Note: Descriptions are shown in the official language in which they were submitted.
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METHODS AND COMPOSITIONS FOR IMPROVING HYDROCARBON
RECOVERY BY WATER FLOOD INTERVENTION
FIELD OF THE INVENTION
[0001] The present invention provides methods of enhanced recovery of
hydrocarbons from subterranean formations. In particular, the present
invention provides methods for improving the recovery of hydrocarbons from
subterranean formations using relative permeability modifier macromolecules.
DESCRIPTION OF RELATED ART
[0002] Water production is always a harbinger of problems in a subterranean
well, with water cuts in oil producing wells increasing as time passes and oil
fields become more mature. The source of the water is often either formation
water or injected water used for the purpose of reservoir maintenance. In
other instances, heterogeneities encountered in reservoir rocks can cause
water channeling through higher permeability streaks/hairline fractures, or
near wellbore water coning at early periods in the well's productivity life
span,
often due to limited reservoir thickness or excessive pressure drawdowns.
[0003] Such water production can cause a variety of problems. It can cause
scaling problems in susceptible wells, induce fines migration or sandface
failure, increase corrosion of tubulars, and sometimes even kill wells by
hydrostatic loading, among other things. Clearly, while water production is an
inevitable consequence of oil production, it is often desirable to defer its
onset, or at least its rise, for as long as possible during hydrocarbon
production.
[0004] Numerous strategies, both mechanical and chemical, have been
employed over the years in attempts to achieve these goals, or at the least
use the water flow to aid in hydrocarbon production. These approaches have
ranged from simple shut-off techniques, such as cements, mechanical plugs,
and inorganic gel squeezes to isolate watered out zones, to more advanced
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concepts, such as the use of several types of gel systems with varying
degrees of success in the control of water and water production. Among
these, three main chemical gel types have emerged as showing promise in
subterranean water treatments: permeability blockers or gellants, which plug
pore spaces and prevent fluid movement, often by means of a controlled,
delayed chemical reaction, such as precipitation or swelling to form a three-
dimensional "gel"; Disproportionate Permeability Reducers (DPR) and/or
Selective Permeability Blockers (SPB), which also plug the pore spaces,
restricting fluid movement, but do not precipitate, swell, or viscosify
significantly in the presence of hydrocarbons, thereby reducing water relative
permeability; and Relative Permeability Modifiers (RPMs), which, generally
speaking, are water-soluble, hydrophilic polymer systems that, when
hydrated, produce long polymer chains that loosely occupy pore spaces in the
rock. Being strongly hydrophilic, RPMs attract water and repel oil and, as a
net result, exert a "drag force" on water flow in the pores with a minimal
effect
on oil flow.
[0005] Various methods have been proposed for increasing hydrocarbon
production from subterranean formations with water problems. For example,
U.S. Patent No. 4,485,871 suggests a method for recovering hydrocarbons in
which an alcohol is injected into the formation, followed by an aqueous
alkaline solution. However, this type of methodology is particular to
diatomaceous formations. In particular, hydrocarbon recovery using this
method is reportedly not optimum in formations that are deeply buried and/or
have not been extensively exposed to the atmosphere or oxygen bearing
formation water, resulting in an interfacial tension and oil/rock wettability
issues in these formations.
[0006] Davis, in U.S. Patent No. 4,828,031, offers a method for recovering oil
from subterranean formations, in which a solvent is injected into the
formation,
followed by an aqueous surface-active solution. The aqueous surface-active
solution is described to contain a diatomite/oil water wettability improving
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agent and an oil/water surface tension lowering agent. It is also suggested
that the method can be supplemented by the injection of water and/or steam
into the formation, at a pressure just below that where a long fracture may be
induced.
[0007] The use of numerous relative permeability modifiers for the control of
production water have been described in the art. For example, U.S. Patent
No. 6,228,812 describes a chemical composition treatment that selectively
reduces water production by the employment of relative permeability modifiers
(RPMs). According to the specification, the use of RPMs entails low risk to
oil
production, as the polymers reportedly reduce the water permeability
downhole without adversely affecting oil permeability. The use of RPMs for
water control is also reported to be low in cost and low in application cost
as
the use of such compositions does not require expensive equipment for their
application.
[0008] In U.S. Patent No. 6,228,812, compositions and methods for modifying
the permeability of subterranean formations is described, for the purpose of
selectively reducing the production of aqueous fluids. The compositions are
described to include relative permeability modifiers which include copolymers
with hydrophilic and anchoring monomeric copolymer units that can be added
to well treatment fluids to form water control treatment fluids.
[0009] However, while the use of polymeric compositions are exhibiting
increased utility and promise for downhole applications, many water control
compositions, and even some relative permeability modifiers, do not always
impart extended effectiveness, or exhibit utility in formations having
permeability's greater than 1 Darcy. Thus, there exists a need for methods to
increase hydrocarbon production from hydrocarbon-bearing formations using
compositions and methods that do not adversely affect oil production or
permeability through the formation.
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SUMMARY OF THE INVENTION
[0010] The present invention is directed generally to methods for increasing
hydrocarbon production from a hydrocarbon-bearing formation, using relative
permeability modifier macromolecules or microgels. In a first aspect, the
present invention provides a method for increasing hydrocarbon production
from a production well in a hydrocarbon-bearing formation wherein there is at
least one injector well associated with the production well, the method
comprising the step of introducing an aqueous composition comprising a
relative permeability modifier macromolecule into the at least one injector
well.
In accordance with this aspect, the relative permeability macromolecule can
be a microgel, be deformable, have a K-value from about 200 to about 1,000,
and/or be present in the aqueous composition in a concentration from about
15,000 ppm to about 50,000 ppm.
[0011] In a further aspect of the present invention, a method for increasing
hydrocarbon production from a production well in a hydrocarbon-bearing
formation having at least one injector well associated with the production
well
is provided, wherein the method comprises the steps of introducing an
aqueous composition comprising a relative permeability modifier (RPM)
macromolecule into an injector well in a permeable formation in an amount
effective to enhance oil production from the production well, and continuing
the injection of the RPM macromolecule into the at least one injector well for
a
time sufficient to increase oil flow from the formation to the production well
where it is subsequently produced to the surface. In accordance with this
aspect of the invention, the RPM macromolecule is capable of redirecting
water flow through the hydrocarbon-bearing formation to provide an improved
injection profile, and/or the method can further comprise the step of forming
a
treating solution comprising at least one RPM macromolecule prior to the
introducing step.
