Note: Descriptions are shown in the official language in which they were submitted.
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SURFACTANT ADDITIVES FOR STIMULATING SUBTERRANEAN
FORMATION DURING FRACTURING OPERATIONS
BACKGROUND
[0001] The present invention relates to hydrocarbon production, and
more particularly, to surfactant additives useful for restoring permeability
of a
subterranean formation and methods of use thereof.
[0002] Formation damage is typically the result of unwanted side effects
from exposing a producing formation with subterranean treatment fluids.
Examples of subterranean treatment fluids that may cause formation damage
include, for example, drilling fluids, completion fluids, fracturing fluids,
work-
over fluids, and the like. As used herein, "formation damage" and its related
terms (e.g., damaged formation) generally refer to a reduction in the
capability
of a reservoir to produce its fluids (e.g., oil and gas), such as a decrease
in
porosity or permeability or both.
[0003] There are several mechanisms that can lead to formation
damage.
These mechanisms may include, among other things, physical
plugging of pores, alteration of reservoir rock wettability, precipitation of
insoluble materials in pore spaces, clay swelling, and blocking by water
(i.e.,
water blocks). In particular, a water block is often caused by an increase in
water saturation in the near-wellbore area, which results in a decrease in
relative permeability to hydrocarbons.
[0004] As used herein, the term "water block" generally refers to a
condition caused by an increase in water saturation in the near-wellbore area.
The increased presence of water may cause any clay present in the formation to
swell and cause a reduction in permeability and/or the water may collect in
the
pore throats, resulting in a decreased permeability due to increased capillary
pressures and cohesive forces.
[0005] Water blocks can be especially problematic in certain fracturing
operations where a large volume of aqueous fracturing fluid leaks off into the
formation through the fracture face, which can lead to a decrease in the rate
at
which oil or gas can be produced.
Because water is immiscible with
hydrocarbons, the leaked off fluid can be slow to return to the surface due to
the
formation being preferentially water-wet. This problem becomes increasingly
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serious with decreasing natural permeability of a formation because pore sizes
are often smaller and capillary action is typically stronger.
[0006] Clean up or removal of water blocking is often difficult,
expensive, and/or environmentally unfriendly.
For example, one common
remedial approach is to treat a formation with surfactants that are capable of
reducing interfacial tension and/or altering wettability properties.
However,
these treatments typically require a surfactant/solvent system that uses harsh
organic solvents that may be environmentally unfriendly and/or expensive.
SUMMARY OF THE INVENTION
[0007] The present invention relates to hydrocarbon production, and
more particularly to surfactant additives useful for restoring permeability of
a
subterranean formation and methods of use thereof.
[0008] In some embodiments, the present invention provides methods
comprising: providing a fracturing fluid comprising: an aqueous fluid, and a
microemulsion surfactant, wherein the fracturing fluid is substantially free
of an
organic solvent; and placing the fracturing fluid into a subterranean
formation at
a rate sufficient to create or enhance at least one fracture in the
subterranean
formation.
[0009] In other embodiments, the present invention provides methods
comprising: providing a fracturing fluid comprising: an aqueous fluid, a
microemulsion surfactant, and a co-surfactant, wherein the fracturing fluid is
substantially free of an organic solvent; and placing the fracturing fluid
into a
subterranean formation at a rate sufficient to create or enhance at least one
fracture in the subterranean formation.
[0010] In still other embodiments, the present invention provides
methods comprising: providing a composition comprising: a microemulsion
surfactant, wherein the composition is substantially free of an organic
solvent;
placing the composition into at least a portion of a fracture in a
subterranean
formation having a first permeability; and allowing the composition to remove
a
water block from the subterranean formation to increase permeability of the
subterranean formation to a second permeability.
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[0011] 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] The following figure is included to illustrate certain aspects of the
present invention, and should not be viewed as an exclusive embodiment. The
subject matter disclosed is capable of considerable modifications,
alterations,
combinations, and equivalents in form and function, as will occur to those
skilled
in the art and having the benefit of this disclosure.
[0013] Fig. 1 shows a plot illustrating regain permeability resulting from
surfactant treatments as described in Example 1.
DETAILED DESCRIPTION
[0014] The present invention relates to hydrocarbon production, and
more particularly to surfactant additives useful for restoring permeability of
a
subterranean formation and methods of use thereof.
