Assessment of Tight Rock Wettability by Spontaneous Imbibition at Elevated Pressures

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2019-01-23 Assessment of Tight Rock Wettability by Spontaneous Imbibition at Elevated Pressures

Sánchez Martinez, John Jairo

Sánchez Martinez, J. J. (2019). Assessment of Tight Rock Wettability by Spontaneous Imbibition at Elevated Pressures (Unpublished master's thesis). University of Calgary, Calgary, AB. http://hdl.handle.net/1880/109505 master thesis

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Assessment of Tight Rock Wettability by Spontaneous Imbibition at Elevated Pressures

John Jairo Sánchez Martínez

A THESIS

SUBMITTED TO THE FACULTY OF GRADUATE STUDIES

IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE

DEGREE OF MASTER OF SCIENCE

GRADUATE PROGRAM IN CHEMICAL ENGINEERING

CALGARY, ALBERTA

JANUARY, 2019

Wettability is an important reservoir property and must be well understood as it gives an indication of how fluids are distributed through the porous media. In tight reservoirs, which generally have been produced using hydraulic fracturing, the wettability evaluation becomes even more important for enhancing oil recovery, as it is a reference point for understanding the interaction between the fracturing fluids and the reservoir, to then be able to alter the rock wettability tendency into a more water-wet system by using appropriate fracturing fluids that would displace the oil into the matrix to the fractures by spontaneous imbibition.

It is known that the wettability evaluation of a reservoir is affected by multiple factors (core preservation state, fluid properties, temperature and pressure), and that the most representative results are obtained by using conditions as similar to the reservoir as possible. However, different than conventional reservoirs, in tight media reservoirs the measurement of wettability and its alteration become even more challenging, basically due to its low porosity and permeability, and also due to its mineralogical heterogeneity.

As a first approach for evaluating the wettability tendency of tight media reservoirs as close as possible to the reservoir conditions, a novel apparatus and methodology were designed in this thesis for assessing the wettability tendency of tight media samples by spontaneous imbibition tests at elevated pressures. Furthermore, the wettability tendency of four tight media core plugs from the Lower Shaunavon reservoir were evaluated by multiple spontaneous imbibition tests at atmospheric and elevated pressures.

Keywords: Wettability, spontaneous imbibition, elevated pressure, tight media reservoirs.

ii Acknowledgements

First, I thank God for all his blessings. In addition, I want to thank my supervisor, Dr. Apostolos

Kantzas for his continuous support and guidance. I am also grateful with Department of

Chemical and Petroleum Engineering at the University of Calgary, for accepting me in the

Master of Science program. Finally, I want to thank all people from PERM Inc. and specially

Lilly Yu for her collaboration and guidance.

iii Dedication

This thesis is dedicated to God, my son Santiago, my daughter Lucía and my wife Carolina; to my parents, Jairo and Ligia; and to my mother in law, Ruth.

iv Table of Contents

Abstract ...... ii Acknowledgements ...... iii Dedication ...... iv Table of Contents ...... v List of Tables ...... vii List of Figures and Illustrations ...... viii List of Symbols, Abbreviations and Nomenclature ...... xi

1. Chapter One: Introduction ...... 12 2.1. Lower Shaunavon Reservoir ...... 13

2. Chapter Two: Literature Review ...... 16 2.1. Wettability ...... 16 2.1.1. Classification...... 16 2.1.2. Wettability Measurement Methods at Atmospheric Conditions ...... 17 Traditional ...... 17 Modern ...... 22 2.2. Tight Media Wettability Survey ...... 24 2.2.1. Montney ...... 25 2.2.2. Bakken...... 27 2.2.3. Duvernay ...... 30 2.3. Wettability Measurements Methods at High Pressure and High Temperature35 2.3.1. High Temperature...... 35 2.3.2. High Pressure ...... 36 2.3.3. High Temperature and Pressure ...... 38

3. Chapter Three: Methodology ...... 42 3.1. Apparatus Design ...... 42 3.1.1. Equipment...... 43 Sight Glass Cell ...... 44 Cathetometer ...... 45 3.2. Materials ...... 46 3.2.1. Fluids ...... 46 Oil ...... 47 Brine ...... 47 Fluids Properties ...... 47 3.2.2. Rock Samples...... 48 3.3. Experiment Design ...... 50 3.3.1. Spontaneous Imbibition at Elevated Pressures Design ...... 51 Samples Restoration ...... 51 Spontaneous Imbibition at Elevated Pressures ...... 61 3.3.2. Spontaneous Imbibition Tests ...... 67

4. Chapter Four: Results ...... 69 4.1. Berea Sandstone Samples ...... 69

v 4.1.1. Cleaned Samples ...... 69 4.1.2. Restored Samples ...... 70 Atmospheric Pressure Spontaneous Imbibition ...... 71 High Pressure Spontaneous Imbibition ...... 71 4.2. Shaunavon Samples ...... 73 4.2.1. Cleaned Samples ...... 73 4.2.2. Brine Saturated Samples ...... 74 Oil Spontaneous Imbibition ...... 74 4.2.3. Restored Samples ...... 75 Atmospheric Pressure Spontaneous Imbibition ...... 76 High Pressure Spontaneous Imbibition ...... 76 4.3. Wettability Assessment Summary ...... 78

5. Chapter Five: Conclusions and Recommendations ...... 82 5.1. Conclusions ...... 82 5.2. Recommendations ...... 84

References ...... 85

A. Appendix A: Sight Glass Cell Pressure Test ...... 92

B. Appendix B: Sight Glass Cell Calibration ...... 95

C. Appendix C: Vacuum Saturation and Water Injection Procedure...... 98

D. Appendix D: Copyright Permissions ...... 103

vi List of Tables

Table 2-1 Contact angle wettability classification (Anderson, 1986) ...... 18

Table 2-2 Wettability evaluation by Amott test (Anderson, 1986) ...... 20

Table 2-3 Amott-Harvey Index (Anderson, 1986) ...... 21

Table 2-4 Montney wettability survey...... 33

Table 2-5 Bakken wettability survey ...... 34

Table 2-6 Duvernay wettability survey ...... 34

Table 3-1 Oil and brine viscosity ...... 48

Table 3-2 Oil and brine density ...... 48

Table 3-3 Rock samples physical properties ...... 50

Table 4-1 Saturation of Berea sandstone samples ...... 70

Table 4-2 Brine saturation of Shaunavon samples ...... 74

Table 4-3 Saturation of Shaunavon samples ...... 75

Table A-1 Sight glass cell pressure tests ...... 94

Table B-1 Sight glass cell calibration ...... 97

vii List of Figures and Illustrations

Figure 1-1 Lower Shaunavon reservoir map (Schlosser et al., 2015) ...... 14

Figure 1-2 Shaunavon formation stratigraphic column (Fic and Pedersen, 2013) ...... 14

Figure 1-3 Shaunavon formation well log (Modified from Fic and Pedersen, 2013) ...... 15

Figure 2-1 Contact angle (Modified from Anderson, 1986) ...... 18

Figure 2-2 Spontaneous imbibition test ...... 19

Figure 2-3 Areas under the capillary pressure curves ...... 22

Figure 2-4 NMR integrated to Amott-USBM tests for wettability evaluation (Modified from Rios et al., 2015) ...... 24

Figure 2-5 High temperature spontaneous imbibition test ...... 35

Figure 2-6 High pressure spontaneous imbibition test (modified from Chahardowli et al., 2016) ...... 37

Figure 2-7 High pressure and high temperature spontaneous imbibition test (Kyte et al., 1961) ...... 39

Figure 2-8 Steel cell for high pressure and high temperature spontaneous imbibition tests (modified from Ruidiaz et al., 2017) ...... 40

Figure 3-1 Apparatus design for high pressure spontaneous imbibition ...... 44

Figure 3-2 Sight glass cell for high pressure spontaneous imbibition tests ...... 45

Figure 3-3 Cathetometer ...... 46

Figure 3-4 Heptane (0.03 wt% Sudan II)...... 47

Figure 3-5 Lower Shaunavon formation core plugs ...... 49

Figure 3-6 Berea sandstone core plugs...... 49

Figure 3-7 Core cutting machine ...... 50

Figure 3-8 Spontaneous imbibition design for tests at elevated pressures ...... 51

Figure 3-9 Dean Stark apparatus ...... 52

Figure 3-10 Oven ...... 53

Figure 3-11 Brine saturation comparison ...... 54

viii Figure 3-12 Apparatus design for high pressure differential brine saturation ...... 55

Figure 3-13 Brine saturation comparison after high pressure differential saturation ...... 57

Figure 3-14 Oil injection rig ...... 58

Figure 3-15 Leaking test diagram ...... 58

Figure 3-16 Injection system diagram...... 59

Figure 3-17 Shaunavon sample 3P aging in oil ...... 61

Figure 3-18 Example of a Shaunavon sample that was wiped ...... 62

Figure 3-19 Example of a Shaunavon sample that was not wiped ...... 63

Figure 3-20 Early oil production from a Shaunavon sample following Ruidiaz (2015) procedure ...... 64

Figure 3-21 Brine completely covering a Shaunavon sample ...... 65

Figure 3-22 Shaunavon sample after pressurization to 10345 [kPa] ...... 66

Figure 3-23 Spontaneous imbibition tests ...... 68

Figure 4-1 Spontaneous imbibition in cleaned Berea sandstone sample ...... 70

Figure 4-2 Spontaneous imbibition test of sample SST1 at atmospheric pressure ...... 71

Figure 4-3 High pressure spontaneous imbibition test of Berea sandstone sample SST1 ... 72

Figure 4-4 High pressure spontaneous imbibition test of Berea sandstone sample SST2 ... 72

Figure 4-5 Spontaneous imbibition in cleaned Shaunavon samples ...... 73

Figure 4-6 Oil spontaneous imbibition test of Shaunavon sample 3P at atmospheric pressure ...... 75

Figure 4-7 Spontaneous imbibition test of Shaunavon samples 3P and 4P at atmospheric pressure ...... 76

Figure 4-8 High pressure spontaneous imbibition test of Shaunavon sample 3P ...... 77

Figure 4-9 High pressure spontaneous imbibition test of Shaunavon sample 4P ...... 77

Figure 4-10 High pressure spontaneous imbibition test of Shaunavon sample 5P ...... 78

Figure 4-11 High pressure spontaneous imbibition test Shaunavon sample 8P ...... 78

ix Figure 4-12 Wettability assessment summary ...... 81

Figure A-1 Graphite gaskets after Pressure Tests 1, 2 and 3...... 92

Figure A-2 Pressure Test 4 and 5 ...... 93

Figure B-1 Sight glass cell calibration ...... 95

Figure B-2 Sight glass cell leveling ...... 96

Figure C-1 Vacuum saturation equipment ...... 98

Figure C-2 Samples soaking in brine ...... 99

Figure C-3 Leaking test diagram...... 100

Figure C-4 Injection system diagram ...... 100

x List of Symbols, Abbreviations and Nomenclature

Acronyms Definition NMR Nuclear Magnetic Resonance. OOIP Original Oil-in-Place. PEEK Polyether Ether Ketone. SEM Scanning Electron Microscope. TDS Total Dissolved Solids. WCSB Western Canada Sedimentary Basin.

Nomenclature Definition Ai Area under the imbibition capillary pressure curve. Ad Area under the drainage capillary pressure curve. He Helium. HP High pressure. KCl Potassium chloride. NaCl Sodium chloride. N*m Newton meter. Sor Residual oil saturation. Swi Irreducible water saturation. T2 Transverse relaxation time. Vosp Oil volume produced by brine spontaneous imbibition. Vot Total oil volume produced by brine spontaneous imbibition and forced displacement. Vwsp Brine volume produced by brine spontaneous imbibition. Vwt Total brine volume produced by oil spontaneous imbibition and forced displacement.