[0012] In yet another aspect of the present invention, a method for increasing
hydrocarbon formation from a production well in a hydrocarbon-bearing
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formation having at least one injector well associated with the production
well
is provided, the method comprising the steps of introducing an aqueous
composition of a water-soluble, crosslinked, RPM macromolecule comprised
of a terpolymer, copolymer, or homopolymer of a vinyl acetamide and a
sulfonated vinyl monomer into an injector well, and continuing the injection
for
a period of time sufficient to increase oil flow from the formation to the
production well, where the oil can be subsequently produced. In accordance
with this aspect of the invention, the RPM macromolecule can further be
classified as a microgel, have a weight average molecular weight from about
10,000 to about 50,000,000 g/mol, and/or a K-value from about 200 to about
1,000.
[0013] In a further aspect of the present invention, a method for increasing
hydrocarbon production from a production well in a subterranean formation is
provided, the method comprising introducing an aqueous treating solution
comprising a crosslinked relative permeability modifier (RPM) macromolecule
into the subterranean formation through an injector well that is associated
with
the production well. In accordance with this aspect of the invention, the
crosslinked RPM macromolecule comprises a terpolymer, copolymer, or
homopolymer comprising an anchoring monomer and a hydrophilic monomer,
and is capable of redirecting water flow through the hydrocarbon-bearing
formation to provide an improved injection profile.
[0014] In another aspect of the present invention, a method for increasing
hydrocarbon production from a production well in a hydrocarbon-bearing
formation, wherein there is at least one injector well associated with the
production well, the method comprising introducing an aqueous water-control
fluid composition comprising a crosslinked relative permeability modifier
(RPM) macromolecule and an aqueous base fluid into an injector well in a
permeable formation, and continuing the injection of the crosslinked RPM
macromolecule into the injector well for a time sufficient to increase oil
flow
from the formation to the production well where it is subsequently produced to
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the surface via the producer well. In accordance with this aspect of the
present invention, the crosslinked RPM macromolecule is a terpolymer,
copolymer or homopolymer comprising a hydrophilic monomeric unit and a
vinyl amide unit, is capable of redirecting water flow through the hydrocarbon-
bearing formation to provide an improved injection profile, and
is introduced into the hydrocarbon-bearing formation prior to, in conjunction
with, or after a stimulation operation.
[0015] In yet another aspect of the present invention, a method for enhancing
hydrocarbon recovery from a reservoir or formation containing substantially
immobile hydrocarbons is provided, wherein the method comprises drilling
and completing at least one injector well in a subterranean formation in
proximity to a producer well, or converting a producer well into an injector
well
in proximity to other producer wells; directing an aqueous mixture comprising
a crosslinked relative permeability modifier (RPM) macromolecule into the
injector well, wherein the RPM macromolecule is present in an amount
effective to redirect water flow in the subterranean formation and thereby
increase hydrocarbon flow therefrom; and continuing the injection of the
aqueous treating composition into the injector well for a time sufficient to
increase flow of hydrocarbons from the formation towards the producer well,
where it is subsequently produced to the surface via the producer well.
DESCRIPTION OF THE FIGURES
[0016] The following figures form part of the present specification and are
included to further demonstrate certain aspects of the present invention. The
invention may be better understood by reference to one or more of these
figures in combination with the detailed description of specific embodiments
presented herein.
Figure 1 is a schematic representation of one aspect of the present invention,
illustrating RPM microgel flow from injector wells towards producer wells.
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Figure 2 is a graphic representation of the parallel core flood test of
compositions in accordance with the present invention.
DETAILED DESCRIPTION OF THE INVENTION
[0017] The present invention is directed to well treatment methods useful in
redirecting water in a subterranean formation so as to improve the injection
profile of the well and increase hydrocarbon production from the well.
Illustrative embodiments of the invention, as well as illustrative methods of
operation of the unit, are described below in detail.
COMPOSITION
[0018] The compositions of the present invention are aqueous treatment
compositions containing one or more relative permeability modifier (RPM)
macromolecules. As used herein an RPM macromolecule refers to a
deformable, polymeric composition that comprises at least one hydrophilic
monomer which aids in the RPM adhering to the formation and adds to the
water/brine solubility; and at least one anchoring monomeric unit to cause the
RPM to adhere to the formation. Further general characteristics of the
relative
permeability modifier macromolecules as used herein include those RPM
macromolecules having K-values from about 200 to about 1,000 (which can
be controlled by the concentration of the starting monomers and/or the
amount of crosslinking), and those RPM macromolecules that are crosslinked,
or both. Such RPM macromolecules also include soft "microgels", which as
used herein refers to those RPM macromolecules which are crosslinked
during their manufacture and have a weight average molecular weight of from
about 104 to 10& g/mol. These RPM microgels typically have a diameter from
about 0.001 micron to about 500 micron, and more typically from about 0.001
micron to about 100 micron.
[0019] The relative permeability modifiers suitable for use in the methods of
the present invention are any polymers which can either impede the
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production of water and/or redirect water through permeable formation
materials. Suitable RPMs include copolymers, homopolymers, or terpolymers
comprised of hydrophilic monomers, at least one anchoring monomeric unit,
an optional secondary anchoring unit, and one or more filler/spacer monomer
units. Optionally, the RPMs can provide grafting sites for the inclusion of
organosilicon compounds. Suitable relative permeability modifiers include
those described in U.S. Patent Nos. 5,735,349; 6,169,058; 6,465,397; and
6,228,812. Optionally, and in accordance with the present invention, the RPM
can include one or more organosilicon compounds. Preferred RPM
macromolecules suitable for use within the present invention are AquaConTM
AQUATROLT"" I , and Aquatrol V (available from BJ Services Company,
Houston, TX).
