Note: Descriptions are shown in the official language in which they were submitted.
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VISCOELASTIC SURFACTANT FLUIDS AND ASSOCIATED
ACIDIZING METHODS
BACKGROUND
The present invention relates to methods and compositions for treating
subterranean
formations. More particularly, the present invention relates to treatment
fluids that comprise
a methyl ester sulfonate ("MES") surfactant, and associated acidizing methods.
The production of desirable fluids (e.g., oil and gas) from subterranean
formations
may often be enhanced by stimulating a region of the formation surrounding a
well bore.
Where the subterranean formation comprises acid-soluble components, such as
those present
in carbonate and sandstone formations, stimulation is often achieved by
contacting the
formation with a treatment fluid comprising an acid. These acid stimulation
treatments are
often referred to as "acidizing" the formation. For example, where
hydrochloric acid contacts
and reacts with calcium carbonate in a formation, the calcium carbonate is
consumed to
produce water, carbon dioxide, and calcium chloride. After acidization is
completed, the
water and salts dissolved therein may be recovered by producing them to the
surface, e.g.,
"flowing back" the well, leaving a desirable amount of voids (e.g., wormholes)
within the
formation, which enhance the formation's permeability and may increase the
rate at which
hydrocarbons subsequently may be produced from the formation. One method of
acidizing,
known as "fracture acidizing," comprises injecting a treatment fluid
comprising anacid into
the formation at a pressure sufficient to create or enhance one or more
fractures within the
subterranean formation. Another method of acidizing, known as "matrix
acidizing,"
comprises injecting the treatment fluid into the formation at a pressure below
that which
would create or enhance one or more fractures within the subterranean
formation.
To enhance acidizing treatments, various additives may be added to the
treatment
fluid. One such additive is a gelling agent which may, among other things,
increase viscosity
of the treatment fluid for improved diversion and particulate suspension,
increase penetration
into the reservoir by decreasing the reactivity of such fluid, reduce fluid
loss, and/or reduce
pumping requirements by reducing friction in the well bore. In some instances,
the acidizing
treatment may be self-diverting to further enhance the treatment. Among other
things, a self-
diverting acid treatment may effectively place the acid in a desired region
within the
subterranean formation, thereby creating a more optimal interaction of the
acid with the acid-
soluble components of the formation, which may create a desired network of
channels that
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may penetrate deeper into the formation than a conventional acid stimulation
treatment. One
such self-diverting treatment fluid includes a crosslinkable gelling agent, a
crosslinking
agent, and a pH buffer to provide a crosslink within a certain pH range. A
crosslinkable
gelling agent comprising crosslinkable polyacrylamide-based polymers has been
found to be
useful in calcium carbonate formations. In such a treatment, as the acid
reacts, the pH of the
self-diverting treatment fluid increases, which causes the fluid to viscosify
so as to form a gel
that, inter alia, temporarily plugs the perforations or natural fractures
accepting the most fluid
flow. When the remaining treatment fluid encounters the gel, it is diverted to
other portions
of the formation. This process then may be repeated - as the treatment fluid
is diverted, the
acid creates another conductive void, and the treatment fluid is viscosified,
diverts flow, and
so forth. Once the treatment is complete, the viscosified treatment fluid may
be "broken" by
reducing its viscosity to a more readily pumpable level, so that the full
productivity of the
well can be restored.
Despite the advantages of using gelling agents in acid treatments, such
treatments
may be problematic. For example, conventional polymeric gelling agents may
leave an
undesirable residue in the subterranean formation after use. As a result,
potentially-costly
remedial operations may be required to clean up the surfaces inside the
subterranean
formation. Foamed treatment fluids and emulsion-based treatment fluids have
been
employed to minimize residual damage, but increased expense and complexity
often result.
To combat these problems associated with polymeric gelling agents, some
surfactants
have been used as gelling agents. Certain surfactants, when mixed with an
aqueous fluid
having a certain ionic strength, are capable of forming a viscous fluid that
has certain elastic
properties, one of which may be shear thinning. Surfactant molecules (or ions)
at specific
conditions may form micelles (e.g., worm-shaped micelles, rod-shaped micelles,
etc.) in an
aqueous fluid. Depending on, among other things, the surfactant concentration,
and the ionic
strength of the fluid, etc., these nvicelles may impart increased viscosity to
the aqueous fluid,
such that the fluid exhibits viscoelastic behavior due, at least in part, to
the association of the
surfactant molecules contained therein.
