copyright by jose ernesto parra perez 2016

Copyright

by

Jose Ernesto Parra Perez

2016

The Thesis Committee for Jose Ernesto Parra Perez

Certifies that this is the approved version of the following thesis:

Experimental Investigation of Viscous Forces during

Surfactant Flooding of Fractured Carbonate Cores

APPROVED BY

SUPERVISING COMMITTEE:

Gary A. Pope

Matthew T. Balhoff

Supervisor:

Co-supervisor:



by

Jose Ernesto Parra Perez, B.S. P.E.

Thesis

Presented to the Faculty of the Graduate School of

The University of Texas at Austin

in Partial Fulfillment

of the Requirements

for the Degree of

Master of Science in Engineering

The University of Texas at Austin

August 2016

Dedication

To my parents, my sister and Lore

v

Acknowledgements

First I want to express my most sincere gratitude to my supervisors Dr. Gary Pope

and Dr. Matthew Balhoff. Working and learning from and with you has been a pleasure

and a privilege. My deepest admiration goes to Dr. Pope who leads by example and who

has greatly inspired me to become better as a professional and as a person. My greatest

appreciation also goes to Dr. Balhoff for his tremendous commitment to challenging,

guiding and supporting me throughout my studies.

I would like to thank the people who contributed for performing this research,

Miguel Mejia, Sean Li, Mohsen Tagavifar and Nadeeka Upamali. I also want to thank

Chevron Energy Technology Co. for its support for this research and the sponsors of the

Chemical EOR industrial affiliates of The University of Texas at Austin.

I want to thank my friends Almas, Pável, Enrique, Héctor, José, Pengpeng,

Leonard, Beibit, Brian and Bruno, as well as my fellow students, the research staff and the

professors in the Department of Petroleum and Geosystems Engineering.

My deepest gratitude goes to my sponsor Instituto Mexicano del Petróleo (IMP) for

supporting and allowing me to pursue my graduate studies at UT. I look forward to going

back to México and contributing to make my country better.

I would like to thank Dr. Fernando Samaniego for all the support throughout the

years and for inspiring me to pursue the highest goals. I also want to thank the people who

have supported me through my petroleum engineering career, Dr. Rafael R. Nieto, M.S. E.

María Isabel Villegas, M.S. E. José Huezo, Dr. Édgar Rangel and Dr. Pedro Silva.

Finally I want to thank my parents, my sister and Lore. You are the people that I

want to make the most proud of me. Thanks for everything.

vi

Abstract



Jose Ernesto Parra Perez, M.S. E.

The University of Texas at Austin, 2016

Supervisor: Gary A. Pope

Co-supervisor: Matthew T. Balhoff

The objective of this research was to investigate the effects of viscous forces on the

oil recovery during surfactant flooding of fractured carbonate cores, specifically, to test the

effects of using surfactants that form viscous microemulsions in-situ.

The hypothesis was that a viscous microemulsion flowing inside a fracture can

induce transverse pressure gradients that increase fluid crossflow between the fracture and

the matrix, thus, enhancing the rate of surfactant imbibition and thereby the oil recovery.

Previous experimentalists assumed the small viscous forces were not important for

oil recovery from naturally fractured reservoirs (NFRs) since the pressure gradients that

can be established are very modest due to the presence of the highly conductive fractures.

Hence, the most common approach for studying surfactants for oil recovery from NFRs is

to perform static imbibition experiments that do not provide data on the very important

viscous and pressure forces.

vii

This is the first experimental study of the effect of viscous forces on the

performance of surfactant floods of fractured carbonate cores under dynamic conditions.

The effects of viscous forces on the oil recovery during surfactant flooding of

fractured carbonate cores were tested by conducting a series of ultralow interfacial tension

(IFT) surfactant floods using fractured Silurian Dolomite and Texas Cream Limestone

cores. The viscosity of the surfactant solution was increased by adding polymer to the

surfactant solution or by changing the salinity of the aqueous surfactant solution, which

affects the in-situ microemulsion viscosity. The fractured cores had an extreme

permeability contrast between the fracture and the matrix (ranging from 2500 to 90,000)

so as to represent typical conditions encountered in most naturally fractured reservoirs.

Also, non-fractured corefloods were performed in cores of each rock type for comparison

with the results from the fractured corefloods.

In all the experiments, the more viscous surfactants solutions achieved the greater

oil recovery from the fractured carbonate cores which contradicts conventional wisdom.

A new approach for surfactant flooding of naturally fractured reservoirs is

presented. The new approach consists of using a surfactant solution that achieves ultralow

IFT and that forms a viscous microemulsion. A viscous microemulsion can serve as a

mobility control agent analogous to mobility control with foams or polymer but with far

less complexity and cost.

The oil recovery from the fractured carbonate cores was greater for the surfactant

floods with the higher microemulsions, thus, it is expected that using viscous

microemulsion can enhance the oil recovery from naturally fractured reservoirs.

viii

Table of Contents

List of Tables ...........................................................................................................x

List of Figures ........................................................................................................ xi

Chapter 1 Introduction ...........................................................................................1

Chapter 2 Background ............................................................................................7

2.1 Naturally fractured reservoirs ...................................................................7

2.1.1 Definition and classification .........................................................7

2.1.2 Physical properties of naturally fractured carbonate reservoirs ..10

2.2 Surfactants and microemulsions .............................................................19

2.2.1 Surfactants...................................................................................20

2.2.2 Microemulsion phase behavior ...................................................21

2.2.3 Microemulsion viscosity .............................................................24

2.3 Surfactants recovery mechanisms in fractured media ............................27

2.3.1 Capillary driven imbibition .........................................................29

2.3.2 Gravity driven imbibition ...........................................................31

2.3.3 Scaling of imbibition...................................................................33

2.3.4 Viscous crossflow .......................................................................35

2.4 Surfactants floods in fractured carbonate media .....................................37

2.5 Summary .................................................................................................43

Chapter 3 Experimental Materials and Procedures ...............................................44

3.1 Fluids.......................................................................................................44

3.1.1 Microemulsion phase behavior ...................................................44

3.1.2 Microemulsion viscosity .............................................................47

3.2 Rocks.......................................................................................................49

3.3 Experimental apparatus ...........................................................................49

3.4 Fractured coreflood procedure ................................................................50

Chapter 4 Experimental Results and Analysis .......................................................53

4.1 Silurian Dolomite experiments ...............................................................56

ix

4.1.1 Fractured coreflood #1 ................................................................56


4.1.3 Non-fractured coreflood #1.........................................................63

4.1.4 Analysis of the Silurian Dolomite coreflood experiments ..........66

4.1.5 Static versus dynamic imbibition ................................................67

4.1.6 Limitations of using Silurian Dolomite cores .............................69

4.2 Texas Cream Limestone experiments .....................................................70





4.2.5 Non-fractured coreflood #2.........................................................80

4.2.6 Analysis of the results .................................................................82

Chapter 5 Conclusions and Future Work ...............................................................87

5.1 Conclusions .............................................................................................87

5.2 Future work .............................................................................................90

Bibliography ..........................................................................................................93

x

List of Tables

Table 2.1: Types of naturally fractured reservoirs (Cinco Ley 1996) ..................9

Table 2.2: Types of naturally fractured reservoirs (Nelson 2001) .....................10

Table 2.3: Scaling groups for gravity dominated imbibition .............................34

Table 3.1: Surfactant formulation at optimum conditions .................................46

Table 3.2: Mineralogy of Silurian Dolomite and Texas Cream Limestone .......49

Table 4.1: Fractured core properties ..................................................................54

Table 4.2: Non-fractured core properties ...........................................................54

Table 4.3: Performance data for the Silurian Dolomite coreflood

experiments .......................................................................................55

Table 4.4: Performance data for the Texas Cream Limestone coreflood

experiments .......................................................................................55

xi

List of Figures

Fig. 1.1: Matrix-fracture system of a mature naturally fractured reservoir .......1

Fig. 2.1: a) Actual fractured carbonate rock and b) Idealized reservoir for

modeling fluid flow (Warren and Root, 1963) ...................................8

Fig. 2.2: Elementary volume of a naturally fractured reservoir ......................10

Fig. 2.3: Slit representation of a fracture .........................................................13

Fig. 2.4: Water-wet (left) and oil-wet (right) rock ..........................................17

Fig. 2.5: Phase behavior salinity scan showing Type I-III-II phase

environments .....................................................................................22

Fig. 2.6: Interfacial tensions and solubilization ratios versus salinity

(Healy et al., 1976)............................................................................23

Fig. 2.7: Microemulsion viscosity as a function of oil concentration

in the microemulsion (Tagavifar et al., 2016)...................................26

Fig. 2.8: Microemulsion viscosity as a function of shear rate

(Tagavifar et al., 2016)......................................................................27

Fig. 2.9: Static imbibition experiment .............................................................29

Fig. 2.10: a) Countercurrent and b) co-current imbibition profiles ...................31

Fig. 2.11: Flow in parallel layers with no hydraulic communication ................36

Fig. 2.12: Schematic representation of the physical fracture-matrix

system used for chemical floods (Najafabadi et al. 2008) ................38

Fig. 2.13: Transverse pressure gradients for a surfactant flood in a

fractured block (Abbasi et al., 2010) ................................................39

Fig. 2.14: Effect of microemulsion viscosity on oil recovery from

fractured media (Abbasi et al., 2010)................................................40

xii

Fig. 2.15: CT scan of a manually fractured carbonate reservoir core

(Lu et al., 2014) .................................................................................41

Fig. 2.16: Imbibition profile of ultralow IFT surfactants into an

oil-wet matrix (Mirzaei et al., 2016) .................................................42

Fig. 3.1: Oil and water solubilization ratios after a NaCl salinity scan at

78 °C and 90 days of equilibration. Oil volume fraction is 30% ......46

Fig. 3.2: Microemulsion viscosity as a function of salinity at 1 and 10 s-1

and 78°C. Oil volume fraction is 30% ..............................................47

Fig. 3.3: Microemulsion viscosity as a function of the oil volume fraction

in the microemulsion at 1 and 10 s-1 and 78 °C. Total oil volume

fraction is 30% ..................................................................................48

Fig. 3.4: Microemulsion viscosity as a function of shear rate for different

salinities at 78 °C. Oil volume fraction is 30% .................................48

Fig. 3.5: Coreflood experimental apparatus ....................................................50

Fig. 3.6: Artificially fractured Texas Cream Limestone core .........................52

Fig. 4.1: CT images at arbitrary cross sections of the fractured Silurian

Dolomite core used in the FRAC-1 experiment ...............................56

Fig. 4.2: Oil recovery from a fractured core for a surfactant flood followed

by a surfactant-polymer flood (fractured coreflood #1) ...................57

Fig. 4.3: Viscosity of the surfactant-polymer solution ....................................58

Fig. 4.4: Pressure drop for a surfactant flood followed by a surfactant-

polymer flood (fractured coreflood #1) ............................................59

Fig. 4.5: Photographs of Silurian Dolomite core a) before surfactant

imbibition (So= 1), b) after surfactant imbibition (So= 0.21). The

core was cut in half and at several cross sections after the

xiii

surfactant flood. The lighter shade at the bottom of the vertical

core indicates a lower oil saturation ..................................................60

Fig. 4.6: Oil recovery from a fractured core for a surfactant flood followed

by a surfactant-polymer flood (fractured coreflood #2) ..................62

Fig. 4.7: Pressure drop for a surfactant flood followed by a surfactant-

polymer flood (fractured coreflood #2) ............................................62

Fig. 4.8: Tracer test of the Silurian Dolomite core used in the

non-fractured experiment ..................................................................63

Fig. 4.9: Oil recovery from an ASP flood of a non-fractured Silurian

Dolomite core (non-fractured coreflood #1) .....................................65

Fig. 4.10: Pressure drop data for an ASP flood in a non-fractured Silurian

Dolomite core (non-fractured coreflood #1) .....................................66

Fig. 4.11: Oil recovery from the fractured and non-fractured corefloods

performed in Silurian Dolomite cores...............................................67

Fig. 4.12: Tertiary oil recovery from surfactant imbibition under static and

dynamic conditions (fractured coreflood experiments). The core

height is 10 cm for static imbibition and 30 cm for dynamic

imbibition ..........................................................................................69

Fig. 4.13: Oil recovery for the surfactant flood at optimum salinity.

Microemulsion viscosity is 17 cp (fractured coreflood #3) ..............72

Fig. 4.14: Pressure drop for the surfactant flood at optimum salinity.


Fig. 4.15: Oil recovery for the surfactant flood at optimum salinity.


xiv

Fig. 4.16: Pressure drop for the surfactant flood at optimum salinity.


Fig. 4.17: Oil recovery for the surfactant flood with a high microemulsion

viscosity of 75 cp (fractured coreflood #5). ......................................77

Fig. 4.18: Pressure drop for the surfactant flood with a high microemulsion

viscosity of 75 cp (fractured coreflood #5) .......................................78

Fig. 4.19: Oil recovery for a surfactant flood with low microemulsion

viscosity followed by a surfactant flood with high microemulsion

viscosity (fractured coreflood #6) .....................................................79

Fig. 4.20: Pressure drop for a surfactant flood with low microemulsion

viscosity followed by a surfactant flood with high microemulsion

viscosity (fractured coreflood #6) .....................................................80

Fig. 4.21: Surfactant flood oil recovery from a non-fractured Texas Cream

Limestone core (non-fractured coreflood #2) ...................................81

Fig. 4.22: Pressure data from a surfactant flood in a non-fractured Texas

Cream Limestone core (non-fractured coreflood #2) .......................82

Fig. 4.23: Effect of the microemulsion viscosity on the oil recovery from

fractured Texas Cream Limestone cores ..........................................83

Fig. 4.24: Surfactant imbibition profile into the matrix and oil expulsion

into the fracture .................................................................................84

Fig. 4.25: Viscous crossflow due to the formation and flow of a

microemulsion in the fracture ...........................................................85

1

Chapter 1: Introduction

Naturally fractured carbonate reservoirs account for a considerable amount of the

world’s oil production and reserves. It is estimated that over 50% of the world’s oil reserves

are contained in carbonate reservoirs and that many of these reservoirs are naturally

fractured (Van Golf-Racht, 1982; Roehl and Choquette, 1985; Saidi, 1987; Chilingarian et

al., 1992; Aguilera, 1995; Nelson, 2001; Ahr 2008).

Naturally fractured reservoirs (NFRs) are composed of two distinct elements, a

fracture network that provides the essential permeability and a matrix that accounts for

most of the pore space. During primary production, the oil in the high permeability

fractures and neighboring matrix can easily flow towards the production wells leading to

very high flow rates. As the reservoir depletes, most of the oil in the fractures will be

recovered while most of the original oil in place (OOIP) will remain stored in the matrix

surrounded by water or gas saturated fractures (Figure 1.1).

Fig. 1.1‒Matrix-fracture system of a mature naturally fractured reservoir.

2

Oil recovery from the matrix of a mature naturally fractured carbonate reservoir is

challenging. Recovery can only be attained via a replacement process in which injection

fluids from secondary or enhanced oil recovery (EOR) techniques are transported into the

matrix (imbibition), while oil is expelled into the fractures where it can flow towards the

production wells.

The conventional recovery approach in NFRs has been to use pressure maintenance

techniques and/or secondary methods such as water or gas flooding that can successfully

imbibe into the matrix due to capillary or buoyancy forces (Saidi, 1987; Rodriguez et al.,

2004). However, secondary recovery processes are severely affected by two major aspects.

