a field application of nanoparticles for improved downhole
TRANSCRIPT
University of Calgary
PRISM: University of Calgary's Digital Repository
Graduate Studies The Vault: Electronic Theses and Dissertations
2015-05-25
A Field Application of Nanoparticles For Improved
Downhole Losses in Invert Emulsion Drilling Fluids
Borisov, Alexey
Borisov, A. (2015). A Field Application of Nanoparticles For Improved Downhole Losses in Invert
Emulsion Drilling Fluids (Unpublished master's thesis). University of Calgary, Calgary, AB.
doi:10.11575/PRISM/24735
http://hdl.handle.net/11023/2268
master thesis
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UNIVERSITY OF CALGARY
A Field Application of Nanoparticles for Improved Downhole Losses in Invert Emulsion Drilling
Fluids
by
Alexey S. Borisov
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 AND PETROLEUM ENGINEERING
CALGARY, ALBERTA
MAY, 2015
© Alexey S. Borisov 2015
ii
Abstract
Invasion of drilling fluids filtrate and solids into porous, permeable, fractured or vuggy zones can
cause formation damage and presents a major source of drilling problems. Furthermore, downhole
mud losses also increase environmental and financial risks associated with drilling operations,
costing over $1B annually.
This thesis investigates the use of in situ prepared calcium carbonate nanoparticles (CNP)
for fluid loss prevention in invert emulsion drilling fluids. CNP at 5 wt% concentration were
synthesized within a custom ‘carrier’ emulsion using a modified microemulsion approach.
Subsequently, the carrier emulsion was used to deliver target concentration of NPs to a host drilling
fluid of interest via volumetric dilution. High pressure, high temperature (HPHT) fluid loss
experiments on commercial invert emulsion drilling fluids showed that CNP at concentration of
0.5 wt% provided a 20–50% improvement over conventional lost circulation materials (LCM). In
addition, basic properties of mud samples were not affected significantly in the presence of the
carrier emulsion.
In order to evaluate performance of CNP under real-life conditions, six full-scale field tests
were conducted in horizontal wells in Alberta, Canada. Industry-scale synthesis of CNP followed
the lab-bench process and was implemented at a specialized mixing facility. The results suggested
that the scale-up from 3×10-4 m3 (300 mL) to 20 m3 did not affect average particle size or final
properties of the carrier emulsion. Furthermore, field HPHT data showed good agreement with the
lab experiments, where the average fluid loss in the test wells was reduced by 20–30% compared
to the control wells using conventional drilling fluids. Finally, analysis of mud losses revealed that
the cumulative losses while drilling were on average 20–30% lower in the presence of 0.5 wt%
CNP, which suggested that NPs help to reduce downhole losses.
iii
Acknowledgements
I would to express my deepest gratitude to my supervisor, Dr. Maen Husein, for giving me this
opportunity and for his invaluable guidance, mentorship, and patience over the years. I also would
like to thank my co-supervisor, Dr. Geir Hareland, for his helpful instruction and financial support.
I am very grateful to Mr. Jeremy Krol, Mr. David Edmonds and nFluids Inc. (Calgary, Alberta)
for all their assistance and kindness, and for making this project possible.
I would like to acknowledge the Department of Chemical and Petroleum Engineering,
NSERC, Talisman Energy, Pason Systems Corp, and Herbert and Ursula Zandmer Scholarship for
their continued financial support during my program.
For the extensive assistance during the field testing, I am especially thankful to Mr. Robert
Merkley and Mr. Trevor Jacobs (Blackstone Drilling Fluids, Calgary, Alberta) and Mr. Lorne
Simpson (Yangarra Resources, Calgary, Alberta).
Last but not least, I would like to thank Dr. Mohammad Zakaria, Dr. Oscar Contreras, Mrs.
Patricia Teichrob, Drilling Research Team and fellow graduate students for all their support and
advice.
iv
Dedication
Dedicated to my loving family and all my friends, without whose motivation and inspiration this
thesis would not be possible.
v
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 .............................................................x
CHAPTER ONE: INTRODUCTION ..................................................................................1
1.1 Functions and properties of drilling fluids .................................................................1
1.2 Types of drilling fluids ..............................................................................................4
1.3 Mud circulation system ..............................................................................................5
1.4 Emulsions and surfactants .........................................................................................7
1.5 Invert emulsion drilling fluids ...................................................................................8
1.6 Mechanism of fluid loss and cross-flow filtration ...................................................11
1.7 Nanoparticles in oil and gas .....................................................................................16
1.8 Emulsion-based synthesis of nanoparticles .............................................................19
1.9 Research objectives ..................................................................................................22
CHAPTER TWO: MATERIALS AND METHODS ........................................................24
2.1 Chemicals and precursors ........................................................................................24
2.2 Drilling fluids sample preparation ...........................................................................24
2.3 Drilling fluids testing ...............................................................................................25
2.3.1 Mud weight ......................................................................................................25
2.3.2 Electrical stability ............................................................................................26
2.3.3 Rheology and gel strength ...............................................................................27
2.3.4 HPHT fluid loss test ........................................................................................28
2.3.5 Retort analysis .................................................................................................29
2.4 In situ synthesis of NPs ............................................................................................30
2.5 Carrier emulsion synthesis .......................................................................................31
2.5.1 Bench-scale synthesis of a carrier emulsion ....................................................32
2.5.2 Field-scale synthesis of a carrier emulsion ......................................................33
2.6 Particle characterization ...........................................................................................34
2.7 Field testing ..............................................................................................................35
2.7.1 Field test implementation ................................................................................37
2.7.2 Field data collection ........................................................................................38
CHAPTER THREE: RESULTS AND DISCUSSION ......................................................42
3.1 Carrier emulsion ......................................................................................................42
3.1.1 Properties of a carrier emulsion .......................................................................42
3.1.2 DLS analysis of a carrier emulsion .................................................................44
3.1.3 SEM and EDX analysis of a carrier emulsion .................................................46
3.2 Basic properties of commercial drilling fluids with CNP ........................................50
3.3 Fluid loss in commercial drilling fluids with CNP ..................................................55
3.4 Field testing ..............................................................................................................58
vi
3.4.1 HPHT fluid loss ...............................................................................................59
3.4.2 The effect of concentration of carrier ..............................................................62
3.4.3 Cumulative mud losses ....................................................................................63
3.4.4 Mud losses per 100 m drilled ..........................................................................65
3.4.5 Correlation of HPHT fluid loss and mud losses ..............................................67
CHAPTER FOUR: CONCLUSIONS, CONTRIBUTIONS AND RECOMMENDATIONS
...................................................................................................................................68
4.1 Conclusions ..............................................................................................................68
4.2 Contributions to knowledge .....................................................................................71
4.3 Recommendations for future work ..........................................................................71
REFERENCES ..................................................................................................................73
vii
List of Tables
Table 2-1: A summary of commercial drilling fluid lab samples. ................................................ 25
Table 2-2: A typical formulation of a carrier emulsion with 5 wt% of CNP. ............................... 32
Table 2-3: An overview of control and test wells. ........................................................................ 36
Table 3-1: Comparison of the properties of the carrier emulsion samples with 5 wt% CNP
prepared on a lab and field scale. .......................................................................................... 43
Table 3-2: Comparison of DLS data on carrier emulsion samples with 5 wt% CNP prepared
in a laboratory vs field scale. 25 °C, THF dispersant. .......................................................... 45
viii
List of Figures and Illustrations
Figure 1: A schematic of a rig mud circulation system. ................................................................. 6
Figure 2: Drilling fluid filtration in the presence of conventional LCM (A) and NPs (B). .......... 15
Figure 3: A schematic of chemical coprecipitation using bulk aqueous phase (top) and a
reverse micelle approach (bottom). ....................................................................................... 21
Figure 4: A FANN Model 140 mud balance. ............................................................................... 26
Figure 5: An OFITE electrical stability tester (Model #131-50). ................................................. 26
Figure 6: A Fann Model 35 viscometer. ....................................................................................... 27
Figure 7: An OFITE HPHT filter press (Model #170-00). ........................................................... 28
Figure 8: An OFITE 50 mL retort kit (Model #165-14). .............................................................. 30
Figure 9: Surface locations of the control and test well groups A, B, C, and D. .......................... 35
Figure 10: A schematic of NPs field implementation using a carrier approach. .......................... 37
Figure 11: A diagram explaining calculation of mud losses in the field. ..................................... 39
Figure 12: Example of the discrepancy between manual and digital floating sensors in a mud
storage tank. .......................................................................................................................... 40
Figure 13: Long-term stability of carrier emulsion samples with 5 wt% CNP prepared in a
laboratory vs field scale. A typical commercial control invert is shown for comparison. ... 44
Figure 14: Intensity size distribution in a carrier emulsion samples with 5 wt% CNP
produced in a laboratory (A) vs field (B). ............................................................................. 46
Figure 15: SEM image of the profile of the filter cake formed by a lab sample of carrier
emulsion with 5 wt% CNP (A); the corresponding overlapped EDX images showing
uniform distribution of calcium, carbon, oxygen, potassium, and chloride (B). .................. 48
Figure 16: SEM images of two different areas within the profile of a filter cake formed by a
lab sample of carrier emulsion with 5 wt% CNP (A, D); the corresponding overlapped
EDX images showing correlation between calcium, carbon, and oxygen (B, E); the same
areas showing correlation between potassium, and chlorine (C, F)...................................... 49
Figure 17: Impact of 0.5 wt% CNP on mud weight of commercial invert emulsion drilling
fluids using in situ and carrier emulsion methods. ............................................................... 51
Figure 18: Impact of 0.5 wt% CNP on electrical stability of commercial invert emulsion
drilling fluids using in situ and carrier emulsion methods. ................................................... 52
ix
Figure 19: Impact of 0.5 wt% CNP on plastic viscosity (A, B) and yield point (C, D) of
commercial invert emulsion drilling fluids. .......................................................................... 53
Figure 20: Impact of 0.5 wt% CNP on gel strength of commercial invert emulsion drilling
fluids at 10 s (A, B) and 10 min (C, D). ................................................................................ 54
Figure 21: Impact of 0.5 wt% CNP on volumetric composition of virgin (A) and recycled (B)
commercial invert emulsion drilling fluids. .......................................................................... 55
Figure 22: Impact of 0.5 wt% CNP on HPHT fluid loss (A, B) and filter cake thickness (C,
D) of commercial invert emulsion drilling fluids at 80 °C and 500 psi. ............................... 56
Figure 23: HPHT fluid loss as a function of measured depth in the control and test wells at 80
°C and 500 psi. ...................................................................................................................... 60
Figure 24: Average HPHT fluid loss in the control and test wells at 80 °C and 500 psi. ............ 61
Figure 25: HPHT fluid loss and calculated concentration of carrier as a function of measured
depth in the test wells. ........................................................................................................... 63
Figure 26: Cumulative mud losses as a function of measured depth in the control and test
wells. ..................................................................................................................................... 64
Figure 27: Final cumulative mud losses at TD in the control and test wells. ............................... 65
Figure 28: Mud losses per 100 m drilled as a function of measured depth in the control and
test wells. ............................................................................................................................... 66
Figure 29: Average mud losses per 100 m drilled at TD in the control and test wells. ................ 66
Figure 30: Correlation between HPHT fluid loss and instantaneous mud losses in the test
wells. ..................................................................................................................................... 67
x
List of Symbols, Abbreviations and Nomenclature
Symbol Definition
𝐴 Cross-section filtration area (cm2)
API American Petroleum Institute
BHA Bottom-hole assembly
BOP Blowout preventer
BTEX Benzene, toluene, ethylbenzene and xylenes
CMC Critical micelle concentration
CNP Calcium carbonate nanoparticles
𝐷𝑖 Initial depth of displacement to invert (m)
𝐷𝑛 Current measured depth (m)
DLS Dynamic Light Scattering
EDX Energy-Dispersive X-ray Spectroscopy
ES Electrical stability (V)
ℎ𝑐 Filter cake thickness (cm) ℎ𝑓 Formation thickness (cm)
HPHT High pressure, high temperature
IFT Interfacial tension
𝑘𝑐 Permeability of the filter cake (D)
𝑘𝑓 Permeability of the formation (D)
LCM Lost circulation materials
LPLT Low pressure, low temperature
LSD Legal sub-division
MD Measured depth (m)
MW Mud weight (kg/m3)
NPs Nanoparticles
OBM Oil based mud
OWR Oil to water ratio
∆𝑃 Pressure differential (atm)
PDI Polydispersity index
𝑃𝑐 Pressure at the inner boundary of the cake (atm)
𝑃𝑓 Formation pressure (atm)
PV Plastic viscosity (cP)
PVT Pit volume totalizer
𝑃𝑤 Wellbore pressure (atm)
𝑞𝐴𝑃𝐼 API fluid loss (mL/s)
𝑞𝑐 Filtrate flux during transitional period (mL/s)
𝑞𝑠 Rate of spurt loss (mL/s)
𝑟𝑐 Inner filter cake radius (cm)
𝑟𝑒 External formation radius (cm)
ROP Rate of penetration (m/hr)
𝑟𝑤 Wellbore radius (cm)
SG Specific gravity
SEM Scanning Electron Microscopy
𝑉𝐶𝐿 Cumulative mud losses (m3)
xi
𝑉𝐿100 Mud losses per 100 m drilled (m3/100 m)
𝑉𝑡 Volume of total liquid fraction (mL)
𝑉𝑤 Volume of aqueous fraction (mL)
WBM Water based mud
YP Yield point (lb/100 ft2)
Greek Symbols Definition
𝜃600 Dial reading at 600 rpm
𝜃300 Dial reading at 300 rpm
𝜇 Mud viscosity (cP)
𝜇𝑝 Plastic viscosity (cP)
𝜏𝑦 Yield point (lb/100 ft2)
1
CHAPTER ONE: INTRODUCTION
1.1 Functions and properties of drilling fluids
Drilling fluids play a crucial role in oil and gas well drilling operations and provide several key
functions. For instance, drilling fluids are used to suspend and carry cuttings to the surface, provide
hydrostatic pressure and support the wellbore, cool and lubricate the drilling assembly, form a cake
sealing off porous and permeable formations, and transmit signals between downhole equipment
and the surface, to name a few (ASME, 2005). As a result, drilling fluids are complex systems,
often composed of a large number of components, each providing a specific functionality or
property. Moreover, composition and properties of drilling fluids constantly change throughout a
drilling operation. This renders reproducible laboratory analysis challenging, and so only the
samples obtained from the same batch can be compared directly. When developing a mud additive
aimed to improve one property of a drilling fluid, it is important to consider and mitigate its
possible detrimental effects on the other basic properties. Therefore, this section discusses several
critical properties that were the focus of experimental work presented herein, while the standard
lab methods for their evaluation are outlined in Chapter Two.