Accordingly, these treatment fluids exhibiting viscoelastic behavior may be
used in a
variety of subterranean treatments where a viscosified treatment fluid may be
useful. For
instance, these surfactants may be used in place of conventional polymeric
gelling agents in
acidizing treatments. In some instances, as the acid reacts with the
formation, the reaction
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by-products and/or spending of the acid may provide the conditions necessary
for
viscosification of the treatment fluid so as to form a gel that, inter alia,
temporarily plugs the
perforations or natural fractures accepting the most fluid flow and diverts
the remaining
treatment fluid and/or another fluid to other regions of the formation.
Because the micelles
are sensitive to the pH and hydrocarbons, once viscosifled, the viscosity of
the treatment fluid
may be reduced after introduction into the subterranean formation without the
need for
conventional gel breakers (e.g., oxidizers). This should allow a substantial
portion of the
treatment fluid to be produced back from the formation without the need for
expensive
remedial treatments. However, surfactants used heretofore as gelling agents
tend to have
undesirable environmental characteristics (e.g., toxicity) and/or may be
limited by strict
environmental regulations in certain areas of the world.
SUMMARY
The present invention relates to methods and compositions for treating
subterranean
formations. More particularly, the present invention relates to treatment
fluids that comprise
a MES surfactant, and associated methods.
In one embodiment, the present invention provides a method of acidizing a
subterranean formation comprising: providing a treatment fluid comprising an
aqueous base
fluid, an acid, and a MES surfactant; introducing the treatment fluid into a
well bore that
penetrates the subterranean formation; and allowing at least a portion of the
treatment fluid to
react with at least a portion of the subterranean formation so that at least
one void is formed
in the subterranean formation.
In another embodiment, the present invention provides a method of acidizing a
subterranean formation comprising: providing a treatment fluid comprising an
aqueous base
fluid, an acid, and a MES surfactant; introducing the treatment fluid into a
well bore that
penetrates the subterranean formation; allowing a first portion of the
treatment fluid to react
with at least a first portion of the subterranean formation so that a void is
formed in the
subterranean formation and the first portion of the treatment fluid forms a
gel sufficient to
divert flow; and allowing the gel to at least partially divert a second
portion of the treatment
fluid and/or another fluid into a second portion of the subterranean
formation.
In another embodiment, the present invention provides a method of acidizing a
subterranean formation comprising: providing a treatment fluid comprising an
aqueous base
fluid, an acid, and a MES surfactant; introducing the treatment fluid into a
well bore that
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penetrates the subterranean formation at or above a pressure sufficient to
create or enhance
one or more fractures in at least a portion of the subterranean formation; and
allowing at least
a portion of the treatment fluid to react with at least a portion of the
subterranean formation
so that at least one void is formed in the subterranean formation.
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.
DRAWINGS
A more complete understanding of the present disclosure and advantages thereof
may
be acquired by referring to the following description taken in conjunction
with the
accompanying drawings, wherein:
Figure 1 is a plot of temperature versus viscosity as measured using a
nonscanning
shear rate procedure on a Fann Model 50 viscometer for sample fluids that
comprises a MES
surfactant and concentrations of sodium chloride.
Figure 2 is a plot of shear stress versus storage modulus, loss modulus, and
phase
angle as measured using a Haake Rheostress RS150 stress-controlled rheometer
for a sample
fluid that comprises a MES surfactant and sodium chloride.
Figure 3 is a plot of shear stress versus storage modulus, loss modulus, and
phase
angle as measured using a Haake Rheostress RS150 stress-controlled rheometer
for another
sample fluid that comprises a MES surfactant and sodium chloride.
While the present invention is susceptible to various modifications and
alternative
forms, specific exemplary embodiments thereof have been shown by way of
example in the
drawings and are herein described in detail. It should be understood, however,
that the
description herein of specific embodiments is not intended to limit or define
the invention to
the particular forms disclosed, but on the contrary, the intention is to cover
all modifications,
equivalents, and alternatives falling within the spirit and scope of the
invention as defmed by
the appended claims. The figures should in no way be used to limit the meaning
of the claim
terms.
DESCRIPTION OF PREFERRED EMBODIlVIENTS
The present invention relates to methods and compositions for treating
subterranean
formations. More particularly, the present invention relates to treatment
fluids that comprise
a MES surfactant, and associated acidizing methods.
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The treatment fluids of the present invention generally comprise an MES
surfactant
and an aqueous base fluid. In one embodiment the fluids also include an acid.
