Note: Descriptions are shown in the official language in which they were submitted.
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METHODS OF USING POLYMER-COATED PARTICULATES
BACKGROUND OF THE INVENTION
The present invention relates to methods of using polymer-coated particulates
in
subterranean operations such as gravel packing, frac-packing, and hydraulic
fracturing.
Hydrocarbon-producing wells are often stimulated by hydraulic fracturing
treatments.
In hydraulic fracturing treatments, a viscous fracturing fluid is pumped into
a producing zone
at a rate and pressure such that the subterranean formation breaks down and
one or more
fractures are formed or extended in the zone. Particulate solids, such as
graded sand, which
are often referred to as "proppant" may be suspended in a portion of the
fracturing fluid and
then deposited in the fractures when the fracturing fluid is converted to a
thin fluid to be
returned to the surface. These particulates serve, among other things, to
prevent the fractures
from fully closing so that conductive channels are formed through which
produced
hydrocarbons may flow.
Hydrocarbon-producing wells may also undergo gravel packing treatments to,
inter
alia, reduce the migration of unconsolidated formation particulates into the
well bore. In
gravel packing operations, particulates, often referred to in the art as
gravel, are suspended in
a treatment fluid, which may be viscosified, and the treatment fluid is pumped
into a well
bore in which the gravel pack is to be placed. As the particulates are placed
in or near the
zone, the treatment fluid either is returned to the surface or leaks off into
the subterranean
zone. The resultant gravel pack acts as a filter to prevent the production of
the formation
solids with the produced fluids. Traditional gravel pack operations involve
placing a gravel
pack screen in the well bore and then packing the surrounding annulus between
the screen
and the well bore with gravel. The gravel pack screen is generally a filter
assembly used to
support and retain the gravel placed during the gravel pack operation. A wide
range of sizes
and screen configurations is available to suit the characteristics of a well
bore, the production
fluid, and any particulates in the subterranean formation.
In some situations, hydraulic fracturing and gravel packing operations may be
combined into a single treatment. Such treatments are often referred to as
"frac pack"
operations. In some cases, the treatments are generally completed with a
gravel pack screen
assembly in place with the hydraulic fracturing treatment being pumped through
the annular
space between the casing and screen. In this situation, the hydraulic
fracturing treatment ends
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in a screen-out condition, creating an annular gravel pack between the screen
and casing. In
other cases, the fracturing treatment may be performed prior to installing the
screen and
placing a gravel pack.
Particulates (such as proppant or gravel) used in subterranean operations are
often
coated with a resinous or polymeric material to facilitate consolidation of
the particulates. In
some cases, the coating may also be used to strengthen low-quality
particulates. Creating
such coated particulates generally involves using solvent methods that may
pose health or
environments risks. Moreover, many particulate coating technologies, such as
epoxy resin
solvent systems, are relatively expensive. Thus, between the potential
environmental and
health hazards posed by many of the particulate coating technologies and the
exorbitant costs
of some, known coating techniques are less than ideal for widespread use in
subterranean
operations.
SUMMARY OF THE INVENTION
The present invention relates to methods of using polymer-coated particulates
in
subterranean operations such as gravel packing, frac-packing, and hydraulic
fracturing.
One embodiment of the present invention provides methods for depositing a
polymer
on particulates suitable for use in a subterranean operation comprising
providing particulates
and a polymer solution comprising a polymer and a polar, aprotic solvent; at
least partially
coating the particulates with the polymer solution to create coated
particulates; and, exposing
the coated particulates to an aqueous medium such that the solvent
substantially dissociates
from the polymer solution and such that the polymer substantially remains on
the particulates.
Another embodiment of the present invention provides methods of treating a
subterranean formation comprising providing a treatment fluid comprising
particulates at
least partially coated with a polymer, wherein the polymer is deposited on the
particulates by
at least partially coating the particulates with a polymer solution comprising
the polymer and
a solvent and then exposing the particulates to an aqueous medium such that
the solvent
substantially dissociates from the polymer solution and such that the polymer
substantially
remains on the particulates; introducing the treatment fluid into a portion of
a subterranean
formation; and, depositing at least a portion of the particulates in the
portion of the
subterranean formation.