a) Mud weight. In overbalanced or managed pressure drilling, mud weight is carefully
selected, so that the corresponding hydrostatic pressure exceeds an anticipated formation
pressure. This provides wellbore stability and prevents formation fluids from entering a
wellbore (known as a kick) or reaching the surface and causing a blowout. Conversely, if
a hydrostatic pressure exceeds the formation breakdown pressure, induced fractures can
lead to large volumes of mud losses, environmental contamination, formation damage, and
borehole collapse (Chin, 1995). Since formation pressure gradient increases with depth,
mud weight has to be monitored regularly and maintained within a specific, optimum
2
range. Mud weight can be increased by adding an appropriate amount of weighting
material, such as a barite mineral (barium sulfate, 4.2 SG). Conversely, it can be decreased
either by solids removal or via volumetric dilution with a less dense fluid. American
Petroleum Institute (API) set a standard practice for measuring mud weight in a lab or at a
drilling site using a special mud balance (API, 2014). Mud weight of drilling fluids
investigated in this work was in the range of 900–1150 kg/m3.
b) Rheology and gel strength. Most drilling fluids exhibit non-Newtonian, shear-thinning
behaviour, which can be described by a Bingham plastic rheological model (Agarwal et
al., 2009; Jihua & Sui, 2011). Viscosity of drilling fluid is a very important parameter: it
has to be sufficient to support drilled solids and prevent sagging, yet should not exceed
pumping capabilities of a rig equipment, so that desirable flow regimes in a drilling string
and annular space could develop. Viscosity of drilling fluids also affects their filtration
rates, which will be described in more detail in the next section. An industry-standard
viscometer was used to measure rheology of drilling samples in the lab in order to
determine an impact of nanoparticles addition. Another important feature of drilling fluids
is gel strength. It allows the fluid to thicken when circulation is stopped, such as when
making a connection or during a trip in/out, which suspends solids and prevents their
settling due to gravity.
c) Volume composition. A relative ratio of solid and liquid components in a drilling fluid is
an important parameter that affects final mud properties and is maintained within a range
specified in a mud program. Generally, increase in a volume concentration of suspended
solids has a negative impact on a drilling operation and results in a reduced rate of
penetration (ROP), increased viscosity and mud weight, increased wear on the equipment
3
and formation damage (ASME, 2005). A variety of solids control equipment exists that
help to manage solids content, of which shale shakers and centrifuges are the most common
(ASME, 2005). A typical range of solids found in most drilling fluids is 1–15% vol/vol.
Another important parameter, which applies to oil-based drilling fluids (OBM) that contain
both an oil and an aqueous phase, is the oil to water ratio (OWR). Volume composition of
drilling fluids is measured using a retort analysis, which employs fractional distillation at
high temperature to separate major components of a system.
d) Filtration control. The afore-mentioned overbalanced conditions cause near-wellbore
invasion of drilling mud filtrate and fine particles into permeable, porous or fractured
formations. This leads to reduced return permeability and is known as formation damage.
Depending on the pressure gradient, the nature of wellbore and formation fluids, and the
lithology, very large volumes of drilling fluid can be lost. When fluid loss occurs in the
pay zone, it can lead to significant declines in production. This is partially circumvented
using filtration control agents or lost circulation materials (LCM) that bridge over the pore
or fracture opening, form a filter cake, and reduce the flux of drilling fluid filtrate into the
formation. A wide variety of fibrous and granular materials have been used as LCM to
reduce mud loss, including nut shells, cellophane flakes, crushed rubber, micronized
marble, polymers, bitumen, calcium carbonate, and others (Caenn et al., 2011). An API
fluid loss test is a standard method for performance evaluation of filtration properties of
drilling fluids. Therefore, it served as a primary indicator in development of an optimum
formulation containing nanoparticles.
e) Electrical stability. Electrical stability (ES) is used to quantify stability of W/O emulsions
based on electrical resistance of a liquid medium between two electrodes. A ramped
4
voltage is applied until the current connects the two electrodes. Since an oil phase is non-
conductive, electrical stability of an emulsion is a function of a number, size, and ionic
strength of the dispersed aqueous droplets. In the case of OBM, solid content of an oil
phase can also have an impact on the electrical stability, especially if a high concentration
of conductive particles is present (Growcock et al., 1994). As a result, a decrease in the
electrical stability in an invert emulsion generally indicates an increase in the average size
of water droplets that more readily conduct current than the smaller and better dispersed
ones. A typical electrical stability tester used in the drilling fluids industry is tuned so that
a non-conductive, pure base oil gives the maximum reading of 1999 V, whereas fresh water
gives a reading of 2–5 V. The higher the value, the better the stability of a W/O emulsion,
therefore effects of different mud additives can be investigated.
1.2 Types of drilling fluids
Three major types of drilling fluids can be identified based on their primary continuous phase,
which can be either water, oil, or gas (Caenn et al., 2011). Water-based muds (WBM) and OBM
exhibit different properties, and are selected based on a drilling program, geology, environmental
concerns, and production economics. Gas-based drilling was not consider in this work and
therefore is outside the scope of this discussion.
WBM are based either on fresh water, sea water, or a brine (Caenn et al., 2011). Other
components depend on a particular application and drilling requirements, and may include LCM,
lubricants, polymers, flocculants, dispersants, surfactants, shale stabilizers, corrosion inhibitors,
and others (Caenn et al., 2011). While WBM offer certain advantages compared to OBM, such as
lower cost and minimal environmental impact, they suffer from a number of significant drawbacks.
5
For instance, water has intrinsically greater coefficient of friction than oil, resulting in increased
torque and drag experienced by a drilling string. Moreover, WBM exhibit poor stability at high
reservoir pressures and temperatures, which limits their performance in deep wells or locations
with high a geothermal gradient. Another issue associated with WBM is swelling of shales due to
water adsorption and ionic exchange. This can lead to wellbore instability, stuck pipe, ballooning,
washout, and other undesirable effects (Sensoy et al., 2009).
OBM are typically based on invert emulsions formed by a continuous oil phase and a
dispersed aqueous phase, although some drilling fluids may use base oil alone. On the one hand,
OBM do not suffer from the same problems associated with WBM; but on the other hand, they
have high cost ($1000–$2000/m3 of base oil as of 2015) and are considerably toxic to the
environment (Caenn et al., 2011). Since the upper wellbore sections often contain unconsolidated
and permeable formations, large volumes of mud can be lost, which is very costly and has
disastrous consequences on the environment. As a result, a common practice in the industry is to
drill and complete a surface hole using WBM, followed by OBM for the remainder of a well. A
surface casing is usually set and cemented at a depth of approximately 500–600 m, which serves
to isolate wellbore fluids, prevent their contact with a formation, and protect underground aquifers
from contamination with oil based filtrate. Subsequently, WBM is displaced to invert, a cement
plug is drilled out, and an intermediate well section begins.
1.3 Mud circulation system
A schematic of a typical drilling fluid circulation system is shown in Figure 1. At the surface, 50–
60 m3 of drilling fluid are continuously circulated between several in-line tanks, known as active
tanks. From there, displacement pumps drive the mud up the standpipe and down the drill string,
6
where it exits through high-shear jets of a drill bit. Drilling fluid then travels upward in the annular
space carrying cuttings to the surface. Mud return line passes through blowout preventers (BOPs)
and is directed onto vibrating mesh screens of shale shakers that separate drilling fluid from
cuttings. Wet cuttings are discarded, while mud and suspended solids small enough to pass through
the screens are collected in a settling tank below. Also known as a sand trap, it helps to remove
suspended solids due to gravity segregation. Finally, depending on the amount of desirable fine
solids, rheology, and density, drilling fluid is either redirected to rotor centrifuges first or returned
to active tanks, and the circulation cycle repeats. As the hole volume increases, more drilling fluid
is required to maintain the required volume in active tanks. Volume is increased with fresh mud
that is either mixed on-site using a pre-mix tank or delivered and stored in a rig tank farm. A typical
pre-mix tank has a capacity of 20 m3 and is used to condition a fresh batch of drilling fluid prior
to bleeding it into the active system. A pre-mix tank was also utilized during the field testing of
nanoparticle-based drilling fluids, as described in the experimental section.
Figure 1: A schematic of a rig mud circulation system.
7
1.4 Emulsions and surfactants
Emulsions are thermodynamically unstable mixtures of two or more immiscible fluids that form a
dispersed phase and a continuous phase (Rosen & Kunjappu, 2012). Based on a volume ratio
between phases, emulsions are traditionally classified as either oil-in-water (O/W, direct) or water-
in-oil (W/O, invert). A common example of an O/W emulsion is dairy milk, while OBM are
typically based on W/O emulsions.
Emulsions are formed when an appropriate mixture of fluids, such as water and oil, is
subjected to a high amount of shear. Shear can be in the form of shaking, blending, jet shear, or
sonication (Rosen & Kunjappu, 2012). High interfacial tension (IFT) between immiscible fluids
impacts the size and stability of the dispersed droplets. Smaller droplets have a higher surface
energy than the larger ones, and thus an emulsion is thermodynamically driven toward a lower
total energy. In a static system, this process can be observed as coalescence and growth of the
dispersed pools, which are driven by the Brownian motion and gravity segregation (Boyd et al.,
1972). Eventually, this deterioration of an emulsion resolves in a phase separation and loss of
functionality. The primary mechanism for destabilization of W/O emulsions is a spontaneous
process known as the Oswald ripening, which also affects invert emulsion drilling fluids subjected
to prolonged static conditions, such as during storage or rig down time (Voorhees, 1985).
Stability of emulsions can be greatly improved using a special class of aphiphilic
compounds, also known as surfactants or emulsifiers, which are partially soluble in both phases.
Surfactants contain a hydrophobic tail, typically composed of a hydrocarbon chain, and a
hydrophilic head, which is either a highly polar or an ionic functional group. Solubility of an
emulsifier in water decreases with increasing chain length of a hydrophobic tail, while its solubility
in organic phase increases. When a surfactant is added to a binary mixture of water and oil, its
8
molecules orient along the interface such that its hydrophilic head is in the aqueous phase and its
hydrophobic tail is in the oil phase. This lowers the IFT and surface energy between the phases. A
free energy of the surface is further reduced with increasing concentration of a surfactant, until the
critical micelle concentration (CMC) is reached. The CMC of a surfactant is defined as a bulk
concentration of surfactant, at which its molecules begin to aggregate into micelles. It varies for
each type of a surfactant, depending on temperature, pressure, and the nature of immiscible fluids,
and can be either determined experimentally or obtained from the literature (Mukerjee & Mysels,
1971). Further increase in the concentration of emulsifier above its CMC results in an increased
number of micelles. When shear is applied to such mixture, surfactant molecules dissolve in the
dispersed phase and form a monolayer surrounding the pools. Very small droplets can be formed
due to lower IFT, and their coalescence and growth are stabilized via electrostatic repulsion or
steric hindrance effects of a surfactant film. In some cases, shorter chained hydrocarbons are added
as co-surfactants that help to improve stability of an emulsion. They insert between their larger
counterparts at the interface of a dispersed phase and provide a steric stabilizing effect. As a result,
surfactant film becomes more ‘rigid’ and dispersed droplets reduce in size, which reduces the
possibility of coalescence and growth of droplets (Oh et al., 1993).
