Copyright 2020, Jiawei Tu

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

ii

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


iv

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


v

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


vi

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


vii

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.


viii

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


ix

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

https://texastechuniversity-my.sharepoint.com/personal/jiawei_tu_ttu_edu/Documents/DissertationDefense/Manuscript/Dissertation%20Manuscript.docx#_Toc52887205


x

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


(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


(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


xi

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


xii

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


xiii

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


1

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


2

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


3

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.


4

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


5

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.


6

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


7

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


8

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.


9

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.


10

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)


11

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.


12

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


13

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)


14

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


15

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


16

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)


17

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)


18

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)


19

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


20

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


21

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.


22

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:


23

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:


24

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


25

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.


26

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


27

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


28

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.


29

• 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.


30

• 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.


31

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.


32

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


33

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:


the operation.








34

• 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%


chemical presented to prevent cross contamination.


35

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.


the operation.



36






• 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.


chemicals presented to prevent cross-contamination.


37

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.


38

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.


39

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


40

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-


41

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


42

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


43

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.


44

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).


45

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


46

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


47

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.


48

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


49

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


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


51

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.


52

Figure 4. 10 Base model with local gridblock refinement

Figure 4. 11 Influence of the number of gridblocks and sandstone base case history

matching


53

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


54

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


55

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


56

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


57

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.


58

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


(16,6,6) of FI at 3000 psi on large scale oil-wet shale


59

Figure 4. 18 Results of forced imbibition on large scale oil-wet shale


(16,6,6) of FI at 3000 psi on large scale water-wet shale


60

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


61

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


62

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


63

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.


64

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


65

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


66


67

Figure 4. 23 Pressure profiles (Left) and dimensionless pressure profiles (Right) based on different time


68

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


69

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


70

Figure 4. 24 Side view of the base reservoir model

Figure 4. 25 Aerial view of the base reservoir model


71

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


72

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.


73

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


74

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


75

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


76

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.


77

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


78

Figure 4. 31 Capillary pressure curves set for different permeabilities

Figure 4. 32 Capillary pressure curves set for different permeabilities


79

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


80

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.


81

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)


82

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


83

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


84

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


85

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


86

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:


87

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


88

wettability-dependent which is also 𝛤𝑠𝑢𝑟𝑓 dependent. 𝐾𝑟

𝛤𝑠𝑢𝑟𝑓𝑈

and 𝑃𝐶


correspond to

the case that completely water-wetness achieved; 𝐾𝑟

𝛤𝑠𝑢𝑟𝑓𝐿

and 𝑃𝐶


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


+ (𝛤𝑠𝑢𝑟𝑓 − 𝛤𝑠𝑢𝑟𝑓

𝐿

𝛤𝑠𝑢𝑟𝑓𝑈 − 𝛤𝑠𝑢𝑟𝑓

𝐿 ) (𝐾𝑟


− 𝐾𝑟


)

P𝐶 = 𝑃𝐶


+ (𝛤𝑠𝑢𝑟𝑓 − 𝛤𝑠𝑢𝑟𝑓

𝐿

𝛤𝑠𝑢𝑟𝑓𝑈 − 𝛤𝑠𝑢𝑟𝑓

𝐿 ) (𝑃𝐶


− 𝑃𝐶


)

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


89

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


90

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


91

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


92

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


93

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


94

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


95

Figure 5. 12 Capillary pressure curves of oil-wet and water-wet cases with different

IFTs


96

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


97

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


98

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


99

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


100

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


101

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


102

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


103

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 )


104

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


6 FI 3000 1

Low IFT 7 SI 14.7 1


9 FI 3000 1

5% KCL 10 SI 14.7 1


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


105

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


106

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


108

Figure 5. 24 Cyclic injection tests in 5% KCl

Figure 5. 25 Cyclic injection tests in High IFT Surfactant (3mN/m)


109

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)


110

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


111

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


112

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.


113

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


114

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.


115

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.


116

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


117

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.


118

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.


119

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