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Yet another embodiment of the present invention provides methods of creating a
propped fracture in a portion of a subterranean formation comprising
hydraulically fracturing
a portion of a subterranean formation to create or enhance at lease one
fracture therein;
providing a fracturing fluid comprising particulates at least partially coated
with a polymer,
wherein the polymer is deposited on the particulates by at least partially
coating the
particulates with a polymer solution comprising the polymer and a solvent and
then exposing
the particulates to an aqueous medium such that the solvent substantially
dissociates from the
polymer solution and such that the polymer substantially remains on the
particulates; placing
the fracturing fluid into the at least one fracture; and, depositing at least
a portion of the
particulates in the at least one fracture.
The features and advantages of the present invention will be readily apparent
to those
skilled in the art upon a reading of the description of the preferred
embodiments that follows.
DESCRIPTION OF PREFERRED EIVIBODIMENTS
The present invention relates to methods of using polymer-coated particulates
in
subterranean operations such as gravel packing, frac-packing, and hydraulic
fracturing.
In accordance with the teachings of the present invention, particulates at
least partially
coated with a polymer may be used to facilitate the consolidation of the
particulates into a
permeable mass having compressive and tensile strength. Generally, the polymer
is
deposited onto the particulates by at least partially coating the particulates
with a polymer
solution comprising a polymer and a solvent, and then exposing the
particulates to an
aqueous medium such that the solvent substantially dissociates from the
polymer solution,
leaving behind the polymer on the particulates. Suitable polymers are
substantially soluble or
miscible in the chosen solvent and are not substantially soluble or miscible
in water. Suitable
solvents are substantially soluble or miscible in water. In some embodiments
of the present
invention, particulates may be coated with the polymer in an amount of from
about 0.1% to
about 25% by weight of the particulates. In other embodiments of the present
invention,
particulates may be coated with the polymer in an amount of from about 1% to
about 5% by
weight of the particulates. In particular embodiments, the present invention
provides a low-
cost and environmentally-sound method of coating particulates with a polymer
that may
improve the quality of low-quality particulates and/or may improve the
resiliency and crush
resistance of a resulting particulate pack
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Particulates suitable for use in the present invention may be comprised of any
material
suitable for use in subterranean operations. Suitable particulate materials
include, but are not
limited to, sand; bauxite; ceramic materials; glass materials; polymer
materials; Teflon
materials; nut shell pieces; seed shell pieces; cured resinous particulates
comprising nut shell
pieces; cured resinous particulates comprising seed shell pieces; fruit pit
pieces; cured
resinous particulates comprising fruit pit pieces; wood; composite
particulates and
combinations thereof. Composite particulates may also be suitable, suitable
composite
materials may comprise a binder and a filler material wherein suitable filler
materials include
silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide,
meta-silicate,
calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass
microspheres, solid glass,
and combinations thereof. Typically, the coated particulates have a size in
the range of from
about 2 to about 400 mesh, U.S. Sieve Series. In particular embodiments,
preferred coated
particles size distribution ranges are one or more of 6/12 mesh, 8/16, 12/20,
16/30, 20/40,
30/50, 40/60, 40/70, or 50/70 mesh. It should be understood that the tenn
"particulate," as
used in this disclosure, includes all known shapes of materials including
substantially
spherical materials, fibrous materials, polygonal materials (such as cubic
materials) and
mixtures thereof. Moreover, fibrous materials that may or may not be used to
bear the
pressure of a closed fracture, are often included in proppant and gravel
treatments. It should
be understood that the term "proppant," as used in this disclosure, includes
all known shapes
of materials including substantially spherical materials, fibrous materials,
polygonal materials
(such as cubic materials) and mixtures thereof.
