✓ Application of an optimum wettability restoration procedure to reduce the gap between laboratory and field conditions.
✓ Extensive contact angle experiments to determine the ability of SiO2
nanofluids to change the wetting character of two types of rock surfaces as a function of aging time and nanofluid concentration.
✓ Comparison between current and previous contact angles analyses to establish the optimum wettability method.
✓ Evaluation of the mineralogical changes in rock before and after aging in nanofluids by mineral liberation analyzer (MLA) tests.
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✓ Evaluation of a nanofluid before and after the aging process with an inductively coupled plasma optical emission spectroscopy (ICP-OES) analysis.
✓ To be published in a scientific journal.
The appendices, at the end of the manuscript, contain all data that were not included in the submission of the articles.
1.2 Hebron Asset Overview 1.2.1 Research Project Area
The research project is focused on the Hebron asset, which is located in the Jeanne d’Arc Basin 340 km offshore of St. John’s, Newfoundland and Labrador, approximately 9 km north of the Terra Nova, 32 km southeast of Hibernia, and 46 km southwest of White Rose (Figure 1.2) fields. The water depth at Hebron ranges from 88 to 102 m.
Figure 1.2 Location of the Hebron Project Area
The Hebron asset contains three discovered fields (Hebron Field, the West Ben Nevis Field and the Ben Nevis Field), four reservoir formations (Avalon, Ben Nevis, Hibernia, and
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Jeanne d’Arc), and five pools. The current best estimation of total oil in place is 2,620 million barrels of oil of which, 30% is considered recoverable. The Hebron Field, specifically the Ben Nevis Formation (Pool 1) is anticipated to produce close to 80% of the Hebron asset’s crude oil. The quality of the crude in the Pool 1 is 20 °API (CNLOPB, 2011).
Figure 1.3 Schematic Cross-Section Across the Hebron Project Area (after CNLOPB, 2011)
1.2.2 Reservoir Characterization 1.2.2.1 Structural Geology
The Hebron Field is on a horst block in between two grabens at the southwest and northeast.
This horst block has two different traps, the first trap is a fault in the Ben Nevis and Hibernia Formation and the second trap is due to combination of structural and stratigraphic configurations in the Jeanne d’Arc Formation. The other two fields (West Ben Nevis and Ben Nevis) are on different fault blocks to the northeast of Hebron Field. The setting of the major faults creates the blocks, and defines the structural traps. The oil-water contacts are
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determined by spill-points between the fault blocks. The major faults are described as syn-depositional, meaning that deposition occurred at the same as the faulting. These faults had a significant impact on the accommodation and thickness of the preserved reservoirs, and a significant growth in the thickness of the Ben Nevis reservoir across these faults is observed. Unfortunately, the quality of the Ben Nevis reservoir in the thicker sections is lower due to the presence of deeper sedimentary facies. The Avalon, Hibernia, and Jeanne d'Arc Formations were deposited prior to the onset of the third episode of rifting, in which the reservoirs were faulted. Since deposition and faulting occurred as different geological events, these reservoirs do not show a change in thickness or quality across the faults (CNLOPB, 2011).
1.2.2.2 Geology of the Ben Nevis Formation
The Ben Nevis Formation (upper Aptian to Albian) is a 125 to 500 m thick succession of upward fining (fine to very fine grained) calcareous sandstone, with thin interbedded layers of sandy limestone, that grades upward into glauconitic siltstone and shale (CNLOPB, 2011). The depositional environment is primarily lower to upper shoreface environment.
The reservoir section is composed predominantly of laminated and bioturbated, medium to fine-grained sandstones. Secondary lithologies include coquinas, shell-rich sandstones, mudstones, and calcite nodules. The reservoir quality is fair to good in Hebron Field (Pool 1) with average permeabilities ranging from 50 to 400 mD and average gross porosities ranging from 10 to 28 percent. The reservoir quality in the Ben Nevis Field (Pool 3) is lower because it is an area dominated by more distal facies. The average permeabilities range from 0.1 to 100 mD, and average gross porosities range from 4 to 24 percent (CNLOPB, 2011).
