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Role of surfactant mass transfer and the formation of an oil bank in displacement of oil through porous media

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Role of surfactant mass transfer and the formation of an oil bank in displacement of oil through porous media
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Surfactant mass transfer and the formation of an oil bank in displacement of oil through porous media
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Chiang, Michael Yao-Chi, 1950-
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English
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xiii, 141 leaves : ill. ; 28 cm.

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Subjects / Keywords:
Adsorption ( jstor )
Alcohols ( jstor )
Brines ( jstor )
Interfacial tension ( jstor )
Oil recovery ( jstor )
Salinity ( jstor )
Slugs ( jstor )
Sulfonates ( jstor )
Surfactants ( jstor )
Viscosity ( jstor )
Oil fields -- Production methods ( lcsh )
Secondary recovery of oil ( lcsh )
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bibliography ( marcgt )
non-fiction ( marcgt )

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Thesis--University of Florida.
Bibliography:
Includes bibliographical references (leaves 135-140).
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Typescript.
General Note:
Vita.
Statement of Responsibility:
by Michael Yao-Chi Chiang.

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University of Florida
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University of Florida
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Copyright [name of dissertation author]. Permission granted to the University of Florida to digitize, archive and distribute this item for non-profit research and educational purposes. Any reuse of this item in excess of fair use or other copyright exemptions requires permission of the copyright holder.
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ROLE OF SURFACTANT MASS TRANSFER AND THE FORMATION OF
AN OIL BANK IN DISPLACEMENT OF OIL THROUGH POROUS MEDIA













By

Michael Yao-Chi Chiang


A DISSERTATION PRESENTED TO THE GRADUATE COUNCIL OF
THE UNIVERSITY OF FLORIDA
IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE
DEGREE OF DOCTOR OF PHILOSOPHY



UNIVERSITY OF FLORIDA


1979




ROLE OF SURFACTANT MASS TRANSFER AND THE FORMATION OF
AN OIL BANK IN DISPLACEMENT OF OIL THROUGH POROUS MEDIA
By
Michael Yao-Chi Chiang
A DISSERTATION PRESENTED TO THE GRADUATE COUNCIL OF
THE UNIVERSITY OF FLORIDA
IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE
DEGREE OF DOCTOR OF PHILOSOPHY
UNIVERSITY OF FLORIDA
1979


To Mother & Father
Digitized by the Internet Archive
in 2011 with funding from
University of Florida, George A. Smathers Libraries with support from LYRASIS and the Sloan Foundation
http://www.archive.org/details/roleofsurfactantOOchia


ACKNOWLEDGMENTS
Greatest thanks and appreciation to Professor Dinesh 0.
Shah in so many ways that are beyond words and expression.
This dissertation would not be possible without his guidance
and numerous suggestions.
I wish to thank members of the Supervisory Committee
for their valuable time and advice. I further wish to
extend my appreciation to the supporting staff: R.L. Baxley,
T.P. Lambert, J.W. Kallaway, M.R. Jones and D. Scott for
their help.
Also, I wish to express my appreciation to the National
Science Foundation-Research Applied to National Needs
(NSF-RANN, Grant No. AER 75-13813), Department of Energy,
and a consortium of 20 major oil and chemical companies for
their financial support for this study.
Finally, I wish to express my gratitude to my parents
and my wife for their encouragement and assistance
throughout the study.
iii


TABLE OF CONTENTS
Page
ACKNOWLEDGMENTS iii
LIST OF TABLES vii
LIST OF FIGURES viii
ABSTRACT xi
CHAPTER
I INTRODUCTION 1
1.1 Capillary Number 6
1.2 Interfacial Tension 8
1.2.1 Parameters 9
1.2.2 Mechanism 12
1.2.3 Application 14
1.3 Mobility 17
1.3.1 Permeability 18
1.3.2 Relative Permeability 21
1.4 Scope 24
II A CORRELATION OF INTERFACIAL TENSION WITH OIL
DISPLACEMENT EFFICIENCY FOR EQUILIBRATED AND
NON-EQUILIBRATED OIL/BRINE/SURFACTANT SYSTEMS 28
2.1 Introduction 28
2.2 Materials and Methods 29
2.2.1 Surfactant Solutions 29
2.2.2 Interfacial Tension Measurement 30
2.2.3 Contact Angle in Quartz/Brine/Oil
Systems 30
2.2.4 Surfactant Concentration Measurements. 31
2.2.5 Oil Displacement in Porous Media 31
iv


Page
2.3 Results and Discussion 32
2.3.1 Effect of Equilibration 32
2.3.2 Effect of Isobutanol 49
2.3.3 Oil Displacement Mechanism 56
2.4 Conclusions 61
III OIL DISPLACEMENT EFFICIENCY OF HIGH SALINITY
FORMULATIONS 63
3.1 Introduction 63
3.2 Materials and Methods 65
3.3 Results and Discussion 71
3.4 Conclusions 83
IV EFFECT OF OIL BANK INJECTION ON OIL
DISPLACEMENT EFFICIENCY 84
4.1 Introduction 84
4.2 Materials 86
4.3 Methods 87
4.3.1 Formulations 87
4.3.2 Oil Displacement 88
4.4 Results and Discussion 92
4.4.1 High Surfactant Concentration
System 92
4.4.2 Low Surfactant Concentration
System 109
V CONCLUSIONS AND RECOMMENDATIONS 119
5.1 Conclusions HO
5.1.1 Effects of Equilibration and
Artificial Oil Bank 119
5.1.2 Concentrated Surfactant System 121
5.1.3 Dilute Surfactant System 121
5.1.4 High Salinity System 122
5.1.5 Summary 122
5.2 Recommendations 123
v


Page
APPENDICES
I DESCRIPTION OF THE SURFACTANTS 126
II OIL DISPLACEMENT IN POROUS MEDIA 128
II. 1 Apparatus 128
II. 2 Procedure 133
BIBLIOGRAPHY 135
BIOGRAPHICAL SKETCH 141
vi


LIST OF TABLES
Table Page
2-1 The Effect of Equilibration on Oil Displace
ment in Sand Packs at 25C. (0.05% TRS 10-80
in 1% NaCl vs. n-Octane) 36
2-2 Interfacial Tension and Emulsification Time
of 0.05% TRS 10-80 in 1% NaCl vs. n-Octane
at 25C 44
2-3 The Effect of IBA on Emulsification Time and
Oil Displacement Efficiency 53
3-1 Oil Recovery of 1.5% TRS 10-410 +2.5% EOR 200
+ 3% IBA in X% NaCl Displacing n-Dodecane in
Berea Cores 68
3-2 Oil Recovery of 1.5% TRS 10-410 +2.5% EOR 200
+ 3% IBA in X% NaCl Displacing n-Dodecane in
Sand Packs 69
3-3 Viscosity of Surfactant Slug (2.5% TRS 10-410
+ 2.5% EOR 200 + 3% IBA in X% NaCl) 70
4-1 Oil Recovery of 5% TRS 10-410 + 3% IBA in X%
NaCl Displacing n-Dodecane in Sand Packs 90
4-2 Oil Recovery of 0.05% TRS 10-80 in 1% NaCl
Displacing n-Octane in Berea Cores 91
4-3 Effect of Sacrificial Agents and Oil Bank in
Oil Recovery 110
vii


LIST OF FIGURES
Figure Page
1-1 Schematic Diagram of Surfactant/Polymer Flooding
Process 4
1-2 Flow Through Porous Medium 19
1-3 The Effect of Water Saturation on Oil and Water
Relative Permeability and Total Mobility 23
2-1 The Effect of Surfactant Concentration on Oil
Displacement in Sand Packs at 25C 33
2-2 0.05% TRS 10-80 in 1% NaCl Displacing n-Octane
in Sand Packs at 25C 37
2-3 Mass Transfer Process for Surfactant Monomers 39
2-4 Contact Angle of n-Octane vs. 0.05% TRS 10-80
in 1% NaCl on Ouartz 45
2-5 Contact Angle of n-Octane vs. Equilibrated 0.05%
TRS 10-80 in 1% NaCl 46
2-6 Continuous Injection of 0.1% TRS 10-410 + 0.06%
IBA in X% NaCl Displacing n-Dodecane in Sand
Packs at 25C 50
2-7 Continuous Injection of 0.1% TRS 10-410 + 0.06%
IBA in X% NaCl Displacing n-Dodecane in Sand
Packs at 25C 51
2-8 Oil Recovery in Berea Cores at 25*C. (Continu
ous Injection of 0.1% TRS 10-410 + 0.06% IBA
in X% NaCl Displacing n-Dodecane 57
2-9 Oil Displacement of 0.1% TRS 10-410 + 0.06%
IBA in 2% NaCl Vs. n-Dodecane 59
viii


Figure Page
3-1 The Effect of Salinity on Solubilization
Behavior 72
3-2 The Effect of Salinity on Interfacial Tension 73
3-3 The Effect of Salinity on Percent Tertiary Oil
Recovery by 1.5% TRS 10-410 +2.5% EOR 200 +
3% IBA of n-Dodecane in Sand Packs at 25C 75
3-4 The Effect of Sacrificial Agent on Solubili
zation Behavior at 25C 77
3-5 The Effect of Sacrificial Agent on Tertiary
Oil Recovery in Berea Cores at 25C 78
3-6 Tertiary Oil Recovery of 1.5% TRS 10-410 +
2.5% EOR 200 + 3% IBA in X% NaCl +0.3% STPP
+ 0.3% Na CO. in n-Dodecane in Berea Cores
at 25*C..7... 80
3-7 The Effect of Salinity on pH of 1.5% TRS 10-410
+2.5% EOR 200 + 3% STPP +0.3% Na CO in X%
NaCl at 25C .... 82
4-1 Viscosity of Mobility Buffer 89
4-2 The Effect of Surfactant Slug Size on Tertiary
Oil Recovery in Sand Packs 93
4-3 Tertiary Oil Recovery Flooding History 95
4-4 The Effect of NaCl Concentration on Percent
Tertiary Oil Recovery by 5% TRS 10-410 + 3%
IBA of n-Dodecane in Sand Packs 96
4-5 Tertiary Oil Recovery of 5% TRS 10-410 + 3%
IBA in X% NaCl on n-Dodecane in Berea Cores
at 25 C 97
4-6 Final Oil Saturation in Sand Packs 5% TRS 10-410
+ 3% IBA in X% NaCl Displacing n-Dodecane at
25 C 99
ix


Figure Page
4-7 Production History of 5% TRS 10-410 + 3% IBA
in o.5% NaCl 101
4-8 Production Response Curves of Sand Pack
No. 100-29 102
4-9 Schematic Diagram of Oil Bank Formation on
Oil Recovery 106
4-10 The Effect of Artificial Oil Bank Slug Size
on Final Oil Saturation in Berea Cores at
25C 112
4-11 Oil Displacement of 0.05% TRS 10-80 + 0.05%
Na2C03 + 0.05% STPP in 1% NaCl vs. n-Octane H4
4-12 Adsorption and Partitioning of Surfactant
in Porous Medium 117
II-l Flow Through Porous Media Apparatus 131
II-2 Permeability Determination Plot of Sand
Pack 15-43. 134
x