[0020] The RPM macromolecules suitable for use in the present invention
have weight average molecular weights ranging from about 10,000 g/mol to
about 50,000,000 g/mol, preferably from about 50,000 g/mol to about
5,000,000 g/mol, and more preferably from about 100,000 g/mol to about
2,000,000 g/mol. The RPM macromolecules for use herein also have a
viscosity from about 1 cP (0.001 Pa-s) to about 10 cP (0.010 Pa-s), and more
preferably from about 1 cP (0.001 Pa-s) to about 5 cP (0.005 Pa-s), as
measured by standard techniques.
[0021] The RPM macromolecule compositions of the present invention are
copolymers, homopolymers, or terpolymers comprising a hydrophilic
monomeric unit; at least one first anchoring monomeric unit; and may also
include at least one optionally selected second anchoring monomeric unit. A
filler monomeric unit may also be employed. These copolymer compositions
may be advantageously used in aqueous-based water control treatment fluids
to selectively control water production from hydrocarbon production wells. As
used herein, the term "monomer" refers to molecules or compounds capable
of conversion to polymers by combining with other like molecules or similar
molecules or compounds. A "monomeric unit" refers to a repeating molecular
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group or unit having a structure corresponding to a particular monomer. In
this regard, the source of a given monomeric unit may or may not be the
corresponding monomer itself.
[0022] As used herein, the term "monomeric anchoring unit" refers to
components of a polymer that will preferentially bind, by either physical or
chemical processes, to subterranean formation material and which therefore
tend to retain the polymer to the formation material. Anchoring groups are
typically selected to prevent a polymer from washing out of the formation due
to fluid flow. Primary anchoring sites for the monomeric anchoring units are
typically clay and feldspar surfaces existing in formation pores, channels and
pore throats. With benefit of this disclosure, those of skill in the art will
understand that particularly useful anchoring monomeric units are those
having functional groups capable of hydrolyzing to form amine-based
anchoring groups on the polymer. Examples include amide-containing
monomeric units.
[0023] Advantageously, the disclosed co-polymers having the first anchoring
monomeric units described herein may be utilized in well treatment methods
to selectively reduce the permeability of a subterranean formation to water by
a factor of about 10 or more, while at the same time leaving the permeability
of the formation to oil virtually unchanged. Furthermore, the disclosed
compositions, when introduced into a formation, tend to exhibit a high
resistance to removal from water bearing areas of the formation over time.
[0024] Hydrophilic monomers may include both ionic and nonionic monomers.
The term "nonionic monomer" refers to monomers that do not ionize in
aqueous solution at neutral pH. Examples of suitable nonionic hydrophilic
monomers include, but are not limited to, vinyl acylamide comonomers
including, but not limited to, acrylamide, N-vinyl acetamide, N-vinyl-N-methyl
acetamide, N,N-dimethyl acetamide, N-vinyl-2-pyrrolidone, N-vinyl formamide
(VF), and N-ethenyl-N-alkyl acetamide, as well as mixtures of two or more of
such comonomers. Ionic monomers may be either anionic or cationic.
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Examples of anionic monomers include, but are not limited to, alkaline salts
of
acrylic acid, ammonium or alkali salts of acrylamidomethylpropane sulfonic
acid ("AMPS"), maleic acid, itaconic acid, styrene sulfonic acid, and vinyl
sulfonic acid (or its ammonium or alkali metal salts). Examples of suitable
cationic monomers include, but are not limited to, dimethyldiallyl ammonium
chloride and quaternary ammonium salt derivatives from acrylamide or acrylic
acid such as acrylamidoethyltrimethyl ammonium chloride.
[0025] In one embodiment, one or more hydrophilic monomeric units are
typically employed and are based on AMPS (such as at least one of
ammonium or alkali metal salt of AMPS, including sodium and/or potassium
salts of AMPS), acrylic acid, an acrylic salt (such as sodium acrylate, N-
vinyl
pyrrolidone, ammonium or alkali metal salts of styrene sulfonic acid, etc.),
or a
mixture thereof. It may be desirable to employ ammonium or alkali metal salts
of AMPS for added stability, with or without one or more other hydrophilic
monomers, in those cases where aqueous treatment and/or formation fluids
contain high concentrations of divalent ions, such as Ca+2, Mg+2, and the
like.
[0026] Optional second anchoring monomeric units may include any
monomeric unit that will adsorb onto formation material. In one embodiment,
examples of optional second anchoring monomeric units include at least one
of dimethyldiallylammonium chloride, ammonium or alkali metal salts of acrylic
acid, (such as sodium salts), or a mixture thereof.
[0027] Optional filler monomeric units may include any monomeric unit
suitable for copolymerization with the other monomers in the composition.
Desirable characteristics of filler monomer units are the ability to retain
water
solubility and/or relative low cost compared to other monomer units present in
a copolymer. Filler monomer units may be based on, for example, monomers
such as acrylamide, methylacrylamide, etc. In one embodiment, optional filler
monomeric units include monomers such as acrylamide, methylacrylamide,
and the like.
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[0028] With benefit of the present disclosure, the disclosed compositions may
be prepared using any method suitable for preparing co-polymers known to
those of skill in the art. In one embodiment, monomers corresponding to the
desired monomeric units in the copolymer are selected and polymerized in an
aqueous monomer solution.
[0029] In one exemplary embodiment, a first N-vinylformamide monomer is
combined with a hydrophilic monomer (such as ammonium or alkali metal
salt/s of AMPS) and a filler monomer (such as acrylamides), in an aqueous
base fluid, typically water. Other additives may include disodium
ethylenediamine tetraacetate (Na2EDTA), pH adjusting chemicals (such as
potassium or sodium hydroxide), and a catalyst to initiate polymerization.
Monomers with other anchoring groups may also be present.
[0030] Any relative proportion of the disclosed monomers that is suitable for
polymerization and use in a water control treatment fluid may be combined in
an aqueous solution for polymerization. However, in one embodiment, a first
anchoring monomer is combined to be present in an amount of from about 2%
to about 50% by weight of the total polymer composition, alternatively from
about 5% to about 25% by weight of the total polymer composition. In another
embodiment a first anchoring monomer is combined to be present in an
amount from about 2% to about 50%, alternatively from about 5% to about
25%, by weight of the total polymer composition; ammonium or alkali metal
salts of AMPS is combined so that AMPS-based monomer is present in an
amount from about 0% to about 50%, alternatively from about 20% to about
30%, by weight of the total polymer composition; and acrylamide is combined
to be present in an amount from about 20% to about 98%, alternatively from
about 40% to about 65% by weight of the total polymer composition. In one
embodiment, N-vinylformamide is utilized as the first anchoring monomer.
