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


Material Information

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


Subjects / Keywords:
Oil fields -- Production methods   ( lcsh )
Secondary recovery of oil   ( lcsh )
bibliography   ( marcgt )
non-fiction   ( marcgt )


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

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Source Institution:
University of Florida
Rights Management:
All applicable rights reserved by the source institution and holding location.
Resource Identifier:
oclc - 05664669
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Full Text



Michael Yao-Chi Chiang




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


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.



ACKNOWLEDGMENTS......................................... iii

LIST OF TABLES....................... ........................ vii

LIST OF FIGURES............. ..... ......... .............. viii

ABSTRACT.................................................. xi


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


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

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

FORMULATIONS...................................... 63

3.1 Introduction................................. 63
3.2 Materials and Methods......................... 65
3.3 Results and Discussion....................... 71
3.4 Conclusions.................................... 83

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


5.1 Conclusions.................................. 119

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



I DESCRIPTION OF THE SURFACTANTS.................... 126


II.1 Apparatus................................... 128
11.2 Procedure.................................. 133

BIBLIOGRAPHY.............................................. 135

BIOGRAPHICAL SKETCH...... ............................... 141


Table Page

2-1 The Effect of Equilibration on Oil Displace-
ment in Sand Packs at 250C. (0.05% TRS 10-80
in 1% NaC1 vs. n-Octane)......................... 36

2-2 Interfacial Tension and Emulsification Time
of 0.05% TRS 10-80 in 1% NaCI vs. n-Octane
at 250C.......................................... 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% NaCI 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% NaC1 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% NaCI).............. 70

4-1 Oil Recovery of 5% TRS 10-410 + 3% IBA in X%
NaC1 Displacing n-Dodecane in Sand Packs......... 90

4-2 Oil Recovery of 0.05% TRS 10-80 in 1% NaCI
Displacing n-Octane in Berea Cores............... 91

4-3 Effect of Sacrificial Agents and Oil Bank in
Oil Recovery........................................ 110


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% NaC1 Displacing n-Octane
in Sand Packs at 25'C ............................ 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% NaC1 on Quartz.............................. 45

2-5 Contact Angle of n-Octane vs. Equilibrated 0.05%
TRS 10-80 in 1% NaC1.............................. 46

2-6 Continuous Injection of 0.1% TRS 10-410 + 0.06%
IBA in X% NaC1 Displacing n-Dodecane in Sand
Packs at 25C........................... .......... 50

2-7 Continuous Injection of 0.1% TRS 10-410 + 0.06%
IBA in X% NaC1 Displacing n-Dodecane in Sand
Packs at 25C....................................... 51

2-8 Oil Recovery in Berea Cores at 250C. (Continu-
ous Injection of 0.1% TRS 10-410 + 0.06% IBA
in X% NaC1 Displacing n-Dodecane................... 57

2-9 Oil Displacement of 0.1% TRS 10-410 + 0.06%
IBA in 2% NaC vs. n-Dodecane....................... 59


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 250C............... 78

3-6 Tertiary Oil Recovery of 1.5% TRS 10-410 +
2.5% EOR 200 + 3% IBA in X% NaC1 + 0.3% STPP
+ 0.3% Na2CO3 in n-Dodecane in Berea Cores
at 25"C......................................... 80

3-7 The Effect of Salinity on pH of 1.5% TRS 10-410
+ 2.5% EOR 200 + 3% STPP + 0.3% Na2CO3 in X%
NaCl at 25 0C...................................... 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 NaC1 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% NaCI on n-Dodecane in Berea Cores
at 25C ........................................... 97

4-6 Final Oil Saturation in Sand Packs 5% TRS 10-410
+ 3% IBA in X% NaCI Displacing n-Dodecane at
25C..... ................... ..... ..... ........... 99


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
25 C............................................... 112

4-11 Oil Displacement of 0.05% TRS 10-80 + 0.05%
Na2CO3 + 0.05% STPP in 1% NaCl vs. n-Octane....... 114

4-12 Adsorption and Partitioning of Surfactant
in Porous Medium.......... ........................ 117

II-1 Flow Through Porous Media Apparatus............... 131

II-2 Permeability Determination Plot of Sand
Pack 15-43........................................ 134


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



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


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

improving the oil recovery process is delineated. Moreover,

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




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,



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

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 shows 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, economically, 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

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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

-- 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., Le surfactant loss may

occur front 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.