1.5 Invert emulsion drilling fluids
A liquid fraction of invert emulsion drilling fluids is composed of a continuous oil phase and a
dispersed water phase, which is stabilized with surfactants. A typical volume ratio of oil to water
(OWR) in commercial drilling fluids varies between 75/25–95/5. While various additives may be
present depending on a particular system, several most common components of commercial invert
emulsions are identified and summarized in this section.
9
a) Base oil. An oil phase of OBM is most commonly represented by long-chain petroleum
distillates, such as diesel (Cutter-D) or gas oil (Distillate 822). These aliphatic base oils
typically contain low aromatics and BTEX, with majority of chains in the C15+ range.
While Cutter-D and Distillate 822 have low cost and show good performance in a variety
of drilling conditions, they are classified as toxic and contain known carcinogens.
Alternatively, some environmentally sensitive drilling applications utilize invert emulsion
drilling fluids based on mineral or synthetic base oil. A common example is the Amodrill
system based on synthetic C12–C14 α-olefins. Synthetic base oil is usually produced via
oligomerization of monomers, which ensures uniform composition and absence of heavy
metal contaminants. Synthetic or mineral base oils have intrinsically lower density and
viscosity than diesel or gas oil and are typically used in deep water drilling, where
formations often have a narrow mud pressure window.
b) Aqueous phase. An aqueous phase of invert emulsion drilling fluids is typically composed
of a brine of calcium chloride with a concentration varying between 20–40% w/w. A high
concentration of chlorides (>100,000 ppm [Cl–]) is used to provide osmotic pressure
against saline interstitial water. The second most common aqueous component is a
saturated solution of calcium hydroxide.
c) Emulsifiers. Most commonly used emulsifiers in oil-based drilling fluids are divalent soaps
of anionic carboxylic acids of varying chain length, degree of branching, and saturation.
Divalent salts of fatty acids are formed by reaction of carboxylic group with Ca2+ ions,
which are usually provided in the form of hydrated lime, Ca(OH)2. Calcium soaps of fatty
acids are better suited to form reverse micelles in W/O emulsions, as opposed to salts of
alkali metals, which are used to prepare O/W emulsions. Commercial blends of emulsifiers
10
are available as technical-grade mixtures of several fatty acids and secondary emulsifiers,
so the exact composition can deviate from batch to batch and is challenging to determine.
Several types of commercial emulsifiers have been investigated in this work, however the
primary component in all cases was a C16–C18 fatty acid, such as palmitic, oleic, or stearic
acid.
d) Wetting agents. Wetting agents are surfactants of varying structure and composition that
are used to impart oil wettability to suspended solids in OBM. Water-wet solids tend to
aggregate and agglomerate, thus increasing rate of solids settling and sagging.
Furthermore, adsorption of wetting agents by water-sensitive shales results in hydrophobic
rock surface that helps to prevent swelling. Wetting agents are commonly included as part
of commercial blends of primary and secondary emulsifiers, but also are available as
separate products at most rig sites.
e) Hydrated lime. Hydrated lime, slacked lime or lime, are all common names for calcium
hydroxide, which is used to activate anionic emulsifiers in W/O drilling fluids. While
excess lime remains in the suspension and contributes to a total solids fraction, a small
amount is dissolved in the aqueous phase reaching its saturation point (1.73 g/L at standard
conditions). This functions to provide alkalinity to the aqueous phase, where pH above 10–
11 is preferred to improve interaction with anionic surfactants.
f) Organophilic clay. A surface-modified bentonite clay is used in W/O drilling fluids as a
rheology modifier and a filtration control agent. With its surface coated with an
organophilic compound, bentonite readily disperses in oil phase even at low shear and
increases viscosity and gel strength of a mud. In addition, clay platelets serve as bridging
agents and reduce mud filtration.
11
g) Calcium carbonate. Calcium carbonate is the most abundant LCM used in most WBM and
OBM. It is the primary component in limestone rock and typically is produced in industry
by crushing and milling limestone rock, making it an inexpensive and benign material.
Several grades of calcium carbonate are available based on the mean particle size, which
normally ranges between 10 µm–1 mm (Cargnel & Luzardo, 1999). Most drilling
applications utilize blends of several calcium carbonate grades to achieve broad size
distribution in the mud. A long history of application of calcium carbonate in drilling fluids
rendered it a good candidate for nanoparticle research and field implementation, which is
a focus of this contribution.
h) Gilsonite. Gilsonite is a naturally occurring asphaltene hydrocarbon used as a loss control
additive in OBM. Its particle size varies between 150 µm–5 mm, and it is responsible for
a characteristic black-brown colour of invert emulsion drilling fluids.
i) Barite. Barite is a natural mineral from of barium sulfate. It is a dense material (SG 4.2)
and is used as a weighting agent in drilling fluids. Due to limitations of mechanical crushing
used in a large-scale production of barite, particle size distribution is typically broad, which
may increase possibility of sag, especially in lateral wellbore sections or when large
quantities of barite are required to increase mud weight.
j) Graphite. Granular graphite with varying particle size is used in drilling fluids as an LCM
and lubricant additive.
1.6 Mechanism of fluid loss and cross-flow filtration
Dynamic filtration of drilling fluids has been investigated extensively in an attempt to mitigate
mud losses and formation damage in troublesome geological zones, such as porous, permeable,
12
unconsolidated, fractured, vuggy, or depleted formations (Al-Hitti et al., 2005; Bennion et al.,
1997; Chin, 1995). Three main stages of fluid flow can be identified in a theoretical analysis of
dynamic mud filtration, namely spurt loss, cake growth, and cake equilibrium (Jiao & Sharma,
1994).
Spurt loss refers to the flux of filtrate at the early times of filtration, before the filter cake
is formed. It can be approximated using a radial form of Darcy’s law, which is given by the
following flow equation:
𝑞𝑠 =
2𝜋𝑘𝑓ℎ𝑓(𝑃𝑤 − 𝑃𝑓)
𝜇ln(𝑟𝑒𝑟𝑤)
(Eq. 1)
where 𝑞𝑠 is the rate of spurt loss (mL/s); 𝑘𝑓 is the permeability of formation (D); ℎ𝑓 is the formation
thickness (cm); 𝑃𝑤 is the wellbore pressure (atm); 𝑃𝑓 is the formation pressure (atm); 𝜇 is the
viscosity of mud filtrate (cP); 𝑟𝑒 is the external radius of formation (cm); 𝑟𝑤 is the wellbore radius
(cm).
Eq. (1) shows that the dynamic flow rate of filtrate in the absence of a filter cake is directly
proportional to the permeability of the formation and the pressure gradient, and inversely
proportional to the viscosity of the mud. As a result, spurt loss in overbalanced drilling can be very
high, especially in the case of highly permeable formations, leading to deep invasion of mud,
damage, and high losses.
Flow of filtrate in the radial direction gives rise to a hydrodynamic drag force, which carries
suspended particles towards the borehole wall. Depending on the particle/pore size ratio, they
either pass through larger openings or get retained at the wall. Liquid and solid particles that pass
through the opening travel further into the formation, where they are eventually immobilized due
to the combined effect of sedimentation, direct interception, and surface attractive forces (Bezeme
13
& Havenaar, 1966). Larger particles normally deposit first followed by smaller ones, as per the
size exclusion principle, and an internal filter cake begins forming. This can cause severe
permeability impairment and formation damage. Conversely, particles that are approximately one
third the size of the opening and larger, get screened out at the wellbore wall and form the external
filter cake. Filtrate flux through the cake becomes a function of pressure drop across the cake as
well as its thickness and permeability. The transitional flow regime can represented
mathematically by the following equation:
𝑞𝑐 =
2𝜋𝑘𝑐ℎ𝑓(𝑃𝑤 − 𝑃𝑐)
𝜇ln(𝑟𝑤𝑟𝑐)
(Eq. 2)
where 𝑞𝑐 is the filtrate flux during transitional period (mL/s); 𝑘𝑐 is the permeability of the filter
cake (D); 𝑃𝑐 is the pressure at the inner boundary of the filter cake (atm); 𝑟𝑐 is the inner radius of
the filter cake (cm).
As more particles are deposited at its surface, the cake continues to grow, and its
permeability and thickness increase, causing reduction of the filtrate flow rate. Consequently,
pressure drop reduces, and the drag force becomes weaker, so that only smaller and smaller
particles are delivered and deposited at the cake surface, until no particles small enough are present
in the mud. This gives rise to an inhomogeneous distribution of particles throughout the cake,
which in turn affects particle packing, porosity, and permeability. Cake growth rate decreases until
it reaches its equilibrium thickness, at which point a steady state filtrate flow is established. Under
dynamic conditions, circulating mud exerts shear stress and erodes the surface of the cake,
therefore its characteristic thickness is achieved when a normal force keeping particles at its
surface arrives at equilibrium with a tangential force acting to detach them.
14
Jiao and Sharma (1994) proposed a widely accepted mechanism for filter cake build up,
which concluded that the solids deposited at the cake surface experience colloidal interactions with
neighbouring particles. Surfaces forces include van der Waals, electrostatic, structural, and Born
forces (Jiao & Sharma, 1994). As the mean particle size decreases, the surface forces act over
shorter separation distances and become more significant. At very small, submicron or nanometer
separation distances, surface forces become orders of magnitude greater than the hydrodynamic
forces, which themselves act over much longer distances. This leads to irreversible particle
attachment and increases resistance of the cake to erosion.
The aforementioned mechanism suggests that the extent of drilling filtrate invasion and
formation damage is strongly dependent on the particle/opening size ratio and can be drastically
reduced if a cake with low permeability is formed rapidly. Since geology can vary greatly
throughout a given well, typical drilling fluids contain a mixture of loss additives to attain wide
particle size distribution and effectively seal appropriately sized openings. However, commercial
filtration materials range anywhere from several µm to several mm in size, which makes them
unsuccessful creating a filter cake in the cases where openings are in the submicron domain, such
as in shales or induced micro-fractures (Nelson, 2009). Given that enough pressure gradient is
provided, mud filtrate can still invade into such formations and cause a number of problems,
including fracturing, clay swelling, obstructed formation evaluation, borehole instability, washout
or collapse (Zamora et al., 2000). A proposed model of filtration in the presence of conventional
micron-sized LCM and NPs is illustrated in Figure 2 (A and B, respectively).
15
Figure 2: Drilling fluid filtration in the presence of conventional LCM (A) and NPs (B).
Filtration properties of drilling fluids can be evaluated in the lab using an industry-standard
American Petroleum Institute (API) fluid loss test. An API low pressure, low temperature (LPLT)
fluids loss experiment applies to WBM, while OBM are tested at high pressure and temperature
(HPHT) to approximate reservoir conditions. Both tests share the same principle and are based on
static filtration of mud through a specially-hardened filter paper, which substitutes a porous
medium. Filtrate is collected at specified time intervals, and the total volume of filtrate collected
in 30 min is used to quantify performance of drilling fluids. Filtrate flux in this case is given by a
one dimensional form of Darcy’s law (Chelton, 1967):
𝑞𝐴𝑃𝐼 =
𝑘𝑐𝐴∆𝑃
𝜇ℎ𝑐 (Eq. 3)
where 𝑞𝐴𝑃𝐼 is the API fluid loss rate (mL/s); 𝐴 is the cross-sectional filtration area (cm2); ∆𝑃 is the
pressure differential (atm); ℎ𝑐 is the thickness of the filter cake (cm).
16
API fluid loss is typically performed at fixed pressure differential, temperature, and surface
area, so that the volume of filtrate is only a function of viscosity of mud and cake parameters.
While the API fluid loss test is the most accepted practice in the drilling industry, it poorly
represents the actual conditions encountered in dynamic filtration through a permeable rock.
Correlation between lab fluid loss and real downhole losses has long been a subject of debate, but
the general observed trend is that subsurface losses tend to be lower in drilling fluids that provide
low LPLT or HPHT volumes (Villas-Boas et al., 1999). Other less common lab techniques used
to evaluate loss prevention include dynamic filtration, core testing, and permeability plugging (Al-
Riyama & Sharma, 2004).
1.7 Nanoparticles in oil and gas
According to a strict definition, nanoparticles are classified as materials with a size in the range of
1–100 nm (Cao, 2004). However, it should be pointed out that in the context of this work, the term
‘nanoparticles’ is used more loosely to refer to a range of submicron size distributions spanning
between 1–1000 nm.
