MECHANISMS OF OIL RECOVERY DURING CYCLIC CO INJECTION ...ourspace.uregina.ca/bitstream/handle/10294/5503/Abedini_Ali_2002… · have seen significant increase in interest for the

MECHANISMS OF OIL RECOVERY DURING CYCLIC CO2

INJECTION PROCESS: IMPACT OF FLUID INTERACTIONS,

OPERATING PARAMETERS, AND POROUS MEDIUM

A Thesis

Submitted to the Faculty of Graduate Studies and Research

In Partial Fulfillment of the Requirements

For the Degree of

Doctor of Philosophy

in

Petroleum Systems Engineering

University of Regina

By

Ali Abedini

Regina, Saskatchewan

July, 2014

Copyright 2014: A. Abedini

UNIVERSITY OF REGINA

FACULTY OF GRADUATE STUDIES AND RESEARCH

SUPERVISORY AND EXAMINING COMMITTEE

Ali Abedini, candidate for the degree of Doctor of Philosophy in Petroleum Systems Engineering, has presented a thesis titled, Mechanisms of Oil Recovery During Cyclic CO2 Injection process: Impact of Fluid Interactions, operating parameters, and Porous Medium, in an oral examination held on July 8, 2014. The following committee members have found the thesis acceptable in form and content, and that the candidate demonstrated satisfactory knowledge of the subject material. External Examiner: *Dr. Hassan Hassanzadeh, University of Calgary

Supervisor: Dr. Farshid Torabi, Petroleum Systems Engineering

Committee Member: Dr. Fanhua Zeng, Petroleum Systems Engineering

Committee Member: Dr. Ezeddin Shirif, Petroleum Systems Engineering

Committee Member: Dr. Hussameldin Ibrahim, Process Systems Engineering

Committee Member: Dr. Shaun Fallat, Department of Mathematics & Statistics`

Chair of Defense: Dr. Dongyan Blachford, Faculty of Graduate Studies & Research

*Via Tele=conference

i

ABSTRACT

Carbon dioxide (CO2) injection processes are among the most promising

enhanced oil recovery techniques based on their great potential to improve oil production

while utilizing geological storage of carbon dioxide to reduce greenhouse gas emissions.

Among various CO2 injection modes, cyclic CO2 injection (CO2 huff-and-puff) scenarios

have seen significant increase in interest for the purpose of enhanced oil recovery (EOR)

in both non-fractured and fractured reservoirs. Several operating parameters, including

operating pressure, solvent (CO2) injection time, soaking period, water saturation, etc.,

affect the performance of this process. However, the number of studies that consider

these parameters is relatively limited. In this study, the performance of cyclic CO2

injection under various operating conditions for a light crude oil system is experimentally

investigated. First, a comprehensive experimental study on the phase behaviour of the

crude oil–CO2 system was conducted. Thereafter, a series of cyclic CO2 injection tests

was designed and carried out in non-fractured and fractured porous media to determine

the impact of various parameters on the recovery efficiency of this process.

For the cyclic CO2 injection tests conducted at operating pressures ranging from

immiscible to near-miscible conditions, it was found that the oil recovery increases

considerably with operating pressures and reaches near maximum value at miscible

condition. However, beyond this range, where the operating pressure exceeds the

minimum miscibility pressure, the oil recovery factor was almost constant and further

increase in operating pressure did not improve the oil recovery effectively. In addition,

although it was seen that a longer soaking period and the presence of connate water

saturation are positive parameters that enhance the recovery performance of immiscible

ii

cyclic CO2 injections, these parameters do not have noticeable influence in miscible

injection scenarios. Furthermore, the results showed that longer CO2 injection time does

not enhance the oil recovery. Additionally, it was observed that the cyclic CO2 injection

process has a great capacity for CO2 storage, and it was found that the CO2 storage

potential is more efficient if the cyclic injection process is implemented at pressures near

the minimum miscibility pressure.

The asphaltene precipitation inside the rock sample and its subsequent

permeability reduction due to the CO2 injection were examined. The amount of the

precipitated asphaltene in the porous media is considerably higher during miscible

injection scenarios resulting in drastic reduction of the oil effective permeability. The

compositional analysis of the remaining crude oil in the core also demonstrated that the

mechanism of light component extraction by CO2 is much stronger during miscible cyclic

CO2 injection compared to immiscible injection.

The effect of fractures in the porous media on the oil recovery of cyclic CO2

injection was investigated, and the results showed that the presence of fracture

significantly improves the oil recovery during the process. The impact of fracture was

found to be more effective during immiscible cyclic CO2 injection. In addition, the

examination of fracture orientation showed that horizontal fracturing remarkably

enhances the oil production, while no noticeable increase in oil production was observed

when the orientation of fracture was vertical. The numerical simulation of the process

also revealed that the oil recovery of cyclic CO2 injection gives larger benefits from

greater fracture width together with the presence of more fractures inside the system

through enlarging the contact area between the CO2 and oil in-place.

iii

ACKNOWLEDGEMENTS

I would like to express my most sincere gratitude and appreciation to my supervisor, Dr.

Farshid Torabi, for his great support, patience, generosity, and invaluable guidance

during this research. I am truly indebted to him for teaching me how to approach complex

problems.

I would like to gratefully thank Dr. Hassan Hassanzadeh, Dr. Ezeddin Shirif , Dr. Fanhua

Zeng, Dr. Hussameldin Ibrahim, and Dr. Shaun Fallat for serving as members of my

examination committee and for their valuable suggestions in this study.

I gratefully acknowledge the Faculty of Graduate Studies and Research (FGSR) at the

University of Regina and the Petroleum Technology Research Centre (PTRC) for

financial support of this research, and thankful to Dr. Peter Gu for providing the IFT

measurement test set-up.

Additional thanks go to my friends and colleagues during my study, and special

appreciation goes to my friend, Mr. Nader Mosavat, for his continuous assistance and

encouragement during my study and technical discussion on the research results.

I would like to thank Ms. Heidi Smithson for technical editing this thesis.

http://www.urengineering.ca/faculty-staff/pse/dr-ezeddin-shirif

iv

DEDICATION

Dedicated to my beloved wife, Atena, my parents and parents-in-law, and my siblings for

their endless love, patience, help, inspiration, and encouragement which made the

completion of this work possible.

v

TABLE OF CONTENTS

ABSTRACT ........................................................................................................................ i

ACKNOWLEDGEMENTS ............................................................................................ iii

DEDICATION.................................................................................................................. iv

TABLE OF CONTENTS ................................................................................................. v

LIST OF TABLES ........................................................................................................... ix

LIST OF FIGURES ......................................................................................................... xi

NOMENCLATURE ..................................................................................................... xxiv

CHAPTER ONE: INTRODUCTION ............................................................................. 1

1.1. Production Phases from a Reservoir ...................................................................... 1

1.2. CO2 Enhanced Oil Recovery (CO2-EOR).............................................................. 4

1.3. Immiscible and Miscible CO2 Injections ............................................................... 5

1.4. Cyclic CO2 Injection .............................................................................................. 6

1.5. Fractured Reservoirs .............................................................................................. 7

1.6. Scope and objectives of the research ................................................................... 12

1.7. Organization of the Thesis ................................................................................... 14

CHAPTER TWO: LITERATURE REVIEW .............................................................. 16

2.1. Cyclic CO2 Injection Process (CO2 Huff-and-Puff) ............................................ 16

2.2. Recovery Mechanisms in CO2-EOR Processes ................................................... 22

2.3. Chapter Summary ................................................................................................ 24

vi

CHAPTER THREE: PHASE BEHAVIOUR STUDY AND PVT

CHARACTERIZATION ............................................................................................... 26

3.1. Crude Oil and Brine Properties ............................................................................ 26

3.2. CO2 Solubility, Oil Swelling Factor, and Interfacial Tension of Crude Oil–CO2

System ......................................................................................................................... 31

3.2.1. CO2 Solubility and Oil Swelling Factor of Crude oil–CO2 System ............. 31

3.2.2. Crude oil–CO2 Interfacial Tension Measurement ........................................ 41

3.3. Minimum Miscibility Pressure (MMP) of Crude Oil–CO2 System ..................... 46

3.3.1. MMP Determination using VIT Technique ................................................. 47

3.3.2. MMP Determination using Oil Swelling/Extraction Test Results ............... 50

of CO2 at lower temperature as well as that the extraction of lighter components by

CO2 starts earlier. ................................................................................................... 54

3.3.3. MMP Determination using Proposed Correlations ...................................... 54

3.4. Solubility of CO2 in Brine–CO2 System .............................................................. 57

3.5. Chapter Summary ................................................................................................ 61

CHAPTER FOUR: CYCLIC CO2 INJECTION TESTS IN NON-FRACTURED

POROUS MEDIUM ....................................................................................................... 63

4.1. Materials and Experimental Set-up ...................................................................... 63

4.2. Experimental Procedure ....................................................................................... 67

4.2.1. Secondary Cyclic CO2 Injection ................................................................... 67

4.2.2. Parametric Study of Cyclic CO2 Injection ................................................... 68

4.2.3. Asphaltene Precipitation and Oil Effective Permeability Damage .............. 71

4.3. Experimental Results and Discussion .................................................................. 72

4.3.1. Oil Recovery Factor, Producing Gas–Oil Ratio (GOR), and Gas Utilization

Factor (GUF) .......................................................................................................... 72

vii

4.3.2. Effect of the CO2 Injection Time (Tinj) ......................................................... 81

4.3.3. Effect of the Soaking Period (Tsoak) .............................................................. 83

4.3.4. Effect of the Connate Water Saturation (Swc) ............................................... 85

4.3.5. Effect of the CO2/Propane mixture .............................................................. 87

4.3.6. Asphaltene Precipitation (Wasph) and Oil Effective Permeability Damage

(DFo) ....................................................................................................................... 90

4.3.7. Compositional Analysis of Remaining Oil .................................................. 92

4.3.8. Production Results of all Secondary Cyclic CO2 Injection Tests ................ 96

4.3.9. Tertiary Cyclic CO2 Injection Test ................................................................. 102

4.3.10. CO2 Storage during Cyclic Injection Tests ................................................... 104

4.4. Chapter Summary .............................................................................................. 115

CHAPTER FIVE: CYCLIC CO2 INJECTION TESTS IN FRACTURED POROUS

MEDIUM ....................................................................................................................... 117

5.1. Experimental Set-up and Configurations of Fractures....................................... 117

5.2. Experimental Results and Discussion ................................................................ 121

5.3. Chapter Summary .............................................................................................. 140

CHAPTER SIX: NUMERICAL SIMULATION STUDY ........................................ 141

6.1. Phase Behaviour Simulation .............................................................................. 141

6.2. Lab-scale Simulation of Cyclic CO2 Injection Tests ......................................... 148

6.2.1. Simulation Model of Non-fractured Porous Medium ................................ 148

6.2.2. Simulation Model of Fractured Porous Medium ........................................ 149

6.3. History Matching and Comparison of Numerical Simulation Results with

Experimental Study ................................................................................................... 154

viii

6.3.1. History Matching Parameters ..................................................................... 154

6.3.2. Non-fractured Porous Medium ................................................................... 157

6.3.3. Fractured Porous Medium .......................................................................... 162

6.4. Parametric Study on Fracture Properties ........................................................... 165

6.4.1. Effect of the Fracture Width ....................................................................... 165

6.4.2. Effect of the Number of Fractures .............................................................. 170

6.4. Chapter Summary .............................................................................................. 174

CHAPTER SEVEN: CONCLUSIONS AND RECOMMENDATIONS ................. 176

7.1. Conclusions ........................................................................................................ 176

7.2. Recommendations .............................................................................................. 183

REFERENCES .............................................................................................................. 184

APPENDIX A: THE STANDARD ASTM D2007-03 METHOD TO MEASURE

ASPHALTENE CONTENT ......................................................................................... 204

APPENDIX B: EXPERIMENTAL RESULTS OF ALL CYCLIC CO2 TESTS IN

NON-FRACTURED POROUS MEDIA ..................................................................... 206

APPENDIX C: LIST OF PUBLICATIONS............................................................... 222

ix

LIST OF TABLES

Table 3.1: Compositional analysis of the light crude oil under study at T = 21 °C and

atmospheric pressure (Conducted by Saskatchewan Research Council). ........ 28

Table 3.2: Pressure range, correlated equations and their accuracy, and calculated multi-

contact and first-contact MMPs obtained from VIT technique at T = 30 °C. .. 48

Table 3.3: Pressure range, correlated equations and their accuracy, and calculated MMP

obtained by the analysis of oil swelling factor results at T = 21 °C and 30 °C. 53

Table 3.4: Proposed correlations for calculating the MMP of crude oil–CO2 system. ..... 55

Table 3.5: Comparison of measured MMPs of crude oil–CO2 system with those

calculated by proposed correlations. ................................................................ 56

Table 4.1: Properties of the core sample and core holder used for cyclic CO2 injection

tests. .................................................................................................................. 66

Table 4.2: Initial (i.e., , k, Swc, and Soi) and operating conditions (i.e., Pop, Tinj, Tsoak, Swc,

and solvent) for all secondary cyclic CO2 injection tests. ................................ 70

Table 4.3: Experimental results (ultimate, 1st, and 2

nd stage recovery factors, total

producing GOR, final GUF, Wasph of produced oil, and oil effective

permeability damage) of all cyclic CO2 injection tests performed at various

operating conditions. ........................................................................................ 97

Table 5.1: Rock properties and characteristics of the artificial fractured systems. ........ 120


and solvent) for all secondary cyclic CO2 injection tests. .............................. 122

Table 6.1: Some of the main properties of the six sub-pseudo-components used to match

the measured PVT properties. ........................................................................ 144

x

Table 6.2: Characteristics of proposed physical model for lab-scale simulation of cyclic

CO2 injection tests conducted in non-fractured porous medium. ................... 150


CO2 injection tests conducted in fractured porous medium. .......................... 152

xi

LIST OF FIGURES

Figure 1.1: Idealization of fracture porous media by Warren and Root (1963). .............. 10

Figure 3.1: Compositional analysis of the original light crude oil sample at atmospheric

pressure and temperature of T = 21 °C (ρoil = 802 kg/m3, μoil = 2.92 mPa.s,

MW = 223 gr/mol, and n-C5 insoluble asphaltene content = 1.23 wt%;

Conducted by Saskatchewan Research Council). ........................................ 29

Figure 3.2: Measured values of crude oil density and viscosity as a change of temperature

at atmospheric pressure. ............................................................................... 30

Figure 3.3: Schematic diagram of the experimental set-up used for CO2 solubility and oil

swelling factor measurements at various equilibrium pressures. ................. 33

Figure 3.4: Details of the visual technique used to determine the volumes of oil and CO2

phases at each equilibrium pressure in order to calculate the CO2 solubility

in crude oil and resulting oil swelling factor. .............................................. 35

Figure 3.5: Measured CO2 solubility in the crude oil at experimental temperatures of T =

21 °C and 30 °C. .......................................................................................... 37

Figure 3.6: Determined oil swelling factor and extraction pressure of crude oil–CO2

system at experimental temperatures of T = 21 °C. ..................................... 39


system at experimental temperatures of T = 30 °C. ..................................... 40

Figure 3.8: Schematic diagram of the experimental set-up used for measuring the

equilibrium IFT for the crude oil–CO2 system at various equilibrium

pressures. ...................................................................................................... 42

xii

Figure 3.9: Measured dynamic interfacial tensions (IFTdyn) of the crude oil–CO2 system

at different equilibrium pressures and a temperature of T = 30 °C. ............. 44

Figure 3.10: Measured equilibrium interfacial tensions (IFTeq) of the crude oil–CO2

system at different equilibrium pressures and a temperature of T = 30 °C. 45

Figure 3.11: Multi- contact and first contact MMPs of crude oil–CO2 system obtained

from VIT technique at a temperature of T = 30 °C. ..................................... 49

Figure 3.12: The MMP of crude oil–CO2 system obtained from the analysis of extraction

phase in oil swelling curve at T = 21 °C (estimated MMPSF = 8.07 MPa). . 51


phase in oil swelling curve at T = 30 °C (estimated MMPSF = 8.96 MPa). . 52

Figure 3.14: Schematic diagram of the experimental set-up used to measure CO2

solubility in the synthetic brine. ................................................................... 58

Figure 3.15: Measured CO2 solubility in the synthetic brine at temperatures of T = 21 °C

and 30 °C. .................................................................................................... 60

Figure 4.1: Schematic diagram of the experimental set-up used for cyclic CO2 injection

tests. ............................................................................................................. 65

Figure 4.2: Cumulative oil recovery factor of cyclic CO2 injection tests (at Tinj = 120 min

and Tsoak = 24 hrs) vs. cycle number and time at various operating pressures.

...................................................................................................................... 73


and Tsoak = 24 hrs) vs. pore volume of injected CO2 at various operating

pressures. ...................................................................................................... 74

xiii

Figure 4.4: Ultimate, 1st and 2

nd stage oil recovery factors of the five cyclic CO2 injection

tests (at Tinj = 120 min and Tsoak = 24 hrs) performed at immiscible, near-

miscible, and miscible conditions. ............................................................... 77

Figure 4.5: Producing GOR of the five cyclic CO2 injection tests (at Tinj = 120 min and

Tsoak = 24 hrs) performed at immiscible, near-miscible, and miscible

conditions. .................................................................................................... 78

Figure 4.6: GUF of the five cyclic CO2 injection tests (at Tinj = 120 min and Tsoak = 24

hrs) performed at immiscible, near-miscible, and miscible conditions. ...... 79

Figure 4.7: Total producing GOR and final GUF of the five cyclic CO2 injection tests (at

Tinj = 120 min and Tsoak = 24 hrs) performed at immiscible, near-miscible,

and miscible conditions................................................................................ 80

Figure 4.8: Ultimate, 1st, and 2

nd stage recovery factors of cyclic CO2 injection tests

performed at operating pressures of Pop = 5.38 MPa and 8.27 MPa with CO2

injection times of Tinj = 30 min and 120 min and identical soaking period of

Tsoak = 24 hrs (Test # 1, 2, 9 and 11). ........................................................... 82

Figure 4.9: Ultimate recovery factor of cyclic CO2 injection tests performed at operating

pressures ranging from Pop = 5.38–10.34 MPa with soaking periods of Tsoak

= 24 hrs and 48 hrs and identical CO2 injection time of Tinj = 120 min. ..... 84


pressures ranging from Pop = 5.38–10.34 MPa in the presence and absence

of connate water saturation. ......................................................................... 86

xiv

Figure 4.11: Cumulative oil recovery factor of cyclic CO2/C3 injection tests (at Tinj = 120

min and Tsoak = 24 hrs) vs. cycle number at operating pressures of Pop = 3.45

MPa and Pop = 4.83 MPa. ............................................................................ 88


min and Tsoak = 24 hrs) vs. pore volume of injected solvent at operating

pressures of Pop = 3.45 MPa and Pop = 4.83 MPa. ....................................... 89

Figure 4.12: Asphaltene content of CO2-produced oil, precipitated asphaltene in the core

and oil effective permeability damage (DFo) of the core sample in cyclic

CO2 injection tests (at Tinj = 120 min and Tsoak = 24 hrs, Pop = 5.38–10.34

MPa) under immiscible, near-miscible, and miscible conditions. ............... 91

Figure 4.13: Compositional analysis, plus fraction and molecular weight of original and

remaining crude oils of cyclic CO2 injection tests performed at Pop = 6.55

MPa and 9.31 MPa (Conducted by Saskatchewan Research Council). ....... 94

Figure 4.14: Grouped carbon number distributions of original crude oil and remaining

crude oil of cyclic CO2 injection tests performed at Pop = 6.55 MPa and 9.31

MPa. ............................................................................................................. 95

Figure 4.15: (a): Ultimate oil recovery factor, (b): 1st stage recovery factor, and (c): 2

nd

stage recovery factor of all cyclic CO2 injection tests performed at various

operating conditions. .................................................................................... 98

Figure 4.16: (a): Total producing GOR, and (b): Final GUF of all cyclic CO2 injection

tests performed at various operating conditions. ......................................... 99

xv

Figure 4.17: (a): Asphaltene content of 1st and 2

nd stage CO2-produced oil, and (b): Oil

effective permeability damage of all cyclic CO2 injection tests performed at

various operating conditions. ..................................................................... 101

Figure 4.18: Cumulative oil recovery factor, producing GOR, and producing WOR

during secondary waterflooding (i.e., conducted at Pop = 3.45 MPa) and

tertiary miscible cyclic CO2 injection (Pop = 9.31 MPa) tests. .................. 103

Figure 4.19: Difference between (a): the cumulative injected CO2 and cumulative

produced CO2 as well as (b): the ratios of produced CO2 to injected CO2 and

stored CO2 to injected CO2 in each cycle for immiscible cyclic CO2

injection test conducted at Pop = 5.35 MPa. ............................................... 105



stored CO2 to injected CO2 in each cycle for immiscible cyclic CO2




stored CO2 to injected CO2 in each cycle for near-miscible cyclic CO2




stored CO2 to injected CO2 in each cycle for miscible cyclic CO2 injection

test conducted at Pop = 9.31 MPa. .............................................................. 108

xvi



stored CO2 to injected CO2 in each cycle for miscible cyclic CO2 injection

test conducted at Pop = 10.34 MPa. ............................................................ 109

Figure 4.24: Retention factor for all cyclic CO2 injection tests performed at different

operating pressures in the range of immiscible to miscible conditions. .... 111

Figure 4.25: Ratios of cumulative produced CO2 to the cumulative injected CO2 and

cumulative stored CO2 to cumulative injected CO2 for cyclic CO2 injection

tests performed at different operating pressures in the range of immiscible to

miscible conditions. ................................................................................... 112

Figure 4.26: Ultimate oil recovery factor and the ratio of cumulative stored CO2 to

cumulative injected CO2 for cyclic injection tests performed at different

operating pressures in the range of immiscible to miscible conditions. .... 114

Figure 5.1: Three different configurations of fractured media. (a): a single horizontal

fracture at the centre of cross section; (b): a single vertical fracture at the

middle of the length; (c): a single horizontal and a single vertical fracture

(combination of the two previous configurations). .................................... 118

Figure 5.2: Measured cumulative oil recovery factor of immiscible cyclic CO2 injection

tests conducted at operating pressure of Pop = 6.55 MPa and in fractured

porous medium with different fracture configuration vs. cycle number. .. 124



xvii

porous medium with different fracture configuration vs. pore volume of

injected CO2. .............................................................................................. 125

Figure 5.4: Comparison between measured cumulative oil recovery factor of immiscible

cyclic CO2 injection tests conducted at operating pressure of Pop = 6.55 MPa

and in non-fractured and fractured porous media. ..................................... 126

Figure 5.5: Measured stage oil recovery factors of immiscible cyclic CO2 injection tests

conducted at operating pressure of Pop = 6.55 MPa and in non-fractured and

fractured porous media. ............................................................................. 128

Figure 5.6: CO2 diffusion process of cyclic CO2 injection test inside the fractured porous

medium during the first and second cycles. ............................................... 129

Figure 5.7: Measured cumulative oil recovery factor of miscible cyclic CO2 injection


porous medium with different fracture configuration vs. cycle number. .. 131



porous medium with different fracture configuration vs. pore volume of

injected CO2. .............................................................................................. 132

Figure 5.9: Comparison between measured cumulative oil recovery factor of miscible

cyclic CO2 injection tests conducted at operating pressure of Pop = 9.31 MPa

and in non-fractured and fractured porous media. ..................................... 133

Figure 5.10: Measured stage oil recovery factors of miscible cyclic CO2 injection tests

conducted at operating pressure of Pop = 9.31 MPa and in non-fractured and


xviii

Figure 5.11: Ultimate oil recovery factor of immiscible (Pop = 6.55 MPa) and miscible

(Pop = 9.31 MPa) cyclic CO2 injection tests conducted in non-fractured and


Figure 5.12: Total producing GOR of immiscible (Pop = 6.55 MPa) and miscible (Pop =

9.31 MPa) cyclic CO2 injection tests conducted in non-fractured and


Figure 5.13: Final producing GUF of immiscible (Pop = 6.55 MPa) and miscible (Pop =

9.31 MPa) cyclic CO2 injection tests conducted in non-fractured and


Figure 6.1: Comparison between the experimental and simulated values of (a): crude oil

density, and (b): crude oil viscosity after the regression. .......................... 145

Figure 6.2: (a): Comparison of simulated saturation pressures with experimental ones at T

= 30 °C before and after the regression, and (b): Error analysis of simulated

saturation pressures compared to the experimental ones before and after the

regression. .................................................................................................. 146

Figure 6.3: (a): Comparison of simulated oil swelling factors with experimental ones at T

= 30 °C before and after the regression, and (b): Error analysis of simulated

oil swelling factors compared to the experimental ones before and after the

regression. .................................................................................................. 147

Figure 6.4: (a): 3-D view and (b): 2-D view (i.e., x-y direction) of proposed physical

model for lab-scale simulation of cyclic CO2 injection tests conducted in

non-fractured porous medium (The injector and producer were located and

perforated in a single location). ................................................................. 151

xix

Figure 6.5: (a): 3-D view and (b): 2-D view (i.e., x-z direction) of proposed physical

model for lab-scale simulation of cyclic CO2 injection tests conducted in

fractured porous medium, specifically fractured system (a) with one

horizontal fracture (The injector and producer were located and perforated

in a single location). ................................................................................... 153

Figure 6.6: Tuned water–oil and liquid–gas relative permeability curves used to history

match the experimental recovery factors of cyclic CO2 injection tests. .... 155

Figure 6.7: (a): Comparison of simulated oil recovery factors with experimental ones vs.

cycle number, and (b): the difference between experimental and simulated

cumulative oil recovery factor after completion of each cycle, for cyclic CO2

injection test at immiscible condition in non-fractured porous medium, Pop =

5.38 MPa (i.e., Test # 2)............................................................................. 159




injection test at near-miscible condition in non-fractured porous medium,

Pop = 8.27 MPa (i.e., Test # 9). .................................................................. 160




injection test at miscible condition in non-fractured porous medium, Pop =

10.34 MPa (i.e., Test # 16)......................................................................... 161

xx



cumulative oil recovery factor after completion of each cycle for cyclic CO2

injection test at immiscible condition in fractured porous medium, Pop =

6.55 MPa (i.e., Test # 21)........................................................................... 163



cumulative oil recovery factor after completion of each cycle for cyclic CO2

injection test at immiscible condition in fractured porous medium, Pop =

9.31 MPa (i.e., Test # 24)........................................................................... 164

Figure 6.12: Simulated cumulative oil recovery factor of immiscible cyclic CO2 injection

process (i.e., Pop = 6.55 MPa) vs. cycle number in a single horizontal

fractured medium at various fracture widths. ............................................ 167

Figure 6.13: Simulated cumulative oil recovery factor of miscible cyclic CO2 injection

process (i.e., Pop = 9.31 MPa) vs. cycle number in a single horizontal

fractured medium at various fracture widths. ............................................ 168

Figure 6.14: Effect of the fracture width on the ultimate oil recovery factor of the

immiscible and miscible cyclic CO2 injection processes. .......................... 169


process (i.e., Pop = 6.55 MPa) vs. cycle number in a fractured medium with

different number of fractures. .................................................................... 171

xxi


process (i.e., Pop = 9.31 MPa) vs. cycle number in a fractured medium with

different number of fractures. .................................................................... 172

Figure 6.17: Effect of the number of fractures on the ultimate oil recovery factor of

immiscible and miscible cyclic CO2 injection process. ............................. 173

Figure B.1: Cumulative and stage recovery factors vs. (a): cycle number and (b): pore

volume of injected CO2 for cyclic CO2 injection tests performed at Pop =

5.38 MPa. ................................................................................................... 207

Figure B.2: Cumulative producing GOR and GUF vs. (a): cycle number and (b): pore


5.38 MPa. ................................................................................................... 208

Figure B.3: (a): Ultimate, 1st, and 2

nd stage recovery factors, and (b): asphaltene content

of CO2-produced oil, and oil effective permeability damage for cyclic CO2

injection tests performed at Pop = 5.38 MPa. ............................................. 209



6.55 MPa. ................................................................................................... 210



6.55 MPa. ................................................................................................... 211





xxii



8.27 MPa. ................................................................................................... 213



8.27 MPa. ................................................................................................... 214







9.31 MPa. ................................................................................................... 216



9.31 MPa. ................................................................................................... 217







10.34 MPa. ................................................................................................. 219

xxiii



10.34 MPa. ................................................................................................. 220




injection tests performed at Pop = 10.34 MPa. ........................................... 221

xxiv

NOMENCLATURE

Symbols

Cp Pseudo-component

DFo Effective oil permeability damage

IFTeq Equilibrium IFT (mJ/m2)

k Absolute permeability (mD)

km Matrix permeability

kmf Matrix-fracture permeability

koi Initial effective oil permeability (mD)

kof Final effective oil permeability (mD)

krw Water relative permeability

krg Gas relative permeability in liquid–gas system

kro Oil relative permeability

krog Oil relative permeability in liquid–gas system

MW Molecular weight (gr/mol)

m Mass (gr)

n Number of fracture

P Pressure (MPa)

Patm Atmospheric pressure

Pb Bubble point pressure (MPa)

Pc Critical pressure (MPa)

Peq Equilibrium pressure (MPa)

Pext Extraction pressure (MPa)

Pop Operating pressure (MPa)

xxv

qw-inj Water injection rate (cm3/min)

qo-inj Oil injection rate (cm3/min)

R Universal gas constant (J/mol.K)

Sl Liquid saturation

Soi Initial oil saturation

Swc Connate water saturation

T Temperature (°C, K)

Tc Critical temperature (K)

Texp Experimental temperature (°C)

Tinj Injection time of CO2 (min)

TR Reservoir temperature (°C)

Tsoak Soaking period (hr)

V Volume (cm3)

vM Molar volume (cm3/mol)

xINT Intermediate components

xVOL Volatile components

Wasph Asphaltene content (wt%)

w Fracture width

Z Gas compressibility factor

Greeks

ρoil Crude oil density (gr/cm3)

μoil Crude oil viscosity (mPa.s)

χCO2 CO2 solubility in crude oil (wt%)

χ'CO2 CO2 solubility in brine (mol/kg)

xxvi

Porosity

δCO2 Binary interaction coefficient of hydrocarbon components with CO2

ω Acentric factor

Abbreviations

ADSA Axisymmetric Drop Shape Analysis

AE Average Error

CMG Computer Modeling Group

EOR Enhanced Oil Recovery

FCM First Contact Miscibility

GHG Greenhouse Gas

GOR Gas Oil Ratio

GUF Gas Utilization Factor

IFT Interfacial Tension

MCM Multi-contact Miscibility

MEOR Microbial Enhanced Oil Recovery

MMP Minimum Miscibility Pressure

OOIP Original Oil in-Place

RF Recovery Factor

SF Oil swelling Factor

SG Specific gravity

VIT Vanishing Interfacial Tension

WAG Water Alternating Gas

1

CHAPTER ONE

INTRODUCTION

1.1. Production Phases from a Reservoir

Production of hydrocarbons from an oil reservoir is commonly recognized to

occur in three production phases including primary, secondary, and tertiary phases of

production (Ahmed, 2006).