First, the once beneficial high permeability fractures now act as thief zones leading to

channeling and early breakthrough of injected fluids, resulting in poor reservoir

sweep/conformance. Second, capillary imbibition depends on the wettability of the

reservoir and carbonate reservoirs are often mixed wet or oil wet. When the reservoir is

water-wet, water can spontaneously imbibe into the matrix, thereby, displacing oil into the

fractures from where it is easily recovered. However, spontaneous imbibition of water into

the matrix is not significant when the matrix is oil wet. In some cases, gas is injected to

take advantage of gravity forces. Unfortunately, gas injection often results in severe

channeling and high separation costs.

Several techniques have been proposed to achieve imbibition and/or improve sweep

efficiency in NFRs, (Austad and Milter 1997, Seright 2000, Babadagli 2003; Hirasaki et

al., 2006; Boerrigter et al. 2007; Sydansk and Seright, 2007).

Surfactants have been considered for many years for enhanced oil recovery from

NFRs (Graham and Ortloff, 1970; Saidi and Hesselink, 1982). Surfactants have been used

for achieving imbibition into the oil-wet matrix of watered-out zones in NFRs and as

foaming agents during gas flooding operations to improve sweep efficiency by providing

3

mobility control or more commonly as permeability reducing agents during production

treatments in fractured wells with a high gas-oil ratio (GOR). Sweep improvement from

the watered-out zones in NFRs has been historically treated through the use of polymer

gels, which serve as blocking agents to divert the flow away from the high conductivity

fractures. However, the application of polymer gels is limited to near wellbore treatments

for production wells, since gels cannot be placed far into the reservoir and their application

only provides a short term solution for conformance control, since the injection fluids

(usually with a higher mobility when compared to oil) will eventually find the less

resistance paths in the reservoir (Sydansk and Seright 2007).

Imbibition of aqueous surfactant solutions into an oil-wet matrix can be achieved

by using surfactants that alter the wettability of the rock and/or lower the interfacial tension

(IFT) between the oil and brine. In the former case, the surfactants render the rock towards

a more water-wet state, thus achieving a positive capillary pressure that drives the

imbibition; in the latter, surfactants reduce the IFT to very low values so the capillary

pressure becomes negligible. At low IFT, surfactant imbibition is driven by buoyancy

forces.

The most common approach for studying surfactants for oil recovery from NFRs is

to perform static imbibition experiments. The core is placed inside a cell and then

surrounded by a brine solution. The oil recovery is measured as a function of time. Once

oil production ceases, the brine is replaced with a surfactant solution and the oil production

is measured. Static imbibition experiments have been used to test the effectiveness of a

wide range of surfactants (Austad and Milter 1997; Chen et al., 2001; Hirasaki and Zhang

2004; Xie et al., 2005; Adibhatla and Mohanty 2008; Zhang et al., 2009; Chen and Mohanty

2013; Li et al., 2016).

4

A lot of effort has also gone into developing scaling groups based on static

imbibition experiments (Mattax and Kyte, 1962; Iffly et al., 1972; Du Prey, 1978; Hagoort,

1980; Schechter et al., 1994, Zhang et al., 1996; Li and Horne, 2006; Li et al., 2016).

However, static imbibition experiments are not designed to provide data on the viscous and

pressure forces (dynamic effects) that are present during surfactant injection processes in

fractured media.

A few authors have investigated the dynamic effects of using aqueous surfactant

solutions for oil recovery from fractured media (Najafabadi et al., 2008; Abbasi et al., 2010;

Kiani et al., 2014; Lu et al., 2015; Mirzaei et al., 2015). These authors have shown that

viscous forces affect the imbibition process. Abbasi et al. (2010) used a simulation model

to predict that viscous pressure gradients transverse to the flow direction in the fractures

would increase the rate of surfactant imbibition into the matrix. Consequently, having a

more viscous surfactant solution flowing inside the fractures (due either to the addition of

polymer, foam or to the formation of a microemulsion) would enhance the oil recovery

from NFRs. An obvious way to increase the viscosity of an aqueous surfactant solution

would be to add polymer to the solution as is done for mobility control in surfactant floods

of non-fractured reservoirs. However, adding polymer is limited by both technical and

economic reasons. Polymer can decrease the rate of imbibition into the matrix by adsorbing

on the fracture face, plugging the pores of the matrix, and slowing diffusion of the

surfactant into the oil rich phase in the matrix. Most importantly, adding polymer increases

the cost when compared to that of solely using surfactants.

Surprisingly, there is not a single reference to experiments in the literature

regarding the use of surfactants in aqueous solutions with or without other chemicals for

simultaneously achieving imbibition and sweep improvement from the water-invaded

zones of naturally fractured reservoirs.

5

A new approach for surfactant enhanced oil recovery from NFRs was studied as

part of this research. In this new approach surfactants are designed to achieve both

imbibition and sweep improvement. The new approach consists of using a surfactant

solution that forms a viscous microemulsion when it mixes with the brine and oil.

A microemulsion has very different properties from those of the resident oil and

brine, and the injected surfactant solution. The mixture properties that most affect the oil

recovery are the interfacial tension between the microemulsion and oil, the interfacial

tension between microemulsion and water and the microemulsion viscosity. Studies in non-

fractured media have shown the great impact of the microemulsion properties on the oil

recovery (Healy et al., 1976; Pope and Nelson, 1978; Walker, 2010; Tagavifar et al., 2016).

For surfactant EOR in fractured media, low interfacial tension is required to drive the

imbibition process; then, as the surfactant imbibes into the matrix, oil is expelled into the

fractures where it mixes with the injected surfactant solution, thus, generating a

microemulsion. The newly formed microemulsion can have a viscosity several orders of

magnitude greater than that of the injected surfactant solution (very close to the viscosity

of water). A viscous microemulsion flowing inside the fractures will then serve as a

mobility control agent, inducing crossflow and increasing the rate of surfactant imbibition

into the matrix as it traverses through the reservoir from the injector to the producer.

The goal of this research was to test experimentally the hypothesis that a viscous

microemulsion flowing inside a fracture can increase the oil recovery from fractured media.

To test this hypothesis, tertiary surfactant floods were preformed following a waterflood

using mixed- to oil-wet fractured Texas Cream Limestone and Silurian Dolomite cores

with a permeability and porosity contrast characteristic of naturally fractured reservoirs (in

these experiments the fracture had a permeability on the order of hundreds of Darcy while

the matrix had an average permeability of 10 or 100 md for the two rock types

6

respectively). The experimental procedure consisted of developing a surfactant formulation

that achieved low IFT when mixed with an oil from a carbonate reservoir and synthetic

brine with high salinity and at a high temperature. The microemulsion viscosity was

changed by injecting the surfactant solution at different salinities. The experiments were

compared in terms of the rate and the ultimate oil recovery.

7

Chapter 2: Background

This chapter is divided into four sections; the first section provides an overview of

naturally fractured reservoirs and discusses the fundamental physical properties that govern

fluid flow in fractured media. The second section covers the basics of surfactants with

special emphasis on surfactants that reduce the interfacial tension to ultralow values and

on microemulsion rheology, which provides the theoretical basis for the experimental study

performed in this research. The third section discusses the mechanisms of oil recovery from

fractured carbonate rocks; special attention is given to gravity driven imbibition and

viscous crossflow effects; however, an overview of capillary driven imbibition is also

given. The fourth section summarizes the experimental and numerical studies of surfactant

floods in fractured carbonates and their implications for the present study.

2.1 NATURALLY FRACTURED RESERVOIRS

2.1.1 Definition and classification

Naturally fractured reservoirs (NFRs) are defined as those reservoirs that are

composed of two elements, a matrix and a fracture network. The matrix has the same

meaning as that pertaining to non-fractured reservoirs, but the fractures lead to distinct

physical properties and will be discussed throughout this section.

Fig. 2.1(a) is a photograph of a fractured carbonate outcrop rock (considered

analogous to NFRs). In the classical reservoir model used to represent naturally fractured

reservoirs (Barenblatt et al., 1960; Warren and Root 1963, Kazemi 1969; Kazemi and

Gilman; 1988), the matrix is represented as a series of identical rectangular blocks

separated by an orthogonal network of fractures as shown in Fig. 2.1(b).

8

a)

b)

Fig. 2.1‒a) Actual fractured carbonate rock and b) Idealized reservoir for

modeling fluid flow (Warren and Root, 1963)

Naturally fractured reservoirs were classified by Cinco Ley (1996) and Nelson

(2001); these classification schemes are presented in Tables 2.1 and 2.2. This research is

concerned with naturally fractured reservoirs of the double-porosity type within the Cinco

Ley classification and Type II according to Nelson.

9

Table 2.1‒ Types of naturally fractured reservoirs (Cinco Ley 1996)

Homogeneous

Fracture and matrix act as a

single medium, either due to the

reservoir being heavily fractured

with small matrix blocks (top), or

when the storage and flow

capacity are provided by the

fracture system (bottom).

Multiple region/

regionally fractured

The reservoir is composed of two

regions of high and low

transmissibility.

Anisotropic

Fractures aligned in one direction

result in much higher

permeability in that direction as

normal to them

Single fracture

Wells produced near or

intersected by major fractures or

faults

Double porosity

Matrix provides the storage

capacity while the fracture

network provides the essential

permeability

10

Table 2.2‒Types of naturally fractured reservoirs (Nelson 2001)

Type 1 Fractures provide the essential porosity and permeability

Type 2 Fractures provide the essential reservoir permeability

Type 3 Fractures assist permeability in an already producible reservoir

Type 4 Fractures provide no additional porosity or permeability, but act as barriers

2.1.2 Physical properties of naturally fractured carbonate reservoirs

An elementary volume of a fractured reservoir is shown in Fig. 2.2. For the

following treatment it will be assumed that the fracture is completely filled with water

while the matrix is fully saturated with oil.

Fig. 2.2‒Elementary volume of a naturally fractured reservoir

11

2.1.2.1 Porosity

Matrix porosity is defined as the void volume in the matrix to the total bulk volume

of the reservoir. Analogously, fracture porosity is defined as the ratio of the void volume

in the fractures to the total bulk volume. Then, the total porosity in a NFR is the sum of the

matrix porosity and fracture porosity

∅𝑇 = ∅𝑚 + ∅𝑓 , (2.1)

where the subscripts m and f stand for the matrix and fracture respectively. The relative

contribution of the fracture porosity to the total porosity is typically small since most of

the fluids are stored in the matrix.

In the classical approach for modeling NFRs, fractures are represented as slits

between matrix blocks. However, fractures are not perfect slits since they usually have

some amount of contact and asperities. Parameters that account for this deviation have been

introduced under different forms, such as the intrinsic fracture porosity, ϕff, or the

roughness/friction factor, ε, (Witherspoon, 1980; Van Golf-Racht, 1982). The intrinsic

fracture porosity is defined as the effective void volume of a fracture to the volume of the

fracture when considered as a perfect slit, this parameter affects both the fracture storage

and flow capacity; the friction factor, on the other hand, only affects the fracture flow

capacity.

2.1.2.2 Fluid flow in fractured media

The general equation of fluid motion was given by Cauchy (1827) as follows:

𝜕

𝜕𝑡𝜌𝑣 = −[∇ ∙ 𝜌𝑣𝑣] − ∇𝑝 − [∇ ∙ 𝜏] + 𝜌𝑔. (2.2)

where ρ is the fluid density, v is the fluid velocity, τ is the shear stress, p is the fluid pressure,

and g is the gravitational acceleration. This equation states that fluid motion occurs due to

12

convection (first term on the right hand side), molecular transport (second and third terms

respectively) and by external forces, such as gravity (last term). If the fluids are assumed

to be incompressible and the acceleration terms are neglected (valid approximation in many

fluid flow through porous media applications where the Reynolds number is low, Re <<1),

the equation of motion reduces to:

∇𝑝 + [∇ ∙ 𝜏] − 𝜌𝑔 = 0, (2.3)

𝜏 = −𝜂𝛾,̇ (2.4)

where the shear stress 𝜏 is defined as the product of the shear rate �̇� and the viscosity η=η(�̇�)

or η=μ for Newtonian fluids, in which the viscosity is not a function of shear rate. The

pressure and gravity components are always present regardless of whether the fluid is under

static or dynamic conditions. However, viscous forces only come into play when there are

velocity gradients.

Fluid flow through fractures has been usually described with the slit analog of the

Hagen-Poiseuille equation for flow between parallel plates. Since this equation is important

for the design and analysis of this experimental study, it will be derived next.

Fig. 2.3 shows the schematic representation of a fracture and an arbitrary coordinate

system. For the following derivation, it is assumed that the fracture height, H, and length,

D, are large compared to the fracture aperture b so that end effects are negligible, that there

is only one fluid flowing and that flow occurs only in the vertical upward direction (later it

is shown that transverse flow is significant during surfactant flooding processes in fractured

media).

13

Fig. 2.3‒Slit representation of a fracture

Under the stated assumptions, equation 2.3 reduces to

𝑑𝜏𝑥𝑧

𝑑𝑥= (

𝑃1 − 𝑃2

𝐻+ 𝜌𝑔),

(2.5)

𝑑𝜏𝑥𝑧 =∆Φ

𝐻𝑑𝑥, (2.6)

where Φ is the flow potential. Integrating equation 2.6 yields

𝜏𝑥𝑧 =∆Φ

𝐻𝑥 + 𝐶1. (2.7)

This equation applies to Newtonian and non-Newtonian fluids, (the former are considered

for this derivation).

Newton’s law of viscosity is mathematically expressed as

𝜏𝑥𝑧 = −𝜇 (𝑑𝑣𝑧

𝑑𝑥),

(2.8)

14

where vz denotes the fluid velocity in the z direction. Inserting equation 2.8 into equation

2.7 leads to

𝑑𝑣𝑧 = (−∆Φ

𝜇𝐿𝑥 +

𝐶1

𝜇) 𝑑𝑥, (2.9)

integrating,

𝑣𝑧 = −∆𝛷

2𝜇𝐿𝑥2 +

𝐶1𝑥

𝜇+ 𝐶2.

(2.10)

The boundary conditions are evaluated at the walls where x=±b/2 at which the fluid

velocity is zero (no slip boundary condition). Then, the fluid velocity along any point in

the 𝑥 direction is given as

𝑣𝑧 =∆𝛷

2𝜇𝐿[(

𝑏

2)

2

− 𝑥2]. (2.11)

The average fluid velocity is obtained by dividing the volumetric flow rate over the cross

sectional area to flow Db as follows

< 𝑣𝑧 >=∫ ∫ 𝑣𝑧

𝑏/2

−𝑏/2𝑑𝑥 𝑑𝑦

𝐷

0

∫ ∫ 𝑑𝑥𝑏/2

−𝑏/2

𝐷

0𝑑𝑦

, (2.12)

< 𝑣𝑧 >=

∆Φ2𝜇𝐿 [(

𝑏2)

2

𝑥 −𝑥3

3 ]

𝑥, (2.13)

< 𝑣𝑧 >=𝑏2∆𝛷

12𝜇𝐿.

(2.14)

The volumetric flow rate is given by the product of the average velocity and the cross

section area to flow

𝑞 =𝑏3𝐷

12𝜇

∆Φ

𝐻, (2.15)

this is the well-known slit analog of the Hagen-Poiseuille equation.