1.2.2.3 Wetting Character of the Ben Nevis Formation
A special core analysis (SCAL) was conducted on a preserved core from the D-94 well in lower section of the Ben Nevis Formation (Pool 1). The results indicated that the rock is
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weakly water-wet as defined by the United State Bureau of Mines (USBM) wettability tests (CNLOPB, 2011).
1.3 Enhanced Oil Recovery Overview
The production life of an oil reservoir can be classified base on the recovery method applied. There are three main methods: primary, secondary and tertiary recovery. The first two are termed conventional recovery and they target the mobile oil in the reservoir.
Tertiary recovery targets the immobile oil, which can not be produced naturally due to capillary and/or viscous forces. In a conventional oil reservoir, the reservoir rocks are generally pressurized above hydrostatic pressure due to compaction of sedimentary rocks over geologic time. Primary recovery occurs when the fluid in the pressurized layer flow to the surface until the pressure in the reservoir is reduced to hydrostatic pressure.
Thereafter, secondary recovery is applied which involves water (water injection) or gas flooding, for pressure maintenance. Waterflooding enhances recovery by sweeping oil to the productions wells, whereas gas injections reduce oil viscosity to improve recovery (Donaldson, Chilingarian, & Yen, 1985).
During the mature phase of field life, tertiary recovery methods, also known as enhanced oil recovery (EOR) are considered. These methods change the fundamental physics or chemistry of the reservoir conditions to improve the oil recovery (Morrow & Heller, 1985).
They are generally classified into thermal techniques, gas injections and chemical methods (Figure 1.4). Each EOR technique has a unique mechanism, and the method applied will depend on the reservoir properties and conditions.
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Figure 1.4 Three Phases of Oil Recovery
1.3.1 Enhanced Oil Recovery Considerations for Hebron Field
The Hebron development plan outlines a preliminary high-level screening of EOR methods. The initial screening of the Ben Nevis Formation (Pool 1) suggests favorable EOR techniques such as gas injection, polymer flooding, and chemical flooding, and discarded thermal EOR method (CNLOPB, 2011).
Valencia, et al. (2017), considering the following variables for EOR: oil gravity, oil viscosity, rock type, porosity, permeability, net reservoir, depth, and reservoir temperature.
They evaluated diverse EOR methods such as: miscible gas (CO2 and hydrocarbon water alternative gas or HC WAG) injection, immiscible gas (nitrogen, CO2, and HC WAG) injection, chemical flooding (polymer, and alkali-surfactant-polymer or ASP), and thermal methods (combustion and steam). From their evaluation, it was concluded that the best techniques would be CO2 and HC WAG as immiscible gas injections, and chemical flooding using polymer.
The EOR screening criteria for this research was based on the oil characteristics and reservoir properties of the Ben Nevis Formation and targeting the fluid-fluid interactions
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and fluid-rock interactions. Four chemical flooding were evaluated low-salinity, surfactant-polymer (SP), alkali-surfactant-surfactant-polymer (ASP), and nanofluid. The first three methods were not considered further because either the Ben Nevis Formation features, or oil properties did not meet the criteria to apply the technique.
One of the requirements for the successful application of low-salinity injection is a high percentage of clay minerals. The effect of low-salinity is related to the presence of clay minerals, and consequently, it is generally accepted that the effect is caused by wettability alteration of clay minerals (Yousef, et al., 2011). The amount of clay minerals presents in the Ben Nevis Formation, however, is only 0.3% to 3%, making this technique unviable.
Surfactant-Polymer (SP) EOR methods improve the displacement and sweep efficiencies.
The surfactant reduces interfacial tension (IFT) between the displacing and displaced phases and the polymer improve the mobility ration. Previous research indicated the importance of the oil gravity to the effectiveness of this technique, hence it was recommended that the oil gravity should be greater than 25 °API (Gao, et al., 2010). The oil gravity in the Hebron Field is lower than the recommended values and the application of this technique would not be effective.