Primary Phase of Production

The first producing phase of a reservoir is the primary production in which the

natural energy sources of the reservoir are used to transport hydrocarbons towards and

out of the production wells. The natural energy sources of the reservoir are also known as

drive mechanisms. Rock and fluid expansion, solution gas drive, gas cap drive, water

drive, gravity drainage, and combination or mixed drive are the main drive mechanisms

acting in oil reservoirs during the primary production phase (Ahmed, 2006). Generally,

the drive mechanism(s) are unknown during the early history of reservoir production and

will be determined through production data (e.g., time, reservoir pressure, volumetric oil

and gas production) analyses. Early and proper determination of reservoir drive

mechanisms can improve and enhance production optimization, reservoir recovery, and

reservoir management in the later life of a reservoir.

2

Secondary Phase of Production

In the secondary production phase, a substance (mainly water or gas) is injected

into the reservoir to improve the oil recovery, if the natural reservoir drive(s) are reduced

to a point where they are no longer effective as a stress causing movement of

hydrocarbons to the production wells. In the case of water injection, water is injected into

the aquifer in order to maintain reservoir pressure or into the oil zone (i.e., waterflooding)

to displace oil toward production wells. The waterflooding process is often efficient

especially in light-to-moderate oil reservoirs and able to produce considerable volumes of

oil, even in some cases greater than that which was produced during the primary phase of

production. Oil–water relative permeability and reservoir rock wettability are the two

important factors affecting the sweep efficiency of waterflooding processes (Hamouda et

al., 2008; Ju et al., 2012). In most reservoirs, 50–70% of reserve remains in the reservoir

after the waterflooding process since it was bypassed by the water that does not mix with

the oil (Green and Willhite, 1998). In addition to waterflooding, gas may be also injected

into the reservoir in the second phase of production. In such scenarios, gas is injected into

reservoirs that usually have large gas caps in order to maintain reservoir pressure. In

secondary phases of production, the reservoir fluid and rock properties are almost

unchanged and there is no phase behaviour reaction or interaction between the displacing

and displaced fluids in the reservoir.

Tertiary Phase of Production (Enhanced Oil Recovery)

The oil recovered by both primary and secondary phases of production ranges

from 30–50% of overall reserve depending on the oil and reservoir properties, and large

3

volumes of reservoir oil remain untouched in the pore spaces of reservoir rock. Tertiary

production or enhanced oil recovery (EOR) results principally from the injection of gases

or liquid chemicals and the use of thermal energy (Green and Willhite, 1998). The

injected fluids interact with the reservoir rock/oil system to create favourable conditions

for oil recovery. These interactions might, for example, result in lower interfacial tension

(IFT), oil swelling, hydrocarbon extraction, oil viscosity reduction, wettability

modification, or favourable phase behaviour. EOR processes can be classified into four

wide categories of chemical, thermal, miscible gas, and microbial.

Chemical processes in EOR are characterized by addition of chemicals to water in

order to improve the mobility. Different types of polymer, surfactant, and alkaline are

used in chemical flooding to provide favourable mobility by increasing water viscosity,

decreasing the water relative permeability, increasing oil relative permeability,

decreasing the oil–water interfacial tension, and decreasing residual oil saturation (Hou,

2005; Carrero et al., 2007).

Thermal processes provide a driving force and add energy (i.e., heat) to the

reservoir to reduce the viscosity of heavy oils and vapourize the lighter oils, leading to

the improvement of their mobility. Thermal methods include hot water injection, steam

injection, cyclic steam injection, in-situ combustion, and microwave heating downhole

(Gates et al., 2007; Alikhalov and Dindoruk, 2011).

In miscible gas injection scenarios, gas (e.g., CO2, N2, hydrocarbon gases) is

injected into the reservoir at the miscible condition. A process is called miscible gas

injection if the gas is injected into the reservoir at pressures greater than the minimum

4

miscibility pressure (MMP) between the oil and injected gas; otherwise, the process is

immiscible gas injection. When the gas is injected under miscible conditions, the

interfacial tension between the gas and reservoir fluid approaches zero, which results in

high oil recovery (Wang and Gu, 2011). Due to the high mobility of the gas, which

causes early breakthrough and fingering, miscible water alternating gas (WAG) is

proposed in order to enhance the sweep efficiency. In WAG processes, water and gas

slugs are alternately injected into the reservoir so that the mobility of the gas is controlled

by the water and a more piston-like displacement with higher efficiency is produced

(Christensen et al., 2001; Ghafoori et al., 2012).

The microbial enhanced oil recovery technique (MEOR) involves the injection of

selected micro-organisms into the reservoir and the subsequent stimulation and

transportation of their in-situ growth products in order that their presence will aid in

further production of residual oil left in the reservoir (Soudmand-asli et al., 2007;

Armstrong and Wildenschild, 2012).

1.2. CO2 Enhanced Oil Recovery (CO2-EOR)

Enhanced oil recovery using CO2 (CO2-EOR) is a hydrocarbon recovery process

that involves the injection of CO2 to flood mature reservoirs (i.e., reservoirs that have

been depleted and waterflooded in primary and secondary production stages) and produce

petroleum substances that would otherwise remain unrecoverable. Several field-scale

CO2-EOR techniques have been employed in different oil fields since the 1960s. The

5

results revealed that 6.7–18.9% of original oil in-place (OOIP) can be recovered by CO2-

EOR processes (Mohammed-Singh and Singhal, 2005; Ferguson et al., 2009).

As an injected phase, CO2 can be injected into the oil zone through various

schemes including immiscible and miscible continuous CO2 injection, cyclic CO2

injection, CO2–flue gas mixture injection, water-alternating-CO2 injection, carbonated

water injection, and CO2-VAPEX, etc. Parameters such as the thermodynamic conditions

of the reservoir (e.g., reservoir pressure and temperature), type of reservoir oil (e.g., light,

intermediate, or heavy crude oils), petrophysical and geo-mechanical properties of the

reservoir rock, rock–fluid properties, and the extension of the oil zone affect the

performance of CO2-EOR processes (Mohammed-Singh et al., 2006; Smalley et al.,

2007; Aladasani et al., 2012; Mosavat and Torabi, 2014).

In addition to the increase in oil production in CO2-EOR processes, such

processes have provided opportunities for CO2 sequestration and storage projects. CO2

disposal in candidate oil reservoirs through EOR operations is one of the several ways to

constrain greenhouse gas (GHG) emissions from entering the atmosphere (Klara and

Byrer, 2003; Gaspar Ravagnani et al., 2009).

1.3. Immiscible and Miscible CO2 Injections

Miscible CO2 displacement processes have been developed as a successful

technique for enhanced oil recovery purposes in light and intermediate oil reservoirs.

Generally, the crude oil and CO2 are immiscible if there is an interface at their contact

area. Under specific conditions (i.e., miscibility conditions), the interface between the

http://www.sciencedirect.com/science/article/pii/S0920410509000072

6

crude oil and CO2 will be removed and they become miscible. The minimum miscibility

pressure (MMP) of a crude oil–CO2 system at a specified temperature is defined as the

minimum pressure under which CO2 can achieve miscibility with the crude oil (Dong et

al., 2001). In the petroleum industry, the MMP is commonly categorized into first-contact

miscibility (FCM) and multi-contact miscibility (MCM) pressures. In FCM conditions,

the CO2 is miscible with crude oil mixed in any proportions (Holm and Josendal, 1974;

Holm, 1986). However, in practice, it is difficult to achieve FCM in crude oil–CO2

systems, especially at high temperatures. Therefore, the term MCM or dynamic

miscibility is more commonly used for multi-component systems wherein miscibility

between the CO2 and some of the lighter components of crude oil starts earlier than the

others at certain pressures and temperatures.

If the reservoir pressure is lower than the MMP between the crude oil and CO2,

the CO2 injection is classified as an immiscible solvent injection. Otherwise, the CO2

injection is considered to be a miscible displacement. Since, under miscible crude oil–

CO2 conditions, interfacial tension (IFT) and capillary pressure (Pc) tend to be zero or

negligible, the residual oil saturation reduces to a low value in miscible CO2 injection

(Holm, 1986; Nobakht et al., 2008).

1.4. Cyclic CO2 Injection

Cyclic CO2 injection, which is also known as a CO2 huff-and-puff process, has

been investigated through experimental and simulation studies as well as field tests as an

EOR technique for three decades. Cyclic CO2 injection was initially proposed as an

7

alternative to cyclic steam stimulation for heavy oil reservoirs. However, it was found

that the cyclic CO2 injection process has wider applications in light oil reservoirs

(Thomas and Monger, 1990). In this technique, after the injection of CO2 into the

reservoir, the well is shut in for a pre-determined period of time (i.e., soaking period),

depending on the reservoir conditions (e.g., pressure, temperature, reservoir rock and

fluid properties). Then, the oil production is initiated by converting the injection well to

a production well. The injected CO2 has the ability to change the reservoir rock and fluid

properties in terms of rock wettability and relative mobility, leading to enhance the oil

recovery.

Several operating parameters including pressure, soaking period, injection time

(i.e., solvent slug size), and number of cycles influence the performance of cyclic CO2

injection. In addition, the types and characteristics of reservoir rock (e.g., conventional or

fractured rock) and fluids also play an important role in this regard. Although some

studies have been conducted on cyclic CO2 injection processes, there remains a lack of

experimental data to illustrate the impact of the aforementioned parameters on the

recovery performance of this technique.

1.5. Fractured Reservoirs

Fractured reservoirs make up a large and increasing percentage of the world’s

hydrocarbon resources. Characterization and forecasting of the behaviour of fractured

reservoirs are one of the current most crucial and challenging issues being investigated in

the oil and gas industry mainly due to the presence of both matrix and fracture in the

8

rock. Fractured porous media are composed of a large number of high storage capacity

disconnected matrix blocks embedded in high flow capacity connected fracture systems.

Although matrix blocks contain almost all of the original oil in-place, they exhibit very

low flow capacity compared to fractures. In this case, the overall fluid flow in the

reservoir strongly depends on the flow properties of the fracture network, with the

isolated matrix blocks acting as the hydrocarbon storage. The interaction between matrix

and fracture media make the study of such reservoirs more complicated than that of

conventional reservoirs (Nelson, 2001; Behbahani et al., 2006; Qasem et al., 2008 and

Ferno, 2012).

Two types of porosities can exist in a fracture reservoir rock. These are termed

primary porosity and secondary porosity (Athyl, 1930; Warren and Root, 1963 and

Dullien, 1992). Primary porosity is described as the porosity of the rock that formed at

the time of its deposition. Secondary porosity develops after deposition of the rock and/or

dolomitization process, and includes vugular spaces in carbonate rocks created by the

chemical process of leaching or fracture spaces formed in fractured reservoirs. Fractures

are usually caused by brittle failure induced by geological features such as folding,

faulting, weathering, and release of lithostatic (overburden) pressure (Van Gulf-Racht,

1982).

Warren and Root (1963) developed an idealized model to mathematically

characterize the rock and fluid behaviour in the fracture reservoirs. They employed a

sugar-cube type matrix-fracture system whereby the fractured porous media is simulated

by rectangular parallelepiped matrix block embedded within a continuous uniform

orthogonal fracture system of one, two, or three dimensions as shown in Figure 1.

9

Meanwhile, matrix blocks are assumed to be homogeneous and isotropic and specified to

contact each other only through the fracture network without the capillary continuity that

might exist between blocks.

Accordingly, they presented an analytical solution for single phase unsteady state

flow in radial geometry, which was designed primarily for application in well test

analysis.

Fractured reservoirs may be divided into different categories characterized by the

relationship and interaction between matrix and fracture properties such as permeability

and porosity. Allen and Sun (2003) performed a comprehensive study on the fractured

reservoirs in the United States. They defined four categories of fractured reservoirs, based

on the ratio between permeability and porosity, as follows:

Type I: little-to-no porosity and permeability in the matrix. The interconnected

fracture network constitutes the hydrocarbon storage and controls the fluid flow to the

producing well.

Type II: low matrix porosity and permeability. Some of the hydrocarbons are

stored in the matrix. Fractures control the fluid flow, and fracture intensity and

distribution dictates production.

Type III: high matrix porosity and low matrix permeability. The majority of the

hydrocarbons are stored in the matrix. The matrix provides storage capacity, and the

fracture network transports hydrocarbons to producing wells.

10

Figure 1.1: Idealization of fracture porous media by Warren and Root (1963).

11

Type IV: high matrix porosity and permeability. The effects of the fracture

network are less significant on fluid flow. In this category, reservoir fractures enhance

permeability instead of dictating fluid flow.

Production mechanisms from the fractured reservoirs are quite different from

those in conventional reservoirs. The reason is mainly attributed to the presence of both

matrix and fracture together and the interaction between them that aggravate reservoir

heterogeneity. The presence of fractures considerably influences the flow of fluids in a

reservoir because of the large contrast in the transmissibility between the fracture and the

matrix. The high permeability of fracture leads to a higher production rate at the initial

stages of production from the fractured reservoirs. However, a considerable amount of oil

is placed in the matrix and must be produced from it, and because the permeability of the

matrix is much lower, the production rate will decline at the later stages of production.

Depending on the structure and type of fractured reservoir, a variety of recovery

mechanisms contributes in the recovery of the oil (Allen and Sun, 2003). Effective

recovery mechanisms are imbibition for water-wet carbonates (Hamon, 2004) and gas-oil

gravity drainage for mixed to oil-wet reservoirs (O’Neill, 1988 and saidi, 1996). Solution

gas drive in fractured reservoirs usually does not lead to significant oil recovery if wells

are completed at the crest of the structure. The reason for this is that as soon as the

critical gas saturation is reached, gas becomes mobile, migrates to the top of the structure,

and is produced, resulting in fast pressure depletion and low recovery factor accordingly

(Kortekaas and Van Poelgeest, 1991 and Scherpenisse et al., 1994). However, if the

liquid mobility increases compared with the gas mobility, higher recovery factors can be

expected (Firoozabadi and Aronson, 1999).

12

1.6. Scope and objectives of the research

Although several studies have been conducted on the performance of cyclic CO2

injection process, there still exists several issued that need to be addressed. This study is

aimed at disclosing the effects of various parameters on the efficiency of the proposed

technique. Additionally, the effective mechanisms contributing to the oil recovery during

the cyclic CO2 injection are experimentally studied. Moreover, the presence of the

fracture(s) and particularly its orientation on the effectiveness of cyclic CO2 injection

method are examined. The main objective of the proposed study is to investigate the

potential of the cyclic CO2 injection process in light oil systems for the purpose of

enhanced oil recovery. A series of cyclic CO2 injection tests was designed and carried out

in the core system as a porous medium under various operating conditions. The following

objectives are investigated in this study:

Laboratory PVT analyses are performed on the crude oil, crude oil–CO2 and

brine–CO2 systems through compositional analysis of original light oil sample

and measurement of oil viscosity at different temperatures, CO2 solubility in

crude oil, oil swelling factor, equilibrium IFT of crude oil–CO2 system, the MMP

of CO2 with original sample crude oil, and CO2 solubility in brine.

Various secondary cyclic CO2 injection tests are implemented under immiscible,

near-miscible, and miscible conditions to determine the effects of the miscibility

condition on the oil recovery of the cyclic CO2 injection process.

Effects of different operating parameters on the performance of cyclic CO2

injection, including operating pressure (Pop), CO2 injection time (Tinj), soaking

13

period (Tsoak), connate water saturation (Swc), and CO2/propane mixture as an

injected solvent, are studied.

The amount of precipitated asphaltene (Wasph), as well as the oil effective

permeability damage (DFo) due to the CO2 injection, are experimentally

determined.

Recovery mechanisms contributing to the cyclic CO2 injection process in a light

oil system under immiscible and miscible conditions are investigated.

The performance of the cyclic CO2 injection process as a strategy to store the CO2

inside the pore spaces of the rock as a mitigation technique to reduce greenhouse

gas emissions is examined.

The effect of the presence of fractures in the porous medium on the oil recovery

performance of immiscible and miscible cyclic CO2 injection processes is

investigated.

The numerical simulation of phase behaviour together with history matching of

the immiscible and miscible cyclic CO2 injection processes in non-fractured and

fractured porous media are conducted.

A parametric study on the impact of fracture properties including the fracture

orientation (i.e., vertical and horizontal), fracture width, and the number of

fracture(s) on the recovery performance of the cyclic CO2 injection process is

conducted.

14

1.7. Organization of the Thesis

The study is presented in seven chapters. Chapter 1 introduces a brief description

of production phases from a reservoir, CO2-EOR processes, immiscible and miscible

injection, cyclic CO2 injection, fractured reservoirs, as well as the proposed research

topic and its main objectives. Chapter 2 presents a literature review on the cyclic CO2

injection process and recovery mechanisms contributing to the CO2-EOR methods. In

Chapter 3, descriptions of the original light crude oil sample used in the cyclic injection

tests together with a detailed experimental PVT study of crude oil–CO2 and brine–CO2

binary systems are provided. The PVT study includes measurements of CO2 solubility in

crude oil and sample brine, oil swelling factor, dynamic and equilibrium interfacial

tension, and determination of minimum miscibility pressure between CO2 and crude oil.

The details of the experimental procedure employed for cyclic CO2 injection tests and a

comprehensive analyses and discussion on the experimental results of injection tests in a

non-fractured porous medium are described in Chapter 4. In this chapter, the effect of

several operating parameters including operating pressure, CO2 injection time, soaking

period, and connate water saturation on the performance of cyclic CO2 injection process

are investigated. The asphaltene precipitation and permeability reduction of the porous

medium were also experimentally determined during injection tests. Chapter 5 provides

the experimental results of immiscible and miscible cyclic CO2 injection tests conducted

in a fractured porous medium with different fracture configurations. The role of fracture

orientation on the recovery performance of cyclic CO2 injection is studied. Chapter 6

summarizes the numerical simulation procedure and history matching of the experimental

results of immiscible and miscible cyclic CO2 injection tests conducted in non-fractured

15

and fractured porous media. Finally, the major conclusions of this study as well as the

proposed recommendations for future works on the topic are presented in Chapter 7.

16

CHAPTER TWO

LITERATURE REVIEW

2.1. Cyclic CO2 Injection Process (CO2 Huff-and-Puff)

Cyclic gas/solvent injection, which is also known as the huff-and-puff technique,

has been investigated through both laboratory and field tests as an efficient enhanced oil

recovery (EOR) technique. Basically, in the huff-and-puff processes, a slug of gas or

solvent is injected into the reservoir either in miscible or immiscible conditions (huff

cycle). After injection, the well is shut-in for a “soak” period to allow for gas/solvent

interaction with the formation oil and to reach equilibrium, and, then, the production is

resumed through the same well (puff cycle). Mechanisms contributing to increased oil

recovery in cyclic solvent injection processes include oil viscosity reduction, oil swelling

due to dissolution of gas in crude oil, solution gas drive aided by gravity drainage,

vapourization of lighter components of oil, interfacial tension reduction, and relative

permeability effects (Mohammed-Singh et al., 2006; Shi et al., 2008).

Among all cyclic injection scenarios, the cyclic CO2 injection (i.e., CO2 huff-and-

puff) process has proved to have great potential to recover oil from various conventional

oil reservoirs. Although this technique was initially developed as an alternative to cyclic

steam injection in heavy oil reservoirs, it has shown great potential for enhancing the oil

recovery in light oil reservoirs (Thomas and Monger, 1990).

17

Several studies on cyclic CO2 injection in depleted shallow light oil reservoirs

were implemented through conducting numerical simulations and some experiments to

review and quantify the influence of various parameters that could be responsible for the

production improvement (Miller, 1990; Miller et al., 1994; Bardon et al., 1994). It has

been reported that oil swelling and viscosity reduction effects combining with changes in

gas/oil relative permeabilities resulted in an increase of oil recovery obtained by CO2

huff-and-puff process.

Towler and Wagle (1992) investigated the cyclic CO2 stimulation of low pressure

gas-solution-drive wells using a black-oil simulator. They concluded that the relative

permeability hysteresis and reservoir pressure increase are the main mechanisms

contributing to this process.

Wolcott et al. (1995) conducted laboratory tests to investigate the effect of some

parameters including gravity segregation, remaining oil saturation, reservoir dip, presence

of gas cap, and the use of a drive gas on the cyclic CO2 injection process. According to

the obtained results, they concluded that cyclic CO2 injection benefited from the presence

of gas cap, gravity segregation, and higher remaining oil saturation. Gravity override

caused better contact of CO2 with the oil through facilitating deeper penetration of the

injected gas. They also found that the reservoir dip and the injection site point (either top

or bottom end) has a significant effect on the performance of the cyclic CO2 process.

Higher reservoir inclination and down-dip injection could improve the efficiency of the

process. In addition, implementation of a drive gas like nitrogen to chase the CO2 could

potentially increase oil recovery by causing deeper penetration of CO2 as cited by other

18

investigations of laboratory experiments and field test results (Monger and Coma, 1988;

Thomas and Monger-McClure, 1991).

The effect of the volume of CO2 or slug size on oil recovery has been investigated

in the literature. A higher volume of CO2 injected into the reservoir could recover more

oil accordingly. Meanwhile, CO2 fingering can occur, most likely with higher injection

rates. As a result, the mixing zone of oil and injected CO2 will be created with reduced oil

viscosity and larger oil saturation due to swelling caused by dissolution of CO2 in the oil

(Mohammed-Singh et al., 2006; Thomas and Monger-McClure, 1991; Haskin and

Alston, 1989; Monger and Coma, 1988; Palmer et al., 1986; Brock and Bryan, 1989).

A parametric study on the reservoir rock characteristics and oil in-place properties

showed that successful cyclic CO2 injection projects were implemented in reservoirs with

crude oil gravities ranging from 11–38 API and in-situ viscosities from 0.5–3000 cP,

porosities between 11–32%, depths from 1150–12,870 feet, thicknesses from 6–220 feet,

permeabilities ranging from 10–2500 mD, and soaking time intervals of 2–4 weeks

(Mohammed-Singh et al., 2006).

Although continuous CO2 injection has been considered not to be the most

effective technique to enhance oil recovery in the case of naturally fractured reservoirs,

mainly due to the fingering effects, the efficiency of cyclic CO2 gravity drainage in

fractured porous media has been investigated by some researchers. Li et al. (2000)

performed several experiments to evaluate the CO2 gravity drainage in the cyclic

injection process on artificially fractured cores at reservoir conditions after water

imbibition. The results demonstrated that CO2 gravity drainage could significantly

19

increase the oil recovery factor after waterflooding. They also concluded that cyclic CO2

injection improves oil recovery during CO2 gravity drainage.

Darvish et al. (2006) investigated tertiary cyclic CO2 injection into a fractured

core system. Their results showed that CO2 injection could increase the oil recovery

substantially after waterflooding. They reported that oil swelling and gravity drainage are

the two main mechanisms of the oil recovery in fractured porous media.

Asghari and Torabi (2007), Torabi and Asghari (2010) and Torabi et al. (2012)

performed several experiments as well as numerical simulation to determine the effect of

some parameters including operating pressure and matrix permeability on the

performance of the CO2 huff-and-puff process in a matrix-fracture experimental model at

both immiscible and miscible conditions. They concluded that higher matrix permeability

assists the efficiency of the cyclic CO2 injection process in immiscible conditions, but it

was not an effective parameter in the miscible case. Moreover, huff-and-puff recovery

processes with CO2 at near-miscible and miscible conditions maximize the recovery

factor.

Implementation of CO2 mixture with other gases (e.g., methane, nitrogen, rich

gas, and flue gas) in cyclic injection processes has also been reported in the literature.

Haines and Monger (1990) performed experimental and numerical simulation studies on

cyclic natural gas injection (i.e., CH4, N2 and CO2) for the enhanced oil recovery of light

oil from waterflooded fields. They reported that approximately 40% of waterflooded

residual oil was recovered by two production cycles under immiscible conditions.

20

Shayegi et al. (1996) performed a series of experiments to investigate the cyclic

stimulation using gas mixtures. They employed different concentrations of CO2/N2 and

CO2/CH4 mixtures in a cyclic injection process and concluded that the mixture of CO2

with other gases can improve the oil recovery obtained by huff-and-puff processes.

Zhang et al. (2004) conducted an experimental study to investigate the feasibility

of using CO2 and flue gas in cyclic gas injection. The results showed that the recovery of

cyclic CO2 injection improves with increasing residual oil saturation. Moreover, enriched

cyclic flue gas injection performed as well or better than pure CO2 huff-and-puff cyclic

injection.

In addition, some field operations as well as experimental studies have also been

conducted to investigate the performance of cyclic CO2/CO2-mixture/solvent injection on

heavy oil systems. Laboratory results and field experiments indicated that cyclic CO2 and

fuel gas injections could improve recovery of the asphaltic and heavy crude oils (Olenic

et al., 1992; Zhang et al., 2000).

Shelton and Morris (1973) studied cyclic rich gas injection to enhance production

rates in viscous-oil reservoirs. The rich gas consisted of methane enriched with propane.

They reported that a cyclic injection process using rich gas can increase oil recovery rates

by reducing oil viscosity and increasing reservoir energy.

Bardon et al. (1986) conducted a field study on well stimulation by CO2 in the

heavy oil field of Camurlu in Turkey and demonstrated apparent productivity increases in

cyclic CO2 injection processes, especially in the first and second cycles. Additionally,

21

they reported that poor injectivity of CO2 is one of the practical problems that needs to be

solved.

Shi et al. (2008) performed an experimental study on CO2 huff-and-puff in a

heavy oil sample and reported that cyclic CO2 injection is a viable non-thermal method

that has potential for enhanced oil recovery of heavy oil after primary production. The

recovery with the CO2 huff-and-puff process was increased by 12.9% and 14.3% in their

experiments.

