Note: Descriptions are shown in the official language in which they were submitted.
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CROSSLINKED ACIDS COMPRISING DERIVATIZED XANTHAN AND
SUBTERRANEAN ACIDIZING APPLICATIONS
BACKGROUND
[0001] The present invention relates to methods of acidizing subterranean
formations or well bores, and more specifically, to acidizing fluids involving
in-situ
crosslinked spent acids and crosslinked live acids comprising derivatized
xanthan for
subterranean acidizing applications. These acidizing fluids may be used in any
suitable
acidizing treatment to acidize a portion of a subterranean formation or any
damage contained
therein. The term "damage" as used herein refers to undesirable deposits in a
subterranean
formation that may reduce its permeability. Scale, skin, and hydrates are
contemplated by
this term. Also contemplated by this term are geological deposits, such as but
not limited to,
carbonates located on the pore throats of the sandstone in a subterranean
formation.
[0002] Acidizing and fracturing treatments using aqueous acidic solutions
commonly are carried out in subterranean formations (including those that
contain
hydrocarbons as well as those that do not) penetrated by well bores to
accomplish a number
of purposes, one of which is to increase the permeability of the formation.
The resultant
increase in formation permeability normally results in an increase in the
recovery of
hydrocarbons from the formation.
[0003] Acidizing techniques can be carried out as "matrix acidizing"
procedures or as "acid fracturing" procedures. Generally, in acidizing
treatments, aqueous
acidic solutions are introduced into a subterranean formation under pressure
so that the acidic
solution flows into the pore spaces of the formation to remove near-well
formation damage
and other damaging substances. The acidic solution reacts with acid-soluble
materials
contained in the formation which results in an increase in the size of the
pore spaces and an
increase in the permeability of the formation. This procedure commonly
enhances
production by increasing the effective well radius. When performed at
pressures above the
pressure required to fracture the formation, the procedure is often referred
to as acid
fracturing. Fracture-acidizing involves the formation of one or more fractures
in the
formation and the introduction of an aqueous acidizing fluid into the
fractures to etch the
fractures' faces whereby flow channels are formed when the fractures close.
The aqueous
acidizing fluid also enlarges the pore spaces in the fracture faces and in the
formation. In
fracture-acidizing treatments, one or more fractures are produced in the
formation and the
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acidic solution is introduced into the fracture to etch flow channels in the
fracture face. The
acid also enlarges the pore spaces in the fracture face and in the formation.
The use of the
term "acidizing" herein refers to both types of acidizing treatments, and more
specifically,
refers to the general process of introducing an acid down hole to perform a
desired function,
e.g., to acidize a portion of a subterranean formation or any damage contained
therein.
[0004] Although acidizing a portion of a subterranean formation can be very
beneficial in terms of -permeability, conventional acidizing fluids can have
significant
drawbacks. One major problem associated with conventional acidizing treatment
fluids is
that deeper penetration into the formation is not usually achievable because,
inter alia, the
acid may be spent before it can deeply penetrate into the subterranean
formation. The rate at
which acidizing fluids react with reactive materials in the subterranean
formation is a
function of various factors including, but not limited to, acid concentration,
temperature, fluid
velocity, mass transfer, and the type of reactive material encountered.
Whatever the rate of
reaction of the acidic solution, the solution can be introduced into the
formation only a certain
distance before it becomes spent. For instance, conventional acidizing fluids,
such as those
that contain organic acids, hydrochloric acid or a mixture of hydrofluoric and
hydrochloric
acids, have high acid strength and quickly react with the formation itself,
fines and damage
nearest the well bore, and do not penetrate the formation to a desirable
degree before
becoming spent. To achieve optimal results, it is desirable to maintain the
acidic solution in a
reactive condition for as long a period of time as possible to maximize the
degree of
penetration so that the permeability enhancement produced by the acidic
solution may be
increased.
[0005] Another problem associated with some current acidizing fluids for
subterranean formations is that synthetic polymers or surfactants are utilized
to gel acidizing
fluids. For instance, to obtain a delayed gel, only a few surfactant gels and
polymer fluids
will work. Moreover, generally, it is desirable in acidizing for the synthetic
polymer to
crosslink upon spending so that it may divert the unspent acid into a new
portion of the
formation. Thus, synthetic polymers are usually the preferred choice for such
applications
due to the wide range of temperatures at which they function and their ability
to tolerate
many additives. Note, though, some viscoelastic surfactants are another
choice, but may
suffer from compatibility issues with additives. Natural biopolymers are
thought to be poor
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choices for crosslinked gel acidizing applications due to the relatively low
temperatures they
were believed to function at and their relatively poor cross linking ability.