[0015] The present invention provides a number of advantages. In
some embodiments, the compositions and methods of the present invention are
able to at least partially remediate and/or reverse some of the effects of
formation damage often caused by the invasion of aqueous or aqueous-based
fracturing fluids into a subterranean formation. In one or more embodiments,
the present invention is able to remove water blocks by using microemulsion
surfactants without the use of organic solvents, which is common in
conventional
surfactant-based remedial treatments. In some embodiments, the present
invention is able to remediate and/or reverse some of the effects of formation
damage better than conventional surfactant-based remedial treatments that
contain organic solvents (see Example 1). The elimination of organic solvents
from the fracturing fluids of the present invention is a key advantage, which
may
provide efficacy, cost, and/or environmental benefits.
[0016] It has been discovered that the use of a fracturing fluid capable
of forming a microemulsion without organic solvents in-situ can at least
partially
restore the permeability of a damaged formation. In some embodiments, the
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use of a fracturing fluid of the present invention can result in a retained
producibility or regain permeability that is higher than that obtained by
using
conventional fracturing fluids containing surfactants and organic solvents.
Without being limited by theory, it is believed that the present invention can
form microemulsions in-situ and water wet the surface of a reservoir, which
can
eliminate water blocks that often reduce production of oil and gas.
[0017] As used herein, "retained producibility" or "regain permeability"
refers to the relative permeability of a formation after exposure to a
fracturing
fluid divided by the permeability of the formation prior to exposure to the
fracturing fluid. Permeability may be determined by flowing, for example, oil,
gas, or water through an aloxide disk or natural core and recording the
differential pressure required to flow at a specific rate. The disk or core is
then
exposed to the fracturing fluid and a return permeability is obtained by again
flowing oil/gas/or water.
The ability to increase the permeability of the
formation, or in a sense stimulate the formation using the fracturing fluid of
the
present invention, may be considered advantageous.
[0018] In some embodiments, the present invention provides methods
comprising: providing a fracturing fluid comprising: an aqueous fluid, and a
microemulsion surfactant, wherein the fracturing fluid is substantially free
of an
organic solvent; and placing the fracturing fluid into a subterranean
formation at
a rate sufficient to create or enhance at least one fracture in the
subterranean
formation. Examples of organic solvents found in conventional surfactant-based
remedial treatments (but excluded from the fracturing fluids of the present
invention) include, but are not limited to, terpene-based solvent, an alkyl
acid
ester of a short chain alcohol, an aryl acid ester of a short chain alcohol,
benzene, toluene, xylene, or any other solvents known to one of ordinary skill
in
the art for use in a wellbore.
The fracturing fluid (and/or the separate
components thereof) may be introduced into a portion of a subterranean
formation by any means known in the art.
[0019] As used herein, the term "fracturing fluid" generally refers to a
subterranean treatment fluid placed into a well as part of a stimulation
process,
oftentimes at a pressure that is sufficient to overcome pressures within the
formation so as to create or enhance fractures therein. Stimulation is
typically
achieved by injecting the fracturing fluid at a flow rate sufficient to
increase
pressure downhole to exceed the fracture gradient of the rock. A fracturing
fluid
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is often a water-based fluid containing various additives. A common additive
found in fracturing fluids is a gelling agent that increases the viscosity of
the
fluid. The gelling agent is commonly a polymeric material that absorbs water
and forms a gel as it undergoes hydration. A fracturing fluid may contain
additional additives such as, but not limited to, acids, biocides, friction
reducers,
iron control agents, crosslinking agents, breakers, surfactants, proppants,
and
the like. Suitable examples of these additives are well-known by those of
ordinary skill in the art.
[0020] The aqueous fluid used in the fracturing fluids of the present
.. invention can comprise any suitable aqueous fluid known to one of ordinary
skill
in the art. Suitable aqueous fluids may include, but are not limited to, fresh
water, saltwater (e.g., water containing one or more salts dissolved therein),
glycol, brine (e.g., saturated saltwater), weighted brine (e.g., an aqueous
solution of sodium bromide, calcium bromide, zinc bromide and the like), and
any combination thereof. Generally, the aqueous fluid may be from any source,
provided that it does not contain components that might adversely affect the
stability and/or performance of the fracturing fluids of the present
invention. In
certain embodiments, the density of the aqueous fluid can be increased, among
other purposes, to provide additional particle transport and suspension in the
fracturing fluids of the present invention using, for example, one or more
salts.