Ivory et al. (2009) carried out numerical and experimental studies on cyclic

injection of a CO2-propane mixture on a heavy oil sample. They concluded that the oil

recovery after primary production and six solvent cycles was 50%, showing the potential

of cyclic solvent injection in heavy oil reservoirs.

Qazvini Firooz and Torabi (2012) experimentally investigated the huff-and-puff

method for different solvents of CO2, methane, propane, and butane in a heavy oil system

and reported that solution gas drive, viscosity reduction, extraction of lighter components,

formation of foamy oil, and to a lesser degree, the diffusion process are governing

mechanisms contributing to the oil production.

Yadali Jamaloei et al. (2012) designed an enhanced cyclic solvent process for

heavy oil and bitumen recovery. In this technique, two types of solvents are injected in

the porous medium via cyclic injection schemes but in two separate slugs. In each cycle,

a more volatile solvent is injected into the system first, and, then, the injection is followed

by a definite slug of a more soluble solvent. The results showed that the aforementioned

22

new technique is capable of significantly improving the cyclic injection process

compared to injection of solvent mixtures.

Du et al. (2013) experimentally investigated the post-CHOPS cyclic solvent

injection process using propane for enhanced oil recovery. They reported that the process

significantly increases the oil recovery particularly if the coverage of the wormhole is

appropriately large.

Jia et al. (2013) implemented a new method of pressure pulsing cyclic solvent

injection to enhance the recovery of heavy crude oil. During this technique, the system

pressure is reduced first to induce foamy oil flow and a foamy oil zone. Thereafter, the

system pressure is re-increased, and, then, the production is initiated with a definite

drawdown (i.e., pressure difference between the inlet and outlet of the system). The

results showed that the oil recovery is significantly enhanced during the proposed

technique.

2.2. Recovery Mechanisms in CO2-EOR Processes

Over the past three decades, oil companies have become more interested in using

CO2 as an injection solvent to exploit light-to-medium oil reservoirs. Among all CO2

injection schemes, miscible CO2 injection is a predominant enhanced oil recovery

technique (Desch et al., 1984; Yu et al., 1990; Lindeberg and Holt, 1994; Ghasemzadeh

et al., 2011). The reason is mainly attributed to a more favourable phase behaviour

between the injected CO2 and oil in-place, which yielded improved sweep efficiency and

high oil recovery. Several studies have been conducted to determine the main recovery

23

mechanisms contributing to the CO2-EOR processes whether in immiscible or miscible

conditions (Orr and Taber, 1984; Mohammed-Singh et al., 2006; Shi et al., 2008; Alipour

Tabrizy, 2012; Cao and Gu, 2013). Oil swelling as a result of CO2 dissolution in the oil,

oil viscosity reduction, interfacial tension reduction, and extraction and vapourization of

lighter components by CO2 are the main mechanisms affecting the CO2-EOR processes.

The solubility of CO2 as a result of CO2 diffusion process is the major parameter

that impacts the performance of the CO2 injection process since it results in oil swelling,

oil viscosity reduction, and elimination of interfacial tension. The CO2 solubility is a

function of pressure, temperature, and oil composition. Various methods have been

proposed to calculate the CO2 solubility in the crude oil under specific conditions (Simon

and Graue, 1965; Mehrotra and Svrcek, 1982; Emrea and Sarma, 2006). Generally, the

solubility of CO2 benefits from higher pressure, lower temperature, and lower oil

molecular weight.

Oil swelling as a result of CO2 dissolution plays an important role in the

immiscible CO2 injection schemes (Bath, P. G. H., 1989; Jamaluddin et al., 1991). The

residual oil in the pore spaces expands by the contact with CO2 and becomes mobilized in

the reservoir. Oil swelling can also effectively assist the production from heavy oil

reservoirs and improve the oil recovery (Spivak and Chima, 1984; Li et al., 2011).

Although oil viscosity reduction is one of the CO2 recovery mechanisms, it is not

very important in light oil reservoirs. However, since the high oil viscosity in heavy oil

reservoirs is the major production issue, reduction in oil viscosity due to CO2 dissolution

is considered as the main mechanism associated in heavy oil production. The viscosity of

24

heavy oils significantly decreases even if a small amount of CO2 dissolves in the oil

(Spivak and Chima, 1984; Jha, 1986; Hatzignatiou and Lu, 1994).

Reduction of interfacial tension enhances the oil recovery effectively in both light

and heavy oil reservoirs (Yang and Gu, 2004; Wang and Gu, 2011). Reduction and

elimination of interfacial tension decreases the capillary pressure and increases the

capillary number, which, together, improve the recovery efficiency.

In near-miscible and miscible CO2 injection processes in which the pressure is

near and above MMP, the extraction of lighter components by CO2 is the greatest

governing mechanism. Generally, in most cases, FCM between crude oil and CO2 cannot

be achieved. However, CO2 becomes miscible with the crude oil through two-way

interfacial mass transfer between crude oil and CO2 phases and produces dynamic

miscibility or MCM (Holm and Josendal, 1974; Nobakht et al., 2008). At the specific

pressure below the MMP, which is the so-called “extraction pressure”, the interfacial

tension reduces to a definite amount at which the significant level of mass transfer

between crude oil and CO2 occurs and the extraction and vapourization of lighter

components is initiated.

2.3. Chapter Summary

A detailed survey on the laboratory and numerical simulation studies of cyclic

CO2 injection process together with field application of this technique was conducted.

The cyclic CO2 injection technique seems not to be a promising method to improve the

oil recovery from light oil systems, but also shows a great potential to increase the

25

production from heavy oil formations. It was also revealed that several operating

parameters as well as reservoir characteristics noticeably affect the performance of cyclic

CO2 injection process as a means of enhanced oil recovery. However, it is believed that

there still exists a lack of knowledge on the details of the mechanisms contributing to the

cyclic CO2 injection process and how the operating parameters can have influence on the

recovery performance during the implementation of this technique. The aim of this study

is to address the issues that may arise during the cyclic CO2 injection technique as a

change of different operating parameters.

26

CHAPTER THREE

PHASE BEHAVIOUR STUDY AND PVT CHARACTERIZATION

Phase behaviour study of crude oil, solvent, and crude oil–solvent systems plays a

substantial role in the investigation of any enhanced oil recovery technique. In order to

have a better understanding of the phase behaviour of crude oil–CO2 systems, a detailed

and comprehensive Pressure-Volume-Temperature (PVT) study was conducted through

various experimental approaches. The measured values of PVT properties were then

employed to regress and tune the PVT model of the crude oil/solvent system built using

the WinpropTM

module (ver., 2011) from the Computer Modeling Croup (CMGTM

, ver.,

2011).

3.1. Crude Oil and Brine Properties

The light crude oil sample under study was taken from the Bakken oil field in

southern Saskatchewan, Canada. The density and viscosity of the sample crude oil at a

temperature of T = 21 °C and atmospheric pressure were measured to be ρoil = 802 kg/m3

and μoil = 2.92 mPa.s, respectively. The n-pentane (n-C5) insoluble asphaltene content

was determined using the standard ASTM D2007-03 method and found to be 1.23 wt%.

Detail procedure to measure the asphaltene content using the standard ASTM D2007-03

method is provided in Appendix A. The compositional analysis of the original sample of

crude oil and carbon number distribution is presented in Table 3.1 and depicted in Figure

27

3.1. A DV-II+Viscometer (Can-AM Instruments LTD.) was used to measure crude oil

viscosity at different temperatures. Figure 3.2 presents the measured values of crude oil

density and viscosity at various temperatures.

A synthetic brine with 2 wt% NaCl concentration, density of ρw = 1001 kg/m3,

and μw = viscosity of 0.98 mPa.s at a temperature of T = 21 °C and atmospheric pressure

was used as a representative of reservoir connate water in injection tests.

Carbon dioxide (CO2) with a purity of 99.99%, supplied by Praxair, was used as

the injected solvent in phase behaviour studies and cyclic injection tests.

28

Table 3.1: Compositional analysis of the light crude oil under study at T = 21 °C and

atmospheric pressure (Conducted by Saskatchewan Research Council).

Carbon number Mole % Carbon number Mole % Carbon number(s) Mole %

C1 0 C12's 4.48 C28's 0.44

C2 1.58 C13's 4.02 C29

's 0.33

C3 0.92 C14's 3.32 C30+'s 2.85

i-C4 0 C15's 3.06

n-C4 3.88 C16's 2.37 C1–C6's 22.48

i-C5 2.20 C17's 2.06 C7+'s 77.52

n-C5 4.03 C18's 1.91

C5’s 0.49 C19's 1.51 C1–C14's 78.82

i-C6 3.07 C20's 1.29 C15+’s 21.18

n-C6 2.95 C21's 1.29

C6’s 3.37 C22's 0.76 C1–C29's 97.15

C7's 13.87 C23's 0.87 C30+'s 2.85

C8's 10.46 C24's 0.71

C9's 8.19 C25's 0.66

C10's 6.38 C26's 0.57

C11's 5.61 C27's 0.49

Molecular weight 223 gr/mol

Density at (21 °C & Patm) 802 kg/m3

Viscosity at (21 °C & Patm) 2.92 mPa.s

n-C5 insoluble asphaltene 1.23 wt %

29

Crude oil components

Mole

percen

t

0

2

4

6

8

10

12

14

16

C1

C2

C3

i-C

4

n-C

4

i-C

5

n-C

5C

6's

C7

's

C8

's

C9

's

C1

0's

C1

1's

C1

2's

C1

3's

C1

4's

C1

5's

C1

6's

C1

7's

C1

8's

C1

9's

C2

0's

C2

1's

C2

2's

C2

3's

C2

4's

C2

5's

C2

6's

C2

7's

C2

8's

C2

9's

C3

0+

CO

2

Figure 3.1: Compositional analysis of the original light crude oil sample at atmospheric

pressure and temperature of T = 21 °C (ρoil = 802 kg/m3, μoil = 2.92 mPa.s, MW = 223

gr/mol, and n-C5 insoluble asphaltene content = 1.23 wt%; Conducted by Saskatchewan

Research Council).

30

Figure 3.2: Measured values of crude oil density and viscosity as a change of temperature

at atmospheric pressure.

Temperature (oC)

15 20 25 30 35 40 45 50

Cru

de o

il v

isco

sity

(m

Pa

.s)

2.2

2.4

2.6

2.8

3.0

Cru

de o

il d

en

sity

(k

g/m

3)

785

790

795

800

805

810

Viscosity

Density

31

3.2. CO2 Solubility, Oil Swelling Factor, and Interfacial Tension of Crude Oil–CO2

System

In CO2 injection schemes, it is highly important to perform accurate PVT studies

on the crude oil–CO2 system. In this study, some of the key parameters of mutual

interactions of the crude oil–CO2 system, including CO2 solubility in the crude oil, oil

swelling factor, interfacial tension between crude oil and CO2 phases, and the MMP of

CO2 with the crude oil sample, were determined through several sets of experiments.

3.2.1. CO2 Solubility and Oil Swelling Factor of Crude oil–CO2 System

Solubility of CO2 in the crude oil is a governing parameter affecting the

performance of CO2-EOR processes. Several attempts have been carried out to measure

and model this parameter for various types of crude oil (Simon and Graue, 1965;

Jamaluddin et al., 1991; Costa et al., 2012). The amount of CO2 solubility into the crude

oil directly influences the oil swelling factor, oil viscosity, oil density, and crude oil–CO2

interfacial tension. Therefore, it is necessary to determine this parameter accurately for

the purpose of experimental studies and numerical simulations.

Swelling factor is defined as the ratio of the volume of the saturated oil with gas

at a specific temperature and pressure to the initial volume of crude oil (Danesh, 1998).

Swelling of the oil as a result of dissolution of CO2 into the crude oil is one of the main

mechanisms affecting different CO2 injection schemes, especially in light oil reservoirs

(Yang and Gu, 2006; Shi et al., 2008).

32

Figure 3 depicts the schematic diagram of the experimental apparatus for

determining the CO2 solubility in the crude oil and the resulting oil swelling factor at

temperatures of T = 21 °C and 30 °C. The apparatus mainly consisted of a see-through

windowed high-pressure cell (Jerguson Co.), a magnetic stirrer (Fisher Scientific), and a

high pressure CO2 cylinder. A temperature controller (Love Controls Co.) was also used

to control the experimental temperature and maintain it constant. The cell was charged

with a specific volume of crude oil sample (i.e., Vo,i = 25 cm3). The magnetic stirrer was

used to create a consistent turbulence inside the cell. The produced turbulence

significantly accelerated the CO2 dissolution into the oil by creating convective mass

transfer (Kavousi et al., 2013). Along the process, the pressure inside the see-through

windowed cell was measured and recorded using a digital pressure gauge (Ashcroft Inc.).

Once the visual cell was pressurized with CO2 to a pre-specified pressure (Pi), the

pressure of the cell was allowed to stabilize while CO2 was dissolving into the crude oil.

The test was terminated when the final CO2 pressure (Pf) inside the cell reached a stable

value and no further pressure decay was observed. The final pressure was considered as

the equilibrium pressure (Peq) of the system. Lastly, initial and final CO2 volumes in the

visual cell were determined by taking photos and utilizing image analysis. Throughout

this study, the solubility of CO2 in the oil (χCO2) was defined as the ratio of the total mass

of dissolved CO2 in 100 g of the original crude oil sample and was calculated using the

mass balance equations. The mass of CO2 which is dissolved into the oil phase is equal to

difference between the initial mass of free CO2 and final one in the cell as presented in

(Eq. 3.1):

33

Figure 3.3: Schematic diagram of the experimental set-up used for CO2 solubility and oil

swelling factor measurements at various equilibrium pressures.

CO

2

Cru

de

oil

Tel

edy

ne

ISC

O s

yri

ng

e p

um

p

Fan &

heater

Fan &

heater

Temperature controller

High P & T

Visual cell

Digital

pressure

gauge

pres

Magnetic

stirrer

Data

acquisition

system

Air bath

34

f

fCOf

i

iCOiCO

f

COfCOf

i

COiCOi

fCOiCOdisCO

Z

VP

Z

VP

RT

MW

RTZ

MWVP

RTZ

MWVP

mmm

,,

,,

,,,

222

2222

222

……… (Eq. 3.1)

oiloiloil Vm ……… (Eq. 3.2)

100

100

,,

,

222

2

2

f

fCOf

i

iCOi

oiloil

CO

oil

dissolvedco

CO

Z

VP

Z

VP

RTV

MW

m

m

……… (Eq. 3.3)

The derived equation to calculate the CO2 solubility in the oil at each temperature (i.e.,

Eq. 3.1) is valid and can be applied for equilibrium pressures lower than the extraction

pressure. Because at pressures beyond the extraction pressure of the system, the

composition of the final CO2 phase is not pure and contains extracted hydrocarbon

components as a result of hydrocarbon extraction mechanism.

The swelling factor of the oil due to the dissolution of CO2 at the specific

operating condition was also determined by the ratio of the final volume of the oil to the

initial volume at the start of the experiment. Figure 3.4 shows the details of the technique

to determine the initial and final volumes of both CO2 and oil phases, in which the

volume ratio for each phase is proportional to the height ratio.

i

f

V

VSF

……… (Eq. 3.4)

35

Figure 3.4: Details of the visual technique used to determine the volumes of oil and CO2

phases at each equilibrium pressure in order to calculate the CO2 solubility in crude oil

and resulting oil swelling factor.

io

fo

f

fCOf

i

iCOi

ioo

CO

CO

fo

fCO

oio

oiCO

fo

fCO

io

iocell

io

iCO

io

iCO

toCO

V

VSF

Z

VP

Z

VP

VRT

MW

V

V

hh

hh

h

h

V

VV

V

V

h

h

HhhpressureeachAt

,

,

,,

,

,

,

,

,

,

,

,

,

,

,

,

,

100

:

222

2

222

22

2

Pi = Patm Pf = 6.79MPa

MPa

Pi P

f

H

t

ho,i

Δho

hCO2

,i

36

The experimental results of CO2 solubility in the sample crude oil at temperatures

of T = 21 °C and 30 °C are depicted in Figure 3.5. This figure illustrates that the

solubility of the CO2 increases as the equilibrium pressure of the system increases. The

concentration of dissolved CO2 is proportional to the partial pressure of the CO2. The

CO2 partial pressure controls the number of CO2 molecule collisions in contact with the

surface of the crude oil sample. Since higher partial pressure (i.e., equilibrium pressure of

the system) results in increase of the number of collisions, which occurs in contact with

the surface, more CO2 is dissolved in the crude oil with increased equilibrium pressure. It

can be seen that the CO2 solubility in crude oil reaches its maximum value of χCO2 =

34.27 grCO2/100 groil at a pressure of Peq = 5.95 MPa for T = 21 °C and χCO2 = 31.46

grCO2/100 groil at a pressure of Peq = 6.79 MPa for T = 30 °C, respectively.

37

Equilibrium pressure (MPa)

0 1 2 3 4 5 6 7 8

C

O2 (

gr C

O2/1

00gr

oil)

0

10

20

30

40

CO2

(T = 21 °C)

CO2

(T = 30 °C)

Figure 3.5: Measured CO2 solubility in the crude oil at experimental temperatures of T =

21 °C and 30 °C.

38

Figure 3.6 and Figure 3.7 depict the determined oil swelling factor as a result of

CO2 dissolution in the oil phase at T = 21 °C and 30 °C, respectively. The volume of the

crude oil increases with increased equilibrium pressure mainly due to the higher

solubility of CO2 in the crude oil at higher pressures and, accordingly, the crude oil

swells in the visual cell. At high equilibrium pressures, the CO2 phase changes from gas

to liquid phase. Since liquid-phase CO2 has a greater capacity to extract hydrocarbon

components, especially the lighter ones, from crude oil than if it were in the gaseous

phase (Tsau et al., 2010; Bui et al., 2010), the volume of the crude oil in the visual cell is,

therefore, reduced. As shown in Figures 3.6 and 3.7, the oil swelling factor increases by

increasing the equilibrium pressure and reaches its maximum values at Peq = 5.95 MPa

and 6.79 MPa for T = 21 °C and 30 °C, respectively. The maximum oil swelling factor at

Texp = 21 °C and 30 °C are SF = 1.37 and 1.32, respectively. After this point, the

extraction phenomena dominates the oil swelling process and leads to shrinkage in the

volume of the crude oil in the visual cell and decline in swelling factor, since lighter

hydrocarbon components are extracted by CO2 and vapourized into gaseous phase. The

results of the swelling test indicates that extraction of light crude oil components by CO2

for the crude oil–CO2 system started at a pressure near Pext = 5.95 MPa for T = 21 °C and

Pext = 6.79 MPa for T = 30 °C. It was also found that the extraction pressure of CO2 in a

crude oil–CO2 system is greater at a higher temperature than that at a lower one.

39


0 2 4 6 8 10 12 14

Oil

sw

elli

ng f

act

or

0.0

0.5

1.0

1.5

2.0

Pex

t

= 5

.95 M

Pa

(T =

21 °

C)

oil swelling mechanism hydrocarbon extraction mechanism


system at experimental temperatures of T = 21 °C.

40


0 2 4 6 8 10 12 14

Oil

sw

elli

ng f

act

or

0.0

0.5

1.0

1.5

2.0

Pex

t =

6.7

9 M

Pa

(T =

30

°C

)

oil swelling mechanism hydrocarbon extraction mechanism


system at experimental temperatures of T = 30 °C.

41

3.2.2. Crude oil–CO2 Interfacial Tension Measurement

Interfacial tension (IFT) between an injected phase and reservoir oil in-place

affects the performance of EOR operations significantly. Various studies have suggested

that low IFT between the injected fluid and oil reservoir can improve sweep efficiencies

and reduce residual oil saturation (Khaled et al., 1993; Gu and Yang, 2004). In CO2-

based EOR techniques, at specific thermodynamic conditions (i.e., pressure, temperature,

and composition), the IFT of the crude oil–CO2 mixtures decreases to a sufficiently low

value, which leads to a more favourable displacing process (Khaled et al., 1993).

In this study, the axisymmetric drop shape analysis (ADSA) technique for the

pendant drop case (Cheng et al., 1990) was applied to determine the IFT between the

crude oil and CO2. Figure 3.8 shows a schematic diagram of the experimental set-up used

for calculating the equilibrium IFT of the crude oil–CO2 system at various equilibrium

pressures and a constant temperature of T = 30 °C. First, the see-through windowed high-

pressure IFT cell (Temco Inc.) was heated to the specific experimental temperature of T =

30 °C and then filled with the CO2 at the pre-specified equilibrium pressure. Afterwards,

the crude oil was introduced to the IFT cell through a stainless steel syringe needle

installed at the top of the IFT cell. Once a well-shaped pendant drop was formed at the tip

of the syringe needle, the appropriate sequential digital images of the dynamic pendant

oil drop at different times were acquired. Finally, the ADSA program for a pendant drop

case was executed to determine the equilibrium IFT between the oil and CO2 at each pre-

specified pressure and a temperature of T = 30 °C.

42

Figure 3.8: Schematic diagram of the experimental set-up used for measuring the

equilibrium IFT for the crude oil–CO2 system at various equilibrium pressures.

CO

2

Cru

de

oil

High pressure

IFT Cell

CO2 at T & Peq

Microscopic

camera

Tel

edy

ne

ISC

O s

yri

ng

e p

um

p

Light

source

Vibration-free table

Data

acquisition

system

Temperature

controller

43

Figure 3.9 depicts the calculated dynamic IFT (IFTdyn) values of the crude oil–

CO2 system at various equilibrium pressures and temperature of T = 30 °C. The dynamic

IFT at each equilibrium pressure was reduced from the initial value and reached a stable

value, which is known as equilibrium IFT. Since the concentration of CO2 in the oil

phase increases at higher equilibrium pressures, the dynamic IFT was significantly

reduced. At equilibrium pressures near and above the extraction pressure, it was found

that the reduction of dynamic IFT was very quick. The reason is mainly attributed to the

strong extraction of light hydrocarbon components, which results in the dynamic IFT

being almost unchanged.

Figure 3.10 shows the equilibrium IFT (IFTeq) values of the crude oil–CO2 system

at different equilibrium pressures in the range of Peq = 0.66–14.64 MPa and a temperature

of T = 30 °C. Accordingly, it was found that the equilibrium IFT of the crude oil–CO2

system decreases linearly in two distinct ranges. In Range (I) with a pressure range of Peq

= 0.66–6.41 MPa, the IFTeq of the crude oil–CO2 system reduces linearly mainly due to

the mechanism of CO2 dissolution into the oil phase. In Range (II) with a pressure range

of Peq = 7.35–14.64 MPa, the governing mechanism, which leads to linear IFT reduction

of the crude oil–CO2 system, changes from CO2 dissolution to extraction of lighter

hydrocarbon components by CO2 phase. The calculated equilibrium IFT decreased from

an initial value of IFTeq = 19.41 mJ/m2 at Peq = 0.66 MPa to its minimum value of IFTeq =

2.4 mJ/m2 at the equilibrium pressure of Peq = 14.64 MPa. The intersection of the two

pressure ranges gives the pressure at which the hydrocarbon extraction by CO2 is

initiated, which was found to be Pext = 6.84 MPa.

44

Time (s)

0 100 200 300 400 500 600 700 800 900

Dyn

am

ic i

nte

rfaci

al

ten

sion

(m

J/m

2)

0

5

10

15

20

25P

eq = 1.14 Mpa

Peq

= 2.43 MPa

Peq

= 3.42 MPa

Peq

= 4.86 MPa

Peq

= 5.99 MPa

Peq

= 7.35 MPa

Peq

= 9.05 MPa

Peq

= 11.83 MPa

Figure 3.9: Measured dynamic interfacial tensions (IFTdyn) of the crude oil–CO2 system

at different equilibrium pressures and a temperature of T = 30 °C.

45


0 5 10 15 20

Eq

uil

ibri

um

in

terf

aci

al

ten

sion

(m

J/m

2)

0

2

4

6

8

10

12

14

16

18

20

22Range (I): Solubility mechanism

Range (II): Hydrocarbon extraction mechanism

Range (I)

Range (II)

Pext

= 6.84 MPa

Figure 3.10: Measured equilibrium interfacial tensions (IFTeq) of the crude oil–CO2

system at different equilibrium pressures and a temperature of T = 30 °C.

46

Comparing the results of the IFT measurement test with those obtained from CO2

solubility and oil swelling factor experiments at T = 30 °C reveals that at a pressure range

lower than Peq = 6.9 MPa, the main mechanism contributing to the interaction between

the sample light crude oil and CO2 phases is the CO2 solubility. Beyond this pressure

range (i.e., Peq > 6.9 MPa), extraction of hydrocarbon components of the crude oil by the

CO2 is the dominant mechanism affecting the phase behaviour of the system. The

extraction pressures estimated by oil swelling and crude oil–CO2 IFT curves were found

to be Pext = 6.79 MPa and 6.84 MPa at T = 30 °C, which are in good agreement with each

other.

3.3. Minimum Miscibility Pressure (MMP) of Crude Oil–CO2 System

CO2-based EOR scenarios can be applied into the reservoirs under two distinct

processes of immiscible and miscible CO2 injection. The MMP of the crude oil–CO2

system is the key parameter used in the recognition of CO2 injection processes whether

they are miscible or immiscible. The MMP of CO2 is defined as the minimum pressure

under which CO2 can achieve multi-contact miscibility with the crude oil (Dong et al.,

2001). It has also been proved that the MMP of CO2 for a reservoir oil depends on the

reservoir temperature, oil composition, and the purity of injected CO2 (Dong et al., 1991).

The slim-tube method is the most commonly used technique among the proposed

experimental methods for determining the MMP (Flock and Nouar, 1983; Elsharkawy et

al., 1991). In addition, there are some other experimental methods that are relatively

cheaper and easier to employ, including rising bubble apparatus (RBA) and vanishing

47

interfacial tension (VIT), in order to measure the IFT experimentally (Christiansen and

Kim, 1987; Rao, 1997; Rao and Lee, 2002, Nobakht et al., 2008).

In this study, the MMP of the CO2 with the light sample crude oil was

experimentally determined using VIT technique and swelling/extraction test results.

3.3.1. MMP Determination using VIT Technique

The VIT technique is based on the concept that IFT between a crude oil sample

and CO2 becomes zero when they are miscible with each other. Therefore, the MMP can

be determined by linearly extrapolating the measured equilibrium IFT values versus

equilibrium pressure to zero equilibrium IFT. As shown earlier in Figure 3.9, the

measured IFT of the crude oil–CO2 system decreased linearly in two distinct pressure

ranges of Peq = 0.66–6.84 MPa and Peq = 6.84–14.64 MPa. The equilibrium IFTs in the

two pressure ranges were regressed linearly to correlate with equilibrium pressures as

presented in Table 3.2 and shown in Figure 3.11. The intersection of the linear equation

representing the equilibrium IFTs in Range (I) with zero IFT (i.e., IFTeq = 0) gives the

multi-contact CO2 miscibility pressure, which was found to be MMP = 9.18 MPa. The

second linear regression intersects with IFTeq = 0 at Peq,max = 20.71 MPa. This pressure

may be interpreted as the MMP of CO2 with intermediate and heavy components of crude

oil or first contact CO2 miscibility pressure with the oil.

48

Table 3.2: Pressure range, correlated equations and their accuracy, and calculated multi-

contact and first-contact MMPs obtained from VIT technique at T = 30 °C.

IFT Phase Pressure range

(MPa)

Correlated Equation Accuracy

(R2)

Calculated MMP

(MPa)

Range (I) 0.66–6.84 IFTeq = -2.3066Peq + 21.1750 0.9983 9.18

Range (II) 6.84–14.64 IFTeq = -0.3864Peq + 8.0042 0.9673 20.71

49


0 5 10 15 20 25

Eq

uil

ibriu

m i

nte

rfa

cia

l te

nsi

on

(m

J/m

2)

0

2

4

6

8

10

12

14

16

18

20

22

Range (I):IFT

eq = -2.3066P

eq + 21.1750 (R² = 0.9983)

0.66 MPa < Peq

< 6.84 MPa

Range (II):IFT

eq = -0.3864P

eq + 8.0042 (R² = 0.9673)

6.84 MPa < Peq

< 14.64 MPa

Multi-contactMMP = 9.18 MPa

Maximum Peq

= 20.71 MPa

Range (I)

Range (II)

Figure 3.11: Multi- contact and first contact MMPs of crude oil–CO2 system obtained

from VIT technique at a temperature of T = 30 °C.