Greek Symbols Definition δo Displacement-by-oil ratio. δw Displacement-by-water ratio. Θ Contact angle.

1. Chapter One: Introduction

The wettability tendency of rock/oil/water systems is determined by either quantitative indicators such as contact angles, Amott-Harvey index (based on spontaneous and forced imbibition), and

USBM index (based on capillary curves), or through qualitative methods such as spontaneous imbibition and nuclear magnetic resonance (NMR) among others. Regardless the different methodologies that have been developed and used for evaluating the wettability tendency of a rock/oil/water system, there has not been an agreement on a unique methodology to be follow as the most exact wettability indicator, basically due to the difficulty for evaluating the repeatability of the test. However, the most representative values are obtained by using conditions as similar to the reservoir as possible (Anderson, 1986), but it is still challenging to perform tests trying to mimic elevated pressures and temperatures.

Therefore, as a first approach for evaluating the wettability tendency as close as possible to the reservoir conditions, this project aims to develop the apparatus and the methodology for running

spontaneous imbibition tests at elevated pressures, and to evaluate the wettability tendency of tight media core plugs from the Lower Shaunavon reservoir by high pressure spontaneous imbibition tests.

In the first part of the project, the apparatus designed for running spontaneous imbibition tests at elevated pressures is calibrated and pressure tested at 10345 [kPa] and room temperature (21

[°C]). A sight glass cell is used for the high pressure spontaneous imbibition tests, where the sample and fluids can be continuously monitored through the sight glass.

In the second part of the project, tight media core plugs from the Lower Shaunavon reservoir and conventional Berea sandstone samples are restored, where a novel approach for water saturation by high pressure differential is proposed and implemented. Additionally, heptane (0.03 wt%

Sudan II) and brine (2 wt% NaCl) are used as the oil and water saturation fluids.

Finally, in the last part of the project, the wettability tendency of the Lower Shaunavon and

Berea sandstone samples is evaluated by running multiple spontaneous imbibition tests at elevated and atmospheric pressures.

2.1. Lower Shaunavon Reservoir

The Middle Jurassic Shaunavon formation is located in the southwest corner of Saskatchewan,

Canada (Figure 1-1), and it is divided in two different members, the lower and the upper

Shaunavon (Figure 1-2 and Figure 1-3). The Lower Shaunavon consists of a carbonate platform deposited in shallow marine conditions, and the Upper Shaunavon consists of units of siliciclastic sandstones, mudstones and carbonates (Fic and Pedersen, 2013).

The Lower Shaunavon formation is a tight oil reservoir (permeability ranges from 0.2 to 0.5

[mD]) composed of clean limestone and oolitic shoals. Its depth ranges from 1300 [m] to 1600

[m] with a thickness about 20 to 35 [m] (National Energy Board, 2011). The Lower Shaunavon formation presents an average oil API gravity of 23 [°], and an estimate original oil-in-place of

680 million cubic meters with an approximate 10 [%] recovery factor by primary production according to Schlosser (2015).

Figure 1-1 Lower Shaunavon reservoir map (Schlosser et al., 2015)

Figure 1-2 Shaunavon formation stratigraphic column (Fic and Pedersen, 2013)

Figure 1-3 Shaunavon formation well log (Modified from Fic and Pedersen, 2013)

2. Chapter Two: Literature Review

This chapter focuses mainly on providing a review of the wettability of tight formations. First, the definitions of wettability, and the different methodologies used to evaluate the wettability at atmospheric conditions are reviewed. Second, a tight media wettability survey is presented, where the methodologies and results of the wettability tendency are discussed and summarized.

Third, the methodologies for evaluating the wettability at high pressure and high temperature are reviewed.

2.1. Wettability

Wettability was defined by Craig (1971) as “the tendency of one fluid to spread on or to adhere to a solid surface in the presence of other immiscible fluids”. In other words, if the reservoir rock is saturated with water and oil, the wettability would be the affinity of the rock to be in contact with either oil or water (Anderson, 1986).

2.1.1. Classification

The wettability tendency of a rock/oil/water system is classified according the affinity that the rock has with each of the fluids. Therefore, if the rock tendency is for water to be in contact with most of the pore walls, the system is water-wet. On the contrary, if the rock tendency is for oil to be in contact with most of the pore walls, the system is oil-wet. However, if the rock tendency is not strong either for oil or water, then the system is neutral-wet. If the rock has multiple wettability tendencies, the system is fractional-wet (Anderson, 1986). Additionally, the system is

classified as mixed-wet, if the larger pores present an oil-wet tendency while the smaller pores are water-wet (Salathiel, 1973).

2.1.2. Wettability Measurement Methods at Atmospheric Conditions

Regardless the different methodologies that have been developed and used for evaluating the wettability tendency of a rock/oil/water system, there has not been an agreement on a unique methodology to be follow as the most exact wettability indicator, basically due to the difficulty for evaluating the repeatability of the test. Therefore, this section briefly describes the traditional methods that have been used for evaluating the wettability of conventional reservoirs, and additionally some novel techniques recently proposed to analyze the wettability tendency on unconventional tight reservoirs.

Traditional

Contact Angle

Generally, this method is performed by placing a drop of water on a surface (e.g., core plug, pure mineral) immersed in oil. Then, the contact angle (θ) between the surface and the drop is measured through the water drop, as shown in Figure 2-1. However, different modifications of the contact angle test have been developed and is necessary to identify which contact angles are being measured (e.g., an oil drop immersed in water, then the contact angle would be between the surface and the drop measured through the surrounding water).

Figure 2-1 Contact angle (Modified from Anderson, 1986)

As a qualitative method for evaluating the wettability tendency, the contact angles are ranged and grouped for classifying the wettability into water-wet, oil-wet, or neutral-wet. Table 2-1 shows a contact angle wettability classification presented by Anderson (1986).

Table 2-1 Contact angle wettability classification (Anderson, 1986)

Water-Wet Neutral-Wet Oil-Wet Contact Minimum 0° 60 – 75° 105 – 120° Angle Maximum 60 – 75° 105 – 120° 180°

Finally, it is important to highlight that the roughness, the mineral heterogeneity of rock, and the contact angle equilibrium are some of the challenges that the contact angle methodology presents for evaluating the wettability of a rock/oil/water system (Anderson, 1986).

Spontaneous Imbibition

The spontaneous imbibition test is commonly used as a qualitative method for analyzing the wettability tendency of a reservoir sample. Although multiple modifications have been used for running the spontaneous imbibition test, normally oil saturated samples are immersed into an

Amott cell with brine and left soaking until a stable value of oil production volume is achieved, as shown in Figure 2-2 (left). Then, if brine imbibed into the sample, the sample is referred as

water-wet, but if no brine imbibed, it would be referred as oil-wet or neutral-wet. On the other hand, the test can be reversed, and now brine saturated samples are immersed in oil and left soaking until a stable value of brine production volume is achieved, as shown in Figure 2-2

(right). Then, if oil imbibed into the sample, the sample is referred as oil-wet, but if no oil imbibed, it would be referred as water-wet or neutral-wet. Finally, if neither brine nor oil imbibed into the sample, the sample is referred as neutral-wet, but if both fluids, brine and oil, imbibed into the sample, the sample would be referred as fractional-wet or mixed-wet

(Anderson, 1986).

Figure 2-2 Spontaneous imbibition test

Amott Test

The Amott test is used as a quantitative method for analyzing the wettability tendency of reservoir samples. This test is commonly performed in four steps, where the spontaneous imbibition and forced displacement (e.g., centrifuging, flooding) mechanisms are combined.

In the first step, an oil saturated sample is immersed in brine and the oil production volume by spontaneous imbibition is measured (Vosp). In the second step, the sample is exposed to brine forced displacement until reach the residual oil saturation value, and the oil production volume is

measured. Then, the total volume of oil produced by spontaneous imbibition and forced displacement is calculated (Vot). In the third step, the sample at residual oil saturation is immersed in oil and the brine production volume by spontaneous imbibition is measured (Vwsp).

Finally, in the fourth step, the sample is exposed to oil forced displacement until reach the irreducible water saturation value, and the brine production volume is measured. Then, the total volume of brine produced by spontaneous imbibition and forced displacement is calculated (Vwt).

With the four steps completed, the displacement-by-water ratio (δw) and the displacement-by-oil ratio (δo) are calculated, and the wettability tendency of the reservoir sample is classified as shown in Table 2-2 (Anderson, 1986).

푉표푠푝 Eq. 2-1 훿푤 = 푉표푡

푉푤푠푝 Eq. 2-2 훿표 = 푉푤푡

Table 2-2 Wettability evaluation by Amott test (Anderson, 1986)

Water-Wet Neutral-Wet Oil-Wet

δw Positive Zero Zero

δo Zero Zero Positive

Amott-Harvey Index

The Amott-Harvey Index refers just to the displacement-by-water ratio minus the displacement- by-oil ratio. Table 2-3 shows the wettability tendency classification based on the Amott-Harvey

Index (Anderson, 1986).

Eq. 2-3 퐼 = 훿푤 − 훿표

Table 2-3 Amott-Harvey Index (Anderson, 1986)

Oil-Wet Neutral-Wet Water-Wet

I = δw - δo -1.0 ≤ I ≤ -0.3 -0.3 < I < 0.3 0.3 ≤ I ≤ 1.0

USBM Test

The USBM test is a quantitative method for analyzing the wettability tendency of reservoir samples. It is based on the fact that the area under the imbibition or drainage capillary curves

(obtained by forced displacement using a centrifuge) is proportional to the work that one fluid needs to displace the other (Figure 2-3). Therefore, if the area under the imbibition curve (Ai) is smaller than the drainage curve (Ad), the sample is more water-wet, but if the area under the imbibition curve is larger than the drainage curve, the sample is more oil-wet, and if both areas are similar, then the sample is neutral-wet (Anderson, 1986).

Figure 2-3 Areas under the capillary pressure curves

For the quantitative evaluation of the wettability tendency, a USMB wettability index (W) is calculated, as shown in Eq. 2-4. Then, if the USBM wettability index is close to 1, the sample is more water-wet, and if it is close to -1, the sample is more oil-wet, and finally if it is close to 0, the sample is more neutral-wet (Anderson, 1986).

퐴 Eq. 2-4 푊 = log ( 푑) 퐴푖

Modern

Micro Contact Angle

Recently, Deglint et al. (2016) presented a novel idea for evaluating the wettability tendency of reservoir samples at micro and nano scale using the Scanning Electron Microscope (SEM) images and a custom user-guided software to obtain the edge profile of the droplets. They implemented three different methodologies for determining the wettability of tight media samples by measuring the contact angles at micro and nano scale.

• Condensation and Evaporation: Essentially, this method works by measuring the contact

angles in a rock sample, immersed in a vapor chamber, while the surrounding vapor

condenses or liquid evaporates. The main advantage of this method is the possibility of

measuring contact angles in specific mineral surfaces at micro and nano scales. The main

disadvantage is that the method is restricted to just one fluid, distilled water.

• Cryogenic: This method works by analyzing the contact angles at micro and nano scales of a

sample that has been frozen at cryo temperatures. The main advantage of this method is that

it allows the analysis of native and restored samples, however, there is still an unknown

implication of how the cryo temperatures affect the rock-fluid interactions.

• Micro-injection: Essentially, this method works by injecting droplets onto the sample at

micro and nano scales for evaluating the wettability tendency of the rock by measuring the

contact angles produced. The main advantages of this method are the micro and nano

precision for the droplet positioning onto the sample, and the possibility of using different

fluids for the test. Some of the challenges this methodology present are: evaluation of the

wettability at reservoir conditions; testing contact angles into water or oil, not just surrounded

by air; contact angle equilibrium; and roughness, because even the injected droplet is small, it

is still larger than some grains, so it is covering an area with multiple morphologies.