In some
instances, the treatment fluids of the present invention may exhibit
viscoelastic behavior
which may be due, at least in part, to the association of at least a portion
of the MES
surfactant into a plurality of micellar structures. The MES surfactants
suitable for use in the
present invention are described by the following formula:
0
R
OMe
.SQg
Formula I
where R is an alkyl chain of fxom about 10 carbon atoms to about 30 carbon
atoms. In
certain embodiments, R is an alkyl chain of from about 16 carbon atoms to
about 22 carbon
atoms. An example of a suitable MES surfactant of Formula I is a palm-oil
derivative
commercially available from Halliburton Energy Services, Inc., Duncan,
Oklahoma, under
the trade name EFSTM-4 surfactant. N1.ES surfactants are believed to be
relatively
environmentally benign, in most instances, because they are biodegradable in
most
environments. The MES surfactants of Formula I are a class of anion.ic
surfactants that have
been found to cause fluids to exhibit viscoelastic properties. It is believed
that, when the
MES surfactant is dissolved in an aqueous environrnent having a certain ionic
strength, the
MES surfactant molecules (or ions) may associate to form micelles because of
their
hydrophobic and hydrophilic regions. These micelles may function, among other
things, to
increase the viscosity of the fluid therein. These micelles may be rod-shaped,
worm-shaped,
or any of a variety of other shapes that will viscosify a fluid where present
in sufficient
concentrations. In certain embodiments, a sufficiently high concentration of
ions to facilitate
micelle formation may be maintained, inter alia, by the addition of a water-
soluble salt or the
interaction of the fluid andlor certain components contained therein with
other materials
resident in the subterranean formation that generate ions in the presence of
the fluid and/or its
components. In the presence of a sufficient amount of hydrocarbons or at a
certain ionic
strength, these micelles may become unstable, thereby disassociating or
forming a micellar
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structure that is not conducive to viscosifying a fluid. This disassociation
and/or modification
of the micellar structure leads to a reduction in viscosity for the treatment
fluid.
M is preferably a compound or element that will form a salt. More preferably,
M is
selected from Na, K, Mg, Ca, Li, Cs, NH4, aild a.mines such as
triethanolamine,
isopropylamine and allylamine
The MES surfactants should be present in an embodiment of a treatment fluid of
the
present invention in an amount sufficient to provide a desired viscosity
(e.g., sufficient
viscosity to divert flow, reduce fluid loss, etc.) through the formation of
the desired micelles.
In certain embodiments, the MES surfactants may be present in the treatment
fluids of the
present invention in an amount of from about 0.5% to about 15% by weight of
the fluid
("bwof'). In certain embodiments, the MES surfactants may be present in the
treatment
fluids of the present invention in an amount of from about 0.5% to about 5%
bwof. One of
ordinary skill in the art, with the benefit of this disclosure, will be able
to deterrnine the
appropriate amount of the MES surfactant to include in a treatment fluid of
the present
invention based on a number of factors, including the desired viscosity, the
ionic strength of
the fluid, and/or the amount and type of co-surfactant employed.
The aqueous base fluid used in the treatment fluids of the present invention
may
comprise fresh water, saltwater (e.g., water containing one or more salts
dissolved therein),
brine (e.g., saturated saltwater), seawater, or combinations thereof.
Generally, the water may
be from any source, provided that it does not contain components that might
adversely affect
the stability and/or performance of the treatment fluids of the present
invention.
The acid of the treatrnent fluids of the present invention may comprise
organic acids,
inorganic acids, derivatives thereof, or combinations thereof. An acid with an
extremely low
pH (e.g., concentrations of HCI greater than about 15%), however, may affect
the ability of
the treatment fluids of the present invention to form a gel. Examples of
suitable acids
include, but are not limited to, hydrochloric acid, hydrofluoric acid, formic
acid, phosphoric
acid, sulfamic acid, acetic acid, derivatives thereof, and mixtures thereof.
In certain
embodiments, the acid may be present in the treatment fluids in an amount of
from about
0.5% to about 20% bwof. In certain embodiments, the acid may be present in the
treatment
fluids of the present invention in an amount of from about 5% to about 15%
bwof.
Individuals skilled in the art, with the benefit of this disclosure, will be
able to select a
suitable acid and a suitable concentration thereof.
