mechanisms of oil recovery during cyclic co2 injection

Transcription

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
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 CO 2
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
i
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.
ii
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.
iii
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.
iv
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
v
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
vi
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
vii
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
viii
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 multicontact 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 2nd 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
ix
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
x
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 CO 2
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
xi
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
xii
Figure 4.4: Ultimate, 1st and 2nd stage oil recovery factors of the five cyclic CO2 injection
tests (at Tinj = 120 min and Tsoak = 24 hrs) performed at immiscible, nearmiscible, 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 2nd 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
xiii
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): 2nd
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
xiv
Figure 4.17: (a): Asphaltene content of 1st and 2nd 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
xv
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
xvi
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
Figure 5.8: Measured cumulative oil recovery factor of miscible cyclic CO 2 injection
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
xvii
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
xviii
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 CO 2
injection test at immiscible condition in non-fractured porous medium, Pop =
5.38 MPa (i.e., Test # 2)............................................................................. 159
cumulative oil recovery factor after completion of each cycle, for cyclic CO 2
injection test at near-miscible condition in non-fractured porous medium,
Pop = 8.27 MPa (i.e., Test # 9). .................................................................. 160
cumulative oil 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)......................................................................... 161
xix
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
Figure 6.15: Simulated cumulative oil recovery factor of immiscible cyclic CO 2 injection
process (i.e., Pop = 6.55 MPa) vs. cycle number in a fractured medium with
different number of fractures. .................................................................... 171
xx
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 2nd 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
xxi
8.27 MPa. ................................................................................................... 213
8.27 MPa. ................................................................................................... 214
9.31 MPa. ................................................................................................... 216
9.31 MPa. ................................................................................................... 217
10.34 MPa. ................................................................................................. 219
xxii
10.34 MPa. ................................................................................................. 220
injection tests performed at Pop = 10.34 MPa. ........................................... 221
xxiii
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)
xxiv
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)
xxv

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
xxvi
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.
1
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
2
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
3
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
4
results revealed that 6.7–18.9% of original oil in-place (OOIP) can be recovered by CO2EOR 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
5
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
6
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 CO 2
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
7
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.
8
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.
9
Figure 1.1: Idealization of fracture porous media by Warren and Root (1963).
10
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).
11
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
12
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.
13
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
14
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.
15
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-andpuff) 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).
16
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
17
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
18
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.
19
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,
20
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
21
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
22
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
23
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
24
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.
25
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
26
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.
27
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
C2
C3
i-C4
n-C4
i-C5
n-C5
C5’s
i-C6
n-C6
C6’s
C7's
C8's
C9's
C10's
C11's
0
1.58
0.92
0
3.88
2.20
4.03
0.49
3.07
2.95
3.37
13.87
10.46
8.19
6.38
5.61
C12's
C13's
C14's
C15's
C16's
C17's
C18's
C19's
C20's
C21's
C22's
C23's
C24's
C25's
C26's
C27's
4.48
4.02
3.32
3.06
2.37
2.06
1.91
1.51
1.29
1.29
0.76
0.87
0.71
0.66
0.57
0.49
C28's
C29's
C30+'s
0.44
0.33
2.85
C1–C6's
C7+'s
22.48
77.52
C1–C14's
C15+’s
78.82
21.18
C1–C29's
C30+'s
97.15
2.85
223 gr/mol
802 kg/m3
2.92 mPa.s
1.23 wt %
Molecular weight
Density at (21 °C & Patm)
Viscosity at (21 °C & Patm)
n-C5 insoluble asphaltene
28
16
14
Mole percent
12
10
8
6
4
2
C30+
C27's
C28's
C29's
C25's
C26's
C23's
C24's
C22's
C20's
C21's
C18's
C19's
C16's
C17's
C15's
C12's
C13's
C14's
C9's
C10's
C11's
C7's
C8's
i-C5
n-C5
C6's
C3
i-C4
n-C4
C1
C2
CO2
0
Crude oil components
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
3.0
810
Viscosity
Density
800
2.6
795
2.4
Crude oil density (kg/m3)
805
2.8
790
2.2
785
15
20
25
30
35
40
45
50
Temperature (oC)
Figure 3.2: Measured values of crude oil density and viscosity as a change of temperature
at atmospheric pressure.
30
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).
31
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):
32
Temperature controller
Crude oil
Digital
pressure
gauge
pres
CO2
Data
acquisition
system
High P & T
Visual cell
Magnetic
stirrer
Teledyne ISCO syringe pump
Fan &
heater
Fan &
heater
Air bath
Figure 3.3: Schematic diagram of the experimental set-up used for CO2 solubility and oil
swelling factor measurements at various equilibrium pressures.
33
mCO2 , dis  mCO2 ,i  mCO2 , f
  Pf VCO2 , f MWCO2
  

Z f RT
 
 PiVCO ,i   Pf VCO , f 
2
2

  


 Z i   Z f

 PiVCO2 ,i MWCO2
 
Z i RT


MWCO2
RT

mco2 ,dissolved
moil
100
 PiVCO ,i
2

 oilVoil RT  Z i
MW CO2
  P f VCO2 , f

  Z
f
 
(Eq. 3.1)
………
(Eq. 3.2)
………
(Eq. 3.3)




moil   oilVoil 
 CO2 
………

 100


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.
SF 
………
Vf
Vi
34
(Eq. 3.4)
Pi
P
f
At each pressure : h CO2  ho  H t
h CO2 ,i