As a particle becomes smaller, its surface area, which is defined as m2/g, increases
accordingly. This leads to a high surface activity and imparts unique physical, chemical, electrical,
thermal, and reactive properties to nano-scale materials that are typically not exhibited by their
larger counterparts with identical chemical structures. Nanotechnology has seen wide-spread
applications in such diverse industries as medicine, electronics, fuel cells, food, and various
consumer products (Cao, 2004). In recent years, a significant research effort focused on potential
applications of nanomaterials in the oil and gas industry. Some of the areas that showed useful
benefits of NPs include heavy oil upgrading (Nassar et al., 2011), enhanced oil recovery (Haroun
17
et al., 2012; Skauge et al., 2010), hydraulic fracturing (Huang et al., 2010), cementing operations
(Patil & Deshpande, 2012), and drilling, drill-in, completion, stimulation, and workover fluids
(Amanullah & Al-Tahini, 2009; Zakaria et al., 2012). Applications of nanomaterials in drilling
fluids are reviewed in more detail in the paragraphs that follow.
Majority of wellbore instability problems associated with WBM are caused by invasion of
water filtrate into shale formations, which in turn comprise 75% of all the lithologies drilled
(Sensoy et al., 2009). Often, the only alternative is to drill with OBM instead; however, this
drastically increases drilling cost and can be damaging to the environment. As a result, a number
of recent studies investigated the use of nanoparticles to increase shale stability. For instance,
Sensoy et al. (2009) used a pressure transmission technique to show that water invasion in shale
samples was reduced in the presence of commercial silica nanoparticles. Water-based mud samples
were prepared using two sizes of ex-situ particles, 5 nm and 20 nm, while their concentration
varied between 5–40 wt%. Experimental results showed that nanoparticles reduced filtrate
invasion in Atoka shale by 98% compared to pure sea water. Recycled drilling fluids also benefited
from the addition of NPs, where fluid invasion was reduced by 16–72% in Atoka shales and by
17–27% in the Gulf of Mexico shale. Scanning Electron Microscopy of shale samples revealed
that nanoparticles and their agglomerates were effective plugging a range of pore throat sizes,
which lead to a 10-fold reduction in permeability. However, noticeable performance was only
achieved at concentrations of NPs above 10 wt%.
Cai et al. (2012) reported similar results in permeability plugging experiments on Atoka
shale samples using seven different commercial nanomaterials with the size between 7–15 nm.
Study of the effect of nanoparticle concentration suggested that fluids containing 10 wt% of NPs
reduced permeability of shale samples by 73–99%.
18
Amanullah et al. (2011) formulated several water-based drilling fluids using three
commercial nanomaterials. It was shown that properties of mud samples were enhanced at low
concentration of NPs (<0.5 wt%) compared to formulations containing conventional macro-sized
additives. In addition to good stability, rheology and gel strength, nano-fluids reduced API spurt
loss and formed a thin mudcake, which is highly desirable. The superior performance of nano-
fluids was attributed to surface interactions that were more dominant on a nano-scale than the
physical forces.
Zakaria et al (2012) investigated the application of nanoparticles for fluid loss reduction in
invert emulsion drilling fluids. Both commercial as well as in-house nanomaterials were tested,
which showed that particles synthesized within the drilling fluid exhibited far superior
performance. Experimental results suggested that in situ NPs were well dispersed and stabilized,
and therefore interacted more favourably with other components in the matrix. While commercial
nanomaterials provided only a negligible LPLT fluid loss reduction of 7%, in-house particles
minimized spurt loss and resulted in 70% lower filtrate volumes.
Nwaoji et al. (2013) introduced a drilling fluid that contained a blend of graphite and in-
house nanoparticles. Hydraulic fracturing experiments were conducted on Roubidoux sandstone
and concrete core samples to investigate potential applications of NPs in wellbore strengthening.
Fluids containing iron- or calcium-based NPs increased fracture pressure resistance of sandstone
by 70% and 36%, respectively. Furthermore, a 25% increase in fracture pressure of impermeable
concrete cores suggested that NPs could provide wellbore strengthening in tight or shale
formations.
Contreras et al. (2014a, 2014b, 2014c) further demonstrated that in-house nanoparticles at
concentrations of 0.5–2.5 wt% reduced HPHT fluid loss in commercial drilling fluids and
19
increased strengthening in sandstone and shale cores. Fracture pressure in sandstone was increased
by up to 65%, while a 30% increase was achieved in shale samples. SEM and EDX analysis of
core samples showed that the induced fractures were sealed with NPs along their entire length,
which suggested a tip screen-out mechanism of wellbore strengthening (Contreras et al., 2014c).
1.8 Emulsion-based synthesis of nanoparticles
There exists a variety of techniques used in the manufacturing of nanoparticles, which are
arbitrarily classified as either dry or wet (Husein & Nassar, 2008). Dry techniques normally
employ mechanical milling to reduce the average particle size (Midoux et al., 1999). Alas, such
approach makes it difficult to control the average size, shape, and properties of the final materials.
Conversely, wet techniques are based on the formation of nanomaterials starting from chemical
precursors and include chemical coprecipitation, sonochemical, electrochemical, reverse micelles,
and sol-gel methods (Husein & Nassar, 2008). Unlike the dry approach, wet techniques can be
tailored to produce nanoparticles with desirable properties (Jolivet et al., 2004). Furthermore,
nanomaterials produced via a wet chemical reaction do not require handling of nano-powders and
hence do not produce potentially hazardous airborne particles.
Chemical coprecipitation of aqueous precursors remains one of the most economic and
versatile processes that could be implemented on a large scale. The method is based on a reaction
between appropriate aqueous solutions that forms an insoluble product, and usually requires a
control mechanism for achieving size distribution in the nanometer domain. In addition to a wide
variety of inorganic nano-materials that can be produced via this approach, their shape, size, and
surface properties can be fine-tuned to meet the required specifications (Parida et al., 2009).
20
Two main stages can be identified in the process of coprecipitation in bulk aqueous phase:
nucleation and growth (Koutsoukos & Kontoyannis, 1984; Taubert et al., 2002). During the
primary nucleation, anionic and cationic species combine, reach local supersaturation, and
precipitate to form an initial crystal. Once formed, seed crystals affect the formation of subsequent
crystals via the process of secondary nucleation. Crystal grows by coming in contact with dissolved
precursors, where it functions as a substrate for the formation of sequential layers. Since smaller
crystals have higher free energy, large particle size is thermodynamically preferred. As a result,
particles have broad size distribution in the micron or even millimeter domain, which is illustrated
in Figure 3 (top).
Size control during coprecipitation in bulk aqueous phase can be achieved by separating
the nucleation and growth processes, which is accomplished either mechanically or chemically.
High shear conditions disrupt crystal growth and increase the number of nucleation sites, which
limits the final particle size. Alas, such high shear mixing is difficult to attain on a large scale, as
was learned in the process of this work. Chemical methods of size control may include surfactants,
polymers or other materials capable of interacting with a crystal face and preventing its growth
(Taubert et al., 2002).
21
Figure 3: A schematic of chemical coprecipitation using bulk aqueous phase (top) and a reverse
micelle approach (bottom).
An alternative to a bulk-phase reaction is known as a reverse micelle or microemulsion
approach (Husein & Nassar, 2007a, 2007b, 2008). This method utilizes invert emulsions, in which
micelles act as individual reactors during coprecipitation. A schematic of a typical process is
provided in the bottom of Figure 3 and can be described as follows. First, two separate invert
emulsions are prepared for each of the precursors using a stoichiometric mixture of oil phase,
surfactants, and aqueous solutions. Next, the invert emulsions are mixed together and shear is
applied. Dispersed water droplets collide, coalesce, exchange solute molecules, and break up
again, until the precursors are fully consumed. Since the amount of available ions, that otherwise
would contribute to crystal growth, is limited by the concentration in each individual droplet, the
average particle size tends to be restricted to a nanometer domain (Husein & Nassar, 2008).
Furthermore, nanoparticles either remain dispersed within the individual pools or interact with a
hydrophilic group of emulsifiers and cross the monolayer into the oil phase, where they are
22
stabilized due to a repulsive effect of a surfactant. This prevents collision and agglomeration of
particles and ensures a narrow size distribution, which often cannot be achieved in a bulk phase
process.
Similar principle, albeit a few modifications, was adopted for an in situ synthesis of
calcium carbonate nanoparticles in invert emulsion drilling fluids. Instead of two separate
emulsions, a single drilling fluid system was utilized. The first aqueous precursor was added to an
invert, where it became emulsified and introduced solute molecules to the already existing water
droplets. Subsequently, the second aqueous precursor was titrated slowly into the system under
continuous mixing. Water droplets containing a counterion were then formed, and a
coprecipitation reaction proceeded according to the two-emulsion mechanism described above.
1.9 Research objectives
Work by Zakaria et al. (2012) served as a starting point of this project. On the one hand, it was
demonstrated that not only invert emulsion drilling fluids can be utilized to synthesize in situ NPs,
but also that such samples exhibited much better filtration properties than those containing ex-situ,
commercial NPs. On the other hand, the process targeted low concentration of NPs in order not to
compromise the stability of the resultant dispersion and was limited to laboratory-scale
preparation. Moreover, it is also important to prove the concept by testing a broad variety of
drilling fluid systems, both virgin and recycled. To summarize, this project focused on the
following key research objectives:
1) Modify the existing technique for the in situ synthesis of calcium carbonate NPs in invert
emulsion drilling fluids in order to ensure a scalable, safe, and cost-effective process.
23
2) Expand the variety of tested drilling fluids in order to prove the concept. In addition to fluid
loss, investigate the impact of NPs on mud weight, OWR, solid content, ES, and rheology
in virgin and recycled mud systems.
3) Develop a scalable method for manufacturing of NPs based on a concentrated carrier
emulsion. Optimize the formulation to achieve a stable emulsion at a high concentration of
NPs and compare performance of this dispersion delivery mechanism to that of the direct,
in situ synthesis.
4) Establish a baseline performance of a final lab formulation using several common invert
systems and replicate the process on a large scale. Conduct a full-scale field test of the final
formulation in a live well. Analyze the data and determine potential impact on losses and
a drilling operation as a whole.
5) Develop a theoretical framework to interpret the results and investigate the applicability of
carrier emulsion approach in synthesis of other types of NPs. Develop standard operating
procedures and provide recommendations for future work.
24
CHAPTER TWO: MATERIALS AND METHODS
2.1 Chemicals and precursors
All chemicals were used as received, unless specified otherwise. Calcium chloride anhydrite
(technical grade, 96-98%) and potassium carbonate anhydrite (technical grade, 95%) were
obtained from Univar Canada (Calgary, Alberta) and used as precursors in the lab bench synthesis
of calcium carbonate NPs. Salts were dissolved in deionized water to prepare 45% w/w and 50%
w/w stock solutions, respectively. Dissolution reaction is exothermic is both cases, so proper
precautions must be taken. Stock solutions were stored at room temperature without visible
recrystallization and used as required.
A large-scale synthesis of calcium carbonate was based on a 50% w/w solution of K2CO3
and 45% w/w solution of CaCl2, both supplied by Univar Canada (Calgary, Alberta). Solutions
were received in 1 m3 totes and stored at a mixing facility where product manufacturing took place,
until required. A Distillate 822 base oil, a premium blend of emulsifiers and wetting agents,
Bentone 150 organophilic clay, and hydrated lime were obtained from Gibson Energy (Sexsmith,
Alberta, Canada).
2.2 Drilling fluids sample preparation
Three virgin and three recycled samples of drilling fluids were tested in the lab, as summarized in
Table 2-1 below. In order to eliminate effect of shear on the measured properties of the samples, a
standard operating procedure for mixing and handling was developed based on the API
Recommended Practices (API, 2014) and International Organization for Standardization
procedures (ISO 10416:2008, 2014). Drilling fluids were first well mixed either via vigorous
shaking or using a stationary dispersator operating at 3,000–4,000 rpm (FANN, USA) to ensure
25
homogenous composition. Subsequently, they were subjected to high shear for 30 min. Depending
on the sample volume, either a Hamilton Beach HMD-200 mixer operating at 7,500 rpm or a
Waring Lab Blender (Model #6012G) operating at 6,500 rpm was used. Finally, fresh samples
were allowed to age and develop at ambient conditions for 10–15 min before being tested. A
typical sample volume ranged between 200–600 mL, and minimum of three replicates per
experiment were sheared separately to reduce experimental errors. Control samples and
formulations containing in situ NPs were obtained from same batches of drilling fluids to ensure
reproducibility.
Table 2-1: A summary of commercial drilling fluid lab samples.
