Note: Descriptions are shown in the official language in which they were submitted.
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NANOHYBRID PHASE INTERFACES
FOR ALTERING WETTABILITY IN OIL FIELD APPLICATIONS
Technical Field
[0001] The inventions generally relate to the field of producing crude oil or
natural gas
from a well. More particularly, the inventions are directed to improved well
fluids and methods
for use in wells.
Background Art
Producing Oil & Gas
100021 In the context of production from a well, oil (in this context
referring to crude
oil) and gas (in this context referring to natural gas) are well understood to
refer to hydrocarbons
naturally occurring in certain subterranean formations. A hydrocarbon is a
naturally occurring
organic compound comprising hydrogen and carbon, which can be as simple as
methane (CH4)
or can be a highly complex molecule or anything in between. Petroleum is a
complex mixture
of hydrocarbons. Oil wells usually produce oil and gas along with water.
100031 A subterranean formation containing oil or gas is sometimes referred to
as a
reservoir. A reservoir is in a shape that will trap hydrocarbons and that is
covered by a relatively
impermeable rock, known as cap rock. The cap rock forms a barrier or seal
above and around
reservoir rock so that fluids cannot migrate beyond the reservoir. Cap rock is
commonly shale,
anhydrite, or salt. In addition, gas shows from shales during drilling have
led some shales to be
targeted as gas reservoirs. A reservoir may be located under land or under the
seabed off shore.
Oil and gas reservoirs are typically located in the range of a few hundred
feet (shallow
reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs) below
the surface of the land
or seabed.
100041 As used herein, "subterranean formation" refers to the fundamental unit
of
lithostratigraphy. A subterranean formation is a body of rock that is
sufficiently distinctive and
continuous that it can be mapped. In the context of formation evaluation, the
term refers to the
volume of rock seen by a measurement made through the wellbore, as in a log or
a well test.
These measurements indicate the physical properties of this volume of rock,
such as the property
of permeability. A "zone" refers to an interval or unit of rock along a
wellbore that is
differentiated from surrounding rocks based on hydrocarbon content or other
features, such as
faults or fractures.
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100051 To produce oil or gas from a reservoir, a wellbore is drilled into a
subterranean
formation, which may be the reservoir or adjacent to the reservoir. The
"wellbore" refers to the
drilled hole, including a cased or uncased portion of the well. As used
herein, the "borehole"
refers to the inside wellbore wall, that is, the rock face or wall that bounds
the drilled hole. A
wellbore can have portions that are vertical and horizontal, and it can have
portions that are
straight, curved, or branched. The wellhead is the surface termination of a
wellbore, which
surface may be on land or on a seabed. As used herein, "uphole" and "downhole"
and similar
terms are relative to the wellhead, regardless of whether a wellbore portion
is vertical or
horizontal.
10006] As used herein, a "well" includes at least one wellbore. A "well" can
include a
near-wellbore region of a subterranean formation surrounding a portion of a
wellbore that is in
fluid communication with the wellbore. As used herein, "into a well" means at
least through the
wellhead. It can include into any downhole portion of the wellbore and it can
include through
the wellbore and into a near-wellbore region.
[0007] Generally, well services include a wide variety of operations that may
be
performed in oil, gas, geothermal, or water wells, such as drilling,
cementing, completion, and
intervention operations. These well services are designed to facilitate or
enhance the production
of desirable fluids from or through a subterranean formation.
100081 As used herein, a "well fluid" broadly refers to any fluid adapted to
be
introduced into a well for any well-servicing purpose. A "well fluid" can be,
for example, a
drilling fluid, a cementing fluid, a treatment fluid, or a spacer fluid. If a
well fluid is to be used
in a relatively small volume, for example less than about 200 barrels, it is
sometimes referred to
in the art as a slug or a pill. Accordingly, as used herein a "well fluid" can
be a slug or a pill.
Drilling and Drilling Fluids
100091 Drilling is the process of drilling the wellbore. The well is created
by drilling a
hole, usually about 5 inches (13 cm) to about 36 inches (91 cm) in diameter
into the earth (or
seabed) with a drilling rig that rotates a drill string with a bit attached.
After the hole is drilled,
sections of steel pipe, known as casing, which are slightly smaller in
diameter than the borehole,
are placed in at least the uppermost portions of the borehole. The casing
provides structural
integrity to the newly drilled wellbore, in addition to isolating potentially
dangerous high
pressure zones from each other and from the surface.
100101 While drilling an oil or gas well, a drilling fluid is circulated
downhole through
a drillpipe to a drill bit at the downhole end, out through the drill bit into
the wellbore, and then
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back uphole to the surface through the annular path between the tubular
drillpipe and the
borehole. The purpose of the drilling fluid is to maintain hydrostatic
pressure in the wellbore, to
lubricate the drill string, and to carry rock cuttings out from the wellbore.
[0011] A drilling fluid can be water-based or oil-based. Oil-based fluids tend
to have
better lubricating properties than water-based fluids, nevertheless, other
factors can mitigate in
favor of using a water-based drilling fluid.
100121 In addition, the drilling fluid may be viscosified to help suspend and
carry rock
cuttings out from the wellbore. Rock cuttings can range in size from fines to
chunks measured
in centimeters. Carrying capacity is the ability of a circulating drilling
fluid to transport rock
fragments out of a wellbore. Carrying capacity is an essential function of a
drilling fluid,
synonymous with hole-cleaning capacity and cuttings lifting. Carrying capacity
is determined
principally by the annular velocity, hole angle, and flow profile of the
drilling fluid, but is also
affected by mud weight, cuttings size, and pipe position and movement.
100131 The wellbore may pass through zones that produce water instead of
hydrocarbons. Besides being highly undesirable during the production phase,
water-producing
zones can cause problems in the wellbore with certain drilling and completion
activities and
associated fluids. For example, the water production may highly dilute the
drilling or other
treatment fluid in the well. If possible, however, water production is
generally ignored during
the drilling phase.
Cementing and Hydraulic Cement Compositions
100141 Cementing is a common well operation. For example,
hydraulic cement
compositions can be used in primary cementing operations during completion in
which a string
of pipe, such as casing or liner, is cemented in a wellbore. In performing
primary cementing, a
hydraulic cement composition is pumped as a fluid (typically a suspension or
slurry) into the
annular space between the exterior surfaces of a pipe string and the borehole
(that is, the wall of
the wellbore). The cement composition is allowed time to set in the annular
space, thereby
forming an annular sheath of hardened, substantially impermeable cement. The
hardened
cement supports and positions the pipe string in the wellbore and bonds the
exterior surfaces of
the pipe string to the walls of the wellbore. Hydraulic cement compositions
can also be utilized
in remedial cementing operations, such as in plugging highly permeable zones
or fractures in
near-wellbore regions, plugging cracks or holes in pipe strings, and the like.
100151 Hydraulic cement is a material that when mixed with
water hardens or sets
over time because of a chemical reaction with the water. Because this is a
chemical reaction
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with the water, hydraulic cement is capable of setting even under water. The
hydraulic cement,
water, and any other components are mixed to form a hydraulic cement
composition in the
initial state of a slurry, which should be a fluid for a sufficient time
before setting for pumping
the composition into the wellbore and for placement in a desired downhole
location in the well.
Well Treatments and Treatment Fluids
[0016] Completion is the process of making a well ready for production or
injection.
This principally involves preparing the bottom of the hole to the required
specifications, running
in the production tubing and associated downhole tools, as well as perforating
and stimulating as
required.
[0017] Well intervention, or "well work," is any operation carried out on a
well during
or at the end of its productive life that alters the state of the well or well
geometry, provides well
diagnostics, or manages the production of the well. Workover can broadly refer
to any kind of
well intervention involving invasive techniques, such as wireline, coiled
tubing, or snubbing.
More specifically, though, it refers to the process of pulling and replacing a
completion.
[0018] Drilling, completion, and intervention operations can include various
types of
treatments that are commonly performed on a well or subterranean formation.
For example, a
treatment for fluid-loss control can be used during any of drilling,
completion, and intervention
operations. During completion or intervention, stimulation is a type of
treatment performed to
enhance or restore the productivity of oil and gas from a well. Stimulation
treatments fall into
two main groups: hydraulic fracturing and matrix treatments. Fracturing
treatments are
performed above the fracture pressure of the subterranean formation to create
or extend a highly
permeable flow path between the formation and the wellbore. Matrix treatments
are performed
below the fracture pressure of the formation. Other types of completion or
intervention
treatments can include, for example, gravel packing, consolidation, and
controlling excessive
water production.
[0019] As used herein, the word "treatment" refers to any treatment for
changing a
condition of a wellbore or an adjacent subterranean formation. Examples of
treatments include
fluid-loss control, isolation, stimulation, or conformance control; however,
the word "treatment"
does not necessarily imply any particular treatment purpose.
10020] A treatment usually involves introducing a treatment fluid into a well.
As used
herein, a "treatment fluid" is a fluid used in a treatment. The word
"treatment" in the term
"treatment fluid" does not necessarily imply any particular action by the
fluid. If a treatment
fluid is to be used in a relatively small volume, for example less than about
200 barrels, it is
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sometimes referred to in the art as a slug or a pill. Accordingly, as used
herein the term
"treatment fluid" can be a slug or a pill.
[0021] The following are some examples and general descriptions of common well
treatments and associated treatment fluids. Of course, other well treatments
and treatment fluids
are known in the art.
Well Treatment - Fluid-Loss Control
[0022] "Fluid loss" refers to the undesirable leakage of the liquid phase of a
well fluid
that contains solid particles into the matrix of a subterranean formation
surrounding a portion of
the wellbore. The resulting buildup of solid particulate material on the walls
of the wellbore is
referred to as a filter cake. Depending on the particulate material and the
liquid phase, such a
filtercake may help block the further loss of the liquid phase (referred to as
a filtrate) into the
subterranean formation. Providing effective fluid-loss control for well fluids
is usually highly
desirable.
[0023] Fluid-loss control materials are additives specifically designed to
lower the
volume of a filtrate that passes through a filter medium. Most attain their
fluid-loss control from
the presence of solvent-specific solids, or from hydrated linear polymers that
rely on filter cake
buildup and on viscoelasticity to inhibit fluid flow into and through the
formation. A variety of
fluid-loss control materials have been used and evaluated, including foams,
oil-soluble resins,
acid-soluble particulates, graded salt slurries, linear viscoelastic polymers,
and heavy metal-
crosslinked polymers. Their respective comparative effects are well
documented. Fluid-loss
control materials are sometimes used in drilling fluids or treatment fluids.
[0024] Other techniques that have been developed to control fluid loss include
the use
of "fluid-loss control pills," which sometimes are referred to as "lost
circulation pills." A "fluid-
loss control pill" is a treatment fluid that is designed or used to provide
some degree of fluid-loss
control. Through a combination of viscosity, solids bridging, and cake buildup
on the porous
rock, these pills oftentimes are able to substantially seal off portions of
the formation from fluid
loss. They also generally enhance filter-cake buildup on the face of the
formation to inhibit fluid
flow into the formation from the wellbore.
[0025] Fluid-loss control pills typically comprise an aqueous base fluid and a
high
concentration of a gelling agent polymer (usually crosslinked), and sometimes,
bridging
particles, like graded sand, potassium salts, or sized calcium carbonate
particles. The most
commonly used fluid-loss control pills contain high concentrations (100 to 150
lbs/1000 gal) of
derivatized hydroxyethylcellulose ("HEC"). HEC is generally accepted as a
gelling agent
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affording minimal permeability damage during completion operations. Normally,
HEC polymer
solutions do not form rigid gels, but control fluid loss by a viscosity-
regulated or filtration
mechanism. Some other gelling agent polymers that have been used include guar,
guar
derivatives, carboxymethylhydroxyethylcellulose ("CMHEC"), and even starch.
[0001] As an alternative to forming linear polymeric gels for fluid-loss
control,
crosslinked gels often are used. Crosslinking the gelling agent polymer
creates a gel structure
that can support solids as well as provide fluid-loss control. Further,
crosslinked fluid-loss
control pills have demonstrated that they require relatively limited invasion
of the formation face
to be fully effective. To crosslink the gelling agent polymers, a suitable
crosslinking agent that
comprises polyvalent metal ions is used. Boron, aluminum, titanium, and
zirconium are
common examples.
[0002] A preferred crosslinkable gelling agent for fluid-loss control pills
are graft
copolymers of a hydroxyalkyl cellulose, guar, or hydroxypropyl guar that are
prepared by a
redox reaction with vinyl phosphonic acid. The gel is formed by hydrating the
graft copolymer
in an aqueous solution containing at least a trace amount of at least one
divalent cation. The gel
is crosslinked by the addition of a Lewis base or Bronsted-Lowrey base so that
pH of the
aqueous solution is adjusted from slightly acidic to slightly basic.
