U.S. patent application number 13/413811 was filed with the patent office on 2013-09-12 for surfactant additives for stimulating subterranean formation during fracturing operations.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Per-Bjarte Tanche-Larsen, Ryan van Zanten. Invention is credited to Per-Bjarte Tanche-Larsen, Ryan van Zanten.
Application Number | 20130233559 13/413811 |
Document ID | / |
Family ID | 47755069 |
Filed Date | 2013-09-12 |
United States Patent
Application |
20130233559 |
Kind Code |
A1 |
van Zanten; Ryan ; et
al. |
September 12, 2013 |
Surfactant Additives for Stimulating Subterranean Formation During
Fracturing Operations
Abstract
The present invention relates to surfactant additives useful for
restoring permeability of a subterranean formation and methods of
use thereof. One embodiment of the present invention provides a
method that includes providing a fracturing fluid having 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.
Inventors: |
van Zanten; Ryan; (Tomball,
TX) ; Tanche-Larsen; Per-Bjarte; (Sandnes,
NO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
van Zanten; Ryan
Tanche-Larsen; Per-Bjarte |
Tomball
Sandnes |
TX |
US
NO |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
47755069 |
Appl. No.: |
13/413811 |
Filed: |
March 7, 2012 |
Current U.S.
Class: |
166/308.1 |
Current CPC
Class: |
C09K 8/602 20130101;
C09K 8/86 20130101; C09K 8/604 20130101; C09K 8/68 20130101 |
Class at
Publication: |
166/308.1 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A method 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.
2. The method of claim 1, wherein the fracturing fluid further
comprises at least one additive selected from the group consisting
of: an acid, a biocide, a breaker, a clay stabilizer, a corrosion
inhibitor, a friction reducer, a gelling agent, a crosslinking
agent, an iron control agent, a scale inhibitor, a surfactant, a
proppant, and any combination thereof.
3. The method of claim 1, wherein the microemulsion surfactant is
selected from the group consisting of: polymeric surfactant, block
copolymer surfactant, di-block polymer surfactant, hydrophobically
modified surfactant, fluoro-surfactant, non-ionic surfactant,
anionic surfactant, cationic surfactant, zwitterionic surfactant,
and any combination thereof.
4. The method of claim 1, wherein the aqueous fluid comprises at
least one component selected from the group consisting of: fresh
water, salt water, glycol, brine, weighted brine, and any
combination thereof.
5. The method of claim 1, wherein the microemulsion surfactant is
present in the fracturing fluid in an amount from about 0.01% to
about 20% by weight of the fracturing fluid.
6. The method of claim 1 further comprising a co-surfactant.
7. The method of claim 6, wherein the co-surfactant is selected
from the group consisting of: an alcohol, a glycol, a phenol, a
thiol, a carboxylate, a ketone, an acrylamide, a sulfonate, a
pyrollidone, any derivative thereof, and any combination
thereof.
8. The method of claim 1, wherein the microemulsion surfactant is
selected from the group consisting of: an arginine methyl ester, an
alkanolamine, an alkylenediamide, an alkyl ester sulfonate, an
alkyl ether sulfonate, an alkyl ether sulfate, an alkali metal
alkyl sulfate, an alkyl or an alkylaryl sulfonate, a
sulfosuccinate, an alkyl or alkylaryl disulfonate, an alkyl
disulfate, an alcohol polypropoxylated and/or polyethoxylated
sulfate, a taurate, an amine oxide, an ethoxylated amide, an
alkoxylated fatty acid, an alkoxylated alcohol, an ethoxylated
fatty amine, an ethoxylated alkyl amine, a betaine, a modified
betaine, an alkylamidobetaine, a quaternary ammonium compound, any
derivative thereof, and any combination thereof.
9. A method 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.
10. The method of claim 8, wherein the microemulsion surfactant is
selected from the group consisting of: an arginine methyl ester, an
alkanolamine, an alkylenediamide, an alkyl ester sulfonate, an
alkyl ether sulfonate, an alkyl ether sulfate, an alkali metal
alkyl sulfate, an alkyl or an alkylaryl sulfonate, a
sulfosuccinate, an alkyl or alkylaryl disulfonate, an alkyl
disulfate, an alcohol polypropoxylated and/or polyethoxylated
sulfate, a taurate, an amine oxide, an ethoxylated amide, an
alkoxylated fatty acid, an alkoxylated alcohol, an ethoxylated
fatty amine, an ethoxylated alkyl amine, a betaine, a modified
betaine, an alkylamidobetaine, a quaternary ammonium compound, any
derivative thereof, and any combination thereof.