Name Supplier Base Oil Virgin/Recycled Mud Weight (kg/m3) O/W Ratio
Cutter-D Bri-Chem Diesel Virgin 1030 90/10
Escaid 110 DSCo Mineral Virgin 913 80/20
Diesel OBM DSCo Diesel Virgin 975 78/22
Cutter-D Blackstone Diesel Recycled 1070 85/15
Distillate
822 Blackstone Diesel Recycled 1090 85/15
Megadrill MI Swaco Diesel Recycled 1150 85/15
2.3 Drilling fluids testing
2.3.1 Mud weight
Mud weight was measured at 22 °C and standard pressure using a FANN Model 140 mud balance
(Part No. 206768, FANN, USA), shown in Figure 4. Three measurements were collected per
sample following a high-shear mixing protocol, as described above. Prior to taking a reading, mud
holder was tapped with a metal cap to release bubbles of dissolved gas.
26
Figure 4: A FANN Model 140 mud balance.
2.3.2 Electrical stability
Electrical stability of invert emulsion drilling fluids was measured with an OFITE electrical
stability tester (Model #131-50, OFI, USA), which is shown in Figure 5. The meter was calibrated
on a regular basis using standards. Sample of drilling fluid was first subjected to 30 min shear and
then transferred into a FANN heating cup (Part No. 101558383, FANN, USA) set at 50 °C.
Temperature was allowed to equilibrate over a 10 min period, after which a sample was rapidly
stirred for 2–3 sec using a probe, and the reading was taken.
Figure 5: An OFITE electrical stability tester (Model #131-50).
27
2.3.3 Rheology and gel strength
A Fann Model 35 viscometer (FANN, USA) was used to measure rheology of drilling fluids
samples, as shown in Figure 6. Similarly to the procedure for electrical stability described above,
samples were sheared for 30 min and transferred to a heating cup. Heating cup was raised to cover
the bob and the viscometer was set to 600 rpm for 10 min. Subsequently, the readings were taken
at 600, 300, 200, 100, 6, and 3 rpm. Finally, gel strength was measured at 10 sec and 10 min. Gel
strength is an important property of drilling fluids, which allows them to thicken and support solids
during stopped circulation. It is defined as the peak meter reading achieved when a bob is rotated
at 3 rpm following an appropriate static period. Readings at 600 and 300 were used to calculate
yield point and plastic viscosity per the following equations:
𝜇𝑝 =𝜃600 − 𝜃300 (Eq. 4)
𝜏𝑦 =𝜃300 − 𝜇𝑝 (Eq. 5)
where 𝜇𝑝 is plastic viscosity (cP); 𝜏𝑦 is yield point (lb/100 ft2); 𝜃300 and 𝜃600 are dial readings at
300 and 600 rpm, respectively.
Figure 6: A Fann Model 35 viscometer.
28
2.3.4 HPHT fluid loss test
HPHT experiments were carried out using a 175 mL single-capped OFITE HPHT filter press with
a 40 cm2 filtration area (Model #170-00, OFI, USA), shown in Figure 7. Samples were sheared
and ~160 mL were loaded into a mud cell. Cell was then assembled and placed inside a heating
jacket, where it was allowed to reach the target temperature over a 30 min period. Temperature
varied between 80–120 °C to match the testing conditions used by mud companies. During the
first 30 min, 100 psi of pressure were applied by means of compressed CO2 bulbs for 30 min to
suppress vapour pressure build up. Subsequently, pressure differential was increased to 500 psi
and the bottom valve stem was opened to initiate filtration. Volume of filtrate was recorded after
30 min and reported as a multiple of 2 to convert the filtration area to the API standard. Cell was
then emptied and the thickness of a mud cake was measured using a digital calliper with accuracy
of ±0.1 mm. Three readings were taken at different sites of a cake and reported as an average.
Figure 7: An OFITE HPHT filter press (Model #170-00).
29
2.3.5 Retort analysis
Retort analysis of mud composition was performed using an OFITE 50 mL retort kit (Part #165-
14), as depicted in Figure 8. Sample cup was filled with a freshly sheared invert in several portions,
followed by gentle tapping to release dissolved gas, until the fluid level reached the top of the cap.
Fine steel wool was packed into the top part of the holder to prevent non-volatile components from
entering the condenser. Liquid fraction was collected in a 50 mL graduated cylinder, and the
experiment was stopped when the volume remained constant for 10 min. Total volume in the
cylinder, as well as the volume of the bottom aqueous phase were recorded and used to calculate
volumetric composition of the mud as follows:
𝑆𝑜𝑙𝑖𝑑𝑠(𝑣𝑜𝑙%) =
50 − 𝑉𝑡50
× 100% (Eq. 6)
𝑂𝑊𝑅 =
𝑉𝑡 − 𝑉𝑤𝑉𝑡
× 100 ∶ 𝑉𝑤𝑉𝑡
× 100 (Eq. 7)
This approach provides ‘uncorrected’ volumetric ratios as it does not account for the
concentration of chlorides and other ions in the aqueous phase, which remain in the solid phase
after evaporation of liquid components. However, the addition of the NPs results in only negligible
increase in chlorides, so this method was deemed appropriate for relative comparison between
control samples and samples with NPs.
30
Figure 8: An OFITE 50 mL retort kit (Model #165-14).
2.4 In situ synthesis of NPs
In situ synthesis of calcium carbonate NPs, both bench- and field-scale, was based on a reverse
micelle method described previously. Bench scale synthesis was carried out using a 300 mL
sample volume and a Hamilton Beach mixer equipped with a wave spindle and operating at 7,500
rpm. The reaction between aqueous precursors proceeds according to the following equation:
𝐶𝑎𝐶𝑙2(𝑎𝑞) + 𝐾2𝐶𝑂3(𝑎𝑞) → 𝐶𝑎𝐶𝑂3(𝑠) + 2𝐾𝐶𝑙(𝑠)
In situ synthesis was carried out as per the following procedure. First, a target volume of
mud with a known density was determined and used to calculate the mass of calcium carbonate
required to achieve a desirable concentration, which in the case of this work was 0.5 wt%. Next,
reaction stoichiometry and molecular weights of reactants and products were used to calculate the
mass of the precursors. The latter was then converted to the mass of a corresponding aqueous
solution with known concentration. Finally, the mass was divided by a density of aqueous solutions
(measured or theoretical) to obtain the required volume of each of the precursors. Appropriate
volumes of precursors were drawn into 10 mL plastic syringes and added slowly, drop wise into a
31
shearing invert sample. Calcium chloride was added first, which was followed by a 10 min mixing.
After sufficient time was given for droplets of calcium chloride solution to reduce in size and
interact with emulsifiers, potassium carbonate was added slowly to the system. Sample was
sheared for additional 30 min to ensure formation of calcium carbonate NPs. A slight color change
and temperature increase indicated that the coprecipitation reaction took place.
2.5 Carrier emulsion synthesis
The aforementioned in situ formation of NPs typically requires high shear and good micro-mixing
to produce submicron particles, which is difficult to realize on a large scale. Instead, a custom
invert emulsion with a high concentration of calcium carbonate NPs was produced and used as a
carrier to deliver NPs to a compatible drilling fluid via volume dilution. Both bench- and field-
scale methods were modeled after the in situ preparation and employed the same aqueous
precursors to precipitate calcium carbonate NPs. To ensure the possibility of scale up, a
formulation was based on commonly used and commercially available mud products, and its basic
properties were designed to closely match those of typical invert emulsion drilling fluids. Cost
effectiveness of a large-scale production via this approach depends on the concentration of NPs
that can be achieved in a carrier emulsion. On the one hand, a higher concentration would result
in a lower volume of carrier required to achieve a target concentration of NPs on-site. On the other
hand, since this method utilizes aqueous precursors, there is a limit on how much water an invert
emulsion system can accommodate before it separates. Furthermore, high concentration of calcium
carbonate would inevitably affect the nucleation and growth processes, where abundance of
suspended crystals would increase rates of aggregation and agglomeration. Long-term observation
has shown that a 5 wt% concentration of NPs provided the optimum emulsion quality, which was
32
stable after 1 week of static aging at ambient conditions. Various combinations of components
were tested until a formulation with the desirable properties was achieved. A typical formulation
of a carrier emulsion with 5 wt% concentration of calcium carbonate NPs is provided Table 2-2.
Table 2-2: A typical formulation of a carrier emulsion with 5 wt% of CNP.
Component Concentration
Base Oil 740–760 L/m3
Emulsifiers 35–45 L/m3
Hydrated Lime 27–30 kg/m3
CaCl2 (aq) 45% w/w 105–115 L/m3
K2CO3 (aq) 50% w/w 90–100 L/m3
Bentone 150 7.5–8.0 kg/m3
2.5.1 Bench-scale synthesis of a carrier emulsion
Lab-scale samples with a total volume of 300 mL were prepared using a Hamilton Beach HMD-
200 mixer. First, base oil was added to a mixing cup and sheared for several minutes. Next, a blend
of emulsifiers was added to the base oil and allowed to mix for additional 5–10 min. Subsequently,
an appropriate amount of hydrated lime powder was slowly added to a cup and allowed to react
with anionic surfactants over a 15 min period of time. Once sufficient time was given, aqueous
calcium chloride was added to the cup drop-wise while mixing. Shearing continued for 30 min to
allow formation of invert emulsion with a small droplet size. Aqueous potassium carbonate was
then added drop-wise. The rate of addition was adjusted to control exothermic effect of a
coprecipitation reaction, such that the temperature remained below 60–70 °C. Following the
addition of the second precursor, invert emulsion was mixed for a total of 30 min. Within 10 min,
33
its colour changed from dark brown to grey-white, which indicated formation of white calcium
carbonate precipitate. Bentone 150 was the last component added to the system and was used to
impart rheological properties and increase viscosity of an emulsion. Invert emulsions in the
absence of clays were not able to support high content of solids, which increased rates of settling
and separation of a suspension. The final product was mixed for additional 30 min before testing.
2.5.2 Field-scale synthesis of a carrier emulsion
Carrier emulsion for field testing was produced on a 20 m3 scale at a Gibson Energy toll mixing
facility located in Sexsmith, Alberta, Canada. Large-scale process utilized the same reagents,
concentrations, sequence and rate of addition, and mixing duration as in the bench-scale process
described previously. The facility was equipped to produce large batches of various OBM systems
and could accommodate volumes up to 75 m3 per batch. The primary mixing skid consisted of
three in-line tanks with 25 m3 capacity. Rather than using high-energy mechanical mixing to
achieve good shear and produce an emulsion, shear jet nozzles and a 150 HP centrifugal pump
were employed. The principle is based on injecting fluid under high pressure through a specially
designed constriction, thus creating a cavity on the other side of a jet. Significant pressure
differential causes the cavity to implode, which sends propagating shock waves through the
medium and achieves high-shear mixing.
The synthesis started by transferring an appropriate volume of Distillate 822 base oil to a
mixing skid, which was followed by emulsifiers. Hydrated lime was then added through a solids
hopper, which was also equipped with a shear jet to ensure good mixing and dispersion of solid
additives. The mixture was circulated for 1 h, and calcium chloride brine was slowly added to the
system through a mixing line at a rate of 40 L/min. Circulation continued for 1 h to ensure
34
formation of an invert emulsion. Subsequently, potassium carbonate brine was introduced in a
similar fashion at a rate of 30 L/min. Temperature of a flow line was monitored at regular intervals
to avoid excessive heat generation. Emulsion was mixed for additional 1 h to ensure completion
of the coprecipitation reaction before adding Bentone 150. Finally, the product was circulated for
1–2 h and transferred to a tanker truck for delivery to a rig site. At the same time, several litres of
carrier were collected for analysis. Mud weight and electrical stability were measured at the mixing
facility, while other properties were evaluated in a lab at a later time.
2.6 Particle characterization
Conventional analytical methods used to characterize nanoparticles are highly sensitive to
concentration and size distribution of solids, as well as the nature and homogeneity of a dispersant.
For instance, particle sizing techniques based on light diffraction (e.g. dynamic light scattering or
laser scattering) rely on a low degree of sample polydispersity and absence of large, agglomerating
or settling particles. As was mentioned earlier, drilling fluids are very complex system and contain
many solid additives, which gives rise to a broad size distribution. As a result, it becomes
extremely challenging to isolate and characterize just one component of the system. In addition,
invert emulsions are multi-component mixtures, therefore an aliquot of a well-mixed drilling fluid
sample contains a continuous oil phase, dispersed water droplets, and micelles of surfactant
molecules. This further hinders accurate analysis of particle size distribution using light scattering
techniques. A Malvern Zetasizer Nano-ZS (Malvern Instruments, UK) was used to analyze size of
calcium carbonate NPs produced in situ, but the data quality was rather low.