50

3.3.2. MMP Determination using Oil Swelling/Extraction Test Results

Swelling/extraction tests are single-contact phase-behaviour experiments

providing the amount of hydrocarbon extracted by CO2 and vapourized into the CO2

phase (Hand and Plnczewski, 1990). Such tests are mostly conducted by measuring the

swelling factor of the oil in contact with the CO2 phase. The MMP can be determined

using the extraction phase in the oil swelling factor curve. As shown earlier (Figure 3.6),

the oil swelling factor values at both temperatures T = 21 °C and 30 °C reduced at a

certain pressure, which is considered as the pressure at which extraction of light

components by CO2 initiates. In the extraction phase, the oil swelling factor decreases

linearly in two distinct pressure ranges of Peq = 5.95–8.07 MPa and Peq = 8.07–12.65

MPa at T = 21 °C. These two pressure ranges are Peq = 6.79–8.96 MPa and Peq = 8.96–

12.55 MPa at T = 30 °C. Based on the measured oil swelling factor values at

temperatures of T = 21 °C and 30 °C, linear regression was applied to correlate the

swelling factor to the equilibrium pressure in the two distinct pressure ranges. The results

are depicted in Figures 3.12 and 3.13. The intersection of the two regressed lines is the

multi-phase-contact MMP of the crude oil–CO2 system at the experimental temperature.

The results of the proposed analysis are described in Table 3.3 as well. Eventually, it was

found that the MMP of the CO2 with the light sample crude oil is MMP = 8.07 MPa and

8.95 MPa at the temperatures of T = 21 °C and 30 °C respectively. The results show that

the CO2 MMP at T = 30 °C calculated by oil swelling factor data (MMPSF = 8.95 MPa) is

in proper agreement with that obtained from VIT technique (MMPVIT = 9.18 MPa).

Furthermore, the MMP of crude oil–CO2 system was found to be lower at T = 21 °C than

that at T = 30 °C. This may be attributed to the higher solubility

51


0 2 4 6 8 10 12 14 16

Oil

sw

elli

ng f

act

or

0.0

0.5

1.0

1.5

2.0

Swelling phase

Upper CO2 extraction phase

Lower CO2 extraction phase

Range (I):SF = -0.2479P

eq + 2.8037 (R² = 0.9811)

8.95 MPa < Peq

< 8.07 MPa

Range (II)SF = -0.0478P

eq + 1.1892 (R² = 0.9913)

8.07 MPa < Peq

< 12.65 MPa

Range (I)

Range (II)

Multi-contact MMP = 8.07 MPa


phase in oil swelling curve at T = 21 °C (estimated MMPSF = 8.07 MPa).

52


0 2 4 6 8 10 12 14 16

Oil

sw

elli

ng f

act

or

0.0

0.5

1.0

1.5

2.0

Swelling phase

Upper CO2 extraction phase

Lower CO2 extraction phase

Range (I):SF = -0.2803P

eq + 3.2840 (R² = 0.9829)

6.79 MPa < Peq

< 8.96 MPa

Range (II)SF = -0.0529P

eq + 1.2483 (R² = 0.9910)

8.96 MPa < Peq

< 12.55 MPa

Range (I)

Range (II)

Multi-contact MMP = 8.96 MPa


phase in oil swelling curve at T = 30 °C (estimated MMPSF = 8.96 MPa).

53

Table 3.3: Pressure range, correlated equations and their accuracy, and calculated MMP

obtained by the analysis of oil swelling factor results at T = 21 °C and 30 °C.

Temperature

(°C)

Extraction

Phase

Pressure range

(MPa)

Correlated Equation Accuracy

(R2)

Calculated

MMP (MPa)

21 Range (I) 5.95–8.07 SF = -0.2479Peq + 2.8037 0.9811

8.07 Range (II) 8.07–12.65 SF = -0.0478Peq + 1.1892 0.9913

30 Range (I) 6.79–8.96 SF = -0.2803Peq + 3.2840 0.9829

8.96 Range (II) 8.96–12.55 SF = -0.0529Peq + 1.2483 0.9910

54

of CO2 at lower temperature as well as that the extraction of lighter components by CO2

starts earlier.

3.3.3. MMP Determination using Proposed Correlations

The experimental values of the MMP for crude oil–CO2 system obtained from the

VIT technique and oil swelling factor curves were verified against some primary

proposed MMP correlations in the literature. Table 3.4 presents MMP correlations

developed to calculate the MMP of the crude oil–CO2 system. As summarized in Table

3.4, generally, the MMP correlations are a function of reservoir temperature and crude oil

composition (volatile and intermediate fractions). Comparison of measured MMPs of the

crude oil–CO2 system with those calculated by proposed correlations as well as absolute

error (AE) of the predicted MMPs by correlations are tabulated in Table 3.5. It is noted

that the AE of the predicted MMPs are calculated based on the experimental MMPs

determined by oil swelling curve. It can be seen that, compared to all existing

correlations, the correlation proposed by Shakir (2007) has the most accurate prediction

of the MMP for the crude oil–CO2 system under this study with average errors of 2.35%

and 5.69% at temperatures of T = 21 °C and 30 °C, respectively. On the other hand, it

was observed that the predicted MMPs from the correlation of Yellig and Metcalfe

(1980) have the lowest accuracy compared to the other correlations.

55

Table 3.4: Proposed correlations for calculating the MMP of crude oil–CO2 system.

Reference Correlation Comments

Cronquist,

1977 150015279.00011038.0744206.0

328.1

11027.0

CMWR

CT

MMP

TR: reservoir temperature (°C)

MWC5+: C5+ molecular weight

C1: mole fraction of CH4

Lee, 1979 1

8.1492/1519772.2103924.7 RT

MMP


Yellig and

Metcalfe,

1980

)328.1(

9427.716

)328.1(1024192.1

)328.1(01553.06472.12

24

R

R

R

T

T

TMMP


Orr and

Jensen,

1984

)328.1(5556.0372.255

201591.10exp

101386.0

RT

MMP


Glaso,

1985

If xINT < 18%

INTR

MW

C

C

xT

eMW

MWMMP

C

1

8.78673.311

2

103564.8)328.1(

101721.1

103470.23251.20

058.1

7

7

7

If xINT > 18%

)328.1(

101721.1

103470.25848.5

058.1

7

7

7

8.786

73.311

2

R

MW

C

C

Te

MW

MWMMP

C



xINT: mole fraction of the intermediates (C2−C6)

Emera and

Sarma,

2004 1073.02785.1

164.15

/

)328.1(100093.5

5 INTVOLC

R

xxMW

TMMP

If Pb < 0.345 MPa

2785.1164.15

5328.1100093.5

CR MWTMMP



Pb: bubble point pressure

xVOL: mole fraction of volatiles (CH4 and N2)

xINT: mole fraction of intermediates (CO2 and

H2S, and C2−C4)

Yuan et al.,

2005

2102

987

2654

321

328.1

328.1

77

7

7

7

RINTCC

R

C

INTC

INTC

TxaMWaMWaa

TMW

xaMWaa

xaMWaaMMP



xINT: mole fraction of the intermediates (C2−C6)

a1 = −1.4634 × 103, a2 = 0.6612 × 101,

a3 = −4.4979 × 101, a4 = 0.2139 × 101,

a5 = 1.1667 × 10−1, a6 = 8.1661 × 103,

a7 = −1.2258 ×10−1, a8 = 1.2283 × 10−3,

a9 = −4.0152 × 10−6, and a10 = −9.2577 × 10−4

Shokir,

2007 432.139804.4

31733.0068616.0 23

z

zzMMP

Where:

4

1i

izz

and iiiiiiii AyAyAyAz 012323

y1 = TR, y2 = xVOL, y3 = xINT, and y4 = MWC5+

A31 = 2.3660 × 10−6, A21 = −5.5996 × 10−4,

A11 = 7.5340 ×10−2, and A01 = −2.9182

A32 = −1.3721 × 10−5, A22 = 1.3644 × 10−3,

A12 = −7.9169 × 10−3, and A02 = −3.1227× 10−1

A33 = 3.5551 × 10−5, A23 = −2.7853 × 10−3,

A13 = 4.2165 × 10−2, and A03 = −4.9485 ×10−2

A34 = −3.1604 × 10−6, A24 = 1.9860 ×10−3,

A14 = −3.9750 × 10−1, and A04 = 2.5430 × 101

Li et al.,

2012

1

7

1001658.208836.2

33647.55

/1ln

328.1ln1030991.7

INTVOLC

R

xxMW

TMMP



Pb: bubble point pressure

xVOL: mole fraction of volatiles (CH4 and N2)

xINT: mole fraction of intermediates (CO2 and

H2S, and C2−C6)

56

Table 3.5: Comparison of measured MMPs of crude oil–CO2 system with those

calculated by proposed correlations.

Method MMP (MPa) AE (%)1,2

T = 21 °C T = 30 °C T = 21 °C T = 30 °C

VIT technique - 9.18 - - Oil swelling curve 8.07 8.96 - - Cronquist, 1997 7.81 9.63 3.22 7.48 Lee, 1979 5.94 7.22 26.39 19.42 Yellig and Metcalfe, 1980 4.06 6.56 49.69 26.79 Orr and Jensen, 1984 5.88 7.20 27.14 19.64 Glaso, 1985 7.07 8.87 12.39 1.00 Emera and Sarma, 2004 7.53 9.61 6.69 7.25 Yuan et al., 2005 7.45 8.69 7.68 3.01 Shokir, 2007 7.88 9.47 2.35 5.69 Li et al., 2012 5.96 7.70 26.15 14.06

1

AE is calculated based on the experimental MMP obtained by oil swelling curve

2100(%)

exp

exp

eriment

ncorrelatioeriment

MMP

MMPMMPAE

57

3.4. Solubility of CO2 in Brine–CO2 System

The solubility of CO2 in brine is also momentously important, since it is a key

parameter in CO2 storage process. In this study, the solubility of CO2 in the brine sample

was also determined through laboratory experiments. The apparatus for measuring CO2

solubility in brine was mainly composed of a CO2 cylinder, a programmable syringe

pump (Teledyne ISCO, 500D series), a constant-temperature air bath, a digital pressure

gauge (Heise Inc.), a piston accumulator, a back pressure regulator (Temco Inc.), and

effluent fluid (i.e., CO2 and water) collectors. The temperature of the airbath was

controlled by a temperature controller (Love Controls Co.). The detail schematic of the

solubility experiment set-up utilized to measure CO2 solubility in brine is presented in

Figure 3.14.

The process of mixing CO2 with brine was conducted at a pre-determined

temperature and equilibrium pressure. CO2 was injected from a high pressure cylinder

into the piston accumulator that holds synthetic brine. The mixture was homogenized for

48 hours inside the airbath at the experimental temperature while the outlet pressure of

CO2 cylinder was kept constant at the desired equilibrium pressure. Thus, during the

equilibration process, the cylinder was kept connected to provide the pressure support on

the mixture. Then, the mixture was oriented vertically and connected to the back pressure

regulator at the same pressure to release the gas cap at the top of carbonated water (i.e.,

brine saturated with CO2). The mixture was pushed upward until some drops of brine

were produced continuously from the back pressure regulator, indicating that the free

CO2 was completely removed and the brine was in CO2-saturated liquid phase.

58

Figure 3.14: Schematic diagram of the experimental set-up used to measure CO2

solubility in the synthetic brine.

Nit

rog

en c

yli

nd

er


Fan &

heater

Fan &

heater

Back

pressure

regulator

Tel

edy

ne

ISC

O s

yri

ng

e p

um

p

Air bath

Carbonated water

Produced gas

collector Produced brine

collector

59

CO2 solubility in brine at various equilibrium pressures and temperatures of T =

21 °C and 30 °C was measured when the carbonated water was prepared and stabilized.

A subsample from the brine–CO2 mixture was extracted using the back pressure regulator

set at the test pressure and a syringe pump to push the mixture out. The volumes of the

produced CO2 and brine were measured to determine the CO2 solubility in the brine

(χ'CO2) as the ratio of the total mass of dissolved CO2 in 100 g of the brine sample using

(Eq. 3.5) and (Eq. 3.6):

2

2

2

222

&@,

,

'

,

'

,

)(CO

TPCOM

eqpCO

COdisCOdisCO

MWv

V

MWnm

eq

……… (Eq. 3.5)

100)(

100

2

2

2

2

2

&@,

,

'

,

bb

CO

TPCOM

pCO

b

disCO

CO

V

MWv

V

m

m

eq

eq

……… (Eq. 3.6)

Figure 3.15 depicts the solubility of CO2 in the brine with 2 wt% NaCl

concentration for various equilibrium pressures and two temperatures of T = 21 °C and

30 °C. It was seen that the solubility of CO2 in brine increased with equilibrium pressure

for both operating temperatures. However, it was found that the CO2 solubility in brine

was almost independent of pressure in high equilibrium pressure ranges. In addition, the

CO2 solubility in the brine at the lower temperature (i.e., T = 21 °C) was relatively higher

than that at the higher temperature (i.e., T = 30 °C).

60


0 2 4 6 8 10 12

' C

O2g

r CO

2/1

00 g

r brin

e

0

1

2

3

4

5

6

7'

CO2 (T = 21 °C)

'CO2

(T = 30 °C)

Figure 3.15: Measured CO2 solubility in the synthetic brine at temperatures of T = 21 °C

and 30 °C.

61


A detailed experimental PVT study on the original light crude oil sample, brine,

and the mutual properties of crude oil–CO2 and brine–CO2 systems was conducted. The

compositional analysis of the sample crude oil was carried out and its viscosity was

measured at different temperatures.

The CO2 solubility in the crude oil was measured in the range of P = 0–Pext at

temperatures of T = 21 °C and 30 °C. The solubility of the CO2 in the crude oil increased

with the equilibrium pressure of the system. Furthermore, it was seen that the CO2

solubility is relatively higher at lower operating temperatures.

The oil swelling factor of crude oil due to CO2 dissolution was determined at

temperatures of T = 21 °C and 30 °C and various equilibrium pressures. At both

temperatures, the volume of the oil increased until the equilibrium pressure approached

the extraction pressure (Pext), and beyond that, the oil volume was reduced due to light

hydrocarbon extraction by CO2.

The dynamic and equilibrium interfacial tensions of the crude oil–CO2 system

were measured using ADSA technique at T = 30 °C. Generally, it was found that the

equilibrium IFTs of the crude oil–CO2 system decreases linearly in two distinct ranges. In

the first linear range, the main mechanism causing the reduction of IFT was the

dissolution of CO2 into the crude oil, while in the second range, the light hydrocarbon

extraction by CO2 was the governing mechanism that resulted in IFT reduction of the

crude oil–CO2 system.

62

The MMP of CO2 with crude oil was determined using two approaches: oil

swelling/extraction data and VIT technique. It was observed that the MMP obtained

using oil swelling curve was in good quantitative agreement with that estimated by VIT

technique. In addition, the measured values of MMP for the crude oil–CO2 system were

verified against some existing MMP correlations, and the results were compared with

each other.

The solubility of the CO2 in the brine–CO2 system was also measured at two

temperatures and various equilibrium pressures. The results showed that the solubility of

CO2 increased with equilibrium pressure while it was apparently less sensitive to pressure

at higher equilibrium pressures. Furthermore, the solubility of CO2 in brine was relatively

higher at the lower experimental temperature.

63

CHAPTER FOUR

CYCLIC CO2 INJECTION TESTS IN NON-FRACTURED POROUS MEDIUM

In this study, the performance of the cyclic CO2 injection process as an EOR

technique in a non-fractured porous medium is investigated. Several laboratory cyclic

CO2 injection tests were designed and carried out at different operating conditions and

under immiscible, near-miscible, and miscible scenarios. This investigation is aimed at

determining how different operating parameters affect the recovery efficiency of cyclic

CO2 injection tests. The materials and experimental set-up, the experimental procedure,

and the results are presented in this chapter.

4.1. Materials and Experimental Set-up

Original light crude oil from the Bakken formation, CO2 (Praxair), and a synthetic

brine with 2 wt% NaCl concentration were used as the reservoir oil, injected solvent, and

reservoir water, respectively. Sample crude oil properties as well as mutual properties of

the crude oil–CO2 system were discussed in detail in the PVT study sections in Chapter 3.

The reference MMP of the crude oil–CO2 system was determined using the average of

experimental MMP values obtained from the VIT technique (i.e., MMPVIT = 9.18 MPa)

and oil swelling curve (MMPSF = 8.96 MPa), which was calculated to be MMP = 9.07

MPa.

64

Figure 4.1 shows the schematic diagram of the experimental set-up used for cyclic

CO2 injection tests in this study. A Berea core with average absolute permeability of k =

70.8 mD was used in this study as a representative of a porous medium. The set-up

consists of a high pressure stainless steel core holder (Hassler, Inc.) with inner and outer

diameters of 6.1 cm and 7.9 cm, respectively. Table 4.1 presents the properties of the core

sample and core holder. The core holder was assembled along the horizontal direction in

order to minimize the effect of the gravity drainage phenomenon during the production.

A strong rubber sleeve (Viton) was used to insulate the core in the core holder

allowing fluids to pass through a cross-section of the core and along the horizontal

direction and prevent flows of fluid around the core. A Teledyne ISCO syringe pump

(Teledyne ISCO, 500D series) was used to inject fluids (i.e., brine, crude oil, and CO2)

into the core through high pressure transfer cells and 1/8” I.D. high pressure stainless

steel pipes (Swagelok Company). To maintain desired back pressure in the system, a

back pressure regulator (Temco Inc.) was connected to the end of the core holder.

Figure 4.1: Schematic diagram of the experimental set-up used for cyclic CO2 injection tests.

Data

acquisition

system

Air bath

Nit

rog

en c

yli

nd

er

To the vent

Gas flow meter

Back

pressure

regulator

Sample

collector


Fan &

heater

Fan &

heater

Tel

edy

ne

ISC

O s

yri

ng

e p

um

p

CO

2

Cru

de

oil

Bri

ne

Core holder

Berea core sample

Diff. pressure transducer

63

66

Table 4.1: Properties of the core sample and core holder used for cyclic CO2 injection

tests.

Permeability,

k (mD)

Porosity,

(%)

Height,

(cm)

Diameter

(cm)

Pore volume,

PV (cm3)

Core sample 70.8 18.5 30.21 5.05 111.94

Core holder - - 35.59 6.12 1046.94

67

4.2. Experimental Procedure

4.2.1. Secondary Cyclic CO2 Injection

Prior to each experiment, the core was cleaned, vacuumed, and saturated with the

brine completely. Along with the brine saturating process, the water injection flow rate

was varied in the range of qw-inj = 0.25–2 cm3/min in order to determine the absolute

permeability (k) of the core sample in each test. Thereafter, the oil sample was injected to

the system with a constant flow rate of qo-inj = 0.25 cm3/min to reach the connate water

saturation (Swc) and establish the initial oil saturation (Soi). The connate water saturation

was found to be Swc = 43.3–45.9%, and the initial oil saturation was in the range of Soi =

54.1–56.7% in all cyclic CO2 injection tests. These saturations can be obtained when no

more water is produced. The initial oil effective permeability (koi) was also determined

using differential pressure between the inlet and outlet of the core holder. After

saturation with oil, the core was allowed to remain for 24 hrs to reach a proper

equilibrium condition at a constant temperature of T = 30 °C. Since the cyclic CO2

injection tests were performed at various operating pressures, the above procedure was

repeated for all experiments.

For the cyclic CO2 injection, the pressure of the CO2 in the transfer cell was

increased up to the desired pressure for each test and kept for 24 hrs to equilibrate at the

experimental temperature. Then, the CO2 was injected into the oil saturated core under a

constant operating pressure for a definite injection time (Tinj = 30 min). After completion

of CO2 injection (i.e., huff cycle), the core was shut for a specific period of time (Tsoak =

24 hrs). The production (i.e., puff cycle) was then implemented with the oil production at

68

the end of the core holder. Since a cyclic injection process is a single well injection-

production technique, both CO2 injection and oil production in this study were conducted

at the same side (i.e., outlet) of the core holder. When the first huff-and-puff cycle was

completed, the second cycle was started with the same procedure of the first cycle. These

cycles were continued until there was no considerable oil production obtained. The

volume of the produced oil and gas in each puff cycle was measured to calculate the oil

recovery factor, the producing gas-oil ratio, and gas utilization factor. Gas utilization

factor is defined as the ratio of the produced oil volume to the injected gas volume. It is

noted that with production in each puff cycle of cyclic CO2 injection, no connate water

was produced.

A series of secondary cyclic CO2 injection tests was performed at different

operating conditions and T = 30 °C following the aforementioned procedure. The cyclic

CO2 injection tests were carried out at five operating pressures of Pop = 5.38, 6.55, 8.27,

9.31, and 10.34 MPa, while the temperature was set to be constant at T = 30 °C and

controlled by a temperature controller in the airbath.

4.2.2. Parametric Study of Cyclic CO2 Injection

As mentioned earlier, several operating parameters may affect the recovery

efficiency of cyclic CO2 injection processes. One of the main objectives of this study is to

determine the functionality of some important operating parameters on the performance

of the cyclic CO2 injection test. Therefore, in addition to the operating pressure (Pop),

effects of some other parameters including injection time (Tinj), soaking period (Tsoak),

69

and connate water saturation (Swc) on the oil recovery of the cyclic CO2 injection process

were also investigated. Two different values of Tinj = 30 min and 120 min as well as Tsoak

= 24 hrs and 48 hrs were considered for the CO2 injection time and soaking period,

respectively. At each operating pressure, one cyclic CO2 injection test was carried out in

the absence of connate water saturation to determine how this parameter affects the

process. Furthermore, two cyclic injection tests were performed by CO2/propane mixture

(80 vol.% CO2 + 20 vol.% C3H8) as the solvent to determine the impact of this mixture

on the cyclic injection process. Table 4.2 presents the initial and operating conditions for

all cyclic CO2 injection tests.

70


and solvent) for all secondary cyclic CO2 injection tests.

Test # (%) k (mD) Swc (%) Soi (%) Pop (MPa) Tinj (min) Tsoak (hr) Solvent

1 18.5 70.8 44.7 55.3 5.35 30 24 CO2

2 18.4 70.6 45.4 54.6 5.35 120 24 CO2

3 18.3 71.3 43.3 56.7 5.35 30 48 CO2

4 18.5 70.9 45.8 54.2 5.35 120 48 CO2

5 18.3 71.4 0 100 5.35 120 24 CO2

6 18.7 70.8 45.9 54.1 6.55 120 24 CO2

7 18.5 71.3 45.5 54.5 6.55 120 48 CO2

8 18.4 70.5 0 100 6.55 120 24 CO2

9 18.6 71 44.7 55.3 8.27 120 24 CO2

10 18.4 70.6 45.4 54.6 8.27 120 48 CO2

11 18.4 70.8 43.3 56.7 8.27 30 24 CO2

12 18.7 71.2 0 100 8.27 120 24 CO2

13 18.6 70.9 44.9 55.1 9.31 120 24 CO2

14 18.4 71.3 45.7 54.3 9.31 120 48 CO2

15 18.7 70.7 0 100 9.31 120 24 CO2

16 18.5 71 44.3 55.7 10.34 120 24 CO2

17 18.3 70.5 45.1 54.9 10.34 120 48 CO2

18 18.6 70.7 0 100 10.34 120 24 CO2

19 18.3 70.5 45.2 54.8 3.45 120 24 CO2+C3

20 18.5 70.7 45.4 54.6 4.83 120 24 CO2+C3

71

4.2.3. Asphaltene Precipitation and Oil Effective Permeability Damage

Precipitation and deposition of asphaltene particles in the pore spaces of reservoir

rocks cause diffusivity reduction, wettability alteration, and permeability damage in

hydrocarbon reservoirs, which consequently reduces the oil recovery considerably

(Ashoori et al., 2010). Asphaltenes are high-molecular weight solids that are soluble in

aromatic solvents such as benzene and toluene but insoluble in paraffinic solvents (i.e., n-

pentane and n-heptane) (Mansoori, 1997). In immiscible and miscible CO2 displacement

processes, the injected CO2 can induce flocculation and deposition of asphaltenes and

other heavy organic particles, which consequently cause numerous production problems

(Srivastava and Huang, 1997; Jafari Behbahani et al., 2012). Thus, it is of great

importance to determine how much asphaltene precipitates are in the porous medium in a

CO2 injection process. In this study, the cumulative average asphaltene content of the

CO2-produced oil in the first and second cycles of each cyclic CO2 injection test was

measured using the standard ASTM D2007-03 method, and n-pentane was used as

precipitant.

In order to determine the permeability damage of the system after each cyclic CO2

injection test, the original light crude oil was re-injected into the core holder with a

constant flow rate of qo-inj = 0.25 cm3/min after the last cycle production. The final oil

effective permeability (kof) was determined using the differential pressure of the inlet and

outlet of the core holder. Finally, the oil relative permeability damage factor (DFo) was

calculated through the relation of DFo = 1-kof/koi. In addition, no water was produced

along the re-injection of the crude oil into the system.

72

4.3. Experimental Results and Discussion

4.3.1. Oil Recovery Factor, Producing Gas–Oil Ratio (GOR), and Gas Utilization

Factor (GUF)

In this study, a series of cyclic CO2 injection tests was conducted at different

operating pressures ranging from Pop = 5.38–10.34 MPa and temperature of T = 30 °C

under immiscible, near-miscible, and miscible conditions. The MMP of the crude oil–

CO2 system was determined to be MMP = 9.07 MPa. In each cycle, the CO2 was injected

into the system for Tinj = 120 min, and then the system was shut in for the soaking period

of Tsoak = 24 hrs, and finally it was opened to produce. The cycle numbers were continued

until no considerable oil production was obtained. It is noteworthy to mention that there

was no water production in the cyclic CO2 injection tests, and the connate water

saturation remained constant along whole process.

Figure 4.2 and Figure 4.3 show the measured oil recovery factor versus cycle

numbers and pore volume of injected CO2 for five cyclic injection tests (Test # 2, 6, 9,

13, and 16) at different operating pressures, respectively. The cumulative oil recovery

factor increased with the cycle numbers and pore volume of injected CO2. The results

showed that for tests performed at immiscible conditions, specifically Test #2 and Test #

6, the recovery factor increases significantly as the operating pressure increases and

reaches the near-miscible condition (Test # 9). The oil recovery factor increased from RF

= 33.22% in Test # 2 with the operating pressure of Pop = 5.38 MPa to RF = 55.83% in

Test # 9, which performed at Pop = 8.27 MPa. The measured oil recovery factor reached

almost maximum value at miscible operating pressure of Pop = 9.31 MPa (Test # 13) with

73

Time (Day)

0 1 2 3 4 5 6 7 8 9 10 11

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

20

40

60

80

Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Test # 1 (Pop = 5.38 MPa)




Test # 5 (Pop = 10.34 MPa)


and Tsoak = 24 hrs) vs. cycle number and time at various operating pressures.

74

Pore volume of injected CO2

0 1 2 3 4 5 6 7

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

20

40

60

80

Test # 2 (Pop

= 5.38 MPa)

Test # 6 (Pop

= 6.55 MPa)

Test # 9 (Pop

= 8.27 MPa)

Test # 13 (Pop

= 9.31 MPa)

Test # 16 (Pop

= 10.34 MPa)

0


and Tsoak = 24 hrs) vs. pore volume of injected CO2 at various operating pressures.

75

RF = 60.86%. Further increase in operating pressure did not result in a substantial oil

recovery factor, which was measured to be RF = 61.54% at Pop = 10.34 MPa (Test # 16).

Moreover, it was found that in cyclic CO2 injection tests performed at the miscible

condition, the ultimate recovery factor was achieved by a lower number of cycles (i.e.,

seven cycles) or pore volume of injected CO2 compared to that in immiscible conditions

(i.e., 10–11 cycles). The reason is mainly attributed to the more favourable phase

behaviour of crude oil–CO2 systems in miscible conditions due to lower interfacial

tension between crude oil and CO2 as well as a stronger light hydrocarbon extraction

mechanism by CO2. These phenomena increase the oil recovery in each cycle, which

leads to a more significant ultimate oil recovery factor with fewer cycles or pore volume

of injected CO2.