ho,i
hCO2
h CO2 , f
H
ho, f
,i
CO2 
Δhot
SF 
ho,i
Pi = Patm
VCO2 ,i
Vo,i


Vcell Vo,i
Vo,i
h CO2 ,i  ho
ho,i  ho
MWCO2
RToVo,i

VCO2 , f
Vo, f
 PiVCO ,i   Pf VCO , f
2
2


 Z i   Z f

  100


Vo, f
Vo,i
Pf = 6.79MPa
MPa
Figure 3.4: Details of the visual technique used to determine the volumes of oil and CO 2
phases at each equilibrium pressure in order to calculate the CO2 solubility in crude oil
and resulting oil swelling factor.
35
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.
36
40
CO2 (T = 21 °C)
CO2 (T = 30 °C)
CO2 (grCO2/100groil)
30
20
10
0
0
1
2
3
4
5
6
7
8
Figure 3.5: Measured CO2 solubility in the crude oil at experimental temperatures of T =
21 °C and 30 °C.
37
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.
38
2.0
oil swelling mechanism
hydrocarbon extraction mechanism
Pext = 5.95 MPa (T = 21 °C)
Oil swelling factor
1.5
1.0
0.5
0.0
0
2
4
6
8
10
12
14
system at experimental temperatures of T = 21 °C.
39
2.0
oil swelling mechanism
1.0
hydrocarbon extraction mechanism
Pext = 6.79 MPa (T =30 °C)
Oil swelling factor
1.5
0.5
0.0
0
2
4
6
8
10
12
14
system at experimental temperatures of T = 30 °C.
40
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 CO2based 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 highpressure 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 prespecified pressure and a temperature of T = 30 °C.
41
Temperature
controller
CO2
Crude oil
Data
acquisition
system
High pressure
IFT Cell
Microscopic
camera
Light
source
CO2 at T & Peq
Vibration-free table
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
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.
43
25
Dynamic interfacial tension (mJ/m2)
Peq = 1.14 Mpa
Peq = 2.43 MPa
Peq = 3.42 MPa
20
Peq = 4.86 MPa
Peq = 5.99 MPa
Peq = 7.35 MPa
15
Peq = 9.05 MPa
Peq = 11.83 MPa
10
5
0
0
100
200
300
400
500
600
700
800
900
Time (s)
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
Equilibrium interfacial tension (mJ/m 2)
22
Range (I): Solubility mechanism
Range (II): Hydrocarbon extraction mechanism
20
18
16
14
Range (I)
12
10
Pext = 6.84 MPa
8
6
4
Range (II)
2
0
0
5
10
15
20
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
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
46
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.
47
Table 3.2: Pressure range, correlated equations and their accuracy, and calculated multicontact and first-contact MMPs obtained from VIT technique at T = 30 °C.
IFT Phase
Range (I)
Range (II)
Pressure range
(MPa)
0.66–6.84
6.84–14.64
Correlated Equation
IFTeq = -2.3066Peq + 21.1750
IFTeq = -0.3864Peq + 8.0042
48
Accuracy
(R2)
0.9983
0.9673
Calculated MMP
(MPa)
9.18
20.71
Equilibrium interfacial tension (mJ/m2)
22
Range (I)
Range (II)
20
18
Range (I):
IFTeq = -2.3066Peq + 21.1750 (R² = 0.9983)
0.66 MPa < Peq < 6.84 MPa
16
14
Range (II):
IFTeq = -0.3864Peq + 8.0042 (R² = 0.9673)
6.84 MPa < Peq < 14.64 MPa
12
10
8
6
Multi-contact
MMP = 9.18 MPa
4
Maximum Peq = 20.71 MPa
2
0
0
5
10
15
20
25
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
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
50
2.0
Range (I):
SF = -0.2479Peq + 2.8037 (R² = 0.9811)
8.95 MPa < Peq < 8.07 MPa
Range (II)
SF = -0.0478Peq + 1.1892 (R² = 0.9913)
8.07 MPa < Peq < 12.65 MPa
Oil swelling factor
1.5
Multi-contact MMP = 8.07 MPa
1.0
Range (I)
0.5
Range (II)
Swelling phase
Upper CO2 extraction phase
Lower CO2 extraction phase
0.0
0
2
4
6
8
10
12
14
16
phase in oil swelling curve at T = 21 °C (estimated MMPSF = 8.07 MPa).
51
2.0
Range (I):
SF = -0.2803Peq + 3.2840 (R² = 0.9829)
6.79 MPa < Peq < 8.96 MPa
Range (II)
SF = -0.0529Peq + 1.2483 (R² = 0.9910)
8.96 MPa < Peq < 12.55 MPa
Oil swelling factor
1.5
Multi-contact MMP = 8.96 MPa
Range (I)
1.0
Range (II)
0.5
Swelling phase
Upper CO2 extraction phase
Lower CO2 extraction phase
0.0
0
2
4
6
8
10
12
14
16
phase in oil swelling curve at T = 30 °C (estimated MMPSF = 8.96 MPa).
52
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 Extraction
(°C)
Phase
21
30
Range (I)
Range (II)
Range (I)
Range (II)
Pressure range
(MPa)
Correlated Equation
Accuracy
(R2)
5.95–8.07
8.07–12.65
6.79–8.96
8.96–12.55
SF = -0.2479Peq + 2.8037
SF = -0.0478Peq + 1.1892
SF = -0.2803Peq + 3.2840
SF = -0.0529Peq + 1.2483
0.9811
0.9913
0.9829
0.9910
53
Calculated
MMP (MPa)
8.07
8.96
of CO2 at lower temperature as well as that the extraction of lighter components by CO 2
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.
54
Table 3.4: Proposed correlations for calculating the MMP of crude oil–CO2 system.
Reference
Cronquist,
1977
Lee, 1979
Yellig and
Metcalfe,
1980
Correlation
MMP  0.11027
Comments
1.8TR  32
0.744206 0.0011038MWC5   0.0015279C1
2.7721519/ 4921.8TR 1
MMP  7.3924 10
MMP  12.6472  0.01553(1.8T R  32)
 1.24192 10
4
(1.8T R  32)
TR: reservoir temperature (°C)
MWC5+: C5+ molecular weight
C1: mole fraction of CH4
2
716.9427
(1.8TR  32)
MMP  0.101386


2015
exp 10.91 

255.372  0.5556(1.8TR  32) 

If xINT < 18%
MMP  20.3251  2.3470 10 2 MW C7 
xINT: mole fraction of the intermediates (C2−C6)

Orr and
Jensen,
1984
Glaso,
1985
786.8 MWC 7  1.0 5 8
 1.172110 11 MW C7  3.73e
(1.8TR  32)  8.3564 10 1 x INT
If xINT > 18%
MMP  5.5848  2.3470 10 2 MW C7 
 1.1721 10 11 MW C7  3.73
e
Emera and
Sarma,
2004
786.8 MWC 7  1.058
(1.8TR  32)
5
MMP  5.0093 10 (1.8TR  32)1.164
MWC 1.2785xVOL / x INT 0.1073
5
If Pb < 0.345 MPa

MMP  5.0093 105 1.8TR  321.164 MWC5
Yuan et al.,
2005
1.2785
MMP  a1  a 2 MW C7   a 3 x INT

x INT
  a 4  a 5 MW C7   a 6
2

MW
C7 



1.8T  32
R



 a 7  a 8 MW C7   a 9 MW C7  2  a10 x INT 1.8T R  322
Shokir,
2007
MMP  0.068616 z 3  0.31733z 2
 4.9804 z  13.432
4
Where:
z
z
i
i 1
and
Li et al.,
2012
zi  A3i yi 3  A2i yi 2  A1i yi  A0i
MMP  7.3099110 5 ln1.8TR  325.33647
lnMW 
1  xVOL / x INT 2.0165810
1
2.08836
C7 
55
Pb: bubble point pressure
xVOL: mole fraction of volatiles (CH4 and N2)
xINT: mole fraction of intermediates (CO2 and
H2S, and C2−C4)
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
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
Pb: bubble point pressure
xVOL: mole fraction of volatiles (CH4 and N2)
xINT: mole fraction of intermediates (CO2 and
H2S, and C2−C6)
Table 3.5: Comparison of measured MMPs of crude oil–CO2 system with those
calculated by proposed correlations.
Method
VIT technique
Oil swelling curve
Cronquist, 1997
Lee, 1979
Yellig and Metcalfe, 1980
Orr and Jensen, 1984
Glaso, 1985
Emera and Sarma, 2004
Yuan et al., 2005
Shokir, 2007
Li et al., 2012
MMP (MPa)
T = 21 °C
T = 30 °C
8.07
7.81
5.94
4.06
5.88
7.07
7.53
7.45
7.88
5.96
9.18
8.96
9.63
7.22
6.56
7.20
8.87
9.61
8.69
9.47
7.70
1
AE (%)1,2
T = 21 °C
T = 30 °C
3.22
26.39
49.69
27.14
12.39
6.69
7.68
2.35
26.15
AE is calculated based on the experimental MMP obtained by oil swelling curve
MMPexp eriment  MMPcorrelation
2
AE (%) 
 100
MMPexp eriment
56
7.48
19.42
26.79
19.64
1.00
7.25
3.01
5.69
14.06
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.
57
Fan &
heater
Nitrogen cylinder
Carbonated water
Back
pressure
regulator
Produced brine
collector
Air bath
Fan &
heater
Produced gas
collector
Figure 3.14: Schematic diagram of the experimental set-up used to measure CO2
solubility in the synthetic brine.
58
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):
'
'
mCO
 nCO
MWCO2
2 , dis
2 , dis