[0006] Despite the advantages of using gelling agents in acid treatments,
using
such gelling agents 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.
[0007] Biopolymers such as xanthan would be more desirable to use due to
their degradability characteristics. Early experimentation, however, with
xanthan yielded less
than satisfactory gels. These gels tended to break or undergo syneresis
easily, and often
looked curdled with a cottage cheese-like consistency. Crosslinking xanthan
can be
especially difficult and/or impractical because the resultant crosslinked
structure has been
thought to be unusable and can have strange rheological properties.
SUMMARY
[0008] The present invention relates to methods of acidizing subterranean
formations or well bores, and more specifically, to acidizing fluids involving
in-situ
crosslinked spent acids and crosslinked live acids comprising derivatized
xanthan for
subterranean acidizing applications. These acidizing fluids may be used in any
suitable
acidizing treatment to acidize a portion of a subterranean formation or any
damage contained
therein.
[0009] In one embodiment, the present invention provides a method
comprising: providing a fluid that comprises an acid, crosslinked oxidized
xanthan, and
optionally, a base fluid; placing the fluid in a well bore penetrating a
subterranean formation;
and allowing the fluid to acidize at least a portion of the formation or
damage contained
therein.
[0010] In one embodiment, the present invention provides a method
comprising: providing a fluid that comprises an acid, crosslinked oxidized
xanthan, and
optionally, a base fluid; and placing the fluid in a well bore penetrating a
subterranean
formation at a pressure sufficient to create or enhance a fracture in the
subterranean
formation.
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[0011] In one embodiment, the present invention provides a method
comprising: providing a fluid that comprises an acid, crosslinked oxidized
xanthan, and
optionally, a base fluid; placing the fluid into a subterranean formation;
allowing the fluid to
contact scale in the well bore or near well bore region; and allowing the acid
to react with the
scale.
[0012] In one embodiment, the present invention provides a method
comprising: providing a fluid that comprises an acid, oxidized xanthan, and
optionally, a base
fluid; placing the fluid in a well bore penetrating a subterranean formation;
and allowing the
fluid to acidize at least a portion of the formation or damage contained
therein.
[0013] In one embodiment, the present invention provides a fluid for
subterranean uses comprising crosslinked, oxidized xanthan.
[0014J In one embodiment, the present invention provides a fluid for
subterranean uses comprising oxidized xanthan.
[0015] In one embodiment, the present invention provides a composition
comprising oxidized, crosslinked xanthan.
[0016] The features and advantages of the present invention will be readily
apparent to those skilled in the art.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0017] The present invention relates to methods of acidizing subterranean
formations or well bores, and more specifically, to acidizing fluids involving
in-situ
crosslinked spent acids and crosslinked live acids comprising derivatized
xanthan for
subterranean acidizing applications. These acidizing fluids may be used in any
suitable
acidizing treatment to acidize a portion of a subterranean formation or any
damage contained
therein.
[0018] The compositions and methods of the present invention may be used in
matrix acidizing applications, acidizing applications, fracture acidizing
applications, scale
removal applications, damage removal applications, hydrate treatment
applications, and
hydrate inhibition applications. They may also be used in open hole diversion
applications.
[0019] Among the many potential benefits of the present invention, one
advantage may be that the acidizing fluids of the present invention should
achieve deeper
penetration into the subterranean formation from the well bore. Additionally,
longer effective
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fracture acidizing lengths should be realized at least in most embodiments
than compared to
ungelled acids. Another benefit may be that leak off may be less as compared
to
conventional ungelled acidic fluids. One of the more important benefits should
be that
deeper penetration of the acid into the subterranean formation should be
obtained.
Additionally, in certain embodiments, the acidizing fluids of the present
invention should
effectively generate wormholes to stimulate production in subterranean
carbonate formations,
dissolve damage, and remove fines to recover production in formations at
elevated
temperatures. Another potential benefit is that the these acidizing fluids
should not leave
undesirable residue like many synthetic polymers do, which could lead to
easier and better
clean-up. Other advantages and objects of the present invention may be evident
to one
skilled in the art with the benefit of this disclosure.
