered in 1985 by Conoco, with estimated 182.1 MSm3 STOOP , 46.5 bil-
lion Sm3 IGIP and 2.2 million tonnes of natural gas liquids (NGL). It was brought on stream
in October 1995. The oil produced from Heidrun is shipped to Statoil’s crude oil terminal at
Mongstad, and the gas goes to Tjeldbergodden through a pipeline. In 2001 Heidrun was con-
nected to Åsgård pipeline, transporting the gas to Kårstø and from there to Dornum in Germany.
The Heidrun field lies predominantly within block 6507/7, with an eastern extension into block
6507/8 Figure 4.1. The reservoir is 2,300m deep beneath the seabed.[5][18]
Heidrun is located at the transition between the Halten Terrace and the southwest-plunging
Nordland ridge. The structure is a large horst1block highly faulted and tilted. Heidrun has been
formed during the Kimmerian extensional tectonic phase in the Late Jurassic-Early Cretaceous.
It consists of sandstone reservoirs: Garn, Ile, Tilje and Åre. Hydrocarbons were sourced from
the Fangst Group, Tilje formation and Are formation. The accumulation is sealed by overlaying
cretaceous shales[18]. The stratigraphy of Heidrun is presented in Figure 4.2.
1Horst is the raised fault block bounded by normal faults [9]
26

CHAPTER 4. HEIDRUN OIL AND GAS FIELD 27
Figure 4.1: Heidrun location [29]
Figure 4.2: Stratigraphy of Heidrun [29]

Chapter 5
3D numerical flow simulation
5.1 3D simulation model description
A 3D synthetic model of Heidrun field I-segment was used to investigate the efficiency of poly-
mer and surfactant flooding to improve oil recovery. For simplification, the porosity and per-
meability are supposed to be constant for all cells within the same layer. Table 2 gives the main
characteristics of the model.
Figure 5.1: Heidrun I-Segment 3D-view
28

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 29
The model initially included two geological formations: Low Tilje (layers 1-17 in the model)
and Åre (layers 18-58 in the model) with different reservoir properties. Each formation has one
pair of wells: injector and producer.
insert table
The simulation in this project will only concern a part of Åre formation. The cells in the layer
1 to 17 describe the low Tilje formation. These cells are deactivated during the simulation.
The active cells are presented in the 3D model of the simulation Figure 5.2. WI-AA is the
injection well; PROD-AA is the production well.
Figure 5.2: Simulation 3D model
The phases considered in the model are oil, gas, dissolved gas and water (brine, polymer/
surfactant). The main properties of reservoir fluids and injected fluids are shown in Table 3.
insert table
All the necessary data were provided by Statoil for Experts in Team Work projects 2015 Hal-
tenbanken village except Surfactant proprieties, which were taken from the master thesis of Ma-
heshwari in IPT NTNU, 2011 [16].

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 30
Åre reservoir model consists of good sandstone and is characterized by heterogeneous lay-
ers.
The input data files are enclosed in Appendix B.
Modelling EOR were performed based on:
1. The change of injected water-polymer solution mobility due to the change in viscosity
depend-ing on polymer concentration (polymer flooding case).
2. The change of the oil and water relative permeabilities via the capillary number and the
change of the injected water viscosity depending on surfactant concentration. (Surfactant
flooding case)
5.2 Assumptions
• Water flood is scheduled to start at the same time as the field production to support the
reservoir pressure and displace oil towards the production wells
• No desorption of polymer and surfactant
• Shear thinning/thickening propriety of polymer is neglected
• Water oil capillary pressure is supposed equal to zero
• Mixing parameter between polymer and brine is equal to one: perfect blending condition
• Minimum bottom hole allowed in the producer PROD-AA is 140 bara
• Maximum allowed bottom hole pressure in the injector WI-AA is 330bara
• No salinity effect is considered
• Constant polymer and surfactant adsorption for different concentrations
• Liquid production rate of 1000 Sm³/day