The third method considered was alkali-surfactant-polymer (ASP) flooding, which is a technique in which alkaline solutions are injected into the reservoir. This chemical solution reacts with the natural acids (naphthenic acids) present in crude oil to form surfactants in-situ (sodium naphthenate) that operate in the same way as injected synthetic surfactants to reduce interfacial tension between oil and water. The polymer solution is then injected into the reservoir to enhance the mobility ratio. The role of the alkali in the ASP process is to reduce the adsorption of the surfactant during displacement through the formation of sequestering divalent ions. The presence of alkali can also alter formation wettability to reach a desire wetting character (Olajire, 2014). To successfully implement this technique, it is suggested that the formation-water chlorides should be lower than 20,000 ppm and divalent ions (Ca2+ and Mg2+) lower than 500 ppm (Taber, et al., 1997). The chloride concentrations in formation waters from the Ben Nevis Formation are approximately 34,925 ppm, and the divalent ions are higher than 500 ppm.
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In summary, nanoparticle injection was considered as the most suitable chemical flooding alternative for the Ben Nevis Formation. It is a new and an innovative method, and the amount of research available has grown in the past few years (Aurand, et al., 2014;
Hendraningrat, et al., 2012; Hendraningrat, et al., 2013; Hendraningrat & Torsæter, 2014;
Li, et al., 2013). Most these researchers conclude that if a specific nanoparticle at the right concentration is injected into a reservoir, it can alter the wetting character, reduce the interfacial tension, and increase oil recovery.
1.3.2 Nanoparticles as a Water Additive for Enhanced Oil Recovery
Nanotechnology as an EOR technique has become more popular during the last few years due to its promising results at the laboratory scale (Hendraningrat et al., 2012). The trends of some top successful industries around the world are based on miniaturization and nanotechnology. Nanoparticles are materials ranging in size between 1nm to 100 nm, similar to the size of proteins or viruses (Figure 1.5). The specific physical and chemical properties of a nanoparticle stem from the core, which is surrounded by the shell that provides a protective layer (Das, et al., 2008).
Figure 1.5 Nanoparticles Sizes Relatives to Other Materials (Modified Image from /www.wichlab.com)
EOR is designed to either generate fluid-fluid interaction between injected fluid and the fluid in the reservoir, such as oil, formation water and/or gas, or fluid-rock interaction between the fluid injected and the rock. Nanoparticles as a water additive for EOR are targeted to generate both fluid-fluid and fluid-rock interactions.
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1.3.2.1 Targeted Properties
The two main targets of silicon dioxide nanoparticles (SiO2) as EOR agents are interfacial tension and wettability alteration. The interfacial tension is the well-defined interface that appears along the contact of two immiscible fluids such as gas-liquid or liquid-liquid (Figure 1.6). The IFT represents only a few molecular diameters in thickness, and it is measured in force per unit length (mN/m) (Donaldson et al., 1985). When this force is low enough, it can increase the capillary number, which affects the microscopic pore-level oil displacement (Lake, et al., 2014).
Figure 1.6 Interfacial Tension
Wettability is an essential rock property for enhancing oil recovery because it describes the preference of a solid to be in contact with one liquid rather than another in a three-phase system. A three-phase system is shown in Figure 1.7, where a drop of oil is surrounded by water on a rock surface. There are three cases that represent the principal types of wettability (Morrow & Heller, 1985). In water wet condition, the contact angle resulting from an oil-water-solid equilibrium is usually low. In an oil wet system, the drop of oil spreads along the rock surface and the contact angle is relatively high. Finally, in an intermediate wet condition, the resulting contact angle is between 75° to 105° (Treiber &
Owens, 1972).