[0020] In certain embodiments, the acidizing fluids of the present invention
comprise an acid, an oxidized crosslinked xanthan, and optionally, a base
fluid.
[0021] If desired, acidizing fluids of the present invention also may comprise
other gelling agents, diverting agents, nonemulsifiers, other acids, cross
linking agents, and/or
mutual solvents. Combinations and derivatives of these also may be suitable.
Although
some fluid loss control agents may be used if needed, in the fluids of the
present invention
there should be less need for additional fluid loss control because the fluids
can crosslink.
This may be application dependent. Any fluid loss may affect the ability to
create longer
fractures. Any sort of proppant particulates may be included if desired as
well. The acidizing
fluids of the present invention may further comprise additional additives as
deemed
appropriate by one of ordinary skill in the art, with the benefit of this
disclosure. Examples
of such additional additives include, but are not limited to, pH-adjusting
agents, pH-buffers,
oxidizing agents, enzymes, lost circulation materials, scale inhibitors,
surfactants, clay
stabilizers, corrosion inhibitors, paraffin inhibitors, asphaltene inhibitors,
penetrating agents,
clay control additives, iron control additives, chelators, reducers, oxygen
scavengers, sulfide
scavengers, emulsifiers, foamers, gases, derivatives thereof and combinations
thereof, and the
like.
[0022] Any acid suitable for use in subterranean applications may be used in
conjunction with the present invention. The acid may comprise organic acids,
inorganic
acids, derivatives thereof, or combinations thereof. Examples of suitable
acids include, but
are not limited to, hydrochloric acid, hydrofluoric acid, formic acid, lactic
acid, phosphoric
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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 40% by weight of the fluid. In certain embodiments, the acid may
be present in
the treatment fluids of the present invention in an amount of from about 2.5%
to about 28%
by weight of the fluid. In other embodiments, the acid may be present in the
treatment fluids
of the present invention in an amount of from about 2.5% to about 15% by
weight of the
fluid. Individuals skilled in the art, with the benefit of this disclosure,
will be able to select a
suitable acid and a suitable concentration thereof for a chosen application.
In some instances,
the particular concentration used in any particular embodiment depends on what
acid is being
used, and what percentage of acid is present. Other complex, interrelated
factors that may be
considered in deciding how much of the acid compound to use include, but are
not limited to,
the composition of the formation, the temperature of the formation, the
pressure of the
formation, the particular fines and damage present in the formation (e.g.,
scale, skin, calcium
carbonate, silicates, and the like), the particular acid used, metals the acid
may contact,
corrosion concerns, the expected contact time of the acid with the formation,
etc. The desired
contact time also depends on the particular application and purpose. For
example, if very
delayed acidizing is desired, then it may be desirable to pump a dilute, low
concentration but
a high volume to get deeper penetration. For matrix stimulation treatments,
the expected
contact time may be determined from the maximum pumping rate that does not
cause the
down hole pressure to exceed the fracturing pressure. For damage or fines
removal
procedures, the expected contact time may be based on laboratory tests, but
usually should
allow for extended contact periods as compared to conventional acid
treatments. For
instance, in conventional treatments where a live acid is pumped to remove
scale or fines,
that acid may react instantaneously so clean up of the entire amount of damage
and fines may
be impossible. Possibly, to achieve an equivalent of a 15% HCl acidizing
treatment, it may
be desirable to run formates and acetates mixtures, depending on which ones
are chosen with
an eye toward the reactivity of the formation at a given temperature. To avoid
undesirable
salt precipitation problems, it may be desirable to combine formates and
acetates or lactates
to keep both below the over saturation concentration that would cause salts to
precipitate in
formation, but still achieve the acid potential and dissolving power necessary
for the job. To
choose the appropriate acid and the right concentration of that acid, one
should balance salt
precipitation and acid dissolving power concentration concerns. In some
embodiments, a
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combination of acetic acid and formic acid or a combination of acetic acid and
lactic acid may
be preferred over a combination of acetic acid and formic acid and lactic
acid. One of
ordinary skill in the art with the benefit of this disclosure should know how
to balance the
factors so that salts do not saturate.