Some embodiments of the present invention are particularly well-suited for use
with
low-quality particulates. By their nature, low-quality particulates are often
plagued by fines
and/or breakage, making their use with a consolidating or strengthening
polymeric coating
advantageous. As used herein, the term "low-quality particulates" refers to
particulates that
do not meet at least one of the standards for sphericity, roundness, size,
turbidity, acid
solubility, percentage of fines, or crush resistance as recited in American
Petroleum Institute
Recommended Practices (API RP) standard numbers 56 and 58 for proppant and
gravel
respectively.
The API RP's describe the minimum standard for sphericity as at least 0.6 and
for
roundness as at least 0.6. As used herein, the terms "sphericity" and
"roundness" are defined
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as described in the API RP's and can be determined using the procedures set
forth in the API
RP's.
API RP 56 also sets forth some commonly recognized proppant sizes as 6/12,
8/16,
12/20, 20/40, 30/50, 40/70, and 70/140. Similarly, API RP 58 also sets forth
some commonly
recognized gravel sizes as 8/16, 12/20, 16/30, 20/40, 30/50, and 40/60. The
API RP's further
note that a minimum percentage of particulates that should fall between
designated sand sizes
and that not more than 0.1 weight % of the particulates should be larger than
the larger sand
size and not more than a maximum percentage (1 weight % in API RP 56 and 2
weight % in
API RP 58) should be smaller than the small sand size. Thus, for 20/40
proppant, no more
than 0.1 weight % should be larger than 20 U.S. Mesh and no more than 1 weight
% smaller
than 40 U.S. Mesh.
API RP's 56 and 58 describe the minimum standard for proppant and gravel
turbidity
as 250 FTU or less. API RP 56 describes the minimum standard for acid
solubility of
proppant as no more than 2 weight % loss when tested according to API RP 56
procedures
for proppant sized between 6/12 Mesh and 30/50 Mesh, U.S. Sieve Series and as
no more
than 3 weight % loss when tested according to API RP 56 procedures for
proppant sized
between 40/70 Mesh and 70/140 Mesh, U.S. Sieve Series. API RP 58 describes the
minimum standard for acid solubility of gravel as no more than 1 weight % loss
when tested
according to API RP 58 procedures. API RP 56 describes the minimum standard
for crush
resistance of proppant as producing not more than the suggested maximum fines
as set forth
in Table 1, below, for the size being tested:
Table 1: Suggested Maximum Fines for Proppant Subjected to Crushing Strength
Mesh Size Crushing Force Stress on Proppant Maximum Fines
U.S. Sieve Series) lbs (psi) (% by wei ht
6/12 6,283 2,000 20
8/16 6,283 2,000 18
12/20 9,425 3,000 16
16/30 9,425 3,000 14
20/40 12,566 4,000 14
30/50 12,566 4,000 10
40/70 15,708 5,000 8
70/140 15,708 5,000 6
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Similarly, API RP 58 describes the minimum standard for crush resistance of
gravel as
producing not more than the suggested maximum fines as set forth in Table 2,
below, for the
size being tested:
Table 2: Suggested Maximum Fines for Gravel Subjected to Crushing Strength
Mesh Size Crushing Force Stress on Gravel Maximum Fines
U.S. Sieve Series) lbs (psi) (% by wei ht
8/16 6,283 2,000 8
12/20 6,283 2,000 4
16/30 6,283 2,000 2
20/40 6,283 2,000 2
30/50 6,283 2,000 2
40/60 6,283 2,000 2
As mentioned above, the particulates of the present invention are at least
partially
coated with a polymer solution comprising a polymer and a solvent. Generally,
any polymer
that has a thermal and chemical resistance suitable for use in a down hole
environment and
that may aid particulates in forming a permeable mass having at least some
cohesive strength
may be used in accordance with the teachings of the present invention.