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,

N a dimensionless figure written as N = where V is
cc 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

is N = o where cose 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

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 1-
( V w 0.4
ycose w 0
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
T Ly D
- 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.

The term L- when incorporated with the permeability, K, can

be converted to the capillary number, by the Darcy's
law: V = 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

laboratory waterflooding condition, 40% residual oil satura-

tion corresponded to a capillary number of 10-6

It was proposed by Taber (1969) and Melrose and

Brandner (1974) that the capillary number should be increased

to 10-3 or 10-2 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

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

(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


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

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


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

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

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


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

should correspond to this maximum 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

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

tension between excess oil/microemulsion or microemulsion/

excess brine phases is yom or y mw, respectively.

As salinity increases, y and V /V increase while
mw o s

Y and V /V decrease. The salinity, at which y inter-
om w s mw

sects m' or V /V intersects V /V is the optimal
om o s w s

salinity for interfacial tension behavior, S or phase behavior,

S respectively. From the numerous published data on the S

and the S4 (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,

i.e., the higher of the two interfacial tensions ( om or

Ymw) controls the oil displacement efficiency. The yom

correlates with the interfacial tension at the surfactant

slug front/oil-water bank interface while the y

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

Ymw are low and equal, a maximum oil recovery is obtained.

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, V /V

and V /Vs can be measured as the parameter varies. The

intersection of the two curves then determines the optimal

value of that parameter. Thus, the "middle" phase formation

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,
k k
X A and X ro----
rrw w ro
w 0-,ro 1I

are the mobility of water and oil respectively, where krw

kro and i w, y are the relative permeabilities and

viscosities of water and oil respectively (Gogarty et al.,


1.3.1 Permeability

When a Newtonian fluid of viscosity p 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

Q0 K( P
A 11 AL

where K, the proportionality constant is the permeability of

the porous medium. Here, Q is measured in cm3/sec, A in
cm p in centipoise, AP in atmosphere and AL in cm, K
has the dimension of cm or darcy, with

1 darcy = 9.87 x 109 cm2

When defined by the Darcy's equation, the permeability,

like the porosity, 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



J <----- A ------

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

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).

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, k., 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, kri, expressed in percent. It is found that

the sum 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:

Permeability Symbol Equation

Single-phase Absolute K K =
Flow Permeability A AP

Effective k. k = Ek Permeability i i A AP
Relative i <
Permeability ri ri K ri<

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, Ab, equals

the sum of the mobilities of oil, ro, and water, rw,

within the bank. This is written as

k k
x x +X A .[ ] ro + k rw
b ro rw b p w1 b
o 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



w o


0 20 40 60 80


Figure 1-3

The Effect of Water Saturation on Oil
and Water Relative Permeability and
Total Mobility.

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


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?

* 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


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


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,

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. 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 in 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

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.


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

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 NaCI crystals (1% NaCI) were

dissolved in distilled, deionized water to make the surfactant

stock solutions by weight. Then, they were diluted by brine

(1% NaCI) to the desired concentration just before the start

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 25 C. 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 microsyringe, an oil drop was deposited

on the underside of a smooth, polished quartz surface sub-

merged in aqueous solutions at 250C. 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

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


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 equilibratedd oil phase displaced by equilibrated

aqueous phase, F in Table 2-1), 94% oil was recovered at










S 0/






! 0 IN3033d 'k3A032 710IC




Q n




S o


S 4-i

S c o
o c



0 4-4


0.05% TRS 10-80 concentration as compared to 65% at either

0.005% or 0.5% concentration. This maximum oil recovery at

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% NaCI 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.