Similarly, Electron Scanning Microscopy (SEM) is routinely used to observe
nanoparticles, but high resolution is necessary to distinguish sub-micron particles, which is not
35
attainable with all instruments. Also, SEM chamber operates under vacuum, which precludes the
use of volatile samples, such as OBM. A special cryogenic system can be installed that uses liquid
nitrogen to freeze volatile samples, but in the case of this work it introduced a source of vibrations
that made it impossible to achieve high magnification. Although, an Energy Dispersive X-Ray
analysis (EDX) was used to confirm deposition of calcium carbonate within a filter cake following
HPHT filtration of a 5 wt% carrier invert. Freshly prepared carrier was filtered through an HPHT
press, and a small piece of a filter cake was quenched in liquid nitrogen and placed in a FEI Quanta
250 SEM for analysis.
2.7 Field testing
A total of six full-scale field tests were carried out at several locations near Rocky Mountain
House, Alberta, Canada. The wells were drilled in pairs using the same double-type rig and mud
program. Despite passing through the same lithological sequences, the wells were separated into
four groups based on their surface location in order to further account for slight variations in the
geology, as shown in Figure 9. Table 2-3 provides an overview of the test and control wells.
Figure 9: Surface locations of the control and test well groups A, B, C, and D.
36
Table 2-3: An overview of control and test wells.
Well Group LSD TD,
m MD Type
OBM
System
Initial Invert
Depth, m MD
Test A1 A 02-08-041-06-W5 3610 HZ** Cutter-D
90/10 613
Control A1 A 01-08-041-06-W5 3620 HZ Cutter-D
90/10 613
Control A2 A 02-10-041-06-W5 3250 HZ Cutter-D
90/10 613
Control A3* A 01-10-041-06-W5 3475 HZ Cutter-D
90/10 614
Test B1 B 02-21-041-07-W5 3516 HZ Cutter-D
85/15 613
Test B2 B 03-21-041-07-W5 3500 HZ Cutter-D
85/15 612
Control B1 B 12-19-041-07-W5 3705 HZ Cutter-D
85/15 613
Control B2 B 13-19-041-07-W5 3655 HZ Cutter-D
85/15 613
Test C1 C 04-35-037-08-W5 4033 HZ
Cutter-
D/D822
85/15
1201
Control C1 C 16-35-037-08-W5 3874 HZ
Cutter-
D/D822
85/15
1170
Control C2 C 09-36-037-08-W5 3905 HZ
Cutter-
D/D822
85/15
1205
Control C3 C 15-35-037-08-W5 3861 HZ
Cutter-
D/D822
85/15
1200
Control C4 C 03-35-037-08-W5 4097 HZ
Cutter-
D/D822
85/15
1198
Test D1 D 12-02-039-05-W5 3912 HZ
Cutter-
D/D822
85/15
612
Test D2 D 11-02-039-05-W5 3935 HZ
Cutter-
D/D822
85/15
613
* Includes a residual NP-based drilling fluid from well Test A1.
** HZ = Horizontal.
37
2.7.1 Field test implementation
A custom carrier emulsion was mixed according to the procedure described above and delivered
to a rig site where it was transferred to an empty storage tank. Initially, 10 vol% of carrier emulsion
with respect to the total volume of circulating mud (typically 6–7 m3) were slowly added to the
active system over several circulations to achieve the target concentration of CNP of 0.5 wt%. As
drilling progressed, and more drilling fluid was transferred from a tank farm to maintain the
circulation volume, 1 m3 of carrier invert was used for every 10 m3 of pre-mix. A diagram of field
implementation is shown in Figure 10.
Figure 10: A schematic of NPs field implementation using a carrier approach.
20 m3 carrier
5 wt% CNP
9 m3 invert1 m3 carrier
10 vol% carrier
0.5 wt% CNP
Mixing Facility
Tanker Truck
Rig Tank Farm
Active Ri g Tanks Pre-mix Tank
38
2.7.2 Field data collection
Field trials involved continuous presence at a rig site from initial depth to TD, and the data was
acquired throughout a day at specific depth increments (typically 200–400 m). At each depth point,
samples of drilling fluid were collected at a flow line and tested on-site. Mud weight, electrical
stability, retort analysis, and HPHT fluid loss were measured using the same lab techniques and
equipment as previously described. Subsequently, the necessary volume measurements and
calculations were performed to estimate mud losses. Additional observations included analysis of
cuttings and monitoring of drilling parameters to ensure that NPs did not cause any problems.
Ideally, extensive field analysis requires additional information such as wireline logs,
production data, and well testing data, which could be used to accurately determine the impact of
NPs on various aspects of drilling, completion or production. Unfortunately, due to the sensitive
and proprietary nature of such detailed information, an operator company could only provide
historic data from several offset wells in the area. The data was limited to mud losses and basic
properties of drilling fluids, and it was used to establish average values in control wells for
comparison.
Total mud losses were estimated using a conventional volumetric balance approach. The
method was based on calculating the difference between control volumes at two different depth
points. Given that no new volume was generated (e.g. product addition or new mud shipment), the
difference corresponded to the volume of total mud losses. However, this approach suffered from
a number of significant limitations and gave rise to large experimental errors, as will be explained
in further detail. A method for calculation of mud losses is shown in Figure 11.
39
Figure 11: A diagram explaining calculation of mud losses in the field.
Control volume consisted of several discreet elements: a tank farm, a pre-mix tank, active
tanks, and hole volume. Consequently, each element needed to be determined separately. Tank
volumes were provided by floating sensors and therefore depended on their calibration and
accuracy. Volumes provided by tank sensors did not always correspond to the true volumes of
fluid delivered on site, hence why starting volumes used in the calculation of losses were based on
a sensor reading rather than the actual volume of fluid delivered. Figure 12 below shows one such
example of the discrepancy between tank volume readings provided by digital sensors as opposed
to a manual gauge.
40
Figure 12: Example of the discrepancy between manual and digital floating sensors in a mud
storage tank.
Conversely, pipe and annular volumes can only be estimated theoretically. Calculations are
based on an inner diameter of individual hole sections, as well as on a capacity and displacement
of separate elements of a drilling string. While the information about drilling string assembly was
readily available from drilling reports, hole diameter could not be determined directly without a
calliper log. Therefore, it was assumed to be either equal to a bit size (e.g. no washout). It becomes
obvious than in the situations where hole washout is taking place, the actual hole volume may be
greater than the theoretical. This introduces errors in the calculation of losses, which often remain
unnoticed.
Another factor affecting the accuracy of mud losses calculation is associated with volume
increase due to products addition. For example, large amounts of barite could be added to increase
mud weight between two depth points of interest. This addition exaggerates the control volume,
41
so that the difference in the total volumes between data points becomes smaller and no longer
reflects losses that occurred. While it is possible to correct for such volume increase, the mud
company managing drilling fluids at the test locations did not adopt that practice. Therefore, the
effect of product additions was ignored in order to maintain consistency with the historic data.
While the volumetric balance approach employed in this thesis provided an estimate of
whole mud losses, it did not distinguish between surface and downhole losses. Surface losses were
mostly caused by residual mud on discarded drilled cuttings and centrifuge solids. As a result, they
varied depending on the efficiency of shakers, mesh size, ROP, formation drilled, type of a drill
bit, amount of operating hours and settings of a centrifuge, etc. Since only some of this information
was available, it was impossible to accurately determine the relative ratio of surface and downhole
losses for each well. Therefore, it was assumed that each well on average experienced similar
geology, mud system, drilling parameters, and solids control protocol throughout its life. The
second assumption was that NPs only affected the downhole portion of total mud losses. As a
result, any change in the final mud losses averaged across control and test wells could be attributed
to the action of NPs.
42
CHAPTER THREE: RESULTS AND DISCUSSION
3.1 Carrier emulsion
3.1.1 Properties of a carrier emulsion
The carrier emulsion approach of introducing NPs to a drilling fluid was based on volumetric
dilution. Consequently, it was desirable to achieve high concentration of NPs in a carrier fluid,
which in turn would reduce the volume required to achieve a target concentration of NPs in a host
fluid. However, even when aqueous precursors are near-saturated, the maximum concentration of
NPs is limited by the amount of water that the invert emulsion can support before breaking down.
Laboratory observation suggested that carrier emulsion separated at concentrations of CNP above
5 wt%. Accordingly, since previous lab experiments set the optimum concentration of NPs in a
host fluid at 0.5 wt%, such approach involved a 10-fold dilution. As mentioned earlier, it was
important to minimize impact of NPs addition on basic properties of a drilling fluid. Therefore,
formulation of carrier emulsion was varied until its final properties approximated those of a typical,
most representative diesel-based mud. Laboratory experiments suggested that the impact of
addition of carrier emulsion on basic properties of several different commercial mud samples was
insignificant. This rendered the carrier emulsion approach a valid alternative to the direct, in situ
method, as will be explored in further detail in the following sections.
The final lab formulation of a carrier emulsion with 5 wt% CNP was recreated on a 20 m3
volume scale according to the procedure described in Chapter Two. Sample of a product was
collected at the end of the mixing process, and its properties were evaluated against the lab-based
standard. Properties of the final formulation of carrier invert samples prepared on a lab and field
scale are provided in Table 3-1. The results indicate that the large-scale process did not affect the
apparent properties of a carrier emulsion.
43
Table 3-1: Comparison of the properties of the carrier emulsion samples with 5 wt% CNP
prepared on a lab and field scale.
Property Lab
Scale
Field
Scale
MW (kg/m3) 1049±3 1045±5
ES (V) 780±20 582±57
PV (cP) 12±2 12±2
YP (lb/100 ft2) 5±2 5±2
GS 10 s (lb/100 ft2) 4±1 4±1
GS 10 min (lb/100 ft2) 6±1 5±1
OWR 83/17 83/17
Solids (vol%) 8±1 8±1
To further examine the applicability of the carrier emulsion approach, it was important to
evaluate long-term stability of the final formulation of a carrier emulsion. During normal drilling,
mud in storage tanks can remain stagnant up to several days. This leads to gravity segregation and
consolidation of solids at the bottom of a tank. Typically, when additional drilling fluid from the
storage tanks is required to make up volume, it is circulated for several hours using built-in pump
to homogenize the mixture. Therefore, it was essential to monitor long-term stability of carrier
emulsion samples and ensure that they can perform in field conditions. Samples of carrier invert
prepared on a lab and field scale were stored at ambient conditions for four days in order to
determine their stability, as shown in Figure 13. Observations suggest that both carrier invert
preparations exhibited similar rate of settling as a typical diesel-based invert emulsion drilling fluid
containing conventional LCM and other solids. After 96 hours of storage under static, ambient
44
conditions, all three samples showed a clear solid phase boundary. However, even following one
week of settling, solids could be easily dispersed by shaking, yielding a once again homogeneous
emulsion in all samples. In addition, despite having similar composition, the colour of carrier
emulsion samples was lighter than that of a control drilling fluid. This indicates the presence of
white calcium carbonate precipitate and confirms that the coprecipitation reaction took place.
While this section focused on the macroscopic properties of lab- and field-scale carrier
emulsion samples, it was also necessary to investigate the process on a microscopic level. This is
the topic of the next two sections.
Figure 13: Long-term stability of carrier emulsion samples with 5 wt% CNP prepared in a
laboratory vs field scale. A typical commercial control invert is shown for comparison.
3.1.2 DLS analysis of a carrier emulsion
Dynamic Light Scattering is one of the most commonly used analytical techniques for NPs
characterization (Murty et al., 2013). Analysis is usually based on five different parameters that
are used together and provide an estimate of the average particle size in a sample. The calculation
45
of the parameters involves complex cumulants and distribution fitting algorithms, which are
sensitive to the concentration and polydispersity of a sample. While the actual theory involved in
DLS is outside the scope of this thesis, it is important to stress that in an ideal, monodispersed
system, intensity-, volume-, number-, and Z-average sizes should fall within a close range, and
polydispersity index (PDI) should be low. Conversely, when large, sedimenting or agglomerating
particles are present in a sample, data quality deteriorates. Usually, this leads to a large deviation
between the calculated parameters and results in a high PDI. For that reason, DLS analysis of
invert emulsion drilling fluids is problematic due to a wide range of particle sizes, in addition to
the presence of water pools and micelles.
Results of the DLS analysis on the lab- and field-based carrier emulsion samples are
provided in Table 3-2. One the one hand, the data shows some disagreement between the calculated
parameters. For instance, the mean particle size in the lab sample ranged between 150±80 nm and
450±80 nm, depending on the method used. While a number of factors could contribute to this
deviation, sample polydispersity was likely the main cause. On the other hand, standard deviation
between separate replicates falls within 10–20%, which is acceptable, considering a rather broad
size distribution (PDI 0.3–0.4). Furthermore, the data for the two samples was in a good agreement,
which also suggests that the scale-up process did not significantly affect the average particle size.
Table 3-2: Comparison of DLS data on carrier emulsion samples with 5 wt% CNP prepared in a
laboratory vs field scale. 25 °C, THF dispersant.