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 31
5.3 Simulation results and analysis
Different cases were simulated with fully implicit black oil simulator Eclipse100.The effects of
chemical EOR have been compared to a base case of water flooding.
5.3.1 Water injection rate analysis
In order to make the base case and the different EOR scenarios comparable, it is compulsory to
set the injection rate to a constant. This injection rate has to satisfy the injector and producer
constraints. In addition to satisfy the wells constraints, the optimal water injection rate should
assure a maximum cumulative oil production and the longest plateau rate period of production.
The injection rate values within the range of 1000-1800 Sm³/day were considered.
It is observed that for 1000-1200Sm3/day injection rates, the well bottomhole pressure (WBHP)
of the production well reaches the minimum allowed Figure 5.5. For 1600-1800Sm³/day injec-
tion rates WBHP in the injection well reaches the maximum WBHP after 10 years of production.
Moreover, Figure 5.4 shows that the total oil production decreases with increasing injection rates
for injection rates greater than 1200Sm³/day. Finally, the injection rate 1300Sm³/day is the rate,
which gave the longest plateau period Figure 5.3, maximum cumulative oil and honored the
wells constraints.
All the following simulations were performed with the injection rate 1300Sm³/day.

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 32
Figure 5.3: oil production rate for different injection rates
Figure 5.4: Injection rate effect on the total oil produced for Åre formation

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 33
Figure 5.5: WBH Pressure in the producer for different rates

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 34
Figure 5.6: WBH Pressure vs time in the injector for different rates
5.3.2 Potential of polymer and surfactant flooding
In order to quantify the potential of the surfactant and polymer floodings and compare different
scenarios the following indicators were used:
• The oil recovery factor
• The total oil production
• The oil production rate
Two simulations were initially run to evaluate the potential of polymer and surfactant flood-
ing. 0.5 kg/m³ of polymers were injected in the case of polymer flooding. A 10 kg/m³ surfactant
solution was used for surfactant flooding. The injections lasted during the entire production
period.

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 35
Figure 5.7: Total oil produced for Water/Polymer/Surfactant flooding cases
The results of Figure 5.7 show an additional oil production due to surfactant/polymer injec-
tion.
inseett table
The oil recovery was increased in comparison to the water flooding base case. 2.4 percent
and 1.9 percent additional oil was recovered in cases of polymer and surfactant flooding respec-
tively. The simulations results are encouraging because the recovery of the oil is enhanced.
In the next chapter, sensitivity analysis are carried out to compare different scenario of poly-
mer and surfactant flooding.
5.3.3 Sensitivity analysis on EOR simulation
It is important to conduct sensitivity analysis to understand the effect of different parameters of
chemical flooding on incremental oil production.
In this work, sensitivity analysis will concern the concentration of the chemical solution and
the slug size. The slug sizes are given in fractions of pore volume and concentrations in kg/m³.
The different scenarios are compared to the base case of water flooding.

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 36
Åre formation parameters and the simulated cases are listed in the tables 4 and 5:
insert table
insert table
Effect of Polymer concentration
The first sensitivity analysis deals with the concentration of the polymer solution. It is an im-
portant parameter as it affects the oil recovery and the economics1of the EOR process. The
base case is compared to continuous polymer flooding cases with concentrations ranging from
0.3kg/m³ to 0.9kg/m³.
Figure 5.8 verifies that all the polymer solutions with different concentrations satisfies the
constraints of the injection and production wells. Furthermore, it confirms that the injection of
a polymer solution results in a rise of the pressure in the injection well WI-AA. This is because
polymer solutions have higher viscosity than water, which increase the flow resistance around
the injector and causes an increase in the pressure.
1An important part of the EOR projects is the economic analysis of the cases. It is necessary to have a positive
cost/performance balance. In short, the income from the additional oil produced should cover the expanses of
implementing the EOR process

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 37
Figure 5.8: WHP in WI-AA and PROD-AA vs time for different polymer concentration solutions
Results depicted in Figure 5.9 show that concentration 0.9kg/m³ gives the greatest oil recov-
ery. In fact, highly concentrated solutions give a smaller mobility ratio. The volumetric sweep
efficiency is enhanced and more oil is displaced.