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




o -4

u 0

U 0



0 0-0

0 CO

4- "

(i 0o -

% 0

0 0



* LlJ










,= -


^z 2



J i


oP -o







o C






i< Cm <6



I I 0


r ,
I )

I- e




i X I

dIO .N33a3d',8a3A033y 110



00 -4
r0 (


w U

0 0

w U


o C

D ca

-j z

0 0




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

o C.

0 0

z Z
< LL
L. Z.a
0 ,a 0 /
-c u: u z 4-4
0 0

0 0 o

0 i
,- X o

U 0

------i ,i- a:

0 0

Li-0 Zo

1 z l z p

< U-?<
o U Ld 0
zr L.-oU) 6
U .. O I

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


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. Thus, 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

measured in vitro is presumably not achieved in 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% NaC1, 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% NaCI and fresh oil/

equilibrated surfactant solution are 50.8 and 0.731 dynes/cm,

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


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, Sof was

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

systems and the results are listed in Table 2-2. Except for

the system of fresh oil/l% NaC1, 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


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

Table 2-2 Interfacial Tension and Emulsification Time
of 0.05% TRS 10-80 in 1% NaCI vs. n-Octane
at 250C.


I. Fresh 011/1% NaCI

II. Fresh Oil/Equili-
brated Surfactant

III. Fresh Oil/Fresh
Surfactant Solution

IV. Equilibrated Oil/
1% NaC1

V. Equilibrated Oil/
Equilibrated Sur-
factant Solution

VI. Equilibrated Oil/
Fresh Surfactant

J5 *






(minutes) (% OIP)












* 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 H O at 200C, y 50.8 dynes/cm, "Inter-
facial Phenomena", Davis and Rideal, Chapter 1, p.17 Table 1.

Equilibrated n-Octane vs.
0.05% TRS 10-80 in 1% NaCl

Equilibrated n-Octane vs.
1% NaCI


Figure 2-4


Contact Angle of n-Octane vs. 0.05% TRS 10-80
in 1% NaC1 on Quartz.


Figure 2-5

Contact Angle of n-Octane vs. Equilibrated
0.05% TRS 10-80 in 1% NaC1.


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).

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% NaC1 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

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 + 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% NaCl--n-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

Soiinity, NaCI wt.%

Figure 2-6

Continuous Injection of 0.1% TRS 10-410
+ 0.06% IBA in X% NaC1 Displacing
n-Dodecane in Sand Packs at 25 C.

dIO IN333d 'Ay3AO033 110




w +


-to -
0 0

0 0

-H T


0 1m


0 0

( g^

r1 i-

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 10-410--n-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 10-410--n-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 10-410--n-dodecane

system with and without IBA. Therefore, the observed difference

in oil recovery cannot be explained by the change in interfacial










0 <+ ,

to 0u

*e f


I rl

a u
c 0









e 4Jd
1 C










Q 0

0 4-

4- -1H
0) C

4 J
o 0

E r-4

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.

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% NaC1),

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

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 run. The cumulative oil



Permecbility = 450 millidorcy
Velocity = 2.3 Ft/Day


60 F

0 0.5


1.5 2.0
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% NaC1 Displacing n-Dodecane)





20 c



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


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

isd cV'aouajajpiC aGnssaid

0 0 0
03/3 luoJsad 'UO!,DJ4ua3uo3 ,uoDDjlJnS ,uan|lj3
AJaAO38a ao3DOd-ul-I!0 (uGJjad
(uaoJsd 'n3 I!0

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/C

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.

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.

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 in 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

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.