Nuclear Magnetic Resonance (NMR)

During this decade, multiple studies have used the nuclear magnetic resonance tool (NMR) for evaluating the wettability tendency on tight media samples, by analyzing the transverse evaluation times (T2) or T2 distributions. Although some NMR models for wettability evaluation of conventional reservoirs were proposed during the last decade (Fleury and Deflandre, 2003;

Chen et al., 2006), what has been observed for the tight media wettability evaluation is that the

NMR is being used as a qualitative approach.

Additionally, many studies (Karimi et al., 2017; Tinni et al., 2014; Sulucarnain et al., 2012;

Odusina et al., 2011; Rios et al., 2015) have implemented the NMR as a complementary analysis to the traditional wettability measuring methods (e.g., Amott, USBM, and spontaneous imbibition tests), instead of being used as a single methodology for the wettability evaluation.

Typically, the NMR is performed at end steps of the Amott and the USBM tests (Figure 2-4), and the wettability tendency is qualitatively analyzed based on the T2 distributions behaviors.

Figure 2-4 NMR integrated to Amott-USBM tests for wettability evaluation (Modified from

Rios et al., 2015)

2.2. Tight Media Wettability Survey

This section presents a summary of the wettability test methodologies and results (most of them at atmospheric conditions, except of some at elevated temperatures) for three of the most productive Western Canada Sedimentary Basin (WCSB) tight media formations: the Montney,

Bakken, and Duvernay formations.

2.2.1. Montney

General Information

The Montney formation is a conventional and tight-media reservoir located in the WCSB, spreading from the northeast British Columbia to the northwestern Alberta. The Montney lithology is mainly composed by siltstones and its depth ranges from 500 to 4500 [m] with a thickness up to 300 [m] (ERCB/AGS, 2012).

Wettability Survey

Javaheri et al. (2017) evaluated the wettability tendency with reservoir fluids at atmospheric conditions of five native Montney core plugs, using brine-air and oil-air contact angle tests over polished surfaces, and by running co-current spontaneous imbibition tests of oil and brine in twin plugs (one sample for oil and the other for brine), where just the bottom face of the plug is in contact with the imbibing fluid, and the others faces are surrounded by air. They observed that in the oil-air contact angle, the oil drops completely spread over the surface, indicating an oil-wet tendency, but in the brine-air contact angle, the angles range from 66-120 [°], indicating a weak water-wet to neutral-wet tendency. Finally, from the co-current spontaneous imbibition tests they observed that more oil (40-80 [%] of pore volume approx.) than brine (30-40 [%] of pore volume approx.) imbibed, but brine imbibed faster.

Lan et al. (2015) performed the same tests as Javaheri et al. (2017), but instead of using reservoir fluids they used dodecane and synthetic brine (2 wt% KCl). They observed that in the oil-air contact angle test, the oil drops completely spread over the surface. However, in the brine-air contact angle test, the angles range from 35-50 [°], indicating higher affinity to oil than to brine.

Finally, from the co-current spontaneous imbibition tests they observed that more oil (2.4-4.5

[%] of pore volume approx.) imbibed than brine (< 2.4 [%] of pore volume approx.).

Habibi et al. (2016) analyzed the wettability tendency with reservoir fluids at atmospheric conditions of twenty native Montney core plugs, by doing a series of spontaneous imbibition and contact angle tests. First, they ran spontaneous imbibition tests of oil and brine in the native samples (measuring the mass changed with time), and second, they ran spontaneous imbibition tests of oil and brine into the partly saturated plugs, obtained from the first part (measuring the production volumes with time). Additionally, they performed multiple contact angle measurements over polished surfaces: first, brine-air and oil-air contact angles on native samples; second, brine-air and oil-air contact angles on plugs partly saturated, with oil or brine, obtained from the first spontaneous imbibition test; and third, brine-kerosene contact angles on brine saturated plugs. They observed that in the spontaneous imbibition tests in native samples, both oil (40-95 [%] of pore volume approx.) and brine (40-90 [%] of pore volume approx.) imbibed into the sample, indicating a mixed-wet tendency. However, in the spontaneous imbibition tests in partly oil saturated samples, about 25-45 [%] of oil recovery was observed by spontaneous imbibition of brine, but in the partly brine saturated samples, no oil imbibition was observed. On the other hand, they observed that in all the oil contact angle tests, the oil drops completely spread over the surface, indicating an oil-wet tendency. Differently, they observed that brine-air contact angles ranged from 12-61 [°] in native samples, 10-37 [°] in brine saturated samples, and 60-103 [°] in oil saturated samples, indicating that the water-wet tendency increases when samples are aged in brine, and decreases when samples are aged in oil. Finally, the brine-

kerosene contact angles in brine saturated samples range from 30-63 [°], indicating a water-wet tendency.

Deglint et al. (2017) analyzed the wettability tendency of Montney samples (pieces of core plugs) with deionized water by measuring traditional macro contact angles (sessile drop) and by using the condensation and evaporation and micro-injection contact angle methodologies. They observed that macro contact angles ranged from 75-85 [°], indicating a neutral-wet tendency. In contrast, the micro contact angles by condensation and evaporation ranged from 45.3-99.3 [°], and angles by micro-injection ranged from 25.8-70.9 [°], indicating a water-wet to neutral-wet tendency.

In summary, in the spontaneous imbibition tests, both oil and brine imbibe into the sample, indicating a fractional-wet tendency. Similarly, the contact angle experiments showed an affinity to both fluids oil and brine, indicating a fractional-wet tendency. Therefore, it is concluded that the Montney reservoir has a fractional-wet tendency based on this literature survey. An overview of the methodologies and results of each of the papers reviewed in this survey is presented in Table 2-4.

2.2.2. Bakken

General Information

The Bakken tight oil formation is located in the WCSB, at the south of Saskatchewan and

Manitoba provinces. It has a depth ranging from 900 to 2500 [m], with a thickness of approximately 25 [m]. It is usually divided in three units: a lower and upper shale, and a middle member with lithological content varying from calcareous and argillaceous sandstone, dolomitic

and calcareous siltstone, silty lime-mudstone, limestone, and dolostone. The middle unit is considered to be the main reservoir interval (ERCB/AGS, 2012).

Wettability Survey

Wang et al. (2012) evaluated the wettability tendency of native and cleaned core plugs from the

Bakken formation by calculating the Amott-Harvey Index. They used reservoir oil and a synthetic brine (15-30 [%] TDS) as the saturation fluids for the tests. For the native core plugs

(three samples), they observed that the Amott-Harvey indices ranged from -0.358 to 0, indicating an oil- to neutral-wet tendency. On the other hand, for the cleaned core plugs (twelve samples), they observed that the Amott-Harvey indices ranged from -0.81 to 0, indicating that the wettability tendency varied from oil-wet to neutral-wet among the samples.

Luo and Li (2017) evaluated the wettability tendency with reservoir oil and synthetic brine of five cleaned core plugs from the Bakken formation by measuring the oil-brine contact angles, and by determining the USBM wettability index at reservoir temperature (63 [°C]) and atmospheric pressure with a high-speed centrifuge (able to reach up to 2400 [kPa] and 3000

[kPa] for the drainage and imbibition capillary pressure, respectively). For the oil-brine contact angles, the angles ranged from 48.8-60.8 [°] (angles measured through the brine phase), indicating a water-wet tendency. Similarly, a water-wet tendency was suggested by the USBM tests, with indices ranging from 0.56 to 1.15.

Alvarez and Schechter (2016) analyzed the wettability tendency of two restored core plugs from the Bakken formation by measuring oil-brine contact angles and running water spontaneous imbibition tests, both experiments at elevated temperature (82 [°C]) and atmospheric pressure.

For the oil-brine contact angles, the angles were 121 and 122 [°] (angles measured through the

brine phase), indicating an oil-wet to neutral wet tendency. On the other hand, the spontaneous imbibition tests, performed by using a temperature resistant glass Amott cell, showed an oil recovery of 15.9 and 8.4 [% OOIP], indicating a “poor performance” in oil recovering according the authors.

Karimi and Kazemi (2015) evaluated the wettability tendency of one cleaned core plug from the

Bakken formation using the USBM method with reservoir fluids at atmospheric conditions. At the end of the test, the USBM index was 0.3, indicating a water-wet tendency. However, they stated that the result could be affected by the cleaning process performed on the sample.

Deglint et al. (2016) analyzed the wettability tendency of Bakken samples (pieces of core plugs) using the condensation/evaporation and cryogenic micro contact angle methodologies. The micro contact angles from the condensation and evaporation method ranged from 68-95 [°], indicating a water-wet to neutral-wet tendency. Similarly, using reservoir oil and synthetic brine, the oil- brine contact angles by the cryogenic method ranged from 109-130 [°] (measured through the oil phase) or 71-50 [°] (measured through the brine phase), indicating a water-wet to neutral-wet tendency.

In summary, for the Bakken reservoir is observed how the sample state (native, cleaned, or restored) affected the wettability tendency: the wettability was oil-wet to neutral-wet when native or restored samples were used, but more water-wet when cleaned samples were used, probably because adsorbed organic matter and polar compounds to the rock surface were removed when cleaning the samples (Anderson, 1986). However, the results were not completely consistent, because for example, in the tests performed by Wang et al. (2012), the wettability of the cleaned

samples varied from oil- to neutral-wet. An overview of the methodologies and results of each of the papers reviewed in this survey is presented in Table 2-5.

2.2.3. Duvernay

General Information

The Duvernay shale formation is located in the WCSB, in central Alberta covering an area of

130000 [km2], or 20 [%] of the area of Alberta. Due to its large area, the Duvernay productive zones are divided into three assessment areas: Kaybob in the north, Edson-Willesden Green in the central part, and Innisfail in the south. The reservoir depth ranges from 1700 to 5000 [m], with about 2-99 [m] in thickness. It is typically divided in three members: A shale, B Carbonate, and C shale. The A and C members are considered to be the main reservoirs intervals (AER,

2016).

Wettability Survey

Begum et al. (2017) analyzed the wettability tendency of the Duvernay reservoir by running contact angle and spontaneous imbibition tests at atmospheric conditions with reservoir fluids and not well-preserved core plugs (some were dried). For the undried samples, both oil (40-90

[%] of pore volume approx.) and brine (20 [%] of pore volume approx.) imbibed into the samples. However, higher volumes of oil imbibed, indicating higher wetting affinity to oil than to water. Similarly, when measuring the oil-air contact angle, the oil drops completely spread over the surface, but when measuring the brine-air contact angle, the angles ranged from 47-89

[°], indicating higher wetting affinity to oil than to water. A higher wetting affinity to oil was also observed for the brine-kerosene contact angle (168 [°]), and the oil-brine contact angle (93

[°]). On the other hand, when measuring the oil-air contact angles of the dried samples, the oil drops completely spread over the surface indicating an oil-wet tendency; but when measuring the brine-air contact angle, the angles ranged from 33-41 [°] (lower angles in comparison with not dried samples), indicating a water-wet tendency.

Yassin et al. (2016) analyzed the wettability tendency of nine core plugs (not fully preserved) from the Duvernay reservoir using spontaneous imbibition and contact angle tests at atmospheric conditions with reservoir oil and brine for the saturation fluids. For the spontaneous imbibition tests (twin plugs), they observed that more oil (40-100 [%] of pore volume approx.) than brine

(10-30 [%] of pore volume approx.) imbibed into the samples, indicating a higher wetting affinity to oil than to water. Similarly, an oil-wet tendency was observed with the contact angle tests, with oil drops completely spreading over the surface for the oil-air contact angle test, and with angles ranging from 65-103 [°] for the brine-air contact angle test.

