copyright 2020, jiawei tu
TRANSCRIPT
Investigation of Enhanced Oil Recovery through Fracturing Fluid Imbibition in
Unconventional Oil Reservoirs
by
Jiawei Tu, M.S.
A Dissertation
In
Petroleum Engineering
Submitted to the Graduate Faculty
of Texas Tech University in
Partial Fulfillment of
the Requirements for
the Degree of
DOCTOR OF PHILOSOPHY
Approved
James J. Sheng
Chair of Committee
Sheldon Gorell
Ion Ispas
Qingwang Yuan
Mark Sheridan
Dean of the Graduate School
December 2020
Copyright 2020, Jiawei Tu
Texas Tech University, Jiawei Tu, December 2020
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ACKNOWLEDGMENTS
First and foremost, I would like to express my sincere gratitude to my advisor
Dr. James J. Sheng. His guidance and support have been immensely instrumental in
the success of my doctorate program. He has put in a lot of time and effort to provide
valuable insights into my work that helped me improve my research skills in my
career. Most importantly, I am deeply indebted to him for continuously having faith in
me and providing me with an assistantship throughout my doctoral education. This
greatly supported me with my finances towards finishing my degree work. I have been
very grateful to have a mentor who is prestigious in the industry, dedicated to the
research, and caring about student’s wellbeing.
I would like to extend my appreciation to my other graduate committee
members: Dr. Sheldon Gorell, Dr. Ion Ispas, and Dr. Qingwang Yuan for providing
valuable comments and serving on my defense committee.
To my mother and family, I am ever thankful for their love, support, and
encouragement throughout my entire life. This work would not have been complete
without the guidance of my colleagues and dearest friends, Lei Li, Yu Pang, Ziqi
Shen, Sharanya Sharma, Srikanth Tangirala, Xiukun Wang, and Nur Wijaya. I
appreciate all the help that you all have provided to me.
Finally, I would like to express my sincere appreciation to Dr. Marshall
Watson, Heather Johnson, Charlotte Stockton, Cecil Millikan from the Bob L. Herd
Department of Petroleum Engineering, and the Graduate School for all the
assistantship, scholarships they provided towards my program.
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TABLE OF CONTENTS
ACKNOWLEDGMENTS ........................................................................................ ii
ABSTRACT ......................................................................................................... vi
LIST OF TABLES .............................................................................................. viii
LIST OF FIGURES .............................................................................................. ix
I. INTRODUCTION ............................................................................................... 1
1.1 Background and Problem Statement .................................................... 1
1.2 Objective of the Study .......................................................................... 3
1.3 Organization of the Dissertation .......................................................... 4
II. LITERATURE REVIEW ................................................................................... 6
2.1 Interfacial Tension and Wettability .......................................................... 6
2.2 Flows in Porous Media. ......................................................................... 11
2.3 Characteristics of surfactant and surfactant EOR .................................. 14
2.3.1 IFT Reduction and Wettability Alteration of Surfactant .............................. 14
2.3.2 Surfactant selection .................................................................................... 17
III. EXPERIMENTAL METHODOLOGY ............................................................. 19
3.1 Experimental Materials .......................................................................... 19
3.1.1 Rock samples ............................................................................................. 19
3.1.2 Fluid samples ............................................................................................. 20
Crude oil .............................................................................................................. 20
Brine .................................................................................................................... 21
Surfactants .......................................................................................................... 21
3.2 Preparation Experiments ........................................................................ 22
3.2.1 Core Saturation .......................................................................................... 22
Core saturation without aging ............................................................................. 23
Core saturation with aging .................................................................................. 24
3.2.2 Wettability determination ............................................................................ 24
Contact Angle measurement for air-rock-liquid system ...................................... 25
Contact Angle measurement for air-rock-liquid system ...................................... 25
3.2.3 Surfactant evaluation ................................................................................. 26
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Interfacial tension reduction ................................................................................ 26
Wettability alteration ............................................................................................ 28
3.2.4 Permeability and porosity determination .................................................... 29
3.3 Spontaneous Imbibition Experiments .................................................... 31
3.4 Forced Imbibition Experiments.............................................................. 32
3.4.1 Forced imbibition with constant soaking .................................................... 32
3.4.2 Imbibition with cyclic pressurization ........................................................... 35
IV. MECHANISM STUDY OF IMBIBITION IN UNCONVENTIONAL FORMATION 37
4.1 Overview of Mechanisms of Imbibition ................................................ 37
4.1.1 Mechanism of spontaneous imbibition ....................................................... 38
4.1.2 Mechanism of forced imbibition ................................................................. 39
4.1.3 Counter-current imbibition and co-current imbibition ................................. 40
4.2 Experimental Study ................................................................................ 41
4.2.1 Experiment design ..................................................................................... 41
4.2.2 Determination of testing pressures ............................................................ 42
4.2.3 Experimental results and discussion .......................................................... 44
Recovery profile of spontaneous imbibition experiments ................................... 44
Comparison of final recovery under pressurized condition ................................. 47
4.3. Numerical Simulation of Lab Scale Model ........................................... 49
4.3.1 Model description and validation ................................................................ 49
Sandstone model ................................................................................................ 49
Shale model ........................................................................................................ 53
4.3.2 Results of core experiments modeling ....................................................... 54
4.3.3 Effect of soaking pressure on forced imbibition ......................................... 56
Model modification .............................................................................................. 56
Mechanism of forced imbibition in oil-wet shale.................................................. 56
Mechanism of forced imbibition in water-wet shale ............................................ 60
Further analysis of forced imbibition characters ................................................. 62
4.4. Further Analysis of Reservoir Scale Modeling ..................................... 68
4.4.1 Base Reservoir model description ............................................................. 68
4.4.2 Effect of cluster spacing ............................................................................. 71
4.4.3 Effect of wettability ..................................................................................... 74
4.4.4 Effect of permeability.................................................................................. 77
4.4.5 Effect of initial water saturation .................................................................. 79
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V. STUDY OF SURFACTANT EOR IN UNCONVENTIONAL OIL RESERVOIRS ... 80
5.1 Spontaneous Imbibition with Surfactant in Oil-wet Shale ..................... 81
5.1.1 Experimental study ..................................................................................... 81
Experiment design .............................................................................................. 81
Experiment results and discussion ..................................................................... 83
5.1.2 Simulation study ......................................................................................... 85
Modeling of interfacial tension reduction ............................................................. 86
Modeling of wettability alteration ......................................................................... 87
Modeling of spontaneous imbibition in oil-wet matrix ......................................... 89
Model validation .................................................................................................. 90
Model adjustment ................................................................................................ 93
Comparison between experimental and simulation results ................................ 97
Sensitivity studies: Effect of interfacial tension and wettability ........................... 99
5.2 Forced Imbibition with Surfactant in Oil-wet Shale ............................ 103
5.2.1 Experimental design................................................................................. 103
5.2.2 Result comparison and discussion .......................................................... 104
Effect of soaking fluid ........................................................................................ 110
Effect of operational techniques ........................................................................ 111
VI. CONCLUDING REMARKS AND CONCLUSIONS ......................................... 113
6.1 Imbibition in unconventional reservoirs .............................................. 113
6.1.1 Spontaneous imbibition ............................................................................ 113
6.1.2 Forced imbibition ...................................................................................... 113
Forced imbibition in core scale model ............................................................... 114
Forced imbibition in reservoir scale model ........................................................ 115
Sensitivity analysis of influential factors ............................................................ 116
6.2 Surfactant EOR in Unconventional Oil Reservoirs ............................. 116
6.3 Methods of Implementation ................................................................. 118
BIBLIOGRAPHY .............................................................................................. 119
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ABSTRACT
Crude oil productions from unconventional reservoirs continue to increase and
will remain as the leading source of fuel energy supply in the United States. The oil
recovery from this type of reservoirs usually relies on the depletion after horizontal well
drilling and multi-stage hydraulic fracturing technology. However, the steep decline rate
still constrains the ultimate hydrocarbon recovery. While most current Enhanced Oil
Recovery approaches resort to replenish reservoir energies through gas injection or
cyclic gas injection after the primary recovery phase, this study focuses on the
possibility of enhancing tight oil recovery through fracturing fluid imbibition during the
stage of well completion.
This dissertation combines the approaches of experimental and numerical
simulation to investigate the mechanisms of liquid imbibition in shale matrix with
different manners. The experiments firstly simulate the process of spontaneous
imbibition, forced imbibition, and imbibition under cyclic pressurizations in tight sand,
carbonate, and shale core plugs. Meanwhile, a high-pressure imbibition test set-up is
designed to execute the proposed experiments. Numerical simulation approach is used
to further probe in the mechanisms of imbibition with both core and field-scale models.
Models are tuned with the experimental results based on the recovery factors. The
results indicate that capillary pressure is the primary driving force for the water-wet
matrix, while the effect of gravity is insignificant in unconventional reservoirs
regardless of the wettability. In a hydraulic fracture – matrix system, counter-current
flow is the dominant imbibition behavior. The effect of externally applied pressure
gradient is nonessential on the core-scale model but negatively impacts the recovery in
the reservoir scale water-wet matrix. The effect of pressure is insignificant for oil-wet
matrix. Similarly, the effect of cyclic pressurization is minor on the imbibition process
itself as well.
Shale oil reservoirs are characterized by oil-wet status which further reduces the
oil production and complicates the imbibition behaviors. The effect of wettability
alteration agents is further studied. Imbibition experiments with the presence of
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surfactants are conducted in the same manner. A numerical model with phase behavior
considered is developed to investigate the tendency of imbibition in initially oil-wet core
plugs quantitatively. The experimental results implicate that the wettability of oil-wet
shale core can be effectively converted to a more water-wet status with the presence of
a nonionic surfactant. Oil recovery is significantly enhanced compared with the cores
without wettability alteration agents. It is concluded that the surfactant with the ability
to alter the wettability of rock surface to more water-wet status while maintaining high
interfacial tension between oleic and aqueous phases is the best candidate to trigger
spontaneous imbibition. The effect of pressure is notable from our experimental results
and cyclic injection is the most efficient manner as the process of wettability alteration
is expedited.
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LIST OF TABLES
1. 1 Technically recoverable shale oil and shale gas resources in
the world.......................................................................................................... 2
3. 1 Properties of core samples ............................................................................ 19
3. 2 Mineralogical composition of core samples ................................................. 20
3. 3 Properties of the crude oil sample. ................................................................ 20
3. 4 Mole percent data of the crude oil sample. ................................................... 21
3. 5 Selected surfactant candidates in this study .................................................. 22
4. 1 Properties of core samples ............................................................................ 42
4. 2 The range of possible soaking pressure at each depth .................................. 44
4. 3 Results of Spontaneous Imbibition Experiments .......................................... 45
4. 4 Final Recovery Factors of spontaneous and forced
experiments ................................................................................................... 48
4. 5 Petrophysical parameters of sandstone base model ...................................... 51
4. 6 Petrophysical parameters of shale base model .............................................. 54
4. 7 Matrix and fracture properties of the base reservoir model .......................... 69
4. 8 Case design for the effect of cluster spacing and analysis on
the effects ...................................................................................................... 73
4. 9 Case design for the effect of permeability .................................................... 77
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LIST OF FIGURES
1. 1 Current and projected U.S. crude oil source distribution ................................ 1
2. 1 Schematic of a system of two immiscible liquids in contact
with a mineral surface ..................................................................................... 7
2. 2 Surface tensions at the three-phase intersection .............................................. 8
2. 3 Distribution of water and oil in porous media .............................................. 10
2. 4 Resultant force in different wetting systems ................................................. 12
2. 5 Schematic capillary desaturation curve ......................................................... 13
2. 6 Mechanism of cationic surfactant wettability alteration ............................... 16
2. 7 Mechanism of anionic surfactant wettability alteration ................................ 17
3. 1 Schematic of the core saturation setup. ......................................................... 23
3. 2 Drop shape analyzer DSA25 for contact angle measurement ....................... 26
3. 3 The schematic illustration of the captive bubble method.............................. 26
3. 4 GRACE Spinning drop tensiometer M6500 ................................................. 27
3. 5 Illustration of the Amott cell for spontaneous imbibition
experiment ..................................................................................................... 32
3. 6 Schematic of the imbibition experiment setup .............................................. 35
4. 1 Water saturation profile of oil-wet shale cores counter-current
imbibition. ..................................................................................................... 41
4. 2 Wettability pre-evaluation by Contact Angle measurement ......................... 42
4. 3 The illustration of the multi-stage hydraulic fracturing process ................... 43
4. 4 Recovery Profiles of Spontaneous Imbibition experiments .......................... 45
4. 5 Oil recovered from the bottom by overcoming the
gravitational force ......................................................................................... 46
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4. 6 Untraceable oil recovery during the imbibition on carbonate
oil-wet cores .................................................................................................. 46
4. 7 Results of forced imbibition tests on three types of rocks ............................ 48
4. 8 Illustration of numerical simulation model in CMG STARS ....................... 50
4. 9 Relative permeability (Left) and capillary pressure (Right)
curves of base sandstone model .................................................................... 50
4. 10 Base model with local gridblock refinement ............................................... 52
4. 11 Influence of the number of gridblocks and sandstone base
case history matching .................................................................................. 52
4. 12 Results of History Matching of Sandstone and Shale .................................. 53
4. 13 Relative permeability (Left) and capillary pressure (Right)
curves of shale model with different wettability ......................................... 54
4. 14 Results of forced imbibition on core-scale water-wet
sandstone ..................................................................................................... 55
4. 15 Results of forced imbibition on core-scale oil-wet shale ............................. 56
4. 16 Oil phase pressures (𝑃𝑜) and oil saturation (𝑆𝑜) within block
(15,6,6) and (16,6,6) of SI on large scale oil-wet shale ............................... 58
4. 17 Oil phase pressures (𝑃𝑜) and oil saturation (𝑆𝑜) within block
(15,6,6) and (16,6,6) of FI at 3000 psi on large scale oil-wet
shale ............................................................................................................. 58
4. 18 Results of forced imbibition on large scale oil-wet shale ............................ 59
4. 19 Oil phase pressures (𝑃𝑜) and oil saturation (𝑆𝑜) within block
(15,6,6) and (16,6,6) of FI at 3000 psi on large scale water-
wet shale ...................................................................................................... 59
4. 20 Results of forced imbibition on large scale water-wet shale........................ 61
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4. 21 Path of pressure profiles and the pressure distribution of FI
1000 psi at 24hr ........................................................................................... 61
4. 22 Pressure profiles of different forced imbibition cases.................................. 65
4. 23 Pressure profiles (Left) and dimensionless pressure profiles
(Right) based on different time ..................................................................... 67
4. 24 Side view of the base reservoir model ......................................................... 70
4. 25 Aerial view of the base reservoir model ...................................................... 70
4. 26 RF profiles vs. different cluster/stage of the reservoir model ...................... 73
4. 27 RFs of different cluster spacings at 365 days............................................... 74
4. 28 Relative permeability curves set .................................................................. 75
4. 29 Capillary pressure curves set ........................................................................ 76
4. 30 The recover factors of 5 timesteps that reflect the effects of
external pressures and reservoir wettability. ............................................... 76
4. 31 Capillary pressure curves set for different permeabilities............................ 78
4. 32 Capillary pressure curves set for different permeabilities............................ 78
4. 33 Capillary pressure decreases as the water increased .................................... 79
4. 34 Correlation of imbibed volume and initial water saturation ........................ 79
5. 1 Contact angle of core samples after saturation and aging (Oil-Wet) 81
5. 2 Spontaneous imbibition experiment apparatus ............................................ 82
5. 3 Recovery profiles of Spontaneous imbibition experiments ......................... 84
5. 4 Illustration of the base case simulation model (blue blocks
represent the core plug and the red blocks represent the
soaking environment in Amott Cell) ........................................................... 85
5. 5 Schematic of Kr and Pc curves interpolation ............................................... 88
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5. 6 Capillary pressure curves of oil-wet and water-wet for the
base carbonate cases .................................................................................... 89
5. 7 Surfactant adsorption isothermal.................................................................. 91
5. 8 Correlation between surfactant concentration and
solubilization parameter .............................................................................. 91
5. 9 Correlation between solubilization parameter and IFT ................................ 92
5. 10 History Matching results of spontaneous imbibition from
carbonates .................................................................................................... 92
5. 11 Relative permeability curves for different IFTs of oil-wet
(left) and water-wet (right) cases ................................................................. 94
5. 12 Capillary pressure curves of oil-wet and water-wet cases
with different IFTs ....................................................................................... 95
5. 13 10-times refinement shale imbibition model............................................... 96
5. 14 Sensitivity analysis of grid block numbers on shale model ........................ 97
5. 15 Comparison between experimental and simulation results ......................... 98
5. 16 Sensitivity analysis results of interfacial tension ........................................ 99
5. 17 Sensitivity analysis results of wettability .................................................. 100
5. 18 Analysis of gravity effect on carbonate and shale models ........................ 101
5. 19 Combined effects of IFT and wettability .................................................. 102
5. 20 Contact Angles after surfactant treatment (from left to right:
high IFT, intermediate IFT, low IFT ) ..................................................... 103
5. 21 Recovery profile of spontaneous imbibition tests ..................................... 106
5. 22 Recovery profile of forced imbibition tests .............................................. 107
5. 23 Recovery profile of cyclic injection tests .................................................. 107
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5. 24 Cyclic injection tests in 5% KCl ............................................................... 108
5. 25 Cyclic injection tests in High IFT Surfactant (3mN/m) ............................ 108
5. 26 Cyclic injection tests in Intermediate IFT Surfactant (0.4
mN/m) ...................................................................................................... 109
5. 27 Cyclic injection tests in Low IFT Surfactant (0.02 mN/m) ...................... 109
5. 28 Comparison of final recoveries ................................................................. 110
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CHAPTER Ⅰ
INTRODUCTION
In this chapter, the background information of this dissertation is introduced,
and the research motivation and the objectives are explained. The organization of this
dissertation is briefed.
1.1 Background and Problem Statement
The latest U.S. EIA’s annual energy outlook (2020) predicts that oil production
from tight and shale formations remains as the leading source of the U.S. crude oil
supply till 2050. (Center 2020) However, oil production from this type of reservoir is
known to be declining fast and low in primary recovery. For example, the newest first-
year productions declined between 65% to 85% among those newly completed wells
in 2019 at Permian Basin.(Xu, Yu et al. 2017)
Figure 1. 1 Current and projected U.S. crude oil source distribution (Center 2020)
The economical production of unconventional oil reservoirs depends on
multistage hydraulic fracturing treatments. The current primary recovery strategy is
reservoir depletion. This strategy is strongly dependent on the reservoir pressure drop
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and hydrocarbon expansion.(Tran, Sinurat et al. 2011, Ozkan, Kurtoglu et al. 2012,
Sheng and Chen 2014, Sheng 2015, Dembicki 2016, Pang, Hu et al. 2020) Through
this technique, the recovery from liquid-rich shale reservoirs is reported to be less than
10%.(Mantell 2013, Sheng 2017) To further improve the oil production, gas huff-n-
puff and gas injection are well-investigated methods. Some selected types of gas are,
for example, carbon dioxide, methane, and nitrogen.(Sheng and Chen 2014, Sheng
2015, Li and Sheng 2016, Li, Zhang et al. 2017, Li, Sheng et al. 2018) This technique
is initiated during or after the primary recovery by replenishing the depleted reservoir
pressure or achieving the miscibility. By implementing this strategy, recovery factors
are reported to increase by 6 to 20% of OOIP in field operations.(Hoffman 2012)
However, the cost of gas separation, transportation, storage, and compression has
become the main challenge given the current low oil prices.(Jia, Tsau et al. 2019)
Table 1. 1 Technically recoverable shale oil and shale gas resources in the world (EIA
2015)
During the hydraulic fracturing operations, a large amount of fracturing fluid
was injected at high pressure with chemical additives and proppants to keep the
fractures from closing. Without the wells being soaked intentionally, this pressurized
state may sustain for more than a month before flow-back and production. It has been
noticed that a great percentage of fracturing fluid was retained inside of the rock
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matrix. From the field experiences, the flowback water recovery could be as low as
5% of the total injection volume in Hayneville shale to as high as 50% of that in
Barnett and Marcellus shales (King 2012, Fakcharoenphol, Torcuk et al. 2013). While
some reserchers concern that it may cause a significant reduction in relative
permeability of hydrocarbon, some believe that this process could be ustilized to
displace oil from the matrix into the fracture networks and enhance oil recovery in
shale reservoirs through imbibition (Yaich, Williams et al. 2015, Sheng 2017) By
utilizing this peculiar character of shale reservoir, oil recovery from this type of
reservoirs could be improved.