Abstract of Dissertation Presented to the Graduate
Council of the University of Florida in Partial
Fulfillment of the Requirements for the Degree
Of Doctor of Philosophy
ROLE OF SURFACTANT MASS TRANSFER AND THE FORMATION OF
AN OIL BANK IN DISPLACEMENT OF OIL THROUGH POROUS MEDIA
By
Michael Yao-Chi Chiang
June, 1979
Chairman: Professor Dinesh 0. Shah
Major Department: Chemical Engineering
The oil displacement in the surfactant/polymer flooding
process occurs in three stages: first, oil ganglia are
released from the capillaries by the surfactant slug, then
they are dislodged and coalesce to form an oil-water bank,
finally, the bank is driven out of the porous media by the
polymer solution. In this study, a novel idea of injecting
a slug of oil to initiate the oil-water bank is proposed
and investigated for both the small slug concentrated surfac
tant system and the large slug dilute surfactant system.
To further improve the oil displacement efficiency, the
effects of the size of the injected oil bank slug and the
sacrificial chemicals are studied.
For the concentrated surfactant system, the oil/water
relative permeability curve is suggested to account for the
xi


observed improvement in oil recovery efficiency. For the
dilute surfactant solution, the surfactant adsorption and
the integrity of the oil bank are the determining factors.
Surfactant mass transfer from the injected fluid to the
reservoir fluid is the key to control the said factors and
to ensure the success of the process.
A high salinity formulation consisting of petroleum
sulfonate, alcohol and electrolytes with the ethoxylated
sulfonate is employed to study its ability to displace oil
in porous media. The solubilization parameters and the
interfacial tension are measured. The oil displacement
efficiency correlates with the optimal salinity of the system.
For Berea cores, the sacrificial chemicals are incorporated
to improve oil recovery. The results are explained in terms
of the liquid-liquid interaction and the pH variation caused
by the added sacrificial chemicals.
Finally, the correlation of capillary number vs. oil
recovery are examined from a new perspective. The interfacial
tension, the emulsification time, and the oil displacement
for various combinations of the non-equilibrated and the
equilibrated aqueous and oleic phases are determined. The
oil displacement results are explained in terms of interfacial
viscosity, emulsification time, and interfacial tension
in vitro vs. in. situ. Also, the role of alcohol in
xii


improving the oil recovery process is delineated. Moreover,
it is pointed out that the ultralow interfacial tension
achieved in vitro may not be achieved ini situ and, in certain
cases, the interfacial viscosity and not the bulk viscosity
may be a predominant factor influencing the oil displacement
efficiency.
xiii


CHAPTER I
INTRODUCTION
Since the first oil recovery patent (Atkinson, 1927)
involving surface-active agents was issued, the study of the
surfactant flooding method has received ever-increasing
attention by both oil industries and academic institutions.
Due to the worldwide oil price increase in recent years, the
economic constraint on the surfactant flooding method has been
drastically reduced. Also the present national priority of
energy independence from the Organization of Petroleum Exporting
Countries (OPEC) necessitates the development of workable
processes in the near future. In view of the expected world
wide shortage of oil, it is desirable to improve the domestic
production until an alternative energy source can be developed.
Therefore, the search for more oil becomes more urgent than ever.
The production of crude oil from the petroleum reservoir
can be divided into three stages: primary, secondary and tertiary.
In the primary stage, the oil is forced out of the reservoir by
the pressure of the entrapped gases. When the oil production
declines as sufficient gas is released from the formation or
is produced along with oil, water or gas is injected to increase
the pressure required to drive the oil. This constitutes the
secondary oil recovery stage. When no more oil comes out,
1


2
thermal or chemical flooding techniques can be employed to
improve the oil recovery from the reservoir; this is commonly
referred to as the tertiary oil recovery.
According to Simpson (1977) the combined oil recovery
by the primary and the secondary processes is about 30% of the
oil-in-place, while the tertiary oil recovery process is
estimated to recover another 20%. That means that almost 50%
of the oil-in-place is considered unrecoverable (Geffen, 1975).
Currently, there are four tertiary oil recovery methods
considered to be promising, namely, the carbon dioxide flood
ing, the surfactant/polymer flooding, the hydrocarbon miscible
flooding, and the thermal recovery. Based on the energy
balances for energy input and output for any of these techniques,
Carpenter and Davies (1976) have shown that carbon dioxide
flooding and surfactant/polymer flooding processes are the most
efficient processes. However, due to problems in mobility
control and pressure requirements as well as the difficulty
in obtaining cheap carbon dioxide on site, the carbon dioxide
flooding method is not favored. Therefore, the surfactant/
polymer method is believed to be one of the most promising
techniques for enhanced oil recovery.
The surfactant/polymer process consists of an injection of
a 5-20% pore volume (PV) surfactant slug carrying 5-15%
petroleum sulfonate, alcohol, and brine or oil into the porous


3
medium. It is followed by a 50% pore volume thickened mobility
buffer solution according to the conformance principle, i.e.,
the mobility of the displacing fluid should not be greater than
that of the displaced fluid. If this condition is not satisfied,
fingering of the driving fluid takes place in porous media and
the integrity of the injected slug is lost. Finally, brine is
injected to displace all other fluids.
Figure 1-1 is a schematic representation of the surfactant/
polymer process. It shox^s that in a waterflooded porous medium,
the discontinuous oil ganglia are mobilized and the resulting
coalescence forms an oil/water bank followed by the surfactant
slug, a polymer-thickened mobility buffer solution and a brine
chaser. Carpenter and Davies (1976) speculated that of the
recoverable tertiary oil, 60% can be recovered by the surfactant/
polymer method, i.e., approximately 12% of the original oil-in
place. Furthermore, they estimated that it takes 5-8 pounds of
commercial petroleum sulfonate to recover one barrel of crude
oil. Thus, economicallv, the future of the surfactant/polymer
process is very promising.
Surfactant formulation injected in tertiary oil recovery
can be divided in two groups, namely, the oil external systems
and the water external systems. However, irrespective of the
form in which they are injected, their performance ultimately
depends upon the phase equilibria relationships when such


INJECTION
FLOOD
WATER
SURFACTANT SLUG
I
- u -
77777777,
PRODUCTION
^ OIL-WATER
^BANlT
RESIDUAL
OIL ~AN D~
RESIDENT
BRINE
7r7T777
THICKENED
FRESH
WATER
Figure 1-1 Schematic Diagram of Surfactant/Polymer Flooding Process


5
injected slug are diluted by the resident brine and oil in
porous media. It had been shown that the optimal oil recovery
occurred at a specific salt concentration irrespective of
the form in which the slug is injected whether oil external
or water external (Chou & Shah, 1978).
However, the surfactant/polymer flooding process has
certain constraints. The surface activity of the surfactant
is sensitive to salt concentration, particularly, to the di-
and the tri-valent cations. The reservoir temperature, pH,
and wettability, all have a profound influence on the proper
ties of the surfactant solution. Taber (1969) found that the
oil displacement is a unique function of the critical ratio
AP
where AP is the pressure drop across the distance L
and Y is the oil/water interfacial tension. This critical
ratio is an inverse function of the permeability of the rock
(Taber et al., 1973). Furthermore., the surfactant loss may
occur from the injected slug by adsorption, precipitation,
partitioning in oil, and entrapment in pores (due to surfac
tant-polymer association or separate phase formation)(Reed &
Healy, 1977; Trushenski et al., 1974). Therefore, one has to
discern and understand the effects of these factors on surfac
tant behavior in order to predict and improve the oil displace
ment efficiency.


6
1.1 Capillary Number
After waterflooding, the remaining crude oil is found
as discontinuous oil ganglia trapped in the pores of rocks
due to capillarity. These oil droplets will be mobilized
if a high enough viscous force is applied. Thus, for a given
porous medium under a definite pressure, the oil saturation
can be correlated with the ratio between the viscous force
and the capillary force (Leverett et al., 1942; Melrose &
Brandner, 1974). This ratio is called the capillary number,
Vu
N a dimensionless figure written as N = where V is
c ^ c y
the flow velocity in cm/sec, p is the displacing fluid
viscosity in centipoise, and y is the oil/water interfacial
tension in dynes/cm. In calculating the capillary number,
the in situ interfacial tension, the viscosity and the velocity
should be used. However, the values existing in porous medium
are difficult, if not impossible, to estimate. Hence, the
equilibrium interfacial tension, the bulk viscosity and the
average velocity are used for calculation of N^.
Various modifications have been offered for the capillary
number. Moore and Slobod (1956) analyzed a two-pore flow model
and concluded that the wettability of the porous medium should
be included in correlating oil displacement efficiency with
capillary number. They proposed that the capillary number


7
is = "^'CoS'q' where cos0 is the wettability of the rock,
which is measured as the contact angle through the water phase
on the solid surface. Another dimensionless group, the
Pw
viscosity ratio of water to oil, was discussed separately
from the capillary number by Foster (1973) but was considered
together with the capillary number as
(
V y
ycos0
)(
w ^0. 4
by Abrams (1974). The viscosity ratio indicates the relative
velocity of water and oil in a two-phase flow system in porous
medium. More recently, McDonald and Dullien (1976) suggested
AP 1
a tertiary oil recovery number, N = ( )( ), where
i. Jjy u
AP
is the microscopic pressure gradient, y is the interfacial
tension, 1 is the mean length of an oil ganglion and D is the
"structural difficulty index", a measure of the pore structure.
AP
The term when incorporated with the permeability, K, can
Ly
be converted to the capillary number, by the Darcys
law: V = -L An excellent review paper on this subject
has been published by Stegemeier (1977).
Abrams (1974) examined the influence of fluid viscosity,
interfacial tension, and flow velocity on residual oil satura
tion after waterflooding. He showed that the oil saturation
decreased as the capillary number Increased and that after


8
laboratory waterflooding condition, 40% residual oil satura-
_6
tion corresponded to a capillary number of 10
It was proposed by Taber (1969) and Melrose and
Brandner (1974) that the capillary number should be increased
-3 -2
to 10 or 10 before the oil ganglia can be mobilized and
displaced. Since the flow velocity and viscosity of the
fluid can only be increased slightly, the interfacial tension
has to be reduced by 4 orders of magnitude in order to have
a 4 fold increase in the capillary number. A number of
investigators (Taber, 1969; Foster, 1973; Hill et al., 1973)
reported that by adding surface-active compounds (surfactants),
the interfacial tension between the oil/water interface can
be lowered from 30 to 0.001 dynes/cm. Since then, many papers
on the oil displacement by the surfactant/polymer process
have been published (Shah & Schechter, 1977).
1.2 Interfacial Tension
From previous discussion and the works by Reisberg and
Doscher (1956) and Berkeley et al.(1960), it is evident that
the oil/water interfacial tension must be reduced to 0.01 or
0.001 dynes/cm in order to increase oil displacement efficiency.
Water-soluble surfactants such as fatty acid soaps, polyglycol
ether, petroleum sulfonates, and polyoxyalkylene compounds have
been studied in the laboratory and have been shown to be


9
promising for improved oil recovery (Holbrook, 1958).
However, because of their low cost and their ability to achieve
ultralow interfacial tension, petroleum sulfonates have been
studied extensively and tested in the pilot field projects.
1.2.1 Parameters
Typically, the surfactant formulation used in a tertiary
oil recovery process consists of 2-6% petroleum sulfonate and
2-5% alcohol in brine or oil or both. Hill et al. (1973)
reported that the surfactant interfacial activity is a strong
function of the salinity. Using the inbibition-between-two-
glass-slides method, they found that there is a narrow region
of optimal salinity corresponding to a given surfactant con
centration for an efficient displacement of oil drops.
Moreover, this optimal salinity increases as the surfactant
concentration increases and decreases as the average molecular
weight of the sulfonate increases.
A number of investigators have reported that there are
two regions of ultralow interfacial tension: one in a low
concentration region below 0.2%, and the other between 1-10%
surfactant. In the low concentration region the oil brine
surfactant system is strictly a two phase system, i.e., oil
and brine in equilibrium with each other. However, in the
second region, it is a three phase region where the middle
phase contains essentially most of the surfactant and alcohol