The ultimate oil recovery factor together with first and second stage recovery factors of

the aforementioned five cyclic CO2 injection tests versus operating pressure in three

discrete regions of immiscible, near-miscible, and miscible conditions are plotted in

Figure 4.4. As illustrated in this figure, in the range of immiscible to near-miscible cyclic

CO2 injection processes, the ultimate oil recovery factor, highly depends on the operating

pressure and increases considerably with the increased operating pressure. Similarly the

same results were obtained for the first and second stage recovery factors in the same

regions. Moreover, it was found that 40–60% of ultimate oil recovery in cyclic injection

tests was produced in the first and second cycles. This can be explained in that along the

initial oil saturating of the core sample, the oil phase occupies the porous medium starting

with larger pore spaces (i.e., larger pore radius) because of lower resistance force due to

lower water–oil capillary pressure. Therefore, oil saturation is generally higher in the

76

larger pore sizes (Abedini et al., 2012). On the other hand, since the capillary pressure of

oil–gas phase is also lower in larger pore spaces of the core, the CO2 molecules begin to

occupy and diffuse into the larger pores during initial cycles (i.e., first and second

cycles). As a result, CO2 interacts with a larger portion of the oil in-place during initial

cycles and a lower volume of that in the subsequent cycles, leading the oil recovery factor

to be higher in the first and second cycles and reduced in following cycles of the cyclic

CO2 injection process.

The producing gas–oil ratio (GOR) and gas utilization factor (GUF) of the five

cyclic CO2 injection tests performed at different operating pressures ranging from

immiscible to miscible conditions are shown is Figures 4.5 and 4.6. In addition, Figure

4.7 portrays the total producing GOR and final GUF of the five injection tests. It was

found that the total producing GOR of miscible cyclic CO2 injection tests was relatively

lower than that in immiscible and near-miscible cyclic CO2 injection tests. This is due to

a lower volume of CO2 being required to be injected into the core holder as well as the

larger amount of oil in-place being produced from the porous media in miscible injection.

For the same reason, the final GUF in miscible cyclic CO2 injection tests was higher than

that in immiscible ones, since more volume of the original oil in-place was recovered by

injecting a lower volume of CO2 into the system.

77

Operating pressure (MPa)

5 6 7 8 9 10 11

Ult

imate

oil

rec

over

y f

act

or

(%)

25

30

35

40

45

50

55

60

65

1st a

nd

2n

d s

tage

reco

ver

y f

act

ors

5

10

15

20

25

30

Ultimate oil recovery factor

1st stage recovery factor

2nd stage recovery factor

Immiscible Near-miscible Miscible

Figure 4.4: Ultimate, 1st and 2

nd stage oil recovery factors of the five cyclic CO2 injection

tests (at Tinj = 120 min and Tsoak = 24 hrs) performed at immiscible, near-miscible, and

miscible conditions.

78


0 1 2 3 4 5 6 7

Pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f oil

)

0

500

1000

1500

2000

2500Test # 2 (Pop = 5.38 MPa)



Test # 13 (Pop

= 9.31 MPa)

Test # 16 (Pop = 10.34 MPa)

Figure 4.5: Producing GOR of the five cyclic CO2 injection tests (at Tinj = 120 min and

Tsoak = 24 hrs) performed at immiscible, near-miscible, and miscible conditions.

79


0 1 2 3 4 5 6 7

Gas

uti

liza

tion

fact

or

(cm

3 o

f oil

/cm

3 o

f in

j. g

as)

0.0001

0.001

0.01

0.1

Test # 2 (Pop

= 5.38 MPa)

Test # 6 (Pop

= 6.55 MPa)

Test # 9 (Pop

= 8.27 MPa)

Test # 13 (Pop

= 9.31 MPa)

Test # 16 (Pop

= 10.34 MPa)

Figure 4.6: GUF of the five cyclic CO2 injection tests (at Tinj = 120 min and Tsoak = 24

hrs) performed at immiscible, near-miscible, and miscible conditions.

80


Tota

l P

rod

ucin

g G

OR

(cm

3 g

as/

cm

3 o

il)

0

500

1000

1500

2000

2500

3000

Fin

al

GU

F *

10

6 (

cm

3 o

il/c

m3 i

nj.

gas)

0

200

400

600

800

Total producing GOR

Final GUF

5.38 6.55 8.27 9.31 10.34

Figure 4.7: Total producing GOR and final GUF of the five cyclic CO2 injection tests (at

Tinj = 120 min and Tsoak = 24 hrs) performed at immiscible, near-miscible, and miscible

conditions.

81

4.3.2. Effect of the CO2 Injection Time (Tinj)

Figure 4.8 shows the effect of the CO2 injection time (Tinj) on the ultimate, first,

and second stage oil recovery factors of cyclic CO2 injection tests performed at operating

pressures of Pop = 5.38 MPa and 8.27 MPa (i.e., Test # 1, 2, 9, and 11). Comparing the

recovery factors of cyclic CO2 injection tests performed with Tinj = 30 min with those

tests carried out with Tinj = 120 min reveals that increase of the CO2 injection time did not

improve the recovery factors of cyclic CO2 injection tests effectively. The ultimate oil

recovery factor of tests carried out at Pop = 5.38 MPa and 8.27 MPa with Tinj = 30 min

were RF = 32.57% and 54.39%, respectively, while these values for the tests

implemented with Tinj = 120 min were RF = 33.22% and 55.80%. The reason is mainly

attributed to the physical size of the porous medium in this study. Since the physical size

of the model under this study was very limited compared to the real reservoir case, the

core sample was saturated by CO2 rapidly in each huff cycle and higher CO2 injection

time did not result in the injection of more significant volume of the CO2 into the system

leading to a higher oil recovery factor. However, this parameter may play an effective

role in field-scale cyclic CO2 injection processes. In order to investigate the influence of

injection time on the cyclic CO2 injection test, it is recommended to perform such tests on

larger experimental models that have larger pore volume to be occupied by more CO2.

82

Pressure (MPa)

5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5

Ult

imate

oil

rec

over

y f

act

or

(%)

0

10

20

30

40

50

60

70

80

Sta

ge

reco

ver

y f

act

or

(%)

0

5

10

15

20

25

30Ultimate RF: Tinj = 30 min,

Ultimate RF: Tinj = 120 min

1st

stage RF: Tinj = 30 min

1st


2nd


2nd


Figure 4.8: Ultimate, 1st, and 2

nd stage recovery factors of cyclic CO2 injection tests

performed at operating pressures of Pop = 5.38 MPa and 8.27 MPa with CO2 injection

times of Tinj = 30 min and 120 min and identical soaking period of Tsoak = 24 hrs (Test #

1, 2, 9 and 11).

83

4.3.3. Effect of the Soaking Period (Tsoak)

Figure 4.9 depicts the impact of the soaking period (Tsoak) on the ultimate oil

recovery factor of cyclic CO2 injection tests performed at operating pressures ranging

from Pop = 5.38–10.34 MPa and a temperature of T = 30 °C under immiscible, near-

miscible, and miscible conditions. Comparing the oil recovery factors of cyclic CO2

injection tests performed with Tsoak = 24 hrs with those tests carried out with Tsoak = 48

hrs reveals that a longer soaking period substantially enhanced the recovery factors of

cyclic CO2 injection tests, especially in those tests carried out under immiscible

conditions. A longer soaking period raised the ultimate recovery factor up to 5% in the

region of immiscible to near-miscible condition. Since mass transfer phenomena

particularly for gas–liquid systems in porous media are time consuming processes and

highly dependent on molecular diffusion mechanisms, more specifically apparent

molecular diffusion, in the absence of a convection term (Abedini et al., 2012; Kavousi et

al., 2013), a longer soaking period intensifies the interaction between oil and CO2 phases

in porous media and aids the diffusion process of CO2 in crude oil. As a result, more CO2

diffuses into the oil phase, and the CO2 recovery mechanisms (i.e., CO2 solubility, oil

swelling factor, IFT reduction, and extraction of lighter components) are stronger.

However, at miscible conditions and beyond, the soaking period was found to be almost

negligible on the recovery performance of cyclic CO2 injection. During the miscible

condition, the hydrocarbon extraction mechanism acts very quickly compared to oil

swelling mechanism during immiscible condition (see Figure 3.9). Therefore, longer

soaking period has no noticeable influence on the oil recovery of miscible cyclic CO2

injection.

84

Pressure (MPa)

5 6 7 8 9 10 11

Ult

imate

oil

rec

over

y f

act

or

(%)

0

10

20

30

40

50

60

70

80

Tinj = 120 min, Tsoak = 24 hrs and Swc is not zero




pressures ranging from Pop = 5.38–10.34 MPa with soaking periods of Tsoak = 24 hrs and

48 hrs and identical CO2 injection time of Tinj = 120 min.

85

4.3.4. Effect of the Connate Water Saturation (Swc)

Two different sets of cyclic CO2 injection tests were performed at operating

pressures ranging from Pop = 5.38–10.34 MPa in the presence and absence of the connate

water saturation (Swc) to determine the effect of this parameter on the performance of

cyclic CO2 injection process. Figure 4.10 portrays how connate water affected the

ultimate oil recovery factor of cyclic CO2 injection tests under immiscible, near-miscible,

and miscible conditions. It can be seen that the presence of connate water in a porous

medium is a beneficial parameter in immiscible and near-miscible cyclic CO2 injection

tests resulting in a larger amount of oil production and higher ultimate oil recovery factor,

while it has no significant influence on the oil recovery performance of miscible cyclic

CO2 injection scenarios.

The presence of connate water in the porous medium improves the oil recovery by

increasing the interaction of crude oil and CO2 together with enlarging the contact area

between these two phases. The CO2 can diffuse and dissolve in the water and move into

the oil phase through the contact area between the oil and connate water (Torabi, 2008).

Another reason that may occur in longer injection schemes is the generation of

carbonated water as a result of the co-presence of CO2 and water. Carbonated water

provides an acidic environment and can dissolve reservoir rock, which results in

improvement of rock permeability.

86

Pressure (MPa)

5 6 7 8 9 10 11

Ult

imate

oil

rec

over

y f

act

or

(%)

10

20

30

40

50

60

70


Tinj = 120 min, Tsoak = 24 hrs and Swc is zero



pressures ranging from Pop = 5.38–10.34 MPa in the presence and absence of connate

water saturation.

87

4.3.5. Effect of the CO2/Propane mixture

In some cases, due to certain reservoir properties (i.e., mainly thermodynamic

properties such as pressure, temperature, and crude oil composition), different mixtures

of CO2 with other hydrocarbon gases (e.g., methane or propane) are used as solvents in

cyclic injection processes. Therefore, in addition to CO2, a mixture of CO2 and propane

(80 vol.% CO2 + 20 vol.% C3H8) was examined in cyclic injection tests. Two cyclic

CO2/C3 injection tests were performed at operating pressures of Pop = 3.45 MPa and 4.83

MPa with Tinj = 120 min and Tsoak = 24 hrs. Figure 4.11 and Figure 4.12 depict the oil

recovery factor vs. cycle number and pore volume of injected solvent for cyclic CO2/C3

injection tests, respectively. It can be observed that CO2/C3 mixture increased the oil

recovery considerably, although the test was operated at lower pressures. The ultimate oil

recovery factor of cyclic CO2/C3 injection tests performed at Pop = 3.45 MPa and 4.83

MPa were found to be RF = 49.41% and 59.30%, respectively.

The reason is mainly attributed to the higher solubility and diffusivity of propane

in crude oil compared with pure CO2. As a result, the average solubility and molecular

diffusivity of the CO2/C3 mixture are higher than those of pure CO2, which leads to more

favourable phase behaviour between the mixture and crude oil. Consequently, the oil

recovery performance of the cyclic injection process is improved. In the reservoirs with

relatively low pressures or high temperatures which make it infeasible to inject CO2 under

near-miscible or miscible conditions, the CO2/C3 mixture is capable of recovering more

amount of in-placed oil if injected as a solvent during cyclic injection process.

88

Cycle number

0 1 2 3 4 5 6 7

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

10

20

30

40

50

60

70

Pop = 3.45 MPa

Pop = 4.83 MPa


min and Tsoak = 24 hrs) vs. cycle number at operating pressures of Pop = 3.45 MPa and Pop

= 4.83 MPa.

89

Pore volume of injected solvent (CO2 + C

3)

0.0 0.5 1.0 1.5 2.0 2.5

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

10

20

30

40

50

60

70

Pop = 3.45 MPa

Pop = 4.83 MPa

0


min and Tsoak = 24 hrs) vs. pore volume of injected solvent at operating pressures of Pop =

3.45 MPa and Pop = 4.83 MPa.

90

4.3.6. Asphaltene Precipitation (Wasph) and Oil Effective Permeability Damage (DFo)

The average asphaltene content of CO2-produced oil from the first and second

cycles of cyclic CO2 injection tests, as well as precipitated asphaltene in the core, are

plotted in Figure 4.12. The initial n-pentane insoluble asphaltene content of original light

crude oil was Wasph = 1.23 wt%, while the measured asphaltene content of CO2-produced

oil in cyclic CO2 tests was lower than the initial content. This is an indication of

asphaltene precipitation and deposition phenomena in the pore spaces of the core sample

as a result of CO2 injection. As shown in Figure 4.12, for the cyclic CO2 injection tests

carried out at a pressure lower than MMP (i.e., immiscible conditions), specifically Test #

2 and Test # 6, the asphaltene content of the CO2-produced oil of the first and second

cycles are considerably higher than that in the tests performed at pressures near and

above MMP (i.e., near-miscible and miscible conditions, specifically Tests # 9, 13, and

16). Conversely, it can be concluded that in the near-miscible and miscible cyclic CO2

injection tests, the amount of precipitated asphaltene in the porous medium is drastically

higher. This is mainly due to the stronger light component extraction process by CO2 at

pressures near and above MMP, which leads to asphaltene particles becoming unstable,

and their association with other hydrocarbon groups, particularly resins, is reduced.

The effective oil permeability damage of the core sample after termination of

cyclic CO2 injection tests at each operating pressure was determined and is illustrated in

Figure 4.12. The permeability damage was calculated using DFo = 1-kof/koi, in which koi

and kof are the initial and final oil effective permeability of the core sample before and

after each cyclic CO2 injection test, respectively. The oil effective permeability damage

in to the core system is mainly attributed to the rock wettability alteration from water-wet

91

Figure 4.12: Asphaltene content of CO2-produced oil, precipitated asphaltene in the core

and oil effective permeability damage (DFo) of the core sample in cyclic CO2 injection

tests (at Tinj = 120 min and Tsoak = 24 hrs, Pop = 5.38–10.34 MPa) under immiscible, near-

miscible, and miscible conditions.


5 6 7 8 9 10 11

Asp

halt

en

e c

on

ten

t of

CO

2-p

rod

uced

oil

(w

t%)

0.40

0.45

0.50

0.55

0.60

0.65

Precip

itate

d a

sph

alt

en

e i

n t

he c

ore (

wt%

)

0.55

0.60

0.65

0.70

0.75

0.80

0.85

0.90

Oil

Rela

tive P

erm

eab

ilit

y d

am

age(%

)

9

10

11

12

13

14

15

Asphaltene content of CO2-produced oil

Precipitated asphaltene in the core

Permeability damage of the core


92

to mixed or oil-wet due to the precipitation and deposition of heavy oil components,

especially asphaltene particles, on the rock surfaces. The results showed that the

permeability damage of the core sample in near-miscible and miscible cyclic CO2

injection tests is considerably higher than that in immiscible ones since the remaining and

deposited asphaltene particles and heavy components in the porous medium are larger in

the tests carried out at pressures near and above MMP.

4.3.7. Compositional Analysis of Remaining Oil

After termination of cyclic CO2 injection tests performed at Pop = 6.55 MPa (Test

#6: immiscible CO2 injection) and Pop = 9.31 MPa (Test # 13: miscible CO2 injection),

fresh original light crude oil was re-injected into the system and a small amount of the

remaining oil was collected at the start of the production time. The compositional

analysis was performed on the collected remaining oil samples in order to determine the

main CO2 recovery mechanism(s) in the cyclic CO2 injection process.

Figure 4.13 and Figure 4.14 depict the compositional analysis as well as grouped

carbon number distributions of the remaining crude oil for cyclic CO2 injection tests

carried out at the aforementioned operating pressures. It is seen that due to the

mechanism of light component extraction by CO2, lighter components ranging C1–C4’s

were completely extracted and removed from oil phase at Pop = 6.55 MPa, but the

extraction of other light components ranging C5’s–C7’s was very low. Accordingly, the

mole percent of intermediate to heavy hydrocarbons including C10–C19’s, C20–C29’s, and

C30+ and the molecular weight of remaining oil were slightly higher than those in the

93

original crude oil. This implies that the CO2 extraction mechanism was initiated near Pext

= 6.55 MPa, which is in good agreement with the results obtained from oil swelling and

IFT tests.

The compositional analysis of remaining oil for cyclic CO2 injection tests

implemented at Pop = 9.31 MPa reveals that the extraction mechanism was much stronger

at this operating pressure compared to that at Pop = 6.55 MPa. At Pop = 9.31 MPa. Lighter

components ranging C1–C5’s were completely extracted and removed from the oil phase.

In addition, considerable amounts of other lighter components ranging C6’s–C7’s were

extracted, as well. Subsequently, the amount of intermediate to heavy hydrocarbons,

including C10–C19’s, C20–C29’s, and C30+, and the molecular weight of remaining oil were

significantly higher than those in the original crude oil. Comparison of the remaining oil

compositional analysis of cyclic CO2 injection tests at Pop = 9.31 MPa with that of cyclic

tests at Pop = 6.55 MPa confirms that the precipitated asphaltene in the core was

substantially higher in miscible cyclic CO2 injection tests than in immiscible CO2 huff-

and-puff tests.

The results show that extraction of lighter components of crude oil by CO2 in

miscible cyclic CO2 injection tests is the main production mechanism contributing to the

CO2 enhanced oil recovery of light crude oils, but for the immiscible to near-miscible

cyclic CO2 injection scenarios, the recovery process is not greatly affected by the

extraction of lighter components. However, in such conditions, the oil solubility, oil

swelling, IFT reduction, and, to some extent, reduction of viscosity are the primary

recovery mechanisms.

94

Figure 4.13: Compositional analysis, plus fraction and molecular weight of original and

remaining crude oils of cyclic CO2 injection tests performed at Pop = 6.55 MPa and 9.31

MPa (Conducted by Saskatchewan Research Council).

Col 2

Crude oil components

Mo

le p

ercen

t

0

2

4

6

8

10

12

14

16

Composition of original light crude oil(C

30+ = 2.86%, MW = 223 gr/mol)

Composition of remaining crude oil at 6.55 MPa(C

30+ = 3.96%, MW = 242 gr/mol)

Composition of remaining crude oil at 9.31 MPa(C

30+ = 5.61%, MW = 268 gr/mol)

C1

C2

C3

i-C

4

n-C

4

i-C

5

n-C

5C

6's

C7

's

C8

's

C9

's

C1

0's

C1

1's

C1

2's

C1

3's

C1

4's

C1

5's

C1

6's

C1

7's

C1

8's

C1

9's

C2

0's

C2

1's

C2

2's

C2

3's

C2

4's

C2

5's

C2

6's

C2

7's

C2

8's

C2

9's

C3

0+

CO

2

95

Mo

le P

ercen

t

0

10

20

30

40

50

60

70C

1-C

4's

C5's

-C9's

C10's

-C19's

C20's

-C29's

C30+

Original crude oil Remaining crude oil

(Pop

= 6.55 MPa)

Remaining crude oil

(Pop

= 9.31 MPa)

Figure 4.14: Grouped carbon number distributions of original crude oil and remaining

crude oil of cyclic CO2 injection tests performed at Pop = 6.55 MPa and 9.31 MPa.

96

4.3.8. Production Results of all Secondary Cyclic CO2 Injection Tests

Table 4.3 presents the experimental results of all cyclic CO2 injection tests

including ultimate, first, and second stage oil recovery factors, total producing GOR, final

GUF, asphaltene content of CO2-produced oil, and oil effective permeability damage.

Figure 4.15a-c shows the ultimate, first, and second stage recovery factors of all

cyclic CO2 injection tests carried out at several operating conditions and under

immiscible, near-miscible, and miscible injection scenarios. It can be seen that the

ultimate recovery factor increased substantially with increased operating pressure in the

range of immiscible to near-miscible conditions and approached its maximum value at

miscible operating conditions. Furthermore, increasing the operating pressure beyond the

MMP (i.e., Pop > MMP) did not improve the oil recovery efficiency. The same trend was

also found for the first and second stage recovery factors, in which the recovery factor

significantly increased with the higher operating pressures for immiscible to near-

miscible CO2 injections, while it was almost constant in miscible and above miscible

conditions.

Figures 4.16 a & b depict the total producing GOR and final GUF for all cyclic CO2

injection tests. The figure shows that the total producing GOR of immiscible and near-

miscible injection processes was much higher than that of miscible injection scenarios

since more cycles and larger amounts of injected CO2 were required in immiscible and

near-miscible cyclic CO2 injection to achieve maximum oil recovery. For the same

reason, the final GUF of the miscible cyclic CO2 injection tests was found to be relatively

97

Table 4.3: Experimental results (ultimate, 1st, and 2

nd stage recovery factors, total

producing GOR, final GUF, Wasph of produced oil, and oil effective permeability damage)

of all cyclic CO2 injection tests performed at various operating conditions.

Test # Ultimate

RF (%)

1st stage

RF (%)

2nd

stage

RF (%)

Total GOR

(cm3/cm

3)

Final GUF [×106]

(cm3/cm

3)

Wasph

(wt%)

DFo

(%)

1 32.57 7.06 5.46 1479.35 405.7 0.57 9.63

2 33.22 7.63 5.76 1610.33 342.8 0.59 9.81

3 36.95 8.08 6.21 1368.90 422.2 0.54 10.47

4 37.51 8.22 5.93 1516.89 337.7 0.52 10.40

5 29.50 7.30 6.02 860.00 480.4 0.46 12.04

6 47.50 12.87 9.78 1560.00 379.4 0.53 10.72

7 51.30 13.90 9.44 1670.00 317.3 0.51 10.51

8 34.90 10.08 7.30 877.90 466.0 0.42 12.48

9 55.80 16.80 11.22 2083.32 320.8 0.48 13.34

10 58.70 17.92 11.40 2231.21 299.5 0.45 13.90

11 54.39 15.40 10.67 2200.41 323.0 0.50 13.06

12 53.15 15.22 11.30 1377.70 317.4 0.39 14.47

13 60.80 23.90 15.04 932.47 574.3 0.46 13.95

14 61.34 24.79 15.40 990.53 538.2 0.43 14.26

15 58.40 21.30 14.93 546.09 899.8 0.38 14.29

16 61.52 23.53 16.10 979.18 537.3 0.45 13.79

17 62.10 25.20 15.98 1031.10 508.6 0.44 14.19

18 59.90 21.51 15.31 572.87 882.0 0.37 14.91

19 49.41 20.13 14.04 172.71 3140 0.43 16.37

20 59.28 22.58 17.22 230.11 1870 0.37 18.46

98

Figure 4.15: (a): Ultimate oil recovery factor, (b): 1st stage recovery factor, and (c): 2

nd

stage recovery factor of all cyclic CO2 injection tests performed at various operating

conditions.

Pressure (MPa)

5 6 7 8 9 10 11

Ult

imate

oil

rec

over

y f

act

or

(%)

10

20

30

40

50

60

70






Pressure (MPa)

5 6 7 8 9 10 11

1st s

tage

oil

rec

over

y f

act

or

(%)

0

6

12

18

24

30

36Tinj = 30 min, Tsoak = 24 hrs and Swc is not zero




Pressure (MPa)

5 6 7 8 9 10 11

2n

d s

tage

oil

rec

over

y f

act

or

(%)

0

3

6

9

12

15

18





(a)

(b)

(c)



99

Pressure (MPa)

5 6 7 8 9 10 11

To

tal

pro

du

cin

g G

OR

(cm

3 o

f g

as/

cm3 o

f o

il)

0

500

1000

1500

2000

2500





Pressure (MPa)

5 6 7 8 9 10 11

To

tal

GU

F [

*1

06]

(cm

3 o

f o

il/c

m3 o

f g

as)

0

200

400

600

800

1000





(a)

(b)



Figure 4.16: (a): Total producing GOR, and (b): Final GUF of all cyclic CO2 injection

tests performed at various operating conditions.

100

higher than that of immiscible and near-miscible cyclic CO2 injection tests since larger

oil volume was produced with a lower volume of injected CO2.

The asphaltene content of CO2-produced oil and the oil effective permeability

damage for cyclic CO2 injection tests are plotted in Figure 4.17a & b. According to the

results, the CO2-produced asphaltene content decreased almost regularly from the

immiscible conditions to the miscible ones. Conversely, it can be concluded that the

amount of precipitated asphaltene in the core system increased with the operating

pressure from immiscible cyclic CO2 injection tests to the miscible cases. Regarding the

permeability damage, it was found that the reduction in oil effective permeability

increased when the operating conditions changed from immiscible cyclic injection

scenarios to miscible ones. This was mainly due to the higher asphaltene precipitation

phenomenon in miscible CO2 injection processes, which caused pore throat plugging of

the porous medium and reduced the oil effective permeability.

The experimental results including incremental and cumulative oil recovery

factor, incremental and cumulative producing GOR and GUF, the amount of asphaltene

precipitation, and oil effective permeability damage of all cyclic CO2 injection tests

carried out at the operating pressures Pop = 5.38–10.34 MPa (i.e., immiscible, near-

miscible and miscible conditions) are presented graphically in Appendix B.

101

Pressure (MPa)

5 6 7 8 9 10 11

Asp

halt

ene

con

ten

t of

CO

2-p

rod

uce

d o

il (

wt%

)

0.3

0.4

0.5

0.6

0.7Tinj = 30 min, Tsoak = 24 hrs and Swc is not zero




Pressure (MPa)

5 6 7 8 9 10 11

Oil

eff

ecti

ve

per

mea

bil

ity d

am

age

(%)

6

8

10

12

14

16





(a)

(b)



Figure 4.17: (a): Asphaltene content of 1st and 2

nd stage CO2-produced oil, and (b): Oil

effective permeability damage of all cyclic CO2 injection tests performed at various

operating conditions.

102

4.3.9. Tertiary Cyclic CO2 Injection Test

Since in many reservoirs, waterflood residual oil saturation and, in most cases,

gas and solvent injection processes are implemented as a tertiary recovery mode, the oil

recovery of the cyclic CO2 injection process as a tertiary enhanced oil recovery technique

was examined. Thus, a secondary waterflooding test with water injection rate of qw-inj =

0.75 cm3/min at Pop = 3.45 MPa followed by a tertiary miscible cyclic CO2 injection test

at Pop = 9.31 MPa was conducted.

Figure 4.18 depicts the cumulative oil recovery factor, producing GOR, and

producing WOR of a secondary waterflooding test followed by a miscible cyclic CO2

injection test conducted at Pop = 9.31 MPa. The results showed that the waterflooding

process is able to produce 53.9% of original oil in-place (i.e., ultimate RF = 53.9%). It

was also observed that the oil recovery factor at the water break-through is RF = 43.2%

showing that most of the produced oil during waterflooding was recovered before the

water break-through. The producing water-oil ratio (WOR) increased drastically after the

water break-through and reached WOR = 1.68 at the end of the secondary waterflooding

process. The results also indicated that the conducted tertiary miscible CO2 huff-and-puff

test significantly increases the oil production with an extra recovery factor of RF =

16.3%. The ultimate oil recovery factor of RF = 70.2% was achieved by conducting both

secondary waterflooding and tertiary CO2 huff-and-puff tests. The producing water-oil

ratio started to decline gradually during the tertiary CO2 huff-and-puff test, while the

producing gas-oil ratio was significantly increased.

103

Figure 4.18: Cumulative oil recovery factor, producing GOR, and producing WOR

during secondary waterflooding (i.e., conducted at Pop = 3.45 MPa) and tertiary miscible

cyclic CO2 injection (Pop = 9.31 MPa) tests.