[0023] The acidizing fluids of the present invention comprise crosslinked
oxidized xanthan, which, inter alia, acts as a gelling agent to viscosify the
fluid. Preferably,
the xanthan polymer used is of high purity. One of ordinary skill in the art
with the benefit of
this disclosure will recognize the grade of purity of xanthan polymer
appropriate for a
particular application. An example of a suitable source of xanthan polymer is
commercially
available from Kelco Oil Field Group, of Houston, Tex., under the tradename
"XANVISTM L." An example of another suitable source of xanthan polymer is
commercially
available from Halliburton Energy Services, Inc., of Duncan, Okla., under the
tradename
"WG-24." An example of another suitable source of xanthan polymer is
commercially
available from Halliburton Energy Services, Inc., of Duncan, Okla., under the
tradename
"WG-37." The amount of oxidized xanthan to include in a fluid of the present
invention will
depend on several factors including, but not limited to the desired viscosity
of the fluid, the
characteristics of the formation, the characteristics of the acidizing
application, etc. Preferred
xanthans are disclosed in U.S. Published Patent Application No. 2006/0014648.
Other
considerations will be known to those skilled in the art with the benefit of
this disclosure. In
some embodiments, the amount may range from about 10 to about 200 lbs/1000
gallons of the
fluid. In other embodiments, the amount may range from about 20 to about 160
lbs/1000
gallons of fluid.
[0024] Suitable oxidizers for oxidizing the xanthan polymer include, but are
not limited to, salts of perborates, salts of permanganates, salts of
percarbonates, salts of
periodates, salts of hypochlorite, sodium perborate, sodium persulfate,
potassium persulfate,
ammonium persulfate, sodium permanganate, potassium permanganate, magnesium
permanganate, calcium permanganate, sodium percarbonate, potassium
percarbonate, sodium
periodate, potassium periodate, sodium hypochlorite, hydrogen peroxide,
calcium peroxide,
and magnesium peroxide. Derivatives and combinations of these may also be
suitable. To
oxidize the xanthan, in certain embodiments, the oxidizer may used in an
amount of from
about 0.01% to about 50% based on the amount of the xanthan present. A more
preferred
range would be from about 0.1 to about 10% and an even more preferred would be
from
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about 0.5 to about 5% Generally speaking, one thing to be mindful of is that
the more
oxidizer used, the faster the oxidation reaction will be.
[0025] In some embodiments, the xanthan polymer may be pre-oxidized and
taken in its oxidized form to a well site for use in a subterranean
application. In other
instances, the xanthan may be oxidized at the well site. However, it is
preferred that the
oxidizer be added to the xanthan before the acid is added to the xanthan even
if the xanthan is
oxidized at the well site.
[0026] At least a portion of the oxidized xanthan included in the fluids of
the
present invention may be crosslinked by a reaction comprising a crosslinking
agent, e.g., to
further increase the treatment fluid's viscosity thereof. The oxidized xanthan
can be
crosslinked before the fluid is placed in a well bore or at any other suitable
time.
Crosslinking agents typically comprise at least one metal ion that is capable
of crosslinking
polymer molecules. Really there are an unlimited number of crosslinking agents
that may be
suitable because the compositions of the present invention are not limited by
ligand choice on
the crosslinking agent. Examples of suitable crosslinking agents include, but
are not limited
to, zirconium compounds (such as, for example, zirconium lactate, zirconium
lactate
triethanolamine, zirconium carbonate, zirconium acetylacetonate, zirconium
maleate,
zirconium citrate, zirconium oxychloride, and zirconium diisopropylamine
lactate); titanium
compounds (such as, for example, titanium lactate, titanium maleate, titanium
citrate,
titanium ammonium lactate, titanium triethanolamine, and titanium
acetylacetonate);
aluminum compounds (such as, for example, aluminum lactate or aluminum
citrate); borate
compounds (such as, for example, sodium tetraborate, boric acid, disodium
octaborate
tetrahydrate, sodium diborate, ulexite, and colemanite); antimony compounds;
chromium
compounds; iron compounds; copper compounds; zinc compounds; or derivatives
and
combinations thereof. An example of a suitable commercially available
zirconium-based
cross linking agent is "CL-24TH" cross linker from Halliburton Energy
Services, Inc.,
Duncan, Oklahoma. An example of a suitable commercially available titanium-
based cross
linking agent is "CL-39TM" cross linker from Halliburton Energy Services,
Inc., Duncan
Oklahoma. An example of a suitable borate-based cross linking agent is
commercially
available as "CL-22TM" delayed borate cross linker from Halliburton Energy
Services, Inc.,
Duncan, Oklahoma. Divalent ions also may be used; for example, calcium
chloride and
magnesium oxide. An example of a suitable divalent ion cross linking agent is
commercially
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available as "CL-30TM" from Halliburton Energy Services, Inc., Duncan,
Oklahoma. Another
example of a suitable cross linking agent is "CL-15," from Halliburton Energy
Services, Inc.,
Duncan Oklahoma. Where present, the cross linking agent generally should be
included in
the fluids of the present invention in an amount sufficient, among other
things, to provide the
desired degree of cross linking. In some embodiments, the cross linking agent
may be
present in the treatment fluids of the present invention in an amount in the
range of from
about 0.01% to about 5% by weight of the treatment fluid. Buffering compounds
may be
used if desired, e.g., to delay or control the cross linking reaction. These
may include
glycolic acid, lactic acid, carbonates, bicarbonates, acetates, phosphates,
and any other
suitable buffering agent.