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To provide the ionic strength for the desired micelle formation, the treatment
fluids of
the present invention may optionally comprise a water-soluble salt. For
example, in some
embodiments, it may be desirable to include a water-soluble salt in the
treatment fluids of the
present invention. Adding a salt may promote micelle formation for the
viscosification of the
fluid. In another embodiment, the treatment fluids of the present invention
may contain no
salts so that micelle formation does not occur until a desired time, for
example, after the
treatment fluid is introduced into the well bore. In some embodiments, the
aqueous base
fluid may contain the water-soluble salt, for example, where saltwater, a
brine, or seawater is
used as the aqueous base fluid. Suitable water-soluble salts may comprise
ammonium,
lithium, sodium, potassiuin, cesium, magnesium, calcium, or zinc cations, and
chloride,
bromide, iodide, formate, nitrate, acetate, cyanate, or thiocynate. Examples
of suitable water-
soluble salts that comprise the above-listed anions and cations include, but
are not limited to,
ammonium chloride, lithium bromide, lithium chloride, lithium formate, lithium
nitrate,
calcium bromide, calcium chloride, calcium nitrate, calcium formate, sodium
bromide,
sodium chloride, sodium formate, sodium nitrate, potassium chloride, potassium
bromide,
potassium nitrate, potassium formate, cesium nitrate, cesium formate, cesium
chloride,
cesium bromide, magnesium chloride, magnesium bromide, zinc chloride, zinc
bromide, and
combinations thereof. In certain embodiments, the water-soluble salt may be
present in the
treatment fluids of the present invention in an amount in the range of from
about 1% to about
10% bwof. In certain other embodiments, the water-soluble salt may be present
in the
treatment fluids of the present invention in an arnount in the range of from
about 5% to about
10% bwof.
The treatment fluids of the present invention may optionally comprise a co-
surfactant,
among other things, to facilitate the formation of and/or stabilize the foam,
increase salt
tolerability, and/or stabilize the treatment fluid. The co-surfactant may
comprise any
surfactant suitable for use in subterranean environments that does not
adversely affect the
treatment fluid. Examples of suitable co-surfactants include betaines (e.g.,
cocobetaine,
cocoamidopropylbetaine), amine oxides, derivatives thereof, and combinations
thereof. One
of ordinary skill in the art, with the benefit of this disclosure, will be
able to determine which
co-surfactants are best suited to the particular embodiments and applications
of the
compositions and metllods described herein. For example, in some embodiments,
the
treatment fluids of the present invention may be foamed by injection of a gas
therein, wherein
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g
a co-surfactant (such as a cocobetaine) is included in the treatment fluids of
the present
invention to facilitate the formation of and/or stabilize the foam. In some
embodiments, the
co-surfactant may act to at least partially stabilize the treatment fluids.
Generally, the co-
surfactants may be present in the treatment fluids of the present invention in
an amount
sufficient to optimize the performance of the treatment fluid in a particular
application, as
determined by one of ordinary skill in the art. In one embodiment, for
example, where the
co-surfactant is included to increase salt tolerability or to stabilize the
treatment fluid, the co-
surfactant is present in a co-surfactant to MES surfactant weight ratio in the
range of from
about 1:3 to about 3:1.
The treatment fluids of the present invention may fur-ther comprise
particulates (such
as proppant particulates) suitable for use in subterranean applications.
Particulates suitable
for use in the present invention may comprise any material suitable for use in
subterranean
operations. Suitable particulate materials include, but are not limited to,
sand, bauxite,
ceramic materials, glass materials, polymer materials, Teflon inaterials, nut
shell pieces,
cured resinous particulates comprising nut shell, pieces seed shell pieces,
cured resinous
particulates comprising seed shell pieces, fruit pit pieces, cured resinous
particulates
comprising fruit pit pieces, wood, composite particulates, and combinations
thereof. Suitable
composite particulates may comprise a binder and a filler material wherein
suitable filler
materials include silica, altnnina, fumed carbon, carbon black, graphite,
mica, titanium
dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly
ash, hollow glass
microspheres, solid glass, and combinations thereof. The particulate size
generally may
generally range froin about 2 mesh to about 400 mesh on the U.S. Sieve Series;
however, in
certain circumstances, other sizes may be desired and will be entirely
suitable for practice of
the present invention. In particular embodiments, preferred particulates size
distribution
ranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60,
40/70, or 50/70
mesh. It should be understood that the term "particulate," as used in this
disclosure, includes
all known shapes of materials, including substantially spherical materials,
fibrous materials,
polygonal materials (suc11 as cubic materials), and mixtures thereof. In
certain embodiments,
the particulates included in the treatment fluids of the present invention may
be coated with
any suitable resin or tackifying agent known to those of ordinary skill in the
art that does not
adversely affect other components of the treatment fluid.
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The treatment fluids of the present invention may further comprise an additive
for
maintaining and/or adjusting pH (e.g., pH buffers, pH adjusting agents, etc.).