Due to the oil-wet to mixed-wet nature of shale and tight oil reservoirs,
chemical agents such as surfactant is necessary to induce the imbibition. Adding
surfactant into injected fluid may reduce oil-water interfacial tension and alter the
wettability and thereby improve recovery. (Hirasaki, Miller et al. 2008) This idea has
been well studied in conventional and carbonate reservoirs for decades. However, the
mechanism of surfactant EOR in unconventional oil reservoirs is not clear.
Therefore, the feasibility of Enhanced Oil Recovery in unconventional oil
reservoirs through fracturing fluid imbibition came into our research scope.
1.2 Objective of the Study
The main objective of this dissertation is to investigate the potential of
enhancing oil recovery through fracturing fluid imbibition in unconventional oil
reservoirs during the well completion stage. This dissertation will approach this topic
through the combination of experimental and numerical simulation study.
Experiments will be designed, and numerical simulation models will be built
and verified to investigate the mechanisms of liquid imbibition in unconventional
matrix. Further, feasibility analysis of different implementation methods is conducted.
Chemical agents, such as surfactant, were studied to induce the imbibition in oil-wet
shale and tight reservoirs.
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This work enables the idea of enacting liquid imbibition in oil-wet
unconventional reservoirs to improve oil recovery. This topic of utilizing imbibition
during the completion stage will bring potential hydrocarbon recovery before a well
starts to produce, and to avoid further investment given the unstable global crude oil
market.
1.3 Organization of the Dissertation
This dissertation is divided into six chapters.
Chapter I introduces the background information of this dissertation topic and
explains the research motivation and the objectives.
Chapter II gives a literature review on the concept of spontaneous imbibition,
forced imbibition, surfactant Enhanced Oil Recovery (EOR) in unconventional
reservoirs. The up to date state of art was summarized.
Chapter III describes the experimental methodology, workflow, and
procedures used in this dissertation. It includes descriptions of experimental materials,
preparation experiments such as core saturation, petrophysics properties
determination, and surfactant evaluation; operations of spontaneous imbibition and
forced imbibition and experimental apparatus.
Chapter IV presents the results and discussion of the experimental and
numerical simulation study of the mechanisms of imbibition in unconventional
reservoirs. The experimental results include spontaneous imbibition and forced
imbibition. Simulation model was verified with the experimental data. This chapter
summarized the mechanism of imbibition and the effects of soaking pressure on both
water-wet and oil-wet scenarios.
Chapter V presents the experimental and simulation work of surfactant EOR in
oil-wet shale reservoir. This chapter is essential to investigate the feasibility of
imbibition EOR in shale because the oil-wet nature. Chemical agent such as surfactant
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need to be introduced to trigger the imbibition. Different implementation approach
such as pressurized soaking and cyclic pressurization with different soaking fluid were
investigated experimentally.
Chapter VI summarizes the research work presented in this dissertation and
presents the conclusions drawn from the work.
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CHAPTER Ⅱ
LITERATURE REVIEW
2.1 Interfacial Tension and Wettability
In a multiple phases system, it is necessary to consider the effect of the forces
at the interface when two immiscible fluids are in contact. The fluids could be gas, oil,
and water in a petroleum reservoir. The terms of surface tension and interfacial tension
are used to describe the forces existing at the interfaces of gas-liquid and liquid-liquid,
respectively. For an oil-water interface, a molecule at the interface has a force acting
upon it from the oil layer immediately above the interface and the water layer below
the interface. The resultant forces are not balanced because the magnitude of forces is
different, which results in interfacial tension. Generally, the interfacial tension of two
liquids is less than the highest individual surface tension of one of the liquids because
the mutual attraction is moderated by all molecules involved. Therefore, the interfacial
or surface tension has the dimensions of force per unit length usually expressed as
𝑚𝑁 𝑚⁄ (𝑑𝑦𝑛 𝑐𝑚⁄ ) and commonly denoted by the Greek symbol 𝜎. Most IFT values
of reservoir crude oil and brine are about 25 𝑚𝑁 𝑚⁄ . (Dandekar 2013)
Reservoir wettability plays an important role in various oil recovery processes.
There are a few definitions of wettability, and it is generally a term used to describe
the relative adhesion of two fluids to a solid surface or defined as the tendency of one
fluid to spread on a solid surface in the presence of other immiscible fluids. This is a
major factor controlling the location, flow, and distribution of fluids in a reservoir.
Many investigations of wettability and its effects on oil recovery have concluded that
there is a favorable reservoir wettability for operators to recover maximum crude oil
from a given reservoir.
The degree of wetness can be described by the contact angle or the adhesion
work. At any point located on the liquid-liquid-solid or gas-liquid-solid triple line,
each sketch illustrates a small liquid droplet is resting on a flat horizontal solid
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surface, the tangent line drawn tangential to the liquid-liquid or gas-solid interface
forms an angle with the solid-liquid interface. This angle θ is called the contact angle
(Figure 2.1). For a system composed of oil, water, and rock, wetting can be
characterized into the following types:
Water-wet: θ < 75°. In this case, the rock can be wetted up by water, meaning
that the rock has good hydrophilicity.
Intermediate-wet: 75° < θ < 105°. In this case, the rock has about equivalent
capacities to wet up oil and water, so the rock has both hydrophilicity and
lipophilicity.
Oil-wet: θ > 105°. In this case, the rock can be wetted up by oil, meaning that
the rock has good lipophilicity.
Figure 2. 1 Schematic of a system of two immiscible liquids in contact with a mineral
surface (Abdallah, Buckley et al. 1986)
The spreading of a fluid covering the solid surface results from the interactions
among the surface tensions occurring along the line of contact where three phases
meet. In Figure 2.2 taking the intersection as an example, gives the three surface
tensions at each point of the contact triple line: the gas-liquid surface tension
𝜎𝐿𝐺(𝛾𝐿𝐺), the gas-solid surface tension 𝜎𝑆𝐺(𝛾𝑆𝐺), and the liquid-solid surface tension
𝜎𝑆𝐿(𝛾𝑆𝐿). In equilibrium, the three surface tensions satisfy such a correlation equation
(Young’s Equation):
𝜎𝑆𝐺 = 𝜎𝑆𝐿 + 𝜎𝐿𝐺𝑐𝑜𝑠𝜃
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By rearranging the equation above, we can get:
𝑐𝑜𝑠𝜃 =𝜎𝑆𝐺 − 𝜎𝑆𝐿
𝜎𝐿𝐺
𝜃 = 𝑎𝑟𝑐𝑐𝑜𝑠𝜎𝑆𝐺 − 𝜎𝑆𝐿
𝜎𝐿𝐺
Figure 2. 2 Surface tensions at the three-phase intersection
Another indicator for the magnitude of wetting of a rock is the adhesion work,
which means the work required in the environment of a non-wetting phase to separate
per unit area of the wetting phase from the solid surface.
If phase 1 is solid, phase 2 is liquid, and the surrounding phase is gas, the work
is converted into new surface energy of the solid. Denoting the surface-energy
increment as the symbol ∆Us, we can calculate it in this relation:
∆Us = 𝑈2 − 𝑈1 = (𝜎𝐿𝐺 + 𝜎𝐺𝑆) − 𝜎𝐿𝑆
Where, 𝑈1, 𝑈2—the specific surface energy before and after the leaving of the
wetting phase from the solid surface;
𝜎𝐿𝐺 , 𝜎𝐺𝑆 , 𝜎𝐿𝑆— the liquid-gas, gas-solid, liquid-solid surface tension.
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In terms of the concept of surface tension, we can know that (𝜎𝐿𝐺 + 𝜎𝐺𝑆) >
𝜎𝐿𝑆. So, ∆Us > 0, meaning that the surface energy of the system has increased. This
increment of surface energy is equal to the adhesion work W:
W = ∆Us = 𝑈2 − 𝑈1 = (𝜎𝐿𝐺 + 𝜎𝐺𝑆) − 𝜎𝐿𝑆 = (𝜎𝐺𝑆 − 𝜎𝐿𝑆) + 𝜎𝐿𝐺
By rearranging Young’s equation:
W = 𝜎𝐿𝐺(1 + 𝑐𝑜𝑠𝜃)
According to the equation above, a smaller contact angle 𝜃 is indicative of a
greater adhesion work W and thereby a better spreading of the wetting phase on the
solid surface. Therefore, the adhesion work can be used to tell the level of rock
wettability: for an oil-water-rock three-phase system, the rock is hydrophilic (water-
wet) if the adhesion work is greater than the oil-water surface tension; and the rock is
lipophilic (oil-wet) if the adhesion work is smaller than the oil-water surface tension;
and the rock is neutral- wet if the adhesion work is equal to the oil-water surface
tension.
The original wettability of a formation and altered wettability during and after
hydrocarbon migration influence the profile of initial water saturation and production
characteristics in the reservoir by affect the condition of oil-water distribution in
porous media. It has been commonly accepted that for most reservoirs are water-wet
before the hydrocarbon migration and exhibit a long transition zone, through which
saturation changes gradually from mostly oil with irreducible water at the top of the
transition zone to water at the bottom. Such a distribution behavior is decided by the
buoyancy pressure and capillary pressure between the oil and water phases, as has
been discussed above. When oil migrating into an oil-wet reservoir would display a
different saturation profile: essentially maximum oil saturation down to the base of the
reservoir. This difference reflects the ease of invasion by a wetting fluid.
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Most importantly, wettability can also affect the amount of producible oil in
the matrix, as measured after waterflooding by the residual oil saturation. In the case
of water-wet formation, injected water imbibes into a matrix block and displaces the
crude oil. After a certain period of displacement, oil remains in the larger pores, where
it can snap off, or become disconnected from a continuous mass of oil, and become
trapped. As in the oil-wet formation, oil is trapped by capillary pressure, due to the
adherence to the surfaces of the matrix (Figure 2.3). Also, could be trapped by water
globules as the non-wetting phase snap-off effects. Therefore, the intermediate wet
rocks usually obtain the highest recovery or lowest residual oil saturation(Kennedy,
Burja et al. 1955, Amott 1959, Owolabi and Watson 1993, Jadhunandan and Morrow
1995, Chen, Hirasaki et al. 2004) Finally, increasing the possibility of a continuous
path to a producing well, and resulting in a lower residual oil saturation. This feature
will influence the performance of gas and water flooding greatly.
Figure 2. 3 Distribution of water and oil in porous media (Abdallah, Buckley et al.
1986)
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2.2 Flows in Porous Media.
There are three influential factors affect the multiphase flows in porous media,
which are viscous force, gravity force, and capillary force. In porous media, these
forces act on each phases of fluids, also interact between phases. The flows in porous
media or oil recovery are the result of competitions among these forces.
Viscous force is the result of fluid viscosity, and it is caused by the friction
among molecules within the fluid. The magnitude of viscous force is proportional to
the contact area between fluid layers and the velocity gradient. The coefficient is
defined as viscosity (𝜇). In a single capillary tube, it can be expressed as:
𝐹 = 𝜇𝐴𝑑𝑣
𝑑𝑟
where, A is the area of the cylinder layer with a distance r away from the
center line; 𝑑𝑣
𝑑𝑟 is the velocity gradient; F is the viscous force.
The capillary forces in a petroleum reservoir are the result of the combined
effect of the surface and interfacial tensions of the rock and fluids, the pore size and
geometry, and the wetting characteristics of the system. When two immiscible fluids
are in contact, a discontinuity in pressure exists between the two fluids (For example:
oil – water, oil – gas, water - gas). This pressure difference depends upon the
curvature of the interface separating the fluids and is referred to as the capillary
pressure (𝑃𝑐). The displacement of one fluid by another in the porous media is either
assisted or resisted by the capillary pressure. In a single capillary tube, the capillary
pressure can be expressed by Young-Laplace equation:
𝑃𝑐 =2𝜎𝑐𝑜𝑠𝜃
𝑟
where 𝜎 is the interfacial tension; 𝜃 is the contact angle; 𝑟 is the radius of the
pore.
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Finally, the gravity force depending on the density difference of two phases of
fluids under the gravity field. The process of gravity dominant current flow is also
known as buoyancy-driven, and it is related to the fluid density difference (∆𝜌) and
gravitational acceleration (𝑔).
The displacement during a drainage or imbibition process in a two phases
system is the result of competition among vicious, capillary, and gravity forces. For
different wetting conditions, the movability of a single oil globule is different. Figure
2.4 shows the resultant force that exists in three types of wetting conditions.
Figure 2. 4 Resultant force in different wetting systems
A set of dimensionless numbers is usually defined to quantify these relative
magnitudes. The capillary number (𝑁𝐶) is the typical ratio of the viscous pressure drop
at the pore scale to the capillary pressure, while the Bond number (𝑁𝐵) quantifies that
of the typical hydrostatic pressure drop over a pore to the capillary pressure. In an oil-
water system, these two numbers can be expressed as:
𝑁𝑐 =𝑣𝜇𝐷
𝜎𝑂𝑊𝑐𝑜𝑠𝜃
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𝑁𝐵 =∆𝜌𝑔𝐿2
𝜎𝑂𝑊𝑐𝑜𝑠𝜃
where, 𝑣 is the velocity of the displacing phase; 𝜇𝐷 is the viscosity of the
displacing phase; 𝜎𝑂𝑊 is the IFT between water and oil phases; 𝜃 is the contact
angle; 𝐿 is the characteristic length.
During a displacing process, the larger the capillary number is, the less residual
oil saturation is. It is usually considered that the critical capillary number for non-
wetting phase is about the magnitude of 10−5 and is 10−3for wetting phase. (Lake,
Carey et al. 1984)
Figure 2. 5 Schematic capillary desaturation curve (Lake, Carey et al. 1984)
Besides implementing flooding or injection operations to improve oil recovery,
spontaneous imbibition is another phenomenon that could be used. Spontaneous
imbibition is the process by which a wetting fluid is drawn into a porous medium by
capillary action.(Morrow and Mason 2001) If the IFT is low enough, for example: the
presence of surfactant, and thus the capillary pressure to negligible values, it can still
occur in this case by buoyancy or gravity drainage. (Schechter, Zhou et al. 1994)
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2.3 Characteristics of surfactant and surfactant EOR
2.3.1 IFT Reduction and Wettability Alteration of Surfactant
IFT reduction is the most used mechanism in conventional surfactant EOR in
sandstone reservoirs since sandstone rocks are more likely to show a water-wet status.
Surfactant chemicals are medium with long-chain molecules that have both a
hydrophilic and a hydrophobic section. Thus, the molecules accumulate at the
oil/water interface and lower the IFT between the phases. Since capillary forces
prevent oil from moving through water-wet restrictions, such as pore throats, decrease
the interfacial tension can increase recovery by alleviating capillary trapping. When
the capillary number is high enough, the residual oil can be displaced through
injection or flooding. This also applies to a gravity-dominated displacement, where the
Bond number is sufficiently high, to overcome capillary trapping. Surfactant injection
reduces the residual saturations so that each relative permeability is increased. Sheng
(2010) analyzed the permeability ratio of the aqueous phase to the oleic phase from
published relative permeability data and found that the relative permeability ratio is
decreased in the high aqueous phase saturation range when IFT became lower. Thus,
the oil sweep efficiency is improved because of surfactant injection. (Sheng 2010,
Sheng 2015)
In carbonate reservoirs, the main mechanism is to alter the wettability because
carbonate formations compared to sandstones are much more likely to be
preferentially oil-wet. (Treiber and Owens 1972, Sheng 2015) Additionally, carbonate
formations are more likely to be fractured and will depend on spontaneous imbibition
or buoyancy for the displacement of oil from the matrix to the fracture. (Hirasaki,
Miller et al. 2008)
Oil composition is the key factor to alter the wettability of a naturally water-
wet surface to more oil-wet because of the wettability-altering components in the
crude oil composition. These polar compounds are resins and asphaltenes, both of
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which combine hydrophilic and hydrophobic characteristics. Bulk-oil composition
determines the solubility of the polar components. The crude oil that is a poor solvent
for its surfactants will have a greater propensity to change wettability than one that is a
good solvent. (Al-Maamari and Buckley 2003) Temperature and pressure also affect
asphaltene stability. For components altering the surface from water-wet to oil-wet,
the oil phase must displace formation brine from the rock surface. The surface of a
water-wet material is coated by a film of the water. The part of this water film that is
closest to the surface forms an electronic “Double layer”, excessive charges on the
solid surface will be countered by electrolyte ions of opposite charges. The first layer
of water with these ions is static, and the second layer exchanges ions with the bulk
water. When oil-phase appears, the water film is likely to be penetrated, resulting in
the composition of crude oil adhere on the surface of the rock then alter the wettability
to more oil-wet.
Surfactant-induced wettability alteration process appeared to be beneficial for
field implementation in oil-wet reservoirs. In oil-wet reservoirs, surfactants can induce
wettability alterations to either less oil-wet or water-wet state, resulting in improved
oil recovery. In initially water-wet reservoirs, the surfactant-induced wettability
alteration process is beneficial only of the surfactant induces either mixed wettability
or intermediate wettability. This process is detrimental for improved oil recovery if the
surfactant induces oil-wet behavior. Thus, the surfactant type (ability to induce
favorable wettability alteration), rock mineralogy, and the surfactant concentration are
critical in determining the economic success for this process in the field. Improper
determination of original reservoir wettability can lead to poor decisions for improved
oil recovery field applications using surfactants. Hence, the surfactant must be
carefully chosen depending on initial reservoir wettability to maximize the benefit.