In some embodiments, the aqueous fluid is present in the fracturing fluid in
an
amount ranging from about 40% to about 99.9% by weight of the fracturing
fluid.
[0021] In general, the methods and compositions of the present
invention are capable of forming microemulsions in a fracturing fluid. The
term
"microemulsions" as used herein refers to liquid dispersions of water and oil
that
are made thermodynamically stable by the mixture of three or more
components: a polar phase (e.g., water), a nonpolar phase (e.g., oil), and a
microemulsion surfactant. In some embodiments, the microemulsion may
include other surfactants (e.g., a co-surfactant such as an alcohol, glycol or
phenol, or their ethoxy derivatives). In some embodiments, the microemulsion
surfactant may form the microemulsion within a subterranean formation. The
use of a fracturing fluid comprising a microemulsion surfactant can be used to
alter the wettability of the formation surface, remove oil and/or water
blocks,
and alter the wettability of a filter cake or other fluid loss additive placed
into the
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subterranean formation during a fracturing operation. In some embodiments,
the fracturing fluids and methods described herein may be used to remove a
water block by removing at least a portion of the water in the near wellbore
area, and/or altering the wettability of the subterranean formation. This may
directly or indirectly lead to reduced capillary pressure in the porosity of
the
formation. Reduced capillary pressure may lead to increased water and/or oil
drainage rates. As will be appreciated, improved water-drainage rates should
allow a reduction in existing water blocks, as well as a reduction in the
formation
of water blocks.
[0022] As used herein, the term "microemulsion surfactant" can include
any surfactant capable of forming a microemulsion in a fracturing fluid that
comprises a polar phase and a non-polar phase and/or an oleaginous fluid,
alone
or in combination with a co-surfactant. As used herein, a "co-surfactant"
refers
to a compound that participates in aggregation of molecules into a
microemulsion but does not aggregate on its own.
[0023] The phase equilibria of microemulsions may be classified by
Winsor types. These types are generally described as one of the following: a
Winsor I which describes a microemulsion in equilibrium with an excess oil
phase; a Winsor II which describes a microemulsion in equilibrium with excess
water; and a Winsor III which describes a middle phase microemulsion in
equilibrium with excess water and excess oil (e.g., as a part of a three-phase
system). In addition, a Winsor IV is a single-phase microemulsion, with no
excess oil or excess water. The thermodynamically stable single phase Winsor
IV microemulsion could evolve by a change in formulation or composition into
the formation of a mini-emulsion or nano-emulsion, which is a two-phase system
with submicron size droplets which could be stable for long periods of time,
but
not permanently stable as a microemulsion.
[0024] The fracturing fluids of the present invention may comprise one
or more microemulsion surfactants. Suitable microemulsion surfactants include,
but are not limited to, polymeric surfactants, block copolymer surfactants, di-
block polymer surfactants, hydrophobically modified surfactants, fluoro-
surfactants, non-ionic surfactants, anionic surfactants, cationic surfactants,
zwitterionic surfactants, derivatives thereof, and combinations thereof.
Suitable
non-ionic surfactants include, but are not limited to, alkyl polyglycosides,
sorbitan esters, methyl glucoside esters, amine ethoxylates, d ia mine
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ethoxylates, polyglycerol esters, alkyl ethoxylates, alcohols that have been
polypropoxylated and/or polyethoxylated or both, derivatives thereof, and
combinations thereof. Suitable cationic surfactants include, but are not
limited
to, arginine methyl esters, alkanolamines, alkylenediamides, alkyl ester
sulfonates, alkyl ether sulfonates, alkyl ether sulfates, alkali metal alkyl
sulfates,
alkyl or alkylaryl sulfonates, sulfosuccinates, alkyl or alkylaryl
disulfonates, alkyl
disulfates, alcohol polypropoxylated and/or polyethoxylated sulfates,
taurates,
amine oxides, alkylamine oxides, ethoxylated amides, alkoxylated fatty acids,
alkoxylated alcohols, ethoxylated fatty amines, ethoxylated alkyl amines,
betaines, modified betaines, alkylamidobetaines, quaternary ammonium
compounds, alkyl propoxy-ethoxysulfonate, alkyl propoxy-ethoxysulfate,
alkylaryl-propoxy-ethoxysulfonate, derivatives thereof, and combinations
thereof. Specific microemulsion surfactants may also include, but are not
limited
to, polyoxyethylene sorbitan monopalmitate, polyoxyethylene sorbitan
monostearate, polyoxyethylene sorbitan monooleate, linear alcohol alkoxylates,
alkyl ether sulfates, dodecylbenzene sulfonic acid, linear nonyl-phenols,
dioxane,
ethylene oxide, polyethylene glycol, ethoxylated castor oils, dipalmitoyl-
phosphatidylcholine, sodium 4-(1' heptylnonyl)
benzenesulfonate,
polyoxyethylene nonyl phenyl ether, sodium dioctyl sulphosuccinate,
tetraethyleneglycoldodecylether, sodium octlylbenzenesulfonate, sodium
hexadecyl sulfate, sodium laureth sulfate, ethylene oxide, decylamine oxide,
dodecylamine betaine, dodecylamine oxide, any derivative thereof, and any
combination thereof. In one or more non-limiting embodiments, at least two
surfactants in a blend may be used to create single phase microemulsion in-
situ.