Preferably, the chosen base is
substantially free of polyvalent metal ions. The resulting crosslinked gel
demonstrates shear-
thinning and rehealing properties that provide relatively easy pumping, while
the rehealed gel
provides good fluid-loss control upon placement. This gel can be broken by
reducing the pH of
the fluid. Some fluid-loss pills of this type are described in U.S. Patent No.
5,304,620, assigned
to Halliburton Energy Services. Fluid-loss control pills of this type are
commercially available
under the trade name "K-MAX" from Halliburton Energy Services Inc. in Duncan,
Oklahoma.
[0003] After their application, fluid-loss control pills can cause damage to
the
permeability of near-wellbore areas due to polymer filtration or filter-cake
formation. To
produce oil or gas from a subterranean formation, the filter cake resulting
from a fluid-loss
control pill must be removed to restore the formation's permeability,
preferably to at least its
original level. If the formation permeability is not restored to at least its
original level,
production levels from the formation can be significantly lower.
Well Treatment - Acidizing
[0004] A widely used stimulation technique is acidizing, in which a treatment
fluid
including an aqueous acid solution is introduced into the formation to
dissolve acid-soluble
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materials that clog or constrict formation channels. In this way, hydrocarbon
fluids can more
easily flow from the formation into the well. In addition, an acid treatment
can facilitate the
flow of injected treatment fluids from the well into the formation.
[0030] Acidizing techniques can be carried out as "matrix acidizing"
procedures or as
"acid fracturing" procedures.
[0031] In matrix acidizing, the acidizing fluid is injected from the well into
the
formation at a rate and pressure below the pressure sufficient to create a
fracture in the
formation. The acid permeates into channels and dissolves materials that clog
or constrict the
channels, thereby increasing permeability of the formation. Thus, an increase
in permeability is
affected primarily by the reaction of the acid within the formation, and
little or no permeability
increase is due to induced fractures within the formation.
[0032] In acid fracturing, an increase in permeability is affected by
fractures as well as
by the acid etching through the channels within the formation. The acidic
fracturing fluid is
injected into the well that is disposed within the formation to be fractured.
Sufficient pressure is
applied to the acidizing treatment fluid to cause production of one or more
fractures in the
formation.
Well Treatment - Hydraulic Fracturing and Proppant
[0033] "Hydraulic fracturing," sometimes simply referred to
as "fracturing," is a
common stimulation treatment. A treatment fluid adapted for this purpose is
sometimes referred
to as a "fracturing fluid." The fracturing fluid is pumped at a sufficiently
high flow rate and
pressure into the wellbore and into the subterranean formation to create or
enhance a fracture in
the subterranean formation. Creating a fracture means making a new fracture in
the formation.
Enhancing a fracture means enlarging a pre-existing fracture in the formation.
100341 A "frac pump" is used for hydraulic fracturing. A
frac pump is a high-
pressure, high-volume pump. Typically, a frac pump is a positive-displacement
reciprocating
pump. The structure of such a pump is resistant to the effects of pumping
abrasive fluids, and
the pump is constructed of materials that are resistant to the effects of
pumping corrosive fluids.
Abrasive fluids include hard, insoluble particulates, such as sand, and
corrosive fluids include,
for example, acids. The fracturing fluid may be pumped down into the wellbore
at high rates
and pressures, for example, at a flow rate in excess of 50 barrels per minute
(2,100 U.S. gallons
per minute) at a pressure in excess of 5,000 pounds per square inch ("psi").
The pump rate and
pressure of the fracturing fluid may be even higher, for example, flow rates
in excess of 100
barrels per minute and pressures in excess of 10,000 psi are often
encountered..
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[0035] To fracture a subterranean formation typically requires hundreds of
thousands
of gallons of fracturing fluid. Further, it is often desirable to fracture at
more than one downhole
location of a well. Thus, a high volume of fracturing fluid is usually
required to treat a well,
which means that a low-cost fracturing fluid is desirable. Because of the
ready availability and
relative low cost of water compared to other liquids, a fracturing fluid is
usually water-based.
[0036] The formation or extension of a fracture in hydraulic fracturing may
initially
occur suddenly. When this happens, the fracturing fluid suddenly has a fluid
flow path through
the fracture to flow more rapidly away from the wellbore. As soon as the
fracture is created or
enhanced, the sudden increase in the flow of fluid away from the well reduces
the pressure in the
well. Thus, the creation or enhancement of a fracture in the formation may be
indicated by a
sudden drop in fluid pressure, which can be observed at the wellhead. After
initially breaking
down the formation, the fracture may then propagate more slowly, at the same
pressure or with
little pressure increase.
[0037] A newly-created or extended fracture will tend to
close together after the
pumping of the fracturing fluid is stopped. To prevent the fracture from
closing, a material must
be placed in the fracture to keep the fracture propped open. A material used
for this purpose is
referred to as a "proppant."
[0038] The proppant is in the form of a solid particulate, which can be
suspended in the
fracturing fluid, carried downhole, and deposited in the fracture as a
"proppant pack." The
proppant pack props the fracture in an open condition while allowing fluid
flow through the
permeability of the pack. A particulate for use as a proppant is selected
based on the
characteristics of size range, crush strength, and insolubility.
[0039] The proppant is an appropriate size to prop open the fracture and allow
fluid to
flow through the proppant pack, that is, in between and around the proppant
making up the pack.
Appropriate sizes of particulate for use as a proppant are typically in the
range from about 8 to
about 100 U.S. Standard Mesh. A typical proppant is sand sized, which
geologically is defined
as haying a largest dimension ranging from 0.0625 millimeters up to 2
millimeters (mm). (The
next smaller particle size class below sand sized is silt, which is defined as
having a largest
dimension ranging from less than 0.0625 mm down to 0.004 mm.) Preferably, the
proppant has
a particulate size distribution range such that at least 90% of the proppant
has a size of 0.0625
mm to 1.0 mm. For this purpose, "proppant" does not mean or refer to suspended
solids, silt,
fines, or other types of insoluble particulate smaller than 0.0625 mm.
Further, it does not mean
or refer to particulates larger than 2 mm.
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100401 The proppant is sufficiently strong, that is, has a sufficient
compressive or crush
resistance, to prop the fracture open without being deformed or crushed by the
closure stress of
the fracture in the subterranean formation. For a proppant material that
crushes under closure
stress, the proppant preferably has an API crush strength of at least 4,000
psi closure stress
based on 10% crush fines for 20/40 mesh proppant or 16% crush fines for 12/20
mesh proppant
according to procedure API RP-56. This performance is that of a medium crush-
strength
proppant, whereas a very high crush-strength proppant would be 10,000 psi. The
higher the
closing pressure of the formation of the fracturing application, the higher
the strength of
proppant is needed.
100411 Further, a suitable proppant should not dissolve in fluids commonly
encountered in a well environment. Preferably, a material is selected that
will not dissolve in
water or crude oil.
100421 Suitable proppant materials include, but are not limited to, sand
(silica), ground
nut shells or fruit pits, sintered bauxite, glass, plastics, ceramic
materials, processed wood, resin
coated sand or ground nut shells or fruit pits or other composites, and any
combination of the
foregoing. Mixtures of different kinds or sizes proppants can be used as well.
If sand is used, it
typically will be from about 20 to about 100 U.S. Standard Mesh in size. For a
synthetic
proppant, mesh sizes from about 8 ¨ 100 typically are used.
100431 The proppant pack in the fracture provides a higher-permeability flow
path for
the oil or gas to reach the wellbore compared to the permeability of the
surrounding
subterranean formation. This flow path increases oil and gas production from
the subterranean
formation.
100441 The concentration of proppant in the treatment fluid is preferably in
the range of
from about 0.03 kilograms to about 12 kilograms of proppant per liter of
liquid phase (from
about 0.1 lb/gal to about 25 lb/gal).
Well Treatment - Gravel Packing
100451 An insoluble solid particulate also can be used for "gravel packing"
operations.
The insoluble particulate, when used for this purpose, is referred to as
"gravel." More
particularly in the oil and gas field and as used herein, the term "gravel" is
sometimes used to
refer to relatively-large insoluble particles in the sand size classification,
that is, particles
ranging in diameter from about 0.5 mm up to about 2 mm. Generally, low-
strength proppants
are used in gravel packing including sand.
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Increasing Viscosity of Fluid for Suspending Particulate
[0046] Various particulates can be employed in a fluid for use in a well or a
fluid can
be used to help remove particulates from a well. As used herein, "particulate"
or "particulate
material" refers to matter in the physical form of distinct particles. The
distinct particles have a
high tendency to disperse. This tendency may be, for example, because the
particles have
already been dispersed (e.g., the water molecules of steam) or because the
distinct particles are
too large to be appreciably affected by Intermolecular Forces (e.g., dust or
sand). In the context
of oil and gas wells, a particulate can be a material that has particle sizes
ranging anywhere from
or between that of fines (measured in micrometers) and that of rock cuttings
(up to a few
centimeters).
[0047] For example, during drilling, rock cuttings should be carried by the
drilling
fluid and flowed out of the wellbore. The rock cuttings typically have
specific gravity greater
than 2.
100481 Similarly, a proppant used in hydraulic fracturing typically has a much
different
density than water. For example, sand has a specific gravity of about 2.7,
where water has a
specific gravity of 1.0 at room temperature and pressure. A proppant having a
different density
than water will tend to separate from water very rapidly.
[0049] Increasing the viscosity of the water using a viscosity-increasing
agent can help
prevent a particulate having a different specific gravity than an external
phase of the fluid from
quickly separating out of the external phase.
Increasing Viscosity with Emulsions
[0050] The internal-phase droplets of an emulsion disrupt streamlines and
require more
effort to get the same flow rate. Thus, an emulsion tends to have a higher
viscosity than the
external phase of the emulsion would otherwise have by itself. This property
of an emulsion can
be used to help suspend a particulate material in an emulsion. This technique
for increasing the
viscosity of a liquid can be used separately or in combination with other
techniques for
increasing the viscosity of a fluid.
Increasing Viscosity with Viscosity-Increasing Agent
[0051] A viscosity-increasing agent is sometimes known in the art as a
"thickener" or a
"suspending agent," but it should be understood that increasing the viscosity,
without more, may
only slow the settling or separation of distinct phases.
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[0052] Some viscosity-increasing agents can also help suspend a particulate
material
by increasing the elastic modulus of the fluid. An example of a viscosity-
increasing agent that
also increases the elastic modulus of a fluid is a viscoelastic surfactant. An
elastic modulus is
the measure of a substance's tendency to be deformed non-permanently when a
force is applied
to it. The elastic modulus of a fluid, commonly referred to as G', is a
mathematical expression
and defined as the slope of a stress versus strain curve in the elastic
deformation region. G' is
expressed in units of pressure, for example, Pa (Pascals) or dynes/cm2. As a
point of reference,
the elastic modulus of water is negligible and considered to be zero.
Viscosity-Increasing Agent - Water-Soluble Polysaccharides or Derivatives
[0053] A water-soluble polysaccharide can be used to increase the viscosity of
a fluid.
In general, the purpose of using such a polysaccharide is to increase the
ability of the fluid to
suspend and carry a particulate material.
100541 A polysaccharide can be classified as being non-helical or helical (or
random
coil type) based on its solution structure in aqueous liquid media. Examples
of non-helical
polysaccharides include guar, guar derivatives, and cellulose derivatives.
Examples of helical
polysaccharides include xanthan, diutan, and scleroglucan, and derivatives of
any of these.
[0055] As used herein, a "polysaccharide" can broadly include a modified or
derivative
polysaccharide. As used herein, "modified" or "derivative" means a compound or
substance
formed by a chemical process from a parent compound or substance, wherein the
chemical
skeleton of the parent exists in the derivative. The chemical process
preferably includes at most
a few chemical reaction steps, and more preferably only one or two chemical
reaction steps. As
used herein, a "chemical reaction step" is a chemical reaction between two
chemical reactant
species to produce at least one chemically different species from the
reactants (regardless of the
number of transient chemical species that may be formed during the reaction).
An example of a
chemical step is a substitution reaction. Substitution on a polymeric material
may be partial or
complete.
[0056] A guar derivative can be selected from the group consisting of, for
example, a
carboxyalkyl derivative of guar, a hydroxyalkyl derivative of guar, and any
combination thereof.
Preferably, the guar derivative is selected from the group consisting of
carboxymethylguar,
carboxymethylhydroxyethylguar, hydroxyethylguar,
carbox ym eth yl h ydrox yprop y I guar,
ethylcarboxymethylguar, and hydroxypropylmethylguar.