Suitable polymers are
not readily soluble in water and may be made into a solution in a suitable
solvent (such as
propylene carbonate) and then may be made to precipitate out of the solvent
when placed in
an aqueous fluid (such as a fracturing fluid). By way of example, a solution
can be made by
dissolving acrylic fibers (containing at least about 85% acrylonitrile units)
into N,N-
dimethylformamide ("DMF") to form a 20 weight percent solution of acrylic in
DM.F; when
exposed to water, acrylic polymer beads precipitate out of the D1VIF solution
and into the
water.
Some suitable polymers include, but are not limited to, acrylic polymers such
as
acrylonitrile polymers, acrylonitrile copolymers, and mixtures thereof. Some
preferred
polymers include homopolymers and copolymers of polyacrylonitrile (including
copolymers
of acrylonitrile and methyl acrylate, methyl methacrylate, vinyl chloride,
styrene and
butadiene), polyacylates, polymethacrylates, poly(vinyl alcohol) and its
derivates, and
mixtures thereof. As used herein the term "acrylic" polymers refers to any
synthetic
polymer composed of at least 85% by weight of acrylonitrile units (the Federal
Trade
Commission definition). Thus, the definition of the term may include
homopolymers of
polyacrylonitrile and copolymers containing polyacrylonitrile. Usually they
are copolymers
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of acrylonitrile and one or more of the following: methyl acrylate, methyl
methacrylate,
vinyl chloride, styrene, butadiene. However, polymers that do not meet the
definition of an
acrylic polymer (such as those having less than 85% acrylonitrile) may also be
suitable. For
instance, Example 3 uses poly(acrylonitrile-co-butadiene-co-styrene) that
contains
approximately 25 wt % acrylonitrile. Furthermore, anyone skilled in the art
can select a wide
variety of suitable polymers (including non-acrylic polymers) and solvents
from numerous
sources. For example, using published references such as the Polymer Handbook
(J.
Brandrup J. and E. H. Immergut, John Wiley & Sons, New York, 1989) one could
find a
polymer suitable for their application with example solvents. For example,
from the
reference previously cited it can be found that poly(methyl methacrylate) and
poly(vinyl
acetate) are soluble in acetone which is a water soluble/ miscible solvent.
The polymer may
be present in the polymer solution in an amount from about 5 to about 95% by
weight of the
polymer solution. Typically, the polymer is present in the polymer solution in
an amount of
from about 5% to about 95% by weight of the polymer solution. In some
embodiments the
polymer is present in the polymer solution in an amount of from about 25% to
about 75% by
weight of the polymer solution.
The solvent of the present invention generally comprise polar, aprotic
solvents. In
particular embodiments, the solvent is non-aromatic. Suitable such solvents
include, but are
not limited to, N,N-dimethylformamide ("DMF"); acetone; tetrahydrofuran
("THF"); 1,4-
dioxane; dimethylsulfoxide ("DMSO"); tetramethylenesulfone (sulfolane);
acetonitrile;
hexamethylphosphoramide ("HMPA"); 1,3-methyl-3,4,5,6-tetrahydro-2(1H)-
pyrimidinone
("DMPU"); propylene carbonate, ethylene carbonate and mixtures thereof. In
particular
embodiments of the present invention, propylene carbonate is used as the
solvent due to the
fact that it is inexpensive, is relatively environmentally sound, and has a
high boiling point.
After at least partially coating the particulates with the polymer solution,
the polymer-
coated particulates are exposed to an aqueous treatment fluid or some other
source of water.
Suitable aqueous media include fresh water, salt water, brine, or any other
aqueous liquid that
does not adversely react with the polymer or solvent of the present invention.
In particular
embodiments, the fracturing fluid the particulates are to be suspended in is
the aqueous
medium. Due to the highly water-soluble nature of the solvent, the solvent
substantially, and
oftentimes rapidly, dissociates from the polymer solution upon exposure to the
aqueous
medium Upon dissociation, the solvent enters the aqueous medium, leaving
behind the
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polymer on the surface of the particulates. So deposited, the polymer
typically is present on
the resulting polymer-coated particulates in an amount of from about 0.01% to
about 10% by
weight of the particulates, preferably from about 1% to about 3% by weight of
the
particulates.