Suitable microemulsion surfactants may also include surfactants containing a
non-ionic spacer-arm central extension and an ionic or non-ionic polar group.
The non-ionic spacer-arm central extension may be the result of
polypropoxylation, polyethoxylation, or a mixture of the two, in non-limiting
embodiments.
[0025] The term "derivative," as used herein refers to any compound
that is made from one of the identified compounds, for example, by replacing
one atom in the listed compound with another atom or group of atoms, or
rearranging two or more atoms in the listed compound.
[0026] The amount of microemulsion surfactant included in the
fracturing fluid of the present invention may be based on a number of factors
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including, but not limited to, the type of aqueous fluid, the temperature of
the
formation, the particular surfactant or surfactant blend used, the type of
optional
additives included, and the like. In some embodiments, the microemulsion
surfactant is present in the fracturing fluid in an amount of from about
0.001%
to about 50% by weight of the fracturing fluid. In some embodiments, the
microemulsion surfactant is present in the fracturing fluid in an amount of
from
about 0.01% to about 20% by weight of the fracturing fluid.
[0027] In some embodiments, the fracturing fluid may comprise a
microemulsion surfactant or a surfactant blend or a surfactant-co-surfactant
mixture. Suitable co-surfactants useful with the fracturing fluids of the
present
invention include, but are not limited to, alcohols (e.g., propanol, butanol,
pentanol in their different isomerization structures, ethoxylated and
propoxylated alcohols), glycols, phenols, thiols, carboxylates, sulfonates,
ketones, acrylamides, sulfonates, pyrollidones, derivatives thereof, and
combinations thereof. In some embodiments, an alcohol useful as a co-
surfactant may have from about 3 to about 10 carbon atoms.
In an
embodiment, suitable alcohols can include, but are not limited to, t-butanol,
n-
butanol, n-pentanol, n-hexanol, 2-ethyl-hexanol, propanol, and sec-butanol.
Suitable glycols can include, but are not limited to, ethylene glycol,
polyethylene
glycol, propylene glycols, and triethylene glycol. In some embodiments, the co-
surfactant may be included in the fracturing fluids of the present invention
in an
amount ranging from about 0.001% to about 20% by weight of the fracturing
fluid.
[0028] In some optional embodiments, the addition of an amphiphilic
polymer to the fracturing fluids of the present invention may improve the
stability of microemulsions. Without being limited by theory, it is believed
that
this stabilization may be achieved by tuning the curvature of a surfactant
film
with the hydrophilic and hydrophobic blocks that make up the amphiphilic
polymers. In some embodiments, the amphiphilic polymers may integrate into
the surfactant film to form a "tethered polymer," resulting in a stabilization
of
various surfactant structures ranging from micelles to flat bi-layers. This
stabilization can create an "efficiency boosting effect," allowing the
surfactant
structures to absorb more non-polar and/or oleaginous fluid and remain in a
single phase. In some embodiments, these stabilized microemulsions enable
fracturing fluids of the present invention to absorb up to 50% more, or
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alternatively, up to 60% more non-polar and/or oleaginous fluid than other
emulsions or microemulsion fluids not comprising an amphiphilic polymer.
[0029] The amphiphilic polymer used in the present invention may
comprise a variety of polymers known in the art that comprise a hydrophobic
component and a hydrophilic component.