For example,
the additive for maintaining and/or adjusting pH may be included in the
treatment fluids,
among other things, to maintain the pH in, or adjust the pH to, a desired
range and thereby
maintain, or provide, the necessary ionic strength to form the desired
micellar structures. The
additive for maintaining and/or adjusting pH may also be included in the
treatment fluids to
prevent precipitation of by-products of the acidizing reaction. Examples of
suitable additives
for maintaining and/or adjusting pH include, but are not limited to, sodium
acetate, acetic
acid, sodium or potassium diacetate, sodium or potassium phosphate, sodiuwn or
potassium
hydrogen phosphate, sodium or potassium dihydrogen phosphate, combinations
thereof,
derivatives thereof, and the like. The additive for adjusting and/or
maintaining pH may be
present in the treatment fluids of the present invention in an amount
sufficient to maintain
and/or adjust the pH of the fluid. One of ordinary skill in the art, with the
benefit of this
disclosure, will recognize the appropriate additive for maintaining and/or
adjusting pH and
amount thereof to use for a chosen application.
The treatment fluids of the present invention may optionally comprise
additional
additives, including, but not limited to, corrosion inhibitors, scale
inhibitors, fluid loss control
additives, gas, emulsifiers, paraffin inhibitors, asphaltene inhibitors,
catalysts, hydrate
inliibitors, iron control agents, clay control agents, biocides, friction
reducers, combinations
thereof and the like. For example, in some einbodiments, it may be desired to
foam a
treatment fluids of the present invention using a gas, such as air, nitrogen,
or carbon dioxide.
Individuals skilled in the art, with the benefit of this disclosure, will
recogiiize the types of
additives that may be necessary for inclusion in the treatment fluids of the
present invention
for a particular application.
The treatment fluids of the present invention may be prepared by any suitable
method.
In some embodiments, the treatment fluids may be prepared on the job site. As
an example
of such an on-site method, a MES surfactant may be combined with an aqueous
base fluid
and an acid. In one certain embodiment, a salt or an additive for maintaining
and/or adjustiilg
pH may be combined with the aqueous base fluid, among other things, to adjust
the pH, or
maintain the pH, in a desired range to promote the desired micelle formation,
such that the
treatment fluid exhibits viscoelastic behavior. The additive for maintaining
and/or adjusting
pH may be combined with the aqueous base fluid either prior to, after, or
simultaneously with
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the MES surfactant. Furthermore, additional additives, as discussed above, may
be combined
with the treatment fluid and/or the aqueous base fluid as desired. For
example, a particulate
additive (e.g., a particulate scale inhibitor) or particulates (e.g., gravel
particulates or
proppant particulates) may be suspended in the treatment fluid. In some
embodiments, to
facilitate mixing with the aqueous base fluid, the MES surfactant may be
combined with a
surfactant solubilizer prior to its combination with the other components of
the treatment
fluid. The surfactant solubilizer may be any suitable surfactant solubilizer,
such as water,
simple alcohols, glycols, and combinations thereof. For example, in some
embodiments, the
MES surfactant may be provided in a mixture that comprises the surfactant
solubilizer and
the MES surfactant. One or ordinary skill in the art, with the benefit of this
disclosure, will
be able to determine other suitable methods for preparation of the treatinent
fluids of the
present invention.
As previously discussed, 'at certain conditions, the surfactant molecules
present in the
treatment fluids may associate to form the desired micelles, which, depending
on a number of
factors (e.g., MES suxfactant concentration), may viscosify the treatment
fluid. The micelles
present in the treatment fluids of the present invention are generally
sensitive to, among other
things, the ionic strength of the treatment fluid, hydrocarbons, and shear
stress. Further, they
also may be sensitive to temperature. Accordingly, tliese treatinent fluids
containing the
desired micelles may experience a viscosity decline after introduction into
the well bore
and/or penetration into the subterranean forination, without the need for
external gel brealcers.
As previously discussed, this viscosity reduction is generally due to the
dissociation and/or
modification of the micellar structure. For example, in hydrocarbon-containing
portions of
the subterranean formation, the viscosity of the treatment fluids of the
present invention may
be reduced by contact with the hydrocarbons contained therein. Likewise, in
certain portions
of the subterranean formation (e.g., carbonate formations), the treatment
fluids of the present
invention may experience a pH change, thereby facilitating a cha.nge in the
ionic strength of
the fluids. In certain embodiments, dilution of the treatment fluid may also
facilitate a
reduction in viscosity of the treatment fluid. For example, a treatment fluid
of the present
invention may be diluted by contact with formation fluids and/or subsequently
injected
treatment fluids, thereby reducing the concentration of the desired micelles
in the treatment
fluid and/or changing the ionic strength of the treatment fluid.
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In certain embodiments, the treatment fluids of the present invention may be
used in
acidizing treatments, in which a treatment fluid comprising an aqueous base
fluid, an acid,
and a MES surfactant may be provided, introduced into a well bore that
penetrates a
subterranean formation, and allowed to react wit11 at least a portion of the
subterranean
foi7mation so that at least one void is formed in the subterranean formation.