10
(Reed & Healy, 1977; Hsieh & Shah, 1977; Wade et al., 1977;
Chan & Shah, 1979). Thus, for several systems containing
petroleum sulfonate, alcohol, brine, and oil, there are two
minima of interfacial tension as a function of surfactant
concentration.
Jones and Dreher (1975) studied the effect of alcohol in
the surfactant formulation used for oil displacement process.
They concluded that the hydrophilic-lipophilic balance (HLB)
of the surfactant is markedly influenced by the type of
alcohol added. The water-soluble alcohol makes the surfactant
more hydrophilic while the oil-soluble alcohol induces
hydrophobicity. Hsieh (1977) showed that there is a difference
of one order of magnitude in interfacial tension at a given
salinity depending on whether isobutanol or hexanol is in the
formulation. In addition, he further showed that not only
the type of alcohol affects the interfacial activity of a
surfactant but also the amount of alcohol used has a profound
influence on the interfacial tension. For the system studied,
as the amount of alcohol in the formulations increases, the
interfacial tension also increases.
A number of investigators (Hsieh & Shah, 1976; Cash et al.,
1976; Chan, 1978) have pointed out that for the same surfactant
system, different interfacial tensions are obtained with
different types of oil, i.e., oils of different molecular


11
structure, chain lengths, etc. Knowing that for a specific
surfactant system, the minimum interfacial tension occurred
only at a specific chain length of the alkane, Cash et al.
(1976) proposed the concept of the Equivalent Alkane Carbon
Number (EACN) for the hydrocarbon oil mixtures. It is
written as
EACN = EEACN X ,
til
where X^ is the mole fraction of the i component of the
mixture. The equation implies the additive nature of each
component species. Conversely, a minimum in interfacial
tension can be detected at a specific surfactant concentration
for any given oil mixture, e.g., crude oils. Then, the
corresponding alkane that exhibits a minimum interfacial
tension at this surfactant concentration can be found and
matched with the oil mixture. Thus, a pure alkane can be
employed to characterize the interfacial tension behavior of
a crude oil in the laboratory.
Furthermore, the brine/oil ratio is a variable in deter
mining the interfacial tension of the system. At a constant
surfactant and alcohol concentration of 8%, Chou et al.(1977)
showed that the interfacial tension is a function of brine/
oil ratio. Likewise, for a low surfactant concentration
system (0.05%), Chiang and Shah (1978) observed that the
interfacial tension varies as the brine/oil ratio changes


12
and a minimum interfacial tension occurs at a certain
brine/oil ratio.
In short, since the properties of an interface will be
affected by changes in either of the two phases involved, the
interfacial tension is a function of variables that change
the bulk properties of the phases. It is clear that the
intrinsic properties such as the type and the amount of
surfactant, alcohol, brine, and oil all have a strong
influence on the interfacial tension of the system. Also,
any extrinsic variables such as the temperature (Chiang
& Shah, 1977; Healy & Reed, 1974) and pH (Hurd, 1976; Holm,
1978) that cause a change in HLB of surfactant plus alcohol
system would also change the interfacial tension at oil/
brine interface.
1.2.2 Mechanism
The elucidation of molecular mechanisms to achieve
ultralow interfacial tension is of considerable interest
among researchers. The classical electrocapillary effect
suggests that the attainment of ultralow interfacial tension
may originate from the electrical charges at the interface.
Indeed, Miller and Scriven (1970) stated that the interfacial
free energy at the brine/oil interface is influenced by the
electrical double layer interaction. Watanabe et al.(1978)
produced a spontaneous emulsification by applying electrical


13
voltage at the interface. Moreover, the study on the elec
trophoretic mobility of the oil droplet in brine (Chiang
et al., 1978), caustic, and surfactant solution (Chan, 1978)
indicate that the maximum surface charge density corresponds
to the minimum interfacial tension. Thus, the ultralow
interfacial tension occurs at the highly charged water/oil
interface.
In addition to the surface charge density effect, for
a dilute surfactant micellar solution-oil system, ultralow
interfacial tension is produced when the surfactant
partition coefficient is close to unity, i.e., the surfac
tant concentration in oil equals that in the brine (Baviere,
1976; Chan, 1978; Wade et al., 1977). It was shown that
for the system composed of petroleum sulfonate, alcohol,
pure hydrocarbon oil, and electrolyte solution, the surfac
tant partition coefficient is a function of the salinity,
the surfactant concentration, the oil chain length (Chan &
Shah, 1978), as well as the alcohol concentration and the
brine/oil ratio (Chiang & Shah, 1978). Baviere (1976)
proposed that the condition for reaching a maximum inter
facial activity is the attainment of maximum surfactant
concentration at the interface. Chan and Shah (1978)
confirmed this by the surface tension measurements.
However, a maximum monomer concentration in aqueous phase


14
should correspond to this mximum interfacial concentration.
Using light scattering and osmotic pressure, Chan and Shah
(1978) also established that there was indeed a maximum
activity in the bulk phase corresponding to this ultralow
interfacial tension. They further found that this concen
tration at which there is a minimum interfacial tension, and
maximum monomer concentration in the aqueous phase would
correspond to the critical micelle concentration (CMC) of the
surfactant remaining in the aqueous phase after equilibration
with oil. Thus, both the monomer concentration in the bulk
phase and at the interface are responsible for achieving
the ultralow interfacial tension.
1.2.3 Application
For a typical surfactant formulation, Healy and Reed (1974)
reported that by adding surfactant and alcohol to the 1:1 v/v
mixture of oil and brine, the surfactant may reside in the
aqueous phase in equilibrium with the excess oil, or in the
oil phase in equilibrium with the excess brine at either low
or high salinities. At the intermediate salinities, a third
"middle" phase forms in equilibrium with excess oil and brine.
Composed of surfactant and alcohol, this middle phase also
solubilizes various amounts of oil and brine at different
salt concentrations. Here, two interfacial tensions can
be measured for the two interfaces existing among these


15
three phases. Within this middle phase region, they further
defined the optimal salinities for phase behavior and inter
facial tension behavior by plotting solubilization parameters
V /V or V /V and interfacial tension y or y
o s w s om mw
against the salinity. The amount of oil or brine solubilized
into the surfactant rich microemulsion phase per unit of
surfactant is V /V or V /V respectively, and the interfacial
os w s
tension between excess oil/microemulsion or microemulsion/
excess brine phases is y or y respectively.
om mw J
As salinity increases, y and V /V increase while
7 'mw o s
y and V /V decrease. The salinity, at which y inter-
om w s mw
sects y or V /V intersects V /V is the optimal
'om os w s v
salinity for interfacial tension behavior, S or phase behavior,
S,, respectively.
9
From the numerous published data on the
and the Scf> (Healy & Reed, 1974; Hsieh & Shah, 1977; Bansal &
Shah, 1977), it is evident that S^ is always nearly the same
as S.. Thus, in many instances, S, is measured when S is

difficult to obtain.
Healy and Reed (1976) found that the maximum oil
recovery occurs at this optimal salinity; accordingly, they
suggested the concept of "controlling" Interfacial tension,


16
i.e. the higher of the two interfacial tensions ( y or
om
y ) controls the oil displacement efficiency. The y
mw 7 om
correlates with the interfacial tension at the surfactant
slug front/oil-water bank interface while the y
'mw
correlates with the interfacial tension at the rear part
of surfactant slug/polymer buffer interface. Low inter
facial tensions at both the surfactant slug front and the
rear are the prerequisite for good oil recovery efficiency.
Consequently, at the optimal salinity when both y and
y are low and equal, a maximum oil recovery is obtained,
mw
This concept of optimal salinity can further be extended
to include other parameters, e.g., surfactant concentration,
alcohol concentration, surfactant/alcohol ratio (Chou et al,,
1977) as well as oil chain length (Chan, 1978) and tempera
ture (Chiang & Shah, 1977). For any given surfactant-
alcohol-oil system, keeping all parameters fixed except
one, the surfactant phase behavior as a function of that
parameter can be studied. If a surfactant-rich phase exists
in equilibrium with both excess brine and excess oil phases
upon equilibration, the solubilization parameter, VQ/Vg
and V /V can be measured as the parameter varies. The
w s
intersection of the two curves then determines the optimal
value of that parameter. Thus, the "middle" phase formation


17
and the subsequent finding of the optimal "parameter" becomes
a convenient tool in screening surfactant formulations for
a given oil and reservoir condition.
1.3 Mobility
After a surfactant slug is injected into a waterflooded
reservoir, the oil ganglia are released from the capillaries
upon contact and together with the connate water, they are
pushed toward the production well. If the displacing fluid
is less mobile than the displaced fluid, a piston-like flow
pattern (or plug-flow) occurs; conversely, the displacing
fluid will produce "fingers" following the path of least
resistance. Thus, for a more mobile displacing fluid, it
will preferentially move the lesser resisting water phase
and bypassing the more resisting oil phase. Therefore, in
the surfactant/polymer flooding process, not only the ultralow
interfacial tension between oil/water interface is necessary,
but also the mobility of each injected slug has to be con
formed, i.e., the mobility of a slug should be less than that
of the preceding fluids.
For a fluid flowing in a porous medium, the mobility
of a fluid is defined as the ratio of its relative permeabil
ity to its viscosity. For example,
A
rw
w
ro
y
o
and A


18
are the mobility of water and oil respectively, where k ,
k and y y are the relative permeabilities and
ro w o
viscosities of water and oil respectively (Gogarty et al.,
1967).
1.3.1 Permeability
When a Newtonian fluid of viscosity y flows through
a horizontal porous bed of cross sectional area A in laminar
regime, the pressure difference AP across the length AL
depends upon the volumetric flow rate Q (Figure 1-2). This
flow behavior is described by the Darcy's equation
Q JC_, AP .
A y 1 AL '
where K, the proportionality constant is the permeability of
3
the porous medium. Here, Q is measured in cm /sec, A in
2
cm y in centipoise, AP in atmosphere and AL in cm, K
2
has the dimension of cm or darcy, with
1 darcy = 9.87 x 10 ^ cm^
When defined by the Darcy's equation, the permeability,
like the porositv, is a property of the porous medium itself.
However, it differs from the porosity in that the permeabil
ity measures the dynamic flow resistance of the porous
medium whereas the porosity is a static quantity of the void
space as a percent of the total volume. Thus, a highly porous


19
Figure 1-2 Flow Through Porous Medium.
material may be impermeable because of the lack of inter
connected pores, and porous beds packed with uniform spheres
will have different permeabilities as a function of the grain
diameter though the porosities are the same (Baptist, 1966).
Therefore, it is evident that any factors, e.g., mean
pore diameter, narrow necks and tortuosity that affect the
flow path, influence the permeability measurement. The
tortuosity is the ratio of the length of the flow channel
for a given molecule with respects to the apparent length
of the porous medium (Scheidegger, 1956). For a highly
tortuous flow path, the distance travelled by a given
particle is much longer than the apparent length of the
medium. In spite of these difficulties, the empirical


20
correlations between the porosity and the permeability
are found to be useful in practice (Lefebvre Du Prey, 1978).
The notion that the permeability is independent of
the fluid and is only a property of the porous medium
itself needs to be scrutinized. Klinkenberg (1941) found
that for a low permeability material, the gas permeability
is always higher than the liquid permeability and that this
difference decreases as the permeability increases. He
attributed the difference to the gas-slippage next to the
rock surface when gas is the flowing fluid. For the liquid,
it would form a stationary boundary layer next to the solid
surface, hence, developing a higher resistance across the
porous bed. As the flow path is widened for a highly
permeable material, the effect of the boundary layer
diminishes and the liquid permeability equals that obtained
by the gas.
Furthermore, one of the underlying assumptions in
acquiring the permeability is that the flowing fluid does
not react with the solid. This assumption often fails when
water is used to saturate the clay-containing sandstones.
It was shown that the permeability reduction of a water-rock
system is influenced by the type and the amount of clay in
the rock as well as the type and the amount of ions in the
water (Baptist & Sweeney, 1955; White et al., 1964).