 
 CO
2
VCO2 , p eq
(v M ,CO2 ) @ Peq & T
'
mCO
2 , dis
mb

(v M ,CO2 ) @ Peq & T
 b Vb
(Eq. 3.5)
………
(Eq. 3.6)
MWCO2
 100
VCO2 , peq
………
MWCO2
100
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).
59
7
'CO2 (T = 21 °C)
'CO2 (T = 30 °C)
'CO2grCO2/100 grbrine
6
5
4
3
2
1
0
0
2
4
6
8
10
12
Figure 3.15: Measured CO2 solubility in the synthetic brine at temperatures of T = 21 °C
and 30 °C.
60
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.
61
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.
62
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.
63
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.
64
63
CO2
Core holder
Crude oil
Fan &
heater
Brine
Fan &
heater
Nitrogen cylinder
Berea core sample
Back
pressure
regulator
Diff. pressure transducer
Sample
Air bath
collector
To the vent
Gas flow meter
Figure 4.1: Schematic diagram of the experimental set-up used for cyclic CO2 injection tests.
Data
acquisition
system
Table 4.1: Properties of the core sample and core holder used for cyclic CO2 injection
tests.
Core sample
Core holder
Permeability,
k (mD)
70.8
-
Porosity,
 (%)
18.5
-
Height,
(cm)
30.21
35.59
66
Diameter
(cm)
5.05
6.12
Pore volume,
PV (cm3)
111.94
1046.94
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
67
the end of the core holder. Since a cyclic injection process is a single well injectionproduction 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),
68
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.
69
and solvent) for all secondary cyclic CO2 injection tests.
Test #
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
 (%)
18.5
18.4
18.3
18.5
18.3
18.7
18.5
18.4
18.6
18.4
18.4
18.7
18.6
18.4
18.7
18.5
18.3
18.6
18.3
18.5
k (mD)
70.8
70.6
71.3
70.9
71.4
70.8
71.3
70.5
71
70.6
70.8
71.2
70.9
71.3
70.7
71
70.5
70.7
70.5
70.7
Swc (%)
44.7
45.4
43.3
45.8
0
45.9
45.5
0
44.7
45.4
43.3
0
44.9
45.7
0
44.3
45.1
0
45.2
45.4
Soi (%)
55.3
54.6
56.7
54.2
100
54.1
54.5
100
55.3
54.6
56.7
100
55.1
54.3
100
55.7
54.9
100
54.8
54.6
Pop (MPa)
5.35
5.35
5.35
5.35
5.35
6.55
6.55
6.55
8.27
8.27
8.27
8.27
9.31
9.31
9.31
10.34
10.34
10.34
3.45
4.83
70
Tinj (min)
30
120
30
120
120
120
120
120
120
120
30
120
120
120
120
120
120
120
120
120
Tsoak (hr)
24
24
48
48
24
24
48
24
24
48
24
24
24
48
24
24
48
24
24
24
Solvent
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2
CO2+C3
CO2+C3
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., npentane 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.
71
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
72
80
Test # 1 (Pop = 5.38 MPa)
Cumulative oil recovery factor (%)
60
Test # 5 (Pop = 10.34 MPa)
40
20
0
0
1
2
3
4
5
6
7
8
9
10
11
7
8
9
10
11
Cycle number
0
1
2
3
4
5
6
Time (Day)
and Tsoak = 24 hrs) vs. cycle number and time at various operating pressures.
73
80
Test # 13 (Pop = 9.31 MPa)
60
Test # 16 (Pop = 10.34 MPa)
40
20
0
0
1
2
3
4
5
6
7
Pore volume of injected CO2
and Tsoak = 24 hrs) vs. pore volume of injected CO2 at various operating pressures.
74
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
75
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.
76
65
30
Ultimate oil recovery factor (%)
60
2nd stage recovery factor
25
55
50
20
45
15
40
35
10
1st and 2nd stage recovery factors
Ultimate oil recovery factor
1st stage recovery factor
30
Near-miscible
Immiscible
Miscible
25
5
5
6
7
8
9
10
11
Figure 4.4: Ultimate, 1st and 2nd 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
2500
Producing GOR (cm3 of gas/cm3 of oil)
2000
Test # 13 (Pop = 9.31 MPa)
Test # 16 (Pop = 10.34 MPa)
1500
1000
500
0
0
1
2
3
4
5
6
7
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
Gas utilization factor (cm3 of oil/cm3 of inj. gas)
0.1
Test # 13 (Pop = 9.31 MPa)
Test # 16 (Pop = 10.34 MPa)
0.01
0.001
0.0001
0
1
2
3
4
5
6
7
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
800
Total producing GOR
Final GUF
2500
600
2000
1500
400
1000
200
500
0
Final GUF * 106 (cm3 oil/cm3 inj. gas)
Total Producing GOR (cm3 gas/cm3 oil)
3000
0
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.
80
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.
81
80
Ultimate RF: Tinj = 120 min
1st stage RF: Tinj = 30 min
25
1st stage RF: Tinj = 120 min
60
2nd stage RF: Tinj = 30 min
50
20
2nd stage RF: Tinj = 120 min
40
15
30
10
20
Stage recovery factor (%)
70
30
Ultimate RF: Tinj = 30 min,
5
10
0
0
5.0
5.5
6.0
6.5
7.0
7.5
8.0
8.5
Pressure (MPa)
Figure 4.8: Ultimate, 1st, and 2nd 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
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, nearmiscible, 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 CO 2
injection.
83
80
Near-miscible
Immiscible
Miscible
70
60
50
40
30
20
Tinj = 120 min, Tsoak = 24 hrs and Swc is not zero
10
0
5
6
7
8
9
10
11
Pressure (MPa)
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
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.
85
70
Near-miscible
Immiscible
Miscible
60
50
40
30
20
Tinj = 120 min, Tsoak = 24 hrs and Swc is zero
10
5
6
7
8
9
10
11
Pressure (MPa)
pressures ranging from Pop = 5.38–10.34 MPa in the presence and absence of connate
water saturation.
86
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 CO 2/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.
87
70
Pop = 3.45 MPa
Pop = 4.83 MPa
60
50
40
30
20
10
0
0
1
2
3
4
5
6
7
Cycle number
min and Tsoak = 24 hrs) vs. cycle number at operating pressures of Pop = 3.45 MPa and Pop
= 4.83 MPa.
88
70
Pop = 3.45 MPa
Pop = 4.83 MPa
60
50
40
30
20
10
0
0.0
0.5
1.0
1.5
2.0
2.5
Pore volume of injected solvent (CO2 + C3)
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
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 CO 2 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
90
0.90
Precipitated asphaltene in the core
Permeability damage of the core
0.60
0.85
0.80
0.55
0.75
0.70
0.50
0.65
0.45
0.60
Near-miscible
Immiscible
0.55
6
7
8
9
14
13
12
11
10
Miscible
0.40
5
15
10
9
11
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, nearmiscible, and miscible conditions.
91
Oil Relative Permeability damage(%)
Asphaltene content of CO2-produced oil
Precipitated asphaltene in the core (wt%)
Asphaltene content of CO 2-produced oil (wt%)
0.65
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
92
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 huffand-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.
93
Mole percent
16
14
Composition of original light crude oil
(C30+ = 2.86%, MW = 223 gr/mol)
12
Composition of remaining crude oil at 6.55 MPa
(C30+ = 3.96%, MW = 242 gr/mol)
Composition of remaining crude oil at 9.31 MPa
(C30+ = 5.61%, MW = 268 gr/mol)
10
8
6
Col 2
4
2
C30+
C28's
C29's
C26's
C27's
C24's
C25's
C22's
C23's
C20's
C21's
C17's
C18's
C19's
C15's
C16's
C12's
C13's
C14's
C9's
C10's
C11's
C7's
C8's
i-C5
n-C5
C6's
C3
i-C4