In certain
acidizing embodiments, the treatment fluid may be introduced into the well
bore at or above a
pressure sufficient to create or enhance one or more fractures in at least a
portion of the
subterranean formation. Optionally, the treatment fluid may comprise other
additives
suitable for the acidizing treatment. In certain acidizing embodiments, the
treatment fluid
further may contain a salt, or an additive for maintaining and/or adjusting
pH, so that the
treatment fluid has the necessary ionic strength to provide a desired
viscosity prior to
introduction into the subterranean formation. In some embodiments, the
treatment fluid may
be allowed to viscosify prior to, after, or simultaneously with the step of
introducing the
treatment fluid into the well bore. As previously discussed, the treatment
fluid generally may
experience a reduction in viscosity after introduction into the subterranean
formation. After a
chosen time, the treatment fluid may be recovered through the well bore.
In certain embodiments, a treatment fluid comprising an aqueous base fluid, an
acid,
and a MES surfactant may be employed as, among other things, a self-diverting
acid.
Optionally, the treatment fluid may comprise other additives suitable for the
acidizing
treatment. In some self-diverting embodiments, the treatment fluid may be
formulated so that
its viscosity is initially very low (e.g., less than about 20 cP at 511 s"1).
For example, prior to
its introduction into the subterranean formation, it may be desired for the
treatment fluid to
have a viscosity sufficient to provide fluid loss control and/or to reduce
friction created by the
flow of treatment fluids in the subterranean formation. One of ordinary skill
in the art, with
the benefit of this disclosure, will recognize the optimal initial viscosity
for the treatment
fluid in a specific application.
In these self-diverting embodiments, the treatment fluid may be introduced
into a well
bore that penetrates the subterranean formation and allowed to react with the
subterranean
formation. As the treatment fluid reacts with the subterranean formation, the
presence of
reaction by-products and/or spending of the acid may, inter alia, provide the
conditions
necessary for the viscosification of the treatment fluid into a gel sufficient
to divert flow. The
viscosity of the gel necessary to divert flow may depend on, among other
factors, the depth of
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the gel plug created, the size of the wormhole to be plugged, the strength of
the acid used, the
composition of the treatment fluid to be diverted, the temperature of the
subterranean
formation, and the differential pressure. One of ordinary skill, with the
benefit of this
disclosure, will recognize the appropriate viscosity sufficient to divert flow
for a particular
application. The gel may divert subsequently injected fluids to other portions
of the
subterranean formation. Because the treatment fluid generally will first enter
perforations or
natural fractures accepting the most fluid (e.g., portions of the subterranean
formation with
higher permeabilities), other portions of this treatment fluid and/or other
fluids (e.g.,
acidizing treatinent fluids) subsequently introduced into the well bore may be
diverted to less
permeable portions of the subterranean formation. For example, a treatinent
fluid may be
provided and introduced into a well bore that penetrates a subterranean
formation, and a first
portion of the treatment fluid may be allowed to react with at least a first
portion of the
subterranean formation so that (1) at least one void is formed in the first
portion of the
subterranean formation and (2) the first portion of the treatment forms a gel
sufficient to
divert flow. In such embodiments, the gel may be allowed to at least partially
divert a second
portion of the treatment fluid and/or another fluid into a second portion of
the subterranean
for7nation.
The gelling and diversion optionally may be repeated as additional amounts of
the
treatment fluid are introduced into the well bore. For example, the second
portion of the
treatment fluid may be allowed to react with at least the second portion of
the subterranean
formation so that (1) at least one void is formed in the second portion of the
subterranean
formation and (2) the second portion of the treatment fluid forms a gel
sufficient to divert
flow. After a chosen time, the treatment fluid may be recovered through the
well bore.
To facilitate a better understanding of the present invention, the following
examples
of preferred embodiments are given. In no way should the following examples be
read to
limit or define the entire scope of the invention.
EXAMPLES
EXAMPLE 1
To determine the viscosification of a treatment fluid using a MES surfactant,
laboratory samples were prepared by mixing a MES surfactant (EFSTM-4
surfactant) with an
aqueous base fluid. The aqueous base fluid used was tap water unless otherwise
indicated.
In certain samples, a salt was included in the aqueous base fluid. Where
included, the
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concentration and type of salt included in the aqueous base fluid were varied.
Once prepared,
each sample was observed to determine gel formation. For purposes of this
example, a
sample was considered gelled if it had a viscosity of greater than about 20
centipoise at 511
sec"1. The compositions of each sample and observations thereof are listed in
Table 1.