Gupta et al. (2017) evaluated the wettability tendency of unpreserved and dried core plugs from the Duvernay reservoir using spontaneous imbibition tests at atmospheric conditions with kerosene and deionized water. They observed that about 0.4 [%] of normalized mass of kerosene imbibed and about 0.4-0.8 [%] normalized mass of water imbibed into the samples (normalized mass is the ratio of imbibed mass to the mass of dry rock sample), with higher imbibition rates for water than for kerosene.

In summary, for the Duvernay reservoir, both oil and brine imbibe into the sample in the spontaneous imbibition tests, indicating a fractional-wet tendency. Similarly, the contact angle experiments show higher wetting affinity to oil than to brine. Therefore, the Duvernay reservoir

has a fractional-wet tendency based on this literature survey. An overview of the methodologies and results of each of the papers reviewed in this survey is presented in Table 2-6.

Table 2-4 Montney wettability survey

Fluids Author Year Sample Type Sample State Test Average Test Result Wettability Evaluation Oil Brine Oil-air contact angle 0 [°] Fully oil-wet Crude oil Produced brine Brine-air contact angle 66-120 [°] Partially water-wet A. Javaheri et al. 2017 Core plug Native Density = 0.8007 [g/cc] Density = 1.101 [g/cc] Oil: 40-80 [%] of pore volume More oil than brine imbibed, but brine Viscosity = 1.87 [cP] Viscosity = 1.18 [cP] Co-current sp. imbibition Brine: 30-40 [%] of pore volume imbibed faster Oil-air contact angle 0 [°] Affinity to oil higher than to water Synthetic brine Brine-air contact angle 35 - 50 [°] Q. Lan et al. 2015 Core plug Native Dodecane (2 wt% KCl) Oil: 2.4-4.5 [%] of pore volume Co-current sp. imbibition Mixed-wet Brine: < 2.4 [%] of pore volume Oil: 40-95 [%] of pore volume Sp. imbibition in native samples Mixed-wet Brine: 40-90 [%] of pore volume Oil-air contact angle in native 0 [°] samples Affinity to oil higher than to water Brine-air contact angle in native 12-61 [°] samples Oil sp. imbibition in brine saturated Not oil imbibition observed Not oil imbibition observed samples Crude oil Brine sp. imbibition in oil saturated Produced brine 25-45 [%] oil recovery 25-45 [%] oil recovery A. Habibi et al. 2016 Core plug Native Density = 0.834 [g/cc] samples Density = 1.1 [g/cc] Viscosity = 3.55 [cP] Oil-air contact angle in brine 0 [°] Affinity to oil higher than to water, but saturated samples aging in water increases the water-wet Brine-air contact angle in brine 10-37 [°] tendency saturated samples Oil-air contact angle in oil saturated 0 [°] Affinity to oil higher than to water, but samples aging in oil decreases the water-wet Brine-air contact angle in oil 60-103 [°] tendency saturated samples Brine-kerosene contact angle in 30-63 [°] Water-wet brine saturated samples Macro contact angle 75-85 [°] Mixed-wet Micro contact angle 45.3-99.3 [°] Water-wet to Mixed-wet H. J. Deglint et al. 2017 Pieces of core plugs Not specified - Deionized water Condensation & evaporation Micro contact angle 25.8-70.9 [°] Water-wet to Mixed-wet Micro-injection

Table 2-5 Bakken wettability survey

Fluids Author Year Sample Type Sample State Test Average Test Result Wettability Evaluation Oil Brine Native Crude oil (-0.358) to 0 Oil- and Neutral-wet D. Wang. et al. 2012 Core plug Synthetic brine Amott-Harvey Index Cleaned Density = 0.777 [g/cc] (-0.81) to 0 Oil- and Neutral-wet P. Luo and Crude oil USBM 0.56-1.15 Water-wet 2017 Core plug Cleaned Synthetic Brine S. Li Density = 0.805 [g/cc] Oil-brine contact angle 48.8-60.8 [°] Water-wet Oil-brine contact angle 121° and 122° Oil-wet to Neutral-wet J.O. Alvarez and Crude oil Synthetic brine 2016 Core plug Restored 15.9 and 8.4 [% OOIP] Oil D.S. Schechter Density = 0.7936 [g/cc] (4 wt% KI) Spontaneous imbibition Poor performance in recovering oil recovery Crude oil Produced brine S. karimi and 2015 Core plug Cleaned Density = 0.824 [g/cc] Density = 1.117 [g/cc] USBM 0.3 Water-wet H. Kazemi Viscosity = 2.46 [cP] Viscosity = 1.1 [cP] Micro contact angle - Deionized water 68-95 [°] Mixed-wet Condensation & evaporation H. J. Deglint et al. 2016 Pieces of core plugs Not specified Micro contact angle Crude oil Synthetic brine 50-71 [°] - Cryogenic (Oil-brine contact angle)

Table 2-6 Duvernay wettability survey

Fluids Author Year Sample Type Sample State Test Average Test Result Wettability Evaluation Oil Brine Oil: 40-90 [%] of pore volume Spontaneous imbibition Higher wetting affinity to oil than water Brine: 20 [%] of pore volume Not well- Oil-air contact angle 0 [°] Higher wetting affinity to oil than water preserved Crude oil Produced Brine Brine-air contact angle 47-89 [°] M. Begum et al. 2017 Core plug Density = 0.8 [g/cc] Density = 1.09 [g/cc] Brine-kerosene contanct angle 168 [°] Higher wetting affinity to oil than water Viscosity = 2.97 [cP] Viscosity = 1.38 [cP] Oil-brine contact angle 93 [°] Oil-air contact angle 0 [°] Oil-wet Dried Lower contact angle when samples are Brine-air contact angle 33-41 [°] dried Produced Brine Oil: 40-100 [%] of pore volume Crude oil Avg. Density = 1.09 Spontaneous imbibition Higher wetting affinity to oil than water Not well- Brine: 10-30 [%] of pore volume M. R. Yassin et al. 2016 Core plug Avg. Density = 0.76 [g/cc] [g/cc] preserved Avg. Viscosity = 1.5 [cP] Avg. Viscosity = 1.55 Oil-air contact angle 0 [°] Oil-wet [cP] Brine-air contact angle 65-103 [°] Kerosene 0.4 [%] normalized mass A. Gupta 2017 Core plug Dried Kerosene Deionized water Spontaneous imbibition Water: 0.4-0.8 [%] normalized mass 34

2.3. Wettability Measurements Methods at High Pressure and High Temperature

This section presents some of the methodologies and equipment found in the literature for running wettability tests at high pressure and high temperature. Additionally, some of the advantages and challenges observed in each of the apparatus are pointed.

2.3.1. High Temperature

Al Bahlani and Babadagli (2008) performed spontaneous imbibition tests at high temperatures

(90 [°C]) by placing regular glass imbibition cells into an oven for temperature control (Figure

2-5).

Figure 2-5 High temperature spontaneous imbibition test

Advantages:

• Elevated temperatures are considered.

• Easy set up.

• Regular materials.

• Production volumes are directly measured through the graded glass tube.

• Multiple samples and fluids configurations available.

• Spontaneous imbibition process can be visually monitored through the glass cell.

Challenges:

• Temperatures higher than 90 [°C] are not possible with water at atmospheric pressure.

• Tests where the reservoir pressure is also considered.

• Quantify the volume of oil production droplets stuck at the sample and cell walls.

2.3.2. High Pressure

Chahardowli et al. (2016) designed a modified Amott cell for running spontaneous imbibition tests at elevated pressure (maximum 1000 [kPa]) and a constant temperature of 25 [°C]. The modified Amott cell is principally composed of a bottom cell made out of PEEK, where the sample is placed, and a top glass graded tube for quantifying the production volumes (Figure

2-6). For pressurizing the system, nitrogen is injected first through the top of the cell, where a back pressure regulator is placed for pressure control, then the imbibition fluids are injected through the bottom cap of the cell by a Quizix pump. Additionally, they installed a camera system for monitoring the production volumes through the graded tube.

Figure 2-6 High pressure spontaneous imbibition test (modified from Chahardowli et al.,

2016)

Advantages:

• Elevated pressures are considered.

• Production volumes are directly measured and recorded through the graded glass tube at high

pressure.

• Multiple samples and fluids configurations available.

Challenges:

• Pressures higher than 1000 [kPa] are not possible due to maximum operation conditions set

up for the design.

• Temperatures higher than 25 [°C].

• Quantify the volume of oil production droplets stuck at the sample and cell walls.

• Imbibition process cannot be visually monitored through the PEEK cell. Visual monitoring is

useful in order to asses what is happening with the saturated sample during the pressure up

step, during the imbibition fluids injection step, and during the whole imbibition process.

2.3.3. High Temperature and Pressure

Kyte et al. (1961) performed spontaneous imbibition tests at high temperature (71-97 [°C]) and high pressure (17900-20100 [kPa]), trying to mimic the reservoir conditions of the samples they were testing. The experimental setup is shown in Figure 2-7. The steps followed to perform the tests are: 1) preserved samples are first centrifuged and then placed in a stainless-steel vessel, which works as the imbibition cell; 2) the cell is vacuumed; 3) oil is injected into the cell at pressures above the bubble point; 3) brine is injected into the cell at reservoir pressure (also used as pressure controller); 4) the system is heated up to reservoir temperature by using an air bath;

5) the produce oil volume is constantly flushed out through the top of the cell for quantifying purposes; 6) the system is pressured down gradually and the oil production due to pressure reduction is recorded.

Figure 2-7 High pressure and high temperature spontaneous imbibition test (Kyte et al.,

1961)

Advantages:

• High temperature and high pressure are considered.

• Multiple samples and fluids configurations available.

Challenges:

• Imbibition process cannot be visually monitored through the stainless-steel cell. Visual

monitoring is useful in order to asses what is happening with the saturated sample during the

brine injection step for controlling the pressure, when flushing the oil out of the cell, and

during the whole imbibition process.

• Oil production by spontaneous imbibition is not monitored at reservoir conditions.

• In the case of testing tight samples, handling and measuring the small amounts of oil

production could be difficult.

Ruidiaz (2015) built a steel cell, very similar to a regular glass Amott cell, but made out of steel for running spontaneous imbibition tests at high temperatures and pressures. The cell maximum operation pressure is 34400 [kPa], but it has been tested up to 17200 [kPa] at 100 [°C] so far.

Additionally, an interesting feature of the cell is the option to measure the production volumes at high pressure and temperature through the graded sight glass at the top of the cell (Figure 2-8)

Figure 2-8 Steel cell for high pressure and high temperature spontaneous imbibition tests

(modified from Ruidiaz et al., 2017)

The procedure followed by Ruidiaz (2015) for running spontaneous imbibition tests at high pressure and high temperature is as follows: 1) the test fluids (brine and oil) are heated up to test temperature; 2) the oil saturated core plug is removed from the aging cup, and the oil remaining in the plug walls is wiped off; 3) the sample is put into the cell over glass beads (10 [mm]) to avoid the contact between the sample and the cell bottom; 4) nitrogen is injected for about 30 seconds through the bottom line for removing the air inside the cell through the opened top valve; 5) the top valve is closed and the cell is pressured up to 10345 [kPa]; 6) the cell is placed 40

into and oven at 64 [°C]; 7) brine is injected through the bottom line until reach up the cell pressure to 13800 [kPa], and simultaneously, the top valve is opened and closed to bleed off nitrogen manually until the brine level is visible in the sight glass; 8) oil production by spontaneous imbibition is monitored through the sight glass.