n-C4
C1
C2
CO2
0
Crude oil components
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
70
C1-C4's
C5's-C9's
60
C10's-C19's
C20's-C29's
Mole Percent
50
C30+
40
30
20
10
0
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.
95
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 nearmiscible 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 nearmiscible 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
96
Table 4.3: Experimental results (ultimate, 1st, and 2nd 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 #
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Ultimate
RF (%)
32.57
33.22
36.95
37.51
29.50
47.50
51.30
34.90
55.80
58.70
54.39
53.15
60.80
61.34
58.40
61.52
62.10
59.90
49.41
59.28
1st stage
RF (%)
7.06
7.63
8.08
8.22
7.30
12.87
13.90
10.08
16.80
17.92
15.40
15.22
23.90
24.79
21.30
23.53
25.20
21.51
20.13
22.58
2nd stage
RF (%)
5.46
5.76
6.21
5.93
6.02
9.78
9.44
7.30
11.22
11.40
10.67
11.30
15.04
15.40
14.93
16.10
15.98
15.31
14.04
17.22
Total GOR
(cm3/cm3)
1479.35
1610.33
1368.90
1516.89
860.00
1560.00
1670.00
877.90
2083.32
2231.21
2200.41
1377.70
932.47
990.53
546.09
979.18
1031.10
572.87
172.71
230.11
97
Final GUF [×106]
(cm3/cm3)
405.7
342.8
422.2
337.7
480.4
379.4
317.3
466.0
320.8
299.5
323.0
317.4
574.3
538.2
899.8
537.3
508.6
882.0
3140
1870
Wasph
(wt%)
0.57
0.59
0.54
0.52
0.46
0.53
0.51
0.42
0.48
0.45
0.50
0.39
0.46
0.43
0.38
0.45
0.44
0.37
0.43
0.37
DFo
(%)
9.63
9.81
10.47
10.40
12.04
10.72
10.51
12.48
13.34
13.90
13.06
14.47
13.95
14.26
14.29
13.79
14.19
14.91
16.37
18.46
70
(a)
Near-miscible
Immiscible
Miscible
60
50
40
30
20
10
5
6
7
8
9
10
11
Pressure (MPa)
36
(b)
1st stage oil recovery factor (%)
30
24
18
12
6
Near-miscible
Immiscible
Miscible
0
5
6
7
8
9
10
11
Pressure (MPa)
18
(c)
Near-miscible
2nd stage oil recovery factor (%)
Immiscible
Miscible
15
12
9
6
3
0
5
6
7
8
9
10
11
Pressure (MPa)
Figure 4.15: (a): Ultimate oil recovery factor, (b): 1st stage recovery factor, and (c): 2nd
stage recovery factor of all cyclic CO2 injection tests performed at various operating
conditions.
98
2500
Total producing GOR (cm3 of gas/cm3 of oil)
(a)
Near-miscible
Immiscible
Miscible
2000
1500
1000
500
0
5
6
7
8
9
10
11
Pressure (MPa)
1000
(b)
Near-miscible
Total GUF [*106] (cm3 of oil/cm3 of gas)
Immiscible
Miscible
800
600
400
200
0
5
6
7
8
9
10
11
Pressure (MPa)
Figure 4.16: (a): Total producing GOR, and (b): Final GUF of all cyclic CO2 injection
tests performed at various operating conditions.
99
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, nearmiscible and miscible conditions) are presented graphically in Appendix B.
100
Asphaltene content of CO2-produced oil (wt%)
(a)
0.7
0.6
0.5
0.4
Near-miscible
Immiscible
Miscible
0.3
5
6
7
8
9
10
11
Pressure (MPa)
16
(b)
Near-miscible
Oil effective permeability damage (%)
Immiscible
Miscible
14
12
10
8
6
5
6
7
8
9
10
11
Pressure (MPa)
Figure 4.17: (a): Asphaltene content of 1st and 2nd stage CO2-produced oil, and (b): Oil
effective permeability damage of all cyclic CO2 injection tests performed at various
operating conditions.
101
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.
102
Tertiary cyclic CO2 injection
60
1.5
40
1.0
20
0.5
Oil Recovery factor
Producing WOR
Producing GOR
0
0.0
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2500
2000
1500
1000
500
Producing gas-oil ratio (cm3 of gas/ cm3 of oil)
2.0
Secondary waterflooding
Producing water-oil ratio (cm3 of water / cm3 of oil)
80
0
2.0
Pore volume of injected water and CO2
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
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.
104
6e+4
(a)
Cumulative volume of injected CO2
Cumulative volume of produced CO2
Volume of the CO2 (cm3)
5e+4
4e+4
3e+4
2e+4
1e+4
0
0
1
2
3
4
5
6
7
Cycle number
8
9
10
11
1.0
(b)
Produced CO2 / Injected CO2
Stored CO2 / Injected CO2
3
3
Volume ratio (cm /cm )
0.8
0.6
0.4
0.2
0.0
0
1
2
3
4
5
6
7
Cycle number
8
9
10
11
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
1e+5
(a)
Cumulative volume of produced CO 2
8e+4
6e+4
4e+4
2e+4
0
0
1
2
3
4
5
6
7
Cycle number
8
9
10
11
1.0
(b)
3
3
0.8
0.6
0.4
0.2
0.0
0
1
2
3
4
5
6
7
Cycle number
8
9
10
11
to injected CO2 in each cycle for immiscible cyclic CO2 injection test conducted at Pop =
6.55 MPa.
106
1.4e+5
(a)
1.2e+5
1.0e+5
8.0e+4
6.0e+4
4.0e+4
2.0e+4
0.0
0
1
2
3
4
5
6
Cycle number
7
8
9
10
1.0
(b)
Volume ratio (cm3/cm3)
0.8
0.6
0.4
0.2
0.0
0
1
2
3
4
5
6
Cycle number
7
8
9
10
to injected CO2 in each cycle for near-miscible cyclic CO2 injection test conducted at Pop
= 8.27 MPa.
107
7e+4
(a)
6e+4
5e+4
4e+4
3e+4
2e+4
1e+4
0
0
1
2
3
4
Cycle number
5
6
7
1.0
(b)
3
3
0.8
0.6
0.4
0.2
0.0
0
1
2
3
4
Cycle number
5
6
7
to injected CO2 in each cycle for miscible cyclic CO2 injection test conducted at Pop =
9.31 MPa.
108
8e+4
(a)
6e+4
4e+4
2e+4
0
0
1
2
3
4
Cycle number
5
6
7
1.0
(b)
Volume ratio (cm3/cm3)
0.8
0.6
0.4
0.2
0.0
0
1
2
3
4
Cycle number
5
6
7
to injected CO2 in each cycle for miscible cyclic CO2 injection test conducted at Pop =
10.34 MPa.
109
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):
Rt F 
VCO2 ,stored
………………………………
Vo, prod
(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).
110
Retention factor (cm3 gasstored / cm3 oil)
1400
1300
1200
1100
1000
900
800
700
5
6
7
8
9
10
11
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
0.8
Cumumulative produced CO2/ Cumulative injected CO2
Cumumulative stored CO2 / Cumulative injected CO2
0.7
0.7
0.6
0.6
0.5
0.5
0.4
0.4
0.3
0.3
0.2
0.2
5
6
7
8
9
10
Cumumulative stored CO 2 / Cumulative injected CO 2
Cumumulative produced CO 2 / Cumulative injected CO 2
0.8
11
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 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.
113
0.55
Ultimate oil recovery factor
60
0.50
50
0.45
40
0.40
30
20
0.35
5
6
7
8
9
10
70
11
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
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.
115
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 CO 2
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.
116
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.
117
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
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):
k fm  k m 
w3
cos 
12d
………………………………………
(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.
119
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
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)
Fracture porosity (%)
1685
0.5
80.3
Negligible
1711
0.5
Fracture permeability (D)*
3374
Negligible
≈ 3374
Fracture Orientation
*kf 
w2
(Witherspoon et al., 1980)
12
120
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 CO 2
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.
121
and solvent) for all secondary cyclic CO2 injection tests.
Test
#
21
22
23
24
25
26