15

Combining equations 2.7, 2.8 and 2.15 yields the expression for the shear rate at the

fracture wall

�̇�𝑤 =6𝑞

𝐷𝑏2 (2.16)

2.1.2.3 Permeability

There are three major and distinct permeabilities in fractured media; these are the

matrix permeability, km, the fracture permeability, kf, and the effective permeability, ke,

which accounts for the fracture and matrix permeabilities and the bulk dimensions.

The permeability of the fracture shown in Fig. 2.2 is calculated using Darcy’s law

for 1D flow in the vertical direction,

𝑞 =𝐴𝑘

𝜇

∆Φ

𝐻, (2.17)

and equation 2.15, which leads to

𝑘 =𝑏3𝐷

12𝐴, (2.18)

where A can be the cross sectional area of the slit Db, which gives the permeability of the

fracture

𝑘𝑓 =𝑏2

12, (2.19)

and including the intrinsic fracture porosity (if any)

𝑘𝑓 =∅𝑓𝑓𝑏2

12, (2.20)

Or the total cross sectional area of the medium AT, which then gives the effective

permeability accounting for the fracture and matrix permeability’s and the bulk dimensions

(this would be equivalent to the permeability calculated by pressure transient tests)

16

𝑘𝑒 =𝑏3

3𝜋𝐷. (2.21)

The fracture permeability can also be calculated from the expression for single-phase flow

through parallel layers, which states that the total flow rate in a porous medium composed

of uniform layers with different permeabilities, is equal to the sum of the individual flow

rates in each layer, e.g., the fracture and the matrix. For the elementary volume shown in

Figure 2.2 this is denoted as

𝑞𝑇 = 𝑞𝑓 + 𝑞𝑚1 + 𝑞𝑚2, (2.22)

where the second subscript denotes the number of matrix elements. Inserting Darcy’s Law

in equation 2.22 yields

𝐴𝑇𝑘

𝜇

∆Φ

𝐻=

𝐴𝑓𝑘𝑓

𝜇(

∆Φ

𝐻) +

𝐴𝑚1𝑘𝑚1

𝜇(

∆Φ

𝐻) +

𝐴𝑚2𝑘𝑚2

𝜇(

∆Φ

𝐻). (2.23)

Assuming homogeneous matrix blocks with the same dimensions and that the same

pressure drawdown is applied to each layer, leads to

𝑘𝑒 =𝐴𝑓𝑘𝑓 + 2𝐴𝑚𝑘𝑚

𝐴𝑇, (2.24)

and the fracture permeability can be calculated as

𝑘𝑓 =𝐴𝑇𝑘𝑒 − 2𝐴𝑚𝑘𝑚

𝐴𝑓. (2.25)

2.1.2.4 Wettability

Sections 2.1.2.1 to 2.1.2.3 dealt exclusively with rock properties and considered

that only one fluid phase was present; however, at least two fluid phases are generally

present in petroleum reservoirs. The first phenomenon that arises from a porous medium

containing two or more immiscible phases is known as wettability. Wettability is defined

17

as the tendency of a fluid to spread on a solid surface in the presence of a second immiscible

fluid. Rock-fluid systems are generally classified as water-wet, intermediate-wet or oil-

wet. The most common methods for measuring wettability are the contact angle, the Amott

index, the USBM index, imbibition rates, and capillary pressure and relative permeability

curves (Morrow, 1991). Fig. 2.4 shows a strongly water-wet and an oil-wet surface based

on the contact angle criteria. The contact angle θ shown in Fig. 2.4 is the counter clockwise

angle from the rock surface through the water phase.

Fig. 2.4‒Water-wet (left) and oil-wet (right) rock

Treiber et al. (1972) conducted the first extensive study for evaluating the

wettability of reservoir rocks. They examined 55 reservoir rocks out of which 25 were

carbonates. They arbitrarily defined water-wet systems for contact angles from 0 to 75°,

intermediate wettability from 75 to 105° and oil-wet from 105 to 180°. Based on these

criteria, they concluded that 8% of the carbonate rocks were water-wet, 8% were mixed-

wet and 84% were oil-wet. Later, Chillingar and Yen (1983) conducted a wettability study

of 161 cores from carbonate reservoirs. They concluded that 8% of the cores were water-

wet (θ<80°), 12% were intermediate-wet (θ=80-100°), 65% were oil-wet (θ=100-160°) and

15% were strongly oil-wet (θ>160°).

18

The effects of wettability on oil recovery have been investigated by several authors

(Amott, 1959; Donaldson et al., 1969; Anderson, 1987; Morrow, 1990). When water is

injected into a water-wet fractured reservoir, spontaneous imbibition occurs due the

capillary pressure between the water and oil. The capillary pressure is a function of

wettability.

2.1.2.5 Capillary pressure

For oil and water, capillary pressure is defined as the oil pressure minus the water

pressure:

𝑃𝑐 = 𝑃𝑜 − 𝑃𝑤 . (2.26)

For flow in a capillary tube, e.g., matrix pores; capillary pressure is defined as

𝑃𝑐 =2𝜎𝑐𝑜𝑠𝜃

𝑟, (2.27)

where σ is the interfacial tension between the fluid phases and r is the pore radius. Equation

2.26 implies that capillary pressure can be positive, negative or zero. The terms in equation

2.27 indicate that capillary pressure is positive for θ<90° (water-wet), negative for θ>90°

(oil-wet) and 0 for θ=90° (mixed-wet). Also, capillary pressure decreases when the

interfacial tension is reduced and increases as the pore radius becomes smaller.

The order of magnitude of capillary pressure can be estimated as shown in the

following example. The absolute permeability is 10 md, porosity is 0.20, the interfacial

tension between oil and water is 20 mN/m and the contact angle is 135°.

Use of equation 2.27 requires an estimation of the pore radius. This can be obtained

with the Hagen-Poiseuille equation for flow through a capillary tube, which leads to

𝑘 =𝑟2∅

8. (2.28)

19

The pore radius is estimated to be:

𝑟 = √8𝑘

∅= √

8(10 md)

0.20[0.001 D

1 md

9.87x10−13m

1 D],

𝑟 = 6.28x10−7 m = 0.628 μm.

The capillary pressure is

𝑃𝑐 =2 (0.020

Nm

) cos135°

6.28x10−7m= −45038 Pa = −6.53 psi.

The negative sign indicates that imbibition will not occur unless this capillary

pressure can be overcome. Equation 2.27 indicates that this can be achieved by either

changing IFT or the contact angle. It is the purpose of the following sections to describe

the various mechanisms by which surfactants can promote imbibition.

2.2 SURFACTANTS AND MICROEMULSIONS

Most of the research concerning the use of surfactants for application into naturally

fractured reservoirs has focused on surfactants that alter the rock wettability by changing

the contact angle, while a considerably fewer number of authors have used surfactants that

reduce the interfacial tension to ultralow values at which the capillary pressure becomes

negligible. The present study focused on surfactants that reduce the interfacial tension to

ultralow values. The surfactant selection criteria are similar to the well-known criteria used

for designing surfactant flooding in non-fractured reservoirs and is described next.

20

2.2.1 Surfactants

Surface active agents commonly known as surfactants, are amphiphilic molecules

consisting of segregated hydrophilic and lipophilic portions. Surfactants are able to change

the surface and interfacial forces when in contact with other phases, i.e. oil and water.

Depending on the electric charge of their hydrophilic group when dissolved in an aqueous

solution, surfactants are classified into four categories.

1. Cationics. Positively charged. These were the first surfactants considered for

EOR applications in fractured carbonate rocks (Austad and Milter, 1997). These

surfactants were used for wettability alteration purposes and also to minimize

surfactant adsorption in the calcite (CaCO3) or dolomite (CaMg(CO3)2) mineral

surfaces which are also positively charged. Cationic surfactants have been

successful in recovering oil from oil-wet carbonates (Standness and Austad,

2000), however, they are more expensive when compared to other surfactants,

i.e. anionics, which in some cases have performed as good as or better than

cationics.

2. Anionics. Negatively charged. These have been the most common type of

surfactants used in CEOR applications for matrix reservoirs (almost all of them

in sandstones), mainly because of their resistance to adsorption, high

availability and low costs. Anionic surfactants, have also been tested in

carbonate rocks and have been able to recover significant amounts of oil (Chen

et al., 2001; Seethepalli et al., 2004, Adibhatla and Mohanty 2008; Lu et al.,

2014; Mirzaei et al., 2015; Li et al., 2016).

3. Nonionics. These molecules are not ionized. There are some references of using

nonionic surfactants resulting in high oil recovery from spontaneous imbibition

21

experiments using carbonate cores (Chen, 2001; Xie et al., 2005; Sharma 2013),

however, nonionics are much less popular than cationics or anionics.

4. Amphoterics/Zwitterionics. These surfactants possess cationic and anionic

groups but have not been used in CEOR because of their high costs.

2.2.2 Microemulsion Phase Behavior

Mixtures of surfactant, brine and oil may form a stable phase at thermodynamic

equilibrium called a microemulsion.

Microemulsion phase behavior was first described by Winsor (1954) and later

adapted to surfactant EOR by Healy et al. (1976) and Nelson and Pope (1978). These

authors correlated the phase behavior of microemulsion with salinity and other variables.

Salinity is a convenient variable to use for anionic surfactants. An anionic surfactant is

more soluble in water than oil when the salinity is low. Above its critical micelle

concentration (CMC), the surfactant micelles solubilize oil to form a Winsor Type I water-

external microemulsion in equilibrium with excess oil. At intermediate salinities, the

surfactant is soluble in both the water and oil and forms a Winsor Type III bicontinuous

microemulsion in equilibrium with both oil and water. At high salinity, the surfactant is

soluble in oil, so reverse micelles solubilize water to form an oil-external Type II

microemulsion. For other types of surfactants, the same types of microemulsions form but

the principal variables are different e.g. temperature in the case of non-ionics. Fig. 2.5

shows an example of a phase behavior test with varying salinity (a salinity scan) at a fixed

water/oil ratio, surfactant concentration, temperature and pressure. Typically these results

are presented in a graphical way by plotting the oil and brine solubilization ratios (or

parameters) (Fig. 2.6). The water solubilization ratio (σw) is defined as the ratio of the

22

volume of water to the volume of surfactant in the microemulsion. Similarly the oil

solubilization ratio (σo) is defined as the ratio of the oil volume to the volume of surfactant

in the microemulsion.

𝜎𝑜 =𝑉𝑜

𝑉𝑠, (2.29a)

𝜎𝑤 =𝑉𝑤

𝑉𝑠. (2.29b)

Fig. 2.5‒Phase behavior salinity scan showing Type I-III-II phase environments

Healy et al. (1976) observed that interfacial tension decreases as the solubilization

ratio increases (Figure 2.6). Later, Huh (1979) derived an equation for the interfacial

tension as a function of the solubilization ratios.

𝛾 =𝐶

𝜎2. (2.30)

Type I Type III Type II

23

where C is a constant, usually taken as 0.3, γ is the IFT and σ any solubilization ratio. This

equation has been validated with extensive experimental data and is very useful since IFTs

can be calculated from phase behavior measurements.

Fig. 2.6‒Interfacial tensions and solubilization ratios versus salinity (Healy et

al., 1976)

Healy et al., (1976) introduced the concept of optimal salinity to refer to the

intersection point of either the oil/water solubilization ratio curves or to the microemulsion-

oil/microemulsion-water IFT curves, which were found to be very close (Fig. 2.6). Winsor

defined the cohesive energy ratio, R, as the ratio of the interaction energy between

surfactant and oil to the interaction energy between surfactant and water. When R = 1, the

surfactant equally interacts with both oil and water and forms an optimal microemulsion

with equally low IFT between the microemulsion and excess water and the microemulsion

and excess oil.

Vo/Vs Vw/Vs

24

Subsequent research demonstrated that Type III microemulsions are the most

favorable for oil displacement and, further, that use of a salinity gradient during surfactant

flooding provides the greatest window of opportunity to pass through the optimal salinity

(Nelson and Pope, 1978), while at the same time, taking advantage of the high solubility

of the surfactant in oil at higher than optimal salinities and of the surfactant in water

solubility at lower salinities. The salinity gradient also provides a robust design to account

for reservoir variations, reduces surfactant retention and is widely used during surfactant

flooding of non-fractured reservoirs.

2.2.3 Microemulsion viscosity

Section 2.2.2 stated the importance of microemulsion phase behavior, its

relationship with interfacial tensions and its effects on oil recovery. Recently, Walker et al.

(2012) showed that the microemulsion viscosity has a significant effect on tertiary oil

recovery. The authors used multiple surfactant formulations and conducted non-fractured

core floods using microemulsion with both low and high viscosity. Microemulsion

viscosity was changed by increasing temperature, adding co-solvent and through soap

generation by using alkali with active oils. They found the best results using Newtonian

microemulsions with low viscosity. When the viscosity continues to increase at low shear

rate (shear thinning), the microemulsion retention increases due to phase trapping.

Walker et al. pointed out the need for an improved microemulsion viscosity model.

Then, in what was surely one of the most significant advances for surfactant EOR,

Tagavifar et al. (2014) developed a new microemulsion viscosity model based on

fundamental principles. The viscosity is calculated as a function of the oil volume fraction

in the microemulsion using the following equation:

25

𝜂0 =𝜇𝑜exp (𝑣′𝜙)exp(𝑣𝜙′)

𝜙 exp(𝑣′𝜙) + 𝜆𝑟𝜙′exp(𝑣𝜙′), (2.31)

𝜙 =𝛾𝑜

𝛾𝑜 + 𝛾𝑤 (2.32)

where η0 is the microemulsion zero shear rate viscosity, 𝜆r is the viscosity ratio between

oil and water μo/μw, ϕ is the oil volume fraction in the microemulsion, defined as C23 in

Lake et al. (2014) and most other sources, γ is the oil/brine solubilization ratio defined

previously, ϕ’= ϕ -1 and v is a matching parameter ranging from 0.25 to 2.5. This equation

collapses to the correct limits, η0=μw as ϕ → 0 and η0 = μo as ϕ → 1.

Tagavifar adapted the Cross model (Cross, 1965) for estimating microemulsion

viscosity as a function of shear rate.

𝜂(ϕ, �̇�) − 𝜂∞(ϕ)

𝜂0 − 𝜂∞(ϕ)=

1

1 + (𝛼�̇��̇�ℎ

)𝑃𝛼−1 ,

(2.33)

𝜂∞ = (ϕ𝜇𝑜 + ϕ′𝜇𝑤)(𝑓0 + 𝑓1) (2.34)

𝑓0 = (1 − ϕϕ′)𝑣 (2.35)

𝑓1 = 𝑐0(ϕϕ′[0.1 + (ϕ − ϕ𝑚)(ϕ′ − ϕ𝑚)])2, (2.36)

where η∞ is the infinite shear viscosity to be used, except for dilute oil in water

microemulsions where η∞ = μw and for dilute water in oil microemulsions where η∞ = μo. The

terms fo and f1 represent thermodynamic interactions in the fluid and c0 is used for scaling

these interactions; �̇�ℎ and 𝑃𝛼 are the Cross model parameters for characterizing shear

thinning effects and α = 1 unless rheology alteration methods are employed (Tagavifar

2014).

26

The rheological models were in very good agreement when compared with multiple

microemulsion viscosity measurements performed over a wide range of formulations and

experimental conditions as shown in Figs. 2.7 and 2.8. Fig. 2.7 shows measured and

predicted microemulsion viscosity data as a function of the oil concentration in the

microemulsion, which in turn depends on salinity. The figures show that when ϕ = 0 the

microemulsion viscosity is essentially that of water, increases with the oil fraction in the

microemulsion until a maximum point and then eventually decreases to the oil viscosity at

ϕ=1. Fig. 2.8 also shows good agreement between measured and predicted microemulsion

viscosity data for two different formulations having both Newtonian and non-Newtonian

behavior. Relevant parameters for using the model are shown in the figure.