Advantages:

• High temperature and high pressure are considered.

• Production volumes are directly measured and recorded through sight glass at high pressure

and temperature.

• Multiple samples and fluids configurations available.

Challenges:

• Imbibition process cannot be visually monitored through the steel cell. Visual monitoring is

useful in order to asses what is happening with the saturated sample during the nitrogen

injection, brine injection, nitrogen bleed off steps, and during the whole imbibition process.

• Quantify the volume of oil production droplets stuck at the sample and cell walls.

3. Chapter Three: Methodology

This chapter is intended to describe the methodology followed in this thesis for evaluating the wettability of tight rock formations by spontaneous imbibition tests at elevated pressures. First, a description of the apparatus designed for running the high pressure spontaneous imbibition tests is presented. Second, the fluids and rock samples properties are shown. Third, the final experimental design is described, including the procedures followed, the tests performed, and some of the challenges observed during the tests.

3.1. Apparatus Design

The wettability evaluation of tight media reservoirs is challenging, due to their low porosity and permeability, and also due to their mineralogical heterogeneity. Additionally, wettability measurements are affected by multiple factors (core preservation state, fluid properties, temperature and pressure). The most representative values are obtained by using conditions as similar to the reservoir as possible (Anderson, 1986). The spontaneous imbibition apparatus designed for this project aims to overcome three of these challenges: permeability, porosity, and measurement at reservoir conditions.

The first challenge is the low permeability of the samples that leads to late stabilization times in spontaneous imbibition tests. To tackle this challenge a sight glass cell is used (Figure 3-2), in which the imbibition process can be constantly monitored by direct observation of the sample and production volumes, and likewise determine the end of the test. The second challenge is the low porosity of the samples that leads to small production volumes in spontaneous imbibition

tests. To tackle this challenge, a cathetometer (Figure 3-3) is used to quantify the production volumes more precisely. The third challenge is to evaluate the wettability as closely as possible to the reservoir conditions. To do so, a sight glass cell was designed for working at high pressures and high temperatures.

In comparison to the existing methodologies and apparatus for wettability evaluation at high pressure and high temperature (Section 2.3), most of the challenges observed on these are overcome by the spontaneous imbibition apparatus designed for this project:

• Elevated pressures (10345 [kPa]) are considered.

• Production volumes are directly measured and recorded through sight glass at high pressure.

• The imbibition process (sample and production volumes) can be visually monitored through

the sight glass. Visual monitoring is useful in order to asses what is happening with the

saturated sample during the whole imbibition process.

• Oil production droplets stuck at the sample and cell walls can be identified by visual

monitoring through the sight glass.

3.1.1. Equipment

The equipment implemented for running the high pressure spontaneous imbibition test consists of a sight glass cell in which the sample is placed and a cathetometer, used to measure the fluid levels in the cell.

Figure 3-1 shows the apparatus design and components implemented for running the high pressure spontaneous imbibition experiment.

Figure 3-1 Apparatus design for high pressure spontaneous imbibition

Sight Glass Cell

The sight glass cell is the main component of the apparatus for running the high pressure spontaneous imbibition tests. It is made out of stainless steel and its dimensions are 13.97 [cm] height, 10.16 [cm] length, and 10.47 [cm] width, with a total inner volume capacity of approximately 65.2 [cm3] (cylindrical chamber of 2.54 [cm] diameter). In Figure 3-2, the front view of the cell is presented, and the sight glass is also observed. This sight glass is a tempered borosilicate glass (1.75 [cm] thick) suitable high pressure and high temperatures; the exact limit conditions vary according the glass size, shields and gaskets used. For this work, no shields are used, and the gasket used is a reinforced graphite gasket. The cell maximum working pressure is

34500 [kPa] and the maximum working temperature is 65 [°C] (limited by the sight glass).

However, these rating are for brand new equipment. Pressure tests with water and nitrogen were 44

done and the maximum working pressure was set at 10345 [kPa] with a safety margin of 3450

[kPa] at room temperature (21 [°C]). A detailed description of the sight glass cell pressure test is presented in Appendix A.

Figure 3-2 Sight glass cell for high pressure spontaneous imbibition tests

Cathetometer

The optical tool used for measuring the fluid production by spontaneous imbibition through the sight glass is a cathetometer (model M912, Gaertner Scientific Corp., Chicago, IL), as shown in

Figure 3-3, with a Vernier scale that can measure vertical positions with an accuracy of 0.001

[cm]. Since the cathetometer reads length, it was necessary to convert length to volume by calibrating the sight glass cell. The calibration result is that 0.02 [cm] equals to 0.1 [ml]. A detailed description of the sight glass cell calibration is presented in Appendix B.

Figure 3-3 Cathetometer

3.2. Materials

Since this project is a first approach of this type of spontaneous imbibition tests at elevated pressures, “simple materials” were used intentionally as a reference point for simplifying the understanding of the project. “Simple materials” means that neither native samples nor reservoir fluids were used for the experiments.

3.2.1. Fluids

Heptane (0.03 wt% Sudan II) and brine (2 wt% NaCl) were used as the oil and water saturation fluids respectively, for the experiments performed in this thesis. 46

Oil

Heptane (non-polar hydrocarbon) was selected as the oil for running the spontaneous imbibition tests in this thesis. Since the pure heptane is colorless, it is difficult to differentiate between oil and water; therefore, the heptane was dyed to red-orange color by using Sudan II dye at a low concentration of 0.03 wt%, as shown in Figure 3-4. Hofmann et. al. (2006) used Sudan II to dye a poly(dimethylsiloxane) (PDMS) and concluded that the wettability property was seemingly unaffected. Therefore, no wettability effects are assumed by using the Sudan II to dye the heptane.

Figure 3-4 Heptane (0.03 wt% Sudan II)

Brine

Sodium chloride (NaCl) brine with a concentration of 2 wt% NaCl was selected as the water saturation fluid.

Fluids Properties

Viscosity

Oil and brine viscosity were measured at room temperature by using a Brookfield Rheometer

(LVDV-III) with the cone spindle CPA-40Z. The equipment has been precalibrated using

Newtonian fluids by the manufacturer or the service provider in Canada, and its viscosity reading ranges from 0.1 to 3000 [cP]. Table 3-1 shows the average viscosities (with two significant figures) of oil and brine after five readings for each fluid.

Table 3-1 Oil and brine viscosity

Oil Viscosity [cP] Brine Viscosity [cP] Temperature [°C] 0.48 1.15 21

Density

Oil and brine density were measured at room temperature by using an Anton Paar (DMA 4100) digital density meter. The equipment was calibrated using air (0.0012 [gr/cc] at 21 [°C]). Table

3-2 shows the average densities (with four significant figures) of oil and brine after two readings for each fluid.

Table 3-2 Oil and brine density

Oil Density [gr/cc] Brine Density [gr/cc] Temperature [°C] 0.6828 1.0120 21

3.2.2. Rock Samples

Two sets of samples were selected for evaluating the wettability tendency by running spontaneous imbibition tests at elevated pressures. The first and principal study set is composed of four tight media core plugs from the Lower Shaunavon formation (Figure 3-5). On the other hand, the second set, intended as a reference, is composed of two conventional Berea sandstone core plugs (Figure 3-6).

Figure 3-5 Lower Shaunavon formation core plugs

Figure 3-6 Berea sandstone core plugs

Since the Lower Shaunavon is a tight media reservoir, its permeability is very low in comparison to the conventional samples, with gas permeability ranging from 0.106 to 0.205 [mD] for the

Shaunavon samples, and about to 1500 [mD] for the Berea sandstone samples. The rock samples physical properties (dimensions, average bulk volume, helium pore volume, porosity and permeability) are presented in the Table 3-3.

Since the initial diameter of all the plugs were larger than the one required for fitting in the sight glass cell (less than 2.54 [cm]), it was necessary to cut the samples into smaller plugs by using a water cutting machine (samples were not perfectly cylindrical after cutting), as shown in Figure

3-7.

Table 3-3 Rock samples physical properties

He Sample Diameter Length Avg. Bulk He PV Kg Formation Porosity ID [cm] [cm] Volume [cc] [cc] [mD] [%] 3P 2.52 4.85 24.1 4.77 19.80 0.205 4P 2.50 5.08 24.8 4.49 18.10 0.123 Shaunavon 5P 2.50 2.23 11.0 2.00 18.20 0.139 8P 2.52 4.54 22.6 2.89 12.80 0.106 Berea SST1 2.50 3.20 15.7 3.56 22.65 1520 Sandstone SST2 2.50 3.10 15.2 3.68 24.20 1509

Figure 3-7 Core cutting machine

3.3. Experiment Design

This section presents the methodology followed for running spontaneous imbibition tests at elevated pressures, describing how the samples are restored and the test procedure. Additionally,

the organigram of the experiments performed in this thesis is presented, showing the samples used for each test, the samples state, and the tests performed.

3.3.1. Spontaneous Imbibition at Elevated Pressures Design

The spontaneous imbibition test at elevated pressures is essentially composed of two parts, the sample restoration, and the imbibition test (Figure 3-8). In the first part, the complete process of the core plugs restoration is described, where a novel procedure to initially brine saturate the samples is presented. In the second part, the spontaneous imbibition test at elevated pressure is described step by step, presenting the sample conditioning prior the test, the pressurization methodology to start the test and the pressure depletion methodology to end the test.

Figure 3-8 Spontaneous imbibition design for tests at elevated pressures

Samples Restoration

Only non-native state samples (both sets of samples were used previously for routine core analysis) were available for this project, meaning that the original wettability of the samples was 51

already modified. Therefore, to obtain the best possible wettability evaluation, the Shaunavon and Berea sandstone samples were restored following the next procedure: samples were first cleaned, then water saturated, oil saturated, and finally aged in heptane to complete the restoration process.

Cleaning

Cleaning the samples is the first step in the restoration process. To remove all the compounds from the surface of the rock, the Shaunavon samples and Berea sandstone samples were placed in a Dean Stark extraction equipment (Figure 3-9) with toluene for about 72 and 24 [hr] respectively. Then, the samples were removed from the Dean Stark equipment and left in ventilation inside a fume hood for 24 [hr]. Finally, the samples were dried in an oven at 100 [°C] for about 24 [hr] (Figure 3-10).

Figure 3-9 Dean Stark apparatus 52

Figure 3-10 Oven

High Pressure Differential Brine Saturation

After the samples were cleaned and dried, the next step in the restoration process is the water saturation, which is normally performed by first vacuum saturation, and then water injection. The vacuum saturation and water injection were performed following the procedure in Appendix C.

However, after followed this process to water saturate the samples, it was observed that the

Shaunavon samples were not fully saturated, and that some air was left inside the samples.

Figure 3-11 presents a graph where significant differences are observed between a reference helium pore volume and the pore volumes obtained after the vacuum saturation and the water injection. Water pore volumes were obtained measuring the sample’s weight before and after the water saturation (gravimetric analysis).

Figure 3-11 Brine saturation comparison

The helium pore volume was assumed to be the 100 [%] saturation condition. The average water saturation after the vacuum saturation was calculated to be 18.6 [%], meaning that just the 18.6

[%] of the pore volume was filled with water, and that the other 81.4 [%] was filled with air.

Even though the average water saturation increased to 82.5 [%] after the water injection, there was still 17.5 [%] of the pore volume filled with air (probably because water follows preferential pathways and leaves some pores empty). Therefore, to eliminate the air, a novel approach to water saturate the tight samples was developed.

The new approach to saturate the tight samples is based on the observation that due to sample’s low permeability, a vacuum pressure of -100 [kPa] is not enough to saturate the whole sample.