In some embodiments, the
amphiphilic polymer may comprise between 2 and 50 monomer units. In some
embodiments, the amphiphilic polymer may comprise between 2 and 10
monomer units. Examples of hydrophobic components that may be suitable for
use include, but are not limited to alkyl groups, polybutadiene, polyisoprene,
polystyrene, polyoxystyrene, any derivatives thereof, and any combinations
thereof. Examples of hydrophilic components that may be suitable for use
include, but are not limited to, polyethylene oxide (PEO), polyacrylic acid
(PAA),
polyethylacetate, dimethylacrylamide (DMA), n-isopropylacrylamide (NIPAM),
polyvinylpyrrolidone (PVP), polyethyleneimine (PEI), any derivatives thereof,
and
any combinations thereof. Examples of amphiphilic polymers that may be
suitable for use include, but are not limited to polybutadiene-PEO,
polystyrene-
PEO, polystyrene-polyacrylic acid, polyoxystyrene-PEO,
polystyrene-
polyethylacetate, any derivatives thereof, and any combinations thereof. Other
examples of amphiphilic polymers that may be suitable for use in the present
invention include those that comprise units based on one or more of the
following: acrylamides, vinyl alcohols, vinylpyrrolidones, vinylpyridines,
acrylates, polyacrylamides, polyvinyl alcohols,
polyvinylpyrrolidones,
polyvinylpyridines, polyacrylates, polybutylene succinate, polybutylene
succinate-co-adipate, polyhydroxybutyrate-
valerate, polyhyd roxybutyrate-
covalerate, polycaprolactones, polyester amides, polyethylene terephthalates,
sulfonated polyethylene terephthalate, polyethylene oxides, polyethylenes,
polypropylenes, aliphatic aromatic copolyester, polyacrylic acids,
polysaccharides
(such as dextran or cellulose), chitins, chitosans, proteins, aliphatic
polyesters,
polylactic acids, poly(glycolides), poly(E-caprolactones), poly(hydroxy ester
ethers), poly(hydroxybutyrates), poly(anhydrides), polycarbonates,
poly(orthoesters), poly(amino acids), poly(ethylene oxides), poly(propylene
oxides), poly(phosphazenes), polyester amides, polyamides, polystyrenes, any
derivative thereof, any copolymer, homopolymer, or terpolymer, or any blend
thereof. In certain embodiments, the amphiphilic polymer may comprise a
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compound selected from the group consisting of hydroxyethyl acrylate,
acrylamide and hydroxyethyl methacrylate.
[0030] In certain embodiments, the amphiphilic polymer may comprise
one or more alkyl ethoxylates. In certain embodiments, the alkyl ethoxylate
may comprise an alkyl group, and an ethoxylate group. In certain
embodiments, the hydrophilic component may be larger and, for example, have
at least 20 oxyethylene units. In certain embodiments, the hydrophilic
component may be larger and, for example, have at least 40 oxyethylene units.
Commercially available sources of such amphiphilic polymers that may be
suitable for use in the present invention include, but are not limited to,
certain
detergents available under the tradename BRIJ , such as BRIJC)-30 (comprises
polyethylene glycol dodecyl ether), BRIJC)-35 (comprises polyoxyethyleneglycol
dodecyl ether), BRIJC)-58 (comprises polyethylene glycol hexadecyl ether),
BRIJ -97 (comprises polyoxyethylene (10) ley! ether), BRIJC)-98 (comprises
polyoxyethylene (20) leyl ether), and BRIJ -700 (comprises polyoxyethylene
(100) stearyl ether). Other commercially available sources of such amphiphilic
polymers that may be suitable for use in the present invention include,
certain
detergents available under the tradename IGEPAL .
[0031] The amphiphilic polymer should be present in a fluid of the
present invention in an amount sufficient to impart the desired viscosity
(e.g.,
sufficient viscosity to divert flow, reduce fluid loss, suspend particulates,
etc.) to
the fluid. In certain embodiments, the amphiphilic polymer may be present in
the fracturing fluid in an amount in the range of from about 0.01 mol % to
about
5 mol % based on the amount of the microemulsion surfactant.