Pore volume of injected water and CO2

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

20

40

60

80

Pro

du

cin

g w

ate

r-oil

rati

o (

cm3 o

f w

ate

r /

cm3 o

f oil

)

0.0

0.5

1.0

1.5

2.0

Pro

du

cin

g g

as-

oil

rati

o (

cm3 o

f gas/

cm

3 o

f oil

)

0

500

1000

1500

2000

2500

Oil Recovery factor

Producing WOR

Producing GOR

Secondary waterflooding Tertiary cyclic CO2 injection

104

4.3.10. CO2 Storage during Cyclic Injection Tests

CO2 storage in geological formations such as saline aquifers and depleted

hydrocarbon reservoirs has increasingly gained interest among available methods to

reduce the atmospheric CO2 concentration (Riazi et al., 2011; Zeinali Hasanvand et al.,

2013). It is believed that CO2-EOR processes, particularly the cyclic CO2 injection

process in this study, are not only efficient methods to increase the oil recovery, but also

can be considered as a global warming mitigation option through permanently storing

CO2 underground (Gaspar Ravagnani et al., 2009; Uddin et al., 2013). Therefore, in

addition to the oil recovery efficiency of cyclic CO2 injection tests, the potential of this

technique as a means of CO2 storage at different operating pressures (i.e., in the range of

immiscible to miscible conditions) was also examined. Figures 4.19 through 4.21 depict

the difference between the cumulative injected CO2 and cumulative produced CO2 as

well as the ratios of produced CO2 to injected CO2 and stored CO2 to injected CO2 in

each cycle, for immiscible cyclic injection tests (i.e., Pop = 5.35, 6.55, and 8.27 MPa)

with the injection time and soaking period of Tinj = 120 min and Tsoak = 24 hrs,

respectively. Such graphical analyses for the case of miscible cyclic CO2 injection tests

(i.e., Pop = 9.31 and 10.34 MPa) are also illustrated in Figures 4.22 and 4.23. The results

revealed that there is a significant difference between cumulative injected and produced

CO2 in all cyclic injection tests. This difference is an indication of the outstanding

capacity of cyclic CO2 injection for storing the CO2 in the porous media. The stored CO2

mostly dissolved in the residual oil and connate water in the core and became trapped in

the pore spaces of the core sample.


105

Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Volu

me

of

the

CO

2 (

cm3)

0

1e+4

2e+4

3e+4

4e+4

5e+4

6e+4

Cumulative volume of injected CO2

Cumulative volume of produced CO2

Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Volu

me

rati

o (

cm3/c

m3)

0.0

0.2

0.4

0.6

0.8

1.0

Produced CO2 / Injected CO

2

Stored CO2 / Injected CO

2

(a)

(b)


produced CO2 as well as (b): the ratios of produced CO2 to injected CO2 and stored CO2

to injected CO2 in each cycle for immiscible cyclic CO2 injection test conducted at Pop =

5.35 MPa.

106

Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Volu

me

of

the

CO

2 (

cm3)

0

2e+4

4e+4

6e+4

8e+4

1e+5



Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Volu

me

rati

o (

cm3/c

m3)

0.0

0.2

0.4

0.6

0.8

1.0


2


2

(a)

(b)



to injected CO2 in each cycle for immiscible cyclic CO2 injection test conducted at Pop =

6.55 MPa.

107

Cycle number

0 1 2 3 4 5 6 7 8 9 10

Volu

me o

f th

e C

O2 (

cm3)

0.0

2.0e+4

4.0e+4

6.0e+4

8.0e+4

1.0e+5

1.2e+5

1.4e+5



Cycle number

0 1 2 3 4 5 6 7 8 9 10

Volu

me r

ati

o (

cm

3/c

m3)

0.0

0.2

0.4

0.6

0.8

1.0


2


2

(a)

(b)



to injected CO2 in each cycle for near-miscible cyclic CO2 injection test conducted at Pop

= 8.27 MPa.

108

Cycle number

0 1 2 3 4 5 6 7

Volu

me

of

the

CO

2 (

cm3)

0

1e+4

2e+4

3e+4

4e+4

5e+4

6e+4

7e+4



Cycle number

0 1 2 3 4 5 6 7

Volu

me

rati

o (

cm3/c

m3)

0.0

0.2

0.4

0.6

0.8

1.0


2


2

(a)

(b)



to injected CO2 in each cycle for miscible cyclic CO2 injection test conducted at Pop =

9.31 MPa.

109

Cycle number

0 1 2 3 4 5 6 7

Volu

me

of

the

CO

2 (

cm3)

0

2e+4

4e+4

6e+4

8e+4



Cycle number

0 1 2 3 4 5 6 7

Volu

me

rati

o (

cm3/c

m3)

0.0

0.2

0.4

0.6

0.8

1.0


2


2

(a)

(b)



to injected CO2 in each cycle for miscible cyclic CO2 injection test conducted at Pop =

10.34 MPa.

110

Figure 4.24 shows the retention factor (RtF) for all cyclic CO2 injection tests

implemented at different operating pressures. The retention factor is defined as the

volume of the stored CO2 to the volume of produced oil as given by (Eq. 4.1):

prodo

storedCO

tV

VFR

,

,2 ……………………………… (Eq. 4.1)

It was observed that the retention factor increases in the range of the immiscible

condition and then drastically declines as the operating pressures approaches near

miscibility condition. The retention factor reached the minimum value of RtF = 809.1 at

Pop = 9.31 MPa (i.e., near the MMP of the crude oil–CO2 system). The results also

showed that the retention factor increases with operating pressure beyond the MMP of

the crude oil–CO2 system.

Figure 4.25 indicates the ratios of cumulative produced CO2 to the cumulative

injected CO2 (Gpi) and cumulative stored CO2 to cumulative injected CO2 (Gsi) for cyclic

injection tests. It is seen that the ratio of cumulative produced CO2 to cumulative injected

CO2 continuously decreases from Gpi = 0.61 at Pop = 5.35 MPa to Gpi = 0.52 at Pop =

10.34 MPa in the range of immiscible to miscible conditions. Subsequently, the ratio of

cumulative stored CO2 to cumulative injected CO2 increases from Gsi = 0.39 at Pop = 5.35

MPa to Gsi = 0.48 at Pop = 10.34 MPa in the aforementioned range, indicating that a

greater amount of CO2 can be stored in the porous medium at higher operating pressures.

This is mainly attributed to the higher CO2 solubility and diffusivity in both crude oil and

brine phases as the operating pressure increases. At operating pressure beyond the MMP

of the crude oil–CO2 system, no noticeable change in the amount of stored CO2 was

observed (i.e., Gsi = 0.47 at Pop = 9.31 MPa to Gsi = 0.48 at Pop = 10.34 MPa).

111


5 6 7 8 9 10 11

Ret

enti

on

fact

or

(cm

3 g

as st

ored

/ c

m3 o

il)

700

800

900

1000

1100

1200

1300

1400

Figure 4.24: Retention factor for all cyclic CO2 injection tests performed at different

operating pressures in the range of immiscible to miscible conditions.

112


5 6 7 8 9 10 11Cu

mu

mu

lati

ve p

rod

uce

d C

O2 /

Cu

mu

lati

ve i

nje

cte

d C

O2

0.2

0.3

0.4

0.5

0.6

0.7

0.8

Cu

mu

mu

lati

ve s

tored

CO

2 /

Cu

mu

lati

ve i

nje

cte

d C

O2

0.2

0.3

0.4

0.5

0.6

0.7

0.8Cumumulative produced CO

2/ Cumulative injected CO

2

Cumumulative stored CO2 / Cumulative injected CO

2

Figure 4.25: Ratios of cumulative produced CO2 to the cumulative injected CO2 and

cumulative stored CO2 to cumulative injected CO2 for cyclic CO2 injection tests

performed at different operating pressures in the range of immiscible to miscible

conditions.

113

Figure 4.26 depicts the ultimate oil recovery factor together with the ratio of

cumulative stored CO2 to cumulative injected CO2 of cyclic injection tests conducted at

various operating pressures in the range of immiscible to miscible conditions.

Considering the values of these two parameters at different operating pressures, it can be

observed that the operating pressures near MMP are the optimum conditions for cyclic

CO2 injection process for the purpose of both enhanced oil recovery and CO2 storage.

The ultimate oil recovery factor and the amount of the CO2 that is permanently stored in

the porous medium are near their maximum value at pressures near MMP and further

increase in operating pressure beyond the MMP does not assist the cyclic injection

process effectively either as a means of oil recovery or as a CO2 storage technique.

114


5 6 7 8 9 10 11

Ult

imate

oil

recovery f

acto

r (

%)

20

30

40

50

60

70

Cu

mu

mu

lati

ve s

tored

CO

2 /

Cu

mu

lati

ve i

nje

cte

d C

O2

0.35

0.40

0.45

0.50

0.55Ultimate oil recovery factor

Cumumulative stored CO2 / Cumulative injected CO

2

Figure 4.26: Ultimate oil recovery factor and the ratio of cumulative stored CO2 to

cumulative injected CO2 for cyclic injection tests performed at different operating

pressures in the range of immiscible to miscible conditions.

115


Several cyclic CO2 injection tests were designed and carried out at various

operating conditions and under immiscible, near-miscible, and miscible injection

scenarios. Effects of many parameters including operating pressure, CO2 injection time,

soaking period, connate water saturation, and CO2/propane mixture were investigated. In

addition, the amount of precipitated asphaltene in the core as well as effective oil

permeability damage were determined after termination of cyclic injections.

Compositional analysis also was performed on the remaining oil of CO2 cyclic injection

tests at two pressures in order to determine the mechanism(s) contributing to the oil

recovery process.

Results showed that the oil recovery increases significantly with increased

operating pressure in the range of immiscible to near-miscible cyclic CO2 injections. The

oil recovery reached its maximum value at miscible cyclic CO2 injection, and beyond that

(i.e. Pop > MMP), increase in operating pressure did not improve the recovery process

effectively.

Although it was found that the CO2 injection time seems to be a negligible

parameter in both immiscible and miscible cyclic CO2 injection, the soaking period raised

the oil recovery considerably in the range of immiscible to near-miscible cyclic

injections. However, soaking period did not effectively enhance the oil recovery in

miscible injection processes. According to the experimental results of this study, the

optimum operating conditions in term of CO2 injection time and soaking period for

immiscible cyclic injection was found to be Tinj = 30 min and Tsoak = 48 hr, respectively.

116

However, since a longer soaking period was observed to be almost ineffectual during

miscible cyclic injection, the optimum values of injection time and soaking period for

such condition was determined to be Tinj = 30 min and Tsoak = 24 hr, respectively.

The presence of connate water saturation was a positive parameter that improved

the oil recovery in immiscible cyclic CO2 injection processes, while it was almost

ineffective in miscible cyclic tests.

The precipitated asphaltene in the core as a result of CO2 injection into the system

was substantially higher in near-miscible and miscible cyclic CO2 injection tests than in

immiscible scenarios. Furthermore, due to higher amounts of asphaltene precipitation in

the miscible condition, the oil effective permeability damage of the core was drastically

higher in near-miscible and miscible cyclic CO2 injection tests.

Compositional analysis showed that the remaining oil in cyclic CO2 injection tests

contained higher amounts of heavy components and molecular weight because of

stronger hydrocarbon extraction mechanisms by CO2. Moreover, it was found that in

miscible cyclic CO2 injection tests, the remaining oil is relatively heavier than that in

immiscible cyclic CO2 injection processes since the mechanism of lighter component

extraction by CO2 is much stronger at pressures above MMP.

The considerable difference between the amounts of injected and produced CO2

in cyclic injection tests indicated the outstanding potential of this technique for CO2

storage purposes. The amount of stored CO2 increased with the operating pressure in the

range of immiscible to miscible conditions. At pressures higher than MMP, no significant

gain in efficiency of the CO2 storage process was observed.

117

CHAPTER FIVE

CYCLIC CO2 INJECTION TESTS IN FRACTURED POROUS MEDIUM

In order to investigate the efficiency of the cyclic CO2 injection process in

fractured porous media, a series of cyclic CO2 injection tests was designed and

implemented in artificial fractured media. The experimental results and their analysis are

described in this chapter.

5.1. Experimental Set-up and Configurations of Fractures

The experimental set-up utilized in cyclic CO2 injection tests for fractured system

was exactly the same as that used in the cyclic tests in non-fractured porous medium. The

only difference was in the porous medium so that the conventional Berea core sample

used in previous cyclic CO2 injection tests was exchanged with artificial fractured core

samples. Figure 5.1 shows the different configurations of the artificial fractured media

used as representative of a typical fractured rock for cyclic CO2 injection tests.

118

Figure 5.1: Three different configurations of fractured media. (a): a single horizontal

fracture at the centre of cross section; (b): a single vertical fracture at the middle of the

length; (c): a single horizontal and a single vertical fracture (combination of the two

previous configurations).

119

Table 5.1 presents the petrophysical properties of the three different fractured

systems. It is seen that the absolute permeability of the fractured systems, specifically

configurations (a) and (c) were higher compared to that of non-fractured systems. The

absolute permeability of systems (a) and (c) significantly increased form their initial

values k = 73.9 and 76.6 mD to the final values of kfm = 1685 and 1711 mD, respectively,

after the fracturing process. In contrast with the absolute permeability of the fractured

systems (a) and (c), the absolute permeability of the fractured system with configuration

(b) did not increase when the fracture was generated in the core. The reason is mostly

attributed to the orientation of the fracture in system (b), which was not in the same

direction of the fluid flow inside the porous medium. The orientation of the fracture in

this system (i.e., vertical direction) was perpendicular to the direction of the fluid motion

(i.e., horizontal direction), which did not contribute to the fluid motion. For a

homogeneous matrix-fracture system, the permeability of the fracture plus intact-rock

system (kfm) can be estimated as follows (Parsons 1966; Lucia 1983):

cos12

3

d

wkk mfm ……………………………………… (Eq. 5.1)

where w is the fracture width, d is the fracture spacing, and α is the angle between the

axis of the pressure gradient and the fracture. In the case that the orientation of the

fracture is perpendicular to the direction of the fluid motion and the pressure gradient (i.e.

α = 90° and cos α = 0), the presence of the fracture does not improve the permeability of

matrix-fracture system.

120

Table 5.1: Rock properties and characteristics of the artificial fractured systems.

Configuration (a) (b) (c)

Initial porosity (%) 18.4 19.1 17.8

Initial permeability (mD) 73.9 80.3 76.6

Fracture width (mm) 0.2 0.2 0.2

Fracture Orientation

Angle between the axis of the

pressure gradient and the fracture

(degree)

zero 90 zero (horizontal)

90 (vertical)

Final porosity (%) 18.9 19.1 18.3

Final permeability (mD) 1685 80.3 1711

Fracture porosity (%) 0.5 Negligible 0.5

Fracture permeability (D)* 3374 Negligible ≈ 3374

*12

2wk f (Witherspoon et al., 1980)

121

5.2. Experimental Results and Discussion

A series of cyclic CO2 injection tests was conducted at operating pressures of Pop

= 6.55 MPa (i.e., immiscible condition) and 9.31 MPa (i.e., miscible condition) and

temperature of T = 30 °C. Each of the fractured systems was tested under the two

aforementioned operating pressures in order to determine the role of fracture and its

configuration on the recovery performance of immiscible and miscible cyclic CO2

injection processes. All cyclic CO2 injection tests in the fractured systems were carried

out in a fully original oil saturated porous medium in which no connate water was

present. The CO2 injection time and soaking period were also set to be Tinj = 120 min and

Tsoak = 24 hrs, respectively. The oil production procedure for each test was the same as

that employed in previous cyclic injection tests so that the recovery cycles were

continued until no significant volume of oil was produced. In addition, the amounts of

produced oil and gas were measured in order to determine the stage, cumulative and

ultimate oil recovery factors, producing GOR, and GUF for each test. Table 5.2 presents

the initial and operating conditions for all cyclic CO2 injection tests conducted in

fractured porous media.

122


and solvent) for all secondary cyclic CO2 injection tests.

Test

#

(%)

k

(mD)

Swc

(%)

Soi

(%)

Fracture

configuration

Pop

(MPa)

Tinj

(min)

Tsoak

(hr)

Solvent

21 18.9 1685 0 100 a 6.55 120 24 CO2

22 19.1 80.3 0 100 b 6.55 120 24 CO2

23 18.3 1711 0 100 c 6.55 120 24 CO2

24 18.9 1685 0 100 a 9.31 120 24 CO2

25 19.1 80.3 0 100 b 9.31 120 24 CO2

26 18.3 1711 0 100 c 9.31 120 24 CO2

123

Figure 5.2 and Figure 5.3 depict the cumulative oil recovery factor of immiscible

cyclic CO2 injection tests conducted at Pop = 6.55 MPa in fractured media versus cycle

number and pore volume of injected CO2, respectively. It is clearly shown that the

measured oil recovery factor for the cyclic tests conducted on the fractured systems (a)

and (c) were considerably higher than that performed on the fractured system (b). The

reason is mainly attributed to the orientation of the fracture in the porous media. Since

there is a horizontal fracture in the fractured systems (a) and (c), the CO2 diffusion and

the mass transfer between the oil and solvent significantly improved. As a result, the

main recovery mechanisms, including CO2 solubility, oil swelling, and IFT reduction,

became stronger, leading to the higher oil recovery factor. However, in the case of

fractured system (b), the oil recovery was found to be drastically lower due to the

presence of just one vertical fracture in the system that had no noticeable contribution to

the oil recovery mechanisms.

Figure 5.4 shows the comparison between the oil recovery factors of immiscible

cyclic CO2 injection tests (i.e., Pop = 6.55 MPa) conducted in non-fractured and fractured

porous media. The results indicated that there is a significant increase in oil recovery

factor of cyclic CO2 injection tests conducted in fractured systems (a) and (c) compared

to that implemented in the non-fractured porous medium. However, the oil recovery

performance of cyclic CO2 injection test in the fractured system (b) was almost the same

as that of the test carried out in the non-fractured system.

124

Cycle number

0 1 2 3 4 5 6 7 8 9

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

10

20

30

40

50

60

Configuration (a)

Configuration (b)

Configuration (c)


tests conducted at operating pressure of Pop = 6.55 MPa and in fractured porous medium

with different fracture configuration vs. cycle number.

125


0 1 2 3 4 5

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

10

20

30

40

50

60

Configuration (a)

Configuration (b)

Configuration (c)

0



with different fracture configuration vs. pore volume of injected CO2.

126

Cycle number

0 1 2 3 4 5 6 7 8 9

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

10

20

30

40

50

60

Configuration (a)

Configuration (b)

Configuration (c)

Non-fractured porous medium

Figure 5.4: Comparison between measured cumulative oil recovery factor of immiscible

cyclic CO2 injection tests conducted at operating pressure of Pop = 6.55 MPa and in non-

fractured and fractured porous media.

127

Figure 5.5 shows the stage recovery factors of immiscible cyclic CO2 injection

tests (i.e., Pop = 6.55 MPa) conducted in non-fractured and fractured porous media. The

results show that, against the cyclic injection test conducted in non-fractured porous

medium, the second stage recovery factor of cyclic injection tests in fractured systems (a)

and (c) significantly increased from the first cycle to the second one and then declined in

subsequent cycles. The stage recovery factor of fractured systems (a) and (c) increased

from RF = 13.07% and 13.31% in the first cycle to RF = 15.32% and 16.11% in the

second cycle. This is mainly attributed to the presence of a horizontal fracture inside the

system. As illustrated in Figure 5.6, along the CO2 injection period in the first cycle, CO2

diffuses into the oil and contact with the untouched zone through the diffusion process

which occurs only in the oil phase. During the production of the first cycle, the oil inside

the fracture(s) is completely produced so that the volume of the fracture(s) is completely

filled with CO2 during the injection time of the second cycle. Since the horizontal

fracture is extended to the end of the core, CO2 directly contacts a large portion of the

remaining oil and the impact of the CO2 diffusion through the oil becomes minor.

Therefore, a greater amount of oil is produced during the second cycle compared to the

first cycle. On the other hand, the stage recovery factors continuously declined from the

first cycle during the cyclic CO2 injection test in fractured system (b). This is due to the

presence of a vertical fracture inside the system that cannot increase the direct contact

area between the in-placed oil and CO2. As a result, the trend of the oil production as well

as oil recovery factor were the same as those observed during the cyclic injection test

conducted in the non-fractured porous medium.

128

Cycle number

0 1 2 3 4 5 6 7 8 9

Sta

ge

oil

rec

over

y f

act

or

(%)

0

2

4

6

8

10

12

14

16

18

Configuration (a)

Configuration (b)

Configuration (c)


Figure 5.5: Measured stage oil recovery factors of immiscible cyclic CO2 injection tests

conducted at operating pressure of Pop = 6.55 MPa and in non-fractured and fractured

porous media.

129

Figure 5.6: CO2 diffusion process of cyclic CO2 injection test inside the fractured porous

medium during the first and second cycles.

Direct contact of CO2 with crude oil

Diffusion of CO2 through the oil

phase

(a) CO2 diffusion process during the first cycle

Fracture

Matrix

Matrix

(b) CO2 diffusion process during the second cycle

Fracture

Matrix

Matrix

130

Figure 5.7 and Figure 5.8 depict the cumulative oil recovery factor of miscible

cyclic CO2 injection tests conducted at Pop = 9.31 MPa in fractured media versus cycle

number and pore volume of injected CO2, respectively. The results indicated that like

immiscible tests, the cumulative measured oil recovery factor of the miscible cyclic tests

carried out in fractured systems (a) and (c) is significantly higher than that of miscible

cyclic tests implemented in fractured system (b). As mentioned earlier, the lower oil

recovery of the cyclic CO2 injection test in fractured system (b) is due to the vertical

orientation of the fracture inside the system. Meanwhile in fractured systems (a) and (c),

the horizontal fracture considerably improved the mass transfer phenomena and the

subsequent oil recovery mechanisms (please see Figure 5.6) leading to higher oil

recovery.

The comparison of the oil recovery factors during miscible cyclic CO2 injection

tests (Pop = 9.31 MPa) conducted in the non-fractured porous medium with those of

miscible cyclic tests carried out in the fractured porous media (i.e., fractured systems (a),

(b), and (c)) are illustrated in Figure 5.9. It was observed that although the oil recovery

remarkably increased during the tests performed in fractured systems (a) and (c), there is

no noticeable change between the oil recoveries of cyclic CO2 injection tests conducted

in non-fractured medium and fractured system (b). Figure 5.10 depicts the stage recovery

factors of miscible cyclic CO2 injection tests (i.e., Pop = 9.31 MPa) conducted in non-

fractured and fractured porous media. With the same results during immiscible injection

tests and in contrast with cyclic test conducted in the fractured system (b), the stage

recovery factor increased from the first cycle to the second one during the miscible cyclic

CO2 injection tests in fractured systems (a) and (c).

131

Cycle number

0 1 2 3 4 5 6

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

20

40

60

80

Configuration (a)

Configuration (b)

Configuration (c)



with different fracture configuration vs. cycle number.

132


0.0 0.5 1.0 1.5 2.0

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

20

40

60

80

Configuration (a)

Configuration (b)

Configuration (c)

0



with different fracture configuration vs. pore volume of injected CO2.

133

Cycle number

0 1 2 3 4 5 6

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

20

40

60

80

Configuration (a)

Configuration (b)

Configuration (c)


Figure 5.9: Comparison between measured cumulative oil recovery factor of miscible

cyclic CO2 injection tests conducted at operating pressure of Pop = 9.31 MPa and in non-

fractured and fractured porous media.

134

Cycle number

0 1 2 3 4 5 6

Sta

ge

oil

rec

over

y f

act

or

(%)

0

5

10

15

20

25

30

Configuration (a)

Configuration (b)

Configuration (c)


Figure 5.10: Measured stage oil recovery factors of miscible cyclic CO2 injection tests

conducted at operating pressure of Pop = 9.31 MPa and in non-fractured and fractured

porous media.

135

Figure 5.11 depicts the ultimate oil recovery factor of immiscible (i.e., Pop = 6.55

MPa) and miscible (i.e., Pop = 9.31 MPa) cyclic CO2 injection tests conducted in non-

fractured and fractured porous media using a bar chart plot. It is clearly shown that for

both conditions, the ultimate oil recovery factor was significantly improved during the

cyclic CO2 injection tests in fractured porous media, particularly fractured systems (a)

and (c). For the immiscible injection scenario, the ultimate oil recovery increased from

RF = 34.89% in non-fractured system to RF = 49.49% and 50.37% in fractured systems

(a) and (c), respectively. Similar recovery improvement from RF = 58.35% to RF =

70.74% and 71.62% was found during the miscible cyclic CO2 injection tests when the

porous medium was changed from non-fractured to fractured systems (a) and (c),

respectively. However, the results showed that the ultimate oil recovery factor of the

immiscible cyclic CO2 injection test was enhanced more effectively as the porous

medium changed from non-fractured to fractured; compare to that of the miscible

injection tests. The ultimate recovery factor of the immiscible injection scenario was

increased by almost 42%, which was nearly double the ultimate recovery improvement

during the miscible injection test, indicating that the presence of fracture(s) has a more

positive effect on the oil recovery performance of immiscible cyclic CO2 injection

scenarios. In contrast with fractured systems (a) and (c), the ultimate oil recovery factor

was not noticeably enhanced during the cyclic CO2 injection tests in fractured system (b).

This result was observed for both immiscible and miscible cyclic CO2 injection tests. The

ultimate oil recovery factor of immiscible and miscible cyclic tests was slightly changed

from RF = 34.89% and 58.35% in the non-fractured system to RF = 35.76% and 59.13%

in fractured system (b), respectively.

136

Ult

imate

oil

rec

over

y f

act

or

(%)

0

20

40

60

80P

op = 6.55 MPa

Pop

= 9.31 MPa

Non

-fractu

red

porou

s m

ed

ium

Fractu

red

porou

s m

ed

ium

,

con

fig

urati

on

(a)

Fractu

red

porou

s m

ed

ium

,

con

fig

urati

on

(b

)

Fractu

red

porou

s m

ed

ium

,

con

fig

urati

on

(c)

Figure 5.11: Ultimate oil recovery factor of immiscible (Pop = 6.55 MPa) and miscible

(Pop = 9.31 MPa) cyclic CO2 injection tests conducted in non-fractured and fractured

porous media.

137

The total producing GOR and final GUF of immiscible (i.e., Pop = 6.55 MPa) and

miscible (i.e., Pop = 9.31 MPa) cyclic CO2 injection tests conducted in non-fractured and

fractured porous media are presented in Figure 5.12 and Figure 5.13, respectively. The

results showed that for cyclic injection tests conducted in the non-fractured medium and

fractured system (b), the total producing GOR of the immiscible test is larger than that of

the miscible cyclic CO2 injection tests. The reason is mainly that a higher volume of

injected CO2 was required to achieve the ultimate oil recovery during the immiscible CO2

injection scenario in the aforementioned porous media. On the other hand, the total

producing of GOR of immiscible cyclic injection tests was lower than that of miscible

case during the experiments carried out in fractured systems (a) and (c). Since the number

of cycles to reach the maximum oil recovery in fractured systems (a) and (c) for both

miscible and immiscible injection scenarios was the same, the larger portion of CO2 was

injected into the system during the miscible cyclic CO2 injection tests, which resulted in

higher total producing GOR. Comparison between the final GUF values of cyclic tests in

non-fractured and fractured porous media reveals that for the non-fractured medium and

fractured system (b), the final GUF for miscible injection tests is higher than that of the

immiscible tests. However, for cyclic injection tests implemented in fractured systems (a)

and (c), the final GUF of miscible injection tests was lower than that of the immiscible

cases.

138

Tota

l p

rod

uci

ng

GO

R (

cm3 o

f g

as/

cm3 o

f o

il)

0

200

400

600

800

1000P

op = 6.55 MPa

Pop

= 9.31 MPa

Non

-fra

ctu

red

po

ro

us

med

ium

Fra

ctu

red

po

ro

us

med

ium

,

co

nfi

gu

ra

tio

n (

a)

Fra

ctu

red

po

ro

us

med

ium

,

co

nfi

gu

ra

tio

n (

b)

Fra

ctu

red

po

ro

us

med

ium

,

co

nfi

gu

ra

tio

n (

c)

Figure 5.12: Total producing GOR of immiscible (Pop = 6.55 MPa) and miscible (Pop =

9.31 MPa) cyclic CO2 injection tests conducted in non-fractured and fractured porous

media.

139

Fin

al

GU

F *

10

6 (

cm3 o

f o

il/c

m3 i

nj.

gas)

0

200

400

600

800

1000

1200

1400

1600P

op = 6.55 MPa

Pop

= 9.31 MPa

No

n-f

ract

ure

d

po

rou

s m

ediu

m

Fra

ctu

red

po

rou

s m

ediu

m,

con

fig

ura

tio

n (

a)

Fra

ctu

red

po

rou

s m

ediu

m,

con

fig

ura

tio

n (

b)

Fra

ctu

red

po

rou

s m

ediu

m,

con

fig

ura

tio

n (

c)

Figure 5.13: Final producing GUF of immiscible (Pop = 6.55 MPa) and miscible (Pop =

9.31 MPa) cyclic CO2 injection tests conducted in non-fractured and fractured porous

media.