(%)
18.9
19.1
18.3
18.9
19.1
18.3
k
(mD)
1685
80.3
1711
1685
80.3
1711
Swc
(%)
0
0
0
0
0
0
Soi
(%)
100
100
100
100
100
100
Fracture
configuration
a
b
c
a
b
c
122
Pop
(MPa)
6.55
6.55
6.55
9.31
9.31
9.31
Tinj
(min)
120
120
120
120
120
120
Tsoak
(hr)
24
24
24
24
24
24
Solvent
CO2
CO2
CO2
CO2
CO2
CO2
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.
123
60
50
40
30
20
Configuration (a)
Configuration (b)
Configuration (c)
10
0
0
1
2
3
4
5
6
7
8
9
Cycle number
tests conducted at operating pressure of Pop = 6.55 MPa and in fractured porous medium
with different fracture configuration vs. cycle number.
124
60
50
40
30
20
Configuration (a)
Configuration (b)
Configuration (c)
10
0
0
1
2
3
4
5
with different fracture configuration vs. pore volume of injected CO2.
125
60
50
40
30
20
Configuration (a)
Configuration (b)
Configuration (c)
Non-fractured porous medium
10
0
0
1
2
3
4
5
6
7
8
9
Cycle number
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 nonfractured and fractured porous media.
126
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.
127
18
Configuration (a)
Configuration (b)
Configuration (c)
Stage oil recovery factor (%)
16
14
12
10
8
6
4
2
0
0
1
2
3
4
5
6
7
8
9
Cycle number
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
(a) CO2 diffusion process during the first cycle
Matrix
Fracture
Matrix
(b) CO2 diffusion process during the second cycle
Matrix
Fracture
Matrix
Direct contact of CO2 with crude oil
Diffusion of CO2 through the oil
phase
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 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 nonfractured 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).
130
80
60
40
20
Configuration (a)
Configuration (b)
Configuration (c)
0
0
1
2
3
4
5
6
Cycle number
with different fracture configuration vs. cycle number.
131
80
60
40
20
Configuration (a)
Configuration (b)
Configuration (c)
0
0.0
0.5
1.0
1.5
2.0
with different fracture configuration vs. pore volume of injected CO2.
132
80
60
40
20
Configuration (a)
Configuration (b)
Configuration (c)
0
0
1
2
3
4
5
6
Cycle number
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 nonfractured and fractured porous media.
133
30
Configuration (a)
Configuration (b)
Configuration (c)
Stage oil recovery factor (%)
25
20
15
10
5
0
0
1
2
3
4
5
6
Cycle number
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.
134
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 nonfractured 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.
135
80
Pop = 6.55 MPa
60
40
Fractured
porous medium,
configuration (c)
Non-fractured
porous medium
0
Fractured
porous medium,
configuration (b)
20
Fractured
porous medium,
configuration (a)
Pop = 9.31 MPa
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.
136
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.
137
Pop = 6.55 MPa
Pop = 9.31 MPa
800
600
400
Fractured
porous medium,
configuration (c)
Non-fractured
porous medium
0
Fractured
porous medium,
configuration (b)
200
Fractured
porous medium,
configuration (a)
Total producing GOR (cm3 of gas/cm3 of oil)
1000
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.
138
1400
Pop = 6.55 MPa
Pop = 9.31 MPa
1200
1000
800
600
400
Fractured
porous medium,
configuration (c)
Non-fractured
porous medium
0
Fractured
porous medium,
configuration (b)
200
Fractured
porous medium,
configuration (a)
Final GUF * 106 (cm3 of oil/cm3 inj. gas)
1600
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.
139
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.
140
CHAPTER SIX
NUMERICAL SIMULATION STUDY
Although having a comprehensive experimental study for any pilot test or fieldscale 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 CMGWinpropTM 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
141
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 subpseudo-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
142
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.
143
Table 6.1: Some of the main properties of the six sub-pseudo-components used to match
the measured PVT properties.
Cp
Composition
(mole %)
Pc (MPa)
Tc (K)
ω
MW (gr/mol)
Volume shift
SG
δCO2
C1–C3
C4’s–C8’s
C9’s–C15’s
C16’s–C21’s
C22’s–C29’s
C30+
2.5
44.3
35.1
10.4
4.84
2.85
4.646
330.780
0.11787
35.23
0.00000
0.413
0.13184
3.216
522.356
0.29143
89.54
0.00255
0.702
0.09202
2.313
650.857
0.49354
152.78
0.04699
0.799
0.15483
1.581
761.420
0.75936
251.30
0.11797
0.857
0.15000
1.214
831.067
0.96131
334.78
0.19314
0.888
0.15000
1.698
805.504
1.12992
674.40
-0.77194
1.212
0.05917
144
810
(a)
Experimental values
Simulated values
Crude oil density (kg/m3)
805
800
795
790
785
15
20
25
30
35
40
45
50
o
Temperature ( C)
3.0
(b)
Experimental values
Simulated values
2.8
2.6
2.4
2.2
15
20
25
30
35
40
45
50
Temperature (oC)
Figure 6.1: Comparison between the experimental and simulated values of (a): crude oil
density, and (b): crude oil viscosity after the regression.
145
12
(a)
Psat (Experiment)
Psat (Before regression)
Saturation pressure (MPa)
10
Psat (After regression)
8
6
4
2
0
0.0
0.2
0.4
0.6
0.8
CO (mole%)
2
80
(b)
AE before regression
AE after regression
70
Absolute error(%)
60
50
40
10
5
0
0.2
0.3
0.4
0.5
0.6
0.7
CO (mole%)
2
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
1.6
(a)
SF (Experiment)
SF (Before regression)
SF (After regression)
Oil swelling factor
1.5
1.4
1.3
1.2
1.1
1.0
0.0
0.2
0.4
0.6
0.8
CO2 (mole%)
20
(b)
AE before regression
AE after regression
Absolute error(%)
15
10
5
0
0.2
0.3
0.4
0.5
0.6
0.7
CO2 (mole%)
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
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
148
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.
149
CO2 injection tests conducted in non-fractured porous medium.
Type
Porosity (%)
Permeability
No. of grid (i×j×k)
Block width (i,j,k)
Swc (%)
Length
Cross-sectional area
Pore volume
Cartesian
18.5*
70.8 mD**
20×3×3
1.5105 cm, 1.492 cm, 1.492 cm
44.7***
30.21 cm
20.03 cm2
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%)
150
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
CO2 injection tests conducted in fractured porous medium.
Type
Matrix porosity (%)
Matrix permeability
Fracture porosity (%)
Fracture permeability
No. of grid (i×j×k)
Matrix dimension (i,j,k)
Fracture dimension (i,j,k)
Length
Cross-sectional area
Pore volume
Cartesian
18.4
73.9 mD
0.99
3374 D
20×3×5
1.509 cm, 1.492 cm, 1.119 cm
1.509 cm, 1.492 cm, 0.02 cm
30.18 cm
20.07 cm2
112.52 cm3
152
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
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:
Dij 
 ko Dijo
k
0.99589 0.096016
kr
 0.22035 kr2  0.032874 kr3