Therefore, a greater differential pressure is required to fully saturate the tight samples. The

higher pressure differential is achieved using the apparatus for running the high pressure spontaneous imbibition tests (Figure 3-12).

Figure 3-12 Apparatus design for high pressure differential brine saturation

The high pressure differential water saturation is performed with the following procedure:

• A dried sample is placed inside the sight glass cell.

• Valves 6, 7, and 8 are opened.

• The injection pump is turned on, and brine is pumped until it exits through Valve 2.

• The injection pump is turned off.

• Valve 3 and 4 are opened.

• The vacuum pump is turned on, and the system in between Valves 2 and 5 is vacuumed for

15 [min]. 55

• The injection pump is turned on and Valve 2 is opened.

• Brine is injected under vacuum until it completely covers the sample.

• Valve 2 is closed and the injection pump is turned off.

• The system is vacuumed for extra 20 [min].

• Valve 4 is closed and the vacuum pump is turned off and disconnected.

• Valve 5 is opened and the system is pressurized to 6900 [kPa] with nitrogen.

• Valve 5 is closed.

• Valve 4 is opened very quickly to bleed off the nitrogen and decreased the system pressure

(6900 [kPa]) to the atmospheric pressure. Simultaneously, the air initially saturating the

sample is enhanced to come out (by density differences), creating a pressure gradient (from

outside to inside the sample) that enhances the surrounding water to flow in and saturates the

sample.

• The vacuum pump is connected again and the system in between Valves 2 and 5 is vacuumed

for 15 [min].

• Valve 4 is closed and the vacuum pump is turned off and disconnected.

• Steps 12 to 16 are repeated. The cycle of high pressure differential saturation is repeated in

case some air is left inside the sample.

• The sample is removed from the sight glass cell and weighed.

After following the high pressure differential process to saturate the samples with brine, it was observed that the Shaunavon samples were now fully saturated. Figure 3-13 shows how the pore volumes after the high pressure differential process almost replicate the helium references 56

values. The average water saturation after the high pressure differential process reached 98.4

[%], as 100% replication of the helium pore volume was not expected because the very small molecular size of the helium atom in comparison to the water molecule.

Figure 3-13 Brine saturation comparison after high pressure differential saturation

This methodology of water saturation by high pressure differential process presents some advantages and disadvantages over the traditional vacuum saturation and water injection methods. The main two advantages of this method are that samples are fully brine saturated with a 98.4 [%] of saturation in comparison to 82.5 [%] and 18.6 [%] for water injection and vacuum saturation respectively; and that about 1.5 [hr] are required to perform the whole test for one sample, instead of about 24 [hr] and 168 [hr] for water injection and vacuum saturation respectively. The main disadvantage of this method is that only samples of less than 2.54 [cm] in diameter fit inside the sight glass cell.

Oil Injection

After the samples were water saturated, the next step in the restoration process is the oil saturation (Figure 3-14). The samples are oil saturated with the following oil injection procedure, which is composed of two parts, the leak test and the oil injection.

Figure 3-14 Oil injection rig

The leak test is performed prior the oil injection and aims to validate there is no leaking from the overburden to the sample. The leak test procedure followed is presented next:

1. The sample is placed inside the rubber sleeve and then into the core holder. Figure 3-15

shows the diagram for the leaking test.

Figure 3-15 Leaking test diagram 58

2. All valves are opened.

3. The overburden pump is set to 6900 [kPa] using the constant pressure mode and turned on.

4. If no water is observed coming out from the injection or production lines (no leaking), then

the overburden pressure is increased to 17200 [kPa].

5. If no water is observed coming out from the injection or production lines (no leaking), then

the other parts of the injection system are connected, as observed in Figure 3-16.

Figure 3-16 Injection system diagram

After the leak test is performed, with no leaks, the next step is the oil injection and the procedure is given below:

1. Valves 1, 3, 5, 6, 7, and 8 are opened.

2. The injection pump is turned on until see oil exits Valve 7.

3. Valve 6 is closed. 59

4. The injection pump is turned off.

5. Valve 7 is closed.

6. The production line of the core holder is closed with a blind bolt.

7. Valves 7 and 9 are opened.

8. The vacuum pump is turned on and lines upstream Valve 6 are vacuumed.

9. The vacuum pump is turned off and Valve 7 is closed.

10. The injection pump is set up at 690 [kPa] in the constant pressure mode with maximum

pressure limit of 13800 [kPa].

11. The injection pump is turned on.

12. Valve 6 is opened.

13. When the injection pump reaches the 690 [kPa], the set-up is switched to constant flow rate

mode with a flow rate of 1 [ml/hr].

14. After 30 [min], the blind bolt in the production line is removed and a plastic hose to the

production bottle is connected.

15. The sample is oil flooded with a flow rate of 1 [ml/hr] with 17200 [kPa] of overburden

pressure for about 24 [hr] (after oil breakthrough no more water displacement was observed).

The volume of water displaced is recorded for calculating the oil saturation.

16. The overburden pressure is released and the overburden pump is turned off.

17. Valves 9 and 10 are closed.

18. The injection pump is turned off.

19. Valves 3, 5 and 6 are closed.

20. The core holder is disconnected.

21. The sample is removed from the rubber sleeve and weighed.

Sample restoration process was repeated twice for most of the samples. Berea sandstone and

Shaunavon samples saturations are presented in Table 4-1 and Table 4-3 respectively.

Aging

Finally, after the samples were oil saturated, the samples were left aging in oil for about 120 [hr], as shown in Figure 3-17. While aging the restored samples in oil, implicitly oil spontaneous imbibition tests at atmospheric conditions were performed. No brine production was observed in either the Shaunavon samples or the Berea sandstone samples (samples weight before and after aging were the same).

Figure 3-17 Shaunavon sample 3P aging in oil

Spontaneous Imbibition at Elevated Pressures

After completing the restoration process for the Shaunavon and Berea sandstone samples, the spontaneous imbibition tests at elevated pressures were performed. The spontaneous imbibition test at elevated pressure consists of three steps: sample conditioning prior the test, the pressurization step to begin the test, and the pressure depletion step to end the test. 61

Sample Conditioning

Before samples are placed into the sight glass cell to start the test, the samples are taken out from the aging vessels and weighed for mass balance purposes. Before weighing the samples, they are usually wiped to remove some oil remaining in the surfaces of the sample. However, when samples are wiped, some air can get into the sample, and consequently the spontaneous imbibition tests would be between air, oil and water, instead of just oil and water, as shown in

Figure 3-18, where air coming out from a sample that was previously wiped is observed from the beginning of the spontaneous imbibition test.

Figure 3-18 Example of a Shaunavon sample that was wiped

Therefore, as a preventing measure, samples were not wiped after being removed from the aging vessel. However, this action does not mean that no superficial air would be found during the spontaneous imbibition tests, but at least less air is observed (Figure 3-19) and can be assumed to be negligible.

Figure 3-19 Example of a Shaunavon sample that was not wiped

Pressurization

The pressurization step is considered the beginning of the spontaneous imbibition test at elevated pressures. As a preliminary approach, the methodology followed to pressure up the system was similar to the one performed by Ruidiaz (2015), where the sample was first placed in the cell, then nitrogen was injected to the system to pressurize the cell up to 9650 [kPa] and finally, brine was injected until reach up the cell pressure to 10345 [kPa]. Simultaneously the top valve was opened and closed as necessary to bleed off nitrogen manually until reach the brine level above the top of the sample. However, when following this methodology some unexpected early oil production was observed, meaning that just when the brine level is above the top of the sample

(time zero of the spontaneous imbibition test), oil production had already recovered (Figure

3-20).

Figure 3-20 Early oil production from a Shaunavon sample following Ruidiaz (2015) procedure

Therefore, to avoid oil production other than by spontaneous imbibition, the pressurization methodology was modified to increase the pressure of the system with nitrogen after completely covering the sample with brine. In this way the sample is not exposed directly to nitrogen when pressuring up the system, and also is not exposed to differential pressures when opening and closing the top valve to reach the brine level above the top of the sample. A detailed procedure of the modified pressurization methodology is presented next (please use the schematic presented in

Figure 3-1 as a reference):

1. A saturated sample is placed inside the sight glass cell.

2. The sight glass cell is closed.

3. Valves 6, 7, and 8 are opened.

4. Valve 2 is opened and disconnected from the upstream line.

5. The injection pump is turned on, and brine is pumped until see it exits Valve 2. This step

aims to bleed off any air downstream of Valve 2.

6. The injection pump is turned off.

7. Valve 2 is closed and re-connected.

8. The pump is set to 1000 [ml/hr] using the constant flow rate mode and turned on.

9. Valve 2 is opened.

10. Brine is injected until completely cover the sample, then the pump is turned off. Neither air

nor early oil production are observed while brine covers the samples (Figure 3-21).

Figure 3-21 Brine completely covering a Shaunavon sample

11. Valve 2 is closed.

12. Valves 3 and 5 are opened.

13. Nitrogen is injected until the pressure reaches 345 [kPa] less than the setup pressure for the

test; i.e. if the setup pressure for the test is 10345 [kPa], then the final pressure for the

nitrogen would be 10000 [kPa].

14. Valve 3 is closed.

15. Valve 4 is opened to bleed off the nitrogen pressure back in the lines.

16. Valves 4 and 5 are closed.

17. The pump is set to 345 [kPa] higher than the nitrogen pressure using the constant pressure

mode and is turned on; i.e. if the nitrogen pressure is 10000 [kPa], then the pump pressure

would be 10345 [kPa].

18. Valve 2 is opened.

19. The spontaneous imbibition test at high pressure is started and the produced oil volume is

monitored using the cathetometer until a stable value of oil the production volume is

achieved (no extra oil production observed). Neither air nor early oil production are observed

after the system is pressurized (Figure 3-22).

Figure 3-22 Shaunavon sample after pressurization to 10345 [kPa]

Pressure Depletion

The pressure depletion step is considered the final phase of the spontaneous imbibition test at elevated pressures. It also could be a transition step for next experiments to be done (e.g. forced

displacement into an Amott test). Therefore, the pressure depletion phase aims to decrease the pressure of the system gradually in order to prevent further oil production from the samples while pressuring down the system, and in that way preserves the samples state. Although there are multiple options to gradually decrease the pressure of the system, the pressure depletion methodology used in this project is performed by a gas expansion technique, where pressure is released by allowing the gas to expand into a controlled system. The detailed procedure of the pressure down methodology performed in this project is presented next (please use the schematic presented in Figure 3-1 as a reference):

1. After stable production by spontaneous imbibition is achieved and quantified, Valve 2 is

closed (system pressure in between Valve 2 and 3 is 10345 [kPa]).

2. The pump pressure is released, and pump is turned off.

3. Valve 3 is slightly opened and immediately closed (pressure is being released gradually by

gas expansion).

4. Valve 4 is slightly opened for releasing the nitrogen in between Valves 3 and 5.

5. Valve 4 is closed.

6. Steps 3 to 5 are repeated until the pressure of the system decreases to atmospheric pressure.

7. The sight glass cell is opened and the sample is removed.

3.3.2. Spontaneous Imbibition Tests

The spontaneous imbibition experiments performed for this project are divided into two groups, the first one is the group of the Berea sandstone samples, intended to be a reference for the

second group, the Shaunavon samples. For each group of samples, multiple spontaneous imbibition tests were planned, as shown in Figure 3-23. For the Berea sandstone samples, brine and oil spontaneous imbibition tests with cleaned-state samples were performed first. Then atmospheric and high pressure spontaneous imbibition tests were performed with restored-state samples. Similarly, for the Shaunavon samples the first tests performed were brine and oil spontaneous imbibition with cleaned-state samples; then, oil spontaneous imbibition with brine saturated samples were performed. Finally, spontaneous imbibition tests at atmospheric and high pressures were performed with restored-state samples.