140


A number of cyclic CO2 injection tests were carried out in different fractured

porous media with different fracture configurations to determine the role of fracture(s) in

the oil recovery performance of cyclic CO2 injection processes. The configurations of the

fractures were clearly shown in Figure 5.1. The operating pressures were selected so that

they covered both immiscible and miscible injection conditions.

The results indicated that the ultimate oil recovery of cyclic CO2 injection tests is

significantly improved in fractured porous media, particularly those contain fractures in

the horizontal direction (i.e., fractured systems (a) and (c)). It was also found that the

impact of fractures on the oil recovery is more noticeable during immiscible cyclic tests

compared to miscible cases. In contrast with non-fractured porous media, it was observed

that the stage recovery factor was increased from the first cycle to the second one in

fractured media mainly due to the stronger mass transfer and CO2 diffusion as a result of

the presence of horizontal fractures in the system.

Implementing the immiscible and miscible cyclic CO2 injection tests on a

fractured porous medium containing a vertical fracture (i.e., fractured system (b))

demonstrated that the vertical fracture does not noticeably contribute to the oil recovery.

The measured oil recovery of a porous medium with a vertical fracture was found to be

almost the same as that of the non-fractured system.

141

CHAPTER SIX

NUMERICAL SIMULATION STUDY

Although having a comprehensive experimental study for any pilot test or field-

scale project is crucial, conducting an accurate lab-scale numerical simulation can

considerably assist the study of hydrocarbon reservoirs as well as forecast their behaviour

and performance under different production phases (i.e., primary, secondary, and tertiary

production phases). In general, there are two reservoir simulation models employed for

simulation studies including the black oil model and the compositional model. In most

EOR studies in which there are phase behaviour interactions between the fluids, the

compositional model is used to simulate the process. In this study, the CMG-WinpropTM

(ver., 2011) module was employed to simulate the single and mutual fluid properties, and

the CMG-GEMTM

(ver., 2011) module was used to simulate the laboratory tests of the

cyclic CO2 injection process.

6.1. Phase Behaviour Simulation

A detailed numerical simulation of the phase behaviour of the original light crude

oil sample and its mutual interaction with solvent (CO2) was carried out using the CMG-

WinpropTM

module from the Computer Modeling Group. The compositional analysis of

crude oil components together with measured experimental data of crude oil density and

viscosity at various temperatures, CO2 solubility, oil swelling factor, and their

142

corresponding saturation pressures (i.e., equilibrium pressures), were used to develop the

PVT model of the system. In order to reduce the number of components and processing

time, the oil components were lumped into six sub-pseudo-components (Cp#1: C1–C3,

Cp#2: C4’s–C8’s, Cp#3: C9’s–C15’s, Cp#4: C16’s–C21’s, Cp#5: C22’s–C29’s, and Cp#6: C30+).

Afterward, the regression analysis on the thermodynamic properties of the six sub-

pseudo-components was conducted to tune the equation of state (EOS) of the PVT model

and accurately calculate and simulate the aforementioned experimental phase behaviour

results. The objective function of the regression involves the solution of complex

nonlinear equations such as flash and saturation-pressure calculations. A robust

minimization method is therefore required for rapid convergence to the minimum. In

Winprop, a modification of the adaptive least-squares algorithm is employed to minimize

the error between experimental and simulated data (Dennis et al., 1981). Table 6.1

presents some of the main properties of the six sub-pseudo-components used to match the

measured PVT properties of crude oil and the crude oil–CO2 system.

The comparison of the experimental values of crude oil density and viscosity at

various temperatures with those calculated via numerical simulation after the regression

analyses are plotted in Figure 6.1. It is shown that there is an acceptable match between

the experimental and simulated values of crude oil density and viscosity. In addition,

Figures 6.2 and 6.3 depict the matched values of saturation pressure and oil swelling

factor vs. the solubility of CO2 in the original crude oil as well as the average error

between the experimental data and simulated values before and after the regression. The

results show that there is a good qualitative and quantitative agreement between the

experimental data and simulated values after the regression. It is worthwhile to note that

143

the numerical simulation results (i.e., PVT properties calculations, recovery data

predictions) with an absolute error of lower than 10% compared to the experimental data

were considered to be an acceptable match in this study.

Once the PR-EOS and PVT models were well tuned using experimental data of

oil density, oil viscosity, CO2 solubility, and oil swelling factor, the MMP of the crude

oil–CO2 system was calculated and found to be MMP = 9.01 MPa at the temperature of T

= 30 °C, which is very accurate compared to the experimental measurement of MMP.

The MMP for crude oil–CO2 obtained by VIT technique and swelling/extraction test

analysis at T = 30 °C were MMPVIT = 9.18 MPa and MMPSF = 8.96 MPa, respectively.

The MMP was matched with the experimental data by adjusting the CO2 interaction

coefficient with pseudo components.

144

Table 6.1: Some of the main properties of the six sub-pseudo-components used to match

the measured PVT properties.

Cp C1–C3 C4’s–C8’s C9’s–C15’s C16’s–C21’s C22’s–C29’s C30+

Composition

(mole %) 2.5 44.3 35.1 10.4 4.84 2.85

Pc (MPa) 4.646 3.216 2.313 1.581 1.214 1.698

Tc (K) 330.780 522.356 650.857 761.420 831.067 805.504

ω 0.11787 0.29143 0.49354 0.75936 0.96131 1.12992

MW (gr/mol) 35.23 89.54 152.78 251.30 334.78 674.40

Volume shift 0.00000 0.00255 0.04699 0.11797 0.19314 -0.77194

SG 0.413 0.702 0.799 0.857 0.888 1.212

δCO2 0.13184 0.09202 0.15483 0.15000 0.15000 0.05917

145

Temperature (oC)

15 20 25 30 35 40 45 50

Cru

de

oil

den

sity

(k

g/m

3)

785

790

795

800

805

810

Experimental values

Simulated values

Temperature (oC)

15 20 25 30 35 40 45 50

Cru

de

oil

vis

cosi

ty (

mP

a.s

)

2.2

2.4

2.6

2.8

3.0

Experimental values

Simulated values

(a)

(b)

Figure 6.1: Comparison between the experimental and simulated values of (a): crude oil

density, and (b): crude oil viscosity after the regression.

146

CO

2

(mole%)

0.0 0.2 0.4 0.6 0.8

Satu

rati

on

pre

ssu

re (

MP

a)

0

2

4

6

8

10

12Psat (Experiment)

Psat (Before regression)

Psat (After regression)

CO

2

(mole%)

0.2 0.3 0.4 0.5 0.6 0.7

Ab

solu

te e

rror(

%)

0

5

10

40

50

60

70

80

AE before regression

AE after regression

(a)

(b)

Figure 6.2: (a): Comparison of simulated saturation pressures with experimental ones at T

= 30 °C before and after the regression, and (b): Error analysis of simulated saturation

pressures compared to the experimental ones before and after the regression.

147

CO2

(mole%)

0.2 0.3 0.4 0.5 0.6 0.7

Ab

solu

te e

rror(

%)

0

5

10

15

20

AE before regression

AE after regression

CO2

(mole%)

0.0 0.2 0.4 0.6 0.8

Oil

sw

elli

ng

fact

or

1.0

1.1

1.2

1.3

1.4

1.5

1.6SF (Experiment)

SF (Before regression)

SF (After regression)

(a)

(b)

Figure 6.3: (a): Comparison of simulated oil swelling factors with experimental ones at T

= 30 °C before and after the regression, and (b): Error analysis of simulated oil swelling

factors compared to the experimental ones before and after the regression.

148

6.2. Lab-scale Simulation of Cyclic CO2 Injection Tests

6.2.1. Simulation Model of Non-fractured Porous Medium

To investigate the potential of miscible and immiscible cyclic CO2 injection

processes in porous media, more specifically the core system in this study, a simulation

model was built in CMG-BuilderTM

module in order to be used as the input reservoir

model in the CMG-GEM™ compositional simulator module. A Cartesian grid system

was employed to build the simulation model, which consisted of one block with the same

size and dimensions as the physical model. The radial, cross-sectional area of the

physical model was converted to the equivalent rectangular area in the simulation model.

The characteristics of the proposed simulation model are presented in Table 6.2. The

fluid and core properties of the physical model were incorporated into the simulation

model. According to the experimental procedure, CO2 was injected from one end of the

core holder system, and then, after a specific period of soaking, the oil was produced

from the same point. Hence, one injector and one producer were considered for the

simulation model and perforated in a single block with coordinates of (20, 2, 2). The

operational constraints for the injector (i.e., CO2 injection pressure, CO2 injection time)

and producer (i.e., producer bottom-hole-pressure, which is equal to the pressure of the

back pressure regulator) in the simulation model were considered to be the same as those

in the laboratory conditions. Figure 6.4 shows the 2-D and 3-D views of the simulation

model used to simulate the cyclic CO2 injection tests in non-porous medium.

All other parameters in CMG-GEM™, including reservoir properties, fluid

components, rock and fluid properties, initial conditions, and well specifications, were

149

specified in order to ensure an accurate simulation run resembling the experimental

conditions. Some modifications such as the addition of well constraints and modification

of time-step size were made in order to prevent some numerical errors that cause an

abnormal termination.

6.2.2. Simulation Model of Fractured Porous Medium

The same procedure was employed to build the simulation model for cyclic CO2

injection tests conducted in fractured porous medium (i.e., fractured system (a)). In order

to include the fracture layer in the model, a layer with different values of porosity and

permeability was defined at the centre of the model. Table 6.3 presents the characteristics

of proposed physical model for the lab-scale simulation in fractured porous medium. The

rock and fluid properties were incorporated into the physical model. In addition, one

injector and one producer perforated in blocks with coordinates of (20, 2, 2), (20, 2, 3),

and (20, 2, 4) were considered for the simulation model. The injection and production

conditions were also adjusted according to the experimental conditions so that a precise

simulation run could be achieved. The 2-D and 3-D views of the simulation model used

to simulate the cyclic CO2 injection tests in fractured porous medium are shown in Figure

6.5.

150


CO2 injection tests conducted in non-fractured porous medium.

Type Cartesian

Porosity (%) 18.5*

Permeability 70.8 mD**

No. of grid (i×j×k) 20×3×3

Block width (i,j,k) 1.5105 cm, 1.492 cm, 1.492 cm

Swc (%) 44.7***

Length 30.21 cm

Cross-sectional area 20.03 cm2

Pore volume 111.97 cm3

* Porosity is subject to change for each test (a value in the range of 18.3–18.7%)

** Permeability is subject to change for each test (a value in the range of 70.5–71.4 mD)

*** Swc is subject to change for each test (a value in the range of 0–45.9%)

151

Figure 6.4: (a): 3-D view and (b): 2-D view (i.e., x-y direction) of proposed physical

model for lab-scale simulation of cyclic CO2 injection tests conducted in non-fractured

porous medium (The injector and producer were located and perforated in a single

location).

152


CO2 injection tests conducted in fractured porous medium.

Type Cartesian

Matrix porosity (%) 18.4

Matrix permeability 73.9 mD

Fracture porosity (%) 0.99

Fracture permeability 3374 D

No. of grid (i×j×k) 20×3×5

Matrix dimension (i,j,k) 1.509 cm, 1.492 cm, 1.119 cm

Fracture dimension (i,j,k) 1.509 cm, 1.492 cm, 0.02 cm

Length 30.18 cm

Cross-sectional area 20.07 cm2

Pore volume 112.52 cm3

153

Figure 6.5: (a): 3-D view and (b): 2-D view (i.e., x-z direction) of proposed physical

model for lab-scale simulation of cyclic CO2 injection tests conducted in fractured porous

medium, specifically fractured system (a) with one horizontal fracture (The injector and

producer were located and perforated in a single location).

154

6.3. History Matching and Comparison of Numerical Simulation Results with

Experimental Study

6.3.1. History Matching Parameters

This study represents an attempt to obtain a reasonable and appropriate history

match between the recovery factor and production data from the simulation and

laboratory experiments. The water–oil and liquid–gas relative permeability curves

together with the molecular diffusion coefficient of CO2 were tuned to history match the

oil recovery factors obtained in laboratory cyclic CO2 injection tests. The tuned water–oil

and liquid–gas relative permeability curves used to history match the experimental

recovery factors of cyclic CO2 injection tests are plotted in Figure 6.6.

The Sigmund equation (Sigmund, 1976) was used to calculate the molecular

diffusion of CO2 in the oil phase. The binary diffusion coefficient between components i

(i.e., CO2) and j (i.e., hydrocarbon component) in the mixture is:

32 032874.022035.0096016.099589.0 krkrkr

k

oij

ok

ij

DD

……… (Eq. 6.1)

In which:

n

i

ciik

n

i

ciik

kkr

vy

vy

1

3/2

1

3/5

……… (Eq. 6.2)

2/1

2

2/1 110018583.0

jiijij

oij

ok

MMR

TD

……… (Eq. 6.3)

155

Figure 6.6: Tuned water–oil and liquid–gas relative permeability curves used to history

match the experimental recovery factors of cyclic CO2 injection tests.

156

The diffusion of component i in the mixture (i.e., crude oil) can be calculated as given:

The collision diameter (σij) and the collision integral (Ωij) are related to the critical

properties of components as follows (Reid et al., 1977):

In the above equations, kB is the Boltzmann’s constant which is 16103805.1 Bk erg/K.

In order to obtain a more accurate understanding of molecular diffusion of CO2,

the molecular diffusion was also calculated using the Renner equation (Renner, 1988)

which is given as follows:

ij

ijik

ikik

Dy

yD

1

1

……… (Eq. 6.5)

3/1

087.03551.2

ci

ciii

P

T ……… (Eq. 6.6)

ciiBi Tk 1963.07915.0 ……… (Eq. 6.7)

2

ji

ij

……… (Eq. 6.8)

jiij ……… (Eq. 6.9)

ij

Bij

kT

* ……… (Eq. 6.10)

*

*

*15610.0*

89411.3exp76474.1

52996.1exp03587.1

47635.0exp19300.006306.1

ij

ij

ijijij

T

T

TT

……… (Eq. 6.11)

157

In (Eq. 6.12), D is the diffusivity coefficient of CO2 in the crude oil (m2/sec),

2CO is the viscosity of CO2 (cP) at the equilibrium pressure and temperature, Mo is the

molecular weight of the crude oil (g/mol), 2COv is the molar volume of CO2 (cm

3/mol) at

the experimental condition, P is the pressure of crude oil–CO2 system in equilibrium

condition (Psia), and T is the temperature of the crude oil–CO2 system in equilibrium

condition (K). The diffusivity of CO2 in the brine was also estimated using the following

equations (Al-Rawajfeh, 2004):

In which:

wCOD ,2and bCOD ,2

are the diffusion coefficient of the CO2 in distilled water and brine,

respectively.

6.3.2. Non-fractured Porous Medium

Figures 6.7 through 6.9 depict the comparison of simulated ultimate recovery

factors with the experimental measurements for immiscible (Test # 2: Pop = 5.38 MPa),

near-miscible (Test # 9: Pop = 8.27 MPa), and miscible (Test # 16: Pop = 10.34 MPa)

9524.4831.1706.16869.04562.010

22

TPvMD COoCO ……… (Eq. 6.12)

2

5

,

105907.252.7121764.4

2 TTDLog wCO ……… (Eq. 6.13)

w

b

wCO

bCOLog

D

DLog

87.0

,

,

2

2 ……… (Eq. 6.14)

158

cyclic CO2 injection tests conducted in non-porous medium, respectively. Accordingly, it

can be seen that although there is some difference between the simulation and

experimental data, overall, the simulation results are in good qualitative and quantitative

agreement with the experimental ones and in some cases, are identical to the results

obtained in laboratory tests. The differences are likely due to some laboratory operating

conditions and phase behaviour of rock–fluid(s) and fluid–fluid that could not be

completely captured by the simulation process.

The difference between the experimental and simulated values of cumulative oil

recovery factor of the selected cyclic CO2 injection tests in the non-porous medium are

also shown in Figures 6.7–6.9. It was found that the simulation results of immiscible

cyclic CO2 injection scenarios have relatively more accurate predictions than those of the

near-miscible and miscible cyclic CO2 injection tests. This could be attributed to the

change in experimental conditions from immiscible to near-miscible and miscible cases.

As was mentioned earlier, the phase behaviour of CO2 and oil and the interaction

between them in miscible conditions is more complex than in immiscible conditions, and,

accordingly, more operating parameters and mechanisms affect the miscible injection

process. Therefore, it seems that the simulation of near-miscible and miscible cyclic CO2

injection processes is more complicated than that of immiscible ones.

159

Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

5

10

15

20

25

30

35

Experiment

Simulation

(a)

Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Dif

fere

nce

bet

wee

n

exp

erim

enta

l an

d s

imu

late

d

cum

ula

tive

oil

rec

over

y f

act

or

(%)

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0(b)


cycle number, and (b): the difference between experimental and simulated cumulative oil

recovery factor after completion of each cycle, for cyclic CO2 injection test at immiscible

condition in non-fractured porous medium, Pop = 5.38 MPa (i.e., Test # 2).

160

Cycle number

0 1 2 3 4 5 6 7 8 9 10

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

10

20

30

40

50

60

Experiment

Simulation

(a)

Cycle number

0 1 2 3 4 5 6 7 8 9 10

Dif

fere

nce

bet

wee

n

exp

erim

enta

l an

d s

imu

late

d

cum

ula

tive

oil

rec

over

y f

act

or

(%)

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2.5(b)



recovery factor after completion of each cycle, for cyclic CO2 injection test at near-

miscible condition in non-fractured porous medium, Pop = 8.27 MPa (i.e., Test # 9).

161

Cycle number

0 1 2 3 4 5 6 7

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

10

20

30

40

50

60

70

Experiment

Simulation

(a)

Cycle number

0 1 2 3 4 5 6 7

Dif

fere

nce

bet

wee

n

exp

erim

enta

l an

d s

imu

late

d

cum

ula

tive

oil

rec

over

y f

act

or

(%)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5(b)



recovery factor after completion of each cycle, for cyclic CO2 injection test at miscible

condition in non-fractured porous medium, Pop = 10.34 MPa (i.e., Test # 16).

162

6.3.3. Fractured Porous Medium

The experimental cumulative oil recovery factors of immiscible (Pop = 6.55 MPa)

and miscible (Pop = 9.31 MPa) cyclic CO2 injection tests conducted in fractured porous

medium (i.e., fractured system (a)) were also simulated and the results are illustrated in

Figure 6.10 through Figure 6.11, respectively. According to the obtained results, the

difference between the experimental and simulated cumulative oil recovery factors of

cyclic CO2 injection tests carried out in fractured porous medium was greater than that of

cyclic tests conducted in non-fractured porous medium. However, there still exists a

reasonable match between the experimental and simulated oil recovery factors during

tests in fractured porous medium. The higher discrepancy during the simulation of cyclic

CO2 injection in the fractured porous medium is mainly attributed to the presence of

higher heterogeneity (co-presence of matrix and fracture) in the porous medium. Since

the heterogeneity in the structure of the porous medium affects the interactions of fluid-

rock and fluid-fluid systems together with the production mechanisms, it is more difficult

to catch all aspects of the experimental process during the numerical simulation.

163

Cycle number

0 1 2 3 4 5 6 7 8

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

10

20

30

40

50

60

Experiment

Simulation

(a)

Cycle number

0 1 2 3 4 5 6 7 8

Dif

fere

nce

bet

wee

n

exp

erim

enta

l an

d s

imu

late

d

cum

ula

tive

oil

rec

over

y f

act

or

(%)

0

1

2

3

4

5

6(b)



recovery factor after completion of each cycle for cyclic CO2 injection test at immiscible

condition in fractured porous medium, Pop = 6.55 MPa (i.e., Test # 21).

164

Cycle number

0 1 2 3 4 5 6

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

20

40

60

80

Experiment

Simulation

(a)

Cycle number

0 1 2 3 4 5 6

Dif

fere

nce

bet

wee

n

exp

erim

enta

l an

d s

imu

late

d

cum

ula

tive

oil

rec

over

y f

act

or

(%)

0

1

2

3

4

5

6(b)



recovery factor after completion of each cycle for cyclic CO2 injection test at immiscible

condition in fractured porous medium, Pop = 9.31 MPa (i.e., Test # 24).

165

6.4. Parametric Study on Fracture Properties

As shown earlier through the experimental tests and numerical simulation, the

presence of the fracture has a significant influence on the performance of cyclic CO2

injection process. It was illustrated that the horizontal fracture considerably improves the

oil recovery during both immiscible and miscible cyclic CO2 injection techniques.

However, there are some other fracture properties (e.g., fracture width, number of

fracture) that may affect the efficiency of oil recovery during the cyclic injection process.

In this section, the impacts of fracture width and number of horizontal fractures on the oil

recovery performance of cyclic CO2 injection were determined through the numerical

simulation. Since the experimental phase behaviour and cyclic injection tests were

appropriately simulated with an agreeable accuracy and the physical model was tuned

well, it is possible and reasonable to identify the effects of other fracture characteristics

by this simulation technique.

6.4.1. Effect of the Fracture Width

The width of the fracture is a parameter that directly contributes to the fluid flow

inside the fracture since the permeability of a fracture is a function of fracture width. In

this study, different values in the range of w = 0.01–0.05 cm were considered as the

fracture width to investigate the effect of this parameter on oil recovery in cyclic CO2

injection tests. The other properties such as matrix permeability, PVT properties, and

operating conditions were kept the same as those of the previous simulations so that the

impact of the fracture width was determined more specifically.

166

The impact of the fracture width on the oil recovery performance of immiscible

and miscible cyclic CO2 injection processes are depicted in Figure 6.12 and Figure 6.13,

respectively. In general, the simulation results showed that the cumulative oil recovery

factor during immiscible and miscible cyclic CO2 injections increases as the width of the

fracture becomes larger. The simulated ultimate oil recovery factor of the cyclic CO2

injection process for both immiscible and miscible scenarios as a function of fracture

width is plotted in Figure 6.14. It was found that the ultimate oil recovery factor increases

from RF = 48.37% with the fracture width of w = 0.01 cm to RF = 52.33% with the

fracture width of w = 0.05 cm during the immiscible cyclic CO2 injection process (i.e.,

Pop = 6.55 MPa). For the miscible CO2 injection scenario (i.e., Pop = 9.31 MPa), the

ultimate oil recovery factor increased from RF = 68.97% to 75.70% when the fracture

width increased from w = 0.01 cm to 0.05 cm. Considering the simulation results shows

that the cyclic CO2 injection process benefits from the larger fracture width in the porous

media. It was also found that the ultimate oil recovery factor is not noticeably improved

when the fracture width increased to w = 0.04 cm and 0.05 cm, indicating that this

parameter is required to be optimized during the field-scale simulation in order to reduce

the operational costs of the fracturing process. Out of the obtained simulation results and

for the experimental conditions in this study, a fracture width of w = 0.03 cm was found

to be the optimum fracture width to enhance the oil recovery performance during the

cyclic CO2 injection process.

167

Cycle number

0 1 2 3 4 5 6 7 8

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

10

20

30

40

50

60

w = 0.01 cm

w = 0.02 cm

w = 0.03 cm

w = 0.04 cm

w = 0.05 cm


process (i.e., Pop = 6.55 MPa) vs. cycle number in a single horizontal fractured medium at

various fracture widths.

168

Cycle number

0 1 2 3 4 5 6

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

20

40

60

80

w = 0.01 cm

w = 0.02 cm

w = 0.03 cm

w = 0.04 cm

w = 0.05 cm


process (i.e., Pop = 9.31 MPa) vs. cycle number in a single horizontal fractured medium at

various fracture widths.

169

Fracture width (cm)

0.00 0.01 0.02 0.03 0.04 0.05 0.06

Ult

imate

oil

rec

over

y f

act

or

(%)

45

50

55

65

70

75

80

Immiscible cyclic CO2 injection

Miscible cyclic CO2 injection

Figure 6.14: Effect of the fracture width on the ultimate oil recovery factor of the

immiscible and miscible cyclic CO2 injection processes.

170

6.4.2. Effect of the Number of Fractures

In addition to the fracture width, the number of fractures in the porous medium is

a parameter that may significantly affect the performance of cyclic injection processes.

The presence of more fractures in the porous medium results in the increase of surface

area allowing direct contact of CO2 with the oil in-place. As a result, the oil recovery

mechanisms are stronger, leading to higher oil recovery. The impact of the number of

fractures on the performance of immiscible and miscible cyclic CO2 injection processes

in fractured porous media was studied through the numerical simulation. The number of

horizontal fractures was varied from n = 1 to 4 in the simulation model to examine the

effect of this parameter on oil recovery.

Figure 6.15 and Figure 6.16 shows the effect of the number of horizontal fractures

on the oil recovery of immiscible and miscible cyclic CO2 injection tests in fractured

porous medium, respectively. The simulation results illustrated that the presence of more

horizontal fractures in the porous medium effectively improves the oil recovery during

the cyclic CO2 injection process. In addition, Figure 6.17 depicts the simulated ultimate

oil recovery factors versus the number of fractures for both immiscible and miscible

cyclic CO2 injection scenarios. For immiscible conditions (i.e., Pop = 6.55 MPa), the

ultimate oil recovery factor increased from RF = 50.75% with one horizontal fracture to

RF = 53.94% with four horizontal fractures. It was also found that the oil recovery was

improved from RF = 72.71% to RF = 77.54% when the number of horizontal fractures

was increased from one to four during miscible cyclic CO2 injection (i.e., Pop = 9.31

MPa).

171

Cycle number

0 1 2 3 4 5 6 7 8

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

10

20

30

40

50

60

n = 1

n = 2

n = 3

n = 4


process (i.e., Pop = 6.55 MPa) vs. cycle number in a fractured medium with different

number of fractures.

172

Cycle number

0 1 2 3 4 5 6

Cu

mu

lati

ve

oil

rec

over

y f

act

or

(%)

0

20

40

60

80

100

n = 1

n = 2

n = 3

n = 4


process (i.e., Pop = 9.31 MPa) vs. cycle number in a fractured medium with different

number of fractures.

173

Number of fractures

0 1 2 3 4 5

Ult

imate

oil

rec

over

y f

act

or

(%)

45

50

55

65

70

75

80

Immiscible cyclic CO2 injection

Miscible cyclic CO2 injection

Figure 6.17: Effect of the number of fractures on the ultimate oil recovery factor of

immiscible and miscible cyclic CO2 injection process.

174

The simulation results also demonstrated that the ultimate oil recovery factor was

not noticeably improved when the number of fractures in the porous medium increased

from n = 3 to 4. It was observed that n = 3 is the optimum number of fracture for this

study to achieve the highest ultimate oil recovery factor. It is noteworthy to mention that

for a field-scale simulation study, the number of fractures is required to be optimized for

any fracturing process near the well-bore.


Numerical simulation of cyclic CO2 injection tests carried out in non-fractured

and fractured porous media and at immiscible, near-miscible, and miscible conditions

was conducted using the CMG software (ver., 2011). The simulation procedure consisted

of three main parts. In the first part, the PVT model of the original crude oil sample was

generated by the CMG-WinpropTM

module. The crude oil was characterized, and its

components were lumped into six sub-pseudo-components. Thereafter, regression

analysis was performed on the measured PVT data including crude oil density and

viscosities, CO2 solubility, oil swelling factor, and their corresponding saturation

pressures in order to tune the EOS.

In the second part, a simulation model for the non-fractured as well as for the

fractured core system was built with CMG-BuilderTM

module and employed as an input

reservoir model in the CMG-GEM™ compositional simulator module.

In the last part, the history matching process was implemented in order to match

the simulated data with the experimental data obtained in cyclic CO2 injection tests. The

175

water–oil and liquid–gas relative permeability curves as well as molecular diffusion

coefficient of CO2 were tuned in the history matching process.

The results of the simulation study showed that, firstly, the PVT model was

regressed and the proposed EOS tuned suitably as well since it was able to simulate the

measured data of saturation pressure and oil swelling factor with reasonable accuracy

(i.e., AE < 10%). In addition, the simulated results of oil recovery factors for cyclic CO2

injection tests conducted in non-fractured and fractured porous media were appropriately

matched with the experimental ones, and there exists proper agreement between them

(i.e., AE < 10%). In addition, a parametric study on the fracture width and the number of

fractures was carried out to determine the impact of these parameters on the oil recovery

of the cyclic CO2 injection process. It was found that the ultimate oil recovery of both

immiscible and miscible cyclic CO2 injection processes was improved with larger

fracture width and the presence of more fractures inside the porous media. However, such

parameters are required to be optimized for any field-scale simulation study.