TABLE 1
Sample No. MES Aqueous Base Fluid Result
Concentrationl
(by weight)
1 5% Water Not gelled
2 5% Seawater Gelled
3 5% 5% KCI by wt Gelled
4 5% 5% NaCI by wt Gelled
5% 10% NaCI by wt Gelled
6 5% 5% CaC12 by wt Gelled
7 5% 10% CaC12 by wt Gelled
8 5% 5% NaCI by wt Gelled
5% CaC12 by wt
9 5% 10% NaCI by wt Gelled
10% CaC12 by wt
5% 5% NH4C1 by wt Gelled
11 5% 10% NH4C1 by wt Gelled
Sixnilar results were obtained for each sample when 10% by weight of the
MES surfactant was used.
Additionally, further samples were prepared, wherein a sufficient amount of
sodium
hydroxide was included in the aqueous base fluid so that the pH of the sample
was above 7,
i.e., the sample was basified. In certain samples, a salt was included in the
aqueous base
fluid. Where included, the concentration and type of salt included in the
aqueous base fluid
were varied. Once prepared, each sample was observed to determine the gel
formation. The
compositions of each sample and observations thereof are listed in Table 2.
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T,ABLE 2
Sample No. MES Aqueous Base Fluid Result
Concentration? (basified with NaOH
by wei ht to pH 10)
12 5% 5% NaCt by wt Gelled
13 5% 10% NaCl by wt Gelled
5%KCl b wt
14 5% 5% CaC12 b wt Gelled
15 5% 10% CaCl2 b wt Gelled
16 5% 5% NaCI by wt Gelled
lo CaCl2 b wt
17 5% 10% NaCl by wt Gelled
lo CaC12 b wt
18 5% seawater Gelled
19 5% 5% NH4C1 by wt Gelled
zSiinilar results were obtained for each sample when 10% by weight of the
MES surfactant was used.
Additionally, further samples were prepared, wherein a sufficient amount of
hydrochloric acid was included in the aqueous base fluid so that the pH of the
sample was
below 7, i.e., the sample was acidified. In certain samples, a salt was
included in the aqueous
base fluid. Where included, the concentration and type of salt included in the
aqueous base
fluid were varied. Once prepared, each sample was observed to determine the
gel formation.
The compositions of each sample and observations thereof are listed in Table
3.
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TABLE 3
Sample No. MES Aqueous Base Fluid Result
Concentration3 (acidified with HCl
b wei ht to pH 4)
5% 5% NaCI by wt Gelled
21 5% 10% NaCI by wt Gelled
5% IfCl b wt
22 5% 5% CaCl2 by wt Gelled
23 5% 10% CaC12 b wt Gelled
24 5% 5%NaClbywt Gelled
5%CaCl2b wt
5% 10% NaCI by wt Gelled
10% CaC12 by wt
26 5% seawater Gelled
27 5% 5% NII4C1 by wt Gelled
Similar results were obtained for each sample when 10% by weight of the
MES surfactant was used.
Additionally, further samples were prepared wherein the aqueous base fluid
contained
15% hydrochloric acid by weight of the aqueous base fluid. In cextain samples,
a salt was
included in the aqueous base fluid. Where included, the concentration and type
of salt
included in the aqueous base fluid were varied. Once prepared, each sample was
observed to
determine the gel formation. The compositions of each sample and observations
thereof are
listed in Table 4.
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TABLE 4
Sample No. MES Aqueous Base Fluid Result
Concentration~
b wei ht
28 5% 15% HCl Not gelled
29 5% 15% HCI Not gelled
5% NaCl b wt
30 5% 15% HCl Not gelled
5%KCIb wt
31 5% 15% HCl Not gelled
5%CaCl2bywt
32 5% 15% HC1 Not gelled
5% NHq.CI b wt
Simi.lar results were obtained for each sample when 10% by weight of the
MES surfactant was used.
Additionally, further samples were prepared wherein the aqueous base fluid
contained
10% hydrochloric acid by weight of the aqueous base fluid, In certain samples,
a salt was
included in the aqueous base fluid. Where included, the concentration and type
of salt
included in the aqueous base fluid were varied. Once prepared, each sample was
observed to
determine the gel formation. The compositions of each sample and observations
thereof are
listed in Table 5.