21
In summary, permeability is a dynamic property of the
porous medium measuring its resistance to flow. Its value
is, theoretically, independent of the flowing fluid. However,
due to the gas slippage effect and fluid-solid interactions,
different values of permeability of a porous rock may be
obtained by using different fluids.
1.3.2 Relative Permeability
The single-phase permeability K defined by the Darcy's
equation is called the absolute permeability. When there
is more than one phase present, both the number of channels
and the cross sectional area available to flow for any one
phase are reduced and results in a decreased permeability to
that phase. This reduced permeability is called the effective
permeability, a function of phase i saturation and its
distribution in pores. The ratio of the effective
permeability to the absolute permeability is the relative
permeability, k^, expressed in percent. It is found that
the sirm of all effective permeabilities is less than the
absolute permeability because the flow paths become more
tortuous and the cross sectional area decreases in multi
phase flow (Langnes et al., 1972). Hence, the sum of all
relative permeabilities is also less than 1. These terms
and related equations are summarized below:


22
Permeability
Symbol
Equation
Single-phase
Flow
Absolute
Permeability
K
K = ^ -
A AP
VAI/
Multi-phase
Flow
Effective
Permeability
k.
i
Qi Vi
ki A .AP. 5 ZVK absolute
(AI/
Relative
Permeability
k
ri
ki
kri = K Zkri In designing the mobility control in a surfactant/
polymer process, Gogarty et al.(1967) suggested the concept
of minimum mobility. They recognized that oil is displaced
in the form of an oil-water bank whose mobility, A equals
the sum of the mobilities of oil, A and water, A ,
ro rw
within the bank. This is written as
1 A + A L =
r k
ro
k 1
+ 1
L ro rw b
yo
V J
w
Since relative permeability is a function of water
saturation and the oil/water ratio is changing within the
oil-water bank, the bank mobility varies as it propagates
through the reservoir. Complying to the conformance
principle, the mobility of the slug that follows the
oil-water bank should be less than the minimum value of the
bank mobility as illustrated in Figure 1-1. The lower
diagram in Figure 1-3 shows the typical oil and water


100
80
60
40
20
0
100
80
60
40
20
MINIMUM MOBILITY
J i j L
O.C. BAPTIST, ASTM 190, June, 1966
\
\ kro
1\
I
/J
/
/
/ 1
/
/
/
krw//
-L.
20 40 60 80
WATER SATURATION, % PV
3 The Effect of Water Saturation on Oil
and Water Relative Permeability and
Total Mobility.


24
relative permeability curves obtained by Baptist (1966).
Divided by their respective viscosities, the relative per
meability curves can be converted to the mobility curves.
At each water saturation, the total mobility is obtained by
summing the oil and water mobilities as shown in the upper
diagram in Figure 1-3. Finally, a tangent line can be drawn
to the lowest point in the curve resulting in the minimum
mobility value. Thus, this value will set the upper limit
of the mobility of the slug, which displaces the oil-water
bank.
1.4 Scope
The objective of this study is to understand the oil
displacement mechanism by examining the existing capillary
number-oil recovery correlation and the oil/water relative
permeability theory from a new perspective. The attempt is
made in this dissertation to answer several important
questions pertaining to the oil displacement process within
the porous media. A few of these questions are as follows:
Does the interfacial tension in porous media ever attain
the value observed in the test tubes upon vigorous mixing?
Is surfactant mass transfer an important and limiting
factor for attaining the ultralow interfacial tension in
porous media?


25
Can a dilute surfactant system exhibiting ultralow inter
facial tension in vitro be successfully used for efficient
tertiary oil recovery in porous media?
What is the role of alcohol in oil displacement in porous
media?
Is concept of optimal salinity valid in high salinity
formulations at 8-10% brine concentration?
Can the sacrificial agents be effective in the high salinity
formulations?
What is the role of coalescence of oil ganglia in the
formation of an oil bank for secondary or tertiary oil
recovery process?
Can an oil bank be formed by injection of an oil slug to
promote the coalescence of oil ganglia and to mobilize oil
ganglia in porous media?
In Chapter II, the various aspects of the capillary
number vs. the oil recovery correlation are examined. It is
pointed out that the ultralow interfacial tension achieved
in vitro may not be achieved in situ and, in certain cases,
the interfacial viscosity and not the bulk viscosity may be
a predominant factor influencing the oil displacement
efficiency, Furthermore, the equilibrated and the non-
equilibrated low surfactant concentration systems are used
for the oil displacement process. The interfacial tension,


26
the emulsification time, and the oil displacement for various
combinations of the non-equilibrated and the equilibrated
aqueous and oleic phases are determined. The oil displacement
results are explained in terms of interfacial viscosity,
emulsification time, and interfacial tension iri vitro vs.
in situ. The role of alcohol in improving oil recovery is
delineated. Finally, an efficient oil recovery process
using a low surfactant concentration formulation is demonstrated.
Chapter III describes the effectiveness of a high salinity
formulation to displace tertiary oil under the laboratory
conditions. The formulation consists of petroleum sulfonate
and alcohol in the electrolyte solution with the ethoxylated
sulfonate. The solubilization parameters and the interfacial
tension are measured. The oil displacement efficiency in
porous media is correlated with the optimal salinity of the
system. For Berea cores, the sacrificial agents are
incorporated to improve oil recovery. The results are
explained in terms of the liquid-liquid interaction and
the pH variation caused by the added sacrificial chemicals.
In Chapter IV, the effect of the artificial oil bank
injection to initiate the j.n situ oil/water bank formation
and propagation is investigated. In this study, the oil
displacement in porous media by such a process is examined
for both the small slug concentrated surfactant system and


27
the large slug dilute surfactant solution. To further improve
the oil displacement efficiency, the effects of the injected
oil bank slug size and the sacrificial agents are studied.
For the concentrated surfactant system, the oil/water
relative permeability curve is proposed to account for the
observed improvement in oil recovery efficiency. For the
dilute surfactant solution, the surfactant adsorption and
the integrity of the oil bank are the determining factors.
Surfactant partitioning from the injected fluid to the
reservoir fluids is the key to control the said factors and
to ensure the success of the process.
Chapter V concludes the major findings of this study.
The contributions and the possible applications of this study
are outlined. Also, several approaches for future investiga
tion and experiments are suggested.


CHAPTER II
A CORRELATION OF INTERFACIAL TENSION WITH OIL
DISPLACEMENT EFFICIENCY FOR EQUILIBRATED AND
NON-EOUILIBRATED OIL/BRINE/SURFACTANT SYSTEMS
2.1 Introduction
Laboratory studies on oil displacement efficiency by
surfactant-polymer flooding process have been reported by a
number of investigators (Foster, 1973; Taber, 1969; Holm, 1971;
Healy & Reed, 1974). In general, the process is such that
after being conditioned by field brine or preflush, a sandstone
core or sand pack is oil-saturated to the irreducible water
content. It is then waterflooded to the residual oil level.
Finally, a slug of surfactant solution followed by a mobility
buffer is injected. The slug of surfactant solution can
either be aqueous or oleic with a surfactant plus alcohol
concentration of 5-15%.
Because of the cost and the time factors involved, oil
displacement studies are always preceded by certain test tube
screening procedures. Specifically, the interfacial tension
of less than 0.01 dynes/cm is recognized to be the necessary
but not the sufficient criterion for selection of a surfactant
system. Many investigators (Foster, 1973; Hsieh & Shah, 1977;
Cash et al., 1976; Anderson et al., 1976; Chan, 1978) have
28


29
shown that ultralow interfacial tension of less than 0.001
dynes/cm can be achieved with less than 0.1 wt.% surfactant
solution. Since this low surfactant concentration system is
nearly one hundred times more diluted than the ones used in a
typical surfactant-polymer flooding process, the economics
dictates that the oil displacement by such low surfactant
concentration solution should be explored.
In this chapter, two surfactant systems which exhibit
ultralow interfacial tension are studied. The factors that
influence oil displacement efficiency are identified and
examined. The mobilization of oil ganglia is explained in
terms of the surfactant partitioning and the equilibration
procedure. In addition, the role of alcohol in improving oil
recovery is delineated.
2.2 Materials and Methods
2.2.1 Surfactant Solutions
Commercial petroleum sulfonate TRS 10-80 (80% active)
or TRS 10-410 (61,2% active) obtained from Witco Chemicals and
Fisher A.C.S. certified grade NaCl crystals (1% NaCl) were
dissolved in distilled, deionized water to make the surfactant
stock solutions by weight. Then, they were diluted by brine
(l% NaCl) to the desired concentration just before the start


30
of each run, so that the surfactant aging effect was minimized.
Ninety-nine percent pure n-octane or n-dodecane (Chemical
Samples Co.) was used as the oil to equilibrate the surfactant
solution at the volume ratio of 1:2 in a glass-stoppered
1-liter separatory funnel. After vigorous shaking, the surfac
tant and oil mixture was left standing for 10 days on the rack
at room temperature until a clear-mirrorlike interface was
reached. The equilibrated aqueous and oleic solutions then
were drained into separate storage bottles. The effect of
alcohol was studied on the solution prepared by adding 99%
pure isobutanol (Chemical Samples Co.) to the surfactant
solution at 1:1 weight ratio with TRS 10-80 or TRS 10-410
on 100% active basis.
2.2.2 Interfacial Tension Measurement
Interfacial tension between various oleic and aqueous
phases was measured using the Spinning Drop Interfacial
Tensiometer at 25C. The spinning time and rate were kept
constant so that comparative results could be obtained.
2.2.3 Contact Angle in Quartz/Brine/Oil Systems
The wettability of the quartz surface used to simulate
the surface of sandstones, was studied by a contact-angle
goniometer. Using a fflicrosyringe, an oi.1 drop was deposited


31
on the underside of a smooth, polished quartz surface sub
merged in aqueous solutions at 25C. The angle through the
oil phase was measured and Polaroid pictures of the oil drop
were taken at different time intervals.
2.2.4 Surfactant Concentration Measurements
The surfactant concentration in the effluent stream
was measured by the two-dye two-phase titration method
according to Reid et al. (1967).
2.2.5 Oil Displacement in Porous Media
Horizontally mounted sand packs encased in an air-
circulating constant temperature box were used for oil
displacement efficiency tests. The experimental setup as
well as detailed procedure in preparing the sand packs and
Berea cores are described in Appendix II. The sand pack,
1.06" diameter by 7.0" long, had an average porosity of 38%
and permeability of 3.0 darcy, while the Berea core is 1"
square by 12" long cast in expoxy resin within a 1.5" diameter
by 14" long PVC pipe. It had an average porosity of 18% and
permeability of 220 millidarcy.
After water saturation and brine prewashing, oil saturation
as well as aqueous surfactant solution flooding were proceeded.
The brine salinity was the same as the salt concentration in


32
surfactant solution. The injected oil and aqueous solution
were either pre-equilibrated or non-equilibrated. Constant
fluid velocity of 10.0 ft/day was maintained during the oil
saturation and that of 2.3 ft/day was maintained during
aqueous solution or brine flooding. Because the viscosity
of n-octane was 0.5 c.p., a favorable mobility was assumed,
consequently, no polymer was added in the dilute surfactant
solution.
To compare the equilibrated with the non-equilibrated
systems, alternate injections of various fluids were conducted.
The sequence of these injections for each run is listed in
Table 2-1. In the study of the effect of surfactant concen
tration on oil recovery, the total amount of surfactant
injected was the same, i.e., the slug size times the concen
tration was equal (e.g. 70% PV x 0.5% = 700% PV x 0.05% = 35)
for each run.
2.3 Results and Discussion
2.3.1 Effect of Equilibration
Figure 2-1 shows the interfacial tension and the percent of
oil recovery as a function of initial TRS 10-80 concentration
in 1% NaCl. It was observed that for the pre-equilibrated
system (equilibrated oil phase displaced by equilibrated
aqueous phase, F in Table 2-1), 94% oil was recovered at


OIL RECOVERY, PERCENT
TRS 10-80 CONCENTRATION, WT. %
Figure 2-1 The Effect of Surfactant Concentration on Oil Displacement in Sand
Packs at 2$ C.
INTERFACIAL TENSION, dynes/cm


34
0.05% TRS 10-80 concentration as compared to 65% at either
0.005% or 0.5% concentration. This maximum oil recovery at
0
0.5% TRS 10-80 concentration corresponds to the minimum
interfacial tension observed at this concentration. Since
the amount of surfactant injected was the same for each run
(0.125 gm), the maximum oil recovery was interpreted as a
result of the capillary number vs. final oil saturation
correlation (Melrose & Brandner, 1974; Abrams, 1974).
However, this correlation does not seem to hold under
the typical (i.e., non-equilibrated) tertiary oil recovery
process. In order to find the amount of tertiary oil that
can be recovered, the sand pack was saturated with fresh
(i.e., non-equilibrated) n-octane and was brine-flooded to
the residual oil level. A fresh (i.e., non-equilibrated)
surfactant slug of 0.05% TRS 10-80 in 1% NaCl was then pumped
through the sand pack. It was interesting to note that in
this case even after an injection of 10 PV surfactant slug,
no oil was recovered (Case A in Table 2-1; and ~7% in another
run). Because the effluent surfactant concentration was close
to the injected surfactant concentration, the poor oil recovery
cannot solely be explained by the adsorption of the surfactant
on sand particles. The observed excellent oil recovery for
the equilibrated system is then believed to be due to the
surfactant partitioning during equilibration.