100571 A cellulose derivative can be selected from the group consisting of,
for
example, a carboxyalkyl derivative of cellulose, a hydroxyalkyl derivative of
cellulose, and any
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combination thereof. Preferably, the cellulose derivative is selected from the
group consisting of
carboxymethylcellulose,
carboxymethylhydroxyethylcellulose, hydroxyethylcellulose,
methylcellulose, ethylcellulose, ethylcarboxymethylcellulose, and
hydrox ypropyl m ethyl cellulose.
[0058] As used herein, a polysaccharide is considered to be water soluble if
it is
soluble to the extent of at least 10 mg per liter in deionized water at 25 C.
More preferably, the
water-soluble polymer is also soluble to the extent of at least 10 mg per
liter in an aqueous
sodium chloride solution of 32 grams sodium chloride per liter of deionized
water at 25 C. If
desired, the water-soluble polymer can be mixed with a surfactant to
facilitate its solubility in
the water or salt solution utilized. The water-soluble polymer can have an
average molecular
weight in the range of from about 50,000 to 20,000,000, most preferably from
about 1,000,000
to about 3,000,000.
Viscosity-Increasing Agent - Crosslinking of Polysaccharide to Form a Gel
[0059] Because of the high volume of fracturing fluid typically used in a
fracturing
operation, it is desirable to efficiently increase the viscosity of fracturing
fluids to the desired
viscosity using as little viscosity-increasing agent as possible. Being able
to use only a small
concentration of the viscosity-increasing agent requires a lesser amount of
the viscosity-
increasing agent in order to achieve the desired fluid viscosity in a large
volume of fracturing
fluid. Efficient and inexpensive viscosity-increasing agents include water-
soluble polymers.
Typical water-soluble polymers used in well treatments are water-soluble
polysaccharides and
water-soluble synthetic polymers (e.g., polyacrylamide, etc.). The most common
water-soluble
polysaccharide employed in well treatments is guar and its derivatives.
10060] The viscosity of a fluid at a given concentration of viscosity-
increasing agent
can be greatly increased by crosslinking the viscosity-increasing agent. A
crosslinking agent,
sometimes referred to as a crosslinker, can be used for this purpose. One
example of a
crosslinking agent is the borate ion. If a polysaccharide is crosslinked to a
sufficient extent, it
can form a gel with water. Gel formation is based on a number of factors
including the
particular polymer and concentration thereof, the particular crosslinker and
concentration
thereof, the degree of crosslinking, temperature, and a variety of other
factors known to those of
ordinary skill in the art.
100611 A "base gel" is a fluid that includes a viscosity-increasing agent,
such as guar,
but that excludes crosslinking agents. Typically, a base gel is a fluid that
is mixed with another
fluid containing a crosslinker, wherein the mixed fluid is adapted to form a
gel after injection
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downhole at a desired time in a well treatment. A base gel can be used, for
example, as the
external phase of an emulsion.
Breaker for Viscosified Fluid
[0062] After a viscosified well fluid has served its purpose, it is often
desirable to
subsequently reduce the viscosity of the well fluid so that it can be more
easily flowed back
from a portion of a well.
[0063] Drilling or treatment fluids also commonly include a "breaker" for an
emulsifier
or other polymeric material to reduce the viscosity of the fluid after a
desired time. For
example, in the context of viscosity increase provided by a use of a
polysaccharide, the term
"break" or "breaker" as used herein refers to a reduction in the viscosity of
a fluid or gel by
some breaking of the polymer backbones or some breaking or reversing of the
crosslinks
between polymer molecules. No particular mechanism is necessarily implied by
the term. A
breaker for this purpose can be, for example, an acid, base, an oxidizer, an
enzyme, chelating
agent of metal crosslinker or a combination of these. The acids, oxidizers, or
enzymes can be in
the form of delayed-release or encapsulated breakers.
[0064] In the case of a crosslinked viscosity-increasing agent, for example,
one way to
diminish the viscosity is by breaking the crosslinks. For example, the borate
crosslinks in a
borate-crosslinked gel can be broken by lowering the pH of the fluid. At a pH
above 8, the
borate ion exists and is available to crosslink and cause gelling. At a lower
pH, the borate ion
reacts with proton and is not available for crosslinking, thus, an increase in
viscosity due to
borate crosslinking is reversible.
Polysaccharide as Friction Reducer
[0065] There are other uses for a water-soluble polysaccharide in a well
fluids. For
example, during the drilling, completion, and stimulation of subterranean a
well, it is common to
pump a water-based well fluid through tubular goods (e.g., pipes, coiled
tubing, etc.) and into a
subterranean formation adjacent a wellbore. A considerable amount of energy
may be lost due
to friction of the water-based well fluid in turbulent flow through the
tubular goods of the
wellbore. Because of these energy losses, additional pumping horsepower may be
necessary to
achieve the desired purpose of the well fluid. To reduce these energy losses,
a water-soluble
polysaccharide may be included in a water-based well fluid. The use of an
appropriate water-
soluble polysaccharide as a friction reducer in a well fluid is expected to
reduce the energy
losses due to friction.
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[0066] For example, in a "high-rate water fracturing treatment," proppant
suspension
in the treatment fluid is largely achieved by the high rate of pumping and the
high flow rate of
the treatment fluid. To reduce energy losses due to friction, a water-soluble
polysaccharide as a
friction reducer may be included in the fracturing fluid. While a fluid used
in high-rate water
fracturing may contain a water-soluble polysaccharide as a friction-reducing
polymer, the
polysaccharide is usually included in the fracturing fluid in an amount that
is sufficient to
provide the desired friction reduction without appreciably viscosifying the
fluid and usually
without a crosslinker. As a result, the fracturing fluids used in these high-
rate water-fracturing
operations generally have a lower viscosity than conventional fracturing
fluids.
Spacer Fluids
[0067] A spacer fluid is a fluid used to physically separate one special-
purpose fluid
from another. Special-purpose fluids are typically prone to contamination, so
a spacer fluid
compatible with each is used between the two. A spacer fluid is used when
changing well fluids
used in a well. For example, a spacer fluid is used to change from a drilling
fluid during drilling
a well to a cement slurry during cementing operations in the well. In case of
an oil-based
drilling fluid, it should be kept separate from a water-based cementing fluid.
In changing to the
latter operation, a chemically treated water-based spacer fluid is usually
used to separate the
drilling fluid from the cement slurry. Another example is using a spacer fluid
to separate two
different treatment fluids.
Well Fluid Additives
10068] A well fluid can contain additives that are commonly used in oil field
applications, as known to those skilled in the art. These include, but are not
necessarily limited
to, inorganic water-soluble salts, breaker aids, surfactants, oxygen
scavengers, alcohols, scale
inhibitors, corrosion inhibitors, fluid-loss additives, oxidizers, and
bactericides.
Variations in Well Fluid over Time
[0069] Unless the specific context otherwise requires, a "well fluid" refers
to the
specific properties and composition of a fluid at the time the fluid is being
introduced through
the wellhead into a wellbore. In addition, it should be understood that,
during the course of a
well operation such as drilling, cementing, completion, or intervention, or
during a specific
treatment such as fluid-loss control, hydraulic fracturing, or a matrix
treatment, the specific
properties and composition of a type of well fluid can be varied or several
different types of well
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fluids can be used. For example, the compositions can be varied to adjust
viscosity or elasticity
of the well fluids to accommodate changes in the concentrations of proppant
desired to be
carried down to the subterranean formation from initial packing of the
fracture to tail-end
packing. It can also be desirable to accommodate expected changes in
temperatures encountered
by the well fluids during the course of the treatment. By way of another
example, it can be
desirable to accommodate the longer duration that the first treatment fluid
may need to maintain
viscosity before breaking compared to the shorter duration that a later-
introduced treatment fluid
may need to maintain viscosity before breaking. Changes in concentration of
the proppant,
viscosity-increasing agent, or other additives in the various treatment fluids
of a treatment
operation can be made in stepped changes of concentrations or ramped changes
of
concentrations.
Continuum Mechanics and Rheology
100701 One of the purposes of identifying the physical state of a substance
and
measuring the viscosity of a fluid substance is to establish whether it is
pumpable under the
ranges of physical conditions that may be encountered at a wellhead and with
the types and sizes
of pumps available to be used for pumping fluids into a well. Another purpose
is to determine
what the physical state of the substance and its physical properties will be
during pumping
through a wellbore and under other downhole conditions in the well, including
over time and
changing temperatures, pressures, and shear rates. For example, in some
applications, a well
fluid forms or becomes a gel under downhole conditions that later is broken
back to a fluid state.
[0071] Continuum mechanics is a branch of mechanics that deals with the
analysis of
the kinematics and the mechanical behavior of materials modeled as a
continuous mass rather
than as discrete particles. Rheology is the study of the flow of matter:
primarily in the liquid
state, but also as "soft solids" or solids under conditions in which they
respond with plastic flow
rather than deforming elastically in response to an applied force. It applies
to substances that
have a complex structure, such as muds, sludges, suspensions, gels, etc. The
flow of such
substances cannot be characterized by a single value of viscosity, which
varies with temperature,
pressure, and other factors. For example, ketchup can have its viscosity
reduced by shaking (or
other forms of mechanical agitation) but water cannot.
[0072] As used herein, if not other otherwise specifically stated, the
physical state of a
substance (or mixture of substances) and other physical properties are
determined at a
temperature of 77 F (25 C) and a pressure of I atmosphere (Standard
Laboratory Conditions)
without any applied shear.
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Fluid State and Viscosity
[0073] In general, a fluid is an amorphous substance that is or has a
continuous phase
and that tends to flow and to conform to the outline of its container.
Examples of fluids are
gases and liquids. A gas (in the sense of a physical state) refers to an
amorphous substance that
has a high tendency to disperse and a relatively high compressibility. A
liquid refers to an
amorphous substance that has little tendency to disperse and relatively high
incompressibility.
The tendency to disperse is related to Intermolecular Forces (also known as
van der Waal's
Forces).
[0074] Viscosity is the resistance of a fluid to flow. In everyday terms,
viscosity is
"thickness" or "internal friction." Thus, pure water is "thin," having a
relatively low viscosity
whereas honey is "thick," having a relatively higher viscosity. Put simply,
the less viscous the
fluid is, the greater its ease of movement (fluidity). More precisely,
viscosity is defined as the
ratio of shear stress to shear rate. The viscosity of a fluid is usually
expressed in units of
centipoise ("cP").
[0075] The physical state of a substance and the viscosity of a fluid are
highly
dependent on the nature of the substance and the physical conditions,
primarily temperature and
pressure. In addition, the physical state and the viscosity of a fluid may
depend on shear stress
and shear rate and the viscosity may vary over time with continuing shear.
Newton's law of
viscosity is an approximation that holds for some substances but not others.
Non-Newtonian
fluids exhibit a more complicated relationship between shear stress and
velocity gradient than
simple linearity. Thus, there exist a number of forms of viscosity. Newtonian
fluids, such as
water and most gases, have a constant viscosity with rate of shear. Shear
thickening fluids have
a viscosity that increases with the rate of shear. Shear thinning fluids have
a viscosity that
decreases with the rate of shear. Thixotropic fluids become less viscous over
time when shaken,
agitated, or otherwise stressed. Rheopectic fluids become more viscous over
time when shaken,
agitated, or otherwise stressed. A Bingham plastic is a material that behaves
as a solid at low
stresses but flows as a viscous fluid at high stresses.
[0076] There are numerous ways of measuring and modeling viscous properties,
and
new developments continue to be made. The methods depend on the type of fluid
for which
viscosity is being measured. A typical method for quality assurance or quality
control (QA/QC)
purposes uses a couette device, such as a Farm Model 50 viscometer, that
measures viscosity as
a function of time, temperature, and shear rate. The viscosity-measuring
instrument can be
calibrated using standard viscosity silicone oils or other standard viscosity
fluids. Due to the
geometry of most common viscosity-measuring devices, however, large particles
of solid
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particulate, such as proppant or gravel used in certain well treatments, would
interfere with the
measurement. Therefore, the viscosity of a fluid containing such large solid
particulate is
usually inferred by measuring the viscosity of a test fluid that is similar to
the fracturing fluid
without any proppant included.
Gel State and Deformation
100771 A gel state is a semi-solid, jelly-like state that can have properties
ranging from
soft and weak to hard and tough. Shearing stresses below a certain finite
value fail to produce
permanent deformation. The minimum shear stress which will produce permanent
deformation
is known as the shear or gel strength of the gel.
Substance of a Fluid or Gel Can Be a Dispersion
[0078] A dispersion is a system in which particles are dispersed in a external
phase of a
different composition or physical state. A dispersion can be classified a
number of different
ways, including based on the size of the dispersed-phase particles, whether or
not precipitation
occurs, and the presence of Brownian motion. For example, a dispersion can be
considered to
be homogeneous or heterogeneous based on being a solution or not, and if not a
solution, based
on the size of the dispersed-phase particles (which can also refer to droplet
size in the case of a
dispersed liquid phase).