[0031] Where necessary or desirable, the pH of a monomer solution may be
adjusted or neutralized prior to polymerization by, for example, addition of a
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base such as sodium hydroxide or potassium hydroxide. For example, the pH
of an aqueous solution containing ammonium or alkali metal salts of AMPS
may be adjusted to, for example, about 10 prior to the addition of N-
vinylformamide and/or a second anchoring monomer or a filler monomer such
as acrylamide. In one embodiment, a copolymer may be prepared by mixing
the appropriate monomers into a tank of fresh water, followed by addition of a
Na2EDTA, pH adjuster and catalyst system to initiate polymerization. In one
embodiment, ultimate pH range may be from about 6.5 to about 10.0 and
alternatively from about 7.5 to about 9.5.
[0032] Additionally, the rate permeability modifier macromolecules of the
present invention can optionally include organosilicon compounds, in order to
afford modified viscosities and allow for further binding to substrate
materials
including quartz, clay, chert, shale, silt, zeolite, or combinations thereof.
[0033] Suitable organosilicon compounds suitable for use in the aqueous
RPM macromolecule compositions described herein are those capable of
forming water-soluble silanols by hydrolysis, include amino silanes, vinyl
silanes, organosilane halides, and organosilane alkoxides, as well as
combinations thereof. Suitable water-soluble amino silanes include, without
limitation, 3-aminopropyltriethoxy silane and N-2-aminoethyl-3-
aminopropyltrimethoxy silane. Vinyl silanes suitable for use in accordance
with the present invention include but are not limited to vinyl tris-(2-
methoxyethoxy) silane, aminopropyl triethoxy silane, aminoethyl triethoxy
silane, aminopropyl trimethoxy silane, aminoethyl trimethoxy silane, ethylene
trimethoxy silane, ethylene triethoxy silane, ethyne trimethoxy silane, ethyne
triethoxy silane, 3,3,3-trifluoropropyl(2-
trimethylsilylpiperidinyl)dimethoxysilane; 3,3,3-trifluoropropyl(2-
trimethylsilyl-
pyrrolidinyl)dimethoxysilane; 3,3,3-trifluoropropyl(2-(3-
methylphenyl)piperidinyl)-dimethoxysilane; 3,3,3-trifluoropropyl(2-(3-
methylphenyl)pyrrolidinyl)dimethoxysilane; 3,3,3-trifluoropropyl(1,2,3,4-
tetrahydroquinolinyl)dimethoxysilane; 3,3,3-trifluoropropyl-(1,2,3,4-
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tetrahydroisoquinolinyl)dimethoxysilane; 3,3,3-trifluoropropyl-
(decahydroquinolinyl)dimethoxysilane; 3,3,3-trifluoropropyl(bis(2-
ethylhexyl)amino)-dimethoxysilane; and 3,3,3-trifluoropropyl(cis-2,6-
dimethylpiperidinyl)dimethoxy-silaneand combinations thereof.
[0034] Organosilane halides suitable for use in accordance with the present
invention include those silanes of formula (I):
Ri
I
R2 ii-X
R3 (I)wherein X is halogen, R, is an organic radical, and R2 and R3 are
independently hydrogen, or are the same or different halogens, or are the
same or different organic radicals. Preferably, R, is a Cl-C5a radical
selected
from the group of CI-C50 alkyl, Cl-C50 alkoxy, Cl-C5o alkoxyalkyl, C2-C50
alkenyl, C2-C50 alkynyl, an aralkyl group, or an aryl group having from 1 to
18
carbon atoms. Similarly, in accordance with the present invention, it is
preferred that X in Formula (I) is a halogen selected from the group
consisting
of bromine, chlorine, fluorine, and iodine, with chlorine and bromine being
preferred. R2 and R3, as indicated previously, can be hydrogen, the same or
different halogens, or a C,-C50 radical selected from the group of Cl-C50
alkyl,
Cl-C50 alkoxy, Cl-C5o alkoxyalkyl, C2-C50 alkenyl, CZ-C50 alkynyl, an aralkyl
group, or an aryl group having from 1 to 18 carbon atoms.
[0035] Suitable organosilane halides of formula (I) suitable for use with the
present invention include but are not limited to methyldiethylchlorosilane,
dimethyldichlorosilane, methyltrichlorosilane, dimethyidibromosilane, diethyl-
diiodosilane, dipropyidichlorosilane, dipropyldibromosilane,
butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane,
tolyltribromosilane, methylphenyl-dichlorosilane, propyid imethoxych lorosi
lane
and the like.
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[0036] Organosilane alkoxides suitable for use in accordance with the present
invention include those silanes of formula (II):
I
R5 ii-OR~
R6 (II),
wherein R4, R5, and R6 are independently selected from hydrogen and organic
radicals having from 1 to 50 carbon atoms, with the proviso that not all of
R4,
R5 and Rs are hydrogen, and R7 is an organic radical having from 1 to 50
carbon atoms and is not hydrogen. Preferably, R4, R5, R6 and R7 are
independently hydrogen, Cl-C50 radicals selected from the group of CI-C5o
alkyl, C1-C50 alkoxy, Cl-C50 alkoxyalkyl, C2-C50 alkenyl, C2-C5o alkynyl, an
aralkyl group, or an aryl group having from 1 to 18 carbon atoms.
