Note: Descriptions are shown in the official language in which they were submitted.
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METHOD FOR DIVERSION OF HYDRAULIC FRACTURE TREATMENTS
BACKGROUND
[0001] The present invention relates to methods useful in subterranean
treatments, and, at least in some embodiments, to methods of diverting
fracturing fluids
within a subterranean formation.
[0002] After a well bore is drilled and completed in a zone of a subterranean
formation, it may often be necessary to introduce a treating fluid into the
zone. As used
herein "zone" simply refers to a portion of the formation and does not imply a
particular
geological strata or composition. For example, the producing zone may be
stimulated by
introducing a hydraulic fracturing fluid into the producing zone to create
fractures in the
formation, thereby increasing the production of hydrocarbons therefrom. To
insure that the
producing zone is uniformly treated with the treating fluid, some form of
diversion within or
among zones in the subterranean formation may be useful. For example, a packer
or bridge
plug may be used between sets of perforations to divert a treatment fluid
between the
perforations. In another technique, solid diverting agents may be used, such
as proppant
particulates, to form bridges or plugs in the casing to divert fluid within or
among zones. In
another technique, balls may be used to seal off individual perforations to
divert fluid within
or among zones. Such techniques may be only partially successful in diverting
fluid and
ensuring uniform distribution of fluid among the various producing zones and
perforations
within a subterranean formation.
[0003] One of many problems in the use of the some or all of the above
described procedures may be that the means of diverting the treatment fluid
preferably is
subsequently removed from the well bore to allow the maximum flow of produced
hydrocarbon from the subterranean zone into the well bore. For example, a
bridge plug
generally is removed or drilled out at the end of the operation to allow for
production.
Similarlyõ sand plugs or bridges are cleaned out for poduction; sealing balls
are often
recovered for production. These may entail additional steps in the treatment
process leading
to additional time and expenses.
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SUMMARY
[0004] The present invention relates to methods useful in subterranean
treatments, and, at least in some embodiments, to methods of diverting
fracturing fluids
within a subterranean formation.
[0005] According to one aspect, the invention provides a method for treating a
well bore which method comprises introducing a degradable diverting material
into a
subterranean formation; and introducing a treatment fluid into the
subterranean formation,
wherein the degradable diverting material diverts at least a portion of the
treatment fluid.
[0006] In another aspect, the invention provides a method for fracturing a
subterranean formation comprising: fracturing a portion of a subterranean
formation with a
fracturing fluid through a first perforation tunnel to create a first
fracture; introducing a
degradable diverting material into the first perforation tunnel; and
fracturing the subterranean
formation with the fracturing fluid through a second perforation tunnel to
create a second
fracture, wherein the degradable diverting material diverts at least a portion
of the fracturing
fluid away from the first perforation tunnel.
[0007] In a further aspect, the present invention provides a method for
treating
a well bore comprising treating a subterranean formation with a first
treatment fluid, wherein
the first treatment fluid treats a first treated zone; introducing a
degradable diverting material
into the subterranean formation; and treating the subterranean formation with
a second
treatment fluid, wherein the degradable diverting material diverts at least a
portion of the
second treatment fluid away from the first treated zone.
[0008] In a further aspect, the present invention provides a method for
fracturing a subterranean formation comprising fracturing a subterranean
formation with a
fracturing fluid through a first perforation tunnel to create a first
fracture; introducing a
degradable diverting material into the first perforation tunnel at a sub-
fracture pressure; and
fracturing the subterranean formation with the fracturing fluid through a
second perforation
tunnel to create a second fracture, wherein the degradable diverting material
diverts at least a
portion of the fracturing fluid away from the first perforation tunnel.
[0009] In a further aspect, the present invention provides a method for
fracturing a well bore comprising fracturing a well bore with a fracturing
fluid containing a
plurality of proppant particulates through a first perforation tunnel to
create a first fracture;
forming a proppant particulate plug in the well bore, wherein the plug covers
the first
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perforation tunnel; introducing a degradable diverting material into the
proppant particulate
plug at a sub-fracture pressure; fracturing the subterranean formation with
the fracturing fluid
through a second perforation tunnel to create a second fracture, wherein the
degradable
diverting material diverts at least a portion of the fracturing fluid away
from the first
perforation tunnel covered by the proppant plug.