(Roychaudhury, Rao et al. 1997, Wang, Butler et al. 2011)
Since the organic components of crude oil (resins and asphaltenes) have
negatively charged groups, and these types or groups usually absorbs on the surface of
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carbonates, which surfaces are generally positively charged, interactions occur
between the cationic surfactant monomer and the anionic material (mostly
carboxylate) adsorbed on the rock surfaces from crude oil. Due to ion pair formation
between cationic monomer and anionic groups, adsorbed material at the oil, water, and
rock interfaces will be desorbed to the rock surface. This ion pair is not soluble in the
aqueous phase but soluble in the oleic phase, and thus, water will penetrate the oil
film. When the material is desorbed to the surface, it becomes more water-wet and oil
can be displaced. The mechanism of wettability alteration by cationic surfactants is
shown in Figure 2.6. This type of alteration is considered permanent. Unlike cationic
surfactants, anionic surfactants are not able to interact with negatively charged groups
from the rock surface. Anionic surfactants generate weak capillary forces through
hydrophobic interaction between the tail of the surfactant and the negatively charged
adsorbed groups (Standnes and Austad 2000) Minor oil displacement by ethoxylated
sulfonates from carbonate cores is associated with the formation of a water-wet bilayer
between the carbonate surface and oil. The mechanism of the formation of the bilayer
is shown in Figure 2.7. (Kamal, Hussein et al. 2017)
Figure 2. 6 Mechanism of cationic surfactant wettability alteration (Standnes and
Austad 2000)
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Figure 2. 7 Mechanism of anionic surfactant wettability alteration (Standnes and
Austad 2000)
2.3.2 Guideline of surfactant selection
There are a few general guidelines of surfactant selection from current
literature:
In an oil-wet carbonate reservoir, anionic surfactants can reduce IFT without
significantly changing wettability, whereas cationic surfactants can change wettability
without significantly reducing IFT. (Wang, Xu et al. 2011)
The nonionic surfactant performed best while the anionic surfactant came to
the second, and cationic surfactant performed average in spontaneous imbibition
experiment in Bakken Shale and Eagle Ford shales. However, the performance of IFT
reduction and WA alteration were not specified. (Nguyen, Wang et al. 2014)
The mixture of cationic-anionic surfactant is more effective on wettability
alteration than a single surfactant alone, due to the complex lithology with positive
and negative charges on shale rocks. (Zhou, Das et al. 2016)
In a Wolfcamp shale system, the combination of Anionic-Nonionic surfactant
performs better than Nonionic surfactant alone on both IFT reduction and Wettability
alteration (Neog and Schechter 2016)
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Anionic surfactant worked best on IFT reduction and Contact angle rather than
Nonionic, Nonionic-Cationic, Nonionic-Anionic surfactant in Permian Basin cores.
(Alvarez and Schechter 2016)
On both Wolfcamp and Eagle Ford cores, cationic surfactants had more
adsorption and better wettability alteration capacity, but anionic surfactants decreased
IFT further than cationic and Nonionic-anionic surfactants. Cationic surfactant also
had a better recovery factor during spontaneous imbibition experiment due to a more
water-wet status. (Alvarez and Schechter 2017)
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CHAPTER Ⅲ
EXPERIMENTAL METHODOLOGY
In this Chapter, the experimental methodologies used in this dissertation are
introduced. The mechanisms and detailed procedures are explained and described.
Experiments conducted in this study can be categorized as preparation experiments
that evaluate rock, fluid, and chemical properties for further analysis; imbibition
experiments as the cornerstone of this dissertation explore the potential of enhancing
hydrocarbon productions through each method. The result from the experiment will be
explained in the next chapters and will be used for simulation history matching.
3.1 Experimental Materials
3.1.1 Rock samples
Rock samples used in this study are outcrops from Eagle Ford shale, Kentucky
Sandstone, and Burlington Carbonate distributed by Kocurek Industries. Core plugs
are cut parallel to the bedding plane. The lengths are 2 inches and the diameters are
1.5 inches. Integrated core plugs are used for permeability, porosity measurements,
and imbibition tests. Rock chips are used for wettability determination and surfactant
selections. While the procedures of measurement will be elaborated further, the
following table listed the average data of samples from three formations for readers to
establish a general idea of our rock properties.
Table 3. 1 Properties of core samples
Rock Type Permeability, md Porosity, % Wettability
Eagle Ford Shale 0.0003-0.0009 Extreme- Low 7-9 Oil-Wet
Burlington Carbonate 0.004-0.007 Very- Low 2-5 Oil-Wet
Kentucky Sandstone 0.05-0.1 Very- Low 14-19 Water-Wet
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Table 3. 2 Mineralogical composition of core samples
Mineralogy, wt. % Eagle Ford Shale Burlington Carbonate Kentucky Sandstone
Calcite 82.80 97.72
Quartz 8.40 61.23
Dolomite 1.80
Pyrite 0.80
Albite 0.40 12.37
Chlorite 0.80
Montmorillonite 2.29 14.74
Kaolinite 4.00
Illite 1.00 11.67
3.1.2 Fluid samples
Crude oil
Crude oil used is light dead oil from Wolfcamp shale formation. Properties of
the crude oil sample are shown in Table 3.3 and the composition details showed in
Table 3.4. Due the properties of crude oil altered slightly after the saturation process
due to the light components’ evaporation. All properties are measured under the lab
room temperature at 70℉. The viscosity is measured under 300 RPM with Model 900
Viscometer from OFI Testing Equipment, Inc.
Table 3. 3 Properties of the crude oil sample.
Density at 70℉ Viscosity at 70℉ API Gravity Conditions
0.794 𝑆. 𝐺. 3.66 𝑐𝑝 46.7 °𝐴𝑃𝐼 Before core saturation
0.809 𝑆. 𝐺. 8.70 𝑐𝑝 43.4 °𝐴𝑃𝐼 After core saturation
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Table 3. 4 Mole percent data of the crude oil sample.
Components Mole
Fraction
Components Mole
Fraction
Components Mole
Fraction
C3H8 0.01% FC9 8.34% FC21-22 2.27%
IC4 0.00% FC10 8.34% FC23-24 1.04%
NC4 0.01% FC11-12 11.79% FC25-26 1.73%
IC5 1.35% FC13-14 9.41% FC27-28 1.05%
NC5 1.35% FC15-16 6.79% FC29-30 0.50%
FC6 4.59% FC17-18 4.94% FC31-36 0.95%
FC7 10.68% FC19 2.15% FC37-40 0.94%
FC8 12.30% FC20 1.28% FC41+ 8.21%
Brine
5% potassium chloride (KCl) solution is used to serve as the formation brine
and the base of fracturing fluid without chemical additives. It is used in all imbibition
experiments as the control group. 5% KCl solution is used commonly in shale-fluid
experiments to prevent sample cracking by inhibiting the clay contents swelling (Shi,
Wang et al. 2019)
Surfactants
Five commercial surfactants were selected based on the performances in
Interfacial Tension (IFT) reduction and wettability alteration. Different surfactants
were added to investigate the effect of IFT and wettability on various types of
imbibition. Table 3.5 lists the primary information of these candidates and the
procedures of selection will be explained in surfactant evaluation section.
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Table 3. 5 Selected surfactant candidates in this study
Surfactant Type of surfactant Primary component of surfactant
N1 Nonionic Ethoxylated Alcohol
C1 Cationic ammonium salt
C2 Cationic
A1 Anionic Alcohol Propoxylate
A2 Anionic
3.2 Preparation Experiments
3.2.1 Core Saturation
There are two types of saturation protocols in this study depending on the
purpose of the experiments. The difference can be categorized based on the desired
connate wettability. The connate wettability of reservoir formations is essentially
correlated with the rock mineralogy composition itself. For example, the percentage of
quartz is determinant for a reservoir to exhibit water-wet behavior in a water-oil-rock
three-phase system.(Anderson 1986, Liu and Sheng 2019, Liu, Sheng et al. 2019)
However, it also depends on the circumstances that it contacts with formation fluids.
For example, aging time, aging temperature, initial water saturation, crude oil
distribution, and the composition of crude oil will also shift the rudimentary
wettability determination. (Zhou, Torsaeter et al. 1995, Tang and Morrow 1996,
Chattopadhyay, Jain et al. 2002) A study on pure quartz plates showed the wettability
alteration (water-wet to oil/intermediate wet) occurred with the increase of asphaltene
content under 75℃. (Qi, Wang et al. 2013) Therefore, by manipulating these factors
during the crude oil saturation process, the initial wettability of the outcrops core plugs
can be artificially achieved for different purpose of experiments.
The setup of core saturation experiment is illustrated in Figure 3.1. It consists
of a vacuum pump, a saturation steel vessel, an accumulator, and Quizix pump and an
air compressor to provide the power. Vacuum pump is used to remove original gas in
the core samples. Accumulator contains the crude oil sample to be saturated. Steps of
oil saturation experiment are described below:
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Figure 3. 1 Schematic of the core saturation setup.
Core saturation without aging
The procedures of saturating dry cores with crude oil are:
• Heating up the cores in the oven at 270℉ for 24 h to remove potentially
residual fluids.
• Measuring the dry weight of each core as 𝑊𝑑.
• Putting cores into the saturation vessel and turn on the vacuum pump for
48 h.
• Turning on the Quizix pump to displace crude oil from the accumulator
into the vacuumed saturation vessel and ramping up the pressure to 5000
psi gradually.
• Maintaining the soaking pressure in room temperature for a week, and
bleeding off the pressure gradually.
• Opening the saturation vessel and measuring the weight of each saturated
core as 𝑊𝑠 . This saturation method is established from our previous
research, and the weight gain stopped after applying the steps described
above. (Yu, Meng et al. 2016)
The volume of saturated oil can be calculated with the equation for further
recovery factor calculation:
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𝑉𝑜𝑖 =𝑊𝑠 − 𝑊𝑑
𝜌𝑜
Where 𝜌𝑜 is the density of our crude oil.
Core saturation with aging
• Heating up the cores in the oven at 270℉ for 24 h to remove potentially
residual fluids.
• Measuring the dry weight of each core as 𝑊𝑑.
• Putting cores into the saturation vessel and turn on the vacuum pump for
48 h.
• Turning on the Quizix pump to displace crude oil from the accumulator
into the vacuumed saturation vessel and ramping up the pressure to 5000
psi gradually.
• Maintaining the soaking pressure in over, under 75℃ for at least four
weeks, and bleeding off the pressure gradually.
• Opening the saturation vessel and measuring the weight of each saturated
core as 𝑊𝑠.
• The saturation volume can be determined as the same calculation
mentioned above.
3.2.2 Wettability determination
One of the universal methods to quantify the wettability is Contact Angle (CA)
measurement. In a rock-water-oil three-phase system, the wettability is commonly
considered as water-wet if the contact angle between the solid surface and water
droplets is less than 75 degrees, while it is considered to be oil-wet if the angle is
larger than 105 degrees. The surface is intermediate-wet if the CA is measured in
between.(Anderson 1986) Therefore, the wettability of rock surface is determined by
Contact Angle (CA) measurement in this study. The measurement conducted with
sessile drop method for air-rock-liquid system, and captive bubble method for water-
rock-oil system. Drop shape analyzer DSA25 and ADVANCE software from KRÜSS
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GmbH are used to complete the test. The following steps are repeated for wettability
determination:
Contact Angle measurement for air-rock-liquid system
• Polish the surface of rock samples.
• Place the rock sample onto the calibrated positioning table.
• Introduce one drop of desired liquid phase material to the surface of polished
rock chip.
• Continue measuring contact angle every thirty second with ADVANCE
software till the angles stopped changing.
• Repeat the process for three time and calculate the average value as the final
measured contact angle.
Contact Angle measurement for air-rock-liquid system
• Polish the surface of rock samples.
• Place an environmental cuvette onto the calibrated positioning table.
• Fill the cuvette with desired third phase liquid (water or surfactant fluid)
• Hang the rock sample in the center of the glass cuvette
• Expel any air bubbles may attach to the rock sample
• Introduce one drop of desired liquid phase material to the bottom surface of
polished rock chip with a J-shaped needle (oil phase)
• Continue measuring contact angle every thirty second with ADVANCE
software till the angles stopped changing.
• This process usually last for few hours and at least 24 hours till for wettability
alteration process with surface agents
• Repeat the process for three time and calculate the average value as the final
measured contact angle.
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Figure 3. 2 Drop shape analyzer DSA25 for contact angle measurement
Figure 3. 3 The schematic illustration of the captive bubble method (Xue, Shi et al.
2014)
3.2.3 Surfactant evaluation
Interfacial tension reduction
The ability of Interfacial Tension (IFT) reduction is one of the most important indicators
of the performance of a surfactant. Surfactant, as amphipathic agents act at the interface
of two phases, for example, oil-water or water-air, which reduces the IFT between the
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two original phases. Spinning drop tensiometer M6500 from GRACE Instrument was
used to measure the IFTs. This method enables us to determine the range of IFT from
10−6 − 102 𝑚𝑁/𝑚. It allows us to select surfactant solution with IFTs from ultra-low
to high.
• A drop of oil sample was introduced into a capillary tube filled with surfactant
solution.
• Horizontally arranged into the spinner and rotated under a set of designated
speeds.
• The diameter and curvature of the drop that is elongated by centrifugal force
correlate with the IFT, and can be calculated by the formula:
σ = 1.44 × 10−7∆𝜌𝐷3𝜔2
where σ is the IFT, mN 𝑚⁄ ; ∆𝜌 is the density difference, g/cm3; 𝐷 is the measured
drop diameter, mm; 𝜔 is the angular frequency, rpm
An alternative way is to use the pendant drop method. This measurement was complete
by the Drop Shape Analyzer DSA25 and ADVANCE software. However, the range of
using this method is no less than 0.01 𝑚𝑁/𝑚 depending on the size of needle.(Berry,
Neeson et al. 2015)
Figure 3. 4 GRACE Spinning drop tensiometer M6500
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Wettability alteration
The term of wettability alteration can refer to the process that shifting the wetness of
porous media from original water-wet to intermediate-wet or oil-wet, or the reversal
process where changing the wettability from oil-wet to more water-wet status. This
study focuses on the alteration of wetness from oil-wet to more intermediate-wet or
water-wet by surfactant agents. Surfactant-induced wettability alteration process can be
caused by molecular adsorption, absorption, reaction and penetration with organic
matters on the surfaces of porous media. (Standnes and Austad 2000, Gupta and
Mohanty 2011) The evaluation of wettability alteration is quantified by the changes of
contact angles of the rock samples before and after soaking by a surfactant fluid. The
ability of each fluid-rock system was assessed by measuring contact angle between oleic
and aqueous phases after 24 hours of soaking. The procedures of evaluation tis capacity
can be summarized as the following:
• A drop shape analyzer DSA25 from KRÜSS was calibrated to conduct contact
angle measurement by a captive bubble method.
• Core plugs or polished rock chips after saturation were hang in the middle of a
environmental cuvette filled with water or the fluids of surfactant being
evaluated.
• Oil drops were then introduced at the bottom of rock sample with a J-shaped
needle. The contact angle (CA) between oleic and aqueous phases can be
captured through the camera and processed by ADVANCE software provided
by KRÜSS.
• The contact angle measurement is repeated at least 5 times on each sample. To
determine the initial wetness of rock chips.
• The final contact angles of rock chips were measured after soaking in the
surfactant solution for 24 hours. The measuring process was also repeated for at
least 5 times for each sample.
• For each rock chip, the measurements were only conducted with one surfactant
solution to exclude any cross contaminations.
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• Comparing the contact angle before and after soaking to quantify the capacity
of alteration by difference in the contact angles.
3.2.4 Permeability and porosity determination
Regular gas porosimeter from OFI Testing Equipment, Inc is used for porosity
measurement. Samples are vacuumed before testing with helium.
Although the regular steady state method which measures the permeability
through Darcy’s law can also be applied to a shale core sample, it usually takes
extremely long time for flowrate to get stabilized across the core plug. In addition, very
high injection pressure is required at the inlet of core sample to induce sufficient gas
flowrate to measure at the outlet. Thus, Autolab-1000 system manufactured by New
England Research, Inc is used in this study for permeability measurement. The system
performs complex transient method to measure the permeability of the shale core plugs.
(Boitnott 1997) In the complex transient measurement system, the pore pressure at the
top of the sample is controlled while the bottom of the sample is attached to a fixed
volume filled with pore fluid. When the system is in equilibrium and perturb the
pressure at the top of the sample, the response at the bottom pressure of the sample is
measured.
The tests were conducted at room temperature with helium. The detailed
experimental procedures are listed in the following.
• Install the core sample is in a rubber tube that cut to the length of the
core sample.
• Attach the rubber tube which has the core plug inside is attached to the
upper plug and lower plug of the core holder.
• Steel wire is rolled and tighten on the outside of the rubber tube at the
connection part with the upper and lower plugs.
• The core holder is installed to the confining vessel. The confining vessel
is filled with confining hydraulic oil.
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• 5 MPa confining pressure is applied to the confining vessel for 10
minutes to check leakage. If no leaking is detected, go to the next step.
Otherwise, check leakage and fix it.
• Increase the confining pressure to 15 MPa which is the confining
pressure used in the measurement.
• Keep the core plug confined at 15 MPa for 24 hours before the
permeability measurement so that the stress in the core plug can get
stabilized.
• Inject pore fluid into the pore fluid input port and make the intensifier’s
volume fully occupied with the pore fluid.
• Make the pore fluid pressure to the designed value for measuring the
permeability of the core plug.
• Test the permeability using the complex transient option on the software
at different frequency to find the optimum frequency value.
• Test the permeability of the core sample at the optimum frequency value
for several times and take average.
• After the measurement is finished, release the pore fluid pressure to
atmosphere pressure first. Wait until the pressure of the downstream of
the core is close to atmosphere pressure.
• Deplete the confining very slowly to avoid damage to the core plug.
• Get the core out from the rubber tube on the core holder. Clean each part
of the core holder using isopropyl alcohol.
• Clean the pore fluid intensifier using isopropyl alcohol and make the
system ready for next measurement.
• Turn off the hydraulic pump and then turn off the Autolab 1000 control
box.
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3.3 Spontaneous Imbibition Experiments
In this work, the imbibition experiment under atmospheric pressure is named as
spontaneous imbibition. Amott cell is a common experimental apparatus used in
petroleum engineering research for oil recovery evaluation (Figure 3.5). It comes with
a rubber cap and a glass cell that has graduated scales on the cell neck. The rock-fluid
system can be isolated within the cell body after sealing with the rubber cap, and any
fluid recovery will be easily converged and measured at the cell neck due to
gravitational separation. The basic procedures of spontaneous imbibition experiments
are:
• Take out oil-saturated cores from the preserving container right before
the operation.
• Wipe out attached oil from rock surfaces.
• Measure the initial weight before spontaneous imbibition experiments
and calculate the latest initial oil volume 𝑉𝑜𝑖 using the same method from
core saturation experiment.
• Seal the core sample with designated soaking solution (water, brine,
surfactant solution, etc.)
• Place the isolated system onto lab bench to avoid any disturbance.
• The recovery is recorded by reading the oleic phase volume every 12
hours to 24 hours until the end of experiment.
• The recovery factors can be estimated accordingly by calculating the
fraction of produced volume (𝑉𝑜) to the initially saturated volume (𝑉𝑜𝑖).
RF =𝑉𝑜
𝑉𝑜𝑖× 100%
• Each core plug is used for only once spontaneous imbibition with
chemical presented to prevent cross contamination.
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Figure 3. 5 Illustration of the Amott cell for spontaneous imbibition experiment
3.4 Forced Imbibition Experiments
Forced imbibition is not a well-defined process. In our study, forced imbibition
is defined as the imbibition process occurred when the external soaking pressure is
higher than the matrix pore pressure. Under experimental condition, since the initial
pore pressure equals to the atmospheric pressure, forced imbibition occurs when the
ambient pressure is higher than the atmospheric pressure. However, the process is more
complex in reservoir conditions because reservoir pore pressure is tremendous and
cannot be neglected in the formations. Moreover, for a static condition, the downhole
soaking pressure that is mainly composed of borehole fluid hydrostatic pressure and
surface operating pressure can easily exceed 10,000 psi. Therefore, forced imbibition is
a significant process for us to investigate after understanding the behavior of
spontaneous imbibition.