[0037] Suitable organosilane alkoxides of Formula (II) suitable for use within
the present invention include but are not limited to methyltriethoxysilane,
dimethyidiethoxysilane, methyltrimethoxysilane, divinyldimethoxysilane,
divinyldi-2-methoxyethoxy silane, di(3-glycidoxypropyl) dimethoxysilane,
vinyltriethoxysilane, vinyltris-2-methoxy-ethoxysilane, 3-
glycidoxypropyltrimethoxysilane, 3-methacryloxypropyltrimethoxy-silane, 2-
(3,4-epoxycyclohexyl) ethyltrimethoxysilane, N-2-aminoethyl-3-
propylmethyidimethoxysilane, N-2-aminoethyl-3-propyltrimethoxysilane, N-2-
aminoethyl-3-aminopropyltrimethoxysilane, 3-aminopropyltriethoxysilane,
tetraethoxy-silane and the like.
[0038] The weight ratio of RPM macromolecule to organosilicon compound in
the aqueous composition is generally from about 3:200 to about 20:4. The
weight percentage of the RPM and organosilicon compound composite in the
aqueous composition is generally from about 0.01 to about 25 weight percent.
For instance, where the RPM macromolecule is PVA, the concentration ratio
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in parts per million of PVA RPM macromolecule to silicon in the organosilicon
compound in the aqueous composition is generally from about 20,000:80 to
about 200,000:40,000, preferably from about 50,000:800 to about
100,000:4,000. The weight percentage of the PVA RPM and silicon in the
organosilicon compound composite in the aqueous composition is generally
from about 2.0% to 24.00%, preferably from 5.0% to 10.5%, weight
percentage. The concentration ratio in parts per million of polyacrylamide
RPM macromolecule to silicon in the organosilicon compound in the aqueous
composition is generally from about 100:80 to about 6,000:40,000, preferably
from about 900:800 to about 3,000:4,000. The weight percentage of the
polyacrylamide RPM and silicon in the organosilicon compound composite in
the aqueous composition is generally from about 0.02% to 4.60%, preferably
from 0.17% to 0.70%, weight percent.
[0039] As used herein, the terms "alkyl", "alkylene", "alkynyl", "alkoxy",
"alkoxyalkyP', "aryl", "halogen"/"halide", "heterocyclic", and "aralkyl",
alone or in
combination, have their usual chemical meaning, as known to those of skill in
the art. Preferably, the alkyl radicals contain from about 1 to about 50
carbon
atoms, and more preferably from about I to about 25 carbon atoms. In a
similar manner, the alkylene and/or alkynyl radicals contain from about 2 to
about 50 carbon atoms, and more preferably from about 2 to about 18 carbon
atoms.
[0040] The term "substituted", as used herein, indicates that one or more
hydrogen on the designated atom or substituent is replaced with a selection
from the indicated group, provided that the designated atom's normal valency
is not exceeded, and the that the substitution results in a stable compound.
[0041] In one embodiment, the disclosed co-polymers may be polymerized
from monomers using gel polymerization methods. In any case,
polymerization is typically carried out in oxygen free or in a reduced oxygen
environment. In this regard, a closed reactor in which oxygen has been
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removed and the reactor has been sparged and pressured with nitrogen gas,
a solution where nitrogen gas is bubbled throughout the reacting solution, or
other suitable polymerization methods known in the art may be employed with
benefit of this disclosure. If so desired, a water control treatment fluid may
be
prepared at a well site.
[0042] With benefit of this disclosure, an aqueous base fluid may be any
aqueous-base fluid suitable for well treatments known in the art including,
but
not limited to, fresh water, acidified water having pH range from 1.0 to 3.0,
brine, sea water, synthetic brine (such as 2% KCI), produced formation water,
and the like.
[0043] If so desired, optional mutual solvents may also be used with the
aqueous composition of the invention. Mutual solvents, among other things,
may act to remove hydrocarbons adhering to formation material. In this
regard, any mutual solvent suitable for solubilizing hydrocarbons may be
employed including, but not limited to, terpenes (such as limonene), C3 to C9
alcohols (such as isopropanol), glycol-ether (such as ethylene glycol
monobutyl ether, "EGMBE"), or mixtures thereof.
[0044] It will be understood with benefit of the present disclosure that other
additives known in the art for use in stimulation and well treatments may be
employed in the practice of the disclosed method if so desired. For example,
wetting agents, surfactants, thickeners, diversion agents, pH buffers, and the
like can be used. In one embodiment, internal diverting materials may be
employed if desired. Examples of suitable diverting agents include, but are
not
limited to, viscous water external emulsions, and are known to those of skill
in
the art. In one embodiment, an aqueous composition may be added to a salt
solution, such as a 2% salt solution, wherein the salt is preferably potassium
chloride.
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[0045] The disclosed aqueous compositions may be used as the only
component in an aqueous water control treatment fluid or may be combined
with other components of stimulation fluid or other well treatment fluid (such
as hydraulic fracturing fluids, acid fluids, surfactant squeeze treatment
fluids,
etc.).
[0046] Whether utilized as part of a stand-alone water control treatment
fluid,
employed in conjunction with another type of well treatment such as a
stimulation treatment, or otherwise introduced into a well, the disclosed
aqueous composition may be present in any concentration suitable for
controlling water production in a subterranean formation. However, in one
embodiment, one or more of the disclosed RPMs and/or RPM microgel
compositions are present in the treatment fluid at a total concentration of
from
about 1 ppm to about 10,000 ppm polymer, and more preferably from about 3
ppm to about 6,000 ppm polymer, based on the total weight of the water
control treatment fluid.
[0047] To reduce injection pressures during injection of a well treatment
fluid,
the potassium chloride may be added to the aqueous solution and the pH
reduced to a low value, for example to about 1, just prior to introduction of
the
treatment fluid into a wellbore. Using this optional procedure helps minimize
injection pressure and ensure the extent of penetration of the aqueous
composition into the formation. The pH of a well treatment fluid may be
lowered by the addition of any acidic material suitable for decreasing pH of
the fluid to less than about 3, and alternatively between about 1 and about 3.
Suitable acidic materials for this purpose include, but are not limited to,
hydrochloric acid, formic acid and acetic acid, etc. With benefit of this
disclosure, those of skill in the art will understand that addition of acidic
material and adjustment of pH may be varied as desired according to
treatment fluid characteristics and formation temperature conditions in order
to optimize polymer retention and water control.