[0079] The substance of a fluid can be a single chemical substance or a
dispersion. For
example, water (a liquid under Standard Laboratory Conditions) is a single
chemical by that
name. An aqueous salt solution is a dispersion.
[0080] The substance of a gel is a dispersion. The gel state is formed by a
network of
interconnected molecules, such as of a crosslinked polymer or of micelles,
with other molecules
in liquid form. The network gives a gel material its structure (hardness) and
contributes to
stickiness (tack). By weight, the substance of gels is mostly liquid, yet they
behave like solids
due to the three-dimensional network with the liquid. At the molecular level
(nanometer scale),
a gel is a dispersion in which the network of molecules is the continuous
(external) phase and
the liquid is the discontinuous (internal) phase; however, the gel state,
although heterogeneous,
is generally considered to be a single phase.
Classification of Dispersions: Homogeneous and Heterogeneous
10081] A dispersion is considered to be homogeneous if the dispersed phase
particles
are dissolved in solution or the particles are less than about 1 nanometer in
size.
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[0082] A solution is a special type of homogeneous mixture. A solution is
homogeneous because the ratio of solute to solvent is the same throughout the
solution and
because solute will never settle out of solution, even under powerful
centrifugation. An aqueous
solution, for example, saltwater, is a homogenous solution in which water is
the solvent and salt
is the solute.
[0083] Except for the special case of a solution, a dispersion is considered
to be
heterogeneous if the dispersed-phase particles are greater than about 1
nanometer in size. (For
reference, the diameter of a molecule of toluene is about 1 nm).
Classification of Heterogeneous Dispersions: Colloids and Suspensions
[0084] Dispersions can be further classified based on particle size and other
characteristics.
[0085] A heterogeneous dispersion is a "colloid" where the dispersed-phase
particles
are in the range of about 1 nanometer to about 50 micrometer in size.
Typically, the dispersed-
phase particles of a colloid have a diameter of between about 5 to about 200
nanometers. Such
particles are normally invisible to an optical microscope, though their
presence can be confirmed
with the use of an ultramicroscope or an electron microscope.
[0086] A heterogeneous dispersion is a "suspension" where the dispersed-phase
particles are larger than about 1 micrometer. Such particles can be seen with
a microscope, or if
larger than about 0.1 mm, with the naked eye.
Classification of Colloids or Suspensions: External Phase
[0087] Colloids or suspensions can have solid, liquid, or gas as the external
phase.
[0088] In the cases where the external phase of a dispersion is a liquid, for
a colloidal
fluid the dispersed-phase particles are so small that they do not settle.
Unlike colloids, however,
a suspension of particles dispersed in a liquid external phase will eventually
separate on
standing, e.g., settle in cases where the particles have a higher density than
the liquid phase.
Suspensions having a liquid external phase are essentially unstable from a
thermodynamic point
of view; however, they can be kinetically stable over a large period of time,
depending on
temperature and other conditions.
[0089] An example of a suspension of a solid in a liquid would be sand in
water. In
case the dispersed-phase particles are liquid in an external medium that is
another liquid, this
kind of suspension is more particularly referred to as an emulsion.
Suspensions and emulsions
are commonly used as well fluids.
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Emulsions
[0090] More particularly, an emulsion is a dispersion of immiscible liquid as
droplets
into an external liquid phase. In addition, the proportion of the external and
internal phases is
above the solubility of either in the other. A chemical (an emulsifier or
emulsifying agent) can
be included to reduce the interfacial tension between the two immiscible
liquids to help with
stability against coalescing of the internal liquid phase.
100911 An emulsion can be an oil-in-water (o/w) type or water-in-oil (w/o)
type. A
water-in-oil emulsion is sometimes referred to as an invert emulsion. In the
context of an
emulsion, a "water" liquid phase refers to water or an aqueous solution and an
"oil" liquid phase
refers to any organic liquid that is immiscible with water, such as an
oleaginous liquid.
Examples of oleaginous liquids include: diesel, kerosene, mineral oil, an
ester, an alpha-olefin,
crude oil, synthetic oil, and any combination thereof.
[0092] It should be understood that multiple emulsions are possible, which are
sometimes referred to as nested emulsions. Multiple emulsions are complex
polydispersed
systems where both oil-in-water and water-in-oil emulsions exist
simultaneously in the fluid,
wherein the oil-in-water emulsion is stabilized by a lipophilic surfactant and
the water-in-oil
emulsion is stabilized by a hydrophilic surfactant. These include water-in-oil-
in-water (w/o/w)
and oil-in-water-in-oil (o/w/o) type multiple emulsions. Even more complex
polydispersed
systems are possible. Multiple emulsions can be formed, for example, by
dispersing a water-in-
oil emulsion in water or an aqueous solution, or by dispersing an oil-in-water
emulsion in oil.
Foams
10093] In addition, a dispersion can be a foam, which is a liquid that
includes a
dispersion of undissolved gaseous bubbles that foam the fluid, usually with
the aid of a chemical
(a foaming agent) to achieve stability.
Classification of Fluids: Water-Based or Oil-Based
10094] The continuous phase of a substance as a whole is the most external
phase,
regardless of the number of phases. As used herein, a "water-based fluid"
means that water or
an aqueous solution is the continuous phase of the fluid as a whole. In
contrast, an "oil-based
fluid" means that oil is the continuous phase of the fluid as a whole. In the
context of
classifying the one or more liquid phases of a fluid, a "water" liquid phase
refers to water or an
aqueous solution and an "oil" liquid phase refers to any organic liquid that
is immiscible with
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water, such as an oleaginous liquid. Examples of oleaginous liquids include:
diesel, kerosene,
mineral oil, an ester, an alpha-olefin, crude oil, synthetic oil, and any
combination thereof.
10095] It is desirable to improve methods for producing crude oil or natural
gas. It is
desirable to provide well fluids and methods for use in wells that provide
advantages over
known fluids and methods.
SUMMARY OF THE INVENTION
10096] Nanohybrid-containing fluids and methods of using such fluids in a well
are
provided. It is believed a nanohybrid can stabilize phase interfaces. The
methods include the
steps of: (a) forming or providing a well fluid comprising a nanohybrid; and
(b) introducing the
well fluid into a well. The fluids and methods can be used in various
applications for producing
oil or gas, such as in drilling, completion, or intervention operations.
100971 According to an embodiment of the invention, methods of using
nanohybrid-
stabilized emulsions in a well are provided. The methods include the steps of:
(a) forming an emulsion comprising:
(i) a nanohybrid;
(ii) water or an aqueous solution; and
(iii) a water-immiscible liquid;
(b) introducing a well fluid comprising the emulsion into a well; and
(c) after the step of introducing, modifying of the nanohybrid to break the
emulsion in
the well. According to the invention, it is recognized that the nanohybrid can
be modified or
completely destroyed, which can be used as a "switch" to selectively break the
emulsion. This
can be useful where the surface activity of the nanohybrid is needed for a
certain period and then
that surface activity is needed to be "turned off."
100981 According to another embodiment, methods of altering the wettability of
a
surface in a well are provided. The methods include the steps of:
(a) providing a well fluid comprising a nanohybrid;
(b) introducing the well fluid into a well to contact the surface in the
well,
wherein the contact angle of water or an oil on the surface is altered.
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[0005] According to yet another embodiment, foamed fluids including a
nanohybrid
and methods of using such a foamed fluid in a well are provided. The foamed
fluid includes:
(i) a nanohybrid; (ii) a liquid phase; and (iii) a gaseous phase. The methods
include the steps of:
(a) forming a foam comprising:
(i) a nanohybrid;
(ii) a liquid phase; and
(iii) a gaseous phase; and
(b) introducing a well fluid comprising the foam into the well.
According to this embodiment, a nanohybrid can be used to stabilize the liquid-
gaseous interface
of the foam, or an emulsion of the liquid phase, or both. The liquid phase can
be an oil-based
liquid or a water-based liquid. The liquid phase can be a single liquid phase
or an emulsion.
The foam can optionally include a particulate, such as a proppant, or other
components.
[0006] As will be appreciated by a person of skill in the art, the methods
according to
the invention can have application in various kinds operations involved in the
production of oil
and gas, including drilling, completion, and intervention, such as the various
examples described
in the background.
[0007] The features and advantages of the present invention will be apparent
to those
skilled in the art. While numerous changes may be made by those skilled in the
art, such
changes are within the scope of the invention, as defined by the claims.
DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS
AND BEST MODE
General Definitions and Usages
General Terms
[0008] The words "comprise," "containing," and "include" and all grammatical
variations thereof are intended to have an open, non-limiting meaning. For
example, a
composition comprising one component does not exclude the composition having
additional
components, an apparatus having an element or part does not exclude additional
elements or
parts, and a method having a step does not exclude methods having additional
steps.
[0009] While compositions, apparatuses, and methods are described in terms of
"comprising," "containing," or "including" various components, parts, or
steps, the
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compositions, apparatuses, and methods are that "consist essentially of" or
"consist of" the
various components, parts, and steps are specifically included and disclosed.
[0104] The indefinite articles "a" or "an" mean one or more than one of the
component, part, or step that the article introduces.
[0105] Whenever a numerical range of degree or measurement with a lower limit
and
an upper limit is disclosed, any number and any range falling within the range
is also intended to
be specifically disclosed. For example, every range of values (in the form
"from a to b," or
"from about a to about b," or "from about a to b," "from approximately a to
b," and any similar
expressions, where "a" and "b" represent numerical values of degree or
measurement) is to be
understood to set forth every number and range encompassed within the broader
range of values.
[0106] Terms such as "first," "second," "third," etc. are assigned arbitrarily
and are
merely intended to differentiate between two or more components, parts, or
steps that are similar
or corresponding in nature, structure or function, or action. For example, the
words "first" and
"second" serve no other purpose and are not part of the name or description of
the following
name or descriptive terms. Further, the mere use of the term "first" does not
require that there
be any "second" similar or corresponding component, part, or step. Similarly,
the mere use of
the word "second" does not require that there by any "first" or "third"
similar or corresponding
component, part, or step.
Specific Terms
[0107] As used herein, a material is considered to be "soluble" in a liquid if
at least 10
mg of the material can be dissolved in one liter of the liquid when tested at
77 F and 1
atmosphere pressure and considered to be "insoluble" if less than that.
[0108] Unless otherwise specified, any ratio or percentage means by weight.
[0109] As used herein, the phrase "by weight of the water" means the weight of
the
water of the continuous phase of the fluid as a whole without the weight of
any proppant,
viscosity-increasing agent, dissolved salt, or other materials or additives
that may be present in
the water.
101101 Unless otherwise specified, any doubt regarding whether units are in
U.S. or
Imperial units, where there is any difference U.S. units are intended herein.
For example,
"gal/Mgal" means U.S. gallons per thousand U.S. gallons.
101111 Unless otherwise specified, as used herein, the viscosity of a fluid is
measured
at 40 sec-1 and at room temperature of about 77 F (25 C).
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Nanohybrids for Stabilizing Emulsions
101121 According to an embodiment, a purpose of this invention is to use
nanohybrids
comprising a carbon nanotube and inorganic second component (e.g., silica,
alumina,
magnesium oxide, titanium oxide, etc.) for use in emulsions for oil-field
applications. More
particularly, these nanohybrids contain the hydrophobic carbon nanotube and
the hydrophilic
inorganic component (e.g., silica) attached to each other.
[0113] The inherent hydrophobic and hydrophilic character gives these
nanohybrids
surface-active properties. The hydrophilic-lipophilic balance ("HLB") of the
nanohybrid can be
tailored by chemical functionalization of the nanohybrid to get the desired
properties. More
specifically, the HLB can be tailored by functionalization of nanotubes to
make them more
hydrophilic. The nanotubes can be made progressively more hydrophilic to make
the HLB
higher assuming that in the beginning the nanohybrid has a low HLB, i.e., it
is more oil like. If
made to be too hydrophilic, however, the material will lose its surface-active
properties as there
would not be both a hydrophobic and hydrophilic part in the hybrid. This
invention takes
advantage of this in the forming and then breaking of an emulsion. Similarly,
if nanohybrid is
made to be too hydrophobic, the material will lose its surface-active
properties as there would
not be both a hydrophobic and hydrophilic part in the hybrid. This can also be
used as a method
to break the emulsion.