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TABLE 5
Sample No. MES Aqueous Base Fluid Result
Concentration
(by weight
33 5% 10% HCl Gelled
34 5% 10% HCI Gelled
5% NaCl b wt
35 5% 10% HCI Gelled
5%KCIb wt
36 5% 10% HCl Gelled
5% CaC12 by wt
37 5% 10% HCl Gelled
5% NH4C1 b wt
Additionally, further samples were prepared, wherein a sufficient amount of
sodium
hydroxide was included in the aqueous base fluid so that the pH of the sample
was above 7,
i.e., the sample was basified. In certain samples, a salt was included in the
aqueous base
fluid. Where included, the concentration and type of salt included in the
aqueous base fluid
were varied. Once prepared, each sample was observed to determine the gel
formation. The
compositions of each sample and observations thereof are listed in Table 6.
TABLE 6
Sample No. MES Aqueous Base Fluid Result
Concentration (basified with
b wei ht NaOH to pH 10)
38 5% 5% CaC12 by wt Gelled
39 5% 5% M 12 by wt Gelled
40 5% 5% CaC12 by wt Gelled
f'o M C12 by wt
Additionally, further samples were prepared, wherein a sufficient amount of
hydrochloric acid was included in the aqueous base fluid so that the pH of the
sample was
below 7, i.e., the sample was acidified. In certain samples, a salt was
included in the aqueous
base fluid. Where included, the concentration and type of salt included in the
aqueous base
fluid were varied. Once prepared, each sample was observed to determine the
gel formation.
The compositions of each sample and observations thereof are listed in Table
7.
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TABLE'7
Sample No. NIES Aqueous Base Fluid Result
Concentration (acidified with HCl
b weight) to pH 4)
41 5% 5% CaCl2 b wt Gelled
42 5% 5% M C12 by wt Gelled
43 5% 5% CaCl2 by wt Gelled
5% M 12 b wt
Thus, Example I indicates that a MES surfactant may be used to viscosify a
fluid.
EXAMPLE 2
Rheological tests were performed on laboratory samples that were prepared as
follows. Samples were prepared by mixing water with the following components:
an MES
surfactant in an amount of about 1.5% by weight of the sample; a cocobetaine
in an amount
of about 1.5% by weight of the sample; and various concentrations of sodium
chloride (3.5%,
4.0%, 4.5%, 6.0%, and 7.0%). The MES surfactant included in the samples was an
alpha-
sulfo fatty acid methyl ester that is commercially available as ALPHA-STEP
XNA.'-66 from
Stepan Company, Northfield, Jllinois. Further, the cocobetaine used in the
samples is
commercially available as W itco Rewoteric AM B-130.
Once prepared, the samples were each placed in the Rl rotor cup of a Fann
Model 50
viscometer to determine the viscosities of the sample, utilizing a nonscanning
shear rate
procedure. The rotor cups containing the samples were set in motion at a
constant rate of
about 95 rpm providing a shear rate of about 82 sec 1 on the sample. The
sample was brought
up to about 230 F as the viscosities of the samples were measured. A plot of
temperature
( F) versus viscosity (cP) for each sample is provided in Figure 1. Table 8
identifies the
maximum viscosities and corresponding temperatures for each sample.
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TABLE 8
NaCl Concentration Max Viscosity Temperature
(by wei ht cP F
3.5% 73 133
4.0% 88 132
4.5% 97 132
6.0% 98 142
7.0% 92 141
Thus, Example 2 illustrates that a MES surfactant may be used to viscosify a
fluid.
EXAMPLE3
Rheological tests were performed on laboratory samples that were prepared as
follows. Two samples were prepared by mixing water with the following
components: an
MES surfactant in an amount of about 5% by weight of the sample with about 5%
sodium
chloride. Sample A was used without adjusting the pH. The pH of Sample B was
adjusted
with NaOH to about 10. The MES surfactant included in the samples was an alpha-
sulfo
fatty acid methyl ester that is commercially available as EFSTM-4 Surfactant
from Halliburton
Energy Services, Inc., Duncan, Oklahoma.
Once the samples were prepared, the rheology was determined using a Haake
RheoStress RS 150 stress-controlled rheometer fitted with a 60 mm diameter, 2
cone and
plate. The temperature was held constant at 25 C. A constant frequency (1 Hz)
oscillatory
stress sweep was performed over the stress range indicated to obtain the
storage modulus
(G'), loss modulus (G"), and phase angle (5). Results are shown in Figures 2
and 3 for
Samples A and B, respectively.
Thus, Example 3 illustrates that a MES surfactant may be used to viscosify a
fluid.
Therefore, the present invention is well adapted to carry out the objects and
attain the
ends and advantages mentioned as well as those which are inherent therein.
While numerous
changes may be made by those skilled in the art, such changes are encompassed
within the
spirit of this invention as defined by the appended claims. The terms used in
the claims have
their plain, ordinary meaning unless otherwise defined by the patentee.