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Figure 1.7 Types of Formation Wettability (after Abdallah et al., 2007)
In a porous media scale, if the rock is preferentially water-wet and the rock is saturated with oil, water will imbibe the smaller pores and surrounding grains. In oil wet conditions, the oil imbibes into smaller pores, having a preference to be in touch with the grains (Figure 1.8). If no preference is shown by the rock to either fluid, the system is said to exhibit neutral wettability or intermediate wettability, a condition that one might visualize as being equally wet by both fluids (Tiab & Donaldson, 2004).
Figure 1.8 Types of Formation Wettability in a Porous Media Scale (after Abdallah et al., 2007)
Relative permeability curves are used for the quantitative evaluation of water flooding performance, and the relative permeability curves are affected by the changes in the wetting character of the rock. As a result, changes in water flooding behavior are seen as the system wettability is altered, and it is clearly shown in Figure 1.9. The curves show that as the system becomes more oil-wet, less oil is recovered at any given amount of injected water.
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In the water-wet system, the oil displacement will finish earlier in comparison with an oil wet system (Tiab & Donaldson, 2004).
Figure 1.9 Relative Permeability in Water-Wet Reservoirs Versus Oil-Wet Reservoirs (after Tiab & Donaldson, 2004)
1.4 Co-Authorship Statement
The chapters presented in manuscript format have been, or will be, published. The following information describes the work completed by the main author and co-authors.
The research was predominantly completed by the main author with collaboration, guidance and editorial advice from the main supervisor, co-supervisors and other collaborators.
Daniel J. Sivira (main author) designed and performed fluid-fluid interaction (interfacial tension tests) and fluid-rock interaction (contact angle experiment, MLA-SEM analysis, and ICP-OES study) experiments. He also prepared the core samples before the analysis (wettability restoration and aging in nanofluid technique), and the preparation and collection of the fluids to be analysed. Finally, the main author analysed data and wrote the articles and this manuscript.
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Dr. Lesley James (main supervisor) was strongly involved at every single stage of the research. She and the main author structured the project. Her expert guidance was essential in developing the project. She carefully reviewed the design of the experiments and conducting the experiments. Jenny was involved with the analysis of the result providing explanations from a chemist’s point of view, and lastly, reviewed the articles and manuscript.
Dr. Johansen Thormod (co-supervisor) assisted in the early stages of the project, specifically in the first article (Chapter II), providing positive guidance to design the experiments. He also revised Chapter II and suggested constructive editorial comments.
Dr. Yahui Zhang (co-supervisor) joined the project at the beginning of the second article because of his expertise in chemistry. He was strongly involved in the project from then, and provided key suggestions in one of the most challenging aspect of the project, which was the stability of the nanofluid. He provided helpful advises in the analysis of the results, and reviewed the second (Chapter III) and third articles (Chapter IV) and the manuscript suggesting beneficial comments.
Dr. Derek Wilton (co-supervisor) joined the research to provide his expertise in geology, and specifically in MLA-SEM analysis. Dr. Wilton assisted in the interpretation of the MLA-SEM results providing a high-quality analysis. He also revised two of the article (Chapter III and Chapter IV) and the manuscript, providing comments and suggestion for improvements.
Edison Sripal collaborated in the Chapter IV (third paper) of this research. He conducted an effective and innovative wettability restoration technique to the core samples prior to the experiments conducted on them.
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CHAPTER II - THE EFFECTIVENESS OF SILICON DIOXIDE (SiO2) NANOPARTICLE AS AN ENHANCED OIL RECOVERY AGENT IN
BEN NEVIS FORMATION, HEBRON FIELD, OFFSHORE EASTERN CANADA
D. J. Sivira, H. Kim, L.A. James, T. E. Johansen, and Y. Zhang
Memorial University of Newfoundland, St. John’s, Newfoundland and Labrador, Canada.
Published in the Abu Dhabi International Petroleum Exhibition & Conference (ADIPEC), 7-10 November 2016, Abu Dhabi, UAE.