Fig. 2.7‒Microemulsion viscosity as a function of oil concentration in the

microemulsion (Tagavifar et al., 2016).

27

Fig. 2.8‒Microemulsion viscosity as a function of shear rate (Tagavifar et al.,

2016).

The core flood results from Walker et al. (2012) and Jang et al. (2016) have

demonstrated that viscous microemulsions are undesirable for oil recovery from non-

fractured rocks. However, as will be shown later, viscous microemulsions are favorable for

oil recovery from fractured media, thus, a good understanding and characterization of

microemulsion rheological behavior is fundamental for designing and optimizing

surfactant flooding processes.

2.3 SURFACTANTS RECOVERY MECHANISMS IN FRACTURED MEDIA

The purpose of this section is to describe the fundamental mechanisms for oil

recovery from naturally fractured reservoirs using surfactants for enhanced oil recovery.

There are four mechanisms causing flow/transport of chemical species in

permeable media; these are viscous, capillary, gravity and diffusion forces.

28

Capillary and gravity forces are the widely accepted driving mechanisms for oil

recovery from oil-wet carbonate rocks and have been extensively studied with static

imbibition experiments (Fig. 2.9).

Diffusion as a driving force for oil recovery from NFRs was studied by Stoll et al.

(2008). They conducted both imbibition experiments and a theoretical analysis, and

concluded that surfactant imbibition by diffusion is too slow to improve the oil recovery

economically. This argument was later supported by the simulation studies of Najafabadi

et al. (2008) and Abbasi et al. (2010), who used UTCHEM: a 3D, multicomponent,

multiphase, compositional simulator developed at the Center for Petroleum and

Geosystems Engineering at the University of Texas at Austin, to model a wide range of

chemical floods in fractured media.

The effect of viscous forces on imbibition (commonly known as viscous crossflow,

i.e. during fluid flow through layers of different permeability) has been generally neglected

during surfactant flooding applications in fractured media. However, as shown numerically

by Abbasi et al. (2010) and Kiani et al. (2014), viscous forces play a major role during

surfactant EOR processes from fractured carbonate rocks.

29

Fig. 2.9‒Static imbibition experiment.

2.3.1 Capillary driven imbibition

The importance of wettability and capillary pressure was stated in Section 2.1;

additionally, it is important to note that wettability is not a uniform property, meaning

different parts of the same pore, different pores, different rock types and so forth from the

same reservoir can have a different wettability. Thus, contact angle experiments are not

always representative. Thus, it is also useful to conduct spontaneous imbibition

experiments, in which an oil saturated core is placed inside a cell and then surrounded by

a brine solution while the oil recovery is measured as a function of time.

Austad and Milter (1997) performed static imbibition experiments using a low

permeable oil-wet chalk, Ekofisk oil and a brine containing surfactant (1% by weight) as

the imbibing fluid. The surfactant solution recovered 65% of the oil while the brine only

30

recovered 10% of the oil. The oil production occurred from all faces of the core

(countercurrent flow), indicative of a capillary driven process (Fig. 2.10a). The authors

concluded that the increase in oil recovery was due to the surfactants altering the wettability

from an oil-wet state towards a more favorable water-wet state at which the capillary

pressure becomes positive and spontaneous imbibition of the surfactant solution can occur.

In the following years, several investigators tested various kinds of surfactants

(cationic, anionic and nonionics) and confirmed the effectiveness of wettability altering

surfactants for oil recovery from oil-wet carbonate rocks (Standnes and Austad, 2000; Chen

et al., 2000; Hirasaki and Zhang, 2004; Seethepalli et al., 2004; Xie et al., 2005; Adibhatla

and Mohanty, 2008; Kathel and Mohanty, 2013; Chen and Mohanty 2013).

In Section 2.1.2.5, it was shown that an oil-wet rock has a negative capillary

pressure that opposes water imbibition. In this section, the same example is used, except

for that a wettability altering surfactant is added to the brine, changing the contact angle

from 135° to 60°, and reducing the IFT from 20 mN/m to 1 mN/m.

𝑃𝑐 =2 (0.001

Nm) cos 60°

6.28x10−7m= 1,592.35 Pa = 0.23 psi.

Under these conditions, capillary pressure is positive. However, this does not mean

that the surfactant solution can imbibe from the fracture into the matrix; the capillary

pressure in the fracture is approximately zero, thus, the surfactant must first imbibe into

the matrix through other mechanisms, and only once in the pores, will it be able to alter the

wettability to create a favorable capillary pressure and expel oil into the fractures.

31

Fig. 2.10‒ a) Countercurrent and b) co-current imbibition profiles.

2.3.2 Gravity driven imbibition

Typical surfactants used for EOR both reduce the IFT and change the wettability.

The reduction of IFT is typically more important than the change in wettability with respect

to conventional surfactant flooding. Capillary pressure becomes less important and gravity

more important, as the IFT decreases and eventually the imbibition process is dominated

by gravity forces.

Several authors have reported the successful use of surfactants to recovery oil from

oil-wet carbonates by reducing the IFT to low values (Hirasaki and Zhang, 2004; Adibhatla

and Mohanty, 2008, Mirzaei et al., 2015; Li et al., 2016). However, it is surprising that that

there have not been more studies of the low IFT approach to enhance imbibition.

Gravity driven imbibition (also known as gravity drainage within the gas EOR

discipline) occurs due to the potential gradient that arises from the density difference

between the fluids in the fracture and the fluids in the matrix. Gravity driven processes

develop co-current flow profiles as shown in Fig. 2.10b.

32

The following example illustrates the mechanisms underlying gravity driven

imbibition. Figure 2.2 is used as the reference system in conjunction with the following

properties; water density, ρw=1000 kg/m3, oil density, ρo=900 kg/m3, block height, H=1 m.

The gravity potential is calculated as follows:

Φ𝑔 = ∆𝜌𝑔𝐻 (2.37)

Φ𝑔 = (100 kg/m3)(9.81m/s2)(1 m)

Φ𝑔 = 981 Pa = 0.14 psi

This value is lower than the capillary pressure calculated in Section 2.1.2, thus,

imbibition cannot occur. However, when the water is replaced by a surfactant solution that

lowers the interfacial tension to a value of 0.001 mN/m the capillary pressure becomes,

𝑃𝑐 =2 (1x10−6 N

m) cos135°

6.28x10−7m= −2.252 Pa = −3x10−4 psi.

In this case, the gravity potential is much higher than the opposing capillary

pressure and imbibition will occur.

In the previous calculations it was assumed that the surfactant had no effect on the

rock wettability. This is useful for demonstration purposes but is certainly an incorrect

assumption. In fact, it underestimates the potential of surfactants, since it has been shown

that the more favorable contact angles for oil recovery are strongly correlated with the

lowest IFTs (Reed and Healy, 1984; Gupta and Mohanty, 2008). The results of Li et al.

(2016) also support this argument. They conducted a large number of imbibition

experiments using oil-wet carbonate rocks of different sizes (in the horizontal and vertical

direction), as well as different oils and a variety of surfactant formulations that achieved

interfacial tensions ranging from 0.001 to 0.1 mN/m. The authors concluded that the

greatest oil recovery occurred when using surfactants that achieved the lowest IFT.

33

The contribution of gravity forces for oil mobilization at the pore scale is quantified

through a dimensionless ratio of gravity to capillary forces, known as the Bond number.

One such definition is as follows:

𝑁𝐵 =𝑘∆𝜌𝑔

𝜎, (2.38)

where σ is the interfacial tension. The Bond number has been used to estimate oil recovery

from NFRs, (Kamath 2001; Tie and Morrow, 2005; Masalmeh, 2013).

A more general analysis of viscous and gravity forces leads to the trapping number

(Jin, 1995; Pope et al., 2000). The trapping number includes the vector sum of the viscous

and gravity forces. The viscous forces are quantified by the capillary number:

𝑁𝑐 =𝑘∇Φ

𝜎 (2.39)

where σ is the interfacial tension and ∇Φ potential gradient. The Trapping number been

used to understand the effect of these forces on enhanced oil recovery from non-fractured

oil reservoirs (Delshad et al., 1996). It also applies to oil recovery from NFRs, but has

gotten much less attention in such applications.

2.3.3 Scaling of imbibition

The Bond number has also been used to scale the effect of buoyancy on imbibition

(Iffly et al.1972; Du Prey, 1978; Schechter et al., 1994).

𝑁𝐵−1 = 𝐶

𝜎𝑐𝑜𝑠𝜃√𝜙/𝑘

∆𝜌𝑔𝐻, (2.40)

where C is a constant (equal to 4 for the capillary tube model). Schechter et al. (1994)

showed that imbibition is driven by capillary forces when NB-1>5, by gravity forces when

NB-1<1, and by both forces when 1<NB

-1<5.

34

In addition, models that correlate the results obtained from static imbibition

experiments into a greater scale have been presented for both capillary and gravity driven

imbibition. Extensive reviews of these scaling groups can be found in Abbasi (2010) and

Kathel (2015). The fact that so many scaling groups have been proposed over the past

several decades indicates that scaling up imbibition processes is a difficult problem. Many

authors have attempted to correlate their laboratory data using different definitions of

dimensionless time, but these correlations were later found to not accurately represent the

data of other investigators. Table 2.3 shows a few of the proposed scaling groups for gravity

driven imbibition.

Table 2.3‒Scaling groups for gravity dominated imbibition

Scaling group Parameters Reference

𝑡𝐷 =2𝑘𝑘𝑟𝑀𝐸

0 ∆𝜌𝑔𝐻

∅𝜇𝑀𝐸(𝑅2 + 𝑀𝐻2)𝑡 𝑀 =

𝑘𝑟𝑀𝐸0 𝜇𝑜

𝑘𝑟𝑜𝑜 𝜇𝑤

Li et al. (2016)

𝑡𝐷 =𝜆∗∆𝜌𝑔

∅(

1

𝐻+

8𝛼

𝜋𝐷) 𝑡

𝜆∗ =𝑘𝑘𝑟

∗

𝜇∗

𝛼~0.5

Mirzaei et al.,

(2016)

𝑡𝐷 =𝑘∆𝜌𝑔

∅𝜇𝑜𝐿𝑐𝑡

𝐿𝑐 =𝐻

(𝐿𝑥

2 )2

+ (𝐿𝑦

2 )2

+ 𝐻2

Hui et al.,

(2014)

The scaling groups suggest that the rate of oil production decreases as the size of

the core increases, but remarkably the recent study by Li et al. (2016) is the first report of

a systematic experimental investigation of core dimensions even though such data were

needed to determine the validity of the various proposed scaling groups. Li et al. presented

the new model to predict the oil recovery as a function of time and the dimensions of the

cores and used it to define the new dimensionless group shown in Table 2.3. This model is

in good agreement with a large number of experiments and includes variables such as the

35

mobility ratio that have not been included in previous attempts to scale imbibition

experiments. Nevertheless, it is approximate and additional validation with more

experimental data would be desirable.

Neither the static imbibition experiments nor the model capture the dynamic effects

of the transverse pressure gradient, which is now known to be of first order importance

based on the new dynamic experiments reported in this thesis. In these models, the

subscripts ME stands for microemulsion, and the subscripts 0 and * denote the conditions

at which properties are evaluated; at the critical saturation of a residual phase or at the

imbibing front respectively. The other parameters have been previously defined.

2.3.4 Viscous crossflow

The effects of viscous forces have been extensively studied in applications other

than surfactant flooding of NFRs, i.e. for water and polymer floods in layered reservoirs.

Crossflow is defined as the flow transverse to the main bulk flow direction. Crossflow

occurs as a result of gradients in viscous, capillary, dispersion and gravity forces.

Viscous crossflow is caused by the difference in mobilities between the displaced

and displacing fluids. Analysis of viscous crossflow in layered horizontal reservoirs has

been given by several authors (Zapata and Lake, 1981; Clifford and Sorbie, 1985; Willhite,

1986; Sorbie, 1991; Lake et al., 2014).

Viscous crossflow can be explained by considering the two-dimensional cross

sectional reservoir shown in Fig. 2.11. The reservoir is composed of two layers with distinct

uniform properties, a high permeability layer on the bottom and a low permeability layer

on the top. The common starting point in the study of stratified systems with crossflow is

to invoke the assumption of vertical equilibrium (VE). VE implies that the pressures along

36

a vertical cross section of a horizontal reservoir are equal, thus, there is a uniform vertical

pressure gradient and this is only dependent on time and horizontal position. The most

important implication of the VE assumption is that there is perfect communication between

layers, or in other words, maximum crossflow. Zapata and Lake (1981) showed that

assuming VE is a good approximation to describe displacement processes in reservoirs

with an effective length to thickness ratio of 10 or more.

𝑅𝐿 =𝐿

ℎ(

𝑘𝑇

𝑘)

1/2

(2.41)

Where the subscript T is used to denote the transverse direction to flow. For the purpose of

this illustration, it is assumed that each layer has uniform properties, negligible gravity and

capillary effects, and that the fluids are immiscible and incompressible.

Fig. 2.11‒Flow in parallel layers with no hydraulic communication.

To illustrate the concept, first assume the layers are separated by a flow barrier and

that a slug containing a viscous displacing fluid with lower mobility than the resident fluid

is injected into each layer under the same pressure gradient. The pressure profiles at a

37

certain time t during the displacement are shown in Fig. 2.11. Since the overall pressure

drop is fixed, the rate of advance of the injected fluid in the low permeability layer is much

slower than in the high permeability layer. Next, the case of hydraulic communication

between the layers is considered. Again, VE implies that there is only one pressure at any

point in a vertical cross section. Therefore, in order to equalize the pressures and preserve

mass balance flow must occur between the layers. Crossflow occurs from the high to the

low permeability layer at the rear of the viscous fluid and from the low to the high

permeability layer ahead of the viscous fluid, causing the injected fluid to slow down in

the high permeability layer and speed up in the low permeability layer, thus, improving the

vertical sweep efficiency in the reservoir.

Viscous crossflow has been recognized as an important mechanism for oil recovery

during gas flooding operations in naturally fractured reservoirs (Hirasaki et al., 2004; Li et

al., 2010; Sydansk and Romero-Zerón, 2011; Lake et al., 2014; Ferno et al., 2016), but it

has been generally neglected during most studies of surfactant EOR in the same type of

reservoirs. However, fractured reservoirs can be considered as layered reservoirs with

extreme permeability contrast, therefore, viscous forces would be expected to improve

sweep efficiency.

2.4 SURFACTANTS FLOODS IN FRACTURED CARBONATE MEDIA

This section discusses some of the few experimental and numerical studies of

surfactant floods (dynamic imbibition) in fractured carbonate media.

Najafabadi et al. (2008) simulated a chemical flood experiment performed using a

composite core composed of Texas Cream limestone matrix blocks with a permeability of

34 md and 1 mm longitudinal and transverse fractures as shown schematically in Fig. 2.12.

38

The experimental procedure was to saturate the core with oil. Next, a waterflood was

conducted followed by injection of alkali and then by an alkaline-surfactant flood. The

interstitial velocity in the fractures during the floods was about 30 ft/D and the pressure

drop was reported to be about 0.8 psi/ft. The waterflood recovered 15% of the OOIP, an

additional 15% was recovered by injection of alkali and 6% more was recovered by

injection of the alkaline-surfactant solution. The oil recovery mechanisms were modeled

as wettability alteration during the alkaline injection, and wettability alteration and low

interfacial tension during the AS flood.