[0032] The gelling agents suitable for use in the present invention may
comprise any substance (e.g., a polymeric material) capable of increasing the
viscosity of the fracturing fluid. In certain embodiments, the gelling agent
may
comprise one or more polymers that have at least two molecules that are
capable of forming a crosslink in a crosslinking reaction in the presence of a
crosslinking agent, and/or polymers that have at least two molecules that are
so
crosslinked (i.e., a crosslinked gelling agent). The gelling agents may be
naturally-occurring gelling agents, synthetic gelling agents, or a combination
thereof. The gelling agents also may be cationic gelling agents, anionic
gelling
agents, or a combination thereof. Suitable gelling agents include, but are not
limited to, polysaccharides, biopolymers, and/or derivatives thereof that
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one or more of these monosaccharide units: galactose, mannose, glucoside,
glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate.
Examples of suitable polysaccharides include, but are not limited to, guar
gums
(e.g., hydroxyethyl guar, hydroxypropyl guar, carboxymethyl guar,
carboxymethylhydroxyethyl guar, and carboxymethylhydroxypropyl guar
("CMHPG")), cellulose derivatives (e.g.,
hydroxyethyl cellulose,
carboxyethylcellulose, carboxymethylcellulose,
and
carboxymethylhydroxyethylcellulose), xanthan, scleroglucan, diutan, and
combinations thereof. In certain embodiments, the gelling agents comprise an
organic carboxylated polymer, such as CMHPG.
[0033] Suitable synthetic polymers include, but are not limited to, 2,2'-
azobis(2,4-dimethyl valeronitrile),
2,2'-azobis(2,4-dimethy1-4-methoxy
valeronitrile), polymers and copolymers of acrylamide ethyltrimethyl ammonium
chloride, acrylamide, acrylamido-and methacrylamido-alkyl trialkyl ammonium
salts, acrylamidomethylpropane sulfonic acid, acrylamidopropyl trimethyl
ammonium chloride, acrylic acid, dimethylaminoethyl methacrylamide,
dimethylaminoethyl methacrylate, dimethylaminopropyl methacrylamide,
dimethylaminopropylmethacrylamide,
dimethyldiallylammonium chloride,
dimethylethyl acrylate, fumaramide, methacrylamide, methacrylamidopropyl
trimethyl ammonium chloride, methacrylamidopropyldimethyl-n-
dodecylammonium chloride, methacrylamidopropyldimethyl-n-octylammonium
chloride, methacrylamidopropyltrimethylammonium chloride, methacryloylalkyl
trialkyl ammonium salts, methacryloylethyl trimethyl ammonium chloride,
methacrylylamidopropyldimethylcetylammonium chloride, N-(3-sulfopropyI)-N-
methacrylamidopropyl-N,N-dimethyl ammonium betaine,
N,N-
dimethylacrylamide,
N-methylacrylamide,
nonylphenoxypoly(ethyleneoxy)ethylmethacrylate, partially
hydrolyzed
polyacrylamide, poly 2-amino-2-methyl propane sulfonic acid, polyvinyl
alcohol,
sodium 2-acrylamido-2-methylpropane sulfonate,
quaternized
dimethylaminoethylacrylate, quaternized dimethylaminoethylmethacrylate, and
derivatives and combinations thereof. In certain embodiments, the gelling
agent
comprises an acrylamide/2-(methacryloyloxy)ethyltrimethylammonium methyl
sulfate copolymer. In certain embodiments, the gelling agent may comprise an
acrylamide/2-(methacryloyloxy)ethyltrimethylammonium chloride copolymer. In
certain embodiments, the gelling agent may comprise a derivatized cellulose
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that comprises cellulose grafted with an allyl or a vinyl monomer, such as
those disclosed in
U.S. Pat. Nos. 4,982,793, 5,067,565, and 5,122,549.
[0034] Additionally, polymers and copolymers that comprise one or more
functional
groups (e.g., hydroxyl, cis-hydroxyl, carboxylic acids, derivatives of
carboxylic acids, sulfate,
sulfonate, phosphate, phosphonate, amino, or amide groups) may be used as
gelling
agents.
[0035] The gelling agent may be present in the fracturing fluids useful in the
methods of the present invention in an amount sufficient to provide the
desired viscosity. In
some embodiments, the gelling agents (i.e., the polymeric material) may be
present in an
.. amount in the range of from about 0.1% to about 10% by weight of the
treatment fluid
. In certain embodiments, the gelling agents may be present in an amount in
the range of
from about 0.15% to about 2.5% by weight of the fracturing fluid.