3.4.1 Forced imbibition with constant soaking
The literature of experimental studies of forced imbibition is very limited
because the existing equipment or apparatus, for instance, Amott Cell, are hard to resist
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implementing pressures. Amott cell as displaced in Figure 3.5 will not withstand
pressures higher than 5 to 15 psi. While the implementing pressure difference are
usually higher than 5,000 psi in shale formations during hydraulic fracturing process.
The most common experimental apparatus is steel-made and opaque cells,
accumulators, or core holders. The solution to record hydrocarbon recovery is
combining the usage of carbon-fiber chambers with medical computerized tomography
scans. However, it is used to record the saturation changes of gas or condensate
components rather than oil-water system because it is still challenging to distinguish the
oil-water distribution through the minor density difference resulted CT number
deviations. (Li, Zhang et al. 2017, Li, Sheng et al. 2018, Sharma and Sheng 2018)
Therefore, an experimental setup that can withstand up to 10,000 psi is designed.
(Figure 3.6) The recoveries through imbibition can be visually tracked at the end of each
test. We conducted pressurized imbibition tests on core plugs from three sources with
different wettabilities. The applied pressures were from 1000 to 5000 psi. The setup
came with the main parts of two pressure gauges, a high-pressure accumulator, a Quizix
pump, and a modified Amott cell. The cell cap is modified with a communication port
for the material exchange to prevent the cell from burst or crush. The accumulator is
able to contain the entire Amott cell. In our forced imbibition experiments, rock matrix
is entirely exposed to soaking pressure or surrounded by closed boundaries and should
be considered as counter-current forced imbibition. The procedures of forced imbibition
can be summarized as:
• Take out oil-saturated cores from the preserving container right before
the operation.
• Wipe out attached oil from rock surfaces.
• Measure the initial weight before spontaneous imbibition experiments
and calculate the latest initial oil volume 𝑉𝑜𝑖 using the same method from
core saturation experiment.
• Seal the core sample with designated soaking solution (water, brine,
surfactant solution, etc.)
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• Move the piston to the bottom of accumulator with air compressor.
• Fill the accumulator with the same testing fluid in the Amott cell.
• submerge the whole Amott cell into the top portion of the accumulator
and then close the accumulator cap.
• Turn on the three-way valve on the top of the accumulator.
• Turn on the Quizix pump with a very low constant flowrate mode.
• By injecting water through the Quizix pump into the bottom portion of
the accumulator, the upper space will be compressed by the piston.
• Switch the Quizix pump to constant pressure mode when the pressures
showed up on gauges are close to the targeting soaking pressures.
• Maintain the pressure for desired testing period.
• Turn off the pump when the soaking period is finished and remove the
top cap immediately.
• Read the recovered oil from the Amott cell neck and calculate the
recovery factors by fraction of initial saturated oil volume.
RF =𝑉𝑜
𝑉𝑜𝑖× 100%
• Each core plug is used for only once spontaneous imbibition with
chemical presented to prevent cross contamination.
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Figure 3. 6 Schematic of the imbibition experiment setup
3.4.2 Imbibition with cyclic pressurization
The process of imbibition under cyclic pressurization can be considered as a
huff-n-puff process. The external soaking pressure is periodically applied and
released. Therefore, the mechanism of oil recovery through this schematic are from
both imbibition and depletion. The set up of the experiment are the same of forced
imbibition (Figure 3.6). However, the forced imbibition and spontaneous imbibition
alternated every few hours. The experiments in this study followed the schedule of
twelve-hours soaking and twelve-hours depletion with eight cycles in total. The
detailed experimental procedures are listed in the following.
• Take out oil-saturated cores from the preserving container right before
the operation.
• Wipe out attached oil from rock surfaces.
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• Measure the initial weight before spontaneous imbibition experiments
and calculate the latest initial oil volume 𝑉𝑜𝑖 using the same method from
core saturation experiment.
• Seal the core sample with designated soaking solution (water, brine,
surfactant solution, etc.)
• Move the piston to the bottom of accumulator with air compressor.
• Fill the accumulator with the same testing fluid in the Amott cell.
• submerge the whole Amott cell into the top portion of the accumulator
and then close the accumulator cap.
• Turn on the three-way valve on the top of the accumulator.
• Turn on the Quizix pump with a very low constant flowrate mode.
• By injecting water through the Quizix pump into the bottom portion of
the accumulator, the upper space will be compressed by the piston.
• Switch the Quizix pump to constant pressure mode when the pressures
showed up on gauges are close to the targeting soaking pressures.
• Maintain the pressure for desired soaking period (12 hours).
• Turn off the pump when the soaking period is finished and remove the
top cap immediately.
• Read the recovered oil from the stage 𝑥 and recorded as 𝑉𝑜𝑥
• Calculate the recovery factors from stage 𝑥 as:
RFx =𝑉𝑜𝑥 − ∑ 𝑉𝑜𝑥
𝑥−11
𝑉𝑜𝑖× 100%
• Repeat the same process for 8 cycles.
• Each core plug is used for only once spontaneous imbibition with
chemicals presented to prevent cross-contamination.
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CHAPTER Ⅳ
MECHANISM STUDY OF IMBIBITION IN UNCONVENTIONAL
FORMATIONS
In this chapter, conceptions of spontaneous imbibition (SI) vs. forced
imbibition (FI), capillary induced imbibition vs. gravitational driven imbibition, and
counter-current imbibition vs. co-current imbibition will be explained. It is important
to understand and differentiate the mechanisms of each type of imbibition first to
further focus on the investigation and utilize the correct manner of imbibition in
unconventional oil recovery. The methodology followed the workflow of firstly
colleting reliable data from experiments; second, build lab scale model with numerical
simulator; finally, upscale the model to reservoir scale model to further analysis the
effect of each mechanism.
4.1 Overview of Mechanisms of Imbibition
In the previous chapters, we have categorized the types of imbibition into
spontaneous imbibition and forced imbibition based on the relative relation between
the pore pressure and external soaking pressure. Further, within each type, depending
on the dominant driving force, the imbibition can occur as capillary induced
imbibition and/or gravitational driven imbibition. Additionally, based on the flowing
direction of the displacing phase and the displaced phase, imbibition can be
categorized into counter-current imbibition and co-current imbibition. For the co-
current imbibition, wetting and non-wetting phases flow in the same direction, while
counter-current imbibition refers to that when the phases moving in opposite
directions.(Reis and Cil 1993, Li, Morrow et al. 2003) Each driving and flowing
manner can occur in both spontaneous and forced imbibition styles.
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4.1.1 Mechanism of spontaneous imbibition
The mechanism of spontaneous imbibition can be explained as the correlation
among viscous force, capillary force, and density difference resultant gravitational
pressure gradient.
Gravitational driven imbibition is the scenario where the formation
permeability is relatively high but capillary pressure is either too small, or reservoir
hydrocarbon is the wetting phase. Due to the density difference between the soaking
phase and reservoir hydrocarbon. The resultant buoyancy force may overcome the
viscous resistance to relocate the hydrocarbon. It is worth to note that gravitational
imbibition process does occur regardless of the formation wettability. It may take
place with capillary imbibition simultaneously, but it must be the dominant effect of
imbibition to be called a gravitational driven imbibition process. For example, in a
strongly water-wet reservoir, the buoyancy also assists capillary pressure to move the
non-wetting hydrocarbon phase.
Capillary-driven imbibition is the process of the wetting phase displacing the
non-wetting phase, it is most effective when the wetting phase is the displacing phase
and the capillary pressure within a single capillary pore can be expressed by the Yong-
Laplace equation:
𝑃𝑐 =2𝜎𝑐𝑜𝑠𝜃
𝑟
where 𝜎 is the interfacial tension; 𝜃 is the contact angle; 𝑟 is the radius of the
pore.
It can be seen from the equation that to generate a positive capillary pressure
that the contact angle (𝜃) is less than 90 degrees, the soaking phase (water) must
become the wetting phase. The interfacial tension needs to be large enough to over
come the viscous forces in the porous media to drive the capillary driven imbibition.
The magnitude of the capillary pressure relates to the interfacial tension between two
immiscible phases, the extent of wetness and inversely proportional to the pore radius.
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Within the shale or tight reservoirs, confined pores and throats create tremendous
capillary pressure.
4.1.2 Mechanism of forced imbibition
Forced imbibition is an even more complicated process. In addition to the three
main elements mentioned in spontaneous imbibition, more factors should be
considered in reality. First, reservoir pore pressure is tremendous and cannot be
neglected in the formations, while in the spontaneous imbibition tests, pore pressure
equals atmospheric pressure. Moreover, for a static condition, the downhole soaking
pressure that is mainly composed of borehole fluid hydrostatic pressure and surface
operating pressure that can exceed 10,000 psi. Therefore, forced imbibition is a
significant process for us to look into after understanding the behavior of spontaneous
imbibition. However, literature of forced imbibition is very limited.
Based on the currently available literature, forced imbibition is defined
diversely from case to case or vaguely defined by different researchers. Most current
FI studies were conducted as a soaking-flowback technique that had pressure
periodically imposed and released, which should be defined as a cyclic injection or
huff-n-puff process. This is because the measured oil recoveries were not purely from
imbibition but also from the pressure releasing stages. Some studies conducted the
forced imbibition tests with an open-end which is essentially a flooding setup.(Riaz,
Tang et al. 2007, Tang and Kovscek 2011, Kurtoglu 2013, Ruidiaz, Winter et al. 2018)
Shuler et al. explored the potential of liquid chemical huff-n-puff application for
unconventional reservoirs.(Shuler, Lu et al. 2016) However, the experiments were
neither conducted with a rock matrix nor studied the potential of oil recovery. Zhang
and Wang conducted flooding on naturally fractured Bakken core plugs showing a
good potential for oil recovery enhancement in this type of fractured reservoir through
imbibition by the flooding technique with wettability alterable surfactant
solutions.(Zhang and Wang 2018) Zhang et al. investigated the cyclic injection
technique with a field-scale numerical simulation model, but the model was tuned
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from the results of spontaneous imbibition experiments.(Zhang et al. 2019) Wang et
al. analyzed 68 tight cores with NMR technology, results of SI and FI are compared
and FI tests yielded more recovery. However, their forced imbibition test was not
clearly defined and the experimental apparatus is essentially a flooding setup.(Wang et
al. 2018)
4.1.3 Counter-current imbibition and co-current imbibition
The imbibition can take place in either co-current or counter-current manners.
For the co-current imbibition, wetting and non-wetting phases flow in the same
direction, while counter-current imbibition refers to that when the phases moving in
opposite directions.(Reis and Cil 1993, Li, Morrow et al. 2003) Co-current imbibition
is more efficient, but counter-current imbibition is often the main mechanism within
the matrix-fracture system.(Hatiboglu and Babadagli 2008, Qasem, Nashawi et al.
2008, Bourbiaux, Fourno et al. 2016, Nooruddin and Blunt 2016)
When the external pressure is higher than the threshold of pressure entry of the
capillary tube or porous media, forced imbibition can be efficient in the co-current
manner (FCOI). This is because the external pressure increased the pressure gradient
in addition to the capillary pressure.(Hammond and Unsal 2009) However, for the
Forced Counter-Current Imbibition (FCCI) the effect of pressure is more implicit and
complex. Liu and Sheng (Liu and Sheng 2020) conducted experiments of Forced
Counter-Current Imbibition on oil-wet shale cores with the Nuclear Magnetic
Resonance (NMR) technology. In their experiment, the soaking pressures are 1000 psi
and 2000 psi, and the results are compared with that of Spontaneous Counter-Current
Imbibition (SCCI). NMR scans were performed at time 12hr, 24hr, 48hr, and 72hr for
each case with the same pressure, and NMR signals were further converted to the
water saturation profiles along the axis of core plugs (Figure 4.1). It is concluded that
the profiles of Forced Counter-Current Imbibition are similar to that of Spontaneous
Counter-Current Imbibition, and no significant changes observed among cases with
different pressures. Therefore, the pressure does not effectively alter the counter-
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current imbibition of oil-wet core-scale experiments.
Figure 4. 1 Water saturation profile of oil-wet shale cores counter-current
imbibition.(Liu and Sheng 2020)
4.2 Experimental Study
4.2.1 Experiment design
The purpose of the experiments in this chapter is to investigate the
performance the imbibition behaviors in unconventional core samples and to provide
reliable imbibition data for simulation model tuning. Most shale formations are
reported to be mixed-wet to oil-wet (Phillips, Halverson, Strauss, Layman, & Green,
2007; Sheng, 2013; D. Wang, Butler, Liu, & Ahmed, 2011). Therefore, in this study,
we used outcrops from the Eagle Ford shale, Kentucky Sandstone, and Burlington
Carbonate distributed by Kocurek Industries to achieve both water-wet and oil-wet
combinations. Samples from these sources are defined as unconventional based on the
permeabilities. 6 oil-wet shale cores and 6 water-wet sandstone cores are used to study
the effect of pressure on forced imbibition with different wettabilities. Carbonate cores
are oil-wet but have the permeabilities in between of sandstone (0.05-0.1md) and shale
(0.0003-0.0009md). Therefore, to exclude the influence of the permeability difference
other than wettability, we included 6 oil-wet carbonate cores as the control group.
One core from each group is used to conduct spontaneous imbibition
experiment under atmospheric pressure, and the rest five cores from each group are
tested with forced imbibition under different soaking pressures. The properties of each
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core followed the wettability testing and petrophysics testing defined in chapter three,
and are summarized in Table 4.1 and Figure 4.2:
Figure 4. 2 Wettability pre-evaluation by Contact Angle measurement
Table 4. 1 Properties of core samples
Rock Type Permeability, md Porosity, % Wettability
Eagle Ford Shale 0.0003-
0.0009
Extreme-Low 7-9 Oil-Wet
Burlington Carbonate 0.004-0.007 Very-Low 2-5 Oil-Wet
Kentucky Sandstone 0.05-0.1 Very- Low 14-19 Water-Wet
4.2.2 Determination of testing pressures
The range of testing pressures is calculated based on the possible static soaking
pressure within the plugged stage of fractured horizontal wells at the Wolfcamp
formation, Permian Basin. According to the U.S. Geological Survey report 2016 and
case studies, the reservoir pressure gradient is between 0.46 to 0.52 psi/ft and the
reservoir depths are between 8,500 to 10,000 ft (Gaswirth 2017, Yu, Xu et al. 2018).
Reservoir pore pressures in the Permian Basin can be complex due to the complex
lithology. While the pore pressure is related to the overburden stress, the effective
stress is strongly influenced by mineralogy and thickness of shallow, mixed-layer
formations.(Kozlowski, Da Silva et al. 2018)
During a multi-stage hydraulic fracturing operation within the horizontal well,
before a new stage starts, a plug-ball will be dropped from the surface and pumped
down to seal the frac-plug of the previously finished stage. Therefore, in Figure 4.3,
the soaking pressure in ‘stage x-1’ equals the pressure of the wellbore hydrostatic
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pressure plus the pumping pressure at the moment of plug-ball hits the plug of ‘stage
x’. By subtracting the pore pressure, the forced imbibition pressure ∆𝑝 within the stage
can be estimated by:
∆𝑝 = 𝑝𝑠 + 𝑝ℎ − 𝑝𝑝
where, 𝑝𝑠 is the surface treatment pressure during plug ball-drop; 𝑝ℎ is the
hydrostatic pressure of treatment fluid; 𝑝𝑝 is the reservoir pore pressure.
Figure 4. 3 The illustration of the multi-stage hydraulic fracturing process
Considering the typical surface pump-down treatment pressure to be 2,000 to
4,000 psi during the ball-drop, and the fracturing fluid density varies from 9 to 12 ppg,
the possible window of soaking pressure is determined by:
∆𝑝𝑈 = 𝑝𝑠𝑈 + 𝑝ℎ
𝑈 − 𝑝𝑝𝐿
∆𝑝𝐿 = 𝑝𝑠𝐿 + 𝑝ℎ
𝐿 − 𝑝𝑝𝑈
where the superscript U and L represent the upper limit and lower limit of each
component.
Table 4.2 listed the minimum and maximum soaking pressures at each depth.
Since the most probable pressure differences vary from 1000 to 6000 psi. Therefore,
The applied pressures were 1000, 2000, 3000, 4000, and 5000 psi in forced imbibition
test, and the results were compared to that of spontaneous imbibition under
atmospheric pressure. Experimental results were used further in numerical simulation
mechanism study. The simulation model was history matched the experimental data,
and the mechanisms were discussed based on the wettability.
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Table 4. 2 The range of possible soaking pressure at each depth
𝑫𝒆𝒑𝒕𝒉, 𝒇𝒕 𝒑𝒔𝑼 + 𝒑𝒉
𝑼, 𝒑𝒔𝒊 𝒑𝒔𝑳 + 𝒑𝒉
𝑳 , 𝒑𝒔𝒊 𝒑𝒑𝑼, 𝒑𝒔𝒊 𝒑𝒑
𝑳 , 𝒑𝒔𝒊 ∆𝒑𝑼, 𝒑𝒔𝒊 ∆𝒑𝑳, 𝒑𝒔𝒊
8500 9304 5978 4760 3570 5734 1218
9000 9616 6212 5040 3780 5836 1172
9500 9928 6446 5320 3990 5938 1126
10000 10240 6680 5600 4200 6040 1080
4.2.3 Experimental results and discussion
Recovery profile of spontaneous imbibition experiments
The results of Spontaneous Imbibition tests in shale, carbonate, and sandstone
cores are listed in Table 4.3 and plotted in Figure 4.4 as the recovery factor versus
time. From the wettability pre-evaluation, it is not surprising to see that the sandstone
sample (K-1) exhibited the typical spontaneous imbibition profile. The final recovery
at the 8th day (192hr) was as high as 36% due to the positive capillary driven force
when the contact angle is less than 90 degrees (water-wet). As discussed previously,
because the permeability of these rocks is too low, the effect of gravitational-driven
imbibition is minimal. This critical conclusion can be demonstrated in Figure 4.5,
while there was a considerable amount of oil was produced from the bottom of the
core, indicating the capillary force had to even overcome the gravitational forces to be
effective.
For the carbonate (C-1) and shale (S-1) samples, the initial oil-wet condition
hindered the capillary-driven imbibition, and the recovery from density differences
was insignificant. Therefore, for both carbonate and shale samples, the oil recoveries
were in proximity to zero. Any insignificant oil recovery can be contributed by the oil
droplets attached to the core surface. For the C-1 core, the oil recovery at each time
step was untraceable. So, only the final recovery is recorded by gently disturbing the
Amott cell at the end of the experiment (Figure 4.6).
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Table 4. 3 Results of Spontaneous Imbibition Experiments
Eagle Ford Shale (S-0) Burlington Carbonate (C-
0)
Kentucky Sandstone (K-0)
Time,
hrs
Recovery
Factor, %
Time,
hrs
Recovery
Factor, %
Time,
hrs
Recovery
Factor, %
0.00 0.00 0.00 0.00 0.00 0.00
5.15 0.00 24.00 0.00 12.00 21.86
20.98 0.00 48.00 0.00 24.00 27.00
24.12 0.00 72.00 0.00 48.00 29.57
42.65 0.00 96.00 0.00 72.00 30.86
47.95 0.20 120.00 0.00 96.00 32.14
74.02 0.20 144.00 0.00 120.00 33.43
90.32 0.20 168.00 0.00 144.00 33.43
97.70 0.40 192.00 0.20 168.00 34.71
113.32 0.40
192.00 36.00
167.78 0.40
184.12 0.40
193.20 0.40
Figure 4. 4 Recovery Profiles of Spontaneous Imbibition experiments
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Figure 4. 5 Oil recovered from the bottom by overcoming the gravitational force
Figure 4. 6 Untraceable oil recovery during the imbibition on carbonate oil-wet cores
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Comparison of final recovery under pressurized condition
Forced Imbibition tests were performed on the remaining 15 cores to evaluate
the oil recovery under different pressures. The final recoveries at 192hr under certain
soaking pressures along with the results of SI tests are presented in Table 4.4. In
Figure 4.7, each bar represents the FI recovery, and the color distinguishes rock types.