2.1 Abstract
The Hebron Project is the fourth major development offshore Newfoundland and Labrador, Canada, with an estimated 2620 million barrels of oil and a target first oil in 2017. The Ben Nevis reservoir accounts for approximately 80% of the crude oil with an estimated 30%
recoverable. Hence, enhanced oil recovery (EOR) requires attention now even before production starts. This research evaluates the effectiveness of silicon dioxide (SiO2) nanoparticles as a water additive to enhance oil recovery in the Ben Nevis Formation, Hebron Field. The experiments involved two main steps: measuring interfacial tension, and determining the wetting character of the rock surfaces. Unlike previous research using SiO2
nanoparticles, in this work, the SiO2 nanoparticles are dispersed in seawater instead of deionized water or simple synthetic brine; experiments are conducted at reservoir conditions (Hebron Field: 62°C and 19.00 MPa); and synthetic cores were used that best represented facies of Ben Nevis Formation. A major challenge was forming a stable SiO2
nanofluid in North Atlantic seawater. Since salinity directly affected the stability of the nanofluid, hydrochloric acid was used as a stabilizer. Interfacial tension (IFT) was
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measured for SiO2 dispersed in deionized water, as well as stable nanofluids with SiO2
concentrations of 0.01, 0.03, and 0.05 wt% dispersed in seawater, to determine the contribution of SiO2 nanoparticle on the alteration of IFT. The contact angles were measured on core plugs before and after aging in 0.01, 0.03, and 0.05 wt% SiO2 nanofluids, to determine whether SiO2 nanoparticles can alter the wettability of the core. The results show that hydrophilic SiO2 nanoparticles are effective water additive for EOR. When comparing IFT experiments with deionized water and SiO2 nanoparticles dispersed in deionized water, the nanoparticles reduced the IFT from 39.70 mN/m to 21.54 mN/m. IFT is also reduced from 21.80 mN/m to 16.61 mN/m in case of experiments in seawater and a 0.05 wt% stable SiO2 nanoparticles dispersed in seawater. The contact angle experiments demonstrate that SiO2 can decrease the contact angle, and therefore make the rock surface more water wet under reservoir conditions. Finally, it is also found that the higher the SiO2
nanoparticle concentration, the higher the wettability alteration.
2.2 Introduction
Due to the increasing demand for oil, it is necessary to research innovative and effective enhanced oil recovery (EOR) techniques, and optimize oil production from either currently producing fields or future fields. This research project focused on the EOR method for Hebron asset, which is the fourth major development (with first oil targeted for 2017) offshore Newfoundland and Labrador, Canada. The Hebron Field is located in the Jeanne d’Arc Basin, 340 km offshore of St. John’s, Newfoundland and Labrador. It is approximately 9 km north of Terra Nova, 32 km southeast of Hibernia, and 46 km southwest of White Rose, as shown in Figure 2.1. The water depth in this area ranges from 88 to 102 m (CNLOPB, 2011). The Hebron asset is estimated to have 2620 million barrels (MMbbl) of total oil in place, of which only 800 MMbbl are considered recoverable.
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Figure 2.1 Hebron Project Area Location (after CNLOPB, 2011)
The Hebron asset is divided into three fields: Hebron Field, West Ben Nevis Field, and Ben Nevis Field, as shown in Figure 2.2. The Hebron asset presents a total of four reservoirs – Avalon, Hibernia, Jeanne d’Arc, and Ben Nevis Formation – and five pools. This research specifically focuses on the Ben Nevis Formation because this formation is anticipated to produce approximately 80% of the Hebron asset’s crude oil. The Ben Nevis Formation is located in pools 1, 2, and 3 with 70% of recoverable resources expected from Pool 1.
Figure 2.2 Schematic Cross-Section Across the Hebron Project Area
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(after CNLOPB, 2011)
From a geological point of view, the quality of the Ben Nevis reservoir on pool 1 is fair to
From a geological point of view, the quality of the Ben Nevis reservoir on pool 1 is fair to