………
(Eq. 6.1)
………
(Eq. 6.2)
………
(Eq. 6.3)
In which:
 kr




 k 



o
o
k Dij
n
y
5/3
ik v ci
i 1
n

i 1
y ik v ci2 / 3







0.0018583T 1 / 2

 ij2  ij R
 1
1 


 Mi M j 


1/ 2
154
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
The diffusion of component i in the mixture (i.e., crude oil) can be calculated as given:
Dik 
1  y ik
y
………
1
ik Dij
(Eq. 6.5)
j i
The collision diameter (σij) and the collision integral (Ωij) are related to the critical
properties of components as follows (Reid et al., 1977):
T
 i  2.3551 0.087 i   ci
 Pci



1/ 3
 i  k B 0.7915 0.1963i Tci
 ij 
i  j
2
 ij   i  j 
Tij* 
kB
 ij
 
 ij  1.06306Tij*
0.15610


 1.03587exp  1.52996T 
 1.76474exp  3.89411T 
………
(Eq. 6.6)
………
(Eq. 6.7)
………
(Eq. 6.8)
………
(Eq. 6.9)
………
(Eq. 6.10)
………
(Eq. 6.11)
 0.19300exp  0.47635Tij*
*
ij
*
ij
In the above equations, kB is the Boltzmann’s constant which is k B  1.3805 1016 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:
156

D  CO2
0.4562
Mo
0.6869
vCO2
1.706

P 1.831T 4.524 109
………
(Eq. 6.12)
In (Eq. 6.12), D is the diffusivity coefficient of CO2 in the crude oil (m2/sec),
 CO is the viscosity of CO2 (cP) at the equilibrium pressure and temperature, Mo is the
2
molecular weight of the crude oil (g/mol), vCO2 is the molar volume of CO2 (cm3/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):