101141 The surface-active nanohybrids partition at the interface of an aqueous
phase
and an oil phase. This is different from conventional surfactants that form
micelles. The
thermodynamic energy required to displace particles stabilized or nanohybrid
stabilized
emulsion from the interface is very high in comparison to conventional
surfactants. Therefore,
these emulsions formed with surface-active nanohybrids are much more stable
than conventional
surfactants that form micelles. Without being limited by any theory, it is not
presently known
whether the nanohybrids form a micelle. But, it is believed the thermodynamic
reason these
hybrids at least form a more stable interface is that there is a collected
integral of all the energy
forces caused by the hybrid at the interface, whilst the normal single entity
surfactants can flow
in and out of the interface more easily. Pulling the relatively big nanohybrid
from the interface
is believed to require high energy.
10115] Nanohybrids are a new class of hybrid materials is made from carbon
nanotubes
(CNTs) and inorganic glasses or ceramics, which are sometimes known as CNT-
inorganic
hybrids. The many advantages of CNTs in hybrid materials include their high
aspect ratio
(>1,000) and tubular geometry, which provides ready gas access to a large
specific surface area
and percolation at very low volume fractions. CNTs have been combined with a
variety of
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inorganic compounds, including oxides, nitrides, carbides, chalcogenides, and
ceramics. In
contrast to nanocomposites, the CNTs are coaxially coated with the inorganic
compound.
Dominik Eder, Carbon Nanotube-Inorganic Hybrids, Chem. Rev. 2010, 110, 1348-
1385.
10116] In simple terms, CNTs are tubular structures made of rolled-up layers
of
interconnected carbon atoms with diameters ranging from about one nanometer to
tens of
nanometers and lengths up to tens of microns. CNTs can be open-ended or closed
by a
hemispherical fullerene-type cap, depending on the synthesis method. Along
with structures
related to those of fifflerenes, CNTs are considered a third allotropic form
of carbon, with the
others being diamond and graphite. They are classified as either (a) "single-
walled" tubes
(SWCNTs, 0.7 <d < 2 nm), which consist of a single layer of graphene sheet
seamlessly rolled
into a cylindrical tube, or (b) multiwalled CNTs (MWCNT, 1.4 <d < 150 nm),
which comprise
multiple concentric tubes separated by about 0.34 nm. In general, CNTs possess
large specific
surface areas due to their hollow geometry, while their structural integrity
and chemical
inertness support relatively high oxidation stability. Other advantages
include their exceptional
physical properties. Dominik Eder, Carbon Nanotube-Inorganic Hybrids, Chem.
Rev. 2010,
110, 1348-1385.
101171 In general, CNTs can be functionalized by (a) covalent attachment of
chemical
groups through bonding to the a-conjugated skeleton of the CNT or (b)
noncovalent adsorption
or wrapping of various functional molecules. The CNT reactivity is directly
related to the it-
orbital mismatch caused by an increased curvature. Therefore, a distinction
must be made
between the sidewall and the endcaps of a nanotube. The sidewalls can be
considered as curved
graphite, while the tips are like the structure of a fullerene hemisphere and
are thus relatively
reactive. Hence, most reactions will occur first at the tips and then on the
sidewalls. Dominik
Eder, Carbon Nanotube-Inorganic Hybrids, Chem. Rev. 2010, 110, 1348-1385.
[0118] The various synthesis strategies for CNT-inorganic hybrids can be
categorized
as ex situ and in situ techniques. The ex situ (building block) approach first
produces the
inorganic component in the desired dimensions and morphology (typically
spherical
nanoparticles), then modifies and attaches this component to the surface of
CNTs via covalent,
noncovalent, or electrostatic interactions. In contrast, the in situ approach
carries out the
synthesis of the inorganic component in the presence of pristine or
functionalized CNTs, onto
which the inorganic material grows as particles, nanowires, or thin films.
Dominik Eder,
Carbon Nanotube-Inorganic Hybrids, Chem. Rev. 2010, 110, 1348-1385.
101191 Surface-active nanohybrids are a new class of surfactant material. Such
nanohybrids were developed by Professor Daniel Resasco at the University of
Oklahoma, and
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are currently commercially available from SouthWest NanoTechnologies Inc. in
Norman,
Oklahoma. See MM Shen and Daniel E. Resasco, Emulsions Stabilized by Carbon
Nanotube-
Silica Nanohybrids, Langmuir 2009, 25(18), 10843-10851, June 17, 2009. These
nanohybrids
have been shown to make water-in-oil emulsions that are stable in temperature
range of about 50
C to about 250 C, pH range of I to 9, pressures of about 900 psi, and in salt
solutions. In
addition, the stability of the emulsion is not compromised by diluting the
emulsion with NaC1
solution. A minuscule amount of an aqueous liquid in a water-in-oil emulsion
comes out of the
emulsion, but the bulk remains in the emulsion. The nanohybrid made from multi-
walled
carbon nanotubes ("MWNT") gives better performance than single-walled carbon
nanotubes
("SWNT") in stabilizing emulsions. In addition, MWNT are currently much less
expensive than
SWNT, which provides a commercial advantage over SWNT.
Well Fluid as Emulsion
101201 If desired, the well fluids suitable for use in the present invention
may be used
in the form of an emulsion or including a liquid phase in the form of an
emulsion. An example
of a suitable emulsion would comprise an aqueous fluid comprising a viscosity-
increasing agent
and a hydrocarbon as another phase. In some embodiments, the external phase of
the emulsion
would be aqueous. For example, in some embodiments the emulsion can comprise
approximately 30% of an aqueous base fluid and 70% of a suitable hydrocarbon.
In other
embodiments, the external phase of the emulsion would be oil. In certain
embodiments, it may
be desirable to use an emulsion to, among other things, reduce fluid loss to
the subterranean
formation or to provide enhanced particulate suspension.
Step of Forming an Emulsion
101211 The invention can include a step of forming an emulsion comprising: (i)
a
nanohybrid; (ii) water or an aqueous solution; and (iii) a water-immiscible
liquid. Without being
limited by any theory, it is believed that the nanohybrid functions to help
emulsify and maintain
the stability of the emulsion. As used herein, an "emulsifier" means that it
helps prevent the
droplets of the internal dispersed phase from flocculating or coalescing in
the external phase.
The nanohybrid helps stabilize the emulsion, but optionally other surfactants,
particulate
materials, or polymers can also be included to further enhance the stability
of the emulsion.
101221 According to an embodiment, the nanohybrid has a hydrophilic-lipophilic
balance adapted to forming an oil-in-water emulsion. According to another
embodiment, the
nanohybrid has a hydrophilic-lipophilic balance adapted to forming a water-in-
oil emulsion.
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Generally, nanohybrids are hydrophobic prior to any derivatization and prior
to any
derivitization will make water-in-oil emulsion.
[0123] According to an embodiment, a dispersed phase of the emulsion comprises
a
chemical to be released from the dispersed phase upon the step of modifying
the nanohybrid to
break the emulsion. For example, the chemical to be released can include a
crosslinker or a
breaker for polysaccharide in fracturing applications in which delayed
crosslinking or breakage
is desired. It can also be used to release cement retarder or accelerator for
cementing
applications.
[0124] Preferably, the water-immiscible liquid is water insoluble.
10125] The emulsion can also include other additives.
[0126] The emulsion can also contain water-soluble salt(s) at a high-ionic
strength for
other purposes, for example, to increase the density of the continuous phase
of the emulsion or
to prevent the swelling of the clay in the formation. Preferably, the water-
soluble salt is selected
from the group consisting of: an alkali metal halide, alkaline earth halide,
alkali metal formate,
and any combination thereof in any combination.
[0127] The emulsion can contain a freezing-point depressant. More preferably,
the
freezing point depressant is for the continuous phase of the emulsion as a
whole. Preferably, the
freezing-point depressant is selected from the group consisting of water-
soluble ionic salts,
alcohols, glycols, urea, and any combination thereof in any proportion.
[0128] The emulsion can include water-soluble salt(s) at a high-ionic
strength. The
method can also include the step of adding the emulsion to an aqueous solution
of a high-ionic
strength prior to or during the step of introducing.
[0129] The emulsion can include a proppant. The method can include the step of
mixing the emulsion with another fluid comprising the proppant to form a
treatment fluid prior
to or during the step of introducing. Preferably, the proppant is in a
particulate size distribution
range such that at least 90% of the proppant has a size within the range of
0.0625 mm to 2.0
mm.
For fracturing in certain formations, such as shale formations, the proppant
may be down to
about 100 mesh.
Stability of the Emulsion Composition
101301 Preferably, an emulsion composition used in a method according to the
present
invention is highly stable under a wide range of downhole conditions such that
it will not cream,
flocculate, or coalesce in use downhole until the emulsion is broken. For
example, as used
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herein, it should be stable at 77 F for at least 10 days. In downhole
conditions at a higher
temperature, it should be stable for at least the time of the job until it is
desired to be broken.
[0131] As used herein, the term "cream" means at least some of the droplets of
a
dispersed phase converge towards the surface or bottom of the emulsion
(depending on the
relative densities of the liquids making up the continuous and dispersed
phases). The converged
droplets maintain a discrete droplet form. As used herein, the term
"flocculate" means at least
some of the droplets of a dispersed phase combine to form small aggregates in
the emulsion. As
used herein, the term "coalesce" means at least some of the droplets of a
dispersed phase
combine to form larger drops in the emulsion. It should be understood that an
emulsion is
visually examined for creaming, flocculating, or coalescing.
[0132] Preferably, an emulsion composition according to the invention is
stable under
one or more of certain conditions commonly encountered in the storage and use
of such an
emulsion composition for use in a well. For example, an emulsion composition
according to the
invention is preferably stable for storing, including under freeze-thaw
conditions, to high-
temperature well environments, to the addition of salts to give a high-ionic
strength to the water
phase of the emulsion, or to diluting the emulsion with high concentrations of
water or solutions
having high-ionic strength. Most preferably, an emulsion according to the
invention has all of
these advantages.
[0133] As used herein, stability to storing means stability to storing at 77
F for 10
days. As used herein, stability to "freeze-thaw conditions" means to cooling
from 77 F to 0 F
and warming back to 77 F. Preferably, the dispersed phase does not cream,
flocculate, or
coalesce when tested under a freeze-thaw cycle from 77 F to 0 F and back to
77 F. More
preferably, the dispersed phase does not cream, flocculate, or coalesce when
cooled and stored at
a temperature of 0 F for 10 days and then warmed to 77 F.
[0134] As used herein, "high-temperature conditions" means in the range of 230
F ¨
500 'F. Preferably, the emulsion does not cream, flocculate, or coalesce when
tested at for the
duration of the job under the temperature conditions of the job.
[0135] As used herein, "high-dilution conditions" means dilution with 5-20
times the
amount of the external phase. Preferably, the dispersed phase of the emulsion
does not cream,
flocculate, or coalesce when tested by dilution with at least 5 times the
amount of the external
phase at 77 'F. For example, the stability of a nanohybrid-stabilized oil-in-
water emulsion is
preferably not compromised by diluting the emulsion 15 times with 1 Molar NaC1
solution.
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Step of Storing the Emulsion before Use
[0136] The method can optionally include the step of storing the emulsion for
at least 7
days within a temperature range of 25 F ¨ 120 F between the step of forming
and the step of
introducing. The method can optionally include the step of storing the
emulsion under
conditions such that the emulsion undergoes at least one freeze-thaw cycle
between the step of
forming and the step of introducing.
Step of Introducing Emulsion into a Well
[0137] The method can optionally include a step of mixing the emulsion with
another
material to form a well fluid comprising the emulsion. A well fluid comprising
the emulsion can
include the emulsion as a nested emulsion in the fluid or the well fluid can
be a dilution or other
modification of the emulsion, provided that the emulsion is not broken before
the step of
introducing the well fluid into the well.
101381 In an embodiment, the well fluid introduced into the well can be the
emulsion.
101391 In another embodiment, the method can comprise a step of mixing the
emulsion
with a third fluid to form the well fluid prior to or during the step of
introducing the well fluid
into the well. In an embodiment, the well fluid introduced into the well
comprises the emulsion
as a nested emulsion in a third fluid that is the continuous phase of the well
fluid as a whole.
The third fluid can include water and a water-soluble polysaccharide. The
third fluid can
include at least a sufficient concentration of the water-soluble
polysaccharide to be capable of
forming a crosslinked gel upon mixing with a crosslinker. The third fluid can
optionally include
water and one or more inorganic ionic salts.
[0140] In an embodiment, the well fluid can include at least one additive
selected from
the group consisting of: a conventional surfactant, an anti-scaling agent, a
crosslinker, corrosion
inhibitor, and a breaker for polysaccharide or crosslinked polysaccharide.
10141] In yet another embodiment, the method can include a step of adding the
emulsion to an aqueous solution of a high-ionic strength salt prior to or
during the step of
introducing.
(0142] According to an embodiment, the well fluid has an elastic modulus of
greater
than 1 Pa as measured within the linear viscoelastic region.