Figure 3-23 Spontaneous imbibition tests

4. Chapter Four: Results

As mentioned before, the wettability evaluation by spontaneous imbibition is a qualitative method for analyzing the wettability tendency of a reservoir sample. Therefore, the results presented in this section are qualitative. Even though the results are qualitative, the experiments were planned in a manner that hints of the wettability tendency are progressively given since the first test (i.e. spontaneous imbibition with cleaned samples), to the last test performed (i.e. high pressure spontaneous imbibition with restored-state samples), and thereby a much solid assessment of the wettability tendency is reached.

4.1. Berea Sandstone Samples

4.1.1. Cleaned Samples

The spontaneous imbibition of oil and brine in the cleaned and dried Berea sandstone samples

(SST1 and SST2) were the first experiments performed for the Berea sandstone set of samples, where the core plugs were initially cleaned and dried, and then were soaked in brine or oil until a stable imbibed volume was observed (no extra volume imbibed). After the tests were completed

(120 [hr]), an average pore volume imbibed with oil and brine of 80.5 [%] and 51.5 [%] were respectively observed (Figure 4-1). The significant imbibition with both oil and brine suggest that cleaned Berea sandstone samples are fractionally-wet when are evaluated by spontaneous imbibition tests at atmospheric pressure.

Figure 4-1 Spontaneous imbibition in cleaned Berea sandstone sample

4.1.2. Restored Samples

After finishing the experiments with cleaned-state samples, the Berea sandstone samples were restored before running the spontaneous imbibition tests at atmospheric and elevated pressures with oil saturated samples. The restored saturations are presented in Table 4-1.

Table 4-1 Saturation of Berea sandstone samples

Formation Test Sample ID Water PV [cc] He PV [cc] Sw [%] So [%] Atmospheric SST1 3.41 3.56 44.3 55.7

Berea Atmospheric SST2 3.42 3.68 67.8 32.2 Sandstone HP SST1 3.46 3.56 43.1 56.9 HP SST2 3.52 3.68 71.1 28.9

Atmospheric Pressure Spontaneous Imbibition

After the Berea sandstone samples were restored, the oil saturated samples (SST1 and SST2) were immersed into an Amott cell with brine (Figure 4-2) and left soaking until a stable value of oil production volume was achieved. After 120 [hr] of testing, the oil recovery factors observed for Samples SST1 and SST2 were 33.5 [%] and 46.4 [%] respectively. The significant oil recovery after spontaneous imbibition and the lack of brine production while aging (oil spontaneous imbibition) suggest that restored Berea sandstone samples present a water-wet tendency when are evaluated by spontaneous imbibition tests at atmospheric pressure.

Figure 4-2 Spontaneous imbibition test of sample SST1 at atmospheric pressure

High Pressure Spontaneous Imbibition

The Berea sandstone samples were restored again after the atmospheric pressure tests and core plugs SST1 and SST2 were placed into the sight glass cell and high pressure tests started by pressuring up the system to 10345 [kPa] (following the methodology explained before). After 71

120 [hr] of testing, the experiments finished with no oil production observed in either sample

SST1 in Figure 4-3 and SST2 in Figure 4-4. The lack of oil production suggests that the restored Berea sandstone samples are neutral-wet when evaluated by spontaneous imbibition tests at elevated pressures.

Figure 4-3 High pressure spontaneous imbibition test of Berea sandstone sample SST1

Figure 4-4 High pressure spontaneous imbibition test of Berea sandstone sample SST2 72

4.2. Shaunavon Samples

4.2.1. Cleaned Samples

The spontaneous imbibition of oil and brine in the cleaned and dried tight media Shaunavon samples (3P, 4P, 5P and 8P) were the first experiment performed for the second set of samples, where the Shaunavon core plugs were initially cleaned and dried, and then were soaked in brine or oil until a stable imbibed volume was observed. After the tests were completed (120 [hr]), average pore volumes imbibed with oil and brine of 96 [%] and 21.6 [%] respectively, were observed (Figure 4-5). The significant imbibition with both oil and brine suggests that cleaned

Shaunavon samples are fractionally-wet but with higher wetting affinity to oil than to brine when evaluated by spontaneous imbibition tests at atmospheric pressure.

Figure 4-5 Spontaneous imbibition in cleaned Shaunavon samples

4.2.2. Brine Saturated Samples

After the cleaned samples tests, the Shaunavon samples were cleaned, cleaned, and brine saturated following the high pressure differential saturation methodology. The average water saturation after the high pressure differential process reached the 98.4 [%], indicating that the

Shaunavon samples are fully brine saturated (Table 4-2).

Table 4-2 Brine saturation of Shaunavon samples

Formation Sample ID Water PV [cc] He PV [cc] Sw [%] 3P 4.75 4.77 99.6 4P 4.47 4.49 99.4 Shaunavon 5P 1.92 2.00 95.8 8P 2.86 2.89 98.9

Oil Spontaneous Imbibition

For the oil spontaneous imbibition tests, the brine saturated Shaunavon core plugs (3P, 4P, 5P and 8P) were placed inside an Amott cell with oil (Figure 4-6) and left soaking until a stable value of brine production volume was achieved. After 240 [hr] of testing, the experiments finished with no brine production observed in all the samples, suggesting that the brine saturated

Shaunavon samples are water-wet when evaluated by oil spontaneous imbibition tests at atmospheric pressure.

Figure 4-6 Oil spontaneous imbibition test of Shaunavon sample 3P at atmospheric pressure

4.2.3. Restored Samples

After finished the experiments with cleaned-state and brine saturated samples, the Shaunavon core plugs were restored before running the spontaneous imbibition tests at atmospheric and elevated pressures with oil saturated samples. The restored saturations are presented in Table

4-3.

Table 4-3 Saturation of Shaunavon samples

Formation Test Sample ID Water PV [cc] He PV [cc] Sw [%] So [%] Atmospheric 3P 4.72 4.77 42.8 57.2 Atmospheric 4P 4.40 4.49 38.6 61.4 HP 3P 4.68 4.77 27.4 72.6 Shaunavon HP 4P 4.45 4.49 39.3 60.7 HP 5P 1.96 2.00 28.4 71.6 HP 8P 2.85 2.89 40.3 59.7

Atmospheric Pressure Spontaneous Imbibition

After the Shaunavon samples are restored, the oil saturated samples (3P and 4P) were immersed into an Amott cell with brine and left soaking until a stable value of oil production volume was achieved. After 240 [hr] of testing, no oil production was observed either in Sample 3P or in

Sample 4P (Figure 4-7). The lack of oil production after spontaneous imbibition and the lack of brine production while aging (oil spontaneous imbibition) suggest that restored Shaunavon samples are neutral-wet when evaluated by spontaneous imbibition tests at atmospheric pressure.

Figure 4-7 Spontaneous imbibition test of Shaunavon samples 3P and 4P at atmospheric pressure

High Pressure Spontaneous Imbibition

The Shaunavon samples were restored again after the atmospheric pressure tests. Core plugs 3P,

4P, 5P and 8P were placed into the sight glass cell and high pressure tests started by pressuring up the system to 10345 [kPa] (following the methodology explained before). After 240 [hr] of testing, no oil production was observed from any sample (Figure 4-8 to Figure 4-11), suggesting

that restored Shaunavon samples are neutral-wet when are evaluated by spontaneous imbibition tests at elevated pressures.

Figure 4-8 High pressure spontaneous imbibition test of Shaunavon sample 3P

Figure 4-9 High pressure spontaneous imbibition test of Shaunavon sample 4P

Figure 4-10 High pressure spontaneous imbibition test of Shaunavon sample 5P

Figure 4-11 High pressure spontaneous imbibition test Shaunavon sample 8P

4.3. Wettability Assessment Summary

Figure 4-12 compiles the results presented for each set of samples. For the Berea sandstone set of samples, when the spontaneous imbibition tests were performed with cleaned samples at atmospheric conditions, a fractional-wet tendency was suggested because both fluids (oil and 78

brine) imbibed into the samples; however, when samples were restored, significant oil was displaced by brine imbibition, indicating that the preference of the rock surface is to be in contact with brine rather than oil (water-wet tendency). Additionally, a wettability preference to water rather than oil is observed during the aging step when no oil imbibition was observed into the

Berea sandstone samples (oil spontaneous imbibition at atmospheric conditions). Finally, an alteration in the wettability preference from water-wet to neutral-wet was observed when spontaneous imbibition tests at elevated pressures were performed with the restored Berea sandstone samples. As no other changes in the experiment conditions rather than the pressure of the spontaneous imbibition test were performed, and no reservoir fluids were used (which could altered the wettability due to the brine chemistry or adsorption of polar compounds), it is suggested that the wettability alteration of the Berea sandstone samples from water-wet to neutral-wet evaluated by spontaneous imbibition tests could be because the high pressure condition of the experiment (10345 [kPa]). Therefore, the effect of the pressure in spontaneous imbibition tests for wettability evaluation could be explained as an external force acting in opposite direction to the capillary force, and consequently slowing the spontaneous imbibition process.

For the tight media Lower Shaunavon samples, when the spontaneous imbibition tests were performed with cleaned samples and at atmospheric conditions, a fractional-wet tendency with higher wetting affinity to oil than to brine was suggested like the Berea sandstone samples.

However, when the samples were brine saturated the wettability tendency changed to water-wet

(as no oil imbibition was observed). Finally, when the samples were restored, a neutral-wet

tendency was suggested from the spontaneous imbibition tests at atmospheric conditions, different than the Berea sandstone samples, but similar to the Middle Bakken formation (Table

2-5), which principal lithology is limestone as the Lower Shaunavon formation. Similarly, a neutral-wet tendency was suggested from the high pressure spontaneous imbibition tests with restored Shaunavon samples. With the restored Shaunavon samples no effects of the pressure in spontaneous imbibition tests were observed, as both tests (spontaneous imbibition at atmospheric and high pressure) suggested neutral-wet tendencies; however, the pressure effect could be covered up by the low permeability of the samples, which also slows the spontaneous imbibition process.

By comparing the wettability results from the Berea sandstone samples and the Lower

Shaunavon samples, it is observed that both sets of samples behaved similar at cleaned-state conditions (as both fluids oil and brine spontaneously imbibed into the samples) because all the adsorbed compounds from the rock surface were removed by the cleaning process. However, with restored-state samples, at atmospheric conditions there is a difference between the Berea sandstone and the Shaunavon samples, by being the first more water-wet and the second one more neutral-wet respectively. This wettability differences could be explained by differences in rock mineralogy and petrophysical properties, as the other experimental factors as pressure and temperature conditions and saturation fluids remained the same. Finally, with restored-state samples and high pressure spontaneous imbibition tests, wettability differences between the

Berea sandstone and the Shaunavon samples were not observed, as both sets of samples presented a neutral-wet tendency.

Figure 4-12 Wettability assessment summary

5. Chapter Five: Conclusions and Recommendations

5.1. Conclusions

• A novel approach of water saturation by high pressure differential process was developed for

tight core plugs, where a pressure differential of 6900 [kPa] is created using the sight glass

cell, in which the cleaned sample is placed and cover with water, and consequently the air

initially saturating the sample is enhanced to come out (by density differences), creating a

pressure gradient (from outside to inside the sample) that enhances the surrounding water to

flow in and saturates the sample. For the Lower Shaunavon samples an average water

saturation of 98.4 [%] was achieved in comparison to 82.5 [%] and 18.6 [%] for the

traditional water injection and vacuum saturation methods respectively; and about 1.5 [hr]

are required to perform the whole test for one sample, instead of about 24 [hr] and 168 [hr]

for water injection and vacuum saturation respectively.