[0010] In a preferred aspect, the treatment fluids and fracturing fluids used
do
not comprise cement.
[0011] The features and advantages of the present invention will be apparent
to those skilled in the art.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] These drawings illustrate certain aspects of some of the embodiments
of the present invention, and should not be used to limit or define the
invention.
[0013] Figure la illustrates a cross-sectional, side view of an exemplary
embodiment of the present invention.
[0014] Figure lb illustrates a cross-sectional, side view of an exemplary
alternate embodiment of the present invention where the fracturing treatment
is placed using
a downhole jetting tool.
[0015] Figure 2a illustrates a cross-sectional, side view of an exemplary
embodiment of the present invention after a first treatment in accordance with
an
embodiment of the present invention.
[0016] Figure 2b illustrates a cross-sectional, side view of an exemplary
embodiment of the present invention after a first treatment in accordance with
an alternate
embodiment of the present invention where the fracturing treatment is placed
using a
downhole jetting tool.
[0017] Figure 3a illustrates a cross-sectional, side view of an exemplary
embodiment of the present invention with a horizontal well bore formed therein
after a first
treatment in accordance with an embodiment of the present invention.
[0018] Figure 3b illustrates a cross-sectional, side view of an exemplary
embodiment of the present invention with a horizontal well bore formed therein
after a first
treatment in accordance with an alternate embodiment of the present invention
where the
fracturing treatment is placed using a downhole jetting tool.
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[0019] Figure 4a illustrates a cross-sectional, side view of an exemplary
embodiment of the present invention after a second treatment in accordance
with an
embodiment of the present invention.
[0020] Figure 4b illustrates a cross-sectional, side view of an exemplary
embodiment of the present invention after a second treatment in accordance
with an alternate
embodiment of the present invention where the fracturing treatment is placed
using a
downhole jetting tool.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0021] The present invention relates to methods useful in subterranean
treatments, and, at least in some embodiments, to methods of diverting
fracturing fluids
within a subterranean formation.
[0022] The term "particulate" as used herein is not limited to any particular
shape and 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.
[0023] The terms "degrade," "degradation," "degradable," and the like when
used herein refer to both the two relative cases of hydrolytic degradation
that the degradable
diverting material 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.
[0024] As used herein, the term "treatment," or "treating," refers to any
subterranean operation that uses a fluid in conjunction with a desired
function and/or for a
desired purpose. The term "treatment," or "treating," does not imply any
particular action by
the fluid or any particular component thereof
[0025] As used in this disclosure, the term "enhancing" a fracture refers to
the
extension or enlargement of a natural or previously created fracture in the
formation.
[0026] "Zone," as used herein, simply refers to a portion of the formation and
does not imply a particular geological strata or composition.
[0027] While numerous advantages of the present invention exist, only some
may be described or alluded to herein. In an embodiment, the diverting
materials of the
present invention may advantageously be used to divert a treatment fluid from
one zone in a
subterranean formation to another, and may then be degraded in the
subterranean formation
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without the need for an additional step of removing the diverting material. In
an
embodiment, the treatment may be a fracturing treatment and the use of
degradable diverting
material may allow for the creation of multiple fractures through several
perforations without
the need for additional related operations, such as moving the tubing or
placing a plug in the
well bore.
[0028] In an embodiment, a method of the present invention may include
treating a subterranean formation with a first treatment fluid, where the
first treatment fluid
treats a first treated zone; introducing a degradable diverting material into
the subterranean
formation; and treating the subterranean formation with a second treatment
fluid, where the
degradable diverting material diverts at least a portion of the second
treatment fluid away
from the first treated zone. The first treatment may be one of several
treatments useful in a
subterranean environment including a fracturing treatment, and the degradable
diverting
material may be used to divert fracturing fluid from an existing fracture to
another perforation
to create or enhance a new fracture.
[0029] In an embodiment, a degradable diverting material may be any
material capable of degrading in a subterranean environment. Further, the
degradable
diverting material may be in any form for delivery, including for example,
particulates or
powders. Nonlimiting examples of degradable diverting material that may be
used in
conjunction with the methods of the present invention may include, but are not
limited to,
degradable polymers. Suitable examples of degradable polymers that may be used
in
accordance with the present invention may include, but are not limited to,
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 may include polysaccharides such as dextran or cellulose;
chitins;
chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides);
poly(.epsilon.-
caprolactones); poly(hydroxybutyrates); poly(anhydrides); aliphatic
polycarbonates;
poly(orthoesters); poly(amino acids); poly(ethylene oxides); and
polyphosphazenes. Of these
suitable polymers, aliphatic polyesters and polyanhydrides may be preferred.