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 (Na2CO3) and sodium tripolyphosphate


(STPP) are two of the effective chemicals acting as sacri-

ficial agents (Hurd, 1976; Bae & Petrick, 1976; Hill et al.,


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% NaC1 and 0 ppm

divalent ions. However, Geffen (1975) pointed out that the

majority of the fields suitable for surfactant flooding

contain at least 5% NaC1 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 (CaS04 2H20) 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.

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% NaC1 alone or 4% NaC1 and 40,000 ppm

CaC12. 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
in below 103 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 NaCI mixed

in deionized distilled water by weight on 100% active basis.

The TRS 10-410 is 61.2% active petroleum sulfonate supplied

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

(Na2CO3) 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 250 1 C. After vigorous shaking, the surfactant and

oil mixtures were left standing for 6 weeks until

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 250 10C (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 250

1 C. 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

cn (1 Cn ooco 00 oo 0 o
r-i in nC r, CO r, Co 00 C)

crCi 0C O c- r c0wi4
r-4 ,- r-i i-l ,-1 v-q v-I Cl Cl



CO 0
o w


m H

U B^









#4- 0
0 o

I u


r-l .,-4
4-< 0
0 Qo


10 inO
-zr Cn '.0

0 0

S if o i)
c\ C' c' r-I

o0 CMN -T a
CMl C4 n C4 CM

c0 -< r. Ch

-:J-; .
-Zr u.


0- l.
oo I-
< -.


C1 N





a; V)





o u






u m

C *
*H (U 4-

V) C






+ 4



o 'a



0 C

O0 i


Lr ui
0o 00 0N 0o




*-3 og Oo 0 N-


0 o-I
3 0


C (8
tfl 6^

Viscosity of Surfactant Slug (2.5%
TRS 10-410 + 2.5% EOR 200 + 3% IBA
in X% NaCI).

NaC1, wt.%






Viscosity, c.p.






Table 3-3


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 250 0.1 C 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 system 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 nlotted in Figure 3-1 as salinity varies.
o s w s
It shows that V /V decreases while V /V increases as
w s o s

salinity increases. The salinity at which these two curves

intersect is the optimal salinity for phase behavior, S .

Figure 3-1 shows that with the addition of 0.1% STPP and 0.1%

Na2CO3, V /V curve upshifts while V /V curve changes

little resulting in a shift of S from 8.75% NaC1 to a higher

salinity of 9.6% NaC1.

Figure 3-2 shows the interfacial tension data as a

function of salinity for the system without STPP and Na2CO3.


TRS 10-410(1.5%) EOR 200(2.5%) -IBA(3%)
0D-- NO STPP 8 No2 C053
20 WITH 0.1% STPP a
S0.1% N2 CO3


15 VO /sVs
0 \ p

SV /V/

S\ /


8.0 9.0 10.0

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

I 1 I I I
TRS 10-410(1.5%)+ EOR 200(2.5%) + IBA(3.0%)



7.5 8.0 8.5 9.0 9.5 10.0

The Effect of Salinity on Interfacial Tension.

6 _

Figure 3-2

It shows the y decreases while yw increases as salinity

increases. The intersection of these two curves at 8.6% NaC1

concentration determines the optimal salinity for interfacial

tension behavior, S At this optimal salinity, Yom equals

Y and there is an ultralow interfacial tension of 10-

dynes/cm. The interfacial tension was not measured in the

presence of STPP and Na2CO3. 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% NaC1 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





8.0 9.0 10.0


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.

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% NaCI

(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 Na2CO3 as effective

chemical additives in preventing surfactant adsorption on

rock mineral surface. Thus, STPP and Na2CO3 were incorporated

into the formulation.

Figure 3-4 shows the effect of STPP concentration with

different amounts of Na2CO3 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 o a
Moreover, on an equal weight basis, STPP caused greater

change in the solubilization parameters than Na2CO3. The

SURFACTANT:1.5% TRS10-410 t2.5% EOR 200
3.0% IBA IN 9%NoCI X% No2CO3

--- 0% No2C03
>" *--- 0.1% Na2CO3

>3 20- A-- -- 0.3% N2CO03



S 15


U) O

51 0
Ii i
0 0.1 0.2 0.3 0.4 0.5 0.6

Figure 3-4 The Effect of Sacrificial Agent on
Solubilization Behavior at 2. C.