Fig. 2.12‒Schematic representation of the physical fracture-matrix system used for

chemical floods (Najafabadi et al. 2008).

The authors used UTCHEM to model the experiment and tested the process

sensitivity to different variables, such as mesh refinement, fracture-matrix permeability

ratio, injection flow rate, molecular diffusion and injection scheme. The authors found that

the pressure drop during the alkaline-surfactant flood was slightly higher when compared

to the injection of alkali alone; they argued that this difference was due to the formation of

a microemulsion and pointed out the need to perform dynamic laboratory experiments to

evaluate the effects of viscous forces during chemical floods in fractured media.

Abbasi et al. (2010) used the UTCHEM reservoir simulator to model chemical

floods (surfactant, surfactant-polymer and alkaline-surfactant-polymer) in fractured media

at the core, block and reservoir scales. They performed a sensitivity analysis on parameters

39

such as IFT, wettability alteration, diffusion coefficient, pressure gradient and viscosity.

The simulations indicated that viscous pressure gradients transverse to the flow direction

in the fractures increased the rate of surfactant imbibition into the matrix and thus increased

the oil recovery. Consequently, they found that having a more viscous surfactant solution

flowing inside the fractures (due either to the addition of polymer, foam or to the formation

of a microemulsion) can increase the rate of oil recovery from fractured media. Fig. 2.13

illustrates the effects of transverse pressure gradients during a surfactant flood in a

fractured block. The surfactant concentration profile is shown on the top and the matrix

and fracture pressure profiles are shown on the bottom. The pressure within the fracture

region containing the surfactant is higher than the pressure in the neighboring matrix (the

higher pressure in the fracture is due to the formation of microemulsion). The transverse

pressure gradient will induce crossflow/imbibition of the surfactant solution from the

fracture into the matrix.

Fig. 2.13‒Transverse pressure gradients for a surfactant flood in a fractured block

(Abbasi et al., 2010).

Abbasi et al. performed a sensitivity analysis on oil recovery to the microemulsion

viscosity after a surfactant flood in a fractured carbonate block. Fig. 2.14 shows the three

40

cases and indicates that the most viscous microemulsion achieves the greatest rate of oil

recovery, even though the ultimate oil recovery is not strongly affected. However, the rate

of recovery is the most important parameter in the design of EOR processes for fractured

media.

Fig. 2.14‒Effect of microemulsion viscosity on oil recovery from fractured media

(Abbasi et al., 2010).

Kiani et al. (2014) introduced a viscous displacement term in the matrix-fracture

transfer function of a dual porosity model and applied it to study surfactant processes in

naturally fractured reservoirs. They concluded that the addition of the viscous displacement

mechanism led to an increase in the oil recovery from a fractured reservoir since it enhances

the matrix-fracture fluid exchange.

Lu et al. (2014) conducted a fractured core flood (dynamic imbibition) and a static

imbibition experiment using ultralow IFT surfactants, an oil-wet rock and fluids from a

fractured carbonate reservoir. The core used for the dynamic experiment was manually

fractured (Fig. 2.15) and then placed into a core holder. The fractured core had an effective

permeability of 1970 md and a matrix permeability of 6 md. The surfactant flood recovered

65% of the residual oil after the waterflood, while the static experiment only recovered

41

33% of the OOIP (brine imbibition did not recover any oil). The fractured core flood results

are impressive considering the fractured state of the core. The oil recovery mechanisms for

the static and dynamic experiments were attributed to be IFT reduction and wettability

alteration, as well as viscous forces for the dynamic experiment. The difference in the oil

recovery indicated that viscous forces were significant for oil recovery from fractured

carbonate rocks.

Fig. 2.15‒CT scan of a manually fractured carbonate reservoir core (Lu et

al., 2014)

Mirzaei et al. (2016) conducted surfactant flooding experiments with fractured

cores using CT imaging. They used ultralow IFT surfactants, a light reservoir oil, soft brine

and oil-wet fractured Estaillades Limestone cores of different dimensions. The

experimental procedure consisted in cutting the cores in half to obtain an artificial fracture

of 1 mm in aperture, which resulted in an enormous permeability contrast between the

fracture (kf ~ 80,000 D) and the matrix (km = 250 md). The cores were 100% oil saturated

and water flooded to zero oil-cut (the waterflood only recovered the oil from the fracture).

Next, a surfactant solution was injected at a rate of 0.01 cm3/min for about 14 days and the

oil recovery was measured. Fig. 2.16a shows the CT images of the core at different times

and heights during the surfactant injection. The hot colors represent the aqueous phase and

the cold colors the oleic phase. Fig. 2.16b also shows the normalized distance of surfactant

42

imbibition into the matrix, obtained by averaging the saturations from the CT images; it

can be seen that the surfactant imbibes as a front. The spike in the imbibed distance around

the middle of the core is a result of an increase in porosity and not a characteristic feature

of the process. Fig. 2.16 demonstrates that imbibition of ultralow IFT surfactants follows

a cone shape profile with the greatest imbibition coming from the bottom of the core and

indicates that this is a gravity-dominated process even under dynamic conditions.

Fig. 2.16‒Imbibition profile of ultralow IFT surfactants into an oil-wet

matrix (Mirzaei et al., 2016).

43

2.5 SUMMARY

Physical mechanisms pertaining to oil recovery from fractured reservoirs were

introduced in this chapter. Major aspects of surfactants whose main purpose is the

reduction of IFT to ultralow values were also discussed. The relationship between the

microemulsion rheological properties and the phase behavior introduced in this chapter is

of great importance for the experimental design presented in Chapter 3. Later it will be

shown that gravity and viscous forces are the main recovery mechanisms for the surfactant

imbibition experiments done during this research. The importance of viscous forces during

surfactant floods in fractured media has been demonstrated by previous simulation results,

however, there was until now no experimental study that focused solely on testing the effect

of viscous forces during surfactant floods in fractured carbonate rocks, this was the purpose

of this research.

44

Chapter 3: Experimental Material and Procedures

The purpose of this chapter is to introduce the experimental materials and

procedures that were used to conduct surfactant flooding experiments in fractured

carbonate cores.

The first step in this research was to develop a surfactant formulation that achieved

ultralow IFT when mixed with a light oil and a synthetic brine at a temperature of 78 °C.

Next, the microemulsion viscosity of the optimized formulation was measured at different

salinities and shear rates. A discussion on the experimental fluids is presented in Section

3.1 followed by a discussion of the rocks and the experimental apparatus in Sections 3.2

and 3.3, respectively.

A total of eight coreflood experiments were performed during this research. Six

fractured coreflood experiments abbreviated as FRAC-# and two non-fractured corefloods

abbreviated as non-FRAC-#. A coreflood (fractured or not) is also referred to as a dynamic

imbibition experiment. The general coreflood procedure is presented in Section 3.4. The

experimental results are presented in Chapter 4.

3.1 FLUIDS

3.1.1 Microemulsion phase behavior

The oil used in all experiments is a crude oil from a Middle East carbonate

reservoir. The oil density is 890 kg/m3. The dead oil has a viscosity of 12 cp at 78 °C. In

some experiments the crude oil was diluted with 10 wt. % toluene. The diluted oil viscosity

is 6 cp. The oil is not active, which means that it does not react with alkali.

The procedures used to measure the phase behavior and the criteria to select the

best formulations can be found in Levitt et al. (2009) and Flaaten et al. (2009) among many

45

other references. Salinity scans were done by adding NaCl to a makeup brine. The

composition of the makeup brine was 30,000 ppm Na2CO3 and 10,000 ppm Na4EDTA.

Only the results of the final formulation used in the corefloods are shown here. The final

surfactant formulation is 0.5% C28-25PO-45EO-carboxylate, 0.2% C15-18 internal olefin

sulfonate and 0.3% C19-28 internal olefin sulfonate.

Aqueous surfactant solutions were prepared at different salinities by adding NaCl

to the makeup brine to determine the aqueous stability of the formulation. The aqueous

stability is defined as the maximum salinity at which the surfactant solution remains clear

and stable (no precipitation, phase separation or other unstable phenomena). The aqueous

stability was observed to be 100,000 ppm TDS at 78 °C.

The solubilization ratios measured after 90 days of equilibration are shown in Fig.

3.1. The solubilization ratio data are plotted as a function of the total dissolved solids

(TDS). The optimum salinity based on where the curves cross is 77,000 ppm. The optimum

salinity based on the emulsion test is 80,000 ppm. The optimum salinity from the emulsion

test was used for designing the surfactant floods. The emulsion test (Levitt et al., 2009) is

an empirical method used to observe qualitatively the IFT during a phase behavior scan.

When the phase behavior tubes are mixed, an emulsion is generated, the emulsions with

smaller oil droplet size and creamier color are indicators of ultralow IFT. The solubilization

ratio at optimum salinity is 13 and the corresponding IFT calculated with the Huh equation

(equation 2.30) is 0.0018 mN/m. Table 3.1 summarizes the surfactant formulation

properties at optimum salinity.

46

Fig. 3.1‒Oil and water solubilization ratios after a NaCl salinity scan at

78 °C and 90 days of equilibration. Oil volume fraction is 30%.

Table 3.1‒Surfactant formulation at optimum conditions

Property Value

C28-25PO-45EO-COO- 0.5%

C15-18 IOS 0.2%

C19-28 IOS 0.3%

Total surfactant concentration 1%

Na4EDTA 10,000 ppm

Na2CO3 30,000 ppm

NaCl 40,000 ppm

Optimum salinity, TDS 80,000 ppm

Solubilization ratio at optimum salinity 13

Interfacial tension at optimum salinity 0.0018 mN/m

47

3.1.2 Microemulsion viscosity

The microemulsion viscosity data for the optimized surfactant formulation as a

function of salinity and oil concentration in the microemulsion at two different shear rates

(1 and 10 s-1) are shown in Figs. 3.2 and 3.3, respectively. The viscosity measurements

were performed using on an ARES-LS1 rheometer from TA instruments and following the

procedure describe by Tagavifar et al. (2016).

The microemulsion viscosity at 70,000 ppm or lower salinity is very similar to the

water viscosity (0.5 cp at 78 °C). The microemulsion viscosity at a salinity of 110,000 ppm

or higher is essentially the oil viscosity (12 cp at 78 °C). The viscosity is a maximum at

95,000 ppm (oil volume fraction of 0.8). The microemulsion is shear thinning as shown in

Fig. 3.4.

Fig. 3.2‒Microemulsion viscosity as a function of salinity at 1 and 10 s-1 and 78 °C.

Oil volume fraction is 30%.

48

Fig. 3.3‒Microemulsion viscosity as a function of the oil volume fraction in the

microemulsion at 1 and 10 s-1 and 78 °C. Total oil volume fraction is 30%.

Fig. 3.4‒Microemulsion viscosity as a function of shear rate for different salinities at

78°C. Oil volume fraction is 30%.

s-1

s-1

49

3.2 ROCKS

Two carbonate rocks were used during this research. Three coreflood experiments

were performed using Silurian Dolomite cores and five coreflood experiments were

conducted in Texas Cream Limestone cores. Table 3.2 shows the X-ray diffraction (XRD)

mineralogy measurements of the Silurian Dolomite and the Texas Cream Limestone rocks.

The coreflood experiments were performed using cylindrical cores with a diameter

of 3.8 cm and a length of 30 cm, (except for FRAC-1, in which the diameter was 5 cm).

The porosity of the Silurian Dolomite ranged from 15 to 18% and the oil permeability from

100 to 320 md. The porosity of the Texas Cream Limestone ranged from 27 to 29% and

the oil permeability from 8 to 11 md cores, respectively.

Table 3.2‒Mineralogy of Silurian Dolomite and Texas Cream Limestone

Mineral Silurian Dolomite

wt. %

Texas Cream Limestone

wt. %

Calcite 0.0 98.8

Dolomite 97.1 0.0

Quartz 1.0 0.7

Feldespar 0.3 0.0

Plagioclase 0.4 0.0

Illite and mica 0.6 0.5

Kaolinite 0.6 0.0

3.3 EXPERIMENTAL APPARATUS

The experimental apparatus that was used for the corefloods is shown schematically

in Fig. 3.5. The apparatus is composed of a steel core holder that is rated to a confining

pressure up to 138 bar (2,000 psi) and a maximum temperature of 150 °C. Taps along the

core holder, as well as at the inlet and the outlet, provide hydraulic communication between

the core and a series of pressure transducers.

50

Fig. 3.5‒ Coreflood experimental apparatus

3.4 FRACTURED COREFLOOD PROCEDURE

The following procedure was followed for each fractured coreflood experiment.

1) The core weight and dimensions were measured. Next, the core was wrapped

in a plastic shrink tube and placed inside a steel core holder.

2) Matrix permeability was determined using a gas permeameter at a confining

pressure of 1,000 psi.

3) The core was taken out of the core holder and a natural or artificial fracture was

created along its longitudinal axis. The fractures in the Silurian Dolomite cores

were created using the tensile splitting method (ASTM C 496, 2004); in this

method the core is aligned horizontally while a vertical load is applied until a

51

crack is created. The fractures in the Texas Cream Limestone cores were created

artificially by cutting the cores in two halves using an electric saw (Fig. 3.6).

After fracturing, the core was placed back into the core holder. A Computerized

Tomography (CT) scanner was sometimes used to scan the cores before and

after fracturing.

4) The pore volume was determined by saturating the core with oil under vacuum;

the initial oil saturation, Soi= 1.

5) The fracture core was placed inside an oven at 78 °C and aged for seven days.

6) The fractured core was flooded with oil and the effective permeability was

determined. The fracture width and fracture permeability was calculated using

equations 2.18 and 2.19, respectively. The equivalent shear rate in the fracture

was calculated using equation 2.16.

7) The cores were waterflooded to zero oil cut at a rate of 0.3 cm3/min.

8) The cores were flooded with a surfactant solution at a rate of 0.01 cm3/min.

9) In some coreflood experiments, the viscosity of the surfactant solution was

increased by adding polymer or by increasing the salinity and additional

surfactant solution was injected at the same rate.

10) The effluent from the chemical flood was collected in 10 mL glass test tubes.

When present, emulsified oil was separated by increasing the temperature and

centrifuging the tubes.

Two non-fractured coreflood experiments were also performed for comparison

purposes. One experiment was conducted in a Silurian Dolomite and the other in a Texas

Cream Limestone core.

52

Fig. 3.6‒Artificially fractured Texas Cream Limestone core.

53

Chapter 4: Experimental Results and Analysis

This chapter presents the results of the six fractured and the two non-

fractured coreflood experiments that were performed throughout this research.

The physical properties of the fractured and the non-fractured cores are shown in

Tables 4.1 and 4.2, respectively.

The chapter is divided into two major sections. The objective of the experiments

presented in Section 4.1 was to test the effect of viscous forces on the oil recovery from a

surfactant flood in fractured Silurian Dolomite cores. Two fractured corefloods and one

non-fractured coreflood were performed using the Silurian Dolomite rock. The fractured

cores had a very high permeability contrast between the fracture and the matrix (Table 4.1).

The effects of viscous forces on the oil recovery were studied by performing a low viscosity

surfactant flood with a microemulsion viscosity of 17 cp until the oil cut was negligible,

followed by a high viscosity surfactant flood achieved by adding polymer to the surfactant

solution to increase its viscosity to 30 cp.