[0030] Aliphatic polyesters may degrade chemically, inter alia, by hydrolytic
cleavage. Hydrolysis may be catalyzed by either acids or bases. Generally,
during the
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hydrolysis, carboxylic end groups may be formed during chain scission, and
this may
enhance the rate of further hydrolysis. This mechanism is known in the art as
"autocatalysis," and may make polyesters more bulk eroding.
[0031] Suitable aliphatic polyesters have the general formula of repeating
units shown below:
Formula I
¨ n
0
where n is an integer between 75 and 10,000 and R is selected from the group
consisting of
hydrogen, alkyl, aryl, alkylaryl, acetyl, heteroatoms, and mixtures thereof.
[0032] Of the suitable aliphatic polyesters, poly(lactide) may be preferred.
Poly(lactide) may be synthesized either from lactic acid by a condensation
reaction or more
commonly by ring-opening polymerization of cyclic lactide monomer. Since both
lactic acid
and lactide can achieve the same repeating unit, the general term poly(lactic
acid) as used
herein refers to formula I without any limitation as to how the polymer was
made such as
from lactides, lactic acid, or oligomers, and without reference to the degree
of polymerization
or level of plasticization.
[0033] The lactide monomer may generally exists in three different forms: two
stereoisomers L- and D-lactide and racemic D,L-lactide (meso-lactide). The
oligomers of
lactic acid, and oligomers of lactide are defined by the formula:
Formula II
0
HO[
H
¨ m
O
where m is an integer: 2<m<75. Preferably m is an integer: 2<m<10. These
limits may
correspond to number average molecular weights below about 5,400 and below
about 720,
respectively. The chirality of the lactide units may provide a means to
adjust, inter alia,
degradation rates, as well as physical and mechanical properties. Poly(L-
lactide), for
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instance, may be a semicrystalline polymer with a relatively slow hydrolysis
rate. This may
be desirable in applications of the present invention where a slower
degradation of the
degradable diverting material may be desired. Poly(D,L-lactide) may be a more
amorphous
polymer with a resultant faster hydrolysis rate. This may be suitable for
other applications
where a more rapid degradation may be appropriate. The stereoisomers of lactic
acid may be
used individually or combined to be used in accordance with the present
invention.
Additionally, they may be copolymerized with, for example, glycolide or other
monomers
like E-caprolactone, 1,5-dioxepan-2-one, trimethylene carbonate, or other
suitable monomers
to obtain polymers with different properties or degradation times.
Additionally, the lactic
acid stereoisomers may be modified to be used in the present invention by,
inter alia,
blending, copolymerizing or otherwise mixing the stereoisomers, blending,
copolymerizing
or otherwise mixing high and low molecular weight polylactides, or by
blending,
copolymerizing or otherwise mixing a polylactide with another polyester or
polyesters.
[0034] Further plasticizers may be used in the compositions and methods of
the present invention, and include derivatives of oligomeric lactic acid,
selected from the
group defined by the formula:
Formula III
0
R'O R
q
0
where R is hydrogen, alkyl, aryl, alkylaryl or acetyl, and R is saturated,
where R' is hydrogen,
alkyl, aryl, alkylaryl or acetyl, and R' is saturated, where R and R' cannot
both be H, where q
may be an integer: 2<q<75; and mixtures thereof. Preferably q may be an
integer: 2<q<10.
As used herein the term "derivatives of oligomeric lactic acid" may include
derivatives of
oligomeric lactide.