35
Systematic and comprehensive studies on oil displacement
by various fluids were made and the results are listed in Table
2-1 and Figure 2-2. It is clear that oil recovery in all
cases was completed at the end of the first pore volume
injection of the surfactant solution (Figure 2-2). Therefore,
the amount of surfactant required to displace the oil is
100% PV x 0.05% = 5, while the equivalent number for the
conventional small slug concentrated surfactant/polymer
process is 30-40 (Healy & Reed, 1974). Hence, a saving of
chemicals by 7 times can be realized if the dilute surfactant
solution flooding process is utilized.
Case A corresponds to the typical tertiary oil recovery
process while Case F shows 94% recovery of the equilibrated
system (Table 2-1). A fair comparison of the equilibrated
with non-equilibrated system is Case F vs. Case C, the
direct oil displacement by surfactant solution without
brine-flooding. The equilibrated system (Case F) is better
by 22% (94% vs. 72%). This is a clear indication of the
importance of surfactant partitioning during oil displacement.
As fresh n-octane in Case B and equilibrated n-octane
in Case E were being displaced by both brine and equilibrated
surfactant solutions, an oil recovery of 60% and of 88%,
respectively, was observed. Again, the recovery of the
equilibrated oil is better by 23%, a difference of the same


Table
A.
B.
C
D.
E.
F.
2-1 The effect of Equilibration on Oil Displacement in Sand Packs
at 2 C.(0.05% TRS 10-80 in 1% NaCl vs. n-0ctane)
SEQUENCE OF FLUID INJECTION

A/ XWsWNE /AFRESH oiloybrine/

V quiiibrteW^ ^ -^7/////V
3
l. EO"*'',\VequYilTbr1me'/
Secondary
Run Recovery
Tertiary
Recovery
Final Oil
Saturation
SI00-02
61.2%
0%
30.86%
SI00-03
63.7%
7.14%
24.59%
SI00-09
60.36%
0%
30%
5100-06
SI00-07
SI00-08
71.4%
71.99%
75.16%

23.02%
20.48%
20.81%
SIOO-IO
SIOO-II
51.88%
44.29%

36.91 %
43.3%
SIOO-04
83.04%
0%
1 5.58%
S100-05
93.78%
6.13%
SAND PACK DIMENSION: l.06DIA. X 7" l ONG ; PERMEABILITY: 3 DARCY; FLOW RATE: 2.3 FT./DAY
BRiNE: 1% NgCI
U)
O'


FLUID PRODUCED. PORE VOLUME
Figure 2 2 0,05% TRS 10-80 in 1% NaCl Displacing n-Octane in Sand Packs at 25 C
Lo
'-J


38
magnitude as the equilibrated system in Case F being compared
with the non-equilibrated system in Case C. Thus, the equil
ibration of oil and not the equilibration of surfactant
solution, accounts for the observed oil recovery differences
between the equilibrated and the non-equilibrated systems.
Comparing Cases A and B or Cases C and D surfactant
solution non-equilibrated or equilibrated there is either
no difference in oil recovery or the equilibrated performs
worse than the non-equilibrated. Therefore, combining with
the comparison of Cases F and C, it is concluded that the
equilibrated oil rather than the equilibrated surfactant
solution is responsible for a good recovery.
To interpret the observed results, the following expla
nation is offered. The commercial petroleum sulfonate such
as TRS 10-80 is known to be a mixture of various low and
high equivalent weight sulfonates. The higher equivalent
weight species tend to be more oil-soluble or more hydrophobic,
while the lower equivalent weight species tend to be more
water-soluble or more hydrophilic. Schematically, it is
depicted by the diagram on the right in Figure 2-3. When
such a surfactant is added to an oil/water mixture, each
species partitions in the oil and brine according to its
hydrophilic-lipophilic balance. The stipled region is
proportional to the fraction partitioning in the oil, whereas


SURFACTANT SOLUTION INTERFACEINTERIOR OF OIL DROP
Equivalent Weight of Surfactant Species
-- INTERFACIAL TENSION DECREASE DUE TO SURFACTANT MASS TRANSFER
RATE OF MASS TRANSFER DEPENDS UPON THE CONCENTRATION OF OIL
SOLUBLE SPECIES IN THE SURFACTANT SOLUTION
Figure 2-3 Mass Transfer Process for Surfactant Monomers.
OJ
CO


40
the clear region below is proportional to the fraction of
water-soluble species. Initially, the surfactant is dissolved
in the aqueous solution. However, as this aqueous solution
is equilibrated with an oil, the oil-soluble species partitions
into the oil phase. From the interfacial tension data shown
in Table 2-2 and the later discussion, it is evident that
the oil-soluble species are more effective in lowering the
oil/brine interfacial tension, similar to that reported by
Gale and Sandvik (1973). Accordingly, the oil recovery
differences observed between the non-equilibrated and equili
brated systems can be attributed to the adsorption of the
hydrophobic high equivalent weight species at the oil/brine
interface.
When the equilibrated phases are used to study the oil
displacement efficiency, the higher equivalent weight species
have already partitioned into the oil phase and will adsorb
at the oil/brine interface to produce the required low inter
facial tension. Titus, good oil recovery obtained. However,
when the non-equilibrated surfactant slug is injected, the
water-soluble species will form a film at the oil/brine
interface deterring the mass transfer from the aqueous phase
to the oleic phase of the oil-soluble species. As a result,
the low interfacial tension was not achieved under the dynamic
flow condition. Thereby, the ultralow interfacial tension


41
measured In vitro Is presumably not achieved jin situ, hence,
resulting in a falsely high value of capillary number in the
porous media. Or, in other words, the capillary number-oil
recovery correlation still holds in essence.
In Table 2-1, the reason that equilibrated surfactant
solution displaces less oil than the fresh surfactant solution,
as in Cases D and C, is partially due to the fact that there
is less surfactant in the equilibrated solution as compared
to the fresh solution. During the equilibration process, some
of the surfactant species must have migrated from the aqueous
phase to the oleic phase resulting in a reduction in surfac
tant concentration in brine. This is substantiated by the
measurement of surfactant concentration of 0.01% for the
original 0.05% surfactant solution after equilibration.
However, the reason for the poorer oil recovery of Case
D (waterflooding by the equilibrated surfactant solution) as
compared to the 60% recovery of Cases A and B (waterflooding
by brine) does not seem obvious. One would predict that
waterflooding by equilibrated surfactant solution should be
at least as good as the one by 1% NaCl, if not any better.
The oil displacement results are in reverse order with the
interfacial tension data shown in Table 2-2. Here, the
interfacial tension between fresh oil/1% NaCl and fresh oil/
equilibrated surfactant solution are 50.8 and 0.731 dynes/cm,


42
respectively. Because the fluid velocity and the viscosity
are the same in both cases, it erroneously suggests that a
larger capillary number corresponds to a lesser oil recovery.
This discrepancy is attributed to the interfacial film
rigidity.
It is hypothesized that a rigid surfactant film forms
on the oil droplet when displaced by the equilibrated surfac
tant solution. This film prevents the coalescence of oil
droplets in the narrow channels of the sand pack and presumably
caused the formation of stable emulsions. It was observed that
the differential pressure (AP) across the sand pack increases
continuously when flooded by the equilibrated surfactant
solution, but AP decreases or levels off when flooded by 1%
NaCl. Hence, the apparent paradox in capillary number-oil
recovery correlation can be resolved if the interfacial
viscosity (Wasan & Mohan, 1977) is considered in addition to
the bulk viscosity and interfacial tension.
Also, the results of Cases A and C as well as Cases E
and F indicate that less final oil saturation, S was
of
obtained if the sand pack was flooded directly by the
surfactant solution without a secondary flooding by brine.
To explain the effect of equilibration on oil recovery,
the liquid-liquid and liquid-rock interfaces, i.e., the inter
facial tensions and contact angles were studied for these


43
systems and the results are listed in Table 2-2. Except for
the system of fresh oil/1% NaCl, the contact angle measurements
followed the pattern shown in Figures 2-4 and 2-5. The oil
drop formed a sphere on the quartz surface initially. It
then flattened out and, finally, disintegrated or emulsified
into many small droplets. The time between the formation of
the initial spherical droplet and the final emulsification is
defined as the emulsification time. Except for system III,
there is a positive correlation between the emulsification
time, the interfacial tension value and the oil displacement
efficiency.
Among systems I through V, the lowest interfacial tension
existed for the interface between equilibrated oil and equili
brated surfactant solution. A drastic increase in interfacial
tension occurred as either equilibrated oil or equilibrated
surfactant solution was replaced by fresh oil or fresh surfac
tant solution. However, examining systems II and IV, it is
evident that the equilibrated oil rather than the equilibrated
surfactant solution is responsible for the lowering of inter
facial tension. Hence, the oil-soluble species are the low
tension producing sulfonates.
These hydrophobic species are also responsible for the
emulsification time of the oil drop. The emulsification time
of a single oil drop has a direct bearing on the oil


44
Table 2-2 Interfacial Tension and Emulsification Time
of 0.05% TRS 10-80 in 1% NaCl vs. n-Octane
at 25C.
INTERFACIAL EMULSIFICATION OIL
SYSTEM
TENSION
TIME
RECOVERY
(dynes/cm)
(minutes)
(% OIP)
I.
Fresh Oil/1% NaCl
**
-50.8
CO
61-63
II.
Fresh Oil/Equili
brated Surfactant
Solution
0.731
110.
44-52
III.
Fresh Oil/Fresh
Surfactant Solution
0.627
8.
77-75
IV.
Equilibrated Oil/
1% NaCl
0.121
15.
83
V.
Equilibrated Oil/
Equilibrated Sur
factant Solution
0.0267
4.
94
VI.
Equilibrated Oil/
Fresh Surfactant
Solution
0.00209
0.25
91
* Emulsification time is defined as the time required for
the n-octane drop to gradually flatten out the subsequently
disintegrate into smaller droplets.
** Octane/ distilled HO at 20C, y 50.8 dynes/cm, "Inter
facial Phenomena", Davis and Rideal, Chapter 1, p.17 Table 1.


45
Equilibrated n-Octane vs. Equilibrated n-Octane vs.
0.05% TRS 10-80 in 1% NaCl 1% NaCl
Figure 2-4 Contact Angle of n-Octane vs. 0.05% TRS 10-80
in 1% NaCl on Quartz.