Carrier
Scale
Intensity
Mean (nm)
Volume
Mean (nm)
Number
Mean (nm)
Z-Average
(nm) PDI
Lab 280±20 300±40 270±20 450±80 0.400±0.050
Field 300±60 280±30 150±80 395±30 0.360±0.060
46
To further investigate the effect of carrier preparation on the particle size, intensity
distributions of the two samples were plotted for comparison. As shown in Figure 15 below, the
lab sample exhibited a range of sizes between 150–400 nm, as opposed to 50–900 nm of the field
sample. While this may be caused by an experimental error, it may also indicate that high shear
mixing of the lab sample provided better size control than the high-pressure shearing employed in
the preparation of the field sample. Considering that both samples had the exact same components,
their solid fraction was primarily composed of CNP. As a result, changes in the DLS data were
likely to reflect the difference between two preparation methods.
Despite the aforementioned limitations of the DLS analysis of carrier emulsions, it
provided a helpful insight when combined with other experimental data.
Figure 14: Intensity size distribution in a carrier emulsion samples with 5 wt% CNP produced in
a laboratory (A) vs field (B).
3.1.3 SEM and EDX analysis of a carrier emulsion
Scanning Electron Microscopy is an ideal method to investigate size, shape, and distribution of
sub-micron particles (Murty et al., 2013). However, most typical applications involve dry powders,
which excludes invert emulsion drilling fluids from the list of suitable samples. Instead, SEM was
used to gain insight into the distribution of solids within a filter cake formed during static HPHT
47
fluid loss experiment. Since the cake was oil-wet, cryogenic sample probe and chamber were
employed to limit volatility of the sample. Unfortunately, at magnification levels above 10,000x,
vibrations from the cryogenic unit made it impossible to maintain steady focus, and the image
became blurry.
To further facilitate the analysis, Energy Dispersive X-ray (EDX) spectroscopy was
employed to investigate elemental composition of the sample. EDX distinguishes between
elements based on their unique atomic structure and can be tuned to detect elements of interest. In
this case, the elements included those added as part of the precursors: calcium, carbon, oxygen,
potassium, and chlorine. In addition to indicating relative amounts of different elements within an
area of a sample, EDX is also capable of mapping that data as separate colored images for each of
the element. As a result, such images can indicate how different elements are correlated via
chemical bonding, as well as how they are distributed within a focus area. In order to make such
links more obvious, EDX mapping images were overlaid using different levels of transparency.
Black background corresponds to the lack of the selected elements, while the colored foreground
becomes more intense with increasing concentration.
An SEM image of the profile of a filter cake at 50x magnification is provided in Figure 15-
A, while the corresponding EDX mapping is shown in Figure 15-B below. It is worth pointing out
that the temperature of the sample was maintained at -150 C, which caused cracks and may have
otherwise affected the structure of the cake. The analysis of EDX images suggested that all five
elements of interest were distributed uniformly throughout the cake. However, higher levels of
magnification were required to discern any structural details.
48
Figure 15: SEM image of the profile of the filter cake formed by a lab sample of carrier
emulsion with 5 wt% CNP (A); the corresponding overlapped EDX images showing uniform
distribution of calcium, carbon, oxygen, potassium, and chloride (B).
Two different areas within the sample were chosen to attempt further magnification, as
shown on the left- and right-hand side of Figure 16, respectively. The first area was acquired at
5,000x magnification and showed several large irregular-shaped particles and a number of
scattered rhombic crystals. The corresponding EDX mapping (shown in Figure 16-C) revealed that
the crystals were in fact potassium chloride, which was a by-product of the co-precipitation
reaction. Similarly, overlaid images in Figure 16-B also showed that calcium, carbon, and oxygen
were closely correlated. While this confirms the formation of calcium carbonate during the co-
precipitation reaction, it does not provide enough resolution to observe NPs. The large structural
49
features featured in the SEM image are either entirely composed of calcium carbonate or, which
is more likely considering the atypical shape, present clay platelets or agglomerates coated with
CNP. Colored spots in the background of the EDX image correspond to the parts of the SEM
image where no individual particles are visible at this level of magnification.
Figure 16: SEM images of two different areas within the profile of a filter cake formed by a lab
sample of carrier emulsion with 5 wt% CNP (A, D); the corresponding overlapped EDX images
showing correlation between calcium, carbon, and oxygen (B, E); the same areas showing
correlation between potassium, and chlorine (C, F).
Subsequently, the second area within the sample was chosen and examined at higher
magnification of 10,000x, as shown in Figure 16-D. Similar to the image on the left, SEM showed
a number of crystals ranging between 1–3 m, but the resolution was still too low to notice any
50
details in the background. EDX analysis shown in Figure 16-F verified that crystals were formed
by potassium carbonate, likely as a result of high temperature and pressure conditions during the
HPHT test. Accordingly, mapping images in Figure 16-E indicated the presence of calcium
carbonate and showed dark spots corresponding to crystals of potassium chloride. However, the
background of the image suggested the presence of sub-micron particles that constituted the cake
matrix but were too small to observe on that scale.
All further attempts to increase magnification and resolution were unsuccessful due to the
loss of focus; therefore, the experiment only provided limited information. The only conclusion
was that the emulsion-based chemical co-precipitation did in fact produce calcium carbonate, and
that such particles were primarily in the sub-micron domain.
3.2 Basic properties of commercial drilling fluids with CNP
Before probing the potential benefit of NPs on filtration of drilling fluids, it was first necessary to
ensure that their addition did not affect basic properties of mud to a significant extent. Both the in
situ and the carrier emulsion methods were investigated, and the results suggested that neither
exhibited adverse effects on the samples. Properties of commercial virgin and recycled drilling
fluids in the presence of 0.5 wt% CNP were evaluated following the procedures outlined in Chapter
Two.
Theoretically, mud weight of mud samples should increase by less than 1% in the case if
in situ method, while the corresponding increase in the case of emulsion approach depends on how
closely densities of the two fluids are matched. In reality, however, the difference in mud weight
measured with a mud balance was so negligible, that for the most part it was obscured by the
51
experimental error. This is shown in Figure 17 for virgin and recycled mud samples (left and right,
respectively).
Figure 17: Impact of 0.5 wt% CNP on mud weight of commercial invert emulsion drilling fluids
using in situ and carrier emulsion methods.
The effect of addition of 0.5 wt% CNP on electrical stability of commercial drilling fluids
is shown in Figure 18. The in situ method either did not affect ES of the samples, or its impact was
minimal. This result was expected considering that composition of the host fluid was altered only
marginally. On the other hand, carrier emulsion method reduced electrical stability of drilling
fluids slightly. The effect was most pronounced in the case of virgin mineral and diesel OBM,
while the other samples were not affected to the same extent. This behaviour has not yet been fully
understood. However, electrical stability was in the acceptable range in all samples, and it was
deemed that NPs did not result in any dramatic differences
52
Figure 18: Impact of 0.5 wt% CNP on electrical stability of commercial invert emulsion drilling
fluids using in situ and carrier emulsion methods.
Plastic viscosity and yield point of drilling fluid samples are provided in the top and bottom
of Figure 19, respectively. Both parameters were affected by the addition of 0.5 wt% NPs, and
similar to the previous discussion, carrier emulsion approach exhibited more significant effect.
The general trend suggested increase in PV and YP in the presence of CNP. However, despite the
differences in rheological properties, they were well within the operating range maintained during
drilling operation.
53
Figure 19: Impact of 0.5 wt% CNP on plastic viscosity (A, B) and yield point (C, D) of
commercial invert emulsion drilling fluids.
To further determine the potential impact of NPs on rheology of mud samples, gel strengths
at 10 s and 10 min were measured and summarized in Figure 20. Similar to the case of plastic
viscosity and yield point, impact on gel strengths in most drilling fluids was minimal.
54
Figure 20: Impact of 0.5 wt% CNP on gel strength of commercial invert emulsion drilling fluids
at 10 s (A, B) and 10 min (C, D).
Last but not least, retort analysis was used to measure volumetric composition of drilling
fluids with and without NPs. The results shown in Figure 21 suggest that the impact on OWR and
solids content of all mud samples was less than 1%, which again was within the normal operating
range.
Once the experiments confirmed that NPs at 0.5 wt% can be safely introduced to typical
commercial drilling fluids without causing significant changes in the final properties, it was
appropriate to focus laboratory testing on fluid loss.
55
Figure 21: Impact of 0.5 wt% CNP on volumetric composition of virgin (A) and recycled (B)
commercial invert emulsion drilling fluids.
3.3 Fluid loss in commercial drilling fluids with CNP
Zakaria et al. (2012) showed that in situ calcium carbonate NPs at 0.5 wt% were effective reducing
spurt loss and filtrate volume in several types of commercial invert emulsion drilling fluids. The
experiments were independently reproduced in the lab using a modified in situ preparation method
based on aqueous precursors. Three different types of virgin drilling fluids were tested, as
presented in the left-hand side of Figure 22.
56
Figure 22: Impact of 0.5 wt% CNP on HPHT fluid loss (A, B) and filter cake thickness (C, D)
of commercial invert emulsion drilling fluids at 80 °C and 500 psi.
Both virgin diesel-based fluids showed reduction of fluid loss in the presence of 0.5 wt%
CNP. It is worth mentioning that virgin drilling fluids typically exhibit much higher fluid loss than
their conditioned, field-based counterparts. As a result, this makes any changes in the data more
apparent. Subsequently, virgin samples of Cutter-D and Diesel OBM showed a 17% and 33%
reduction of average filtrate volumes at 30 min in the presence of in situ 0.5 wt% CNP,
respectively. The corresponding average filter cake thickness was also reduced compared to the
control samples.
On the one hand, the HPHT values in the virgin Cutter-D sample were further reduced by
52% when the same concentration of CNP was introduced via a carrier emulsion approach. On the
57
other hand, the in situ and carrier emulsion methods exhibited similar performance in the case of
the virgin diesel-based OBM. The difference was attributed to the presence of clays alongside NPs
in the carrier emulsion approach. It is possible that NPs interacted with clay platelets and formed
a composite network that reinforced the structure of the cake and reduced its permeability. An
example of such process was investigated and reported elsewhere (Walz, 2011).
Finally, regardless of the approach utilized, CNP did not affect the filtration properties of
the virgin mineral-based OBM, where HPHT values and cake thickness remained within the
standard deviation of the control sample. This suggested that adverse interactions likely took place
between CNP and other components in the mud, which in turn limited the ability of NPs to reduce
filtration rates.
Since virgin drilling fluids did not fully represent properly conditioned and matured field
mud, it was essential to further investigate the impact of a composition of recycled samples on its
filtration properties in the presence of NPs. The average values of filtrate volume and cake
thickness are provided on the right-hand side of Figure 22. Field samples typically contain higher
concentration of filtration control agents, as well as higher solids content in general. Accordingly,
the HPHT values in all three recycled control samples were in the range of 4–6 mL2, which was
much lower than in the case of the virgin fluids. However, despite the already optimized
composition of each of the three field samples, CNP at 0.5 wt% reduced the filtrate volumes even
further. Unlike the virgin fluids, in situ and carrier emulsion methods exhibited negligible
difference and achieved an average of 30–40% lower filtrate volumes compared to the control
samples. In addition, the average thickness of a filter cake in field fluids was also reduced in the
presence of 0.5 wt% CNP, which is a significant result.
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To summarize, the results of the HPHT experiments demonstrated that CNP at 0.5 wt%
improved filtration control properties of virgin and real-life invert emulsion drilling fluids. While
the performance of NPs depended on the nature of the host drilling fluids as well as the method of
CNP synthesis, average HPHT values and the corresponding cake thickness were reduced in the
most representative field samples. The reduction was consistent with the filtration model
developed in Chapter One. More importantly, it was also shown that the carrier emulsion approach
achieved the same reduction in recycled fluids as the in situ approach. This signified that the
process could be scaled up to a field application, which is the topic of the remainder of this chapter.
3.4 Field testing
Before proceeding with the analysis of field data, it is important to discuss its accuracy and
limitations. As was pointed out earlier, typical field data suffers from large degree of errors that
are caused both by the limitations of the measurement devices as well as the human factor. In
addition, total mud losses are normally affected by so many different parameters, that they can
vary dramatically even when wells are drilled in the same location and using the same mud system.
Since the objective of the field trial was to determine the impact of NPs on mud losses, a reliable
baseline for comparison had to be established first. Ideally, large volumes of field data for control
and test wells are required to reduce statistical error and provide a more accurate estimate.
However, in the case of this thesis the amount of available information was rather limited. In order
to increase reliability of the field results, the data was collected independently and then compared
with measured and calculated values provided by a mud company representative. In all cases the
difference was within ±1%, so the results are used interchangeably throughout this chapter.
Finally, despite the use of proper scientific methodology and a consistent approach, it must be
59
acknowledged that the field data presented herein serves to provide general and relative trends
rather than absolute values.