[0035] The plasticizers may be present in any amount that provides the
desired characteristics. For example, the various types of plasticizers
discussed herein
provide for (a) more effective compatibilization of the melt blend components;
(b) improved
processing characteristics during the blending and processing steps; and (c)
control and
regulate the sensitivity and degradation of the polymer by moisture. For
pliability, a
plasticizer may be present in higher amounts while other characteristics are
enhanced by
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lower amounts. The compositions may allow many of the desirable
characteristics of pure
nondegradable polymers. In addition, the presence of a plasticizer may
facilitate the melt
processing, and enhances the degradation rate of the compositions in contact
with the
environment. The intimately plasticized composition may be processed into a
final product
in a manner adapted to retain the plasticizer as an intimate dispersion in the
polymer for
certain properties. These may include: (1) quenching the composition at a rate
adapted to
retain the plasticizer as an intimate dispersion; (2) melt processing and
quenching the
composition at a rate adapted to retain the plasticizer as an intimate
dispersion; and (3)
processing the composition into a final product in a manner adapted to
maintain the
plasticizer as an intimate dispersion. In certain embodiments, the
plasticizers may be at least
intimately dispersed within the aliphatic polyester.
[0036] An aliphatic polyester may be poly(lactic acid). D-lactide is a
dilactone, or cyclic dimer, of D-lactic acid. Similarly, L-lactide is a cyclic
dimer of L-lactic
acid. Meso D,L-lactide is a cyclic dimer of D-, and L-lactic acid. Racemic D,L-
lactide
comprises a 50/50 mixture of D-, and L-lactide. When used alone herein, the
term "D,L-
lactide" is intended to include meso D,L-lactide or racemic D,L-lactide.
Poly(lactic acid)
may be prepared from one or more of the above. The chirality of the lactide
units may
provide a means to adjust degradation rates as well as physical and mechanical
properties.
Poly(L-lactide), for instance, may be a semicrystalline polymer with a
relatively slow
hydrolysis rate. This may be desirable in applications of the present
invention where slow
degradation is preferred. Poly(D,L-lactide) may be an amorphous polymer with a
faster
hydrolysis rate. This may be suitable for other applications of the present
invention. The
stereoisomers of lactic acid may be used individually combined or
copolymerized in
accordance with the present invention.
[0037] The aliphatic polyesters of the present invention may be prepared by
substantially any of the conventionally known manufacturing methods such as
those
disclosed in U.S. Pat. Nos. 6,323,307; 5,216,050; 4,387,769; 3,912,692 and
2,703,316.
[0038] Poly(anhydrides) may be another type of suitable degradable polymer
useful in the present invention. Poly(anhydride) hydrolysis may proceed, inter
alia, via free
carboxylic acid chain-ends to yield carboxylic acids as final degradation
products. The
erosion time may be varied over a broad range of changes in the polymer
backbone.
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Examples of suitable poly(anhydrides) may include poly(adipic anhydride),
poly(suberic
anhydride), poly(sebacic anhydride), and poly(dodecanedioic anhydride). Other
suitable
examples include, but are not limited to, poly(maleic anhydride) and
poly(benzoic
anhydride).
[0039] The physical properties of degradable polymers may depend on several
factors such as the composition of the repeat units, flexibility of the chain,
presence of polar
groups, molecular mass, degree of branching, crystallinity, orientation, etc.
For example,
short chain branches may reduce the degree of crystallinity of polymers while
long chain
branches may lower the melt viscosity and impart, inter alia, elongational
viscosity with
tension-stiffening behavior. The properties of the material utilized may be
further tailored by
blending, and copolymerizing it with another polymer, or by a change in the
macromolecular
architecture (e.g., hyper-branched polymers, star-shaped, or dendrimers,
etc.). The properties
of any such suitable degradable polymers (e.g., hydrophobicity,
hydrophilicity, rate of
degradation, etc.) may be tailored by introducing select functional groups
along the polymer
chains. For example, poly(phenyllactide) may degrade at about 1/5th of the
rate of racemic
poly(lactide) at a pH of about 7.4 at 55 C. One of ordinary skill in the art
with the benefit of
this disclosure will be able to determine the appropriate functional groups to
introduce to and
the structure of the polymer chains to achieve the desired physical properties
of the
degradable polymers.
[0040] In choosing the appropriate degradable material, one should consider
the degradation products that may result. These degradation products should
not adversely
affect other operations or components. The choice of degradable material also
may depend,
at least in part, on the conditions of the well, e.g., well bore temperature.