11. The method of claim 8, wherein the co-surfactant is selected
from the group consisting of: an alcohol, a glycol, a phenol, a
thiol, a carboxylate, a ketone, an acrylamide, a sulfonate, a
pyrollidone, any derivative thereof, and any combination
thereof.
12. The method of claim 8, wherein the fracturing fluid further
comprises an additive selected from the group consisting of: an
acid, a biocide, a breaker, a clay stabilizer, a corrosion
inhibitor, a friction reducer, a gelling agent, a crosslinking
agent, an iron control agent, a scale inhibitor, a surfactant, a
proppant, and any combination thereof.
13. The method of claim 8, wherein the microemulsion surfactant is
present in the fracturing fluid in an amount from about 0.01% to
about 20% by weight of the fracturing fluid.
14. The method of claim 8, wherein the co-surfactant is present in
the fracturing fluid in an amount from about 0.001% to about 20% by
weight of the fracturing fluid.
15. A method 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.
16. The method of claim 15, wherein the microemulsion surfactant is
selected from the group consisting of: an arginine methyl ester, an
alkanolamine, an alkylenediamide, an alkyl ester sulfonate, an
alkyl ether sulfonate, an alkyl ether sulfate, an alkali metal
alkyl sulfate, an alkyl or an alkylaryl sulfonate, a
sulfosuccinate, an alkyl or alkylaryl disulfonate, an alkyl
disulfate, an alcohol polypropoxylated and/or polyethoxylated
sulfate, a taurate, an amine oxide, an ethoxylated amide, an
alkoxylated fatty acid, an alkoxylated alcohol, an ethoxylated
fatty amine, an ethoxylated alkyl amine, a betaine, a modified
betaine, an alkylamidobetaine, a quaternary ammonium compound, any
derivative thereof, and any combination thereof.
17. The method of claim 15, wherein the increase in permeability of
the subterranean formation correlates to a regain permeability of
about 50% or greater.
18. The method of claim 15, wherein the increase in permeability of
the subterranean formation correlates to a regain permeability of
about 80% or greater.
19. The method of claim 15, wherein the composition further
comprises a co-surfactant.
20. The method of claim 15, wherein the microemulsion surfactant
forms a microemulsion within the subterranean formation.
Description
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
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.
[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 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 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 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, diamine 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 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 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,
polyhydroxybutyrate-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(.epsilon.-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 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.RTM., such as
BRIJ.RTM.-30 (comprises polyethylene glycol dodecyl ether),
BRIJ.RTM.-35 (comprises polyoxyethyleneglycol dodecyl ether),
BRIJ.RTM.-58 (comprises polyethylene glycol hexadecyl ether),
BRIJ.RTM.-97 (comprises polyoxyethylene (10) oleyl ether),
BRIJ.RTM.-98 (comprises polyoxyethylene (20) oleyl ether), and
BRIJ.RTM.-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.RTM..
[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 contain 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-dimethyl-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-sulfopropyl)-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 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, the entire disclosures of
which are incorporated herein by reference.
[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.
Example 1
[0040] Regain permeability tests were performed for various
surfactants using a 150 .mu.D Crab Orchard Sandstone core to
simulate a tight gas formation. Table 1 summarizes the composition
of the surfactants including decyl amine oxide (C10AO),
cocoamidopropyl betaine (CFS-485), dodecyl amine oxide (C12AO),
microemulsion surfactant/solvent additive (commercially available
as GASPERM 1000.TM. from Halliburton Energy Services, Inc.),
microemulsion additive (commercially available as MA-844 from CESI
Chemical), KCl brine, and amphoteric surfactant. Some of the
samples also include a cosurfactant (pyrrolidin commercially
available as SURFADONE.RTM. from ISP Performance Chemicals or
butanol). The tests were performed according to the following
description.
TABLE-US-00001 TABLE 1 Regain Perme- Surfactant Cosurfactant Ratio
ability (%) decyl amine oxide (C10AO) pyrrolidin ring 1:2 76
(Surfadone .RTM.) cocoamidopropyl betaine (CFS-485) butanol 1:5 100
dodecyl amine oxide (C12AO) butanol 1:4 100 microemulsion
surfactant/solvent 56 additive (GasPerm1000 .TM.) microemulsion
additive (MA-844) 40 KCl 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-% KCl 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 KCl brine
alone suffered severe damage (.about.70% permeability) due to water
blocks. Gas permeability was greatly affected by capillary pressure
and water spanning 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 may be incorporated
herein by reference, the definitions that are consistent with this
specification should be adopted.
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