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 38
Figure 5.9: Polymer concentration effect on the recovery factor
However, the high volumetric sweep increases the chance of polymer adsorption and re-
tention. It can be seen from Figure 5.10 that the amount of polymer absorbed increases as the
solution’s concentration increases.
Figure 5.10: Total polymer adsorption vs time for different polymer concentrations

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 39
Figure 5.11 indicates that highly concentrated solutions will also result in high polymer pro-
duction. This brings additional treatment cost that may affect the economy of the project and
makes it less profitable.
Figure 5.11: Polymer production vs time for different polymer concentrations
Concerning the pressure in the reservoir, the results of Figure 5.12 show a decrease in its
values after polymer injection. 0.9kg/m3 solution gives the highest pressure drop. In fact, the
pressure drop is cor-related to the amount of the oil produced. As seen before, 0.9kg/m3 so-
lution gave the highest incre-mental produced oil. Thus, the reservoir pressure dropped more
when this concentration was used.

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 40
Figure 5.12: Reservoir Pressure vs time for base case and different polymer concentration
In case of polymer flooding, more oil is recovered. Hence, the water saturation behind the
trailing edge for a polymer flooding is higher than the water saturation in case of water flooding.
In other words, the water production rate is less in case of polymer flooding. This explains the
results depicted in Figure 5.13. Figure 5.13 also shows that higher concentration give lower water
production rates.

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 41
Figure 5.13: Water production rate vs time for water flooding and different polymer concentra-
tions
Effect of Polymer slug size
The polymer concentration is fixed at 0.5kg/m3. Polymer slug size varies from 0.15PV to 0.35PV .
Figure 5.14 shows the oil recovery for five cases: base case and polymer with slug size of
0.15PV , 0.25PV and 0.35PV and continuous polymer flooding.
The simulation with greater slug size gives the higher oil recovery. The difference in the
recovery is important when comparing a 0.15 PV slug injection with a 0.25 PV slug injection.
However, this differ-ence tends to decrease by increasing the slug 0.35 PV . This is because for a
long slug, it takes more time to see changes on the oil recovery. Moreover, the oil recovery factor
for a 0.35 PV slug is almost the same as the recovery factor for continuous polymer injection,
whereas a big difference in the pol-ymer consumption is observed from Figure 5.15. Therefore,
continuous polymer injection cannot be an optimal solution.

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 42
Figure 5.14: Oil recovery for base case and the different polymer slug sizes
Figure 5.15: Total polymer injection vs time for 0.35PV and continuous polymer flooding
Short slug versus long slug
In this section two scenarios are compared to the base case
• Scenario 1 of injection of 0.5kg/m3 and 0.15PV polymer.
• Senario2 of injection of 0.25 kg/m3 and 0.3PV polymer.
The total quantity of polymer injected is the same, but the slug sizes are different. Figure
5.16 shows the total oil produced for the different scenarios. Small slug size gives slightly better

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 43
increase in oil production compared to longer slug size. Thus, it is better to inject small slugs
with high concentration.
Figure 5.16: Total oil produced vs time for two scenarios with the same amount of polymer
injected
Effect of surfactant concentration
Four different concentrations as 5kg/m³, 10kg/m³, 15kg/m³ and 20kg/m³ were modeled to see
which would return a maximal oil recovery. The surfactant injection lasted during all the pro-
duction time. Figure 5.17 shows that all cases gave improved oil recovery over the base case. The
base case correspond to a surfactant concentration equal to zero. It also shows an increase in
recovery efficiency with the increase of surfactant concentration. Hence, more oil is displaced
by highly concentrated surfactant solutions.

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 44
Figure 5.17: Effect of surfactant concentration on the oil recovery factor
The results of Figure 5.18 show that when the concentration of the solution increases, the
total water produced decreases. This is because some of the water injected occupies the pore
volume after oil displacement, yielding less water production.
Figure 5.18: Total water produced for base case and different surfactant concentration flooding
The injection of surfactant affects the reservoir pressure as shown in Figure 5.19. The con-
tinuous surfactant injection shows a decline in the pressure comparing to the base case. The

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 45
decline is more important for highly concentrated solutions as the oil production from these
solutions is greater.
Figure 5.19: Reservoir pressure vs time for base case and different surfactant concentrations
Effect of surfactant slug size
The surfactant concentration was fixed at 5kg/m³. The slug size varied from 0.15PV to 0.35PV . It
can be seen from Figure 5.20 that longer slugs give higher recovery. The recovery of a continuous
surfactant injection is displayed as well.