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[0048] The aqueous composition may be batch prepared or prepared by
continuous mix processes. For example, the water control treatment fluid may
be first prepared in total, and then injected or otherwise introduced into a
subterranean formation. This is referred to as a "batch mixing" process. In
another embodiment, a water control treatment fluid may be prepared by
continuous mix processes, wherein the treatment fluid components are mixed
together while the fluid is simultaneously introduced into the wellbore.
[0049] Once a treatment fluid is prepared (either by batch or continuous
mixing), the water control treatment fluid is introduced into the subterranean
formation in any amount suitable for contacting a portion of a reservoir
matrix
of flow pathways. By "introduced" it is meant that a fluid may be pumped,
injected, poured, released, displaced, spotted, circulated or otherwise placed
within a well, wellbore, and/or formation using any suitable manner known in
the art. In one embodiment, an amount of treatment fluid sufficient to treat
the
entire height of the producing interval having a radius of from about 3 to
about
10 foot from the wellbore may be employed, however greater or lesser
amounts are also possible.
[0050] The aqueous treating compositions of the present invention have
particular applicability in those instances where the formation permeability
is
between from about 0.1 mD to about 10,000 mD. In high permeability (>1 to
1.5 Darcy) formations, optimum treatment results have been obtained. Core
flow test results show effectiveness at a permeability as high as 8.0 Darcy
(8,000 mD) under high rate flow conditions. Such hydrocarbon-bearing
formations suitable for treatment with the compositions described herein are
permeable formations including those comprised of diatomaceous materials,
quartz, shale, zeolite, chert, clay, silt, carbonate, or combinations thereof.
CROSSLINKERS
[0051] As indicated previously, and in accordance with the present invention,
the relative permeability modifier macromolecules of the present invention
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used as water redirecting agents can be crosslinked either internally,
externally, or both. Such crosslinking is preferably performed using one or
more chemical cross-linking techniques (vs. UV irradiation, biological
crosslinking, etc.), and can occur during the synthesis of the RPM
macromolecules, at the welisite just prior to injection into an injector well
(in
the case of external crosslinking), or both. Crosslinkers suitable for use
with
the RPM macromolecules/microgels of the present invention include
aldehydes, amides, acrylamides, isocyanates, metal salts, di- or poly-allyl
based monomers, carbodiimide cross-linkers, and polyepoxide compounds.
Most preferably, the RPM macromolecules of the present invention are
crosslinked using aidehyde-based crosslinking techniques, acrylamide-based
crosslinking techniques, or using polyepoxide compounds.
[0052] Examples of useful multifunctional crosslinking monomers include
multifunctional acrylamides, and (meth)acrylates containing unsaturation at
preferably 2, and optionally 3 or more sites on each copolymerizable
comonomer molecule. In one embodiment, the multifunctional crosslinking
monomers are selected from the group consisting of monomeric polyesters of
acrylic or methacrylic acids and polyhydric alcohols; and monomeric
polyalkenyl polyethers of polyhydric alcohols containing from 2 to about 6
polymerizable alkenyl ether groups per polyether molecule. Another
exemplary crosslinking monomer is a monomeric polyester of an acrylic or
methacrylic acid and a polyhydric alcohol containing from 2 to about 6
polymerizable , -unsaturated acrylic groups per polyester molecule. Other
copolymerizable crosslinking monomers include divinyl ether, ethylene glycol
dimethacrylate, (m)ethylene-bisacrylamide, allyipentaerythritol, and the like.
The preferred crosslinking comonomers are somewhat water soluble and
monomer soluble. Preferably, the acrylamide crosslinking agent used with the
RPM macromolecules suitable for use in the methods of the present
disclosure is methylene bis-acrylamide, or combinations of crosslinkers
including methylene bis-acrylamide.
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[0053] Aldehyde-based cross-linking techniques includes those techniques
using a reagent containing two reactive aldehyde groups to form covalent
cross-links between neighboring amino groups of monomer residues in the
relative permeability modifier macromolecules described herein [Khor, E.,
Biomaterials, Vol. 18: pp. 95-105 (1997)]. Aldehydes suitable for use with the
present invention include but are not limited to glutaraidehyde, formaldehyde,
propionaldehyde, and butyraidehyde. Preferably, the aidehydes are
glutaraldehyde or formaldehyde.
[0054] Polyepoxy based cross-linking techniques and agents include the use
of compounds, such as short, branched polymers, terminating in reactive
epoxy functionalities. Polyepoxy compounds suitable for use as cross-linking
agents in the present invention include but are not limited to glycerol
ethers,
glycol, and glycerol polyglycidyl ethers.
[0055] Isocyanates are also suitable for use as cross-linking agents in the
present invention. Generally, the isocyanates (R-NCO) react with primary
amines to form a urea bond (R-H-CO-NH-R); difunctional isocyanates
therefore have the ability to cross-link RPMs via lysine-like side chains.
Isocyanates suitable for use as cross-linking agents in the present invention
are preferably diisocyanates, including biphenyl diisocyanate, dimethoxy-4,4'-
biphenyl diisocyanante, dimethyl-4,4'-biphenyl diisocyanate, 1,3-
bis(isocyanatomethyl)benzene, phenyl diisocyanate, toluene diisocyanate,
tolyiene diisocyanate, diisocyanato hexane, diisocyanato octane, diisocyanato
butane, isophorone diisocyanante, xylene diisocyanate, hexamethylene
diisocyanante, octamethylene diisocyanante, phenylene diisocyanate, and
poly(hexamethylene diisocyanate). Preferably, the isocyanate used as a
cross-linking agent of the RPM macromolecules of the present invention is
hexamethylene diisocyanate.
[0056] Carbodiimide cross-linking agents and techniques can also be used
within the scope of the present invention. These agents react with the
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carboxyl groups of monomers within the RPM macromolecules/microgels to
form isoacylurea derivatives/iso-peptide bonds [Khor, E., ibid.].