From the results, it is obvious that wettability still played an important role under the
pressurized condition when comparing to the values of sandstone samples with
carbonates/shales at each soaking pressure. However, we could not observe a
consistent correlation of the final recoveries with the soaking pressures, but all the
values converged within a certain range. The average oil recovery from water-wet
sandstone cores was 33.83%, and 0.52% for oil-wet carbonates, 0.07% for oil-wet
shales. This may be because the influence of soaking pressure, if existing, is too trivial
to be noticed in core-scaled samples. Moreover, after accumulating the errors from the
individual core samples, we can barely observe the effects of pressure on the
imbibition experimentally. Therefore, to exclude these errors, we designed a numerical
simulation model in combination with our experimental results to further investigate
the mechanisms of forced imbibition.
A few notes can be taken at this point. Regardless of the soaking pressure, the
wettability of low-permeable rocks is crucial in terms of oil recovery. Further, the
recovery is mainly achieved from the capillary-driven process, while the effect of
density difference induced gravitational-driven imbibition is minimal. Therefore,
managing wettability alteration in oil-wet tight or shale oil reservoirs is significant to
enhance oil production regardless of the soaking pressure.
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Figure 4. 7 Results of forced imbibition tests on three types of rocks
Table 4. 4 Final Recovery Factors of spontaneous and forced experiments
Eagle Ford Shale Burlington Carbonate Kentucky Sandstone
Soaking
Pressure, psi
Core
No.
Final Recovery
Factor, %
Core
No.
Final Recovery
Factor, %
Core
No.
Final Recovery
Factor, %
14.7 (SI) S-0 0.40 C-0 0.20 K-0 36.00
1000 S-1 untraceable C-1 0.63 K-1 30.69
2000 S-2 untraceable C-2 0.94 K-2 35.55
3000 S-3 untraceable C-3 0.47 K-3 31.27
4000 S-4 untraceable C-4 0.21 K-4 33.14
5000 S-5 untraceable C-5 0.67 K-5 36.32
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4.3. Numerical Simulation of Lab Scale Model
4.3.1 Model description and validation
From the experimental tests, carbonate as a control group bridges the gap
between sandstone and shale samples in permeability. The results showed that the
permeability difference between our materials does not shift the fact that capillary-
driven imbibition dominates the recovery over gravity-driven. Therefore, the
simulation study will start from the model validation with water-wet sandstone and
oil-wet shale. Further, we will purely investigate the mechanism of pressurized
imbibition on shale with different wettabilities.
Sandstone model
Computer Modeling Group’s (CMG) advanced processes simulator, STARS, is
used for this work. The model was built under a Cartesian coordinate with aqueous
and oleic phases. The model is homogenous and can be categorized into two different
sectors (Figure 4.8, 4.10). The sector in green color (Sector 2) mimics the soaking
ambience in the experimental setup that filled with brine initially, while the blocks in
red color represent the core matrix saturated with oil (Sector 1). Since the sandstone
core experiments delivered us the most explicit results, we used its properties to build
and validate our base model. The base model has 20, 12, 12 blocks on I, J, K
directions respectively, where the central 10 × 10 × 10 that simulates the core plug
has the dimension of 0.18 ft in the I-direction, 0.11ft in the J and K-direction in total.
The matrix bulk volume equals to that of our experimental cores. The initial pressures
in matrix blocks and soaking ambience are assigned to 14.7 psi. An injector and
producer is perforated at block (1, 5, 1) to mimic the pressurizing line in the
experiments to achieve the soaking pressures from 1000 to 5000 psi.
The relative permeability and capillary pressure curves are described by
Brooks and Corey’s model (Figure 4.9) (Brooks and Corey 1966). The endpoint of the
capillary is estimated by the Yong-Laplace equation and the correlation between pore
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50
radius and permeability.(Leverett 1939, Leverett and Lewis 1941) Other related
petrophysical parameters and initial conditions of the sandstone model and the soaking
ambience are listed in Table 4.5.
r = √𝑐𝑘
∅
where ∅ is the porosity, r is the pore radius, and c is the geometric factor that
accounts for the shape, connectivity, aspect ratio of pores, and tortuosity of the pores.
Figure 4. 8 Illustration of numerical simulation model in CMG STARS
Figure 4. 9 Relative permeability (Left) and capillary pressure (Right) curves of base
sandstone model
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Table 4. 5 Petrophysical parameters of sandstone base model
Sandstone Matrix Ambience
Oil Phase Water
Phase
Oil Phase Water Phase
Sor & Swi 0.15 0.0 0.0 0.0
Endpoint of Kr 1.0 0.15 1.0 1.0
Kr Exponent 2 2 1 1
Endpoint of Pc (psi) 5 0
Pc Exponent 10 1
Permeability (mD) 0.1 1000
Porosity (%) 0.17 0.999
During the forced imbibition process, the water phase will enter the core
matrix due to the soaking pressure, which is different from spontaneous imbibition.
Therefore, the changes in saturation in the matrix sector do not necessarily represent
the recovery factor. In order to correctly quantify recovery performance from the
imbibition model, the total recovery factor (RF) for a given time is calculated as
follows:
RF = [𝑂𝑖𝑙 𝑉𝑜𝑙𝑢𝑚𝑒 𝑖𝑛 𝑡ℎ𝑒 𝑎𝑚𝑏𝑖𝑒𝑛𝑐𝑒 𝑎𝑡 𝑎𝑛𝑦𝑡𝑖𝑚𝑒
𝐼𝑛𝑖𝑡𝑖𝑎𝑙 𝑂𝑖𝑙 𝑉𝑜𝑙𝑢𝑚𝑒 𝑖𝑛 𝑡ℎ𝑒 𝑚𝑎𝑡𝑟𝑖𝑥]
𝑆𝐶× 100%
To validate the model, sector 1 was refined into 8 times and 27 times (Figure
4.10). Figure 4.11 plots the recovery factor from imbibition as a function of time
which illustrates that refining the grid blocks from 8 times to 27 times effectively
reduced the influence from grid block numbers in this model, and thus we used this
model for further analysis.
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Figure 4. 10 Base model with local gridblock refinement
Figure 4. 11 Influence of the number of gridblocks and sandstone base case history
matching
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Shale model
The major differences between the shale and sandstone imbibition models are
the initial wettability as well as the pore radius correlated capillary pressure. Tu and
Sheng used a simulation model that matched the shale spontaneous imbibition
experiments for rock-fluid systems different in interfacial tension and wettability. (Tu
and Sheng 2019) In this work, we referred to the parameters and adjusted it to match
our data in Table 4.6, oil-wet condition. Figure 4.12 plots the results of the final
history matching from both sandstone and shale models. In addition to the oil-wet case
achieved from the experiments in this study, we also created a water-wet shale to
investigate the effect of soaking pressure later in Table 4.6. Relative permeability and
capillary pressure curves are plotted in Figure 4.13.
Figure 4. 12 Results of History Matching of Sandstone and Shale
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Figure 4. 13 Relative permeability (Left) and capillary pressure (Right) curves of shale
model with different wettability
Table 4. 6 Petrophysical parameters of shale base model
Oil-Wet Water-Wet
Oil Phase Water
Phase
Oil Phase Water Phase
Sor & Swi 0.15 0.0 0.15 0.0
Endpoint of Kr 0.59 0.23 1 0.15
Kr Exponent 3.3 2.9 2 2
Endpoint of Pc (psi) -1450 1450
Pc Exponent 2 2
Permeability (mD) 0.00035
Porosity (%) 7.5
4.3.2 Results of core experiments modeling
A series of simulation cases were designed for the sandstone and shale models
described above. The injector was scheduled to be constant bottom hole pressure
injecting at 1000, 2000, 3000, 4000, 5000 psi, respectively, to simulate the
experimental conditions. The results are plotted in Figure 4.14 and 4.15.
For neither the water-wet nor oil-wet model, we were able to observe the effect
of soaking pressure among cases in terms of the oil recovery factor, which is
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consistent with our experimental results. In the experiments, the average recovery
factors of sandstone under different pressures converged to 33.83% with standard
deviation equals to 2.5%, while the average recovery factor from the simulation is
35.14% with only 0.12% standard deviation. Similarly, for the oil-wet shale, the
recovery factors are negligible from the simulations. These results manifest that the
result of pressure on imbibition is not prominent for a low-permeable core-scaled
model, regardless of the initial wetness. However, this may not be the case for a larger
shale formation model in which the time of pressure transient can be extremely long.
Therefore, to further investigate the impact of soaking pressure and reduce the errors,
the model was modified to a larger scale.
Figure 4. 14 Results of forced imbibition on core-scale water-wet sandstone
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Figure 4. 15 Results of forced imbibition on core-scale oil-wet shale
4.3.3 Effect of soaking pressure on forced imbibition
Model modification
The shale models were scaled up 100 times each direction that enlarged the
volume into 1 million times to a core plug. Thus the dimension of the matrix is now
18ft × 11ft × 11ft, which is comparable to the most common and closest cluster
spacing within Permian Basin nowadays. (Alzahabi, Trindade et al. 2019)
Mechanism of forced imbibition in oil-wet shale
To start with, Figures 4.16 and 4.17 plot the changes in oil phase pressures(𝑃𝑜)
and oil saturation(𝑆𝑜) of the central-surface matrix block (15,6,6) and the ambience
block (16,6,6) adjacent to the matrix. Figure 16 shows the results from SI when
soaking pressure is 14.7 psi. The oil phase pressure at the matrix block decreases with
time, and this pressure is less than the oil phase pressure in the soaking ambience
block throughout the entire time. Therefore, the capillary-driven imbibition does not
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occur in the oil-wet shale model. Since the capillary pressure is almost zero or
negative at the initial condition, the gravity-induced imbibition caused the oil
saturation to decrease, which further decreased the capillary pressure (Figure 4.16).
This process caused the 𝑃𝑜 in the block (15,6,6) to continuously decrease. This figure
also illustrated that the effect of gravity in shale is minor since only 0.007% was
recovered in 90 days through this mechanism.
Figure 4.17 shows the results from forced imbibition with 3000 psi soaking
pressure. First, it can be noticed that oil saturation decreased drastically at the
beginning, which is caused by the soaking pressure-induced viscous force. Water
entered the matrix block due to the injection and further triggered the 𝑃𝑜 to decrease
within the block (15,6,6) because capillary pressure decreased. When the pressure
further equilibrated, 𝑆𝑜 and 𝑃𝑜 stabilized to a constant value. It should be noticed that
the oil saturation decreased in the block (15,6,6) does not represent the oil was
recovered because it is caused by water gain within the matrix. Since the soaking
pressure only further reduces the negative capillary pressure, and the gravity effect in
shale is minor, it can be expected that the values of soaking pressure wouldn’t make a
difference on the oil-wet large-scaled shale model. Figure 4.18 plots the recovery
profile of this model. Quite similar to the core-scaled result, there was no obvious oil
recovery achieved. It illustrates that the oil recovery from imbibition is independent
from soaking pressures in oil-wet shale cases because the capillary pressure is small at
where oil saturation is high.
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Figure 4. 16 Oil phase pressures (𝑃𝑜) and oil saturation (𝑆𝑜) within block (15,6,6) and
(16,6,6) of SI on large scale oil-wet shale
Figure 4. 17 Oil phase pressures (𝑃𝑜) and oil saturation (𝑆𝑜) within block (15,6,6) and
(16,6,6) of FI at 3000 psi on large scale oil-wet shale
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Figure 4. 18 Results of forced imbibition on large scale oil-wet shale
Figure 4. 19 Oil phase pressures (𝑃𝑜) and oil saturation (𝑆𝑜) within block (15,6,6) and
(16,6,6) of FI at 3000 psi on large scale water-wet shale
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Mechanism of forced imbibition in water-wet shale
The recent literature has demonstrated that it is possible to alter the oil-wet
shale to mixed or water-wet by utilizing chemical additives (Liu and Sheng 2019,
Miller, Zeng et al. 2019, Salahshoor, Gomez et al. 2019, Tangirala and Sheng 2019,
Tu and Sheng 2019, Wang, Abeykoon et al. 2019). To illustrate the mechanism after
wettability alteration, the water-wet shale model described above was utilized in this
section. Figure 4.19 plots the block properties from forced imbibition with 3000 psi
soaking pressure in a water-wet large shale model described above. As can be seen
that 𝑃𝑜 in block (15,6,6) was greater than that in the block (16,6,6) throughout the
entire time, and thus the imbibition proceeded continuously till the oil saturation
decreased further. Due to the reduction of oil saturation, the capillary pressure will
eventually be too low to sustain the imbibition process.
Similarly, cases with soaking pressures assigned to 14.7, 1000, 2000, 3000,
4000, and 5000 psi were created for this model. The recovery profile is plotted in
Figure 4.20. Different from oil-wet cases or water-wet core-scale cases, a consistent
trend can be observed. The recovery factor at a given time is negatively correlated to
the soaking pressure. From the curvature of the curves, FI was suppressed within the
first 10 days that induced the RF of 5000 psi-FI to be 1.05% less than that of the SI
case.
To investigate the mechanism of this problem, we plotted the pressure profile
within the rock matrix from the tip-block (15,2,2)/(3,1,1) to the center-block
(11,6,6)/(1,3,3). The second vector specifies the location of the refined-child block,
and the path is illustrated in Figure 4.21. Colors in the figure also represent the
pressure distribution of the 1000 psi FI test at 24 hr. We can clearly observe a high-
pressure barrier generated at the surface which is greater than the soaking pressure in
the ambience. The high-pressure barrier equals to the sum of soaking pressure and
local capillary pressure and moves toward the center with time. In this dynamic
process, as time elapsed, the pressures at the external layers gradually decrease
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because the capillary pressures decrease with the increase of water saturation. The
pressure of the inner layer matrixes will increase because of the transfer of soaking
pressure, and the appearance of the second phase boosts the capillary pressure from
zero to 1450 psi. Until the soaking pressure fully transferred to the central block, the
imbibition is constrained in different degrees. This can be the reason for the imbibition
suppression of FI cases.
Figure 4. 20 Results of forced imbibition on large scale water-wet shale
Figure 4. 21 Path of pressure profiles and the pressure distribution of FI 1000 psi at
24hr
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Further analysis of forced imbibition characters
To better understand the inhibitive effects of soaking pressure on imbibition,
the pressure profiles are plotted based on soaking pressures at different time steps in
Figure 4.22. In contrast, another set of pressure profile showed in Figure 4.23 are
grouped by different timings.
In Figure 4.22, each curve represents the pressure distribution at 15min, 1hr,
2hr, 5hr, 12hr, 24hr, 4day, 7day, 15day, 30day, and 90day. In the SI case (Figure
4.22a), the pressure at location 0 reached the peak at the beginning (15 mins) due to
the instant positive capillary pressure, while in the FI cases, the pressure equals the
sum of local capillary pressure and soaking pressure. Therefore, the peak pressure
needs a longer time to build up. For instance, in Figure 4.22a and 4.22c, the 1000 psi
case consumed 1 hour to reach the peak-pressure while it took 2 hours for the 2000 psi
case. The local water saturation increases as the imbibition continues, which caused
capillary pressure to decrease. Therefore, the local peak pressures vary at locations
and tend to decrease with time. If we compare the imbibition of SI and FI cases, the oil
phase pressure within the matrix of spontaneous imbibition was greater than the
ambient pressure (14.7 psi) since the beginning. Therefore, the imbibition started
without constrains for the SI case. Whereas for the Forced imbibition, the local
capillary pressure plus the soaking pressure needs to be larger than the ambient
pressure to overcome the peak pressure barrier and trigger the imbibition. This process
is prominent only in the unconventional reservoirs for two important reasons. First, the
magnitude of capillary pressure is large enough to be comparable to the injecting
pressure. Second, the time for pressure equilibrium is much longer within the low-
permeable unconventional reservoirs.
Figure 4.23 exhibits this process in a more straightforward way. It shows the
pressure profiles and dimensionless pressure (𝑝𝐷) of all cases sorted by time. The
timings are 12 hr, 24hr, 4day, and 7day. The dimensionless pressure is defined as the
quotient of local pressure versus the soaking pressure. Therefore, if the local 𝑝𝐷 is
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larger than 1, the local pressure is larger than the pressure barrier, and the imbibition is
not confined at the given location. When the 𝑝𝐷 curve is completely surpassed 1, the
imbibition is completely free from pressure blocking. Faster recovery can be achieved
if the 𝑝𝐷 is larger as the pressure drop is greater. Among those four charts, 𝑝𝐷 of the SI
is larger than 1 throughout the entire time. Contrarily, FI cases were constrained for a
certain time depending on the soaking pressures. Comparing to the charts of 12hr and
24hr as an example, the intersects of the 𝑝𝐷 curves with the x-axis represent the
location of the high-pressure barriers, and the barrier moves inward with time. By the
time of 4 days, the cases of 1000 psi and 2000 psi FI became non-constrained
imbibition. By the time of 7 days, the constrains released from all the cases, and this is
the time when the curvatures of recovery profiles in Figure 4.20 became paralleled.
From the analysis above, the dimensionless pressure (𝑝𝐷) is an important
parameter to quantitatively evaluate the progress of any forced imbibition cases. The
imbibition behaviors of FI became identical to that of SI case if the 𝑝𝐷 is larger than 1
in the whole matrix. Therefore, to benefit more from the imbibition stage during the
hydraulic fracturing, reducing the time of 𝑝𝐷 achieving 1 is important. To achieve this
goal, the pump-down rate through the ball-drop can be engineered to decrease the
pressure differences between the hydraulic fractures and the reservoir. The hydrostatic
pressure can also be optimized to obtain the same goal. In our study, the difference in
recovery factors from the SI and FI-5000 cases is only 1.5%. However, in reality,
depending on the cluster spacing and reservoir properties, this difference can be larger
to make a huge impact on oil recovery.
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a. Change of pressure profile of 14.7 psi SI case
b. . Change of pressure profile of 1000 psi FI case
c. . Change of pressure profile of 2000 psi FI case
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d. . Change of pressure profile of 3000 psi FI case
e. . Change of pressure profile of 4000 psi FI case
f. Change of pressure profile of 5000 psi FI case
Figure 4. 22 Pressure profiles of different forced imbibition cases
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Figure 4. 23 Pressure profiles (Left) and dimensionless pressure profiles (Right) based on different time
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4.4. Further Analysis of Reservoir Scale Modeling
As discussed previously, in a water-filled fracture-rock matrix reservoir
system, counter-current flow is often the only possible mean of imbibition (Behbahani,
Di Donato et al. 2006, Feng, Wu et al. 2019). In the oil-wet matrix system, the soaking
pressure may not overcome the water pressure inside the matrix because of negative
capillary pressure, and thus the imbibition is inhibited regardless. Whereas in the
water-wet matrix, a high-pressure boundary at the two-phase contact is generated by
the local capillary pressure and the externally imposed pressure. The pressure barrier
is only noticeable in unconventional reservoirs with extremely low permeability
because first, the transient of pressure requires significant time, second, the capillary
pressure is high compared with conventional reservoirs (Leverett 1939, Donnelly,
Perfect et al. 2016). Accordingly, before the local pressure gradient is higher than the
adjacent blocks towards the fracture, the imbibition is suppressed. In this sense, it has
been concluded that in a closed boundary model where can only FCCI occur, soaking
pressure negatively affects the imbibition in terms of the rate of recovery. Thus, FCCI
is less efficient than SCCI (Tu and Sheng 2020). As the matrix size becomes larger,
this closed boundary condition is not satisfied. Therefore, the model is upscaled to
further analyze the forced imbibition performance in unconventional liquid-rich
reservoirs through sensitivity analysis with different parameters.