• An innovative apparatus and methodology for evaluating the wettability tendency of tight

media reservoirs by spontaneous imbibition tests at elevated pressures were developed and

implemented using conventional Berea sandstone samples, and tight media samples from the

Lower Shaunavon reservoir. The main features of the apparatus are:

o Elevated pressures (10345 [kPa]) are considered.

o Production volumes by spontaneous imbibition are directly measured and recorded

through sight glass at high pressure.

o The imbibition process (sample and production volumes) can be visually monitored

through the sight glass. Visual monitoring is useful in order to asses what is

happening with the saturated sample during the whole imbibition process.

o Oil production droplets stuck at the sample and cell walls can be identified by visual

monitoring through the sight glass.

o Multiple rock samples (e.g., shales, sandstone, carbonates) and fluids configurations

(e.g., reservoir fluids, fracturing fluids, solvents, surfactants) can be used.

• The wettability assessment by spontaneous imbibition tests at elevated and atmospheric

pressure suggested a neutral-wet tendency for the restored Shaunavon core plugs. However,

for the brine saturated core plugs a water-wet tendency was suggested when evaluated by oil

spontaneous imbibition tests at atmospheric pressure, and finally a fractional-wet tendency

with higher wetting affinity to oil than to brine is suggested when cleaned and dried

Shaunavon core plugs are evaluated by spontaneous imbibition tests at atmospheric pressure.

• For the restored Berea sandstone samples, an alteration in the wettability preference from

water-wet to neutral-wet was observed when spontaneous imbibition tests at atmospheric and

elevated pressures were performed respectively. As no other changes in the experiment

conditions rather than the pressure of the spontaneous imbibition test were performed, and no

reservoir fluids were used; it is suggested that the wettability alteration of the Berea

sandstone samples from water-wet to neutral-wet could be because the high pressure

condition of the experiment (10345 [kPa]). The effect of the pressure in spontaneous

imbibition tests for wettability evaluation could be explained as an external force acting in

opposite direction to the capillary force, and consequently slowing the spontaneous

imbibition process.

5.2. Recommendations

• The cathetometer optical tool used for this thesis is an analog tool, where the length is

measured by reading a Vernier Scale. Therefore, for improvement purposes it would be

better if a digital optical tool is used for avoiding the error implicit during the readings.

• As mentioned before, the most representative wettability measurements are obtained by using

conditions as similar to the reservoir as possible. Therefore, it would be interesting to

evaluate the wettability by spontaneous imbibition tests including elevated pressures,

temperatures and reservoir fluids.

• Even though the spontaneous imbibition test at elevated pressures is a qualitative wettability

evaluation method, it is also the first step of an Amott test, a quantitative method for

analyzing the wettability tendency. Therefore, it would be interesting to develop a wettability

assessment project by running Amott tests at elevated pressures. However, to develop a

complete Amott test at high pressures, the oil spontaneous imbibition step at elevated

pressures should be tackled first. The principal challenge of the oil spontaneous imbibition

test at elevated pressures is to figure out the way the sight glass cell would hold the sample at

the top, allowing to collect the production water at the bottom.

• Similar than tight reservoirs, shale reservoirs are generally produced using hydraulic

fracturing. Therefore, it would be interesting to evaluate the wettability tendency of shale

reservoirs by using the apparatus and methodology for spontaneous imbibition tests at

elevated pressures developed in this project.

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A. Appendix A: Sight Glass Cell Pressure Test

For a brand new sight glass cell, the maximum working pressure is 34500 [kPa] and the maximum working temperature is 65 [°C] (limited by the sight glass glass); however the sight glass cell used for running this work is not new. Therefore, pressure tests with water and nitrogen were done to establish the pressure threshold, 10345 [kPa] with a safety margin of 3450 [kPa] at room temperature (21 [°C]).

Five high pressure tests were done in total, where factors such as the type of graphite gasket, grease added to the gasket-glass seal, and bolt torque were analyzed until a successful pressure test was obtained. Table A-1 presents a summary of the five pressure tests performed.

Regardless the different factors implemented in Pressure Test 1, 2 and 3, leaks throught the gasket-glass seal were observed at 13800, 10345 and 6900 [kPa] in Test 1, 2 and 3 respectively, meaning that the gasket-glass seal was not working appropiately. Damaged graphite gaskets are observed in Figure A-1.

Figure A-1 Graphite gaskets after Pressure Tests 1, 2 and 3

For the Pressure Test 4, a thinner graphite gasket was used to prevent the leaks presented in the previous tests. The pressure was held satisfactorily up to 13800 [kPa], where pressure started to go down slowly due to a leaking presented at the lower cap rubber gasket of the cell.

For the pressure test 5, the lower cup rubber gasket was replaced and the test was performed with nitrogen and brine (2 wt% NaCl). Pressure at 10345 [kPa] was held satisfactorily for 240 [hr], where the test was finished and the pressure threshold was established at 10345 [kPa] with a safety margin of 3450 [kPa] at room temperature (21 [°C]). Figure A-2 shows the pressure vs. time plot of the Test 4 and 5.

Pressure Test 4 and 5 14,000 13,000 12,000 11,000 10,000 9,000

8,000 Test 4 7,000 Test 5 6,000

Pressure [kPa] 5,000 4,000 3,000 2,000 1,000 0 0 50 100 150 200 250 Time [hr]

Figure A-2 Pressure Test 4 and 5

Table A-1 Sight glass cell pressure tests

Gasket Other Pressure [kPa]/Time [hr]

Final Initial Torque Information Thick Grease 1380 3450 4140 5170 5500 6900 7580 8270 10345 13800 Thick [mm] [N*m] [mm]

Test 1 New Thick 1.87 1.58 No 54 0.2 0.3 - - - 0.3 - - - Leak Water Gasket

Test 2 New Thick 1.87 1.57 Yes 81 0.3 0.5 - - - 0.3 - 0.17 Leak - Water Gasket

Test 3 New Thick 1.87 1.59 Yes 81 0.1 0.1 - - - Leak - - - - Water Gasket

Test 4 New Thin 1.05 - No 81 0.1 0.3 - 0.3 - 24 0.3 120 28 Leak Water Gasket

Test 5 Used Thin 1.05 - No 81 - - 0.1 - 0.2 21 - - 240 - N2-water Gasket

B. Appendix B: Sight Glass Cell Calibration

This appendix presents the sight glass cell calibration performed with the cathetometer optical tool. As explained before in Chapter 3, the cathetometer is the optical tool used for measuring the production volumes through the sight glass cell. However, as the cathetometer just reads length with the help of a Vernier scale that can measure vertical positions with an accuracy of 0.001

[cm], it was necessary to convert that vertical length to volume by calibrating the sight glass cell

(Figure B-1).

Figure B-1 Sight glass cell calibration

The sight glass cell calibration is performed by first leveling the cell in a horizontal plane

(Figure B-2), then the cell is half filled with brine (2 wt% NaCl), and by using a 1 [ml] syringe two fixed volumes of oil (0.1 and 1 [ml]) are placed inside the sight glass cell to then measure the vertical length covered by the oil interphase and determine the ratio of length to volume.

Additionally, the measurements where performed at two different times, just after the oil is placed into the cell, and after 24 [hr] of waiting.

Figure B-2 Sight glass cell leveling

Three different oils were used for the calibration, the first one is a vacuum pump oil (VWR vacuum pump oil 19, 54996-082) with a density of 0.87 [gr/cc], the second one is a motor oil

(Penzoil 5W-20) with a density of 0.86 [gr/cc], and the last one is the oil used as the saturation

fluid for the spontaneous imbibition tests, heptane (0.03 wt% Sudan II) with a density of 0.68

[gr/cc].

Table B-1 presents the results of the sight glass cell calibration, where the average calibration result is that 0.02 [cm] of length in the cathetometer Vernier scale represents 0.1 [ml] of volume inside the sight glass cell.

Table B-1 Sight glass cell calibration

Length in the Vernier Scale [cm] Heptane Pump Oil Engine Oil Volume (0.03 wt% Sudan II) [ml] 0 [h] 24 [hr] 0 [h] 24 [hr] 0 [h] 24 [hr] Calibration [cm/0.1ml] 0.1 - 0.02 0.02 0.022 0.02 0.02 0.0204 1 0.2 0.2 0.22 0.215 0.18 0.17 0.0198 Average Calibration 0.020 [cm/0.1ml]

C. Appendix C: Vacuum Saturation and Water Injection Procedure

In this appendix, a detailed step by step procedure of the water saturation is presented. The description is divided in three sections, water saturation under vacuum, leaking test and water injection.

Water Saturation under Vacuum

The water saturation under vacuum is a simple process used for first removing the air inside the sample, and then water saturating the sample under vacuum to prevent any air gets inside the sample again. The equipment required for running this test mainly consists of a vacuum pump and two chambers, as observed in Figure C-1.

Figure C-1 Vacuum saturation equipment

The process followed to vacuum saturate the samples with water is presented next:

1. Samples dried weight is measured before starting the test.

2. Samples are placed in a beaker and then put into the right chamber.

3. A bottle with water is placed in the left chamber.

4. The vacuum pump is turned on and both chambers are vacuumed at -100 [kPa] for 48 [hr].

5. If no leaking is observed, then a valve is opened to allow water fill up the sample’s vessel

until completely cover them.

6. Samples are saturated under vacuum with water at -100 [kPa] for 120 [hr].

7. Vacuum pump is turned off and samples are removed from the chamber to measure the initial

water saturated weight of the samples.

8. Samples are left soaking in brine meanwhile the brine injection is performed.

Figure C-2 Samples soaking in brine

Leaking Test

The leaking test is performed prior the water injection and aims to validate that there is no leaking from the overburden to the sample. The leaking test procedure followed is presented next:

1. Sample is placed inside the rubber sleeve and then into the core holder. Figure C-3 shows

the diagram for the leaking test. 99

Figure C-3 Leaking test diagram

2. All Valves are opened.

3. The overburden pump is set to 6900 [kPa] using the constant pressure mode and turned on.

4. If no water is observed coming out from the injection or production lines (no leaking), then

overburden pressure is increased to 17200 [kPa].

5. If no water is observed coming out from the injection or production lines (no leaking), then

the other parts of the injection system are connected, as observed in Figure C-4.

Figure C-4 Injection system diagram 100

Water Injection

1. Valves 1, 2, 4, 6, 7, and 8 are opened.

2. The injection pump is turned on until water exits through Valve 7.

3. Valve 6 is closed.

4. The injection pump is turned off.

5. Valve 7 is closed.

6. The production line of the core holder is closed with a blind bolt.

7. Valves 7 and 9 are opened.

8. The vacuum pump is turned on and lines upstream Valve 6 are vacuumed.

9. The vacuum pump is turned off and Valve 7 is closed.

10. The injection pump is set to 690 [kPa] in the constant pressure mode with a maximum

pressure limit of 13800 [kPa].

11. The injection pump is turned on.

12. Valve 6 is opened.

13. When the injection pump reaches the 690 [kPa], the set-up is switched to constant flow rate

mode with a flow rate of 1 [ml/hr].

14. After 30 [min], the blind bolt in the production line is removed and a plastic hose to the

production bottle is connected.

15. The sample is water flooded with a flow rate of 1 [ml/hr] with 17200 [kPa] of overburden

pressure for 24 [hr]. 101

16. The overburden pressure is released and pump is turned off.

17. Valves 9 and 10 are closed.

18. The injection pump is turned off.

19. Valves 2, 4 and 6 are closed.

20. The core holder is disconnected.

21. The sample is removed from the rubber sleeve and weighed.

22. The Sample is left soaking in brine.

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D. Appendix D: Copyright Permissions

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