10143] According to an embodiment, the well fluid is introduced into the well
at a rate
and pressure and directed to a subterranean formation at a rate and pressure
that is at least
sufficient to create at least one fracture in the subterranean formation of
the well. The well fluid
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can further include a proppant. For example, the method can include a step of
mixing the
emulsion with a third fluid comprising a proppant prior to or during the step
of introducing.
[0144] The step of introducing a well fluid comprising the emulsion into a
well can be
accomplished by pumping or injecting according to various techniques well
known in the art.
Step of Breaking the Emulsion
[0145] According to the invention, it is recognized that the surface activity
of these
nanohybrid surfactants can be modified or completely destroyed, which property
can be used as
a "switch" for breaking an emulsion stabilized by a nanohybrid surfactant.
101461 For example, oxidizing the carbon nanotube component and making it more
hydrophilic can change the surface activity. An example of a suitable oxidizer
is a nitric
acid/sulfuric acid mixture to generate hydroxyl and carboxyl groups on the
nanotubes to make
them hydrophilic. It is also contemplated that the silica of the nanohybrid
can be chemically
removed or made oil-wet making it more hydrophilic. For example, silica can be
reacted with
long chain quaternary amine compounds to make them hydrophobic thereby making
the whole
of the nanohybrid hydrophobic. This will result in dissolution of the
nanohybrid in the oil
phase, thus breaking the emulsion. Either approach can be used as a "switch"
useful in a variety
of oil field applications, where surface activity is needed for a certain
period and then that
surface activity is needed to be turned off. The silica can also be reacted
with silanes to make
them hydrophobic or reacted with epoxides containing a long chain alkyl group
to make them
hydrophobic.
[0147] The emulsion can also be broken by addition of chemicals that
functionalize the
nanotube or form charge-transfer complexes. A hydrophilic group can be
attached with the
moiety that forms a charge-transfer complex with the carbon nanotube.
[0148] An emulsion stabilized with a nanohybrid can also be broken by wrapping
the
nanohybrid in a water-soluble polymer.
[0149] For a nanohybrid made up of some inorganic material other than silica,
a
suitable chemical group can be attached to make it more hydrophobic to break
emulsion.
[0150] In some cases, these materials for modifying or destroying the
nanohybrid can
be included at the time of preparation of an emulsion. In other cases, the
material can be
pumped later to break the emulsion.
[0151] After the step of introducing, the methods include a step of modifying
of the
nanohybrid to break the emulsion in the well.
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101521 As used herein, to "break" an emulsion means to cause the creaming and
coalescence of emulsified drops of the internal dispersed phase so that they
the internal phase
separates out of the external phase. Breaking an emulsion can be accomplished
mechanically
(for example, in settlers, cyclones, or centrifuges) or with chemical
additives to increase the
surface tension of the internal droplets.
101531 Preferably, the step of modifying the nanohybrid is by modifying the
hydrophilic-lipophilic balance ("HLB") of the nanohybrid such that it would no
longer stabilize
the original emulsion.
10154] Preferably, according to one embodiment, the step of modifying the
nanohybrid
is with a strong oxidizing agent for the nanohybrid. The emulsion can be
broken by treating the
emulsion with an oxidizer such as nitric acid. The oxidizer functionalizes the
carbon nanotubes
of the nanohybrid and reduces their hydrophobic surface activity, thereby
breaking the emulsion.
Alternatively, an oxidizer can be incorporated in the aqueous phase of the
emulsion and the
emulsion can be tailored to self-degrade after a delay. An example of a
suitable oxidizing agent
is HNO3.
101551 According to an embodiment, the well fluid comprises a chemical for
modifying the hydrophilic-lipophilic balance of the nanohybrid. According to
another
embodiment, a chemical for modifying the hydrophilic-lipophilic balance of the
nanohybrid is
pumped separately from the well fluid, for example, as a post flush over the
well fluid or a pre-
flush that flows back over the well fluid.
Emulsion Applications
[0156] The nanohybrid emulsions can be very stable, including, for example, at
high
temperatures (up to 250 C), over a broad pH range, with high-ionic strength
aqueous phases,
and to high dilution. In addition, the nanohybrid can be tailored to have
desired HLB for
making emulsions useful in various applications. According to the methods, the
emulsion can
be chemically degraded or completely broken downhole.
10157] These nanohybrid emulsions can be used for various oil field
applications
described below, such as in drilling, completion, or intervention operations.
Drilling Fluid and Drilling
10158] The nanohybrids can be used to make emulsion-based well fluids for
drilling
and other application that can be used in the temperature range of 22 C to
250 C (71.6 F to
482 F). For drilling operations, water-in-oil emulsions are typically
desired; however, oil-in-
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water emulsions are sometimes used. Oil-in-water emulsions are used in certain
formations
where oil wetting of the formation surface is not desired. The emulsion can
also be used below
22 C where winterization of the emulsion is undertaken by addition of salt to
water phase or
adding glycols or alcohols to the aqueous phase of the emulsion. For example,
the stability of an
oil-in-water emulsion is not compromised by diluting the emulsion (e.g., 15
times with 1 Molar
NaC1 solution). This is an advantage while drilling through a water-bearing
formation, where
integrity of the emulsion would otherwise be compromised by dilution with the
invading water.
[0159] The emulsion can be broken by treating the emulsion with a chemical to
change
the surface activity of the nanohybrid according to one of the techniques
described above,
thereby breaking the emulsion. This is a way to remove a filter cake built by
these drilling
fluids. Alternatively, an chemical can be incorporated in the aqueous phase of
the emulsion and
the emulsion can be tailored to self-degrade after a delay.
Cementing Fluid and Cementing
[0160] An emulsion stabilized with a nanohybrid can be used to deliver an
accelerator
for delayed setting of a cement in a cementing application. The emulsion can
be part of a
cementing fluid. For example, the cement accelerator such as calcium chloride
can be
solubilized in the aqueous phase and then emulsion is prepared with nanohybrid
and oil. The
aqueous phase can optionally have breaker to break the emulsion to release
calcium chloride
accelerator. Similarly oxidizer can be encapsulated in the water-in-oil
emulsion which can be
broken down in cement by techniques described previously thereby releasing
oxidizer that react
with cement retarders present in the cement slurry to accelerate the setting
of the cement. The
emulsion can be broken by treating with a chemical to change the surface
activity of the
nanohybrid according to one of the techniques described above, thereby
breaking the emulsion
when desired to release the retarder or accelerator.
Fluid-Loss Control Pill and Fluid-Loss Control
101611 An emulsion stabilized with a nanohybrid can be used in a fluid-loss
control
pill. In the fluid-loss pill the emulsion can contain oxidizer for breakage of
the fluid-loss pill
polymer and slowly release the breaker to break the pill. The emulsion can be
broken by
treating with a chemical to change the surface activity of the nanohybrid
according to one of the
techniques described above, thereby breaking the emulsion when desired. The
emulsion can
also be used to incorporate a crosslinker in the emulsion that may release
slowly to crosslink the
polymer. This will give the time to place the pill at a desired downhole
location in the wellbore.
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These pills are very thick (e.g., 110 lb/Mgal crosslinked gels) and difficult
to pump if fully
crosslinked at the surface, that is, above the wellhead. Delaying the
crosslinking until the pill
reaches the downhole location is desirable. In other embodiments, water-in-oil
emulsions can be
used as a fluid-loss control agent as the droplets can be made big enough to
plug the formation
pores. This emulsion can be used in fracturing fluid or the pad to give the
fluid-loss
characteristic. The breaker inside the emulsion can break the emulsion and
thus release the
obstruction of pores after the job.
Acidizing Fluid and Acidizing
101621 The nanohybrid can be used in the acidizing of carbonate rock. The
nanohybrid
can be used to make 15% HCI emulsion in oil (continuous phase) and can be
pumped in the
carbonate formation as a kind of matrix treatment. This nanohybrid-stabilized
emulsion will
provide acid systems that will slowly etch the carbonate formation and will
help in making a
longer fracture. Optionally polymers that gel the aqueous phase of the
emulsion can be used to
prevent the leakage of acid prematurely.
101631 Controlling acid reaction rates by incorporation of the acid as an
internal phase
in an emulsion is well known. For ultra hot wells, such as the 'Chaff in Saudi
Arabia, the
conventional acid gel systems are not as temperature stable as the nanohybrid-
stabilized
emulsions would be, and thus new high-temperature acid retardation can be
obtained.
101641 The emulsion can be broken when desired by modifying the nanohybrid.
For
example, the aqueous phase can be loaded with an oxidizer to self-break the
emulsion after a
delay. Other examples of techniques for breaking the emulsion stabilized with
a nanohybrid are
described above.
Fracturing Fluid and Fracturing
101651 Nanohybrid emulsions can be used to produce viscous fracturing fluids
through
emulsification that are stable at temperatures not currently obtainable even
with synthetic
polymers. The emulsion can be broken as desired, breaking at least some of the
viscosity of the
fluid. Besides applications at high temperature (up to 250 C), the resulting
conductivity
impairment from the broken emulsion would be negligible, providing a benefit
relative to most
polymer thickened materials.
101661 In addition, if the water phase of the emulsion is gelled, as in the
Halliburton
SuperEmulsifracTm system, and the encapsulation feature of the invention is
used (described
below), it would provide a two-phase viscous system and a delayed crosslink
feature, too.
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[0167] For a fracturing application, a high internal phase emulsion ("HIPE
emulsion"),
which is water-in-oil, can be made with the nanohybrid system. High internal
phase water-in-oil
emulsions are defined as having greater than about 80% dispersed aqueous
phase. These
emulsions are capable of carrying proppants.
Fluid for Frac Packing or Gravel Packing
[0168] The nanohybrid can be used to stabilize an emulsion for use in "frac
packing"
or "gavel packing" operations. The emulsion can be broken as desired, breaking
at least some of
the viscosity of the fluid. Again, the nanohybrid-stabilized emulsion has
applications at high
temperature (up to 250 C), the resulting conductivity impairment from the
broken emulsion
would be negligible, providing a benefit relative to most polymer thickened
materials.
Emulsion Encapsulation for Delayed Chemical Release in a Well Application
[0169] A nanohybrid can also be used to encapsulate a chemical in an internal
phase of
an emulsion and then selectively break the emulsion to release the chemical in
a controlled
manner for use in a well operation, such as drilling, cementing, or treatment.
[0170] For example, a water-soluble chemical can be encapsulated in the
internal water
phase of a water-in-oil emulsion stabilized with a nanohybrid. The water-in-
oil emulsion can
then be emulsified in an outer water phase or aqueous fluid, either with a
suitable conventional
emulsifier or with a suitable nanohybrid. Upon breaking of the water-in-oil
emulsion, the water-
soluble chemical is released from the oil of the water-in-oil emulsion into
the outer water phase.
[0171] Similarly, an oil-soluble chemical can be encapsulated in the internal
oil phase
of an oil-in-water emulsion stabilized with a nanohybrid. The oil-in-water
emulsion can then be
emulsified in an outer oil phase, either with a suitable conventional
emulsifier or with a suitable
nanohybrid. Upon breaking the oil-in-water emulsion, the oil-soluble chemical
is released from
the water of the oil-in-water emulsion into the outer oil phase. For example,
esters can be
solubilized in oil phase of the emulsion and then they hydrolyze to provide
organic acids that
can be used to break crosslinked fluid, solubilize calcium carbonate in filter
cake to break filter
cake and similar applications.
[0172] In an embodiment, the nanohybrid of the present invention can be doped
with a
crosslinker for a fracturing fluid. The rate of release would be adjusted to
obtain the proper
crosslink time. For example, as a fracturing fluid heats in a formation, being
able to deliver via
controlled release additional crosslinker or a different crosslinker would
provide benefits in a
fracturing treatment.
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[0173] In another embodiment, a water-soluble breaker (for example, an enzyme,
oxidizer, acid, etc.) for a crosslinked gel can be contained in the internal
water phase of a water-
in-oil emulsion stabilized with a nanohybrid. The water-in-oil emulsion is
itself emulsified in an
outer aqueous phase. Upon breaking the water-in-oil emulsion, the breaker is
released from
inside the oil phase to break an aqueous fracturing gel of the outer-aqueous
phase after a desired
delay.
[0174] Similarly, these techniques can be employed to encapsulate a breaker
for a filter
cake to help break the filter cake from the inside. Polymer-based fluid-loss
control pills often
require long cleanup periods. Moreover, an effective cleanup usually requires
fluid circulation
to provide high driving force, which allows diffusion to take place to help
dissolve the
concentrated build up of materials. Such fluid circulation may not be
feasible. Additional
methods of delivering or releasing a chemical to help remove a filter cake are
desirable.
Viscous Sweep Application
[0175] Emulsions made by the nanohybrid can also be used to form a viscous
fluid for
viscous sweeps. In this application, a relatively small volume of viscous
fluid is circulated to
sweep, or remove, debris or residual fluids from the circulation system. The
viscosity of the
fluid can be broken by modifying the nanohybrid.