In particular embodiments of the present invention, the particulates may be
coated
with the polymer solution and introduced into the treatment fluid, which acts
as the aqueous
medium, directly prior to being introduced into a subterranean formation in an
on-the-fly
treatment. As used herein, the term "on-the-fly" is used to mean that a
flowing stream is
continuously introduced into another flowing stream so that the streams are
combined and
mixed while continuing to flow as a single stream as part of an on-going
treatment. For
instance, the polymer-coated particulates may be mixed with an aqueous liquid
(such as a
treatment fluid) on-the-fly to form a treatment slurry. Such mixing can also
be described as
"real-time" mixing. As is well understood by those skilled in the art such
mixing may also be
accomplished by batch or partial batch mixing. One benefit of on-the-fly
mixing over batch
or partial batch mixing, however, involves reducing waste by having the
ability to rapidly
shut down the mixing of the components on-the-fly.
Generally, any treatment fluid suitable for a subterranean operation may be
used in
accordance with the teachings of the present invention, including aqueous
gels, viscoelastic
surfactant gels, foamed gels and emulsions. Suitable aqueous gels are
generally comprised of
water and one or more gelling agents. Suitable emulsions can be comprised of
two
immiscible liquids such as an aqueous liquid or gelled liquid and a
hydrocarbon. Foams can
be created by the addition of a gas, such as carbon dioxide or nitrogen. In
exemplary
embodiments of the present invention, the fracturing fluids are aqueous gels
comprised of
water, a gelling agent for gelling the water and increasing its viscosity,
and, optionally, a
crosslinking agent for crosslinking the gel and further increasing the
viscosity of the fluid.
The increased viscosity of the gelled, or gelled and cross-linked, treatment
fluid, inter alia,
reduces fluid loss and allows the fracturing fluid to transport significant
quantities of
suspended particulates. The water used to form the treatment fluid may be
fresh water, salt
water, brine, sea water, or any other aqueous liquid that does not adversely
react with the
other components. The density of the water can be increased to provide
additional particle
transport and suspension in the present invention.
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A variety of gelling agents may be used, including hydratable polymers that
contain
one or more functional groups such as hydroxyl, carboxyl, sulfate, sulfonate,
amino, or amide
groups. Suitable gelling typically comprise polymers, synthetic polymers, or a
combination
thereof. A variety of gelling agents can be used in conjunction with the
methods and
compositions of the present invention, including, but not limited to,
hydratable polymers that
contain one or more functional groups such as hydroxyl, cis-hydroxyl,
carboxylic acids,
derivatives of carboxylic acids, sulfate, sulfonate, phosphate, phosphonate,
amino, or amide.
In certain exemplary embodiments, the gelling agents may be polymers
comprising
polysaccharides, and derivatives thereof that contain one or more of these
monosaccharide
units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose,
glucuronic acid, or
pyranosyl sulfate. Examples of suitable polymers include, but are not limited
to, guar gum
and derivatives thereof, such as hydroxypropyl guar and
carboxymethylhydroxypropyl guar,
and cellulose derivatives, such as hydroxyethyl cellulose. Additionally,
synthetic polymers
and copolymers that contain the above-mentioned functional groups may be used.
Examples
of such synthetic polymers include, but are not limited to, polyacrylate,
polymethacrylate,
polyacrylamide, polyvinyl alcohol, and polyvinylpyrrolidone. In other
exemplary
embodiments, the gelling agent molecule may be depolymerized. The term
"depolymerized,"
as used herein, generally refers to a decrease in the molecular weight of the
gelling agent
molecule. Depolymerized gelling agent molecules are described in United States
Patent No.