176

CHAPTER SEVEN

CONCLUSIONS AND RECOMMENDATIONS

7.1. Conclusions

In the present study, the performance of the cyclic CO2 injection process in non-

fractured and fractured porous media for the purpose of enhanced oil recovery was

experimentally investigated. A detailed phase behaviour study on the original light crude

oil sample together with a comprehensive study on the mutual interactions of crude oil–

CO2 and brine–CO2 systems were carried out. Thereafter, several cyclic CO2 injection

tests were designed and performed at different operating conditions and under

immiscible, near-miscible, and miscible scenarios in non-fractured and fractured porous

media. The role of several parameters including operating pressures (Pop), CO2 injection

time (Tinj), soaking period (Tsoak), connate water saturation (Swc), and CO2/propane

mixture on the performance of cyclic CO2 injection tests were experimentally

determined. In addition, the asphaltene precipitation inside the porous medium due to

CO2 injection into the core and the consequent permeability damage were investigated.

The recovery mechanisms contributing to the CO2-oil recovery during immiscible and

miscible conditions were also examined by the compositional analysis of the remaining

crude oil inside the core. Moreover, a numerical simulation on the phase behaviour and

CO2 injection tests were conducted via CMG software (ver., 2011). The followings are

the conclusions drawn according to the results of the aforementioned studies:

177

Phase behaviour study

1) The CO2 solubility in the crude oil (χCO2) and the resulting oil swelling factor

(SF) increased with the equilibrium pressure (Peq) up to the extraction

pressure (Pext). At equilibrium pressures beyond the extraction pressure, the

oil swelling factor drastically declined. In addition, the solubility of the CO2

and the oil swelling factor were found to be relatively lower at higher

temperatures than those at lower temperature.

2) The dynamic and equilibrium interfacial tension (IFTdyn and IFTeq) of the

crude oil–CO2 system was measured by ADSA technique at various

equilibrium pressures. It was observed that the dynamic IFT decreases

significantly faster at equilibrium pressures higher than extraction pressure

and quickly reached the equilibrium IFT. The equilibrium IFT was also

significantly reduced with increased equilibrium pressure in two distinct

pressure ranges.

3) The CO2 extraction pressure for the crude oil–CO2 system was determined via

both oil swelling and equilibrium IFT curves and found to be Pext = 6.79 MPa

and 6.84 MPa, respectively, at T = 30 °C. The determined extraction pressure

obtained with the two approaches was almost identical and confirmed each

other. In addition, it was seen that there are two main mechanisms

contributing to the phase behaviour of the crude oil–CO2 system, which acted

in discrete ranges of pressure. In the range of pressure lower than extraction

pressure, oil swelling is the main mechanism acting in the crude oil–CO2

178

system while at pressures beyond the CO2 extraction pressure, the extraction

of lighter crude oil components by CO2 is the governing mechanism

associated with the crude oil–CO2 system.

4) The MMP between crude oil and CO2 was determined using two different

approaches: the oil swelling/extraction data and by applying the VIT

technique on the measured equilibrium IFTs. Again, it was found that the

MMPs obtained by the two methods are almost identical. The determined

MMP of the crude oil–CO2 system by employing the swelling/extraction data

and equilibrium IFTs values at T = 30 °C was MMPSF = 8.96 MPa and

MMPVIT = 9.18 MPa, respectively.

5) The solubility of the CO2 in the sample brine (χ'CO2) was also measured at two

different temperatures, and it was found that the CO2 solubility increases with

increased pressure; however, at high equilibrium pressures near the CO2

liquefaction pressure, the CO2 solubility in brine was almost independent of

the pressure.

Cyclic CO2 injection

1) Several cyclic CO2 injection tests were conducted in a non-fractured porous

medium and at various operating pressures ranging from Pop = 5.38–10.34

MPa so that they covered immiscible to miscible conditions. It was seen that

in the immiscible to near-miscible range of operating pressures, the oil

recovery factor increases significantly with the pressure. The oil recovery

179

factor reached nearly its maximum value at the miscible condition and further

increase of operating pressure beyond the MMP did not result in noticeable

increase in oil recovery factor.

2) The effect of CO2 injection time (Tinj) on the performance of cyclic injection

was studied, and it was found that the longer CO2 injection time did not

effectively increase the oil recovery factor. This is mainly because of the

limited physical size of the experimental model. Since the physical size of the

core system was very limited compared to a practical case and it was

becoming nearly saturated with the CO2 in a short period of injection, increase

of this parameter did not affect the recovery factor. However in a real field

case, CO2 injection time may have a positive influence on the recovery factor

obtained by cyclic CO2 injection.

3) Longer soaking period (Tsoak) significantly enhanced the oil recovery

especially during immiscible and near-miscible cyclic CO2 injection tests.

Longer soaking period in the cyclic injection process provides the opportunity

for CO2 to diffuse into the oil phase to a greater degree, and a larger volume

of oil in-place is recovered from the core. It was also found that soaking

period does not increase the oil recovery during miscible injection tests.

4) The effect of connate water saturation (Swc) on the oil recovery of the cyclic

CO2 injection process was also determined. The results indicated that the

cyclic injection benefits from the presence of connate water saturation during

the immiscible CO2 injection tests. However, it was observed that the oil

180

recovery factor during miscible conditions was almost independent of connate

water saturation.

5) The effect of the CO2/propane mixture as an injected solvent in cyclic

injection tests was also experimentally investigated. It was found that a

mixture of CO2 and propane has a greater potential to recover the oil in-place

during cyclic injection scenarios at lower operating pressures compared to the

pure CO2.

6) Since the asphaltene precipitation phenomenon is a major operational problem

in the CO2-based EOR techniques, the precipitated amount of asphaltene as a

result of CO2 injection was measured during immiscible, near-miscible, and

miscible conditions. It was found that the asphaltene content of the CO2-

produced oil for miscible injection tests was significantly lower than that of

immiscible ones, which conversely showed that the precipitated amount of

asphaltene in the core is higher in miscible cyclic CO2 injection tests. In

addition, due to the heavier asphaltene precipitation in the miscible cyclic CO2

injection tests, the permeability reduction was drastically higher during

miscible injection tests than that during immiscible cyclic CO2 injection tests.

7) The compositional analysis of the remaining crude oil after termination of two

selected cyclic CO2 injection tests (Pop = 6.55 MPa and 9.31 MPa) showed

that the extraction of lighter components of crude oil by CO2 is much stronger

during miscible cyclic CO2 injection tests (i.e., Pop = 9.31 MPa) than that

during immiscible cyclic tests (i.e., Pop = 6.55 MPa). The remaining crude oil

181

obtained from miscible cyclic CO2 injection tests contained a higher fraction

of C30+ as well as molecular weight compared to those from remaining crude

oil of immiscible cyclic tests.

8) The significant difference between the injected CO2 and produced CO2 shows

remarkable capacity for the cyclic CO2 injection process to store CO2 in the

porous spaces of oil reservoirs. It was also observed that operating pressure

near the MMP of the crude oil–CO2 system is the optimum pressure to

achieve the highest efficiency for CO2 storage.

9) The measured oil recovery factor during the cyclic CO2 injection tests in

fractured porous media revealed that the presence of fracture(s) inside the

rock significantly improves the oil recovery. Additionally, it was found that

the immiscible cyclic CO2 injection tests benefit more from the presence of

fracture(s) compared to miscible cyclic scenarios. The presence of fracture(s)

in the porous media increases the contact area between the injected CO2 and

the oil in-place resulting in the diffusion of CO2 into the larger portion of the

reservoir and a higher volume of crude oil can be produced.

10) The results of cyclic CO2 injection tests in fractured porous media also

showed that the orientation of the fracture plays a key role in the performance

of this process. A horizontal fracture(s) considerably increases the oil

recovery during cyclic CO2 injection process. On the other hand, it was

observed that a vertical fracture(s) has very limited contribution to the oil

182

recovery unless the vertical fracture(s) are connected to each other through a

horizontal fracture(s).

11) The phase behaviour test results were used to regress and tune the PVT model

of the crude oil. The cyclic CO2 injection tests in non-fractured and fractured

porous media were also simulated using the CMG software (ver., 2011), and

the relative permeability curves together with molecular diffusion coefficient

of CO2 were employed to history match the experimental data. Comparison of

simulated results with experimental ones showed that there exists appropriate

agreement between the simulation and experimental data.

12) The parametric study on the fracture width showed that larger fracture width

improves the oil recovery of the cyclic CO2 injection process. In addition, the

presence of more fractures, particularly horizontal fractures, is a beneficial

parameter to enhance the performance of cyclic CO2 injection tests in

fractured porous media. It is also worthwhile to mention that the two

aforementioned parameters need to be optimized for any field-scale studies.

183

7.2. Recommendations

Based on the results of this research, the following are recommended for future

studies:

1) Conducting the cyclic CO2 injection tests in a larger-scale experimental model

in order to accurately investigate the impact of operating parameters,

particularly CO2 injection time and injection rate, on the oil recovery of this

process. In addition, pressure decline during the production period may

effectively have an impact on the production mechanisms. Hence, it is also

recommended to use a flow rate controller during production from a larger

size model to determine the possible effect of pressure decline during the puff

cycle.

2) Since heterogeneity in the reservoir is a parameter that affects the

performance of cyclic injection processes, an attempt should be made to study

this topic, preferably through the analysis of micro-model experiments with

diverse heterogeneous patterns.

3) The impact of the connectivity of the fractures (i.e., fracture network) in

porous media on the recovery efficiency of the cyclic CO2 injection process

should be examined.

184

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204

APPENDIX A

THE STANDARD ASTM D2007-03 METHOD TO MEASURE ASPHALTENE

CONTENT

The following procedure is used to measure the asphaltene content of an oil

sample by utilizing the standard ASTM D2007-03 method. This standard is issued under

the fixed designation D 2007 “Standard Test Method for Characteristic Groups in

Rubber Extender and Processing Oils and Other Petroleum-Derived Oils by the Clay-Gel

Absorption Chromatographic Method”.

Step 1: Weigh 10 ± 0.5 g of the sample to the nearest 0.5 mg in a pre-weighed 250 mL

conical flask, add 100 mL of n-pentane and mix well. Warm the mixture in a warm water

bath for a few seconds with intermittent swirling to hasten solution. Allow the mixture to

stand about 30 min at or near room temperature. Samples containing a high content of

insolubles may require more agitation to dissolve the n-pentane-soluble portion. In such

cases, use a stirring rod, together with intermittent warming and swirling to hasten

solution of the sample. Solution should be cooled to room temperature before filtering.

Step 2: Set up a filtering assembly, using a 500-mL flask, a 125 mm borosilicate filtering

funnel equipped with a folded rapid 15 cm filter paper, and filter the sample. Rinse the

conical flask and stirring rod with 60 mL n-pentane, and pour the rinse through the paper

filter.

205

Step 3: Rinse the filter paper and contents with 60 mL of n-pentane in small portions

from a dispensing bottle, taking care to rinse down the sides of the filter paper.

Step 4: Transfer the solution to an anti-creep beaker in portions and evaporate the n-

pentane on a hot plate at a temperature of 100–105 °C. Rinse the flask with small

portions of n-pentane, adding these rinsings to the anti-creep beaker. n-Pentane shall be

considered removed when the change in weight is less than 10 mg in 10 min at this

temperature. Slow nitrogen flows over the beaker can be used to assist the evaporation,

but rapid stirring by the gas should be avoided.

Step 5: Weigh the recovered oil. The weight of sample minus the weight of the oil is the

asphaltenes content.

More information can be obtained through: ASTM D2007-03: “Standard test method for

characteristics groups in rubber extender and processing oils and other petroleum-derived

oils by the clay–gel absorption chromatographic method. West Conshohocken (PA)”,

ASTM International, 2007.

206

APPENDIX B

EXPERIMENTAL RESULTS OF ALL CYCLIC CO2 TESTS IN NON-

FRACTURED POROUS MEDIA

In this Appendix, the experimental results of all cyclic CO2 injection tests carried

out at the operating pressures Pop = 5.38–10.34 MPa are shown graphically. The

incremental and cumulative recovery factors as a function of cycle number and pore

volume of injected CO2 as well as incremental and cumulative producing GOR and GUF

of all tests are plotted in the following figures. The bar charts are also used to compare

the ultimate, first, and second stage oil recoveries, asphaltene content of CO2-produced

oil (Wasph), and oil effective permeability damage (DFo) for the cyclic CO2 tests

performed at each operating pressure.

207

Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Cu

mu

lati

ve

reco

ver

y f

act

or

(%)

0

10

20

30

40

50

60

Sta

ge

reco

ver

y f

act

or

(%)

0

2

4

6

8

101

Cum. RF (T # 1)2

Cum. RF (T # 2)3

Cum. RF (T # 3)4

Cum. RF (T # 4)5

Cum. RF (T # 5)

1Stage RF (T # 1)

2Stage RF (T # 2)

3Stage RF (T # 3)

4Stage RF (T # 4)

5Stage RF (T # 5)


0 1 2 3 4 5 6 7 8

Cu

mu

lati

ve

reco

ver

y f

act

or

(%)

0

10

20

30

40

50

60

Sta

ge

reco

ver

y f

act

or

(%)

0

2

4

6

8

101

Cum. RF (T # 1)2

Cum. RF (T # 2)3

Cum. RF (T # 3)4

Cum. RF (T # 4)5

Cum. RF (T # 5)

1Stage RF (T # 1)

2Stage RF (T # 2)

3Stage RF (T # 3)

4Stage RF (T # 4)

5Stage RF (T # 5)

(a)

(b)

1 Test # 1 (Tinj = 30 min, Tsoak = 24 hrs, Swc = 44.7 %)



4 Test # 4 (Tinj = 120 min, Tsoak = 48 hrs, Swc =45.8 %)

5 Test # 5 (Tinj = 120 min, Tsoak = 24 hrs, Swc is zero)


volume of injected CO2 for cyclic CO2 injection tests performed at Pop = 5.38 MPa.

208

Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Cu

mu

lati

ve

pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f oil

)

0

200

400

600

800

1000

1200

1400

1600

Cu

mu

lati

ve

GU

F (

cm3 o

f oil

/cm

3 o

f gas)

0.0001

0.001

0.01

0.1

1

101

Cum. GOR (T # 1)2

Cum. GOR (T # 2)3

Cum. GOR (T # 3)4

Cum. GOR (T # 4)5

Cum. GOR (T # 5)

1Cum. GUF (T # 1)

2Cum. GUF (T # 2)

3Cum. GUF (T # 3)

4Cum. GUF (T # 4)

5Cum. GUF (T # 5)


0 1 2 3 4 5 6 7 8

Cu

mu

lati

ve

pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f oil

)

0

200

400

600

800

1000

1200

1400

1600

Cu

mu

lati

ve

GU

F (

cm3 o

f oil

/cm

3 o

f gas)

0.0001

0.001

0.01

0.1

1

101Cum. GOR (T # 1)2Cum. GOR (T # 2)3Cum. GOR (T # 3)4Cum. GOR (T # 4)5Cum. GOR (T # 5)

1Cum. GUF (T # 1)

2Cum. GUF (T # 2)

3Cum. GUF (T # 3)

4Cum. GUF (T # 4)

5Cum. GUF (T # 5)

(a)

(b)




4 Test # 4 (Tinj = 120 min, Tsoak = 48 hrs, Swc =45.8 %)

5 Test # 5 (Tinj = 120 min, Tsoak = 24 hrs, Swc is zero)



209

Test number

1 2 3 4 5

Ult

ima

te r

eco

ver

y f

act

or

(%)

0

5

10

25

30

35

40

0

5

10

25

30

35

40Ultimate recovery factor(%)

1st

stage recovery factor (%)

2nd

stage recovery factor

Test number

1 2 3 4 5

Asp

ha

lten

e co

nte

nt

of

CO

2-p

rod

uce

d o

il (

wt%

)

0.0

0.5

1.0

8.0

9.0

10.0

11.0

12.0

13.0

0.0

0.5

1.0

8.0

9.0

10.0

11.0

12.0

13.0W

asph (1

st and 2

nd stage CO

2-produced oil)

DFo (%)

Sta

ge

reco

ver

y f

act

or

(%)

Oil

eff

ecti

ve

per

mea

bil

ity

dam

age

(%)

(a)

(b)

Test # 1 (Tinj = 30 min, Tsoak = 24 hrs, Swc = 44.7 %)



Test # 4 (Tinj = 120 min, Tsoak = 48 hrs, Swc =45.8 %)

Test # 5 (Tinj = 120 min, Tsoak = 24 hrs, Swc is zero)



of CO2-produced oil, and oil effective permeability damage for cyclic CO2 injection tests

performed at Pop = 5.38 MPa.

210

Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Cu

mu

lati

ve

reco

ver

y f

act

or

(%)

0

10

20

30

40

50

60

70

Sta

ge

reco

ver

y f

act

or

(%)

0

2

4

6

8

10

12

14

161Cum. RF (T # 6)2Cum. RF (T # 7)3Cum. RF (T # 8)

1 Stage RF (T # 6)

2 Stage RF (T # 7)

3 Stage RF (T # 8)


0 1 2 3 4 5 6 7 8

Cu

mu

lati

ve

reco

ver

y f

act

or

(%)

0

10

20

30

40

50

60

70

Sta

ge

reco

ver

y f

act

or

(%)

0

2

4

6

8

10

12

14


1 Stage RF (T # 6)2 Stage RF (T # 7)3 Stage RF (T # 8)

(a)

(b)



3 Test # 8 (Tinj = 120 min, Tsoak = 48 hrs, Swc = 0)



211

Cycle number

0 1 2 3 4 5 6 7 8 9 10 11

Cu

mu

lati

ve

pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f o

il)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

Cu

mu

lati

ve

GU

F (

cm3 o

f o

il/c

m3 o

f ga

s)

0.0001

0.001

0.01

0.11Cum. GOR (T # 6)2Cum. GOR (T # 7)3Cum. GOR (T # 8)

1 Cum. GUF (T # 6)2 Cum. GUF (T # 7)3 Cum. GUF (T # 8)


0 1 2 3 4 5 6 7 8

Cu

mu

lati

ve

pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f oil

)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

Cu

mu

lati

ve

GU

F (

cm3 o

f o

il/c

m3 o

f gas)

0.0001

0.001

0.01



(a)

(b)






212

Test number

5 6 7 8 9

Ult

imate

rec

over

y f

act

or

(%)

0

5

10

15

30

40

50

60

0

5

10

15

30

40

50


1st


2nd


Test number

5 6 7 8 9

Asp

halt

ene

con

ten

t of

CO

2-p

rod

uce

d o

il (

wt%

)

0.0

0.5

1.0

8.0

9.0

10.0

11.0

12.0

13.0

0.0

0.5

1.0

8.0

9.0

10.0

11.0

12.0

13.0

Wasph

(1st and 2

nd stage CO

2-produced oil)

DFo (%)

Sta

ge

reco

ver

y f

act

or

(%)

Oil

eff

ecti

ve

per

mea

bil

ity d

am

age

(%)

(a)

(b)



Test # 8 (Tinj = 120 min, Tsoak = 48 hrs, Swc = 0)





213

Cycle nuber

0 1 2 3 4 5 6 7 8 9 10

Cu

mu

lati

ve

reco

ver

y f

act

or

(%)

0

10

20

30

40

50

60

70

80

Sta

ge

reco

ver

y f

act

or

(%)

0

4

8

12

16

201Cum. RF (T # 9)

2Cum. RF (T # 10)

3Cum. RF (T # 11)

4Cum. RF (T # 12)

1Stage RF (T # 9)

2Stage RF (T # 10)

3Stage RF (T # 11)

4Stage RF (T # 12)


0.0 0.5 1.0 1.5 2.0 2.5 3.0

Cu

mu

lati

ve

reco

ver

y f

act

or

(%)

0

10

20

30

40

50

60

70

80

Sta

ge

reco

ver

y f

act

or

(%)

0

4

8

12

16

201Cum. RF (T # 9)

2Cum. RF (T # 10)

3Cum. RF (T # 11)

4Cum. RF (T # 12)

1Stage RF (T # 9)

2Stage RF (T # 10)

3Stage RF (T # 11)

4Stage RF (T # 12)





(a)

(b)



214

Cycle nuber

0 1 2 3 4 5 6 7 8 9 10

Cu

mu

lati

ve

pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f oil

)

0

250

500

750

1000

1250

1500

1750

2000

2250

2500

Cu

mu

lati

ve

GU

F (

cm3 o

f oil

/cm

3 o

f gas)

0.0001

0.001

0.01

0.11Cum. GOR (T # 9)

2Cum. GOR (T # 10)

3Cum. GOR (T # 11)

4Cum. GOR (T # 12)

1Cum. GUF (T # 9)

2Cum. GUF (T # 10)

3Cum. GUF (T # 11)

4Cum. GUF (T # 12)


0.0 0.5 1.0 1.5 2.0 2.5 3.0

Cu

mu

lati

ve

pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f oil

)

0

250

500

750

1000

1250

1500

1750

2000

2250

2500

Cu

mu

lati

ve

GU

F (

cm3 o

f oil

/cm

3 o

f gas)

0.0001

0.001

0.01

0.11Cum. GOR (T # 9)

2Cum. GOR (T # 10)

3Cum. GOR (T # 11)

4Cum. GOR (T # 12)

1Cum. GUF (T # 9)

2Cum. GUF (T # 10)

3Cum. GUF (T # 11)

4Cum. GUF (T # 12)





(a)

(b)



215

Test number

8 9 10 11 12 13

Ult

ima

te r

eco

ver

y f

act

or

(%)

0

5

10

15

20

40

50

60

70

0

5

10

15

20

40

50

60


1st stage recovery factor (%)

2nd


Test number

8 9 10 11 12 13

Asp

ha

lten

e co

nte

nt

of

CO

2-p

rod

uce

d o

il (

wt%

)

0.0

0.5

1.0

11.0

12.0

13.0

14.0

15.0

16.0

0.0

0.5

1.0

11.0

12.0

13.0

14.0

15.0

16.0

Wasph

(1st and 2

nd stage CO

2-produced oil)

DFo (%)

Sta

ge

reco

ver

y f

act

or

(%)

Oil

eff

ecti

ve

per

mea

bil

ity

da

ma

ge

(%)

(a)

(b)









216

Cycle number

0 1 2 3 4 5 6 7

Cu

mu

lati

ve

reco

ver

y f

act

or

(%)

0

10

20

30

40

50

60

70

80

Sta

ge

reco

ver

y f

act

or

(%)

0

3

6

9

12

15

18

21

24

27




0.0 0.4 0.8 1.2 1.6 2.0

Cu

mu

lati

ve

reco

ver

y f

act

or

(%)

0

10

20

30

40

50

60

70

80

Sta

ge

reco

ver

y f

act

or

(%)

0

3

6

9

12

15

18

21

24

27



(a)

(b)






217

Cycle number

0 1 2 3 4 5 6 7

Cu

mu

lati

ve

pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f oil

)

0

200

400

600

800

1000

1200

Cu

mu

lati

ve

GU

F (

cm3 o

f oil

/cm

3 o

f gas)

0.0001

0.001

0.01

0.11Cum. GOR (T # 13)

2Cum. GOR (T # 14)3Cum. GOR (T # 15)

1 Cum. GUF (T # 13)

2 Cum. GUF (T # 14)3 Cum. GUF (T # 15)


0.0 0.4 0.8 1.2 1.6 2.0

Cu

mu

lati

ve

pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f oil

)

0

200

400

600

800

1000

1200

Cu

mu

lati

ve

GU

F (

cm3 o

f oil

/cm

3 o

f gas)

0.0001

0.001

0.01



(a)

(b)






218

Test number

12 13 14 15 16

Ult

imate

rec

over

y f

act

or

(%)

0

5

10

15

20

25

30

50

60

70

80

0

5

10

15

20

25

30

50

60

70


1st


2nd


Test number

12 13 14 15 16

Asp

halt

ene

con

ten

t o

f C

O2-p

rod

uce

d o

il (

wt%

)

0.0

0.5

1.0

12.0

13.0

14.0

15.0

16.0

0.0

0.5

1.0

12.0

13.0

14.0

15.0

16.0

Wasph

(1st and 2

nd stage CO

2-produced oil)

DFo (%)

Sta

ge

reco

ver

y f

act

or

(%)

Oil

eff

ecti

ve

per

mea

bil

ity

dam

age

(%)

(a)

(b)








219

Cycle number

0 1 2 3 4 5 6 7

Cu

mu

lati

ve

reco

ver

y f

act

or

(%)

0

10

20

30

40

50

60

70

80

Sta

ge

reco

ver

y f

act

or

(%)

0

3

6

9

12

15

18

21

24

27




0.0 0.4 0.8 1.2 1.6 2.0

Cu

mu

lati

ve

reco

ver

y f

act

or

(%)

0

10

20

30

40

50

60

70

80

Sta

ge

reco

ver

y f

act

or

(%)

0

3

6

9

12

15

18

21

24

27






(a)

(b)



220

Cycle number

0 1 2 3 4 5 6 7

Cu

mu

lati

ve

pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f oil

)

0

200

400

600

800

1000

1200

Cu

mu

lati

ve

GU

F (

cm3 o

f oil

/cm

3 o

f gas)

0.0001

0.001

0.01




0.0 0.4 0.8 1.2 1.6 2.0

Cu

mu

lati

ve

pro

du

cin

g G

OR

(cm

3 o

f gas/

cm3 o

f oil

)

0

200

400

600

800

1000

1200

Cu

mu

lati

ve

GU

F (

cm3 o

f oil

/cm

3 o

f gas)

0.0001

0.001

0.01



(a)

(b)






221

Test number

15 16 17 18 19

Ult

ima

te r

eco

ver

y f

act

or

(%)

0

5

10

15

20

25

30

50

60

70

80

0

5

10

15

20

25

30

50

60

70


1st stage recovery factor (%)

2nd


Test number

15 16 17 18 19

Asp

ha

lten

e co

nte

nt

of

CO

2-p

rod

uce

d o

il (

wt%

)

0.0

0.5

1.0

12.0

13.0

14.0

15.0

16.0

0.0

0.5

1.0

12.0

13.0

14.0

15.0

16.0

Wasph

(1st and 2

nd stage CO

2-produced oil)

DFo (%)

Sta

ge

reco

ver

y f

act

or

(%)

Oil

eff

ecti

ve

per

mea

bil

ity d

am

ag

e (%

)

(a)

(b)








222

APPENDIX C

LIST OF PUBLICATIONS

Parametric Study of the Cyclic CO2 Injection Process in Light Oil Systems

Ali Abedini and Farshid Torabi

Industrial & Engineering Chemistry Research, 52 (43), 15211–15223, 2013

223

Oil Recovery Performance of Immiscible and Miscible CO2 Huff-and-Puff

Processes


Energy & Fuels, 28 (2), 774–784, 2014

224

On the CO2 Storage Potential of Cyclic CO2 Injection Process for

Enhanced Oil Recovery


Fuel, 124, 14–27, 2014

225

Determination of Minimum Miscibility Pressure of Crude Oil–CO2 System

by Oil Swelling/Extraction Test

Ali Abedini, Nader Mosavat, and Farshid Torabi

Energy Technology, 2 (5), 431–439, 2014

226

Phase Behaviour Study of Bakken Crude oil–CO2 System: Solubility,

Swelling/Extraction, and Miscibility Tests

Farshid Torabi, Ali Abedini, and Nader Mosavat

Geoconvention 2014: FOCUS, Calgary, Alberta, May 12–16, 2014

227

Oil Recovery, Asphaltene Precipitation and Permeability Damage during

Immiscible and Miscible Cyclic CO2 Injections in Light Oil Systems


Geoconvention 2014: FOCUS, Calgary, Alberta, May 12–16, 2014

228

Phase Behaviour of CO2–Brine and CO2–Oil Systems for CO2 Storage and

Enhanced Oil Recovery: Experimental Studies

Nader Mosavat, Ali Abedini, and Farshid Torabi

International Conference on Greenhouse Gas Control Technologies (GHGT),

Austin, Texas, October 5–9, 2014

Documents

MECHANISMS OF OIL RECOVERY DURING CYCLIC CO INJECTION ...ourspace.uregina.ca/bitstream/handle/10294/5503/Abedini_Ali_2002… · have seen significant increase in interest for the