Spacer Fluid Application
[0176] A nanohybrid-stabilized emulsion can be used in a spacer fluid, for
example, in
a cement spacer. The nanohybrid can be used to control the viscosity of the
spacer without the
need for any polymer, can be broken on demand, and also the desired aqueous
phase can be
weighted with clear fluids, or the internal phase of the emulsion set to yield
the desired
viscosity. The high temperature stability of the emulsion allows achievement
of higher
temperatures than currently capable conventional polymers.
Swellable Packer Application
101771 Rubber swellable packers are used to close the annulus between
formation and
the pipe. An oil-in-water emulsion stabilized according to the invention can
be used to swell a
swellable packer having an oil-swelling rubber element after a delay. A water-
in-oil emulsion
can be used to swell a swellable packer having a water-swelling packing
material after a delay.
A delay is desired for positioning the packer at the appropriate location in a
wellbore before
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swelling the packer. After placing the swell packer the emulsion is broken by
the methods
described so that the internal phase can swell the packer and set it in place.
Treatment Fluid and Methods for Changing the Wettability of Solid Surfaces in
Wells
101781 After a treatment of a portion of a well, some of the fluid is trapped
in the
formation or proppant pack and cannot be flowed back through and out of the
well. For
example, the success of a fracturing treatment is related to the amount of the
fracturing fluid
recovered after the treatment. Normally, the more fracturing fluid that is
recovered, the higher
the production of the well after the treatment.
101791 Recovery of the fluid depends on several factors and among them
capillary
pressure is one of the most important. The capillary pressure AP is governed
by a simple, albeit
approximate, relation as shown in the following equation:
AP = ¨cos
where a represents the surface tension of the fluid, r the radius of pore
throat, and 0 the contact
angle. For a certain formation, pore throat size r is constant, and therefore
there are only two
parameters, namely o and 0, that can be adjusted to manipulate the capillary
pressure.
101801 A common method is to add surfactants to the well fluid to reduce the
surface
tension 6 and thus the capillary pressure AP, and consequently, the resistance
to flowback. The
limitation of the approach is that it is very hard to reduce the surface
tension of an aqueous fluid.
101811 Another method is to alter the wettability of a subterranean formation.
Wetting
and wettability involve the contact between a liquid and a solid surface,
resulting from the
intermolecular interactions when the two are brought together. The amount of
wetting depends
on the energies (or surface tensions) of the interfaces involved such that the
total energy is
minimized. One measurement of the degree of wetting is the contact angle, the
angle at which
the liquid-vapor interface meets the solid-liquid interface. If the wetting is
very favorable, the
contact angle will be low, and the fluid will spread to cover or "wet" a
larger area of the solid
surface. If the wetting is unfavorable, the contact angle will be high, and
the fluid will form a
compact, self-contained droplet on the solid surface. If the contact angle of
water on a surface is
low, the surface may be said to be "water-wetted" or "water-wettable," whereas
if the contact
CA 02860793 2016-01-04
angle of an oil droplet on a surface is low, the surface may be said to be
"oil-wetted" or "oil-
wettable."
[0010] As used herein, a water-wet surface has a contact angle for water
between 0 to
90 degrees. A surface having a contact angle at or above ninety degrees for
water is described
as non-water wet. Similarly, an oil-wet surface has a contact angle for oil
between 0 to 90
degrees. A surface having a contact angle at or above ninety degrees for oil
is described as non-
oil wet.
[0011] The wettability of the formation can be altered by changing the contact
angle of
the formation. By changing the contact angle, the capillary pressure to a
water-based or oil-
based fluid can be greatly changed. For example, when the contact angle 0
becomes 90 , cos 0
becomes zero, and so does the capillary pressure, or when the contact angle is
larger than 90 ,
cos 0 becomes negative, meaning the fluid is repelled by the pores in a
subterranean formation.
[0012] One method of changing the wettability of a solid surface is using a
chemical
agent selected from a group consisting of organosiloxane, organosilane, fluoro-
organosiloxane,
fluoro-organosilane, and fluorocarbon. The fluid contains a sufficient amount
of the agent to
alter the wettability of the formation when the fluid contacts the formation.
Fluids according to
the present invention can further comprise nanoparticles. Optionally,
nanoparticles, for example
Si02 nanoparticles, can be added into a fluid comprising such a chemical
agent. Nanoparticles
are normally considered to be particles having one or more dimensions of the
order of 100 nm or
less. The surface property of a nanoparticle can be either hydrophilic or
hydrophobic.
Adsorption of the nanoparticles on the fracture surface or proppant surface
may further enhance
hydrophobicity and oleophobicity. Nanoparticles of different types and sizes
are commercial
available and have been used to treat solid surface, in combination with
hydrophobizing agents,
to make highly hydrophobic or oleophobic surfaces for various applications.
Such a well fluid
when introduced into a subterranean formation may alter the wettability of
pores in the
formation by changing the contact angle. Additional information regarding this
method is
disclosed in International Publication No. WO 2011/088556 Al published on 28
July 2011,
having for named inventors Kewei Zhang.
[0013] Other fluids are known to change the wettability of rock surfaces. For
example,
as discussed above, drilling fluids, also known as drilling muds or simply
"muds," are typically
classified according to their base fluid (that is, the continuous phase). In
water-based muds,
solid particles are suspended in water or brine. Oil can be emulsified in the
water as the
continuous phase. Brine-based drilling fluids are a water-based mud (WBM) in
which the
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aqueous component is brine. Oil-based muds (OBM) are the opposite or inverse.
Solid particles
are often suspended in oil, and water or brine is emulsified in the oil and
therefore the oil is the
continuous phase.
101861 Oil-based muds can be either all-oil based or water-in-oil
macroemulsions,
which are also called invert emulsions. In oil-based mud, the oil can consist
of any oil that may
include, but is not limited to, diesel, mineral oil, esters, or alpha-olefins.
OBMs as defined
herein also include synthetic-based fluids or muds (SBMs) which are
synthetically produced
rather than refined from naturally-occurring materials. SBMs often include,
but are not
necessarily limited to, olefin oligomers of ethylene, esters made from
vegetable fatty acids and
alcohols, ethers and polyethers made from alcohols and polyalcohols,
paraffinic, or aromatic
hydrocarbons, alkyl benzenes, terpenes and other natural products and mixtures
of these types.
101871 When OBMs, SBMs, or other non-aqueous fluids ("NAFs") are used, the
subterranean rock formations become oil wet and resistant to treatments using
well fluids that
are water-based. Non-limiting examples of water-based well fluids include high-
viscosity pills
to help lift cuttings out of a vertical wellbore; freshwater pills to dissolve
encroaching salt
formations; pills to free stuck pipe, such as to relieve differential sticking
forces or to destroy
filter cake; lost circulation or fluid loss pills to plug a thief zone or
inhibit fluid from being lost
into a relatively high permeability zone; and crosslink pills to deliver and
crosslink
polysaccharides such as guar gums to increase viscosity in a certain zone to
prevent or inhibit
fluid loss.
101881 Compositions and methods are desired to improve the ability to switch
or
convert the wettability of a rock formation or other solid surface that is oil-
wettable to a water-
wettable surface so that subsequently introduced water-based fluids would
perform or be more
effective. In some applications, it can also be desirable to change the
wettability in the reverse
direction.
[0189] It is believed, however, that fluids including a nanohybrid have not
been known
or used for altering the wettability of solid surface in a well.
101901 In a non-limiting embodiment, the present invention includes methods
and
compositions for changing the wettability of solid surfaces in wells. The well
fluid includes a
nanohybrid. Preferably, the fluid contains a sufficient amount and
concentration of a
nanohybrid to alter the wettability of the formation when the fluid contacts
the formation. The
contact angle can be determined under standard laboratory conditions or under
simulated
bottom-hole conditions of temperature and pressure, whichever may be adequate
or most useful
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to the application of the method. The wettability of a surface can be altered
for water or for an
oil.
101911 In one non-limiting embodiment, a method is provided for changing the
wettability of a rock formation or other solid surface in a well previously
contacted with an oil-
based mud (OBM). Generally, under such conditions the solid surface will have
become oil-
wet.
[0192] According to an embodiment, the method involves pumping such a well
fluid
into a subterranean formation, proppant pack, or other subterranean matrix of
solid material.
The well fluid with a nanohybrid can be one of several types, depending on the
particular
application. A person of skill in the art, with the benefit of this
disclosure, will be able to
determine the particular well fluid according to this invention that is
suitable for the intended
purpose of altering the wettability of the surface.
[0193] According to an embodiment, a method of altering the water wettability
of a
surface in a well, the method comprising the steps of: (a) providing a well
fluid comprising a
nanohybrid; and (b) introducing the well fluid into a well to contact the
surface, wherein the
contact angle of water on the surface is altered at least 10 . More
preferably, the contact angle
of water on the surface is altered at least 200.
[0194] In an embodiment of this method, it can further include the step of
determining
the contact angle of water on the subterranean formation or proppant pack
prior to the step of
introducing the well fluid. This step of determining can be based on
laboratory simulation or
based on actual testing of a solid particulate of the solid that is flowed
back from the well before
the treatment. In another embodiment, the method can further include the step
of determining
the contact angle of water on the subterranean formation or proppant pack or
other solid material
downhole after to the step of introducing the well fluid. This step of
determining can be based
on laboratory simulation or based on actual testing of a solid particulate of
the solid that is
flowed back from the well after the treatment.
[0195] According to another embodiment, a method of altering oil wettability
of a
surface in a well, the method comprising the steps of: (a) providing a well
fluid comprising a
nanohybrid; and (b) introducing the well fluid into a well to contact a the
surface, wherein the
contact angle of an oil on the surface is altered at least 10 . More
preferably, the contact angle
of the oil on the surface is altered at least 20 .
[0196] In an embodiment of this method, it can further include the step of
determining
the contact angle of the oil on the subterranean formation or proppant pack
prior to the step of
introducing the well fluid. In another embodiment, the method can further
include the step of
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determining the contact angle of the oil on the subterranean formation or
proppant pack after to
the step of introducing the well fluid.
101971 The oil liquid phase for determining the contact angle of oil can be an
oleaginous liquid. For example, the oleaginous liquid can be selected from the
group consisting
of: diesel, kerosene, mineral oil, an ester, an alpha-olefin, crude oil, and
synthetic oil, or any
combination thereof.
101981 According to an embodiment, the well fluid can include a composition
that is an
emulsion according to the invention, which composition contains: (i) at least
one nanohybrid;
(ii) water or an aqueous solution; and (iii) a water-immiscible liquid.
That is, these
compositions, e.g., an emulsion, are pre-formed.
101991 According to another embodiment, the well fluid can include be in situ
emulsion-forming components that include: (i) at least one nanohybrid; and
(ii) water or an
aqueous solution. That is, the emulsion is formed in situ downhole with the
water-immiscible
liquid already present on a solid surface to be treated with the well fluid.
For example, a liquid
already present on a solid surface can be adsorbed onto the surface.
102001 By the use of one or both of these types of well fluids, the rock
formation or
proppant matrix is thereby contacted with a emulsion composition or an
emulsion-forming
composition as described above. By this method, the wettability of at least
part or all of the rock
formation, proppant pack, or other solid surface downhole is changed.
Subsequently another
treatment fluid, whose performance requires water-wet surfaces, such as a
water-based treatment
fluid, is pumped into the rock formation, proppant pack, or other matrix, and
can be more
effective.
102011 The well fluid may optionally contain, for example, a surfactant, and
optionally
and a co-surfactant. For instance, if desired to form a microemulsion, it may
be helpful, but is
not always necessary, to add an alcohol co-surfactant, but in some instances
(e.g. ionic
surfactants at low temperature), it is often necessary or at least it makes
the process easier. In
many cases, the surfactant may be a surfactant blend and is often a surfactant
and co-surfactant
mixture, in which the co-surfactant is a short amphiphilic substance such as
an alcohol (in non-
limiting examples, propanol, butanol, pentanol in their different
isomerization structures) as well
as glycols, and ethoxylated and propoxylated alcohols or phenols. Alcohols are
also noted
herein as substances of intermediate polarity; that is, intermediate between
water-immiscible
substances such as oils and polar substances such as ethanol or water.
[02021 The well fluid can optionally contain, for example, an acid, such as a
mineral
acid or organic acid.
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102031 The majority of fluid-loss control pills and crosslirtk pills are
formulated as
water-based fluids. For this reason, it is desirable to remove the S/OBM and
achieve a reversal
of wettability in the formation, proppant pack, or other solid surfaces
downhole, which may be
naturally fractured or fracture induced, before pumping the fluid-loss control
pills or other
water-based well fluids. Other types of well fluids other than fluid-loss
pills, with which the
methods described herein would be effective include, but are not necessarily
limited to,
horizontal healer pills, reservoir rock cleaning pills, and crosslink pills.