The results from the experiments that were designed to test the effect of the

microemulsion viscosity on the oil recovery from a surfactant flood in oil-wet fractured

Texas Cream Limestone cores. These cores had an enormous permeability contrast

between the fracture and the matrix (Table 4.1) are discussed in this section. The

microemulsion viscosity was varied in each coreflood experiment by changing the salinity

of the surfactant solution. Four fractured corefloods and one non-fractured coreflood were

performed in Texas Cream Limestone.

The performance data for the Silurian Dolomite and Texas Cream Limestone

corefloods are summarized in Table 4.3 and Table 4.4, respectively.

54

Table 4.1‒Fractured core properties

Fractured coreflood #, FRAC- 1 2 3 4 5 6

Rock Silurian Dolomite Texas Cream Limestone

Mass, g 1474 808 652 597 605 598

Diameter, cm 5.0 3.8 3.7 3.7 3.6 3.6

Length, cm 30.4 30.3 29.7 29.6 29.8 29.3

Area, cm2 20 11.1 10.7 10.7 10.2 10.2

Bulk volume, cm3 609 336 319 318 303 298

Pore volume, cm3 88 52 82 85 86 87

Porosity, % 15 16 26 27 28 29

Matrix permeability, md 100 180 9 8 10 11

Effective permeability, md 1100 1400 2360 2420 2500 2530

Fracture width, mm 0.08 0.08 0.09 0.09 0.09 0.09

Fracture permeability, D 496 458 734 747 749 754

Table 4.2‒Non-fractured core properties

Non-fractured coreflood #, non-FRAC- 1 2

Rock Silurian Dolomite Texas Cream Limestone

Mass, g 801 626

Diameter, cm 3.8 3.7

Length, cm 30.2 29.4

Area, cm2 11.2 10.7

Bulk volume, cm3 339 316

Pore volume, cm3 61 90

Porosity, % 18 28.5

Matrix permeability, md 320 9

Residual water saturation 0.38 0.36

Oil endpoint relative permeability 0.75 0.42

Surfactant endpoint relative permeability* 0.39 0.60

*The surfactant relative permeability in the non-FRAC-1 experiment was

calculated for a residual oil saturation (Sorc=0.07) after a chemical flood comprising the

injection of a 0.4 pore volume ASP slug followed by continuous injection of a polymer

drive. The surfactant endpoint relative permeability for the non-FRAC-2 core flood was

estimated at the residual oil saturation (Sorc=0.20) after continuous surfactant injection with

no mobility control.

55

Table 4.3 Performance data for the Silurian Dolomite coreflood experiments

Coreflood number non-FRAC

1

FRAC

1

FRAC

2

Initial

Soi 0.62 1 1

Waterflood (100,000 ppm TDS)

Trapping/bond number* 5x10-6 5x10-9 9x10-9

Sorw 0.37 0.57 0.43

Surfactant flood (80,000 ppm TDS)

Viscosity, cp 0.5 0.5

Bond number 6x10-5 1x10-4

Sorc 0.29 0.21

Surfactant-polymer flood (80,000 ppm TDS)

Viscosity, cp 23 30 30

Trapping/bond number* 3x10-3 6x10-5 1x10-4

Sorc 0.07 0.24 0.17

Table 4.4 Performance data for the Texas Cream Limestone coreflood experiments

Coreflood number non-FRAC

2

FRAC

3

FRAC

4

FRAC

5

FRAC

6

Waterflood

Salinity, ppm TDS 80,000 100,000 80,000 95,000 65,000

Trapping/Bond number 3x10-7 4x10-10

Sorw 0.47 0.97 0.96 0.97 0.98

Surfactant flood

Salinity, ppm TDS 80,000 80,000 80,000 95,000 65,000

IFT, mN/m 0.002 0.002 0.002 0.0006 0.006

Microemulsion viscosity, cp 17 17 17 75 0.5

Pressure drop, psi/ft 8.0 0.8 0.9 1.1 0.4

Trapping/Bond number* 1x10-7 5x10-6

Sorc 0.20 0.61+ 0.47 0.30 0.66

Sorw is the oil saturation after the waterflood, Sorc is the oil saturation at the end of

the surfactant or surfactant-polymer flood for an oil cut of less than 1%, +except for the

FRAC-3 experiment which was concluded after 3 PV of injection of surfactant solution.

The surfactant floods were conducted at 0.01 cm3/min. *The Trapping number for vertical

upward flow (NB + NC) is used for the non-fractured corefloods and the Bond number is

used for the fractured corefloods (see Chapter 2 for more details). The microemulsion

viscosity is the value measured with the rheometer as described in Chapter 3.

56

4.1 SILURIAN DOLOMITE EXPERIMENTS

4.1.1 Fractured coreflood #1

The FRAC-1 coreflood was conducted in a Silurian Dolomite fractured core at

78°C. The core was 5 cm in diameter and 30.4 cm long. Matrix permeability was 100 md.

The core was fractured using the tensile splitting method. Fig. 4.1 shows the CT images of

the fractured core at three arbitrary cross sections along its axis. The Silurian Dolomite

core was heterogeneous and contained vugs.

Fig. 4.1‒CT images at arbitrary cross sections of the fractured Silurian Dolomite

core used in the FRAC-1 experiment.

The dry core was saturated with crude oil diluted with 10 wt %. toluene with a

viscosity of 6 cp at 78°C (Chapter 3) and aged for seven days so that the matrix would be

oil wet. This same protocol was followed in the other fractured corefloods unless otherwise

noted. The pore volume of the core was 88 cm3 and porosity was 15%. The fractured core

had an effective permeability of 1100 md. The fracture aperture was calculated to be 0.08

mm using equation 2.21. The fracture volume calculated from this fracture aperture was

1.2 cm3 (a very similar volume was obtained from the oil produced from water injection).

The fracture permeability is 496,000 md using equation 2.25.

The vertical core was water flooded from the bottom upwards with a 100,000 ppm

NaCl brine at a rate of 0.3 cm3/min, equivalent to a frontal velocity of 5 ft/D based on the

whole core cross sectional area and 350 ft/D based on the open area of the fracture. The oil

57

saturation after injecting 1.1 pore volumes (PVs) of water was 0.92. Next, the injected

water flow rate was lowered to 0.05 cm3/min, equivalent to a frontal velocity of 0.8 ft/D

based on the whole core area and 58 ft/D based on the fracture area. Water was injected

continuously until the water cut was 100%. The oil saturation after injecting 4.8 PV of

water was 0.57 and the steady state pressure drop was 0.25 psi/ft.

Next, the core was flooded with the optimized surfactant solution (Table 3.1) with

a salinity of 80,000 ppm at a flow rate of 0.05 cm3/min. The oil saturation after 1.2 pore

volumes injected was 0.49 (Fig. 4.2). Next, the flow rate was lowered to 0.01 cm3/min,

equivalent to a frontal velocity of 0.16 ft/D based on the whole core and 12 ft/D based on

the fracture. The equivalent shear rate in the fracture at this flow rate was estimated as 3 s-

1 (equation 2.16). The microemulsion viscosity at 3 s-1 is 17 cp (Fig. 3.4). The oil saturation

after injection of 4.1 pore volumes of surfactant solution was 0.29 and the oil cut was less

than 1%.

Fig. 4.2‒Oil recovery from a fractured core for a surfactant flood followed by a

surfactant-polymer flood (fractured coreflood #1).

58

Fig. 4.2 shows that the oil cut increased from about 2% to a maximum of 14% as

the flow rate was lowered from 0.05 to 0.01 cm3/min; this is because lowering the flow rate

provided more residence time for the surfactant to imbibe into the matrix. As a consequence

of this finding, all the surfactant solutions in the subsequent floods and experiments were

injected at a flow rate of 0.01 cm3/min, which is equivalent to an interstitial velocity in the

fracture of about 13 ft/D.

Next 3,000 ppm FP 3330s polymer was added to the same surfactant solution to

increase its viscosity to 30 cp at 78 °C at the estimated shear rate of 3 s-1 (Fig. 4.3). Injection

of the viscous surfactant-polymer solution increased the oil cut from 1 to a maximum 7%

and the pressure drop increased from 0.7 to 1.1 psi/ft (Fig. 4.4). The oil saturation after

injection of 1.5 pore volumes was 0.24 and the oil cut was zero. These results indicate that

increasing the viscosity of the surfactant solution was significant for enhancing the oil

recovery from this fractured carbonate core.

Fig. 4.3‒Viscosity of the surfactant-polymer solution

59

Fig. 4.4‒Pressure drop for a surfactant flood followed by a surfactant-

polymer flood (fractured coreflood #1).

The core was cut in half along its length after the surfactant flood and photographed.

For comparison purposes, a core fully saturated with oil is also shown in Fig. 4.5. The faces

of several sections of the core in the direction of flow aligned with the fracture are also

shown in Fig. 4.5. The core looks darker near the top and lighter near the bottom indicating

a lower oil saturation near the bottom. Since the IFT is very low, capillary pressure is

assumed to be negligible in this surfactant flood as well as all of the other surfactant floods

described in this thesis. Thus, gravity and viscous forces dominate the imbibition process.

The relative magnitude of these two forces depends on the in-situ viscosity, permeability

and flow rate.

60

Fig. 4.5‒Photographs of Silurian Dolomite core a) before surfactant

imbibition (So= 1), b) after surfactant imbibition (So= 0.21). The core was cut in half

and at several cross sections after the surfactant flood. The lighter shade at the

bottom of the vertical core indicates a lower oil saturation.


A second coreflood using Silurian Dolomite (FRAC-2) was done under very similar

conditions as the FRAC-1. The core used for the FRAC-2 experiment was 3.8 cm in

diameter and 30.3 cm in length. The matrix permeability was 180 md compared to 100 md

for the core used for FRAC-1. The core was fractured using the tensile splitting method.

61

The dry core was saturated with crude oil diluted with 10 wt. % toluene. The pore

volume was 52 cm3 and porosity was 16%. The effective permeability of the fractured core

was 1,400 md, the fracture width was 0.08 mm and the fracture permeability was 458,000

md (very similar conditions as FRAC-1). The core was water flooded with a 100,000 ppm

NaCl brine at a rate of 0.3 cm3/min. Next, the injection rate was lowered to 0.05 cm3/min

and the same brine was continuously injected until the oil cut was zero. The oil saturation

after the water flood was 0.43.

Next, the core was flooded with the optimized surfactant formulation at a flow rate

of 0.01 cm3/min, equivalent to a frontal velocity of 0.27 ft/D based on the whole core and

16 ft/D based on the fracture. The oil saturation after continuous injection of the surfactant

for 3.2 PV was 0.21. The surfactant flood was followed by injection of a more viscous

surfactant solution with a viscosity of 30 cp at an estimated shear rate in the fracture of 4

s-1. The viscosity of the surfactant solution was increased by adding 3,000 ppm FP3330s

HPAM polymer. Injection of the more viscous surfactant solution increased the oil cut

from 1 to 5%, increased the pressure drop from 0.5 to 0.8 psi/ft and decreased the oil

saturation from 0.21 to 0.17 as shown in Figs 4.6 and 4.7, respectively.

The results from the FRAC-1 and FRAC-2 experiments are in good agreement and

demonstrate that the oil recovery from the fractured carbonate cores was enhanced by the

injection of a viscous surfactant solution since it induces a transverse pressure gradient that

enhances fluid crossflow. The oil recovery from the fractured Silurian Dolomite cores was

higher than expected considering the extremely high permeability contrast of about 5000

and 2500 between the fracture and the matrix for each core, respectively.

62

Fig. 4.6‒ Oil recovery from a fractured core for a surfactant flood followed by a

surfactant-polymer flood (fractured coreflood #2)

Fig. 4.7‒Pressure drop for a surfactant flood followed by a surfactant-

polymer flood (fractured coreflood #2).

63

4.1.3 Non-fractured coreflood #1

A non-fractured core flood was also performed using the Silurian Dolomite rock.

The non-fractured core flood procedure had some differences from the one discussed in

Section 3.3 and will be noted when appropriate. The purpose of this experiment was to

compare the performance of the fractured core floods against a non-fractured core flood

and to obtain parameters such as the oil/water endpoint relative permeability, and the

surfactant retention in this carbonate rock.

The non-fractured core was initially saturated with 10,000 ppm NaCl brine. The

pore volume was 61 cm3 and porosity was 18% determined from a salinity tracer test with

a 40,000 ppm NaCl brine (Fig. 4.8). The tracer test results indicate that the core was very

heterogeneous since the injected salinity was not produced until after 2 PV. Brine

permeability was 320 md.

Fig. 4.8‒Tracer test of the Silurian Dolomite core used in the non-fractured

experiment.

64

The core was flooded with the reservoir oil diluted with 10 wt. % toluene. The

initial oil saturation was 0.62 and the endpoint oil relative permeability was 0.75.

Next, the core was water flooded with a 100,000 ppm NaCl brine at an interstitial

velocity of 10 ft/D. The steady state pressure drop was 14 psi/ft. The residual oil saturation

after the waterflood was 0.37 and the water endpoint relative permeability was 0.04.

A surfactant flood using polymer for mobility control was designed to achieve a

stable displacement and to satisfy retention. The idea was to observe the performance of a

conventional ASP flood in a non-fractured core to use as a reference for the more

complicated fractured corefloods. Corey type relative permeability curves were used to

calculate the total relative mobility curve 𝜆T (equation 4.1). The measured endpoint relative

permeability and viscosity values were used for the calculation. The Corey exponents were

assumed to be 2.0 for both water and oil.

1

𝜆𝑇=

𝑘𝑟𝑤

𝜇𝑤+

𝑘𝑟𝑜

𝜇𝑜, (4.1)

The required viscosity for a stable displacement was estimated to be 21 cp.

The pore volumes of surfactant solution required to satisfy retention was estimated

by calculating the retardation factor using the following equation.

𝐷𝑠 =(1 − ∅)𝜌𝑠𝜔4𝑠

∅𝜌4𝜔41,

(4.2)

where Ds is the retardation factor ω is the mass concentration and the subscripts 1,4 and s

stand for the aqueous phase, surfactant and solid respectively. A surfactant retention of

0.20 mg/g was assumed based on a similar ASP flood performed by this author.

𝐷𝑠 =(1 − 0.18) (2.84

gcm3) (0.0002

gg)

(0.18) (1g

cm3) (0.01gg)

= 0.26

65

A 0.4 PV alkaline-surfactant-polymer (ASP) slug (Table 3.1) containing 3,500 ppm

of FP330s HPAM polymer and a viscosity of 22 cp at an estimated shear rate of 12 s-1 was

injected at 1 ft/D. The slug was followed by a polymer drive at 1 ft/D containing 3,800

ppm FP3330s HPAM polymer in a synthetic brine with a salinity of 65,000 ppm TDS and

a composition of 55,000 ppm NaCl and 10,000 ppm Na2CO3. The oil recovery and pressure

drop data are shown in Fig. 4.9 and Fig. 4.10, respectively. The residual oil saturation after

the ASP flood (Sorc) was 0.07, the tertiary oil recovery was 80% of the waterflood residual

oil, the maximum pressure drop was 7 psi/ft and the retention was 0.29 mg/g of rock.

Fig. 4.9‒Oil recovery from an ASP flood of a non-fractured Silurian

Dolomite core (non-fractured coreflood #1)

66

Fig. 4.10‒Pressure drop data for an ASP flood in a non-fractured Silurian

Dolomite core (non-fractured coreflood #1).