Log DCO2 , w  4.1764 
 DCO2 ,b
Log
 DCO , w
2

712.52  2.5907 105
 
T
T2


  0.87Log  b


 w








………
(Eq. 6.13)
………
(Eq. 6.14)
In which:
DCO2 ,w and DCO2 ,b 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)
157
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.
158
35
(a)
Experiment
Simulation
30
25
20
15
10
5
0
0
1
2
3
4
5
6
7
8
9
10
11
Difference between
experimental and simulated
cumulative oil recovery factor (%)
Cycle number
(b)
2.0
1.5
1.0
0.5
0.0
-0.5
-1.0
-1.5
0
1
2
3
4
5
6
7
8
9
10
11
Cycle number
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
60
(a)
Experiment
Simulation
50
40
30
20
10
0
0
1
2
3
4
5
6
7
8
9
10
Difference between
Cycle number
(b)
2.5
2.0
1.5
1.0
0.5
0.0
-0.5
-1.0
-1.5
0
1
2
3
4
5
6
7
8
9
10
Cycle number
recovery factor after completion of each cycle, for cyclic CO2 injection test at nearmiscible condition in non-fractured porous medium, Pop = 8.27 MPa (i.e., Test # 9).
160
70
(a)
Experiment
Simulation
60
50
40
30
20
10
0
0
1
2
3
4
5
6
7
Difference between
Cycle number
(b)
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
0
1
2
3
4
5
6
7
Cycle number
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).
161
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 fluidrock 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.
162
60
(a)
Experiment
Simulation
50
40
30
20
10
0
0
1
2
3
4
5
6
7
8
(b)
Difference between
Cycle number
6
5
4
3
2
1
0
0
1
2
3
4
5
6
7
8
Cycle number
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
80
(a)
Experiment
Simulation
60
40
20
0
0
1
2
3
4
5
6
(b)
Difference between
Cycle number
6
5
4
3
2
1
0
0
1
2
3
4
5
6
Cycle number
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
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.
165
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.
166
60
50
40
30
20
w = 0.01 cm
w = 0.02 cm
w = 0.03 cm
w = 0.04 cm
w = 0.05 cm
10
0
0
1
2
3
4
5
6
7
8
Cycle number
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
80
60
40
w = 0.01 cm
w = 0.02 cm
w = 0.03 cm
w = 0.04 cm
w = 0.05 cm
20
0
0
1
2
3
4
5
6
Cycle number
process (i.e., Pop = 9.31 MPa) vs. cycle number in a single horizontal fractured medium at
various fracture widths.
168
80
75
70
65
55
50
Immiscible cyclic CO2 injection
Miscible cyclic CO2 injection
45
0.00
0.01
0.02
0.03
0.04
0.05
0.06
Fracture width (cm)
Figure 6.14: Effect of the fracture width on the ultimate oil recovery factor of the
immiscible and miscible cyclic CO2 injection processes.
169
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).
170
60
50
40
30
20
n=1
n=2
n=3
n=4
10
0
0
1
2
3
4
5
6
7
8
Cycle number
Figure 6.15: Simulated cumulative oil recovery factor of immiscible cyclic CO 2 injection
process (i.e., Pop = 6.55 MPa) vs. cycle number in a fractured medium with different
number of fractures.
171
100
80
60
40
n=1
n=2
n=3
n=4
20
0
0
1
2
3
4
5
6
Cycle number
process (i.e., Pop = 9.31 MPa) vs. cycle number in a fractured medium with different
number of fractures.
172
80
75
70
65
55
50
Immiscible cyclic CO2 injection
Miscible cyclic CO2 injection
45
0
1
2
3
4
5
Number of fractures
Figure 6.17: Effect of the number of fractures on the ultimate oil recovery factor of
immiscible and miscible cyclic CO2 injection process.
173
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
174
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.
175
CHAPTER SEVEN
CONCLUSIONS AND RECOMMENDATIONS
7.1. Conclusions
In the present study, the performance of the cyclic CO2 injection process in nonfractured 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:
176
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
177
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
178
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
179
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 CO2produced 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
180
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
181
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.
182
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.
183
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203
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.
204
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 npentane 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.
205
APPENDIX B
EXPERIMENTAL RESULTS OF ALL CYCLIC CO2 TESTS IN NONFRACTURED 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.
206
60
10
1Cum. RF (T # 1)
2Cum. RF (T # 2)
3Cum. RF (T # 3)
4Cum. RF (T # 4)
5Cum. RF (T # 5)
50
1Stage RF (T # 1)
2Stage RF (T # 2)
3Stage RF (T # 3)
4Stage RF (T # 4)
5Stage RF (T # 5)
8
40
6
30
4
20
Cumulative recovery factor (%)
(a)
2
10
0
0
0
1
2
3
4
5
6
7
8
9
10
11
Cycle number
60
1Cum. RF (T # 1)
2Cum. RF (T # 2)
3Cum. RF (T # 3)
4Cum. RF (T # 4)
5Cum. RF (T # 5)
50
10
1Stage RF (T # 1)
2Stage RF (T # 2)
3Stage RF (T # 3)
4Stage RF (T # 4)
5Stage RF (T # 5)
8
40
6
30
4
20
(b)
2
10
0
0
0
1
2
3
4
5
6
7
8
1 Test # 1 (T
inj = 30 min, Tsoak = 24 hrs, Swc = 44.7 %)
2 Test # 2 (T
3 Test # 3 (T
4 Test # 4 (T
inj = 120 min, Tsoak = 48 hrs, Swc =45.8 %)
5 Test # 5 (T
inj = 120 min, Tsoak = 24 hrs, Swc is zero)
volume of injected CO2 for cyclic CO2 injection tests performed at Pop = 5.38 MPa.
207
1600
1Cum. GOR (T # 1)
2Cum. GOR (T # 2)
3Cum. GOR (T # 3)
4Cum. GOR (T # 4)
5Cum. GOR (T # 5)
1400
1200
10
1Cum. GUF (T # 1)
2Cum. GUF (T # 2)
3Cum. GUF (T # 3)
4Cum. GUF (T # 4)
5Cum. GUF (T # 5)
Cumulative GUF (cm3 of oil/cm3 of gas)
Cumulative producing GOR (cm3 of gas/cm3 of oil)
(a)
1
1000
0.1
800
0.01
600
400
0.001
200
0
0.0001
0
1
2
3
4
5
6
7
8
9
10
11
1600
1400
1Cum. GOR (T # 1)
1Cum. GUF (T # 1)
2Cum. GOR (T # 2)
2Cum. GUF (T # 2)
3Cum. GOR (T # 3)
4Cum. GOR (T # 4)
5Cum. GOR (T # 5)
1200
10
3Cum. GUF (T # 3)
1
4Cum. GUF (T # 4)
5Cum. GUF (T # 5)
1000
0.1
800
0.01
600
400
0.001
200
0
(b)
Cycle number
0.0001
0
1
2
3
4
5
6
7
8
1 Test # 1 (T
2 Test # 2 (T
3 Test # 3 (T
4 Test # 4 (T
inj = 120 min, Tsoak = 48 hrs, Swc =45.8 %)
5 Test # 5 (T
inj = 120 min, Tsoak = 24 hrs, Swc is zero)
208
35
30
30