46
Figure 2-5 Contact Angle of n-Octane vs. Equilibrated
0.05% TRS 10-80 in 1% NaCl.


47
displacement efficiency. Because there are thousands of oil
droplets within the porous media, the amount of oil recovered
depends on how easily each of them can be mobilized. The
faster they are emulsified, the easier they are mobilized
and displaced. Cash et al. (1975) demonstrated that oil
displacement by the spontaneous emulsification system is
better than the non-emulsifying system.
In Table 2-2, the longest emulsification time corresponds
to the system that has the least amount of oil-soluble species
present and the worst oil recovery. The only exception is
system III which although emulsified faster than system IV,
gave poorer recovery than system IV. The following explanation
is suggested. While contact angles are being measured, the
oil-soluble species from the fresh surfactant solution
quickly adsorb onto the quartz surface, which facilitates
the oil drop emulsification. When the fresh surfactant
solution passed through the sand pack, most of the oil-soluble
species had adsorbed onto the earlier portion of the sand pack
before they reached the oil ganglia in the later portion.
These adsorbed surfactant species were unable to mobilize
the oil droplets which resulted in a poorer oil recovery.
Indeed, Case C did produce less oil than Case E (Table 2-1),
regardless of the fact that the corresponding system III
seems to emulsify easier than system IV (Table 2-2).


48
To sum up, the following mechanism is proposed to account
for the observed effects in interfacial tension and emulsifi
cation time. In Figure 2-3, mixed micelle in equilibrium with
surfactant monomers is formed by the water-soluble and oil-
soluble species in the bulk aqueous solutions. During equili
bration, the surfactant monomers transfer to the water/oil
interface and then to the interior of the oil drop resulting in
a reduction of interfacial tension. The concentration of
oil-soluble species in the surfactant solution dictates the
absolute value of interfacial tension and the rate of surfac
tant mass transfer, which in turn, determines the emulsifi
cation time of the oil drop.
Because different batches of TRS 10-80 were used in
making the sets of surfactant solutions in Figure 2-1 and
Table 2-2, a small variation in values of interfacial tension
for the equilibrated oil and equilibrated 0.05% TRS 10-80
in 1% NaCl was observed. Nevertheless, the trend of high
and low interfacial tension within each set remained the
same. Therefore, the interpretation of interfacial tension
based on these values is believed to be valid.
In order to apply the low surfactant concentration
system to the oil displacement process, direct flooding of
non-equilibrated n-octane by non-equilibrated TRS 10-80 in
1% NaCl were investigated. The results are plotted as the


49
dash line In Figure 2-1. It shows that the maximum oil
recovery did not coincide with the minimum interfacial
tension at 0.05% TRS 10-80 and the equilibrated systems
recovered more oil than the non-equilibrated systems. As
the surfactant concentration increases from 0.05% to 0.5%,
the oil recovery differences between the equilibrated and
the non-equilibrated systems decreases and the non-equili-
brated finally surpasses the equilibrated.
2.3.2 Effect of Isobutanol
Oil displacement of another low surfactant concentration
system was also studied. The system investigated was the
direct flooding of n-dodecane by 0.1% TRS 10-410 4- 0.06%
isobutanol (IBA) in brine of various salinities. The results
are plotted in Figures 2-6 and 2-7. Figure 2-6 shows the
oil recovery and interfacial tension as a function of salinity
and Figure 2-7 is the flooding history of each experiment.
Similar to the 0.05% TRS 10-80 in 1% NaCln-octane system
(Figure 2-1), sharp maximum in oil recovery corresponding to
the sharp minimum in interfacial tension occurred at 1.5% NaCl.
However, contrary to Figure 2-1, the non-equilibrated systems
perform either the same as or better than the equilibrated
systems. Furthermore, it is shown that almost 100% oil
recovery was obtained at 1.5% and 2.0% NaCl. Thus, with the


50
E
o
\
C
>x
TD
C
O
CO
c
P
o
o
Figure 2-6 Continuous Injection of 0.1% TRS 10-410
+ 0.06% IBA in X% NaCl Displacing
n-Dodecane in Sand Packs at 25C.


Figure 2-7 Continuous Injection of 0.1% TRS 10-410 + 0.06% IBA in X% NaCl Displacing
n-Dodecane in Sand Packs at 25 C.


52
incorporation of alcohol, the practical application of low
surfactant concentration system in oil displacement process
is possible.
Because the petroleum sulfonate concentration are nearly
the same in the systems shown in Figures 2-1 and 2-6 (0.1%
of 61% active and 0.05% of 80% active, respectively), the
conflicting behavior in oil recoveries for the equilibrated
and non-equilibrated systems of this two formulations is attri
buted to the IBA in the TRS 10-410n-dodecane system. In
order to test the effect of added alcohol in oil displacement,
IBA was taken out of the TRS 10-410 formulation and added to
the TRS 10-80 formulation at the same surfactant and alcohol
ratio of 1:1. The results are listed in Table 2-3. For the
non-equilibrated 0.01% TRS 10-410n-dodecane system, the oil
recovery dropped from the 97% with the alcohol to the 84%
without the alcohol, a reduction of 13%. A much more drastic
difference was seen in the non-equilibrated 0.05% TRS 10-80
n-octane system, where the tertiary oil increased from 0%
without IBA to 77% with IBA, Table 2-3 also shows that the
systems with IBA have very short emulsification time.
Hsieh and Shah (1977) have shown that the same interfacial
tension values were obtained for the 0.1% TRS 10-410n-dodecane
system with and without IBA. Therefore, the observed difference
in oil recovery cannot be explained by the change in interfacial


Table 2-3 The Effect of IBA on Emulsification Time and Oil Displacement Efficiency.
RUN
SYSTEM
SECONDARY
RECOVERY
TERTIARY**
RECOVERY
FINAL OIL **
SATURATION
EMULSIFICATION
TIME
S100-48
0.1% TRS 10-410
in 1.5% NaCl
vs. n-Dodecane
84.37%
-
11.73%
90 sec
S100-43
0.1% TRS 10-410
+ 0.06% IBA in
1.5% NaCl vs.
n-Dodecane
98.32%
1.28%
1 sec
S100-02
0.05% TRS 10-80
in 1% NaCl vs.
n-Octane
61.2%
0
30%
420 sec
S100-47
0.05% TRS 10-80
+ 0.04% IBA in
1% NaCl vs.
n-Octane
60.08%
76.84%
5.36%
1 sec
All displacement experiments are carried out with non-equilibrated systems in
sand packs at 25 C.
Secondary and tertiary oil recovery values are percent of oil-in-place, whereas
final oil saturation is percent of tctal pore volume.
Ln
LO


54
tension. It was suggested by Shah et al.(1972) that the rigid
potassium oleate film at the oil/water interface could be
expanded by the penetration of hexanol molecules. Also,
for a commercial petroleum sulfonate-crude oil system,
Wasan et al.(1977) measured the oil droplet size as a
function of time for samples with and without n-hexanol.
They found that initially the two samples had similar oil
droplet size distributions, but the sample with the alcohol
coalesced much faster. Thus, for the systems studied here,
IBA is believed to penetrate the petroleum sulfonate film
reducing its interfacial viscosity and enhance the oil
droplet coalescence as suggested by the emulsification time
measurements. Using silica gel and kaolinite as adsorbent,
Walker et al.(1976) and Fernandez et al.(1978) showed that
the adsorption plateau value of alkylbenzene sulfonates decreased
as alcohol concentration increased. As discussed previously,
the interfacial rigidity and the oil-soluble sulfonate depletion
are the two possible mechanisms having detrimental effects on
the oil recovery, therefore IBA improves the oil displacement
efficiency by (a) increasing the oil/water interfacial fluidity
and (b) preventing the adsorption of oil-soluble species of
the surfactant.


55
Although the above reasoning provides an explanation
for the beneficial effect of alcohol (Table 2-3) in oil
displacement, it does not explain why alcohol containing
systems show better oil recovery in non-equilibrated
state as compare to the equilibrated state even though both
systems contain the alcohol (Figure 2-6). It is interesting
that at 0.5% and 1.0% NaCl concentration, the oil recovery
is same for equilibrated and non-equilibrated systems. Only
at and above the optimal salinity (i.e., 1.5% and 2.0% NaCl),
the non-equilibrated system produces better oil recovery than
the equilibrated system. A possible explanation of this
effect is as follows. It has been shown that at the salt
concentrations higher than the optimal salinity, the tendency
for the surfactant to migrate from the aqueous phase to the
oil phase increases. Therefore, when one takes a non-equili
brated system at or above optimal salinity, there is a
significant driving force for the surfactant to migrate from
the aqueous to oil phase. Moreover, the presence of alcohol
in such solution keeps the interface fluid enough so as not
to hinder the mass transfer of surfactant across the interface.
Therefore, as the non-equilibrated surfactant solution contacts
the oil ganglia very likely a rapid mass transfer occurs
resulting in ultralow interfacial tension. The oil ganglia
presumably flatten out or spontaneously disintegrate into


56
several microdroplets. A successful flattening and dis
integration of the oil ganglia in the initial stages
presumably leads to the formation of an oil-water bank which
then successfully sweeps the oil ganglia along the porous
media by coalescence process. Maintaining the ultralow
interfacial tension at the oil-water bank/driving surfactant
solution interface decreases entrapment of the oil from the
oil-water bank. Therefore, the improved performance of non-
equilibrated system at and above optimal salinity is related
to the effective mass transfer of surfactant from the aqueous
phase to the oil phase and the concommitant generation of
ultralow interfacial tension and presumably low interfacial
viscosity and associated spontaneous flattening or dis
integration of oil ganglia. This explanation is consistent
with the results of oil displacement in Berea cores shown
in Figure 2-8.
2.3.3 Oil Displacement Mechanism
Oil displacement in consolidated sandstone cores by this
dilute surfactant formulation was studied. Figure 2-8 shows
the effect of salinity on the amount of oil recovery as a
percent of oil-in-place and percent final oil saturation.
It indicates that more oil was displaced at a higher salinity
and that close to 90% oil recovery was obtained. Figure 2-9
is a production history of a typical mn. The cumulative oil


57
c
CO
c
o
o
u_
ZJ
o
CO
O
c
0)
o
k
0)
CL
Salinity, NaCI wt.%
Figure 2-8 Oil Recovery in Berea Cores at 25 C.
(Continuous Injection of 0.1% TRS 10-410
+ 0.06% IBA in X% NaCI Displacing n-Dodecane)


58
recovery, pressure difference (AP) across the porous bed,
normalized effluent surfactant concentration and percent oil
cut have been plotted.
Analyzing these curves may provide some insights in
the oil displacement mechanism. As shown in Figure 2-9, the
cumulative oil recovery curve and the AP curve rise sharply
initially then change their slopes at 0.4% PV. The oil
recovery curve further increases at a constant rate while AP
decreases, then both change slopes again at 5 PV and,finally,
the oil recovery graph curve toward final oil recovery level
and AP keeps on rising continuously. Throughout the flooding
process, the effluent surfactant concentration increases very
slowly from 0% initially to 15% of the injected surfactant
concentration at 6.5% PV. It jumps to 40% at 7 PV and
eventually reaches 42% at the end of the run. The oil cut
drops drastically from the 100% at the beginning to 7% at
0.4% PV, then it maintains a 4% recovery for 4.5 PV fluid
production.
The initial fast rise of the oil recovery curve and the
AP curve correspond to the 100% oil recovery in the effluent
stream for the fully oil saturated Berea core. This is
evident from the oil cut curve. The slopes change when
water breaks through at the exit. In the next stage, oil
is then produced in the form of oil-water bank, which is


Figure 29 Oil Displacement of 0,1% TRS 10-410 + 0.06% IBA in 2% NaCl vs. n-Dodecane.
Oil Cut, Percent
Percent Oil-1 n-Place Recovery
Effluent Surfactant Concentration, Percent C/Co
ro -C O
Pressure Difference, AR psi
65
Production history of Berea Core 40D at 25C


60
composed of the coalesced oil droplets mobilized by the
surfactant solution. As oil is recovered at a constant rate,
AP is decreased gradually according to the water-oil relative
permeability theory.
Toward the end of this constant rate of oil production,
oil comes out as the tailing end of the oil-water bank. At
the same time, enough surfactant has been accumulated in the
sandstone core to form emulsions with the oil droplets
in situ. Consequently,AP is increased due to the blockage
of the small pores and narrow channels by these oil-swollen
surfactant-rich emulsions. As the process progresses, the
surfactant-rich emulsion breaks through as a white opaque
solution and manifests itself as a step increase on the C/Cq
curve at 7 PV. Finally, as the end of the flooding process
is approached, oil recovery diminishes, AP keeps on increasing
as before, and C/C levels off.
o
It is interesting to note that the shape of the cumulative
oil recovery curves in the unconsolidated sand pack is
similar to that in the consolidated Berea core (Figures 2-7
and 2-9), except that oil is produced at a much faster rate
for the sand packs. Therefore, the oil displacement mechanism
is presumably the same in these two porous media for the
continuous dilute surfactant solution flooding process.