6,488,091 issued December 3, 2002 to Weaver, et al., the relevant disclosure
of which is
incorporated herein by reference. Suitable gelling agents generally are
present in the
viscosified treatment fluids of the present invention in an amount in the
range of from about
0.1% to about 5% by weight of the water therein. In certain exemplary
embodiments, the
gelling agents are present in the viscosified treatment fluids of the present
invention in an
amount in the range of from about 0.01% to about 2% by weight of the water
therein.
Crosslinking agents may be used to crosslink gelling agent molecules to form
crosslinked gelling agents. Crosslinkers typically comprise at least one metal
ion that is
capable of crosslinking molecules. Examples of suitable crosslinkers include,
but are not
limited to, zirconium compounds (such as, for example, zirconium lactate,
zirconium lactate
triethanolamine, zirconium acetylacetonate, zirconium citrate, and zirconium
diisopropylamine lactate); titanium compounds (such as, for example, titanium
lactate,
titanium citrate, titanium ammonium lactate, titanium triethanolamine, and
titanium
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acetylacetonate); aluminum compounds (such as, for example, aluminum lactate
or aluminum
citrate); antimony compounds; chromium compounds; iron compounds; copper
compounds;
zinc compounds; or a combination thereof. An example of a suitable
commercially available
zirconium-based crosslinker is "CL-24" available from Halliburton Energy
Services, Inc.,
Duncan, Oklahoma. An example of a suitable commercially available titanium-
based
crosslinker is "CL-39" available from Halliburton Energy Services, Inc.,
Duncan Oklahoma.
Suitable crosslinkers generally are present in the viscosified treatment
fluids of the present
invention in an amount sufficient to provide, inter alia, the desired degree
of crosslinking
between gelling agent molecules. In certain exemplary embodiments of the
present
invention, the crosslinkers may be present in an amount in the range from
about 0.001% to
about 10% by weight of the water in the fracturing fluid. In certain exemplary
embodiments
of the present invention, the crosslinkers may be present in the viscosified
treatment fluids of
the present invention in an amount in the range from about 0.01% to about 1%
by weight of
the water therein. Individuals skilled in the art, with the benefit of this
disclosure, will
recognize the exact type and amount of crosslinker to use depending on factors
such as the
specific gelling agent, desired viscosity, and formation conditions.
The gelled or gelled and cross-linked treatment fluids may also include
internal
delayed gel breakers such as enzyme, oxidizing, acid buffer, or temperature-
activated gel
breakers. The gel breakers cause the viscous treatment fluids to revert to
thin fluids that can
be produced back to the surface after they have been used to place
particulates in
subterranean fractures. The gel breaker used is typically present in the
treatment fluid in an
amount in the range of from about 0.5% to about 10% by weight of the gelling
agent. The
treatment fluids may also include one or more of a variety of well-known
additives, such as
gel stabilizers, fluid loss control additives, clay stabilizers, bactericides,
and the like.
In some embodiments of the present invention, the particulates may be coated
with
the polymer solution and exposed to an aqueous medium well in advance of being
introduced
into a subterranean formation, creating polymer-coated particulates that may
be used at some
time in the future.
By coating with particulates with the polymer of the present invention, the
quality of
the particulates may be improved, particularly in embodiments employing low-
quality
particulates. In addition to improving low-quality particulates to make it
suitable for a
fracturing application, particular embodiments may improve the resiliency of a
particulate
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pack comprising the polymer-coated particulates of the present invention. In
particular
embodiments, the resulting particulates may have improved crush resistance,
may be less
susceptible to point loading, and/or may be better able to withstand stress
cycling. The
polymer coating of the present invention may also reduce fmes generation by
entraining fines
released by the particulates, preventing the fines negatively impacting the
production
potential of the well.