[0027] Preferred crosslinking agents are iron compounds such as iron
chloride. When an iron compound is used, one can achieve a delayed crosslink
(or one that
crosslinks in-situ). Using a delayed crosslinked acid as opposed to a
crosslinked "live" acid
(e.g., one that has been crosslinked prior to the acid substantially spending)
may have several
benefits. Delayed crosslinked acids may be more pumpable than crosslinked live
acid
acidizing fluids. One possible limitation of crosslinked live acid acidizing
fluids is that they
may have high viscosity that may lead to increased frictional pressures during
pumping,
which may require greater pumping horsepower. Also, fully crosslinked live
acids are not
always necessary to retard the reaction of strong acids on carbonates; merely
viscosifying the
acid can provide ample retardation. However, in such treatments much of the
acid may be
lost as a result of leak-off through wormholes. When using a delayed
crosslinked fluid, fluid
loss can be controlled as the acid leaks off through wormholes and spends.
When the acid is
nearly spent, the system may crosslink, thereby blocking wormholes and
preventing further
loss of acid from the fracture face. Additionally, this type of fluid
typically will not break
until the acid is substantially spent.
[0028] One should note that including a suitable breaker in an acidizing fluid
of the present invention or adding a suitable breaker to an acidizing fluid of
the present
invention may be advisable depending on the xanthan and its interaction with
the acid and the
well bore conditions. A breaker or breaker aid may be advisable to ultimately
reduce the
viscosity of the fluid. Any breaker suitable for the subterranean formation
and the xanthan
may be used. The amount of a breaker to include will depend, inter alia, on
the amount of
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xanthan present in the treatment fluid. Other considerations regarding the
breaker are known
to one skilled in the art with the benefit of this disclosure.
[0029] Optionally, an iron control additive may be used in conjunction with
the acidizing fluids of the present invention to prevent potential
precipitation of the iron.
Typical examples include, but are not limited to, citric acid,
ethylenediaminetetraacetic acid,
nitrilotriacetic acid, and erythorbic acid, and salts thereof. The amount of
an iron control
additive to include will depend, inter alia, on the amount of potential iron
precipitates present
in the treatment fluid. Other considerations regarding the iron control
additive are known to
one skilled in the art with the benefit of this disclosure
[0030] If used, the base fluid is preferably aqueous-based. A base fluid may
be beneficially used, for example, to provide dilution to control
concentration or coverage
issues. One of ordinary skill in the art with the benefit of this disclosure
will recognize when
a base fluid may be beneficial. The base fluid should be chosen based on its
compatibility
with the formation and the acid used. Suitable base fluids include fresh
water, brines,
seawater, or any other type of aqueous-fluid suitable for subterranean uses.
The amount of
base fluid used is typically dictated by the final concentration of acid
desired and the
concentration of the acid source. One of ordinary skill in the art with the
benefit of this
disclosure ill recognize the appropriate amount of base fluid to include to
reach the final
concentrations desired for a chosen application.