SLUG: 0.1 P.V. 1.5%TRS 10-410+2.5% EOR200
+3.0%IBA IN 9% NaCI

CALGON POLYMER 340 2,000ppm IN 9% NoCI
1.0 RV.

0 60


o C

a. .
40- -.20

\ / I-

0 0.1 0.2 0.3 0.4 0.5

20 t I i 1 -.10
0 0.1 0.2 0.3 0.4 0.5

Figure 3-5 The Effect of Sacrificial Agent on
Tertiary Oil Recovery in Berea Cores
at 25 C.

effect would be amplified on the molar basis. Finally, as

STPP increases and Na2CO3 decreases, V /V decreases while

V /V increases. This means that STPP and Na CO have
w s 2 3

opposite effects on the optimal salinity. Since STPP is

more effective than Na2CO3 in changing the solubilized oil

or brine, the combined effects of STPP and Na2CO3 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% NaC1. In all formulations, STPP

and Na2CO3 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% Na2CO3 can be

partially explained by the shift of the optimal salinity due

to the increased ionic strength.

Since 0.3% STPP and 0.3% Na2CO3 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% NaC1 when the same 0.3% STPP and 0.3%

Na2CO3 are included. Thus, it suggests that the same

9.0 9.5 10.0

Figure 3-6

Tertiary Oil Recovery of 1.5% TRS 10-410 +
2.5% EOR 200 + 3% IBA in X% NaC1 + 0.3% STPP
+ 0.3% Na CO3 in n-Dodecane in Berea Cores
at 250 C. 23

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% Na2CO3, 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% Na2CO

added, the brine pH remain constant and the sulfonate solution

pH stay relatively unchanged up to 9.5% NaC1, 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% Na2CO3 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

o /
0"- -.. -



p *

* Brine Solution +0.3%STPP+0.3% No2CO3
0 Surfactont Solution+0.3%STPP+0.3% No2 C03

8.0 9.0 10.0


Figure 3-7

The Effect of Salinity on pH of 1.5%
TRS 10-410 + 2.5% EOR 200 + 3% STPP
+ 0.3% Na2CO3 in X% NaC1 at 250C.




high pH, hence, the lowering of oil displacement beyond

9.0% NaCi (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.

3.4 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


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



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.


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

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


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 NaC1 crystal, Fisher Company;

Polymers: Pusher 700, Dow Chemical Company, and Polymer

340, Calgon Corporation, both polymers are


Sacrificial Chemicals: Reagent grade sodium carbonate (Na2CO3)

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.


The experimental setup as well as the detailed procedure

preparing these porous media are described in Appendix II,

while their physical characteristics are listed in Tables

4-1 and 4-2.

4.3 Methods

4.3,1 Formulations

Basically, two types of surfactant formulations have

been investigated, the high surfactant concentration and the

low surfactant concentration, in the oil displacement studies.

The high concentration system is composed of 5% TRS 10-410

plus 3% IBA in different salinity brines and the low concen-

tration system is 0.05% TRS 10-80 in 1% NaC1. When employed

in Berea cores, the low surfactant concentration formulation

also includes 0.05% STPP and 0.05% Na2CO3 as sacrificial

agents to reduce sulfonate adsorption loss. All concentrations

are given on a weight basis.

The mobility buffers consisted of either Pusher 700

(500 ppm) or Polymer 340 (2,000 ppm) dissolved in brine; the

polymer concentration was chosen to have a favorable mobility

ratio during flooding process. The viscosity of the solutions

was measured on a Brookfield viscometer, Model LVF with UL

Adaptor at 25.0 0.050C. The results are shown in Figure 4-1.