[0036] In some embodiments, the present invention provides methods comprising:
providing a fracturing fluid comprising: an aqueous fluid, a microemulsion
surfactant, and a
co-surfactant, wherein the fracturing fluid is substantially free of an
organic solvent; and
placing the fracturing fluid into a subterranean formation at a rate
sufficient to create or
enhance at least one fracture in the subterranean formation.
[0037] In some embodiments, the present invention provides methods comprising:
providing a composition comprising: a microemulsion surfactant, wherein the
composition
is substantially free of an organic solvent; placing the composition into at
least a portion of a
fracture in a subterranean formation having a first permeability; and allowing
the
composition to remove a water block from the subterranean formation to
increase
permeability of the subterranean formation to a second permeability.
[0038] In some embodiments, the increase in permeability of the subterranean
.. formation correlates to a regain permeability of about 50% or greater. In
some preferred
embodiments, the increase in permeability of the subterranean formation
correlates to a
regain permeability of about 80% or greater.
[0039] 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 to define, the scope of the invention.
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EXAMPLE 1
[0040] Regain permeability tests were performed for various surfactants
using a 150pD Crab Orchard Sandstone core to simulate a tight gas formation.
Table 1 summarizes the composition of the surfactants including decyl amine
oxide (C10A0), cocoamidopropyl betaine (CFS-485), dodecyl amine oxide
(C12A0), microemulsion surfactant/solvent additive (commercially available as
GASPERM 1000TM from Halliburton Energy Services, Inc.), microemulsion
additive (commercially available as MA-844 from CESI Chemical), KCI brine, and
amphoteric surfactant. Some of the samples also include a cosurfactant
(pyrrolidin commercially available as SURFADONE from ISP Performance
Chemicals or butanol). The tests were performed according to the following
description.
Table 1
Surfactant Cosurfactant Ratio Regain
Permeability (0/0)
decyl amine oxide (C10A0) pyrrolidin ring 1:2 76
(Surfadone )
cocoamidopropyl betaine butanol 1:5 100
(CFS-485)
dodecyl amine oxide butanol 1:4 100
(Cl 2A0)
microemulsion 56
surfactant/solvent additive
(GasPerm1000 Tm)
microemulsion additive 40
(MA-844)
KCI brine 30
amphoteric 17.5
[0041] First, an initial permeability was measured by running nitrogen
through a dry core. The core sample was then saturated with 3 wt-% KCI brine
neat or with 0.2 volume-% of the additive in brine. Next, nitrogen gas was run
through the core to determine the regain permeability. Fig. 1 shows the
results
of the regain permeability tests.
[0042] As shown in Fig. 1, the core saturated in the KCI brine alone
suffered severe damage (-70% permeability) due to water blocks. Gas
permeability was greatly affected by capillary pressure and water spanning
13
CA 02860429 2016-09-21
across the throat of the pores, as is evidenced by the major loss in
permeability when
soaking the core is just brine. By adding a surfactant or surfactant/solvent
combination,
gas/water interfacial tension was reduced and the surfactant was able to water
wet the
pore throat surface. It is believed that the surfactants eliminated water
blocks, which lead to
.. higher gas production. Due to the low viscosity of air, achieving high
regain permeabilities
for gas flow in water- saturated cores was difficult.
[0043] Therefore, the present invention is well adapted to attain the ends and
advantages mentioned as well as those that are inherent therein. 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. Furthermore, no limitations
are intended to
the details of construction or design herein shown, other than as described in
the claims
below. It is therefore evident that the particular illustrative embodiments
disclosed above
may be altered, combined, or modified and all such variations are considered
within the
scope and spirit of the present invention. The invention illustratively
disclosed herein
suitably may be practiced in the absence of any element that is not
specifically disclosed
herein and/or any optional element disclosed herein. While compositions and
methods are
described in terms of "comprising," "containing," or "including" various
components or
steps, the compositions and methods can also "consist essentially of" or
"consist of" the
.. various components and steps. All numbers and ranges disclosed above may
vary by some
amount. Whenever a numerical range with a lower limit and an upper limit is
disclosed, any
number and any included range falling within the range is specifically
disclosed. In
particular, every range of values (of the form, "from about a to about b," or,
equivalently,
"from approximately a to b," or, equivalently, "from approximately a-b")
disclosed herein is
to be understood to set forth every number and range encompassed within the
broader
range of values. 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. If there is any conflict in the usages of a word
or term in this
specification and one or more patent or other documents that is referenced
herein, the
definitions that are consistent with this specification should be adopted.
14