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 46
Figure 5.20: Oil recovery factor for different surfactant slug sizes
It can be seen that the oil recovery factor for continuous surfactant flooding and the oil re-
covery factor from a 0.35 PV slug is similar. Yet, it is apparent from Figure 5.21 that surfactant
requirement for 0.35PV slug is less than that for continuous surfactant flooding. Therefore, a
0.35PV slug is better in terms of oil production and surfactant consumption.
Figure 5.21: Total amount of surfactant injected vs time for 0.35 PV slug and continuous surfac-
tant flooding
Finally, high slug sizes contribute to more surfactant adsorption as one can see from the

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 47
figure 5.22 .
Figure 5.22: Total amount of surfactant adsorbed for different slug sizes
Small slug vs large slug
Regarding the comparison between small slug and large slug, two simulations were run.
• Simulation 1: concentration 5kg/m³ and 0.15PV slug
• Simulation 2: concentration 2.5 kg/m³ and 0.3 Slug.
As for polymer flooding, The FOPT Figure indicates that it is preferable to inject small slugs
with high concentration.

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 48
Figure 5.23: Total oil production vs time for short and long surfactant slug
5.3.4 Summary of the sensitivity analysis for surfactant and polymer flood-
ing

CHAPTER 5. 3D NUMERICAL FLOW SIMULATION 49
Figure 5.24: Overview of the sensitivity analysis, a) Surfactant flooding b) Polymer flooding
The results of surfactant and polymer flooding simulations can be summarized as follows:
• The addition of surfactant /polymer enhances the oil recovery
• The oil recovery factor increases with increased amount of surfactant/polymer injected.
Therefore, bigger slugs correspond to higher recovery. Moreover within one slug size,
higher concentrations solutions give higher oil recovery factor.
• Polymer flooding enhances the oil recovery more efficiently than surfactant flooding. The
recovery factor reaches 27.4 percent for the best polymer flooding case (0.35 PV and 0,9
kg/m³). The oil recovery factor in the case of 0.35PV and 20kg/m³ is around 25

Chapter 6
General Discussion
All the results described in this project are based on simulations using Eclipse 100. The sector
simula-tion model is a part of Heidrun field I-segment. The objective was to describe the impact
of Poly-mer/surfactant injection on the oil efficiency. Different slug sizes and solution concen-
trations were compared to come up with the EOR method that can displace maximum of the
residual oil.
• Statoil provided the input data for water and polymer flooding. However, the surfactant
model was based on literature data.
• The reservoir proprieties were considered laterally homogenous.
• Heidrun I segment was under water flooding during all the production period.
• Before simulating the chemical flooding cases, the water injection rate was selected. The
rate 1300Sm³/day was chosen as it gave the longest production plateau, the higher incre-
mental oil production. It also satisfied the injection and production wells constraints.
• Around 10 years are needed to see the effect of the chemical injection.
• The injection of chemicals such as polymers and surfactants improved the oil recovery.
High concentrations and long slug sizes yielded maximum oil recovery. The surfactant
gave a rise in the oil recovery up to 2 percent. The continuous injection of 0.9kg/m3 poly-
mer solution improved the oil recovery by 4.4 percent.
50

CHAPTER 6. GENERAL DISCUSSION 51
• Increasing the slug size and/or the chemical concentration was found to be more favor-
able for the oil recovery enhancement, but it also increased the chemical costs of the EOR
project as more chemicals needed to be injected.
• The comparison between the recovery from long slugs 0.35PV and the recovery from continu-
ous chemical flooding showed that:
The same amount of total oil was produced in both scenarios.
Less chemical consumption for a 0.35 PV slug
• The water cut was reduced when the chemicals were injected .The total water produc-
tion is was than in case of water flooding because some of the water occupied the space
released by the additional displaced oil.
• The surfactant solutions with concentrations from 15kg/m³ to 20 kg/m³ increase very
slightly (negligible) the oil recovery as compared to a solution with a concentration 15kg/m³.Consequently,
the use of concentrations higher than 15kg/m³ is wasteful.
• Increased production from chemical flooding causes more voidage in the reservoir. This
ex-plains the decline in reservoir pressure compared with the water flooding.
• Increased amount of chemical injected leads to more adsorption/retention.
• A large amount of residual oil remains in the reservoir after polymer or surfactant flooding.
• For the same quantity of chemicals used, it is better to inject small slug with high concen-
tration rather than long slug with low concentration.
Limitations of the results
• • Many simplifying assumptions were taken in this work. So, one should be careful while
analyz-ing these results. In real life, the reservoirs are highly heterogeneous and the cap-
illary pres-sure is less favorable to oil displacement. Additional simplifications were done
for polymer and surfactant simulation models:

CHAPTER 6. GENERAL DISCUSSION 52
Polymer flooding: The shear thinning/thickening property was neglected. The mixing
parameter was assumed to equal to one and the adsorption function was assumed not
changing with polymer concentration.
Surfactant flooding: The effect of surfactant flooding was limited to the change in wa-
ter PVT proprieties and relative permeabilities. This is because the capillary pressure was
taken zero. The surfactant adsorption was supposed constant.
• Other limitations of the results are due to the models used by the simulator. Field prop-
erties such as water hardness, pH, temperature, clay content. . . alter the efficiency of the
chemical flooding. Eclipse 100 does not account the impact of these characteristics. In
addition, not all surfactants or polymers can be used in all reservoir/crude oil configura-
tions. Eclipse 100 does not take in consideration the type of chemical used.

Chapter 7
Conclusions and recommendations
To investigate the feasibility of surfactant/polymer flooding in the synthetic model of Heidrun
field, a polymer/surfactant model was developed in Eclipse 100. Many simulations were con-
ducted. Polymer and surfactants are promising methods for enhancing the oil recovery. Sur-
factants yield mobilization of the residual oil trapped in the pores. Polymer addition allow a
mobility control.
The overall conclusions of polymer/surfactant simulation runs are summarized as follows:
• The surfactant/polymer flooding was started in 2017.Before simulating the chemical flood-
ing cases, it was necessary to set the injection to a constant. The results showed that the
rate 1300Sm³/day was the optimal injection rate.
• The oil recovery factor was enhanced by the addition of polymer/surfactant.
• High recovery was obtained by increasing either the surfactant/polymer concentration or
its slug size. Injecting 0.35PV , 10kg/m³ of surfactant could increase the recovery factor
by 1.86 percent and injecting 0.25PV , 20kg/m³ of surfactant could increase the recovery
by 1.96 percent. Injecting 0.9kg/m³, 0.15PV polymer slug increased the recovery by 1.88
percent and 0.35PV , 0.7kg/m³ polymer solution enhanced the recovery by 3.4 percent.
• The oil recovery factor increased by up to 4.4 percent and 2.1 percent in cases of polymer
and surfactant flooding respectively.
53

CHAPTER 7. CONCLUSIONS AND RECOMMENDATIONS 54
The success of surfactant /polymer flooding does not depend only on the oil recovery factor.
It is necessary that the (surfactant or polymer) EOR project is economically profitable in the
long term. In other words, the balance between the incurred cost and the performances has
to be satisfactory. Thus, an economical evaluation of the previous simulation cases should be
conducted to identify the optimal case. The economic study would involve many parameters
such as: oil price, cost of the chemicals and their availability/storage, the environmental impact
and others.
A large amount of oil remains in the reservoir after surfactant or polymer flooding. As a fu-
ture work it can be interesting to test a combination of polymer and surfactant. This combina-
tion will reduce the IFT and improve the sweep efficiency in the same time. Polymer surfactant
flooding (SP) would yield a better oil recovery as compared to surfactant or polymer flooding.

Appendix A
Acronyms
FTA Fault tree analysis
MTTF Mean time to failure
RAMS Reliability, availability, maintainability, and safety
55

Appendix B
Additional Information
This is an example of an Appendix. You can write an Appendix in the same way as a chapter,
with sections, subsections, and so on.
B.1 Introduction
B.1.1 More Details
56

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Curriculum Vitae
Name: Your Name
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Date of birth: 1. January 1995
Address: Nordre gate 1, N–7005 Trondheim
Home address: King’s road 1, 4590 Vladivostok, Senegal
Nationality: English
Email (1): your.name@stud.ntnu.no
Email (2): yourname@gmail.com
Telephone: +47 12345678
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Language Skills
Describe which languages you speak and/or write. Specify your skills in each language.
Education
• School 1
• School 2
• School 3
Computer Skills
• Program 1
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BIBLIOGRAPHY 61
• Program 2
• Program 3
Experience
• Job 1
• Job 2
• Job 3
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