4.1.4 Analysis of the Silurian Dolomite coreflood experiments

The oil recovery as a fraction of the original oil in place (OOIP) for the two

fractured (FRAC-1 and FRAC-2) and the non-fractured coreflood (non-FRAC-1)

experiments is shown in Fig. 4.11. The FRAC-1 and FRAC-2 fractured coreflood

experiments recovered 76 and 83% of the OOIP respectively. The difference in the oil

recovery between the two experiments is attributed to the matrix permeability of the cores.

The FRAC-2 core was 180 md and the FRAC-1 core was 100 md. The non-fractured core

flood recovered 92% of the OOIP.

67

Fig. 4.11‒Oil recovery from the fractured and non-fractured corefloods performed

in Silurian Dolomite cores.

The results from the fractured and the non-fractured coreflood experiments indicate

that surfactants achieved a high oil recovery from the fractured cores, even comparable to

the recovery obtained from forced gradient displacements in non-fractured cores. The

results also demonstrate that viscous forces are important for oil recovery from fractured

rocks as indicated by the incremental oil recovery after the injection of a more viscous

surfactant-polymer solution following the surfactant solution.

4.1.5 Static versus dynamic imbibition

In this section, the results from the dynamic imbibition (fractured coreflood)

experiments are compared with two static imbibition experimental results of Li (2016). Li

also used Silurian Dolomite cores with similar properties and the same fluids (oil, brine

and surfactant formulation) as used during this research. The cores differed in height and

68

permeability. The dynamic experiments were performed using cores with 30 cm in height

and 100 and 180 md in permeability. The static experiments (IE36 and IE37) from Li

(2016) were 10 cm in height and the permeability of one core was 30 md. The oil recovery

data are shown in Fig. 4.12. The oil recovery is shown as a fraction of the oil remaining

after the waterflood or static water imbibition, and is plotted as a function of time.

The oil recovery is higher for the dynamic experiments than for the static imbibition

experiments even though the cores used for the static imbibition were shorter and the oil

recovery rate decreases as the length of the core increases (Li et al., 2016). The results seem

counterintuitive, since the surfactant channels through the fracture when injected into the

fractured cores with an extremely high ratio of fracture permeability to matrix permeability.

Viscous crossflow may explain the more favorable results for the fractured corefloods (see

Chapter 2 for a description of viscous crossflow).

These results suggest that imbibition of ultralow IFT surfactants is more efficient

under dynamic conditions. This implies that the oil recovery from surfactant EOR

processes in naturally fractured reservoirs is higher than that predicted with static

imbibition experiments since they do not account for the viscous effects that occur while

the surfactant flows though the fractures.

69

Fig. 4.12‒ Tertiary oil recovery from surfactant imbibition under static and

dynamic conditions (fractured coreflood experiments). The core height is 10 cm for

static imbibition and 30 cm for dynamic imbibition.

4.1.6 Limitations of using Silurian Dolomite cores

The Silurian Dolomite rock used in the fractured coreflood experiments was very

heterogeneous, as indicated by the tracer test results (Fig. 4.8) and the CT images (Fig 4.1)

Reproducibility is difficult to achieve given the rock heterogeneity and the variability

between cores (98, 180 and 320 md). Furthermore, the high water flood recoveries (43 and

57% of the OOIP for the FRAC-1 and FRAC-2 experiments) indicate that the core had an

intermediate wettability even after the aging process. In addition, the permeability of the

Silurian Dolomite cores is relatively high compared to most carbonate oil reservoirs.

The rock heterogeneity, variability, wettability and high permeability was

motivation to pursue a rock type other than Silurian Dolomite.

70

4.2 TEXAS CREAM LIMESTONE EXPERIMENTS

The objective of the experiments presented in this section was to test the effect of

the microemulsion viscosity on the oil recovery after a series of surfactant floods using

fractured Texas Cream Limestone cores. Texas Cream Limestone was selected since it is

relatively homogeneous (compared to other carbonates), has a typical permeability of 10

md, and after aging in oil for a few days less than 10% of the oil was recovered after several

weeks of brine imbibition, which indicates it was oil wet.

The Texas Cream Limestone cores were fractured artificially by cutting the cores

in two halves using an electric saw (Fig. 3.6). The artificial fractures provided more

reproducibility than the fractures created with the tensile splitting method. Dead oil with a

viscosity of 12 cp at 78 °C was used in all the Texas Cream Limestone experiments. The

PV and porosity were determined from the initial oil saturation. The fracture aperture was

controlled by adjusting the confining pressure that was applied to the core. The fracture

aperture is the most critical parameter affecting the effective permeability of the core

(which accounts for the fracture and matrix permeability and the core dimensions). All the

experiments performed in Texas Cream Limestone were designed to have an effective

permeability of about 2500 md, in agreement with the permeability that has been in

naturally fractured reservoirs such as the giant Cantarell oil field (Rodriguez et al., 2004).

The effective permeability was calculated from Darcy’s law while the core was oil flooded

and the fracture aperture was calculated by rearranging equation 2.21 as follows:

𝑏 = (3𝜋𝐷𝑘𝑒)1/3. (4.3)

The permeability of the fracture was determined from the equation for single-phase

flow through parallel layers (equation 2.25)

𝑘𝑓 =𝐴𝑇𝑘𝑒 − 2𝐴𝑚𝑘𝑚

𝐴𝑓. (4.4)

71


The purpose of the FRAC-3 was to test the effect of the injection of a surfactant

solution at optimum salinity (Table 3.1) on the oil recovery from a fractured Texas Cream

Limestone core. The surfactant solution at optimum salinity was equilibrated with 30%

volume fraction oil at 78 °C and the viscosity of the middle phase microemulsion measured

after separating it from the excess oil and brine. The microemulsion viscosity data are

shown in Fig. 3.4. The microemulsion viscosity at the estimated shear rate in the fracture

of 3 s-1 is 17 cp.

The core was 3.7 cm in diameter and 29.7 cm long. The matrix permeability to air

was measured using a gas permeameter at 1000 psi and then used to determine the liquid

permeability from the Klinkenberg equation. The matrix permeability was 9 md.

The dry core was cut into two halves to create a fracture. Next the fractured core

was put into the core holder and saturated with dead oil with a viscosity of 12 cp at 78 °C

and aged for seven days so that the matrix would be oil wet. The core had a pore volume

of 82 cm3 and a porosity of 26%.

The fracture aperture was adjusted by increasing the confining pressure. The

effective oil permeability was 2360 md at 1200 psi confining pressure. The fracture width

was determined to be 0.09 mm and the fracture permeability was calculated to be 734,000

md.

The core was waterflooded with a 100,000 ppm NaCl brine at a rate of 0.3 cm3/min,

equivalent to a frontal velocity of 5 ft/D based on the whole core cross sectional area and

410 ft/D based on the fracture. The volume of oil recovered from the waterflood (2 cm3)

was similar to the fracture volume calculated from the effective permeability of the core

during the oil flood (1 cm3). The oil saturation after the water flood was 0.97 and the

pressure gradient at the end of the flood was 0.2 psi/ft.

72

Next, the core was flooded with the surfactant solution at optimum salinity (80,000

ppm TDS) at a rate of 0.01 cm3/min, equivalent to 0.17 ft/D based on the whole core and

14 ft/D based on the area of the fracture. The oil saturation after 3.0 pore volumes of

surfactant injected was 0.61 and the pressure drop was 0.8 psi/ft as shown in Figs. 4.13 and

4.14, respectively. The initial spike in the oil production occurred because the core was in

contact with the waterflood brine for three days before the surfactant was injected. This led

to the production of about 10% of the oil via spontaneous imbibition of brine. In the

subsequent experiments, the surfactant was injected immediately after the waterflood when

the latter achieved an oil cut of 0%.

Fig. 4.13‒Oil recovery for the surfactant flood at optimum salinity. Microemulsion

viscosity is 17 cp (fractured coreflood #3).

73

Fig. 4.14‒Pressure drop for the surfactant flood at optimum salinity. Microemulsion


The most important observation from this experiment is the high pressure drop across the

core. The pressure drop at this low flow rate would be expected to be very low due to the

extremely high permeability of the fracture. The expected pressure drop for the flow of a

surfactant solution with a viscosity of 0.5 cp (as injected) in a 2360 md core assuming a

relative permeability of 1.0 is calculated from Darcy’s law as follows (values were

converted to SI units).

∆𝑝 =𝑞𝜇𝐿

𝐴𝑘=

(1.6𝑥10−10 𝑚3

𝑠 ) (0.0005 𝑃𝑎 ∗ 𝑠)(0.297 𝑚)

0.00107 𝑚2(2.33𝑥10−12)= 9.53 𝑃𝑎 = 0.001 𝑝𝑠𝑖

This pressure drop is significantly lower than the pressure drop measured using the

transducer. However the resolution of the pressure transducer is 0.01 psi and the gravity

head is estimated to be 0.05 psi, so 0.001 psi cannot be accurately measured with this setup.

A better way of analyzing the pressure drop data is to compare the waterflood

pressure drop data with that for the surfactant flood. The waterflood was conducted at 0.3

74

cm3/min and had a pressure drop of 0.20 psi/ft. The surfactant flood was conducted at 0.01

cm3/min and would be expected to have a pressure drop of approximately 0.01 psi/ft,

however the surfactant flood had a pressure drop of 0.8 psi/ft, which is 80 times higher

than expected based on its aqueous phase viscosity. The most likely reason for the higher

pressure drop is the high viscosity of the microemulsion that forms in-situ when oil

produced from the matrix mixes with the injected surfactant solution in the fracture.


The objective of the FRAC-4 experiment was to determine if the results of the

FRAC-3 experiment could be reproduced at least approximately. The core had a pore

volume of 85 cm3 as determined by saturating the core with oil and a porosity of 27%.

Matrix permeability was 8 md, the effective permeability was 2430 md at a confining

pressure of 1100 psi. The corresponding fracture width was 0.09 mm and the fracture

permeability 747,000 md.

The core was waterflooded with a 80,000 ppm NaCl brine at a rate of 0.3 cm3/min,

equivalent to a frontal velocity of 5 ft/D based on the whole core and 407 ft/D based on the

fracture. The oil saturation after the waterflood was 0.95.

The surfactant solution at optimum salinity was injected at a flow rate of 0.01

cm3/min equivalent to 0.16 ft/D based on the whole core and 14 ft/D based on the fracture.

The oil saturation after injection of 4.0 PV of surfactant solution was 0.47 and the pressure

drop was 0.9 psi/ft as shown in Figs. 4.15 and 4.16 respectively.

75

Fig. 4.15‒Oil recovery for the surfactant flood at optimum salinity. Microemulsion

viscosity is 17 cp (fractured coreflood #4)

Fig. 4.16‒Pressure drop for the surfactant flood at optimum salinity. Microemulsion


76

The most important observation from this repeat experiment is that the final

pressure drop was about the same as for fractured coreflood #3. Thus, the high pressure

drop was reproduced and suggested the viscosity of the microemulsion was indeed the

likely reason.


The objective of the FRAC-5 experiment was to test the effect of a high

microemulsion viscosity on the oil recovery from a fractured Texas Cream Limestone core.

This was the first explicit test of a new hypothesis that higher microemulsion viscosity

would increase crossflow and thus oil recovery.

The core had a pore volume of 86 cm3, porosity of 28% and matrix permeability of

10 md. The effective permeability of the core after fracturing was 2500 md. The fracture

width was 0.094 mm and the fracture permeability was 749,000 md at a confining pressure

of 1300 psi.

The waterflood was performed with a 95,000 ppm NaCl brine, injected at a rate of

0.3 cm3/min until no oil was detected in the effluent. The oil saturation at the end of the

water flood was 0.97 since the waterflood only recovered oil from the fracture. The

pressure drop at the end of the waterflood was 0.25 psi/ft.

Next, a surfactant solution with a microemulsion viscosity of 75 cp at the estimated

shear in the fracture of 3 s-1 was injected at a rate of 0.01 cm3/min, equivalent to a frontal

velocity of 14 ft/D based on the fracture.

High microemulsion viscosity was achieved by injecting the surfactant solution at

a salinity of 95,000 ppm TDS (Fig. 3.2). Increasing the salinity also affects the interfacial

tension. The oil solubilization ratio at 95,000 ppm is estimated from Fig. 3.1 to be 22 and

77

the IFT between the microemulsion and oil calculated from the Huh equation is 0.0006

mN/m. The IFT for this experiment is lower than for the FRAC-3 and FRAC-4

experiments; however, both IFT between the microemulsion and brine is higher.

Nonetheless, all the IFTs are ultralow so that the capillary pressure is essentially negligible

in all cases. Since all other properties are nearly the same, any differences in the oil

recovery between the experiments can be attributed to the changes in the microemulsion

viscosity. The oil saturation after injection of 5.4 pore volumes of surfactant solution was

0.30 and the pressure drop was 1 psi/ft as shown in Figs. 4.17 and 4.18, respectively.

The oil recovery and the pressure drop from this experiment were higher than those

obtained from the two previous experiments performed using a lower microemulsion

viscosity. This finding indicates that using a more viscous microemulsion can enhance the

oil recovery from fractured oil-wet rocks by increasing viscous crossflow.

Fig. 4.17‒Oil recovery for the surfactant flood with a high microemulsion viscosity

of 75 cp (fractured coreflood #5).

78

Fig. 4.18‒Pressure drop for the surfactant flood with a high microemulsion viscosity

of 75 cp (fractured coreflood #5).


The objective of the FRAC-6 experiment was to test the previously stated

microemulsion viscosity hypothesis by injecting a surfactant solution that would be

expected to form a lower in-situ microemulsion viscosity based on the rheology

measurements.

The fractured core had a pore volume of 87 cm3 and porosity was 29%. The matrix

permeability was 11 md. The effective permeability was 2530 md. The fracture aperture

and fractured permeability were 0.094 mm and 754,000 md, respectively. The core was

waterflooded with a 65,000 ppm NaCl brine at a rate of 0.3 cm3/min. The waterflood only

recovered the oil in the fracture. The oil saturation after the waterflood was 0.98. The

pressure drop at the end of the flood was 0.25 psi/ft.

The core was flooded with the optimized surfactant solution at a salinity of 65,000

ppm TDS. The microemulsion viscosity at 65,000 ppm is estimated to be 0.5 cp (Fig. 3.2).

79

The oil solubilization ratio at 65,000 ppm is 7.0 and the IFT between the oil and the

microemulsion calculated from the Huh equation is 0.006 mN/m. This IFT is still low

enough so that the capillary pressure is negligible. The surfactant solution was injected at

a rate of 0.01 mL/min, equivalent to 0.16 ft/day based on the whole core and 14 ft/day

based on the fracture. The oil saturation at the end of the surfactant flood was 0.66, the oil

cut was less than 1% and the pressure drop was 0.3 psi/ft as shown in Figs. 4.19 and 4.20,

respectively. Next, the salinity of the surfactant solution was increased to 95,000 ppm, such

as the one used in the FRAC-5 experiment. The microemulsion viscosity at the estimated

shear rate in the fracture and at this salinity is 75 cp. The pressure drop data plotted in Fig.

4.20 shows a pressure increase corresponding to the flow of a more viscous microemulsion.

The more viscous microemulsion was able to increase the oil cut to a maximum of 7% and

reduced the oil saturation to 0.59.

Fig. 4.19‒Oil recovery for a surfactant flood with low microemulsion viscosity

followed by a surfactant flood with high microemulsion viscosity (fractured

coreflood #6).