The change in
wettability from oil-wet to water-wet increases the filtration rate or leak
off rate of the fluid loss
pill into the fractures and fracture tip and forms a tight plug that packs and
seals the fracture
voids. This method increases the tight packing of the particles of the fluid-
loss control pill (or
lost circulation pill) in the permeable and fractured formation, and in
consequence, improves the
effectiveness of the pill.
102041 Without being limited by any theory, it is believed this wettability-
changing
method may occur by solubilization of a significant portion of the non-polar,
water-immiscible
material and eventually polar material into an emulsion when the well fluid
contacts the oil-
wetted rock or other material. An in situ emulsion can be formed when one or
more
nanohybrids and a polar phase (e.g. usually, but not limited to, water)
contacts the reservoir
formation and solubilizes some or all of the non-polar, water-immiscible fluid
of the S/OBM or
S/OBM filter cake encountered in the porous media (e.g. rock or proppant).
102051 By "eventually" it is meant herein that the non-polar material and
nanohybrid at
some point later in time, such as downhole or separately added, contacts a
polar fluid, such as
reservoir fluids, or a fluid of intermediate polarity, such as a separately
added alcohol or co-
surfactant. By "eventually" it is meant that the contact is not necessary or
compulsory, but that
such eventual contact may not be ruled out.
102061 The in situ emulsion removes (at least partially) the S/OBM, the S/OBM
filter
cake, promotes reversal of the wettability of the solid surface, and at least
partially removes the
oil of the filter cake in oil and gas wells drilled with SBM or OBM. The
benefit of using an
emulsion or in situ emulsion before a high fluid-loss squeeze pill or other
water-based fluid
treatment is that the rock formation and solid particles of the filter cake
change from oil-wet to
water-wet, which increases the strength or effectiveness of the water-based
treatment fluid at the
interface with the rock formation or other solid surface. This phenomenon of
increasing the
strength or effectiveness of a water-based treatment fluid is particularly
important in the near
wellbore region.
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102071 One of the benefits of the in situ fluid formation of the emulsion is
that the well
fluid does not require any oil or other water-immiscible solvent in its
initial formulation, or at
least much less than the proportion that could be solubilized in the final
emulsion, which gives a
higher capacity for oil or non-polar material incorporation or cleaning
capability when contacted
with the OBM and other non-polar materials on the rock formation, proppant
pack, or other
matrix downhole. Another benefit is that any particles or other oil-wet
contamination turn from
oil-wet to water-wet. Additionally, the well fluid can improve damage
remediation (including,
but not limited to, filter cake destruction) when mineral acids, organic
acids, oxidizing agents,
water-soluble enzymes (e.g. catalysts), or precursors of these components
(e.g. in situ acid
generators) are spotted into a subterranean formation after the wettability
reversal process,
because it favors the contact between the acid and the particles.
10208] Without being limited by any theory, it is also believed this
wettability-
changing method may occur by depositing a layer of nanohybrid onto the oil-wet
surface. A
relatively non-polar end of the nanohybrid is believed to be capable of
interfacing with an oil-
wet surface, whereas the relatively polar end of the nanohybrid presents a
water-wet surface.
10209] Further, without being limited by any theory, it is believed the
nanohybrid can
adsorb at a liquid-solid interface to alter the wetting of the solid surface.
Flow characteristics in
porous media are altered by changing the contact angle as described by the
Young-LaPlace
equation. These nanohybrid materials can be added to any well fluid in order
to change the
wettability of formation, proppant, cement, or drilling fluid components as
desired. In hydraulic
fracturing, fluorocarbon surfactants have traditionally been applied for this
application. It is
believed the nanohybrid materials can be more permanent, cheaper, and easier
to apply to porous
media than the high molecular weight polymer fluorocarbons.
10210] In one non-restrictive version, it may be desirable to use acid or
other damage
removal additives but only after a wettability change and more likely, some
time after the
drilling phase. As the OBM (or SBM) is contacted by the well fluid and
absorbed or the oil-wet,
non-polar materials and rock surfaces are converted from oil-wet to water-wet
during the in situ
formation of an emulsion, the blend of nanohybrid and a polar phase (e.g.,
water) may also
contain acids, barite dissolvers (chelants) or other precursor additives that
can dissolve the acid-
soluble particles or dissolve the barite and other particulates and also break
down any polymeric
fluid loss additive (if present).
102111 The net effect of such well fluids and methods will be to improve an
operator's
ability to pump water-based treatment fluids into a reservoir, for instance to
improve fluid loss
control, and thereby improve production rates in producing wells or reduce the
costly loss of
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S/OBM drilling fluid in the fractured zone whether it be in the reservoir or
above the reservoir.
In either case, non-polar material alteration is accomplished by creating the
in situ-formed fluid
across the injection/production interval or pumping the pre-formed emulsion
into the formation.
[0212] It will be appreciated that it is not necessary for all of the oil-wet
rock or filter
cake to have its wettability reversed for the inventive method and its
compositions to be
considered successful. Success is obtained if more of the oil-wetted rock
formation is reversed
and becomes water-wetted using the compositions or methods herein, whether not
formed in situ
than if it is not used, or if more rock surface becomes relatively more water-
wet using the
emulsions, as compared to the case where no nanohybrid emulsions or other
similar
compositions are used. Alternatively, the methods and compositions are
considered successful
if at least a portion of the rock formation becomes water wet. In one non-
limiting embodiment
at least a majority (>50%) of the rock becomes water-wet. In general, of
course, it is desirable
to convert as much of the rock formation from oil-wet to water-wet as
possible. One non-
restrictive goal of the methods and compositions herein is to reverse the
wettability of the rock
to obtain a higher percentage of effectiveness of the subsequently introduced
water-based
treatment fluids.
[0213] The subterranean reservoir wettability reversal technology described
herein has
a wide range of applications. By combining the chemical aspect of wellbore
wetting
reversibility or clean up with displacement techniques, it is believed that
subterranean reservoir
disadvantages after drill-in with OBMs (e.g. invert emulsion fluids) may be
significantly
reduced or eliminated.
[0214] The methods and compositions herein may be used to alter or reverse the
wettability of subterranean rock, and may also remove, heal, or remediate
damage caused by
deposits of macromolecules from oils, such as the case of deposition of
asphaltenes in the
reservoir porous media. Other damage that may be removed includes any
emulsions that
incorporate or include any non-polar material (oil and other hydrocarbons)
from the reservoir, or
introduced in the drilling mud, as well as other substances injected downhole.
10215] Thus, the methods and compositions herein have the advantages of being
able
to reverse the wettability of subterranean rock prior to the pumping of a well-
fluid, such as a
fluid-loss pill, to increase and improve the adherence of the fluid-loss pill
or other well fluid to
the formation, and as a consequence, improve the effectiveness of the well
fluid, such as to
control, prevent, or inhibit lost circulation. The well fluid may also reduce
formation damage,
and consequently increase hydrocarbon recovery, or increase water injection
rate, as compared
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with an otherwise identical method and composition without the inventive
emulsions (in situ or
otherwise).
Foamed Fluids and Methods of Using Foamed Fluids
[0216] In some embodiments, the treatment fluids can be foamed (e.g., a liquid
that
includes a gaseous fluid, such as nitrogen, air, or carbon dioxide, as an
internal phase). For
example, in certain embodiments it may desirable that the treatment fluid is
foamed to, among
other things, reduce the amount of treatment fluid that is required, e.g. in
water sensitive
subterranean formations, to reduce fluid loss to the subterranean formation,
enhance flow back
of fluids, or to provide enhanced particulate suspension. In addition, in
certain embodiments
where the treatment fluids suitable for use in the present invention are used
for fluid diversion, it
may be desirable that the treatment be foamed.
[0217] Formation of a foam involves the generation of a large amount of
surface area
for the liquid phase to gaseous phase interface. Thus, the lower the surface
tension of the liquid
phase of the interface, the less energy is required to generate a given amount
of foam. However,
foam bubbles in pure low-viscosity fluids, such as an oil, are not stable and
break almost
instantaneously. To improve stability, there must be something present to
stabilize the foam.
Although water has a high surface tension (compared to an oil, such as an
oleaginous liquid),
and therefore might not be expected to form foam bubbles easily, bubbles in
water are more
easily stabilized since a wider variety of components in water can rapidly
migrate to the surface
of a bubble to stabilize it. For example, a surfactant not only reduces the
surface tension of
water, facilitating foam formation but also migrates to the surface of the
droplets to give an
oriented surface layer with a high viscosity, stabilizing the foam bubbles. To
improve the
stability of a water-based foam, surfactants are conventionally used to lower
the surface tension
of the gas-liquid interface and thus increase the lifetime of gas bubbles.
102181 According to an embodiment of the invention, a nanohybrid can be used
in a
foam. The liquid phase can be an oil-based liquid or a water-based liquid. For
example, the
liquid phase can be an emulsion as described herein. The gaseous phase can be
any convenient
and acceptable gaseous material.
[0219] According to an embodiment, a method of using a foam in a well is
provided,
wherein the method comprises the steps of: (a) forming a foam comprising: (i)
a nanohybrid;
(ii) a liquid phase; and (iii) a gaseous phase; and (b) introducing a well
fluid comprising the
foam into the well.
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[0220] The nanohybrid can be selected to stabilize the liquid-gaseous
interface of the
foam. Adjusting the properties of the nanohybrid material can produce a
desired surface activity
(surface tension) of a liquid phase. This is believed to be especially useful
in producing an oil-
based foam, which has never been commercially accomplished. In addition, for
water foams,
high temperature applications and breaking have both been problems, and a
nanohybrid is
believed to be able to solve these problems.
[0221] The method can additionally include the step of, after the step of
introducing,
modifying the nanohybrid to break the foam in the well.
[0222] Preferably, the liquid phase is an oil-based liquid. For example, the
liquid
phase can be oil or a water-in-oil emulsion. The nanohybrid can be selected to
stabilize the
water-in-oil emulsion of the foam.
[0223] The liquid phase can be a water-based liquid. For example, the liquid
phase
can be water, an aqueous solution, or an oil-in-water emulsion. The nanohybrid
can be selected
to stabilize the oil-in-water emulsion of the foam. If desired, the water-
based liquid can include
a viscosity-increasing agent. Using nanohybrids to foam pure oils would be a
major
advancement.
[0224] While various gases can be utilized for foaming the treatment fluids of
this
invention, nitrogen, carbon dioxide, and mixtures thereof are preferred.
Preferably, the gaseous
phase is at least 5% by volume of the well fluid. In examples of such
embodiments, the gas may
be present in a treatment fluid suitable for in an amount in the range of from
about 5% to about
98% by volume of the treatment fluid, and more preferably in the range of from
about 20% to
about 80%. The amount of gas to incorporate into the fluid may be affected by
factors including
the viscosity of the fluid and wellhead pressures involved in a particular
application.
[0225] The foam can optionally include a particulate, such as a proppant, or
other
components.
[0226] A well fluid according to this embodiment can be introduced into the
well at a
rate and pressure and directed to a subterranean formation at a rate and
pressure that is at least
sufficient to create at least one fracture in the subterranean formation of
the well.
[0227] The well fluid can be, for example, a drilling fluid, a cementing
composition, a
fluid-loss control pill, an acidizing fluid, a viscous-sweep fluid, a
fracturing fluid, a frac-packing
fluid, a gravel-packing fluid, a spacer fluid, or a fluid for swelling a
swellable packer.
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Conclusion
[0014] Therefore, the present invention is well adapted to attain the ends and
advantages mentioned as well as those that are inherent therein.
[0015] The particular embodiments disclosed above are illustrative only, as
the present
invention may be modified and practiced in different but equivalent manners
apparent to those
skilled in the art having the benefit of the teachings herein. It is,
therefore, evident that the
particular illustrative embodiments disclosed above may be altered or modified
and all such
variations are considered within the scope of the present invention, as
defined by the claims.
[0016] The various elements or steps according to the disclosed elements or
steps can
be combined advantageously or practiced together in various combinations or
sub-combinations
of elements or sequences of steps to increase the efficiency and benefits that
can be obtained
from the invention.
[0017] The invention illustratively disclosed herein suitably may be practiced
in the
absence of any element or step that is not specifically disclosed or claimed.
[0018] Also, the terms in the claims have their plain, ordinary meaning unless
otherwise
explicitly and clearly defined by the patentee. Moreover, the indefinite
articles "a" or "an," as
used in the claims, are defined herein to mean one or more than one of the
element that it
introduces.
[0019] No limitations are intended to the details other than as described in
the claims
below.