3.4.1 HPHT fluid loss
Results of HPHT fluid loss experiments in all control and test wells are shown in Figure 23. Once
WBM is displaced, invert emulsion drilling fluids require time to fully develop their properties as
they are continuously circulated, sheared, and heated. Furthermore, when a fresh drilling fluid is
used, it first must be conditioned with additives, as specified in a mud program. Additives are
typically added slowly, over several circulations; hence their impact on HPHT is not immediately
apparent. This effect is often observed as a trend towards lower HPHT values with increasing
depth, until a characteristic plateau region is reached.
60
Figure 23: HPHT fluid loss as a function of measured depth in the control and test wells at 80
°C and 500 psi.
Since the well group A contains control, depleted, and test wells, it allows to investigate
the effect of concentration of NPs on HPHT values. As shown in Figure 23-A, Control A1 started
at 6.5 mL×2 filtrate volume, which then decreased to 4.8 mL×2 at approximately 1500 m MD and
remained constant until TD. Conversely, Test A1 started at a lower value of 4 mL×2, which then
stabilized at 1 mL×2. This supports the notion that the concentration of NPs requires time to reach
the optimum values, especially when fresh invert is used. Similarly, Control A3*, which already
contained NPs at a working concentration, showed even lower initial HPHT fluid loss of 3 mL×2.
After sufficient circulation, it reached the same characteristic value of 1 mL×2 as in the case of
61
Test A1. As drilling progressed, drilling fluid was diluted with fresh invert, and the concentration
of NPs was depleted. As a result, HPHT values increased to 2 mL×2 near the end of the well.
While the control HPHT data for group B was not available, wells Test B1, Test B2 showed
low fluid loss of 1.5 mL×2, which is consistent with the well Test A1.
The four control wells in group C showed a wide range of HPHT values that varied between
2–8 mL×2, while the HPHT values in well Test C1 exhibited a trend similar to that in Test A1 and
reached low values of 2–3 mL×2 in the presence of NPs. This also holds for both test wells in
group D, where fluid loss remained between 1–3 mL×2.
The above HPHT data can be summarized and represented as the average fluid loss within
each well group, which is shown in Figure 24. Results clearly indicate that on average, NPs
reduced HPHT filtrate volumes by 20–30%, compared to control wells that contained conventional
LCM alone. This correlates well with the lab experiments discussed in the previous section, where
the average reduction of filtrate volume of 30% was observed in a similar type of drilling fluids.
Figure 24: Average HPHT fluid loss in the control and test wells at 80 °C and 500 psi.
62
3.4.2 The effect of concentration of carrier
The effect of the concentration of carrier emulsion on HPHT values in the test wells was
investigated further. The theoretical concentration of carrier at each depth point was calculated
using a volumetric ratio of carrier to the total circulating mud volume and then plotted against
measured depth, as shown in Figure 25. Recall that the concentration of NPs in carrier was 5 wt%,
which corresponds to a 10 vol% concentration in the circulating mud system. Wells Test A1 and
Test C1 show that as the volumetric ratio of carrier increased towards 10% v/v, HPHT values
decreased accordingly. Once the concentration of NPs in the drilling fluid was maintained within
the target range, HPHT filtrate volumes remained constant. Similar conclusions can be drawn for
groups B and D, which started at higher concentrations of carrier. As a result, the change in HPHT
values was not as dramatic as in the case of groups A and C. This demonstrates that the
concentration of NPs in a drilling fluid had a direct impact on its filtration control properties.
63
Figure 25: HPHT fluid loss and calculated concentration of carrier as a function of measured
depth in the test wells.
3.4.3 Cumulative mud losses
Cumulative mud losses while drilling in control and test wells are presented as a function of
measured depth in Figure 26. Comparison between test and control wells suggests that NPs had an
impact on mud losses. As such, the well Test A1 showed the lowest total mud losses within the
group, with less than 60 m3 lost at TD. Control A3*, which demonstrated the effect of leftover NPs
in HPHT experiments, also showed lower losses at TD compared to control wells that only
contained conventional LCM. Similar situation can be observed in group B, where both test wells
suffered lower mud losses while drilling than the control wells. Group C demonstrates a wide
range of losses in control wells, which vary between 70 and 117 m3 at TD. However, Test C1 with
64
65 m3 at TD still falls on the lower side that range. Unfortunately, no control data for group D was
available, therefore the direct comparison cannot be made within the same group.
Figure 26: Cumulative mud losses as a function of measured depth in the control and test wells.
To summarize the data shown in Figure 26 above, final cumulative mud losses while
drilling are provided in Figure 27. The results indicate that the losses in the presence of NPs were
on average 20–30% lower than in control wells. This range is very consistent with observations
made during HPHT fluid loss experiments. However, it should be noted that the final cumulative
losses were measured at TD, which varied slightly between the wells. In order to standardize the
data, cumulative losses were converted to losses per 100 m drilled, which are discussed in further
detail in the following section.
65
Figure 27: Final cumulative mud losses at TD in the control and test wells.
3.4.4 Mud losses per 100 m drilled
Similar to the cumulative mud losses while drilling, losses per 100 m drilled showed lower values
in the presence of NPs. As can be seen in Figure 28, test wells consistently achieved on average
of 2 m3/100 m, which is lower than the control wells containing conventional LCM alone. In
addition, the test wells demonstrated more narrow variation of losses with depth, which further
supports the notion that NPs help to control downhole losses.
The data can also be represented as the average losses per 100 m drilled at TD, as shown
in Figure 29. The results clearly indicate that, even after correcting for variation in TD, test wells
still provided a 20–30% reduction of losses compared to the control wells.
66
Figure 28: Mud losses per 100 m drilled as a function of measured depth in the control and test
wells.
Figure 29: Average mud losses per 100 m drilled at TD in the control and test wells.
67
3.4.5 Correlation of HPHT fluid loss and mud losses
As mentioned previously, correlation of HPHT fluid loss and the actual mud losses remains one
of the challenges associated with field testing. Figure 30 shows a plot of HPHT filtrate volumes
versus the corresponding instantaneous mud losses that occurred between two successive depth
points. While the results do not form a consistent trend, test wells (filled markers) tend to be located
closer to the origin point of the graph than the control wells (open markers). In turn, this likely
indicates that reduction of HPHT values corresponds to lower mud losses in the presence of NPs.
Figure 30: Correlation between HPHT fluid loss and instantaneous mud losses in the test wells.
68
CHAPTER FOUR: CONCLUSIONS, CONTRIBUTIONS AND RECOMMENDATIONS
4.1 Conclusions
The results of the lab and field experiments provided in this thesis can be summarized in the
following key points:
1) CNP were successfully synthesized in the lab using chemical co-precipitation of aqueous
precursors. A carrier alternative to the in situ preparation onsite was proposed to ensure
scale-up for a field application. A custom invert carrier emulsion with 5 wt% CNP was
synthesized using a reverse micelle approach and was then used to introduce NPs to a host
fluid via volumetric dilution.
2) Six different invert emulsion drilling fluids were tested in the presence of 0.5 wt% CNP
introduced via two different routes. The in situ method did not significantly impact the
basic mud properties, while the effect was more pronounced when carrier emulsion was
used at a 10 vol% ratio.
3) CNP helped to reduce average HPHT filtrate volumes in virgin and recycled samples by
30–40%. Carrier emulsion approach demonstrated similar performance as the in situ
method, which suggested that scale-up to a field application was possible.
4) Carrier emulsion approach was successfully implemented at an industrial drilling fluids
processing facility. The method was fully compatible with standard oilfield chemicals and
did not require significant deviation from routine mixing operations. A total of 6 batches
of carrier emulsion were successfully prepared on a scale of 20 m3 volume.
5) Macroscopic properties of carrier produced on a large scale were in good agreement with
the lab-based benchmark, which suggested that the scale-up process proceeded according
to the expectations. Lab- and field-scale carrier emulsion samples with 5 wt% CNP were
69
stable after long-term storage. After one week of static ageing under ambient conditions,
samples showed the same extent of solids settling as a representative control sample of a
typical, commercial drilling fluid.
6) SEM and EDX analysis confirmed the distribution of calcium carbonate and potassium
chloride within the profile of a filter cake formed by a carrier emulsion. While the
resolution was insufficient to distinguish sub-micron particles, the experiments provided a
valuable insight into elemental composition of the sample.
7) DLS experiments on lab- and field-based carrier emulsion showed the average particle size
of approximately 300–400 nm. Intensity distribution data further suggested that the lab
preparation achieved a more narrow size range as opposed to the field sample, where the
particles covered the range of 50–900 nm. Since laboratory method employed high shear
mixing conditions, it may have provided better size control than the jet shear principle.
However, this is significant result that demonstrates that the reverse micelle synthesis of
NPs can be successfully implemented on a large scale. Furthermore, the process utilized
common oilfield chemicals and additives that are native to most drilling fluids. Therefore,
the process was economical and did not present significant health risks.
8) Six different commercial drilling fluids were tested in the lab to determine impact of CNP
on their properties. Virgin as well as recycled samples showed relatively insignificant
change in basic experimental parameters. As expected, the impact of in situ method was
less pronounced than the 10 vol% dilution required in the carrier emulsion approach.
However, all three samples of most typical, diesel-based OBM showed good compatibility
with the carrier formulation.
70
9) Results of the HPHT fluid loss experiments on commercial invert emulsion drilling fluids
in the presence of in situ 0.5 wt% CNP were consistent with the previous work by Zakaria
et al. (2012). Filtrate volumes and the corresponding filter cake thickness were reduced by
20–40% on average. Subsequently, the experiments were recreated using the carrier
emulsion approach instead. In the case of the recycled samples, both methods achieved the
same reduction of HPHT values on the order of 30–40%.
10) Six field tests were conducted in the province of Alberta, Canada in 2014. A carrier
emulsion approach was used in all wells, which were assigned into four groups to eliminate
effect of their surface location. Field trials involved regular mud testing, calculation of mud
losses, analysis of cuttings, and continuous monitoring of drilling operation.
Simultaneously, a mud company representative acquired the same data to ensure its
reliability. Comparison revealed that the differences were within ±1%.
11) The basic properties of drilling fluids in the test wells were within same range as in control
wells that contained conventional LCM, while the HPHT values were on average 20–30%
lower. The results were consistent with the lab experiments performed on a small-scale
carrier emulsion. Furthermore, correlation between filtrate volumes and the calculated
concentration of NPs in the whole mud was established.
12) A volumetric balance approach was implemented to evaluate total mud losses in the test
wells. The data was compared to the mud losses in historic offset wells provided by a mud
operator. Despite the limited sample size and high degree of errors, test wells consistently
showed 20–30% lower cumulative losses at TD. Accordingly, losses per 100 m were also
lower than in control wells.
71
13) The results of lab and field experiments were consistent with the model of filtration in the
presence of NPs developed in Chapter One. Lower filtrate volumes corresponded to a
thinner filter cake, which could only mean that CNP were effective reducing the
permeability of the medium.
4.2 Contributions to knowledge
The work presented in this thesis produced significant results that will be of interest to a wide
audience, including the drilling industry and the nanotechnology researchers alike. Firstly it was
demonstrated that a microemulsion-based, in situ synthesis of NPs can be successfully
implemented on an industrial scale. A carrier emulsion of 20 m3 volume containing 1,050 kg of
CNP was produced in a specialized mixing facility following a bench-scale technique and
exhibited similar average particle size and final properties as the samples prepared in the
laboratory. Secondly the results suggested that the carrier emulsion approach can be incorporated
into routine drilling operations without causing any problems, delays or health concerns.
Subsequently, analysis of mud losses indicated that the test wells containing 0.5 wt% CNP
achieved on average 20–30% lower cumulative losses while drilling compared to the control wells
using typical invert emulsion drilling fluids. This bridged the gap between laboratory-based HPHT
experiments and the actual mud losses and confirmed the performance of CNP under real-life
conditions.
4.3 Recommendations for future work
In conclusion, a novel approach for a large-scale manufacturing of NPs was successfully
developed and extensively tested with a variety of commercial drilling fluids. Lab and field
72
experiments provided promising preliminary results and demonstrated potential of the carrier
emulsion approach for reducing downhole mud losses. This opens a wide range of possible
directions for future research efforts. Several most important recommendations are listed below:
1) Modify the carrier emulsion approach to increase the maximum concentration of CNP in
order to reduce the dilution ratio and make the process more cost-effective.
2) Investigate the possibility of synthesis of other types of NPs using the carrier emulsion
approach and perform extensive lab testing to determine their impact on essential mud
properties.
3) Conduct additional field trials to increase the sample size and reduce the statistical error in
the data. If possible, request wireline logs, tower sheets, archive of Pason Autodriller data,
and other helpful information that would allow to expand the focus of the data analysis
beyond simple monitoring of total mud losses.
73
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