Carbodiimides suitable for use as cross-linking agents with the relative
permeability modifier macromolecules of the present invention include but are
not limited to N,N'-dicyclohexylcarbodiimide (DCC); N,N'-
diisopropylcarbodiimide (DIC); N,N'-di-tert-butylcarbodiimide; 1-ethyl-3-(3-
dimethylaminopropyl)carbodiimide (EDC; EDAC); water-soluble EDC (WSC);
1 -tert-butyl-3-ethylcarbodiimide; 1-(3-dimethylaminopropyl)-3-
ethylcarbodiimide; bis(trimethylsilyl)carbodiimide; 1,3-bis(2,2-dimethyl-1,3-
dioxolan-4-ylmethyl)carbodiimide (BDDC, as described in U.S. Patent No.
5,602,264); N-cyclohexyl-N'-(2-morpholinoethyl) carbodiimide; N, N'-
diethylcarbodiimide (DEC); 1-cyclohexyl-3-(2-morpholinoethyl)carbodiimide
methyl-p-toluenesulfonate [e.g., Sheehan, J.C., et al., J. Org. Chem., Vol.
21:
pp. 439-441 (1956)]; oligomeric alkyl cyclohexylcarbodiimides, such as those
described by Zhang, et al. [J. Org. Chem., Vol. 69: pp. 8340-8344 (2004)];
polymer bound DCC; and polymer bound EDC, such as cross-linked N-ethyl-
N'-(3-dimethylaminopropyl)carbodiimide on JANDAJELTM. Additionally, N-
hydroxysuccinimide (NHS), 1-hydroxy-7-azabenzotriazole (HOAt), or similar
reagents can be utilized in conjunction with the carbodiimide to minimize
internal rearrangement of the activated isoacylurea derivative and provide
more efficient cross-linking.
[0057] Other chemical cross-linking agents suitable for use in the present
invention to provide cross-linked RPM macromolecules for use in redirecting
formation water to improve hydrocarbon recovery from subterranean
formations include but are not limited to homobifunctional cross-linkers such
as BMME, BSOCOES, DSP (a thio-cleavable cross-linker), DSS, EGS, water-
soluble EGS, and SATA, as well as heterobifunctional cross-linking agents
including GMB, MBS, PMPI, SMCC, SPDP, and MPH (maleimidopropionic
acid hydrazide), MCH, EMCH (maleimidocaprionic acid hydrazide), KMUH (N-
( -Maleimidoundecanoic acid)hydrazide), and MPBH (4-(4-N-
MaleimidoPhenyl)butyric acid hydrazide), all available from Interchim (Cedex,
France).
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[0058] Specific examples of other crosslinking monomers suitable for use
herein include but are not limited to trimethylol propane triacrylate (TMPTA),
trimethylol propane trimethacrylate (TMPTMA); diethylene glycol diacrylate
(DEGDA), diethylene glycol dimethacrylate (DEGDMA), trimethylene glycol
diacrylate, butylene glycol diacrylate, methylene-bis-acrylamide,
pentamethylene glycol diacrylate, octylene glycol diacrylate, glyceryl
diacrylate, glyceryl triacrylate, neopentyl glycol diacrylate, the
tetraacrylate
ester of pentaerythritol, as well as combinations thereof.
[0059] It is understood that certain monounsaturated monomers may act in
varying degrees to crosslink or branch the water soluble copolymer of the
invention. For example, acrylate monomers with abstractable hydrogens,
which can function as radical reactive sites, can in some embodiments of this
invention, form a more branched or crosslinked polymer, thus affecting the
preferred levels of the polyethylenic unsaturated crosslinking comonomers.
An example of a monounsaturated monomer with an abstractable hydrogen is
2-ethylhexyl acrylate.
[0060] Optional heat-reactive, latent carboxy- or hydroxy-reactive internal
crosslinking systems can be provided by the incorporation of carboxylic-group
containing comonomers, and N-alkylol amides, for example, N-methylol
acrylamide, N-propylol acrylamide, N-methylol methacrylamide, N-methylol
maleimide, N-methylol maleamic acid esters, N-methylol-p-vinyl benzamide,
and the like.
[0061] Known methods for optional post-polymerization crosslinking of
carboxylic acid containing copolymers include, for example, U.S. Pat. No.
4,666,983 (crosslinking agent without any carrier solvent), using e.g.
polyhydric alcohols, polyglycidyl ethers, polyfunctional amines and
polyfunctional isocyanates. U.S. Pat. No. 4,507,438 and 4,541,871 utilize a
difunctional compound in water with inert solvent or mixture of solvents. The
difunctional compounds include glycidyl ethers, haloepoxies, aldehydes and
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isocyanates with ethylene glycol diglycidyl ether crosslinker. The solvents
include polyhydric alcohols with ethylene glycol, propylene glycol and
glycerine enumerated as preferred polyhydric alcohols. U.S. Pat. No.
5,140,076 teaches a water-solvent-crosslinker mixture. Crosslinkers such as
polyhydric alcohol, diglycidyl ether, polyaziridene, urea, amine and ionic
crosslinkers are suggested.
[0062] The crosslinked copolymers used herein form a stable, microgel
solution as a result of obtaining a molecular size or weight, as characterized
by the K-value test, of from about 220 to about 1000 (i.e., a K-value of from
about 200 to about 1,000), and more typically have K-values of from about
220 to about 500. For example, in accordance with one aspect of the present
invention, the relative permeability macromolecules of the present invention
have a K value from about 220 to about 300.
[0063] The crosslinked copolymers of the present invention have no readily
definable molecular weight due to the intermolecular crosslinking of the
polymer chains. The Fikentscher value, or K-value measurement is a way to
indirectly indicate molecular weight and/or size of the copolymers,
accordingly. A higher K-value corresponds to a polymer of comparatively
larger molecular weight and/or size or one that exhibits greater chain
entanglement behavior.
[0064] To determine the K-value, the copolymer is typically dissolved to a
0.5% concentration in deionized water and the flow-out time is determined at
about 25 C by means of a capillary viscometer. This value gives the absolute
viscosity (eta-c) of the solution. The absolute viscosity of the solvent is
eta-0.
The ratio of the two absolute viscosities gives the relative viscosity, z,
eta - c
z=
eta - 0
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from the relative viscosities of the function of the concentration. The K-
value
can then be determined by means of the following equation:
* 2
Logz - 75 k+ kl * c
11+1.5kc
Any suitable capillary viscometer instrument known in the art (e.g., a
Ubbelohde viscometer) can be used for the K-value measurements, in
accordance with the present invention.