61
2.4 Conclusions
The study revealed that the equilibrated oil rather than
the equilibrated surfactant solution is responsible for the
high oil displacement efficiency for surfactant systems
studied. The oil-soluble fraction of petroleum sulfonate is
more effective in lowering the interfacial tension and in
facilitating the oil drop emulsification. Nearly 100% oil
recovery was achieved in sand packs by a low concentration
surfactant plus alcohol formulation. The alcohol improves
the oil displacement efficiency by (a) increasing the oil/water
interfacial fluidity and (b) decreasing the adsorption of oil-
soluble sulfonates. Furthermore, less final oil saturation
was obtained for the system flooded directly by the surfactant
solution without first being brine-flooded. Also, the
capillary number vs. oil recovery correlation holds in
essence. However, in calculating the capillary number, care
should be exercised, because the interfacial tension measured
in vitro may not be the interfacial tension ijn situ and, in
certain cases, the interfacial viscosity and not the bulk
viscosity, may be a predominant factor influencing the oil
displacement efficiency.
The effect of salinity on oil displacement efficiency
revealed that for the alcohol containing formulations, the


62
non-equilibrated system was more efficient for oil recovery
as compared to the equilibrated system. It was proposed
that not only the equilibrium values of the properties such
as interfacial tension and interfacial viscosity are im
portant but the dynamic process of surfactant partitioning
is presumably involved in the mobilization of oil ganglia.
The conditions that promote the efficient mass transfer
from the aqueous phase to the oil phase also deform the
oil ganglia and produce ultralow interfacial tension. This
would contribute toward an early formation of oil-water
bank and subsequent displacement of oil from porous media.
Finally, the results obtained in sand packs and in Berea cores
show that the mechanism of oil displacement in both these
porous media appear to be the same.


CHAPTER III
OIL DISPLACEMENT EFFICIENCY
OF HIGH SALINITY FORMULATIONS
3.1 Introduction
Surfactant formulations consisting of petroleum sulfonate,
alcohol, and electrolyte have been studied extensively for
their ability to achieve ultralow interfacial tension and
their effectiveness in oil displacement (Foster, 1973; Reed &
Healy, 1977; Hsieh, 1977; Chan, 1978). The surfactant used
in these formulations is sensitive to salt concentration,
particularly, to di- and tri-valent ions. It was shown by
Hsieh and Shah (1977) that phase separation or surfactant
precipitation occurs at high salinities. Hill et al.(1973)
and Chan and Shah (1979) reported a strong dependence of
interfacial tension on salinity. Furthermore, these surface-
active compounds adsorb onto the rock surface when propagating
through the reservoir. Gale and Sandvik (1973) showed that
the higher equivalent weight fractions of the commercial
sulfonates are effective low tension producers, but they
are also easily adsorbed. Cheap chemicals can then be added
to the fluid system to saturate the rock surface adsorption
sites. Sodium carbonate (Na^CO^) and sodium tripolyphosphate
63


64
(STPP) are two of the effective chemicals acting as sacri
ficial agents (Hurd, 1976; Bae & Petrick, 1976; Hill et al.,
1973).
A significant amount of residual oil can be recovered
by the use of petroleum sulfonate solutions. Laboratory
reports (Holm, 1971; Chiang & Shah, 1979) indicated that
nearly 100% oil recovery in porous media could be achieved
at a salinity as low as less than 2.0% NaCl and 0 ppm
divalent ions. However, Oeffen (1975) pointed out that the
majority of the fields suitable for surfactant flooding
contain at least 5% NaCl and 1,000 ppm hardness. Thus,
either the hostile reservoir environment has to be conditioned
or a compatible surfactant solution has to be developed.
Bernard (1975) indicated that gypsum (CaSO^'ZH^O) and mont-
morillonite clay can act as a divalent cation source; the
calcium ions within the gypsum and clays are continuously
extracted into the displacing fluid due to the ion exchange
effect. He showed that with 1% gypsum present, 4 to 20 pore
volume of water will be required to dissolve the gypsum.
Hence, preflush of a reservoir by fresh water prior to the
surfactant slug injection was either impossible or economically
unfeasible. Indeed, Pursley et al.(1973) had reported a
failure of the preflush in displacing the formation water in
Loudon Field, Illinois.


65
Dauben and Froning (1971) reported that the presence of
an ethoxylated alcohol in a surfactant formulation increases
the salt tolerance of the formulation. Several patents have
been issued on the possible use of ethoxylated alcohols and
ethoxylated sulfonates in oil recovery formulations (Shupe
et al., 1975a, 1975b, 1976). Recently, Bansal and Shah (1978a,
1978b, 1978c) found that the addition of an ethoxylated
sulfonate in petroleum sulfonate solutions increases the salt
tolerance up to 24% NaCl alone or 4% NaCl and 40,000 ppm
CaCl^. Also, when mixed with paraffinic oil at 1:1 v/v ratio,
these solutions form a surfactant-rich microemulsion "middle"
phase (Reed & Healy, 1977), at which the interfacial tension
_3
in below 10 dynes/cm.
In this chapter, a system consisting of ethoxylated
sulfonate, petroleum sulfonate, alcohol, and high salinity
is investigated. In order to minimize the surfactant adsorption
on rock surface, the effect of sacrificial agents on oil
displacement efficiency is delineated as well.
3.2 Materials and Methods
The formulation tested consisted of 1.5% TRS 10-410,
2.5% EOR 200, 3% isobutanol and various amounts of NaCl mixed
in deionized distilled water by weight on 100% active basis.
The TRS 10-410 is 61.2% active petroleum sulfonate supplied


66
by Wico Chemicals Company and the EOR 200 is 29.3% active
ethoxylated sulfonate supplied by Ethyl Corporation.
Both sulfonates were used as received. TRS 10-410 is
basically a sodium salt of alkyl benzene sulfonate type
compound consisting of isomers and different chain length
hydrocarbons. The average molecular weight is about 420.
The structure and the equivalent weight distribution are
listed in Appendix I. The structure of EOR-200 as reported
by the manufacturer is a hydrocarbon chain having two
sulfonate groups attached via ethoxylated groups. Ninety-nine
percent pure isobutanol and n-dodecane were obtained from
Chemical Samples Company. Reagent grade sodium carbonate
(Na^CO^) and sodium tripolyphosphate (STPP) obtained from
Fisher Company were used as sacrificial agents in preflush,
surfactant formulation, and polymer buffer solution. The
mobility buffer used is composed of 2000 ppm Polymer 340
from Calgon Corporation which was dissolved in corresponding
salt solutions. According to the manufacturer's description,
the Polymer 340 is a copolymer of acrylamide and 2-acrulamido-
2-methyl propyl sulfonate.
A 1:1 v/v ratio of surfactant solution of different
salinities and oil was equilibrated in graduated cylinders
at 25 1C. After vigorous shaking, the surfactant and
oil mixtures were left standing for 6 weeks until


67
clear-mirrorlike interfaces were reached. For the salinity
range tested, each sample showed a surfactant-rich microemulsion
phase in equilibrium with either excess oil or brine or both.
The amount of oil or brine solubilized into the microemulsion
phase was recorded.
The interfacial tension between oil/microemulsion and
between microemulsion/brine phases was measured by a Spinning-
Drop Interfacial Tensiometer at 25 1C (Cayias et al.,1975).
The density of each phase was measured using a 2-ml pycnometer.
Also, the pH of brine solutions and surfactant solutions were
measured by a Coleman Metrion III pH meter Model 28B at 25
1C. Before the measurement, the meter was calibrated by a
standard pH 10 buffer solution.
Horizontally mounted sand packs (1.06" diameter x 18.0"
long) and Berea cores (1" x 1" x 12") encased in an air-circu
lating constant temperature box were used in the oil displace
ment experiments. The experimental setup as well as detailed
procedure in preparing the sand packs and Berea cores are
described in Appendix II. The physical characteristics and
the flooding conditions of these porous media are included
in Table 3-1. The sand packs had an average porosity of 38%
and permeability of 3.0 darcy. The Berea core cast in epoxy
resin had an average porosity of 18% and permeability of 220
millidarcy. For each run, 0.05 pore volume of 7% surfactant


Table 3-1 Oil Recovery of 1.5% TRS 10-410 +2.5% EOR 200 + 3% IBA in X% NaCl
Displacing n-Dodecane in Berea Cores.
Core #
NaCl
wt. %
Sacrificial
Agents
wt. %
OIP
c. c.
Oil
Recovery
Secondary
% OIP
Tertiary
% S
or
Residual Saturation
% S .
of
20
9
0
29
51.72
45.4
19.13
22
9
0.1
20.8
44.23
54.31
13.59
34
9
0.2
29
47.59
42. 76
19.33
24
9
0.3
23.6
46.61
63.49
11.79
23D
9
0.5
26.1
48.28
44.07
18.88
28B
8.5
3
24
48.75
41.46
18
24
9.0
3
23.6
46.61
63.45
11. 79
27
9.5
3
26.5
39.62
37.81
24.88
29B
10
3
26.5
41.13
42.63
22.38
Note: Surfactant Slug: 10% PV; Mobility Buffer: Polymer 340, 2000 ppm in X% NaCl, 1 PV.
Sacrificial Agents: 0.05% STPP and 0.05% Na^CO^.
os
00


Table 3-2 Oil Recovery of 1.5% TRS 10-410 + 2.5% EOR 200 + 3% IBA in X% NaCl
Displacing n-Dodecane in Sand Packs.
Oil Recovery
Run
Salinity
% NaCl
Pore
Volume
c. c.
OIP
c. c.
Secondary
% OIP
Tertiary
% S
or
Residual
Saturation
% S .
of
100-23
8
115
74
64.05
37.22
14.52
100-26
8.5
102
79
66.39
32.39
17.55
100-22
9
101
79
75.32
75.9
4.65
100-25
9.5
100
70
64.86
57.31
10.5
100-24
10
111
87.8
66.4
63.73
9.64
ON
vO


70
Table 3-3 Viscosity of Surfactant Slug (2.5%
TRS 10-410 + 2.5% EOR 200 + 3% IBA
in X% NaCl).
NaCl, wt.% Viscosity, c.p.
8.0
7.38
8.5
4.01
9.0
5.09
9.5
3.09
10.0
5.96


71
concentration was injected, so that the results can be compared
with that by the low salinity formulations reported in
Chapter IV. New sand packs and Berea cores were used for
each run.
Viscosity measurements on each of the flooding fluids
were obtained by a Cannon-Manning Semi-Micro Viscometer No.100
at 25 0.1C and listed in Table 3-3. The polymer concen
tration of the mobility buffer was chosen in order to have a
favorable mobility ratio during flooding process.
3.3 Results and Discussion
For the high salt tolerance svstem investigated, similar
phase behavior as that reported by Reed and Healy (1977)
occurred as salinity changed. The solubilization parameters
V /V and V /V are plotted in Figure 3-1 as salinity varies,
o s w s
It shows that V /V decreases while V /V increases as
w s os
salinity increases. The salinity at which these two curves
intersect is the optimal salinity for phase behavior, S .
9
Figure 3-1 shows that with the addition of 0.1% STPP and 0.1%
NaoC0, V /V curve upshifts while V /V curve changes
2 3 w s os e
little reulting in a shift of S, from 8.75% NaCl to a higher
9
salinity of 9.6% NaCl,
Figure 3-2 shows the interfacial tension data as a
function of salinity for the system without STPP and Na2CO^.