4.4.1 Base Reservoir model description
The simulation model was upscaled to mimic a quarter of the bulk volume of a
realistic fracturing stage within a multi-stage fractured horizontal well system in the
shale oil reservoir. Local grid refinement strategy is used to model the imbibition and
fluid exchange between the matrix and fractures. The side view is shown in Figure
4.24, and Figure 4.25 is the aerial view along the lateral wellbore. The thickness of the
simulated volume is 50 ft (K-direction), and the length is 300 ft (I-direction). In the J-
direction, the fracture half-length is 280 ft to represent the Stimulated Reservoir
Volume (SRV), and the model length extends an extra 420 ft to simulate the Non-SRV
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region. Two clusters were set to the base model. Therefore, the initial cluster spacing
equals the stage spacing, 300 ft. Reservoir and fracture properties are listed in Table
4.7. The reservoir properties are validated through our previous publication, and the
fracture properties are summarized values from available literature (Sharma and Sheng
2018, Tu and Sheng 2020, Tu and Sheng 2020). It should be noted that after
considering the initial reservoir pressure(5000 psi), the pressures showed for this
reservoir model represents the pressure difference. For example, if the forced
imbibition is under 1000 psi, the soaking pressure within the fracture networks is 6000
psi which results in a 1000 psi pressure difference. These values are validated to
accommodate the Wolfcamp reservoir, Midland Basin, where the soaking pressure can
be as high as 10,000 psi (FCCI-5000 psi) during hydraulic fracturing (Tu and Sheng
2020).
Table 4. 7 Matrix and fracture properties of the base reservoir model
Parameter Reservoir Fracture
Permeability, mD 0.00035 100
Porosity % 7.5 90
Initial water saturation, frac 0 1
Residual oil saturation, frac 0.15 0
Endpoint of 𝑘𝑟𝑤, frac 0.15 1
𝑘𝑟𝑤 Exponent 2 1
Endpoint of 𝑘𝑟𝑜𝑤, frac 1 1
𝑘𝑟𝑜𝑤 Exponent 2 1
Endpoint of 𝑝𝑐, psi 1450 0
𝑝𝑐 Exponent 2 0
Cluster Spacing, ft 300
Initial reservoir pressure, psi 5000
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Figure 4. 24 Side view of the base reservoir model
Figure 4. 25 Aerial view of the base reservoir model
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4.4.2 Effect of cluster spacing
It has been summarized that the number of hydraulic fractures and the length
of lateral wellbore affect the production rate. Wells completed with tighter stages and
cluster spacing demonstrated better performances in oil recovery through regular
production strategy (Ozkan, Brown et al. 2011, Zhu, Forrest et al. 2017). These
conclusion remarks were made for the production behavior through depletion. In this
section, we explored the effect of cluster spacing on imbibition behavior. The effect of
cluster spacing is studied as the characteristic length in the lab experiments. Ma et al.
proposed the following equation to describe the recovery from counter-current
imbibition as a function of dimensionless time, 𝑡𝐷 (Shouxiang, Morrow et al. 1997).
The correlation is achieved by spontaneous imbibition experiments on different water-
wet core samples. Many other derivative forms of the equation were proposed by
many scholars but this equation is most representative (Gupta and Civan 1994, Zhang,
Saputra et al. 2018).
𝑡𝐷 = 𝑡√𝑘
∅
𝜎
√𝜇𝑤𝜇𝑜
1
𝐿𝑐2
where 𝑡 is the time, 𝑘 is the permeability, ∅ is the porosity, 𝜎 is the interfacial
tension, 𝜇𝑤and 𝜇𝑜 are the viscosity of aqueous and oleic phases, 𝐿𝑐 is defined as the
characteristic length.
According to the equation, the behavior of imbibition is highly sensitive to the
𝐿𝑐 which is defined as the distance from the open surface to the non-flow boundary. In
a simplified hydraulic fracturing reservoir model, the characteristic length is described
as the half distance of cluster spacing (Behbahani, Di Donato et al. 2006). To simulate
this process, a series of cases were assigned with cluster spacings vary from 300 to 25
ft (Table 4.8). Each case was run under the soaking pressures (∆𝑝) equal to 0, 1000,
and 5000 psi to mimic the SI and FI scenarios. The simulation time of each case lasted
for 365 days, and the 3D results of Recovery Factors (RF) vs. Time and Clusters Per
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Stage are plotted in Figure 4.26. The effect of pressure is calculated by comparing the
recovery for FCCI-5000 psi and SCCI at each cluster spacing. Similarly, the effect of
cluster spacing is calculated by comparing the recovery with 300-ft and 25-ft spacings
at a given soaking pressure.
First, the RFs are highly sensitive to the clusters per stage, or the cluster
spacing. With the spacing decreases from 300 ft to 25 ft (-92%), the RF at the 365th
day increased by 91.42%, 91.67%, 92.49%, respectively for 0, 1000, and 5000 psi
cases. However, the RFs are not sensitive to the soaking pressure changes at a given
cluster spacings reduction. Secondly, with a given cluster spacing, the soaking
pressure negatively influences the RF from counter-current imbibition at a given time
(c.f. Table 4.8, col. 6), which is consistent from our previous conclusion.(Tu and
Sheng 2020) For example, when the soaking pressure increased from 0 (SI) to 5000
psi (FI), the recovery factor reduced by 18.42% when cluster spacing is 300 ft and
reduced by 6.72% if the cluster spacing is 25 ft. Therefore, the RFs are highly
sensitive to the change of cluster spacing. To find the trend of our data, we plotted the
RFs on a log-log scale, and a strong relationship can be observed (Figure 4.27). After
acquiring the equation of the scattered data, the RF can be extrapolated for any cluster
spacing. It can also be observed that the trendlines of different pressure cases converge
as the cluster spacing decreases. In another word, if the cluster spacing is ultimately
small, the discrepancy resulted from soaking pressure will be negligible as the
pressure is equilibrated instantaneously. This conclusion aligns with our previous
discussion as well.
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Table 4. 8 Case design for the effect of cluster spacing and analysis on the effects
RF at 365 days, %
Clusters/stage Cluster Spacing, ft SCCI-0
psi
FCCI-
1000 psi
FCCI-
5000 psi
Effect of
Pressure, %
2 300 0.1579 0.1516 0.1288 -18.42
3 150 0.3088 0.2976 0.2545 -17.58
4 100 0.4600 0.4442 0.3816 -17.03
5 60 0.6119 0.5928 0.5138 -16.02
7 50 0.9177 0.8960 0.7981 -13.03
13 25 1.8393 1.8192 1.7157 -6.72
Effect of Cluster
Spacing, % 91.42 91.67 92.49
Figure 4. 26 RF profiles vs. different cluster/stage of the reservoir model
0.5
1.0
1.5
1.75
2.0
1.75
1.5
1.25
1.0
0.75
0.5
0.25
0
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Figure 4. 27 RFs of different cluster spacings at 365 days
4.4.3 Effect of wettability
The effect of wettability on the behavior of imbibition in the shale oil
reservoirs can be significant. As the counter-current imbibition is dominated by
capillary pressure, the 𝑝𝑐 within a single capillary pore can be expressed by the Yong-
Laplace equation mentioned above. Gupta and Civan (1994) modified Ma’s model by
introducing the contact angle term and is expressed as:
𝑡𝐷 = 𝑡√𝑘
∅
𝜎𝑐𝑜𝑠𝜃
√𝜇𝑤𝜇𝑜
1
𝐿𝑐2
The results from (Feng, Wu et al. 2019) showed a negative correlation of the
contact angle value to the final oil recovery, which indicates that water-wetness is
beneficial to the ultimate recovery in shale. More than 30 spontaneous imbibition
experiments with Wolfcamp and Eagle Ford cores were considered in this study. If the
reservoir is initially oil-wet, most current studies suggested that altering the wettability
to a more water-wet status by adding chemical additives, for instance, surfactant or
solvent, or changing physical conditions such as temperatures, a higher recovery can
be achieved (Sheng 2017, Alvarez, Saputra et al. 2018, Liu and Sheng 2019, Liu,
Sheng et al. 2019, Liu, Sheng et al. 2019, Tu 2019, Tu* and Sheng 2019, Liu and
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Sheng 2020, Tu and Sheng 2020). The simulation followed Brooks and Corey’s
method (Brooks and Corey 1966) to interpolate relative permeability and capillary
pressure curves between two sets of curves for pure water-wet and oil-wet cases. The
interpolator 𝜔 is scaled between 0 and 1, where 1 represents the pure water-wet case,
and 0 stands for the oil-wet case. This is a popular method to simulate the wettability
alteration and is used in this study to study the effect of wettability (Delshad,
Najafabadi et al. 2009, Sheng 2017, Tu and Sheng 2020). The curves calculated by:
𝑝𝑐 = 𝜔 𝑝𝐶𝑤𝑤 + (1 − 𝜔)𝑝𝐶
𝑜𝑤
𝑘𝑟𝑜 = 𝜔𝑘𝑟𝑜𝑤𝑤 + (1 − 𝜔)𝑘𝑟𝑜
𝑜𝑤
𝑘𝑟𝑤 = 𝜔𝑘𝑟𝑤𝑤𝑤 + (1 − 𝜔)𝑘𝑟𝑤
𝑜𝑤
According to the results (Figure 4.30), the imbibition is sensitive to the
wettability and the recovery is proportional to the values of capillary pressures. In this
case, a threshold of capillary pressure, 290 psi that corresponds to 𝜔 = 0.2 can be
observed. SCCI exhibited a faster imbibition rate when the wettability is water-wet to
intermediate-wet.
Figure 4. 28 Relative permeability curves set
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Figure 4. 29 Capillary pressure curves set
Figure 4. 30 The recover factors of 5 timesteps that reflect the effects of external
pressures and reservoir wettability.
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4.4.4 Effect of permeability
The capillary force is considered as the dominant force (Schechter, Zhou et al.
1994). Therefore, In the tight or shale oil reservoir, the effect of permeability on
imbibition should associate with the pore radius and tortuosity, which ultimately
reflects the value of capillary pressure. J – Function method is commonly used to scale
up the average capillary pressure value and gives relatively low errors (Leverett 1939,
Leverett and Lewis 1941, Shahverdi et al. 2020). Finally, combining the tested values
and available literature (Kibodeaux 2014), the calculated 𝑝𝑐 curves to study the effect
of permeability are presented in Table 4.9 and Figure 4.31.
Sheng (2017) discussed the correlation between the imbibition and pore radius
or permeability. Considering Poiseuille’s Law (Washburn 1921), even though the
capillary pressure is higher when the pore radius or permeability is lower, the
imbibition velocity is proportional to the √𝑘/∅ . Therefore, the recovery through
SCCI and FCCI from higher permeability surpasses the rate from low permeability
reservoirs. After plotting the results of RFs based on different permeability on a semi-
log scale, the assumption is verified. (Figure 4.32)
𝐽(𝑆𝑤) = 𝐶 ×𝑝𝑐
𝜎√
𝑘
𝜙
Table 4. 9 Case design for the effect of permeability
𝒌, 𝒎𝒅 ∅, % √∅ 𝒌⁄ 𝑷𝒄 𝒆𝒏𝒅𝒑𝒐𝒊𝒏𝒕 𝑷𝒄 𝒆𝒙𝒑𝒐𝒏𝒆𝒏𝒕
0.00035 7.5 14.6 1450 10
0.001 9 9.5 950 8
0.01 11 3.5 350 5
0.1 17 1.3 125 2
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Figure 4. 31 Capillary pressure curves set for different permeabilities
Figure 4. 32 Capillary pressure curves set for different permeabilities
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4.4.5 Effect of initial water saturation
Initial water saturation (𝑆𝑤𝑖) of the reservoir may reduce the imbibition volume as the
dominant capillary pressure reduces as the saturation increases (Figure 4.33). To
investigate the effect of initial water saturation, cases of our model with the 𝑆𝑤𝑖 ranges
from 0 to 0.1 are showed in Figure 4.34. As expected, the increase of connate water
decreased the imbibed water volume per stage at the end of one-year imbibition. Thus,
the oil recovery volume from imbibition is increased.
Figure 4. 33 Capillary pressure decreases as the water increased
Figure 4. 34 Correlation of imbibed volume and initial water saturation
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CHAPTER Ⅴ
STUDY OF SURFACTANT EOR IN UNCONVENTIONAL OIL
RESERVOIRS
In the previous chapter, we have discussed the mechanism and potential of
utilizing fracture fluid imbibition to improve oil recovery during the well soaking
stage of hydraulic fracturing operation. As is summarized that capillary pressure is the
dominating driving force to induce the imbibition, the water-wet status of reservoir
environment is the prerequisite to trigger the mechanism. However, since most shale
formations are reported to be mixed-wet to oil-wet (Phillips, Halverson et al. 2007,
Wang, Butler et al. 2011, Sheng 2013), surfactant agents with the ability to alter the
wettability of the surfaces of porous media should be used to prompt the capillary
imbibition in unconventional oil reservoirs.
Therefore, in this chapter, the potential of surfactant induced Enhanced Oil
Recovery (EOR) in unconventional oil reservoirs is thoroughly investigated through
core experiments and numerical simulation. The application methods among
spontaneous imbibition, forced imbibition, and cyclical pressurization are compared
based on the behavior of imbibition profiles and oil recovery factors.
As is pointed in the introduction of this dissertation. The mechanism of
surfactant EOR in unconventional oil reservoir through imbibition should be
differentiated from the traditional surfactant EOR in conventional or carbonate
reservoirs. It should also be distinguished from surfactant EOR in condensate gas
reservoirs.
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5.1 Spontaneous Imbibition with Surfactant in Oil-wet Shale
5.1.1 Experimental study
The workflow of the experiment is to first, select commercial surfactants that
exhibit different capacities of IFT reduction and wettability alteration. Second, add the
combinations of selected surfactants as chemical additives into soaking fluid to trigger
spontaneous imbibition in oil-wet shale reservoirs.
The purpose is to investigate the effect of wettability alteration and IFT
reduction of the surfactant during oil-wet shale spontaneous imbibition. After the
experiment, the observed data is used for numerical simulation study to quantitively
analyze those two-effect mentioned above.
Experiment design
As the first step of the experiment, five surfactants were selected based on the
ability of wettability alteration and IFT reduction. The experimental procedure
followed the instructions listed in chapter three. The Selected surfactant candidates are
listed in Table 5.2.
Six Eagle Ford shale core plugs were saturated and aged till the initial
wettability are examined to be oil-wet. (Table 5.1, Figure 5.1) The procedures are
listed in chapter three. Core EF-0 were soaked in 5% KCl solution for spontaneous
imbibition test as the control group. Core EF-1 to EF-5 were soaked in the solution of
surfactant N1, C1, C2, A1, and A2, respectively (Table 5.2). The illustration of
spontaneous imbibition experiment is shown in Figure 5.2.
Figure 5. 1 Contact angle of core samples after saturation and aging (Oil-Wet)
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Table 5. 1 Properties of core samples in the experiment.
Core
Sample
Dry Weight,
g
Saturated Weight,
g
Weight of total
oil, g
Volume of total
oil, ml
EF-0 123.47 127.64 4.17 5.04
EF-1 127.32 132.56 5.24 6.34
EF-2 126.77 131.09 4.32 5.22
EF-3 126.07 131.60 5.52 6.68
EF-4 125.96 129.54 3.58 4.33
EF-5 126.51 131.82 5.31 6.43
Table 5. 2 Selected surfactant candidates based on IFT reduction and Wettability
alteration capacities
Solutions Type of
surfactant
Applied
con., wt.%
IFT, 𝐦𝐍/
𝐦
Final contact
angle (±𝟑 °)
Primary component
KCl N/A 5.0 18.00 130 Potassium Chloride
N1 Nonionic 1.0 3.00 50 Ethoxylated Alcohol
C1 Cationic 0.5 0.46 35 ammonium salt
C2 Cationic 0.5 0.18 52
A1 Anionic 0.1 0.01 33 Alcohol Propoxylate
A2 Anionic 0.1 0.03 36
Figure 5. 2 Spontaneous imbibition experiment apparatus
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Experiment results and discussion
Spontaneous imbibition experiments of different soaking fluid systems were
run for 120 days. The readings of recovered oil volume were recorded every 12 hours
in the first 30 days and then were recorded every few days when a notable change can
be observed. The recovery profiles of recovery factors (RFs) were plotted in Figure
5.3.
From the recovery profiles, it can be observed that the control group (5% KCl
solution) case, though with the highest IFT, because of missing the wettability
alteration effect, achieved the lowest imbibition rate and the recovery factor over the
120 days. The recovery factor became stable at approximately 10%. Nonionic
surfactant N1, with the highest IFT and wettability alteration function among
surfactant group, exhibited the fastest imbibition rate through the beginning to the end,
it also achieved highest recovery factor (64%) at 120 days. Two cationic surfactants
C1 and C2, with intermediate IFT, obtained intermediate recoveries. For anionic
surfactant with extremely low IFT, A1 achieved the lowest oil recovery. However, the
only exception noticed in the experiments is surfactant A2. Though it exhibited a
much lower IFT than C1 and C2, the imbibition was faster than C2 and similar to C1.
This could because of the pre-existing micro-fracture on this core sample.
Based on the simulation results summarized the roles of IFT and wettability
played on spontaneous imbibition in carbonate and shale matrix, Sheng (2017)
proposed that the initial wettability plays an important role in such a scenario.
Therefore, a wettability alterable surfactant is a prerequisite for the success of
spontaneous imbibition in oil-wet shale matrix. In addition, because the alteration
progress usually takes a long period, a high IFT is necessary to make this EOR method
practical and noticeable. Further, due to the ultra-low permeability, the effect of
gravitational imbibition is too small to make any distinctive contribution in a short
period of time. Therefore, if the oil-wet nature was intact, the EOR attempt will
become a fail regardless of the value of IFT. Sheng (2017) In an oil-wet reservoir with
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higher permeability, for example, some carbonate reservoirs, because of the buoyancy
force is able to overcome viscous and capillary resistance among the porous media, it
is important to decrease the IFT to ameliorate the capillary trapping, and the
wettability alteration is not important.(Sheng 2013)
The experimental results of this study verified Sheng’s conclusion from the
simulation results. Capillary pressure is the most essential driving force to propel the
whole imbibition process. In shale oil reservoirs, because of the oil-wet nature and the
extremely low permeability, wettability alteration is the rule of thumb to guarantee the
spontaneous imbibition works. According to the Yong-Laplace equation, capillary
pressure is proportional to the value of IFT. Therefore, a surfactant that has wettability
alteration capacity while holding a higher IFT would be the ideal candidate to be used
in a surfactant EOR project in oil-wet unconventional oil reservoirs. This explained
why the nonionic surfactant N1, which has high-IFT and wettability alteration
function, obtained the highest recovery while the KCl controlling case was the worst.