[0031] In order to insure that the producing zone is contacted by a fluid of
the
present invention uniformly, a supplemental particulate solid diverting agent
may be placed
in the well bore or the formation to isolate the zone of interest. The term
"zone" as used
herein simply refers to a portion of the formation and does not imply a
particular geological
strata or composition. One suitable technique involves packing the diverting
agent in
perforation tunnels extending from the well bore into the subterranean zone.
The diverting
agent in the perforation tunnels causes the fluid introduced therein to be
uniformly distributed
between all of the perforations whereby the subterranean zone is uniformly
treated. The
particulate solid diverting agent should be subsequently removed from the
perforation tunnel
to allow the maximum flow of produced hydrocarbons from the subterranean zone
into the
well bore. This can be accomplished by contacting the particulate solid
diverting agent with
a fluid which degrades the diverting agent, such as, water, oil, xylene and
the like. Other
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chemical diverting agents that are suitable for use in this invention include
oil-soluble resins,
water-soluble rock salts, and emulsions.
[0032] Degradable particulate diverting materials are also suitable for use in
the present invention. The degradable particulate diverting materials of this
invention can be
placed in the subterranean zone or packed into perforation tunnels in the
subterranean zone
by introducing a carrier fluid containing the degradable particulate diverting
materials into
the subterranean zone. Preferred degradable particulate diverting materials
may comprise a
degradable material which is capable of degrading over time when placed in a
subterranean
zone and will not recrystallize or otherwise solidify down hole. The
degradable particular
diverting materials may need a source of water to degrade and this may be
provided by a
particulate hydrated organic or inorganic solid compounds introduced into the
subterranean
formation either before, during or after the degradable particulate diverting
material is
introduced. Nonlimiting examples of degradable particulates that may be used
in conjunction
with the compositions and methods of the present invention include but are not
limited to
degradable polymers. The term "particulate" as used herein is intended to
include material
particles having the physical shape of platelets, shavings, flakes, ribbons,
rods, strips,
spheroids, toroids, pellets, tablets or any other physical shape. The terms
"degrade,"
"degradation," "degradable," and the like when used herein refer to both the
two relative
cases of hydrolytic degradation that the degradable particulate may undergo,
i.e.,
heterogeneous (or bulk erosion) and homogeneous (or surface erosion), and any
stage of
degradation in between these two. This degradation can be a result of inter
alia, a chemical
or. thermal reaction or a reaction induced by radiation. Suitable examples of
degradable
polymers that may be used in accordance with the present invention include but
are not
limited to those described in the publication of Advances in Polymer Science,
Vol. 157
entitled "Degradable Aliphatic Polyesters" edited by A.-C. Albertsson.
Specific examples
include homopolymers, random, block, graft, and star- and hyper-branched
aliphatic
polyesters. Polycondensation reactions, ring-opening polymerizations, free
radical
polymerizations, anionic polymerizations, carbocationic polymerizations,
coordinative ring-
opening polymerizations, and any other suitable process may prepare such
suitable polymers.
Specific examples of suitable polymers include polysaccharides such as dextran
or cellulose;
chitins; chitosans; proteins; aliphatic polyesters; poly(lactides);
poly(glycolides); poly(e-
caprolactones); poly(hydroxybutyrates); poly(anhydrides); aliphatic
polycarbonates;
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poly(orthoesters); poly(amino acids); poly(ethylene oxides); and
polyphosphazenes. Of these
suitable polymers, aliphatic polyesters and polyanhydrides are preferred. Of
the suitable
aliphatic polyesters, poly(lactide) is preferred. The degradable particulate
diverting agents
may comprise a plasticizer.
[0033] In some embodiments, a self-degradable particulate diverting material
which degrades over time may be placed in the subterranean zone. The self-
degradable
particulate diverting material comprises a mixture of a degradable aliphatic
polyester and a
hydrated organic or inorganic solid compound. A treating fluid may be
introduced into the
subterranean zone and then diverted by the self-degradable particulate
diverting material
therein. Thereafter, the degradable aliphatic polyester in the self-degradable
particulate
diverting material is allowed to at least partially degrade in the releasable
water provided by
the hydrated organic or inorganic compound which dehydrates over time when
heated in the
subterranean zone. Examples of the hydrated organic or inorganic solid
compounds that can
be utilized in the self-degradable diverting material include, but are not
limited to, hydrates of
organic acids or their salts such as sodium acetate trihydrate, L-tartaric
acid disodium salt
dihydrate, sodium citrate dihydrate, hydrates of inorganic acids or their
salts such as sodium
tetraborate decahydrate, sodium hydrogen phosphate heptahydrate, sodium
phosphate
dodecahydrate, amylose, starch-based hydrophilic polymers, and cellulose-based
hydrophilic
polymers. Of these, sodium acetate trihydrate is preferred. The lactide units
of the aliphatic
polyester and the releasable water of the organic or inorganic solid compound
utilized are
preferably present in the mixture in equal molar amounts. The specific amount
of the
hydrated compound that may be included will depend upon the presence of
formation water,
produced fluids, formation temperature, treating fluid and production rates.