80

Fig. 4.20‒Pressure drop for a surfactant flood with low microemulsion

viscosity followed by a surfactant flood with high microemulsion viscosity (fractured

coreflood #6).

4.2.5 Non-fractured coreflood #2

The objective of the non-FRAC-2 experiment was measure the oil recovery for a

tertiary surfactant flood using a non-fractured Texas Cream Limestone core for comparison

with the results from the fractured coreflood experiments. The non-fractured coreflood was

also used to determine the endpoint relative permeabilities and the residual oil saturation

after a surfactant flood with no mobility control. The experimental procedure was very

similar to the one followed during the fractured corefloods, but had important differences

with the non-FRAC-1 experiment.

The core used in this experiment was saturated with dead oil and aged for seven

days at 78 °C, which is the same procedure as used for the fractured coreflood experiments.

The pore volume was determined to be 90 cm3 and the porosity was 29%. The oil

permeability was 9 md. The core was flooded with an 80,000 ppm NaCl brine at a rate of

81

0.05 cm3/min, equivalent to a frontal velocity of 0.77 ft/D until no oil was produced. The

oil saturation after the waterflood was 0.47.

The surfactant solution was injected at optimum salinity at a rate of 0.01 cm3/min

equivalent to a frontal velocity of 0.15 ft/D, the pressure drop at this flow rate was 8 psi/ft.

Next, the injection flow rate was increased to 0.06 cm3/min (0.9 ft/D). The oil saturation

after 4.2 PV of injected surfactant solution was 0.20. The oil recovery as a fraction of the

waterflood residual oil was 56%. The maximum oil cut was 17% and the pressure drop at

the end of the flood was 16 psi/ft as shown in Figs. 4.21 and 4.22, respectively. The oil cut

data in Fig. 4.21 indicates that this was an unstable flood, which was expected since no

polymer was used for mobility control. The surfactant solution was displaced by

continuous injection of a 65,000 ppm NaCl brine. The water relative permeability at an oil

saturation of 0.20 (remaining oil after the surfactant flood) was 0.60. And the oil relative

permeability at residual water saturation (Swro) was 0.42.

Fig. 4.21‒Surfactant flood oil recovery from a non-fractured Texas Cream

Limestone core (non-fractured coreflood #2.)

82

Fig. 4.22‒Pressure data from a surfactant flood in a non-fractured Texas Cream

Limestone core (non-fractured coreflood #2).

4.2.6 Analysis of the results

The oil recovery data as a function of the microemulsion viscosity for all the

surfactant floods performed in the fractured Texas Cream Limestone cores are shown in

Fig. 4.23. The oil recovery is shown as fraction of the original oil in place (OOIP) and is

plotted as a function of the surfactant pore volumes injected. The oil recovery data from

the non-fractured coreflood experiment is also shown for comparison purposes.

The surfactant flood experiment with a microemulsion viscosity of 75 cp recovered

68% of the OOIP. The experiments with a microemulsion viscosity of 17 cp recovered 36

and 48% of the OOIP, respectively. The experiment with a microemulsion viscosity of 0.5

cp recovered 32% of the OOIP. The oil recovery from the non-fractured core was 80%

including the oil recovery from both the waterflood and the surfactant flood.

83

Fig. 4.23‒Effect of the microemulsion viscosity on the oil recovery from fractured

Texas Cream Limestone cores.

The results demonstrate that the more viscous microemulsions achieved higher oil

production rate and a higher ultimate oil recovery from the fractured carbonate cores. This

experimental finding is novel and has significant implications for the design of surfactant

EOR processes in naturally fractured reservoirs. They indicate that oil recovery from a

naturally fractured reservoir can be enhanced by the injection of a surfactant solution that

has a high microemulsion viscosity. The oil recovery mechanism due to the formation and

the flow of a viscous microemulsion in a fracture is discussed next.

Fig. 4.24 shows a vertical cross section of a matrix-fracture system. This figure

depicts the injection of a surfactant solution under a constant pressure drop condition at an

arbitrary time t=t1. At this time the surfactant solution has traversed a distance h through

the fracture. The presence of the surfactant in the fracture reduces the capillary forces at

the fracture-matrix boundary. When the capillary forces are low enough, imbibition can

84

occur driven by gravity forces. CT images of a fractured coreflood performed by Mirzaei

et al. (2016) suggest that an inverted cone forms in the core when surfactant is injected

upward from the bottom of the core under gravity dominated flow conditions. The cone-

shaped profile is indicated by the dashed line in Fig. 4.24. The heavy arrows indicate the

direction of oil flow and the light arrows indicate the direction of surfactant flow.

Material balance requires that the amount of surfactant going into the matrix is

equal to the amount of oil that is expelled into the fracture (assuming fluids are

incompressible). Once in the fracture, the oil mixes with the injected surfactant solution

flowing in the fracture and forms a microemulsion. The newly formed microemulsion has

a higher viscosity than that of the injected surfactant solution and the oil residing in the

matrix. Thus, as the viscous microemulsion flows through the fracture towards the

production well, it induces a transverse pressure gradient that results in fluid crossflow. In

other words, it results in more surfactant imbibing into the matrix and more oil being

expelled into the fracture.

Fig. 4.24‒ Surfactant imbibition profile into the matrix and oil expulsion into the

fracture.

85

Fig. 4.25 shows the imbibition profile at an arbitrary time t=t2. For simplicity, the

imbibition profile has been represented by two horizontal layers advancing from the bottom

of the matrix. The upper layer represents the microemulsion front that forms when the

imbibing surfactant solution mixes with oil in the matrix. The lower layer represents the

surfactant solution that flows behind the microemulsion. The process is unstable since the

surfactant solution has a lower viscosity than the microemulsion flowing ahead of it, but it

is also self-correcting because the surfactant that fingers through the microemulsion mixes

with the oil ahead and also generates a microemulsion and it is also at least partly stabilized

by gravity forces since the surfactant solution is denser than the microemulsion. The same

phenomena occurs inside the fracture, where the surfactant solution displaces the

microemulsion, which in turn displaces the water flowing ahead.

Fig. 4.25‒Viscous crossflow due to the formation and flow of a

microemulsion in the fracture.

86

This qualitative interpretation is supported by the experimental pressure drop data

from the surfactant floods with different microemulsion viscosity. The pressure drop for

the high microemulsion viscosity (75 cp) was 1.2 psi/ft, 0.9 psi/ft for the intermediate

microemulsion viscosity of 17 cp and 0.3 psi/ft for the low microemulsion viscosity (0.5

cp). Although the pressure drop data are not in close agreement with the expected values

based on the viscosity for these microemulsions as measured with the rheometer, this may

be because the composition of the external and in-situ microemulsions are not identical and

the viscosity depends on shear rate, which is not uniform in the core. Regardless, it seems

likely that higher microemulsion viscosity leads to higher pressure drops and that the

pressure drops are large enough to significantly increase the oil recovery from the fractured

limestone cores as indicated by the oil recovery data plotted in Fig. 4.23.

87

Chapter 5: Conclusions and Future Work

5.1 CONCLUSIONS

The research results presented in this thesis include experimental evidence

demonstrating the importance of viscous forces for oil recovery during surfactant flooding

of fractured carbonate cores. Most importantly, this research demonstrates that viscous

forces are naturally enhanced by using surfactants that form microemulsions with a high

viscosity inside the core.

The effects of viscous forces on the oil recovery during a surfactant flood in a

fractured carbonate core were investigated by conducting a series of ultralow IFT

surfactant floods using fractured Silurian Dolomite and Texas Cream Limestone cores.

The viscosity of the surfactant solution was increased by adding polymer to the

surfactant solution or by changing the salinity of the aqueous surfactant solution, which

affects the in-situ microemulsion viscosity.

The fractured cores had an extreme permeability contrast between the fracture and

the matrix (ranging from 2500 to 90,000) so as to represent typical conditions encountered

in most naturally fractured reservoirs. Non-fractured coreflood experiments were also

performed in cores of each rock type for comparison with the fractured corefloods.

This is the first experimental study of the effect of viscous forces on the

performance of surfactant floods of fractured carbonate cores under dynamic conditions.

Previous experimentalists assumed the small viscous forces were not important for oil

recovery from fractured reservoirs since the pressure gradients that can be established in

this type of reservoir are very low due to the presence of highly conductive fractures.

However, this study clearly indicates that viscous forces play an important role since even

small pressure gradients transverse to the flow direction in the fracture can induce fluid

crossflow between the fracture and the matrix.

88

Silurian Dolomite cores were used in the first two fractured coreflood experiments.

The ratio of the fracture permeability to the matrix permeability was 5000 for FRAC-1 and

2500 for FRAC-2. In both experiments, water was injected first, followed by a surfactant

solution and then by a surfactant-polymer solution with a higher viscosity. The oil recovery

as a fraction of the original oil in place (OOIP) after the waterflood, the surfactant flood

and the surfactant-polymer flood was 76% for the FRAC-1 and 83% for the FRAC-2

coreflood experiments. The oil recovery from the non-fractured Silurian Dolomite core

after a waterflood and an alkaline-surfactant-polymer flood was 93%. The oil recovery

from the fractured Silurian Dolomite cores was much higher than expected for a fractured

core with such a high permeability contrast. However, the most interesting finding from

this experiment is that the oil production rate and the pressure drop increased when the

more viscous surfactant-polymer solutions were injected.

The role of viscous forces was also indicated by comparing the oil recovery from

the two fractured Silurian Dolomite cores with two static surfactant imbibition experiments

using Silurian Dolomite cores and the same surfactant formulation (Li, 2016). The oil

recovery was much higher when surfactant imbibition occurred under dynamic conditions.

The incremental oil recovery from the dynamic imbibition experiments over the static

imbibition experiments is attributed to viscous forces since gravity and capillary forces are

present under both static and dynamic conditions, however, the viscous forces are greater

for the dynamic coreflood experiments compared to the static imbibition experiments.

The fractured coreflood experiments performed with a viscous surfactant-polymer

solution were useful in demonstrating the importance of viscous forces from fractured

carbonate cores. However, the use of polymer in the surfactant solution adds to the cost

and complexity of the process. A simpler approach would be to use surfactant solutions

that form viscous microemulsions in-situ to increase the viscous forces in the dynamic

89

displacements. Therefore, the second part of this research was dedicated to investigating

the effects of using viscous microemulsions for enhancing the oil recovery during

surfactant floods from fractured carbonate cores.

Four surfactant flooding experiments were performed in fractured Texas Cream

Limestone cores at 78 °C using surfactant solutions that form microemulsions with

different viscosity. The microemulsion viscosity was changed by adjusting the salinity of

the brine in the microemulsion (see Fig. 3.2). Microemulsion viscosities were measured at

78 °C on equilibrated samples at each salinity. The microemulsion viscosity values as

measured with the rheometer were 0.5, 17 and 75 cp, respectively, at the shear rates

estimated in the corefloods. All of the experiments were done under low IFT conditions so

that capillary pressure was negligible. The ratio of the fracture permeability to the matrix

permeability ranged between 70,000 and 90,000 for the Texas Cream Limestone cores.

The oil recovery was greater for the corefloods with the higher microemulsion

viscosities. The oil recovery for a surfactant that formed a microemulsion viscosity of 75

cp was 68% of the OOIP. The oil recovery for a microemulsion viscosity of 17 cp recovered

48% of the OOIP and the oil recovery for a microemulsion viscosity of 0.5 cp was 32% of

the OOIP. The oil recovery after a surfactant flood from a non-fractured core under similar

conditions as the fractured cores was 80%.

These results demonstrate that using surfactants that form microemulsions with a

high viscosity can enhance the oil recovery from fractured carbonates. The finding can be

explained as follows: there is a difference in the gravity head between the surfactant

solution in the vertical fracture and the oil in the matrix due to the lower density of the oil.

The higher pressure in the fracture causes the surfactant to imbibe into the matrix under a

small horizontal pressure gradient. When the surfactant mixes with the oil and brine in the

matrix, it forms a microemulsion. When the salinity is near its optimum value such as in

90

all of these experiments, the IFT is very low and capillary forces are negligible. However,

the oil and microemulsion relative permeabilities increase due to both the ultralow IFT and

the change in wettability from oil wet to more water wet conditions. This allows some of

the oil and microemulsion to flow from the matrix into the fracture where it also mixes

with surfactant solution and forms more microemulsion. As viscous microemulsions flow

through the fracture it generates transverse pressure gradients that increase the rate of

surfactant imbibition into the matrix. A more viscous microemulsion will induce greater

transverse pressure gradients that will result in more crossflow and more oil production.

These results imply that a viscous microemulsion can serve as a mobility control agent,

analogous to mobility control with foams or polymers but with far less complexity and

cost.

Overall, the results from this research demonstrate that viscous forces play a major

role on the oil recovery during surfactant floods of fractured carbonate rocks, which

contradicts conventional wisdom. The results also indicate that the oil recovery from

naturally fractured reservoirs can be enhanced by using surfactants that achieve ultralow

IFT and that provide mobility control by the formation and flow of viscous microemulsions

in the fractures.

5.2 FUTURE WORK

Future research should be dedicated to accurately quantifying the magnitude of

viscous forces on the oil recovery during surfactant floods in fractured rocks, More

fractured coreflood experiments will be needed, but also numerical simulations calibrated

with experimental data could be used to better analyze and optimize surfactant imbibition

processes in naturally fractured reservoirs.

91

The experimental data presented here is the first of its kind and should be used for

calibrating the numerical models that are used to simulate surfactant flooding in naturally

fractured reservoirs. The simulations should help us better understand the effect of the in-

situ microemulsion viscosity. Most simulations of imbibition processes have not used a

sufficiently fine numerical grid. However, if these simulations are to accurately capture the

physics of the process, very fine grid simulations need to be performed. The simulations

could also be used to compare the use of foam with the use of viscous microemulsions for

mobility control.

In addition, pore network models could provide a much better understanding of the

magnitude of transverse pressure gradients and in general of all the mechanisms causing

imbibition. To this date there is not a single reference regarding the investigation of

surfactant imbibition processes by using pore network models.

More fractured coreflood experiments should be performed with a wide variety of

oils, brines, surfactants and rocks. The effect of EDTA, alkali and co-solvent needs to be

investigated for rocks and brines with different geochemistry. A very interesting question

is the effect of the surfactant residence time on the imbibition and oil recovery.

More comparisons between static and dynamic imbibition experiments using the

same fluids, rocks and core dimensions would also be useful.

Several classical scaling groups have been developed for gravity and capillary

driven imbibition but none of them took into account the transverse pressure gradients that

are induced by fluid flow inside a fracture and demonstrated herein to be significant for

enhancing fluid crossflow between the fracture and the matrix. Furthermore, none of the

scaling groups have been developed to account for the microemulsion viscosity and none

of them were validated using cores of different diameters among other severe limitations.

The analytical model recently developed by Li et al., (2016) for low IFT surfactant

92

imbibition is the only available scaling group that accounts for the microemulsion viscosity

and that has been tested with a series of experiments using cores of different sizes, but no

such model is available for dynamic experiments.

The issue of surfactant utilization should also be studied if this process is to become

economically feasible. The implementation of this process will require that a small

surfactant slug can achieve a high oil recovery in a reasonable length of time. This research

has contributed to this goal by demonstrating that using viscous microemulsions can

enhance the rate of oil recovery from fractured carbonate cores. Although much more

remains to be done to meet the challenges of enhanced oil recovery from naturally fractured

reservoirs, the significant progress made during this and other recent research on surfactant

imbibition is a good start and justifies some optimism that this goal will eventually be

achieved.

93

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