This concluding remark will be further investigated by the simulation results.
Figure 5. 3 Recovery profiles of Spontaneous imbibition experiments
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0 20 40 60 80 100 120
Rec
ove
ry F
acto
r, f
ract
ion
Time, days
N1
C1
C2
A1
A2
Water
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5.1.2 Simulation study
The base model was built under a cylindrical coordinate with a two-
dimensional radial cross section (r-z) in STARS by Computer Modeling Group. CMG-
STARS is a reservoir simulator that can design and evaluate the effectiveness of
chemical-EOR processes of complex chemical additives. In this study, the base model
is homogeneous, and has 18 same sized grid blocks in the r-direction, 24 grid blocks in
the z-direction and 1 grid block in the θ-direction. The dimension of r-direction is 0.06
inch, 360 degrees for θ-direction and 0.24 inches for z-direction. As shown in Figure
2, The central 12×1×12 blocks in blue color represent the core plug suspending in the
Amott cell. The rest blocks in red simulate the ambient space of the Amott cell that
filled with water or surfactant solutions. These two sectors were marked by sector 1
and 2 for further results analysis. An illustration can be seen in Figure 5.4.
Figure 5. 4 Illustration of the base case simulation model (blue blocks represent the
core plug and the red blocks represent the soaking environment in Amott Cell)
Sector 1
Sector 2
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Modeling of interfacial tension reduction
By making a correlation between surfactant concentration and interfacial
tension, a lower phase microemulsion can be simulated by CMG-STARS. To manifest
the microemulsion phase, Liquid-Liquid K-value in CMG-STARS is defined as:
𝐾𝑖𝐴𝐵 =
composition of component 𝑖 in phase A
composition of component 𝑖 in phase B
The actual phase of A and B will be decided by the reference phase of
component 𝑖. For a lower phase microemulsion, we can define:
Kwater𝑂𝑊 =
𝜒𝑤𝑎𝑡𝑒𝑟𝑂
𝜒𝑤𝑎𝑡𝑒𝑟𝑊 ≡ 0
Ksurf𝑂𝑊 =
𝜒𝑠𝑢𝑟𝑓𝑂
𝜒𝑠𝑢𝑟𝑓𝑊 ≡ 0
Koil𝑊𝑂 =
𝜒𝑜𝑖𝑙𝑊
𝜒𝑜𝑖𝑙𝑂 = 𝜒𝑜𝑖𝑙
𝑊
where 𝜒𝑤𝑎𝑡𝑒𝑟𝑂 is mole fraction of water in the oleic phase; 𝜒𝑤𝑎𝑡𝑒𝑟
𝑊 is mole
fraction of water in the aqueous phase; 𝜒𝑠𝑢𝑟𝑓𝑂 is mole fraction of surfactant in the oleic
phase; 𝜒𝑠𝑢𝑟𝑓𝑊 is mole fraction of surfactant in the aqueous phase; 𝜒𝑜𝑖𝑙
𝑊 is mole fraction
of oil in the aqueous phase and 𝜒𝑜𝑖𝑙𝑂 is mole fraction of oil in the oleic phase. In this
model, the aqueous phase could also be described as a pseudo-microemulsion phase.
Theoretically, if a table of Koil𝑊𝑂 as a function of 𝜒𝑠𝑢𝑟𝑓
𝑊 is given, a correlation
between the solubilization parameter (𝜒𝑜𝑖𝑙𝑊 ) and surfactant solution contents (𝜒𝑠𝑢𝑟𝑓
𝑊 )
can be established. Huh proposed a good correlation between interfacial tension and
solubilization ratio, so Interfacial tension can be described as a function of
solubilization ratio:
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𝜎𝑂𝑀 =𝐶
(𝑉𝑜𝑚
𝑉𝑠𝑚)
2
where, 𝜎𝑂𝑀 is the IFT between oil and lower phase microemulsion phase; C is
the fitting parameter; 𝑉𝑜𝑚 and 𝑉𝑠𝑚 are the volume of oil or surfactant in the
microemulsion phase; 𝑉𝑜𝑚/𝑉𝑠𝑚 is the solubilization ratio.
Therefore, a correlation between surfactant concentration (𝜒𝑠𝑢𝑟𝑓𝑊 ) and
interfacial tension (𝜎𝑂𝑀) can be constructed. If a set of relative permeability (Kr)
curves and capillary pressure (Pc) curves for different interfacial tensions was given,
the IFT reduction effect can be simulated by controlling the surfactant concentration.
Modeling of wettability alteration
The effect of wettability alteration is characterized by the adsorption isotherm
of surfactant, and it can be described as:
𝛤𝑠𝑢𝑟𝑓 =𝐶1 ∗ 𝜒𝑠𝑢𝑟𝑓
𝑊
1 + 𝐶2 ∗ 𝜒𝑠𝑢𝑟𝑓𝑊
𝛤𝑠𝑢𝑟𝑓 =𝐶1
1𝜒𝑠𝑢𝑟𝑓
𝑊 + 𝐶2
𝛤𝑠𝑢𝑟𝑓 = 𝐺(𝜒𝑠𝑢𝑟𝑓𝑊 )
where, 𝛤𝑠𝑢𝑟𝑓 is the adsorption isotherm of surfactant, 𝑔𝑚𝑜𝑙𝑒/𝑓𝑡3 ; 𝐶1 𝑎𝑛𝑑 𝐶2
are adsorbing constants for Langmuir isotherm adsorption.
By giving the upper boundary (𝛤𝑠𝑢𝑟𝑓𝑈 ) and lower boundary (𝛤𝑠𝑢𝑟𝑓
𝐿 ) of
adsorption, a second level of relative permeability curves and capillary pressure curves
can be calculated to generate the final Kr and Pc curves. The Kr and Pc are
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wettability-dependent which is also 𝛤𝑠𝑢𝑟𝑓 dependent. 𝐾𝑟
𝛤𝑠𝑢𝑟𝑓𝑈
and 𝑃𝐶
𝛤𝑠𝑢𝑟𝑓𝑈
correspond to
the case that completely water-wetness achieved; 𝐾𝑟
𝛤𝑠𝑢𝑟𝑓𝐿
and 𝑃𝐶
𝛤𝑠𝑢𝑟𝑓𝐿
corespond to the
scenario of complete oil-wet. The interpolation for 𝐾𝑟 and 𝑃𝑐 in each grid can be
written in a general form as:
Kr = 𝐾𝑟
𝛤𝑠𝑢𝑟𝑓𝐿
+ (𝛤𝑠𝑢𝑟𝑓 − 𝛤𝑠𝑢𝑟𝑓
𝐿
𝛤𝑠𝑢𝑟𝑓𝑈 − 𝛤𝑠𝑢𝑟𝑓
𝐿 ) (𝐾𝑟
𝛤𝑠𝑢𝑟𝑓𝑈
− 𝐾𝑟
𝛤𝑠𝑢𝑟𝑓𝐿
)
P𝐶 = 𝑃𝐶
𝛤𝑠𝑢𝑟𝑓𝐿
+ (𝛤𝑠𝑢𝑟𝑓 − 𝛤𝑠𝑢𝑟𝑓
𝐿
𝛤𝑠𝑢𝑟𝑓𝑈 − 𝛤𝑠𝑢𝑟𝑓
𝐿 ) (𝑃𝐶
𝛤𝑠𝑢𝑟𝑓𝑈
− 𝑃𝐶
𝛤𝑠𝑢𝑟𝑓𝐿
)
A schematic flow chart of the Kr and Pc curves calculation is explained in
Figure 5.5. Since 𝛤𝑠𝑢𝑟𝑓 is also a function of 𝜒𝑠𝑢𝑟𝑓𝑊 , by changing 𝜒𝑠𝑢𝑟𝑓
𝑊 , both IFT
reduction and wettability alteration effects could be simulated by controlling one
parameter.
Figure 5. 5 Schematic of Kr and Pc curves interpolation
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Modeling of spontaneous imbibition in oil-wet matrix
To simulate the spontaneous imbibition process, the vertical equilibrium is
turned off for initialization, and water will be imbibed into oil blocks because of a
positive capillary pressure. The capillary pressure curves for water and oil wet
conditions are given in Figure 5.6. As mentioned in the wettability alteration section,
both IFT reduction and wettability alteration can be affected by adjusting the
surfactant concentration, which is convenient for some circumstances. However, since
the purpose of this work is to analyze the relative importance of wettability alteration
and IFT reduction mechanisms separately, it is unfavorable to define these two
processes depending on one same factor. To solve this problem, we defined two
chemicals with identical properties as two pseudo components in the model. By doing
so, the first agent (S1) and the second agent (S2) can be manipulated separately to
affect IFT reduction and wettability alteration.
To analyze the oil recovery, average water saturation in sector 1 can be read
and acquired from the results. The recovery factor from the simulation can be
calculated by:
RF =𝑆𝑤̅̅̅̅ − 𝑆𝑤𝑖
1 − 𝑆𝑤𝑖
where, 𝑆𝑤̅̅̅̅ is the average water saturation in sector 1; 𝑆𝑤𝑖 is the initial water
saturation in sector 1
Figure 5. 6 Capillary pressure curves of oil-wet and water-wet for the base carbonate
cases
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Model validation
Delshad et al. and Sheng successfully did history matching on Hirasaki and
Zhang’s spontaneous imbibition experiment in oi-wet carbonate with simulator
UTCHEM (Hirasaki and Zhang 2004, Delshad, Najafabadi et al. 2009, Sheng 2013).
In this work, we firstly used the same experimental results to validate our CMG-
STARS model. In the ambient blocks, the porosity is 0.999 and the capillary pressure
is 0 psi. The permeability is 1000 mD and relative permeability curves are two
diagonals. For the core sample blocks, the relative permeability curves and capillary
pressure curves are described by Brooks and Corey’s model (Brooks and Corey 1966).
Related parameters and petrophysical properties are showed in Table 5.3. Surfactant
adsorption isothermal is shown in Figure 5.7 and the upper-bound and lower-bound
for wettability alteration are 0.01 gmole/ft3 and 0, respectively. The relations of
solubilization parameter versus surfactant concentration and IFT versus solubilization
parameter were adjusted to match the experimental data and were shown in Figure 5.8
& 5.9. As showed in Figure 5.10, the simulation results from our CMG model
matched the experimental data and UTCHEM results.
Table 5. 3 Petrophysical parameters for base model
Oil-Wet Water-Wet
Oil Phase Water Phase Oil Phase Water Phase
Sor & Swi 0.38 0.32 0.38 0.32
Endpoint of Kr 0.59 0.23 1 0.15
Kr Exponent 3.3 2.9 2 2
Endpoint of Pc (psi) -5 5
Pc Exponent 2 2
Permeability (mD) 122
Porosity(%) 24
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Figure 5. 7 Surfactant adsorption isothermal
Figure 5. 8 Correlation between surfactant concentration and solubilization parameter
0.001
0.01
0.1
0.001 0.01 0.1 1
AD
S, g
mo
le/f
t2
Mole Fraction of Surfactant in aqueous phase
0.0001
0.001
0.01
0.1
1
0.0001 0.001 0.01 0.1 1
Mo
le F
ract
ion
of
oil
in m
icro
euls
ion
ph
ase
Mole Fraction of Surfactant in aqueous phase
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Figure 5. 9 Correlation between solubilization parameter and IFT
Figure 5. 10 History Matching results of spontaneous imbibition from carbonates
0.00001
0.0001
0.001
0.01
0.1
1
10
100
0.00001 0.0001 0.001 0.01 0.1 1
IFT
mN
/m
Mole Fraction of oil in microeulsion phase
0
10
20
30
40
50
0 20 40 60 80 100 120 140
Rec
ove
ry F
acto
r, %
Time, Days
Experiment
UT-Chem
CMG-STARS
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Model adjustment
To transform the base model into a shale-scale model, both result accuracy and
running efficiency should be considered. Not only the static properties such as
permeability and porosity need to be changed, but capillary pressure, relative
permeability curves and grid block numbers should be adjusted and refined as well. For
the static properties of this shale model, permeability was assigned to 0.00035 mD (350
nD) and the porosity was 7.5% (Table 5.4). In order to obtain a higher accuracy of
interpolation, a set of 5 relative permeability and capillary pressure curves
corresponding to different IFTs were introduced into the simulation model for both oil-
wet and water-wet cases. The correlation provided by Longeron were considered to
assign the relative permeability curves verse different IFTs. (Longeron 1980) When IFT
that is larger than 1 mN/m, relative permeability curves were considered to be the same,
but the differences started to appear when IFT further decreased. Two diagonals were
considered as the relative permeability curves for ultimate low IFT that equals to
0.001mN/m (Figure 5.11). The capillary pressure curves were plotted separately for
different IFTs in Figure 5.12 based on Young-Laplace equaiton. The endpoint of Pc is
1450 psi when IFT is high and is 0 when ultra-low IFT (0.001mN/m) was achieved. The
capillary pressure values are positive for water-wet cases and negative for oil-wet cases.
Details of assigned values are shown in Table 5.5 and Table 5.6.
Table 5. 4 Static parameters of shale model
Parameters Oil-Wet Water-Wet
Oil Phase Water Phase Oil Phase Water Phase
Sor & Swi 0.15 0 0.15 0
Permeability (mD) 0.00035
Porosity(%) 7.5
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Table 5. 5 Relative permeability and capillary pressure curves for oil-wet rock
IFT, mN/m 20 1 0.1 0.01 0.001
Phase O W O W O W O W O W
Endpoint of Kr 0.59 0.23 0.59 0.23 0.7 0.4 1 1 1 1
Kr Exponent 3.3 2.9 3.3 2.9 2.7 2.2 2 2 1 1
Endpoint of Pc (psi) -1450 -72.50 -7.25 -0.73 0
Pc Exponent 2
Table 5. 6 Relative permeability and capillary pressure curves for water-wet rock
IFT, mN/m 20 1 0.1 0.01 0.001
Phase O W O W O W O W O W
Endpoint of Kr 1 0.15 1 0.15 1 0.4 1 0.7 1 1
Kr Exponent 2 2 2 2 1.7 1.7 1.3 1.3 1 1
Endpoint of Pc (psi) -1450 -72.50 -7.25 -0.73 0
Pc Exponent 2
Figure 5. 11 Relative permeability curves for different IFTs of oil-wet (left) and water-
wet (right) cases
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Figure 5. 12 Capillary pressure curves of oil-wet and water-wet cases with different
IFTs
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The sensitivity analysis of grid block numbers was done before any further
studies. The original base case has 18 grid blocks in the r direction, 1 grid block in the
θ direction and 24 grid blocks in the z-direction. Since the middle 12×1×12 blocks
represent the core sample, we started grid refinement at the outermost layer by 20
times and 10 times (Figure 5.13). As shown in Figure 5.14, for the model with 20
times grid blocks, the running time is more than 30 minutes, which is inefficient for
our study purposes. However, the model with 10 times grid blocks needed only about
5 minutes and the result was quite close to the 20 times model when compared with
the original case. Therefore, the 10 times grid refinement as the final candidate was
selected for the shale-based model.
Figure 5. 13 10-times refinement shale imbibition model
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Figure 5. 14 Sensitivity analysis of grid block numbers on shale model
Comparison between experimental and simulation results
Four numerical simulation cases were created to match the experimental
results from surfactant N1, C1, A1 and water with high, intermediate, low IFT and
non-wettability alteration cases (Figure 5.15). All cases were assigned to original oil-
wet, but only those simulates surfactant solution imbibition were able to be altered the
wettability to water-wet. The one without wettability alteration simulated the brine
system. From the results, final recoveries of three surfactant cases at 120 days matched
the experimental results. However, the initial imbibition rates in our simulation model
were higher than the experiments, this may because of the differences of the efficiency
of wettability alteration between the experiments and simulation models. The
wettability alteration started as the surfactant molecules entered the matrix pores
through diffusion, which is a slow process to initiate. In other words, if a surfactant
has stronger wettability alteration effect, the difference between the experiment and
the simulation results will be smaller. Otherwise, the difference will be larger. Further,
during the experiment, the Amott cells were placed at a stable bench to prevent any
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disturbance, but it also caused some early produced oil attached to the core surface
was not being counted. As the oil droplets converged to bigger sizes, the oil detached
from the surface, and caused the sudden recovery increase on the profile. In the brine
case, simulation result basically showed no oil recovered for the whole period. This is
because the wettability was not altered, and the capillary pressure was negative.
However, in the experiment, capillary imbibition may not the only effect that is
responsible for water uptake. Clay hydration, micro-fracturing and osmosis effects etc.
could result in a certain amount of water being taken into the shale matrix (Singh
2016).
Figure 5. 15 Comparison between experimental and simulation results
0
0.2
0.4
0.6
0.8
1
0 20 40 60 80 100 120
Rec
ove
ry F
acto
r
Time, Days
EXP-N1 SIM-High IFT- 100%WA
EXP-C1 SIM-Interm IFT- 100%WA
EXP-A1 SIM-Low IFT- 100%WA
EXP-Water SIM-High IFT- 0%WA
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Sensitivity studies: Effect of interfacial tension and wettability
The effect of IFT was analyzed first. A series of cases were assigned to
completely altering the originally oil-wet model to water-wet, but the IFT between
oleic and aqueous are different. To differentiate the IFTs, the concentration of
component S1 is assigned to values corresponding to different capillary pressure
curves. The results are shown in Figure 5.16. It is being noticed that the speed of
spontaneous imbibition of oil-wet shale strongly correlates to the value of IFTs. With
the same capacity of wettability alteration, the case of 30 mN/m IFT exhibited the
fastest imbibition speed and highest oil recovery at 120 days, whereas the case with
ultra-low IFT has the lowest recovery, which is less than 1% at 120 days. These results
indicated that if a group of surfactants have the same ability to alter the wettability, the
one keeps the highest IFT should be the best candidate.
Figure 5. 16 Sensitivity analysis results of interfacial tension
The next issue is to investigate the influence of wettability alteration of a
surfactant while the IFTs are the same. Since the extent of wettability alteration
essentially correlates to the concentration of component of surfactant (S2), a series of
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cases are designed to alter the wettability from 0% to 100%. The 0% case corresponds
to the surfactant has no ability to change the wetness, which indicates the shale stays
originally oil-wet state. Analogously, 50% and 100% would represent the ability to
alter the wetness to intermediate-wet and completely water-wet. The IFTs for all cases
are equally assigned to 1 mN/m. The simulation results showed in Figure 5.17
indicated that the speed of spontaneous imbibition also positively correlates to the
extent of water-wetness. It could be explained that the more water-wet state is, the
larger the capillary pressure was expected, which is favorable for spontaneous
imbibition process. Wang and Sheng studied this observation in a micro-scaled pore
network model and yielded a similar observation. Their results showed that when the
oil-wet fraction is larger than 40%, the recovery factor decreased significantly with the
increase of oil-wetness. They concluded that it is due to the significant shrinkage of
the positive capillary pressure (Wang and Sheng 2018).
Figure 5. 17 Sensitivity analysis results of wettability
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In the 0% alteration case, oil recovery is almost zero at 120 days, though the
IFT is reduced by approximately 20 times. This did not occur in either the simulation
or the experimental studies in oil-wet carbonates (Delshad, Najafabadi et al. 2009,
Sheng 2013). This is because the effect of gravity in extremely low permeability is too
small to be effective in a short period of time. To investigate the effect of gravity, we
designed another two cases to verify our explanation. One case represents the
carbonate model with higher permeability (122 md) and the other one stands for a
shale matrix (350 nd). Both two cases are oil-wet and assigned with ultra-low IFT
between oleic and aqueous phases; the initial water saturation and residual oil
saturation were assigned to zero. Therefore, the only driving force in these two
simulation models is gravity, and the results were showed in Figure 5.18. Under an
ultra-low IFT, gravity is very important for water uptake in carbonate matrix, and the
ultimate recovery was reached by 30 days. However, for the shale matrix, such an
effect is negligible in a profitable timeframe because the ultimate recovery was
achieved only at almost 10 million days. The results explained the inefficiency of
imbibition in shale if it stays oil-wet.