[0034] Suitable diverting agents may be provided to the subterranean
formation via a carrier fluid that then dissipates into the subterranean zone,
and as a result the
degradable particulate diverting materials is screened out of the carrier
fluid by the formation.
A variety of carrier fluids can be utilized including, but not limited to,
water, brines, seawater
or formation water. Of these, in certain embodiments, brines and seawater are
preferred.
[0035] If a diverting agent is used, the amount used may range up to 3% or
more by weight or volume of the carrier fluid. Preferred diverting agents are
disclosed in
Halliburton's Published U.S. Patent Application No. 2004-0261996-Al, entitled
Methods of
Diverting Treating Fluids in Subterranean Zones and Degradable Diverting
Materials, filed
CA 02677577 2011-09-07
13
on 06/27/2003 and published on 12/30/2004.
[0036] Mechanical diverting agents may also be suitable. These may include
but are not limited to, perf balls, packers, treatment designs, hydrojetting
methods, and
methods known as "Surgifrac," which are available from Halliburton Energy
Services, at
various locations.
[0037] In some embodiments, the fluids of the present invention may include
surfactants, e.g., to improve the compatibility of the fluids of the present
invention with other
fluids (like any formation fluids) that may be present in the well bore or
reduce interfacial
tension. Using surfactants may be advisable when liquid hydrocarbons are
present in the well
bore. An artisan of ordinary skill with the benefit of this disclosure will be
able to identify the
type of surfactant as well as the appropriate concentration of surfactant to
be used. Suitable
surfactants may be used in a liquid or powder form. Where used, the
surfactants are present in
the fluids in an amount sufficient to prevent incompatibility with formation
fluids or well
bore fluids. If included, a surfactant may be added in an amount of from about
1 /10th of a gal
per 1000 gals up to 10% by volume. Higher concentrations may be used, e.g., if
a surfactant
gelling agent is used, and this amount may be in excess of 5% in some
instances. In an
embodiment where liquid surfactants are used, the surfactants are generally
present in an
amount in the range of from about 0.01% to about 10% by volume of a fluid. In
one
embodiment, the liquid surfactants are present in an amount in the range of
from about 0.1 %
to about 10% by volume of the fluid. In embodiments where powdered surfactants
are used,
the surfactants may be present in an amount in the range of from about 0.001%
to about 10%
by weight of the fluid. Examples of suitable surfactants are non-emulsifiers
commercially
available from Halliburton Energy Services, Inc., of Duncan, Oklahoma, under
the
tradenames "LOSURF-259TM" nonionic nonemulsifier, "LOSURF-300TM" nonionic
surfactant,
"LOSURF-357TM" nonionic surfactant, and "LOSURF-400TM" surfactant. Another
example of
a suitable surfactant is a non-emulsifier commercially available from
Halliburton Energy
Services, Inc., of Duncan, Oklahoma, under the tradename "NEA-96MTM"
Surfactant. It
should be noted that it may be beneficial to add a surfactant to a viscosified
treatment fluid of
the present invention as that fluid is being pumped down hole to help
eliminate the possibility
of foaming if so desired.
CA 02677577 2009-08-06
WO 2008/102138 PCT/GB2008/000591
14
[0038] In some embodiments, the acidizing fluids of the present invention
may be used in conjunction with fluids containing viscoelastic surfactants.