METHODS OF USE
[0065] The RPM macromolecules and/or soft RPM microgel compositions of
the present invention can be used to improve hydrocarbon recovery in
subterranean operations by water flood intervention. More particularly, and as
shown in Figure 1, a series of drilled and completed producing wells (12) has
a series of injection wells (10) loosely spaced apart from each other and
perforated so as to be able to direct fluid (14) in the direction of the
producer
wells (12). According to one aspect of the present invention, injection fluid
(14), which is an aqueous treating fluid comprising at least one RPM
macromolecule as described herein, is directed into injector well or wells
(10)
by a pressure sufficient to move the fluid containing the RPM macromolecules
into the hydrocarbon-bearing formation. The mixture that is ultimately used
can optionally contain, in addition to the RPM macromolecules, one or more
of a combination of chemical additives including wetting agents, surfactants,
and caustic or alkaline materials, in order to enhance the redirection of
water
flow within the subterranean matrix within the formation. As fluid (14) is
pumped into the formation, the RPMs in the treating fluid cause the water to
be redirected through the formation, and in doing so displace the
hydrocarbons (e.g., oil) toward the producing well or wells (12). Thereafter,
the oil will be produced from the producer well (12) to the surface,
preferably
with very little water contamination which would necessitate separation of the
oil from the water at the surface level.
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[0066] Use of the relative permeability modifier macromolecules and/or RPM
microgels in combination with the formations as described herein will allow
substantially more hydrocarbonaceous fluids or oil to be produced from the
formation than before the treatment methods described herein. This occurs
because the flow of the RPM macromolecules in the aqueous treating fluid
down and through the injector wells allow for substantially more formation
contact by the RPM treating fluid mixture, which then redirects water from the
formation toward the producer wells, and in doing so removes oil from the
formation and alters the injection profile of the well.
[0067] The following examples are included to demonstrate preferred
embodiments of the invention. It should be appreciated by those of skill in
the
art that the techniques disclosed in the examples which follow represent
techniques discovered by the inventors to function well in the practice of the
invention, and thus can be considered to constitute preferred modes for its
practice. However, those of skill in the art should, in light of the present
disclosure, appreciate that many changes can be made in the specific
embodiments which are disclosed and still obtain a like or similar result
without departing from the scope of the invention.
EXAMPLES
Example 1: General Procedure for Parallel Core Flow Testing
[0068] The first step is to determine the test core dimensions and baseline
properties. The test cores were placed into a suitable core-holder of a
parallel
flow test apparatus. The dry cores were then saturated with brine. Following
saturation, the cores were heated to the test temperature(s) with the required
confining and back pressures. The initial permeability to brine through both
cores was then determined independently by establishing flow in an arbitrary
injection direction (to simulate injection into the reservoir) at constant
rate until
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steady state. AquaConTM (available from BJ Services Company, Houston,
TX) treatment fluid was then injected through the parallel flow apparatus, at
a
constant rate of approx. 0.3 mi/min, in the injection (treatment) direction.
AquaConTM treatment flow and pressure drops through both the high
permeability and low permeability cores were measured simultaneously. The
duration of this AquaConTM treatment stage depended upon three things: i.)
achievement of an 80-90% permeability reduction (for high permeability cores
only); ii.) little or no noticeable permeability reduction at any given
treatment
concentration; and/or iii.) pore volume throughput based on previous tests.
[0069] Following the initial injection and measurements of the treatment fluid
through the parallel-flow apparatus, brine was re-injected in the same
direction at a constant rate of 0.3 mI/min in order to determine post-
treatment
steady state permeability to brine. These last two steps, treatment fluid
injection and brine re-injection, were then repeated as necessary in order to
further reduce the permeability to brine.
Example 2. Parallel Core Flow Test
[0070] The purpose of this test was to determine AquaConTM (BJ Services
Co., Houston, TX) effectiveness in reducing water flow through high
permeability thief zones without significantly affecting the permeability in
lower
permeability zones. For this test, a high permeability sandstone core that was
10 times more permeable than the low permeability core (air permeability
contrast of 10:1) was used. The result of the linear parallel core flood
testing
with 0.05% AquaConTM is shown in Table 1 below.
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Table 1.
Before Treatment AquaCon After Treatment
Treatment
Test Core Type Ratio % Pore Permeability Ratio
of Conc. Volumes of
Kair Kbrine Kbrine Reduction
High from Initial High
Kbrine - % Kbrine:
Low Low
Kbrine Kbrine
601 134 0.05 19 86%
1 Sandstone 59.4 14 9.6 0.05 23 10 29% 1.9
[0071]A total of 23 pore volumes of AquaConTM treatment were injected
Othrough the parallel core flow apparatus. As expected, the majority of the
AquaConTM treatment flowed preferentially through the high permeability core
that resulted in a significant brine permeability reduction (86%). In the low
permeability core, there was less treatment invasion and hence a smaller
brine permeability reduction (29%). Since a much larger injectivity loss
occurs
in the high permeability core, the AquaConTM treatment significantly improved
the injection profile, or distribution through the cores of contrasting
permeabilities. Initially, the brine permeability contrast between the two
cores
was 9.6, compared to 1.9 after treatment. Figure 2 illustrates the graphical
representation of these test results. The results of this core-flow testing
showed that AquaConTM at very low concentrations could be applied to
effectively treat injection wells.
[0072] AII of the apparatus, methods and other particular embodiments
disclosed and claimed herein can be made and executed without undue
experimentation in light of the present disclosure. While the compositions and
methods of this invention have been described illustratively in terms of
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preferred embodiments, it will be apparent to those of skill in the art that
variations may be applied to the methods and/or apparatus and in the steps or
in the sequence of steps of the methods described herein without departing
from the concept and scope of the invention. Furthermore, no limitations are
intended as relates to the details of construction or design as described
herein. For example, the dimensioning illustrated in some of the drawing
figures is exemplary in nature only, and it is to be understood that the
particular embodiments described herein may be altered or modified by one of
skill in the art, and that all such variations are considered within the scope
and
spirit of the present invention.
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