72
Figure 3-1 The Effect of Salinity on Solubiliza
tion Behavior.


INTERFACIAL TENSION, dynes/cm
73
1 1 1 1 1
SURFACTANT FORMULATION-
TRS 10-410 (1.5%)t EOR 200(2.5%) IBA (3.0%)
OIL- n-DODECANE
TEMPERATURE = 25 lC
I2
8
6
2 -
10
8
6
4
10
7.5
8.0 8 5 9.0
SALINITY, NoCI wt.%
9.5
Figure 3-2 The Effect of Salinity on Interfacial
_i
10.0
Tension.


74
It shows the y decreases while y increases as salinity
om raw J
increases. The intersection of these two curves at 8.6% NaCl
concentration determines the optimal salinity for interfacial
tension behavior, At this optimal salinity, y^ equals
-3
y and there is an ultralow interfacial tension of 10
raw
dynes/cm. The interfacial tension was not measured in the
presence of STPP and ^200^. However, because the system with
sacrificial agents also formed three phases after equilibration,
it is believed that the ultralow interfacial tension existed
at the optimal salinity, too.
The ability of this high salt tolerance formulation to
displace oil was tested in porous media. Figure 3-3 shows the
amount of the tertiary oil recovered at different salinities
in sand packs. A maximum of 76% residual oil was recovered
at 9.0% NaCl concentration, a salinity close to the optimal
salinities designated by the phase behavior and interfacial
tension values. This maximum oil recovery at optimal salinity
is in agreement with those reported for the conventional low
salinity formulation in Chapter IV and by Reed and Healy (1977),
Boneau and Clampitt (1977), and Rathmell et al.(1978).
However, the amount of oil recovered at the optimal salinity,
although significant, is less than that attained by the
conventional systems at the same amount of injected surfactant


75
Figure 3-3 The Effect of Salinity on Percent Tertiary
Oil Recovery by 1.5% TRS 10-410 +2.5%
EOR 200 + 3% IBA of n-Dodecane in Sand
- Packs at 25 C.


76
and the same capillary number. This is attributed to the
insufficient surfactant available to displace oil ganglia.
As the highly surface-active ethoxylated sulfonate being
adsorbed, the alkyl benzene sulfonate was inactivated under
such high salinity environment. Thus, only 76% of the
residual oil was recovered.
The oil displacement in consolidated Berea core was
worse. Only 45% tertiary oil was recovered at 9.0% NaCl
(Figure 3-5) and no surfactant phase broke through as a
middle phase in the effluent solution. This is expected
because the Berea core contains clay particles and has
much higher surface area than the unconsolidated sand pack,
hence, surfactant adsorption would be more pronounced.
Hurd (1976) reported the use of STPP and ^£00^ as effective
chemical additives in preventing surfactant adsorption on
rock mineral surface. Thus, STPP and Na^CO^ were incorporated
into the formulation.
Figure 3-4 shows the effect of STPP concentration with
different amounts of Na9C0^ on the solubilization parameters.
The added chemicals have more pronounced influence on the
solubilized brine, V /V than on the solubilized oil, V /V .
w s os
Moreover, on an equal weight basis, STPP caused greater
change in the solubilization parameters than Na^CO^.
The


SOLUBILIZATION PARAMETERS, V0/Vs OR Vw/V,
Figure 3-4
The Effect of Sacrificial Agent on
Solubilization Behavior at 2f C,


TERTIARY OIL RECOVERY, PERCENT RESIDUAL OIL
78
STPP CONCENTRATION, WT.%
Figure 3-5 The Effect of Sacrificial Agent on
Tertiary Oil Recovery in Berea Cores
at 25 C.


79
effect would be amplified on the molar basis. Finally, as
STPP increases and NaCO_ decreases, V /V decreases while
2 3 os
V /V increases. This means that STPP and NaoC0o have
w s 2 3
opposite effects on the optimal salinity. Since STPP is
more effective than Na^CO^ in changing the solubilized oil
or brine, the combined effects of STPP and Na^CO^ upshift
the optimal salinity S being consistent with that shown
in Figure 3-1.
Figure 3-5 shows the effects of sacrificial agents on
the tertiary oil recovery by surfactant formulation at its
optimal salinity of 9.0% NaCl. In all formulations, STPP
and ^2*70^ were added at an arbitrary weight ratio of 1:1.
Oil recovery was increased from 45% to 62% as sacrificial
agents were added from 0% to 0.3%. The decrease in oil
recovery efficiency at 0.5% STPP and 0.5% ^2^^ can be
partially explained by the shift of the optimal salinity due
to the increased ionic strength.
Since 0.3% STPP and 0.3% Na^CO^ appeared to improve
the recovery the most, the same concentrations were added to
other salinities to see their effects on oil recovery
efficiency. Figure 3-6 shows that the maximum oil recovery
still occurs at 9.0% NaCl when the same 0.3% STPP and 0.3%
Na2C02 are included. Thus, it suggests that the same


TERTIARY OIL RECOVERY, PERCENT RESIDUAL OIL
80
Tertiary Oil Recovery of 1.5% TRS 10-410 +
2.5% EOR 200 + 3% IBA in X% NaCl +0.3% STPP
+ 0.3% Na0COQ in n-Dodecane in Berea Cores
at 25 C. 2 J
Figure 3-6
FINAL OIL SATURATION, S0


81
optimal salinity can be found for the surfactant solution oil
systems with and without sacrificial agents added. Yet, the
solubilization behavior curves (Figure 3-1) indicate that
with the addition of 0.1% STPP and 0.1% ^£00^, the optimal
salinity shifts to a higher value. Therefore, there must be
some other mechanism involved.
In order to account for the observed oil displacement
results, the surfactant solution pH with sacrificial agents
included was measured as a function of salt concentration.
In Figure 3-7 both the brine pH and surfactant solution pH
are plotted. It shows that with 0.3% STPP and 0.3% ^200^
added, the brine pH remain constant and the sulfonate solution
pH stay relatively unchanged up to 9.5% NaCl, it then increased
drastically from 10.8 to 11.6 at 10% NaCl. For a petroleum
sulfonate-field brine-crushed field core system, Hurd (1976)
found that the equilibrium adsorption level of the surfactant
depends on the combined effects of salinity, pH, and the
carbonate ions. He further showed that minimum adsorption
occurred at the pH of 10 and 0.4% ^200^ with field brine.
Since the system studied in this chapter is a saline, high
pH and carbonate ion containing solution, a minimum in
sulfonate adsorption is expected at a specific combination
of these variables. It is conjectured that the amount of
the surfactant adsorbed onto the rock surface increase at


12
9l
~Â¥
Brine Solution -0.3%STPP + 0.3% N02CO3
O Surfactant Solution + 0.3%STPP + 0.3% NogCO^
8
.1
8.0
J
9.0
10.0
SALINITY, NaCI wt.%
The Effect of Salinity on pH of 1.5%
TRS 10-410 + 2.5% EOR 200 + 3%^ STPP
+ 0.3% Na2C03 in X% NaCI at 25C.
Figure 3-7


83
high pH, hence, the lowering of oil displacement beyond
9.0% NaCl (Figure 3-6) is explained in terms of surfactant
adsorption loss due to high pH at these salinities.
Consequently, the maximum in oil recovery did not coincide
with the optimal salinity of the system.
3.A Conclusions
Oil displacement tests in both sand packs and Berea
cores demonstrate that high salinity formulations can be
designed by mixing petroleum sulfonate, cosolvent and
electrolytes with ethoxylated sulfonate. For the case of
Berea cores, sacrificial agents are needed to overcome the
surfactant loss in porous media. The type and amount of
sacrificial agent does affect the maximum amount of oil
recovery.
Furthermore, similar to the low salinity formulations,
the salinity formulations also gives maximum oil recovery
at optimal salinity when no sacrificial agents were used.
However, this is not true with the sacrificial agents
incorporated.


CHAPTER IV
EFFECT OF OIL BANK INJECTION ON
OIL DISPLACEMENT EFFICIENCY
4.1 Introduction
The oil displacement in porous media is commonly modeled
as the competition between the capillary force and the
viscous force, which implies that the only deciding criteria
in a surfactant/polymer process are the low interfacial
tension and the adequate mobility control. However, oil
ganglia upon mobilization by the surfactant slug, must
coalesce to form an oil-water bank before they can be
effectively displaced from the porous medium. Thus, the oil
recovery vs. capillary number empirical correlation, a
steady state relationship, fails to consider the transient
flow behavior of the oil during displacement process. Further
more, it was pointed out that during core flooding experiments
most tertiary oil is produced in form of the oil-water bank
(Davis & Jones, 1968; Reed & Healy, 1977). Therefore, in
order to ensure a successful tertiary oil recovery process,
the factors controlling the initiation and the propagation
of an oil-water bank must be understood.
84


85
Taking data from laboratory studies (Cash et al., 1975)
and field reports (Strange & Talash, 1976; Whitley & Ware,
1976; Widmeyer et al., 1976), Wasan et al.(1977) attributed
the success and failure of surfactant systems in oil displace
ment to oil-water bank formation. This in turn reflects the
stability of emulsions produced by the surfactant solution.
They proposed that the systems which coalesce rapidly would
form an oil-water bank easily, and hence can be displaced
efficiently. On the other hand, for the systems producing
stable emulsion, the formation of oil-water bank is delayed
resulting in a poor oil recovery. They further correlated
the coalescence of oil droplets with the interfacial film
viscosity at the oil/brine interface. For the surfactant-
crude oil systems they studied, it was found that a decrease
in interfacial viscosity corresponded to a decrease in coales
cence time, and thus, inducing the formation of an oil-water
bank and better oil recovery.
In this chapter, a different approach is taken to study
the effect of the oil-water bank on the oil displacement
efficiency. Rather than investigating the factors that
enhance oil-water bank formation, a "seed" oil slug is
injected to initiate the formation of an oil-water bank.
The effect of the size of the injected oil slug on the oil
recovery is examined. In order to test the generality of


86
this novel idea, these studies are conducted in both the
consolidated sandstone cores and the unconsolidated sand
packs for both the concentrated and the dilute surfactant
systems.
4.2 Materials
In this chapter, chemicals used were:
Surfactants: TRS 10-410 (61.2% active) and TRS 10-80 (80%
active), Witco Chemicals Company;
Cosolvent: 99% pure isobutanol, Chemical Samples Company;
Salt: A.C.S. certified NaCl crystal, Fisher Company;
Polymers: Pusher 700, Dow Chemical Company, and Polymer
340, Calgon Corporation, both polymers are
polyacrylamides;
Sacrificial Chemicals: Reagent grade sodium carbonate (^2^^)
and sodium tripolyphosphate (STPP), Fisher Company.
All chemicals were used as received and solutions were prepared
in distilled deionized water.
Oil displacement tests were carried out in sand packs
and Berea cores. The sand packs, 1.06" diameter by 7" long,
had an average porosity of 38% and permeability of 3.0 darcy.
The Berea cores, 1" square by 12" long, cast in expoxy resin,
had an average porosity of 18% and permeability of 220 milli-
darcy. New sand packs and Berea cores were used in each run.


Full Text
UNIVERSITY OF FLORIDA
3 1262 08556 9589



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