25
10
25
10
5
5
0
0
1
(b)
13.0
12.0
Ultimate recovery factor (%)
35
40
Ultimate recovery factor(%)
1st stage recovery factor (%)
2
3
Test number
4
5
13.0
Wasph (1st and 2nd stage CO2-produced oil)
12.0
DFo (%)
11.0
11.0
10.0
10.0
9.0
9.0
8.0
1.0
8.0
1.0
0.5
0.5
0.0
0.0
1
2
3
4
40
(a)
5
Test number
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.
209
60
1Cum. RF (T # 6)
1 Stage RF (T # 6)
2Cum. RF (T # 7)
3Cum. RF (T # 8)
2 Stage RF (T # 7)
16
14
3 Stage RF (T # 8)
12
50
10
40
8
30
6
20
4
10
70
(a)
2
0
0
0
1
2
3
4
5
6
7
8
9
10
11
Cycle number
70
1Cum. RF (T # 6)
2Cum. RF (T # 7)
3Cum. RF (T # 8)
60
16
1 Stage RF (T # 6)
2 Stage RF (T # 7)
14
3 Stage RF (T # 8)
12
50
10
40
8
30
6
20
4
10
(b)
2
0
0
0
1
2
3
4
5
6
7
8
1 Test # 6 (T
2 Test # 7 (T
3 Test # 8 (T
inj = 120 min, Tsoak = 48 hrs, Swc = 0)
210
2000
1800
1600
0.1
1 Cum. GUF (T # 6)
1Cum. GOR (T # 6)
2Cum. GOR (T # 7)
3Cum. GOR (T # 8)
2 Cum. GUF (T # 7)
3 Cum. GUF (T # 8)
1400
0.01
1200
1000
800
0.001
600
400
200
0
(a)
0.0001
0
1
2
3
4
5
6
7
8
9
10
11
2000
1Cum. GOR (T # 6)
2Cum. GOR (T # 7)
3Cum. GOR (T # 8)
1800
1600
0.1
1 Cum. GUF (T # 6)
2 Cum. GUF (T # 7)
3 Cum. GUF (T # 8)
1400
0.01
1200
1000
800
0.001
600
400
200
0
(b)
Cycle number
0.0001
0
1
2
3
4
5
6
7
8
1 Test # 6 (T
2 Test # 7 (T
3 Test # 8 (T
211
50
60
50
40
40
30
15
30
15
10
10
5
5
0
60
(a)
0
5
6
7
8
9
13.0
13.0
st
nd
Wasph (1 and 2 stage CO2-produced oil)
12.0
12.0
DFo (%)
11.0
11.0
10.0
10.0
9.0
9.0
8.0
1.0
8.0
1.0
0.5
0.5
0.0
(b)
Test number
0.0
5
6
7
8
9
Test number
Test # 8 (Tinj = 120 min, Tsoak = 48 hrs, Swc = 0)
212
70
20
1
Cum. RF (T # 9)
2
Cum. RF (T # 10)
3
Cum. RF (T # 11)
4
Cum. RF (T # 12)
Stage RF (T # 9)
2
Stage RF (T # 10)
3
Stage RF (T # 11)
4
Stage RF (T # 12)
16
60
50
12
40
8
30
20
4
10
0
0
0
1
2
80
(b)
4
5
6
Cycle nuber
1
7
8
9
10
20
1
Cum. RF (T # 9)
2
Cum. RF (T # 10)
3
Cum. RF (T # 11)
4
Cum. RF (T # 12)
70
3
Stage RF (T # 9)
2
Stage RF (T # 10)
3
Stage RF (T # 11)
4
Stage RF (T # 12)
16
60
50
12
40
8
30
20
1
80
(a)
4
10
0
0
0.0
0.5
1.0
1.5
2.0
2.5
3.0
1 Test # 9 (T
2 Test # 10 (T = 120 min, T
inj
soak = 48 hrs, Swc = 45.4 %)
3 Test # 11 (T = 30 min, T
inj
soak = 24 hrs, Swc = 43.3 %)
4 Test # 12 (T = 120 min, T
inj
soak = 24 hrs, Swc = 0)
213
2500
1
2250
2000
0.1
1
Cum. GOR (T # 9)
2
Cum. GOR (T # 10)
3
Cum. GOR (T # 11)
4
Cum. GOR (T # 12)
Cum. GUF (T # 9)
2
Cum. GUF (T # 10)
3
Cum. GUF (T # 11)
4
Cum. GUF (T # 12)
1750
0.01
1500
1250
1000
0.001
750
500
250
0
(a)
0.0001
0
1
2
3
4
5
6
7
8
9
10
2500
1
Cum. GOR (T # 9)
2
Cum. GOR (T # 10)
3
Cum. GOR (T # 11)
4
Cum. GOR (T # 12)
2250
2000
0.1
1
Cum. GUF (T # 9)
2
Cum. GUF (T # 10)
3
Cum. GUF (T # 11)
4
Cum. GUF (T # 12)
1750
0.01
1500
1250
1000
0.001
750
500
250
0
(b)
Cycle nuber
0.0001
0.0
0.5
1.0
1.5
2.0
2.5
3.0
1 Test # 9 (T
2 Test # 10 (T = 120 min, T
inj
soak = 48 hrs, Swc = 45.4 %)
3 Test # 11 (T = 30 min, T
inj
soak = 24 hrs, Swc = 43.3 %)
4 Test # 12 (T = 120 min, T
inj
soak = 24 hrs, Swc = 0)
214
60
70
60
50
50
40
20
40
20
15
15
10
10
5
5
0
70
(a)
0
8
9
10
11
12
13
16.0
16.0
15.0
15.0
DFo (%)
14.0
14.0
13.0
13.0
12.0
12.0
11.0
1.0
11.0
1.0
0.5
0.5
0.0
(b)
Test number
0.0
8
9
10
11
12
13
Test number
215
1Cum. RF (T # 13)
2Cum. RF (T # 14)
3Cum. RF (T # 15)
70
30
1 Stage RF (T # 13)
2 Stage RF (T # 14)
3 Stage RF (T # 15)
27
24
60
21
50
18
40
15
12
30
9
20
80
(a)
6
10
3
0
0
0
1
2
3
4
5
6
7
Cycle number
80
70
30
1Cum. RF (T # 13)
2Cum. RF (T # 14)
3Cum. RF (T # 15)
1 Stage RF (T # 13)
2 Stage RF (T # 14)
3 Stage RF (T # 15)
27
24
60
21
50
18
40
15
12
30
9
20
(b)
6
10
3
0
0
0.0
0.4
0.8
1.2
1.6
2.0
1 Test # 13 (T
2 Test # 14 (T
3 Test # 15 (T
216
1200
1000
1Cum. GOR (T # 13)
1 Cum. GUF (T # 13)
2Cum. GOR (T # 14)
2 Cum. GUF (T # 14)
3Cum. GOR (T # 15)
3 Cum. GUF (T # 15)
0.1
800
0.01
600
400
0.001
200
0
(a)
0.0001
0
1
2
3
4
5
6
7
1200
1Cum. GOR (T # 13)
2Cum. GOR (T # 14)
3Cum. GOR (T # 15)
1000
0.1
1 Cum. GUF (T # 13)
2 Cum. GUF (T # 14)
3 Cum. GUF (T # 15)
800
0.01
600
400
0.001
200
0
(b)
Cycle number
0.0001
0.0
0.4
0.8
1.2
1.6
2.0
1 Test # 13 (T
2 Test # 14 (T
3 Test # 15 (T
217
70
80
70
60
60
50
30
50
30
25
25
20
20
15
15
10
10
5
5
0
80
(a)
0
12
13
14
15
16
16.0
16.0
15.0
15.0
DFo (%)
14.0
14.0
13.0
13.0
12.0
1.0
12.0
1.0
0.5
0.5
0.0
(b)
Test number
0.0
12
13
14
15
16
Test number
218
1Cum. RF (T # 16)
2Cum. RF (T # 17)
3Cum. RF (T # 18)
70
30
1 Stage RF (T # 16)
2 Stage RF (T # 17)
3 Stage RF (T # 18)
27
24
60
21
50
18
40
15
12
30
9
20
80
(a)
6
10
3
0
0
0
1
2
3
4
5
6
7
Cycle number
80
1Cum. RF (T # 16)
2Cum. RF (T # 17)
3Cum. RF (T # 18)
70
30
1 Stage RF (T # 16)
2 Stage RF (T # 17)
3 Stage RF (T # 18)
27
24
60
21
50
18
40
15
12
30
9
20
(b)
6
10
3
0
0
0.0
0.4
0.8
1.2
1.6
2.0
1 Test # 16 (T
2 Test # 17 (T
3 Test # 18 (T
219
1200
1Cum. GOR (T # 16)
2Cum. GOR (T # 17)
3Cum. GOR (T # 18)
1000
0.1
1 Cum. GUF (T # 16)
2 Cum. GUF (T # 17)
3 Cum. GUF (T # 18)
800
0.01
600
400
0.001
200
0
(a)
0.0001
0
1
2
3
4
5
6
7
1200
1Cum. GOR (T # 16)
2Cum. GOR (T # 17)
3Cum. GOR (T # 18)
1000
0.1
1 Cum. GUF (T # 16)
2 Cum. GUF (T # 17)
3 Cum. GUF (T # 18)
800
0.01
600
400
0.001
200
0
(b)
Cycle number
0.0001
0.0
0.4
0.8
1.2
1.6
2.0
1 Test # 16 (T
2 Test # 17 (T
3 Test # 18 (T
220
70
80
70
60
60
50
30
50
30
25
25
20
20
15
15
10
10
5
5
0
80
(a)
0
15
16
17
18
19
16.0
16.0
15.0
15.0
DFo (%)
14.0
14.0
13.0
13.0
12.0
1.0
12.0
1.0
0.5
0.5
0.0
(b)
Test number
0.0
15
16
17
18
19
Test number
221
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
222
Oil Recovery Performance of Immiscible and Miscible CO2 Huff-and-Puff
Processes
Energy & Fuels, 28 (2), 774–784, 2014
223
On the CO2 Storage Potential of Cyclic CO2 Injection Process for
Enhanced Oil Recovery
Fuel, 124, 14–27, 2014
224
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
225
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
226
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
227
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
228

mechanisms of oil recovery during cyclic co2 injection

Transcription

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