Figure 5. 18 Analysis of gravity effect on carbonate and shale models
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The final simulation cases are to investigate the combined effect of wettability
alteration and IFT reduction on spontaneous imbibition. We designed 8 cases that can
be paired into 4 groups. An array of IFT values that vary from 20 to 0.01mN/m were
run for 80% and 20% wettability alteration (c.f. Figure 5.19). As previously
discussed, both wettability alteration and IFT reduction correlate to the rate of
spontaneous imbibition. high IFT and a more water-wet status achieved the highest
recovery within an extremely short period. In addition, it can be observed that for any
two cases with the same IFTs, the final oil recovery is essentially controlled by the
matrix wetness status.
Figure 5. 19 Combined effects of IFT and wettability
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5.2 Forced Imbibition with Surfactant in Oil-wet Shale
5.2.1 Experimental design
The purpose of the experimental study in this section is to observe the oil
recovery through surfactant imbibition in oil-wet shale samples. Therefore, besides the
similar fluid system designs from spontaneous imbibition, the approaching techniques
of spontaneous imbibition (SI), forced imbibition (FI), and cyclic injection (CI) are
compared. The period of each core experiment is set to 8 days (192 hours) and the
experimental setup and procedures are described in chapter 3.
For the soaking solutions, three surfactant candidates with similar wettability
alteration abilities (Figure 5.20) and 5% KCl solution that simulates conventional
fracturing fluid were selected for the core experiments, and the fluid properties are
shown in Table 5.7.
Table 5. 7 Fluid properties of selected system
Solution Formula IFT, mN/m Wettability Alteration
CA before
treatment, °
CA after
treatment, °
Final
Wetness
Brine (5% KCl) 18 153 147 Oil-Wet
High IFT surfactant 3 152 40 W-Wet
Intermediate IFT surf. 0.4 161 50 W-Wet
Low IFT surfactant 0.02 169 39 W-Wet
Figure 5. 20 Contact Angles after surfactant treatment (from left to right: high IFT,
intermediate IFT, low IFT )
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The experimental arrangement for each core plug with different fluid systems
and operational methods is summarized in Table 5.8.
Table 5. 8 Specification of experiment assignment for each core plug
Fluid
System
Core
No.
Operational
Methods
Pressures, psi Cycle
Numbers
Time of
Exps, hrs
High IFT 1 SI 14.7 1 192
2 CI 3000 - 14.7 periodically 8
3 FI 3000 1
Intm. IFT 4 SI 14.7 1
5 CI 3000 - 14.7 periodically 8
6 FI 3000 1
Low IFT 7 SI 14.7 1
8 CI 3000 - 14.7 periodically 8
9 FI 3000 1
5% KCL 10 SI 14.7 1
11 CI 3000 - 14.7 periodically 8
12 FI 3000 1
5.2.2 Result comparison and discussion
The results of experiments of SI, FI, and CI in terms of recovery factors are
listed in Table 5.9, 5.10 and 5.11 along with the recovery profiles graphed in Figure
5.21, 5.22 and 5.23. Figure 5.24 to Figure 5.27 are the photos taken after each cycle of
the cyclic injection experiments.
The highest recovery was achieved by high IFT surfactant solution with CI
technique. This combination acquired 38.4% recovery at the end of 8th cycle of
soaking-depletion schedule. In fact, high IFT solution systems achieved highest
recoveries in all categories. This is contradictive to the traditional point of views about
surfactant-EOR as the lower IFT the better recovery percentages can be obtained.
However, the result can be explained by the theory of capillary imbibition. The 5%
KCl fluid systems failed all the tests as expected because the initial wetness stayed oil-
wet, and the IFT was not being reduced. However, it should be noticed that effective
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CI technique was very effective to be applied on unconventional shale matrix with
liquid phase substances, especially with the assistance of surfactants. Even the case of
5% KCl solution that has no WTB alteration and high IFT achieved 8.12% recovery
with CI. This is a tremendous enhancement in such a short period when compared to
that of SI and FI that acquired only 0.4% and 0 recovery within the same time frame.
For a better comparison of the performance of different fluid systems along
with various operational methods, Table 5.12 is created to summarize the final
recovery factors of each scenario. A bar chart is created in Figure 5.28 that classified
each fluid system in clusters. It can be noticed that the CI technique was most
effective compared to the other two in general. Whereas the differences between FI
and SI were not distinguishing, and the applied external pressure can be even
detrimental to the imbibition process. This effect is especially notable in high IFT
fluid system.
Table 5. 9 Oil recovery factor of spontaneous imbibition tests
High IFT Surf. Inter. IFT Surf. Low IFT Surf. 5% KCl
Time, HRS RF, % Time, HRS RF, % Time, HRS RF, % Time, HRS RF, %
0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
5.15 0.79 5.15 0.00 50.00 2.00 5.15 0.00
20.98 3.15 20.98 1.91 96.00 3.22 20.98 0.00
24.12 3.63 24.12 2.49 144.0 4.82 24.12 0.00
42.65 4.73 42.65 3.64 200.0 5.63 42.65 0.00
47.95 4.73 47.95 4.21
47.95 0.20
67.12 6.31 74.02 4.79
74.02 0.20
74.02 7.10 90.32 5.55
90.32 0.20
90.32 7.88 97.70 5.55
97.70 0.40
97.70 7.88 113.32 5.55
113.32 0.40
113.32 8.67 167.78 5.74
167.78 0.40
167.78 11.04 184.12 5.74
184.12 0.40
184.12 11.20 193.20 5.74
193.20 0.40
193.20 11.83
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Table 5. 10 Oil recovery factor of forced imbibition tests
Fluid System RF at 192 HRS, %
High IFT Surf. 7.75
Inter. IFT Surf. 5.37
ow IFT Surf. 5.05
5% KCl 0.00
Table 5. 11 Oil recovery factor of cyclic injection tests
Cycle No. Time, HRS Recovery Factor, %
High IFT Surf. Inter. IFT Surf. Low IFT Surf. 5% KCl
0 0 0 0 0 0
1 24 3.20 3.77 1.87 0.00
2 48 6.40 7.54 2.80 0.81
3 72 9.60 11.31 5.61 1.62
4 96 12.80 13.19 6.54 3.25
5 120 17.60 16.96 7.48 4.06
6 144 24.00 18.85 11.21 4.87
7 168 32.00 20.73 13.08 6.49
8 192 38.40 22.62 14.95 8.12
Figure 5. 21 Recovery profile of spontaneous imbibition tests
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Figure 5. 22 Recovery profile of forced imbibition tests
Figure 5. 23 Recovery profile of cyclic injection tests
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Figure 5. 24 Cyclic injection tests in 5% KCl
Figure 5. 25 Cyclic injection tests in High IFT Surfactant (3mN/m)
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Figure 5. 26 Cyclic injection tests in Intermediate IFT Surfactant (0.4 mN/m)
Figure 5. 27 Cyclic injection tests in Low IFT Surfactant (0.02 mN/m)
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Table 5. 12 Comparison between the final RF of each solution and technique
Operational Technique High IFT Surf. Inter. IFT Surf. Low IFT Surf. 5% KCl
SI 11.83 5.74 5.63 0.40
FI 7.75 5.37 5.05 0.00
CI 38.40 32.04 14.95 8.12
Figure 5. 28 Comparison of final recoveries
Effect of soaking fluid
The properties of each fluid system mainly vary in IFT and wettability.
Traditionally, surfactant was used as an injecting additive in the flooding of
conventional reservoirs to decrease the IFT and the capillary number (Nc) will be
increased by orders of magnitude and thus the residual oil saturation was decreased by
allowing the oil droplets to pass through the pore throats with less resistance. Whereas
in oil-bearing shale formations, due to the ultra-low permeability and poor injectivity,
surfactant flooding is an impossible approach. In another word, even the IFT is
effectively reduced in shale system, the increased capillary number is not enough to
overcome the capillary blockage. Therefore, the IFT reduction may not be the best
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approach to enhance shale oil recovery and most current studies on surfactant shale oil
EOR have been focusing on stimulating the imbibition process.
Nc =𝑣𝜇
σ𝑐𝑜𝑠𝜃
where 𝜎 is the interfacial tension; 𝜃 is the contact angle; 𝜇 is the viscosity of
displacing fluid; 𝑣 is the displacing Darcy velocity.
As can be seen from the Young-Laplace equation, the magnitude and direction
of capillary pressure are related to the IFT, pore radius, and the wetness expressed by
contact angle. The ultra-low permeability of shale matrix offers the possibility of a
tremendous capillary pressure being created, as the pore radius are in nanoscale. (Sigal
2015) Therefore, to utilize the capillary pressure in our favor, on the one hand, the
contact angle shall be controlled to be less than 90 degrees to achieve a water-wet
status. On the other hand, the IFT should be sufficiently high to obtain a higher
capillary pressure. This should be the reason for 5% KCl fluid system achieved the
lowest recovery from our experiment, because of the oil-wet status and high IFT
condition, it creates the highest resistance among all combinations. In addition, the
recovery profile is positively correlated to the IFT value despite the operational
technique because the higher IFT created higher capillary pressure further stimulated
the imbibition process. It has been verified by Liu and Sheng through NMR
experiments that in spontaneous imbibition process, wettability alteration is the key
mechanism to enhance the oil recovery in oil-wet shale reservoirs, while the effect of
IFT reduction is not obvious when wettability not being altered. (Liu and Sheng 2019)
Effect of operational techniques
The experimental setup studied in this chapter simulated the process of
counter-current imbibition with external soaking pressures. Therefore, the pressure
gradient within the porous media should be all balanced once the pressure transmits
through the core’s characteristic length. The mechanism of forced counter-current
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imbibition has been summarized in chapter 4. After the mechanism of imbibition
between SI and FI techniques are both capillary force-driven imbibition once the
soaking pressure is balanced, but this effect is negligible on a core scale rock sample.
This explained why the recovery factors of SI and FI between low and intermediate
IFT systems did not show much difference.
The CI technique is proven to be the most effective method experimentally.
This is because the CI technique, expedited the initiation of wettability alteration
process, the periodical pressure and material compression and release is another
mechanism to speed up the oil recovery process through depletion (huff-n-puff).
However, the residual oil saturation should not be expected to be reduced through high
IFT surfactant imbibition, since the capillary number is not being increased
sufficiently. The experimental results indicated that surfactant EOR is an effective
approach to boost and accelerate the shale oil recovery in a short period of time.
Unlike the ultra-low IFT surfactant used in conventional and carbonate reservoirs, a
higher IFT surfactant with wettability alteration function that is compatible to the
reservoir temperature and salinity should be look for to design a successful EOR
project in shale oil plays.
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CHAPTER Ⅵ
CONCLUDING REMARKS AND CONCLUSIONS
In this chapter, the conclusions derived from the experimental and numerical
simulation reported in this dissertation are summarized. The main objective of this
dissertation was to investigate the potential of enhancing oil recovery through
fracturing fluid imbibition in unconventional oil reservoirs during the well completion
stage. This dissertation approached this topic through the combination of experimental
and numerical simulation study. The mechanisms of liquid imbibition in
unconventional matrix was investigated. Further, feasibility analysis of the
implementation methods was conducted. Chemical agents, such as surfactant, were
studied to solve pragmatic challenge: the oil-wet nature of shale oil reservoir.
This workflow enables the idea of enacting liquid imbibition in oil-wet
unconventional reservoirs to improve oil recovery. The advantage of utilizing
imbibition during the completion stage is to extract extra gains before a well starts to
produce, and to avoid further investment given the unstable global crude oil market.
6.1 Imbibition in unconventional reservoirs
6.1.1 Spontaneous imbibition
According to the experimental results, spontaneous imbibition in
unconventional reservoirs is mainly induced by capillary pressure when the wettability
is water wet. The effect of gravitational driven imbibition is not prominent because the
density difference resultant buoyancy force is unable to either overcome capillary trap
or the initiate viscous flow in unconventional matrix.
6.1.2 Forced imbibition
In this dissertation, forced imbibition is defined as the imbibition process when
the external soaking pressure is higher than the matrix pore pressure. Under the lab
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experiment conditions, forced imbibition occurs whenever the soaking pressure is
larger than the atmospheric pressure (the initial pore pressure inside the core). In the
reservoir environment, forced imbibition only occurs when the soaking pressure is
higher than the reservoir pressure.
In the hydraulic fracture – matrix system, the effect of Forced Counter-Current
Imbibition (FCCI) is critical in unconventional oil production because it is usually the
only manner to take place under the reservoir condition. The study of this topic should
be specifically distinguished from Forced or Spontaneous Co-Current Imbibition
(SCOI and FCOI) because of the effects of pressure, wettability, and many other fluid-
rock interactions can be quite different or even opposite for these two types of
imbibition manners.
Both experimental and numerical simulation results indicated that regardless of
the soaking pressure, the wettability of low-permeable rocks is crucial to engender
positive capillary pressure and trigger counter-current imbibition. Therefore, for an
oil-wet tight or shale oil reservoir, managing wettability alteration is significant to the
success of EOR projects.
Forced imbibition in core scale model
An experimental setup that can withstand up to 10,000 psi was designed to
serve the purpose of investigating forced imbibition experimentally. This setup is to
simulate the process of forced counter-current imbibition, and cyclic injection with
soaking fluid (huff-n-puff). The recoveries through imbibition can be visually tracked
at the end of each test with the setup.
According to our experimental and numerical simulation studies, when the
matrix is water-wet, the effect of soaking pressure is unnoticeable in a core scale
model. This is because the time required for equilibrium of the externally applied
soaking pressure is very short in a core scale model.
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When the model is oil-wet, the soaking pressure does not influence the results
of forced counter-current imbibition as the changes of water saturation and capillary
pressure, which created by the soaking pressure, are negligible.
Forced imbibition in reservoir scale model
According to our numerical simulation results, the effect of soaking pressure in
reservoir scale model is noticeable and inevitable. The applied soaking pressure
negatively correlates to the oil recovery through imbibition in the water-wet
unconventional reservoir. This is because the time required for pressure equilibrium in
reservoir scale model (matrix between hydraulic fractures) is large enough to cause a
discernible effect.
Dimensionless pressure (𝑝𝐷) is defined in this study to quantitatively
determine the extent of imbibition inhibition during forced imbibition. It is defined as
the quotient of local resultant pressure versus the applied soaking pressure. The local
resultant pressure is the combination of local reservoir pressure, capillary pressure,
and soaking pressure. When the 𝑝𝐷 is larger than 1 at a given location, the local
resultant pressure is larger than the pressure barrier, and the imbibition is unconfined
at the given location. When the 𝑝𝐷 curve is completely surpassed 1 across the matrix
characteristic length, the imbibition is completely free from pressure blocking, and the
behavior of imbibition became the same as spontaneous imbibition.
In a reservoir scale model, to benefit more from the imbibition during the well
completion stage and hydraulic fracturing operation, the pressure difference between
the reservoir and hydraulic fractures should be optimized.
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Sensitivity analysis of influential factors
• The imbibition is highly sensitive to the cluster spacing within each
stage. By increasing the clusters per stage, the recovery factor yields to
a power-law ascending correlation.
• The effect of soaking pressure decreases as the cluster spacing getting
tighter. This is because the pressure equilibrates faster as the
characteristic length decreases.
• The imbibition behavior strongly correlated with the wettability of the
porous media. As the media evolve from oil-wet to more water-wet, a
capillary pressure threshold can be expected to trigger the imbibition.
The applied pressure does not assist imbibition in oil-wet reservoirs.
• The permeability correlates with the counter-current imbibition in a
logarithm manner, the imbibition is more efficient in high-permeability
reservoir in terms of oil recovery due to the enhanced effect of
gravitational driven imbibition, even the generated capillary pressure is
lower.
• According to our simulation, the imbibed fluid volume negatively
correlates to the initial water saturation due to the decreased capillary
pressure.
6.2 Surfactant EOR in Unconventional Oil Reservoirs
As has been emphasized through the entire dissertation, the mechanism of
surfactant EOR in unconventional oil reservoir through imbibition should be
differentiated from the traditional surfactant EOR in conventional or carbonate
reservoirs, which assists the capillary number enhancement to reduce the residual oil
saturation through, for example, surfactant flooding.
The mechanism of surfactant additives in unconventional oil reservoir is to
induce imbibition through wettability alteration. Traditional mechanisms are
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negligible due to the ultra-low permeability and poor injectivity. Therefore, this
finding implicates that surfactant EOR through imbibition is not a method to enhance
the ultimate oil recovery factor. Rather, it is a mean of expediting the oil production.
However, this approach still benefits the production economically considering the
sharp declining rate and long production period of shale oil.
Interfacial tension (IFT) reduction is an inevitable phenomenon when
surfactant agents were used. Therefore, the selection of surfactant agents should be
careful because the reduced IFT may cause the capillary pressure to be reduced, even
if the wettability is altered from oil-wet to water-wet.
According to the results of the experimental and numerical simulation, the
effects of IFT reduction and wettability alteration of a surfactant agent in
unconventional oil reservoir EOR are separately investigated. The following
conclusions can be summarized:
• The final recovery is prominently controlled by the extent of wettability
alteration from oil-wet to water-wet.
• For naturally oil-wet shale rocks, the wettability alteration effect is
necessary to trigger the imbibition, regardless of the IFT values.
However, a relatively high IFT is crucial to guarantee the efficiency
and effectiveness of imbibition.
• The effect of gravity is minor when comparing with the capillary force
in shale matrix, due to the extremely low permeability.
• Surfactant agent with the capacity of wettability alteration while
maintaining relatively high IFT is the best candidate to stimulate
imbibition in shale oil reservoir, then further maximize oil recoveries
within a given period.
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6.3 Methods of Implementation
In this dissertation, the implementation methods of spontaneous imbibition
(SI), forced imbibition (FI), and cyclic injection (CI) are compared experimentally
with surfactant solutions. The following points should be taken:
• The experiments proved that liquid phase imbibition in shale oil
reservoir is a potentially effective EOR method with the assistant of
proper surfactant additives. Despite the technique of implementation,
surfactant fluids achieved better oil recovery than brine water alone.
This is mainly because the effect of wettability alteration.
• CI technique is proven to be the most effective method experimentally
because firstly, the approach expedited the initiation of wettability
alteration process; second, the periodical pressurization and release
accelerated the oil recovery process through depletion (huff-n-puff).
• Interfacial tension reduction is not the main mechanism for the EOR
projects design in a shale oil play, and a higher IFT should be adopted
to benefit the oil recovery due to a larger capillary pressure.
• Without the periodically cyclic injection technique, the effect of
external pressure is not prominent between spontaneous imbibition and
forced imbibition, and it is because, first, the recovery is mainly
induced by capillary driven imbibition; second, the soaking pressure
equilibrate instantly across the matrix with the size of a core plug.
• The combination of CI technique and high IFT surfactant with
wettability alteration function is the best approach to enhance the shale
oil recovery. The surfactant should be able to manifest these properties
under the reservoir environment, such as temperature and salinity.
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