[0039] In some embodiments, if desired, the fluids of the present invention
may contain bactericides, inter alia, to protect both the subterranean
formation as well as the
fluid from attack by bacteria. Such attacks may be problematic because they
may lower the
viscosity of the fluid, resulting in poorer performance, for example. Bacteria
also can cause
plugging by bacterial slime production, and can turn the formation sour. Any
bactericides
known in the art are suitable. An artisan of ordinary skill with the benefit
of this disclosure
will be able to identify a suitable bactericide and the proper concentration
of such bactericide
for a given application. Where used, such bactericides are present in an
amount sufficient to
destroy all bacteria that may be present. Examples of suitable bactericides
include, but are
not limited to, a 2,2-dibromo-3-nitrilopropionamide, commercially available
under the
tradename `BE-3STM" biocide from Halliburton Energy Services, Inc., of Duncan,
Oklahoma,
and a 2-bromo-2-nitro-1,3-propanediol commercially available under the
tradename "BE-
6TM" biocide from Halliburton Energy Services, Inc., of Duncan, Oklahoma. In
one
embodiment, the bactericides are present in the viscosified treatment fluid in
an amount in the
range of from about 0.001% to about 0.003% by weight of the viscosified
treatment fluid.
Another example of a suitable bactericide is a solution of sodium
hypochlorite, commercially
available under the tradename "CAT-ITM" chemical from Halliburton Energy
Services, Inc.,
of Duncan, Oklahoma. In certain embodiments, such bactericides may be present
in the
viscosified treatment fluid in an amount in the range of from about 0.01 % to
about 0.1 % by
volume of the viscosified treatment fluid. In certain preferred embodiments,
when
bactericides are used in the viscosified treatment fluids of the present
invention, they are
added to the viscosified treatment fluid before the gelling agent is added.
[0040] In some embodiments, the fluids of the present invention can be
prepared in any suitable tank equipped with suitable mixing means well known
to those
skilled in the art. The fluids may be transferred either at a controlled rate
directly into the
well bore or into a convenient storage tank for later placement down the well
bore. In either
event, the pumping rates and pressures utilized will depend upon the
characteristics of the
formation and whether or not fracturing of the formation is desired. After a
fluid has been
injected into a well bore, the well may be shut in and allowed to stand for a
period of several
hours or more depending on the type of acid employed and the formation
treated. If there is
CA 02677577 2009-08-06
WO 2008/102138 PCT/GB2008/000591
pressure in the well, pressure then can be released and then the spent or at
least partially spent
fluid (that likely contains salts formed by the reaction of the acid in the
subterranean
formation), may be permitted to flow back to the surface for appropriate
disposal. The well
then can be placed on production or used for other purposes.
[0041] Additionally, in some embodiments, the diverting effect of the
acidizing fluids of the present invention may be enhanced by introducing the
fluid into a
subterranean formation in stages. The first stage involves pumping stages of
the acidizing
fluid containing an iron crosslinking agent, and then stopping pumping for a
short amount of
time to allow an in-situ crosslink to form before resuming pumping of the
treatment fluid. A
preferred method of this would be to use a low strength acid in the shut in
stage to provide a
faster crosslink. A preferred range for this would be I to 10% acid and a more
preferred
range would be 2.5 to 7.5% acid. An acid concentration of about 5% is highly
preferred.
[0042] To facilitate a better understanding of the present invention, the
following examples of certain aspects of some embodiments are given. In no way
should the
following examples be read to limit, or define, the entire scope of the
invention.
EXAMPLES
[0043] An 80 lb/Mgal xanthan gel ("WG-37" xanthan was used and is
available from Halliburton Energy Services, Inc., in Duncan, Oklahoma) was
hydrated in
water for 30 minutes in a Waring blender, and then oxidized with 5% by volume
sodium
hypochlorite (6-7.35% sodium hypochiorite in water). Upon a short oxidation
(approximately 5 minutes) while mixing, hydrochloric acid was added to a
concentration in
the final fluid of 15% HC1. Crosslinking agents were also added. When 2% by
volume "CL-
23," which is a zirconium-based crosslinking agent available from Halliburton
Energy
Services in Duncan, Oklahoma, was added to an aliquot, a lipping, live-acid
gel was formed.
In the case of adding 1% "XL-1" to an aliquot, which is a iron-based
crosslinking agent
available from Halliburton Energy Services in Duncan, Oklahoma a crosslinked
gel was
formed as the acid spent with calcium carbonate.
[0044] 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
CA 02677577 2011-09-07
16
design herein shown, other than as described in the claims below. 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 as referring
to the power set (the set of all subsets) of the respective range of values,
and set forth every
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.