In particular embodiments of the present invention, the polymer-coated
particulates
may also be at least partially coated with a partitioning agent. By coating a
partitioning agent
onto particulates that has been coated with the polymer, the methods of the
present invention
are capable of temporarily diminishing the "tackiness" of the treated
particulates, thus
preventing or minimizing the agglomeration of the particulates and the
spreading of the
polymer onto equipment surfaces before introduction into a subterranean
formation. Because
of this, the use of a partitioning agent may be particularly useful where the
polymer-coated
particulates will not be directly introduced into a subterranean formation
(i.e., in non-"on-the-
fly" operations). Partitioning agents suitable for use in the present
invention are those
substances that will dissipate once the particulates are introduced to a
treatment fluid, such as
a fracturing or gravel packing fluid. Moreover, partitioning agents suitable
for use in the
present invention should not interfere with the polymer coated onto the
particulate when it is
used, and should not interfere with the treatment fluid. In particular
embodiments, the
partitioning agent is coated onto the polymer-coated particulates in an amount
of from about
1% to about 20% by weight of the polymer-coated particulates. In particular
embodiments,
substantially the entire surface of the polymer coating is coated with
partitioning agent.
Partitioning agents suitable for use in the present invention are those
materials that are
capable of coating onto the polymer coating of the particulates and reducing
the tacky
character of the polymer coating. Suitable partitioning agents may be
substances that will
quickly dissipate in the presence of the aqueous liquid. Examples of suitable
partitioning
agents that will dissolve quickly in an aqueous liquid include salts (such as
rock salt, fine salt,
KCI, and other solid salts known in the art), barium sulfate, benzoic acid,
polyvinyl alcohol,
sodium carbonate, sodium bicarbonate, and mixtures thereof. The partitioning
agent also
may be a substance that dissipates more slowly in the presence of the aqueous
liquid.
Partitioning agents that dissolve more slowly allow more time to place the
coated
particulates. Examples of suitable partitioning agents that will dissolve more
slowly in an
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aqueous liquid include calcium oxide, degradable polymers, such as
polysaccharides; chitins;
chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides);
poly(E-
caprolactones); poly(hydroxybutyrates); poly(anhydrides); aliphatic
polycarbonates;
poly(orthoesters); poly(amino acids); poly(ethylene oxides); and
poly(phosphazenes); and
mixtures thereof.
To facilitate a better understanding of the present invention, the following
examples
of preferred embodiments are given. In no way should the following examples be
read to
limit or define the scope of the invention.
EXAMPLES
Example 1
Acrylic fibers (containing at least about 85% acrylonitrile units were
dissolved into
N,N-dimethylformamide ("DMF") to form a 20 weight percent solution of acrylic
in DMF.
The solution was then dropped into water and acrylic polymer beads
precipitated out of the
DMF and into the water.
Example 2
Acrylic fibers (containing at least about 85% acrylonitrile units were
dissolved into
propylene carbonate to form a 20 weight percent solution of acrylic in
propylene carbonate.
Ten grams of the solution of acrylic in propylene carbonate were then coated
into 100 grams
of 20/40 Brady sand. The coated sand was then placed into water and propylene
carbonate
came out of the solution and the acrylic polymer was observed to deposit onto
the surface of
the sand particulate leaving an about 2% by weight coating on the polymer.
Example 3
Ten grams of poly(acrylonitrile-co-butadiene-co-styrene) (comprising about 25
weight % acrylonitrile) was dissolved in 90 grams of propylene carbonate at
about 110-120
F. Three milliliters of the resulting liquid polymer solution was then coated
onto about 100
grams of 20/40 Brady sand. The coated sand was then slurried into about 200 ml
of an
aqueous xanthan gel liquid and the poly(acrylonitrile-co-butadiene-co-styrene)
polymer came
out of the propylene carbonate and was deposited onto the sand when the
solvent went into
the aqueous xanthan gel liquid.'
Therefore, the present invention is well adapted to attain the ends and
advantages
mentioned as well as those that are inherent therein. While numerous changes
may be made
CA 02601122 2007-09-13
WO 2006/095136 PCT/GB2006/000715
13
by those skilled in the art, such changes are encompassed within the spirit of
this invention as
defined by the appended claims.