For instance,
lactides have been found to be suitable for lower temperature wells, including
those within
the range of about 60 F (15 C) to about 150 F (66 C), and polylactides have
been found to
be suitable for well bore temperatures above this range. Also, poly(lactic
acid) may be
suitable for higher temperature wells. Some stereoisomers of poly(lactide) or
mixtures of
such stereoisomers may be suitable for even higher temperature applications.
[0041] In an embodiment of the present invention, the degradable diverting
material may be formed into particles of selected sizes. That is, the
degradable diverting
material polymer may be degraded in a solvent such as methylene chloride,
trichloroethylene,
chloroform, cyclohexane, methylene diiodide, mixtures thereof and the like.
The solvent may
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then be removed to form a solid material which can be formed into desired
particle sizes.
Alternatively, fine powders can be admixed and then granulated or pelletized
to form
mixtures having any desired particle sizes. In an embodiment, the degradable
diverting
material may be formed into particulates with a size ranging from about 100
mesh (0.15 mm)
to about one-quarter of an inch (6 mm).
[0042] Examples of treating fluids which can be introduced into the
subterranean formation containing the degradable diverting material include,
but are not
limited to, water based foams, fresh water, salt water, formation water,
various aqueous
solutions and various hydrocarbon based solutions. The aqueous solutions
include, but are
not limited to, aqueous acid solutions, aqueous scale inhibitor material
solutions, aqueous
water blocking material solutions, aqueous clay stabilizer solutions, aqueous
chelating agent
solutions, aqueous surfactant solutions, aqueous fracturing fluids, and
aqueous paraffin
removal solutions. The hydrocarbon based solutions may include, but are not
limited to, oil,
oil-water emulsions, oil based foams, hydrocarbon scale inhibitor material
solutions,
hydrocarbon based drilling fluids, hydrocarbon emulsified acidizing fluids,
and hydrocarbon
based fracturing fluids.
[0043] When the aqueous treating fluid is an aqueous acid solution, the
aqueous acid solution may include one or more mineral acids such as
hydrochloric acid,
hydrofluoric acid, or organic acids such as acetic acid, formic acid and other
organic acids or
mixtures thereof. In acidizing procedures for increasing the porosity of
subterranean
producing zones, a mixture of hydrochloric and hydrofluoric acids may be
utilized.
[0044] Another aqueous treating fluid which may be introduced into the
subterranean producing zone in accordance with this invention is a solution of
an aqueous
scale inhibitor material. The aqueous scale inhibitor solution may contain one
or more scale
inhibitor materials including, but not limited to, tetrasodium ethylenediamine
acetate,
pentamethylene phosphonate, hexamethylenediamine phosphonate and polyacrylate.
These
scale inhibitor materials may attach themselves to the subterranean zone
surfaces whereby
they may inhibit the formation of scale in tubular goods and the like when
hydrocarbons and
water are produced from the subterranean zone.
[0045] Another aqueous treating solution which may be utilized is a solution
of an aqueous water blocking material. The water blocking material solution
may contain
one or more water blocking materials which may attach themselves to the
formation in water
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producing areas whereby the production of water may be reduced or terminated.
Examples
of water blocking materials that may be used include, but are not limited to,
sodium silicate
gels, organic polymers cross-linked with metal cross-linkers and organic
polymers cross-
linked with organic cross-linkers. Of these, organic polymers cross-linked
with organic
cross-linkers are preferred.
[0046] Suitable fracturing fluids for use in the present invention generally
comprise a base fluid, a suitable gelling agent, and proppant particulates.
Optionally, other
components may be included if desired, as recognized by one skilled in the art
with the
benefit of this disclosure. For example, the fluids used in the present
invention optionally
may comprise one or more additional additives known in the art, including, but
not limited to,
fluid loss control additives, gel stabilizers, gas, salts (e.g., KC1), pH-
adjusting agents (e.g.,
buffers), corrosion inhibitors, dispersants, flocculants, acids, foaming
agents, antifoaming
agents, H2S scavengers, lubricants, oxygen scavengers, weighting agents, scale
inhibitors,
surfactants, catalysts, clay control agents, biocides, friction reducers,
particulates (e.g.,
proppant particulates, gravel particulates), combinations thereof, and the
like. For example, a
gel stabilizer compromising sodium thiosulfate may be included in certain
treatment fluids of
the present invention. Individuals skilled in the art, with the benefit of
this disclosure, will
recognize the types of additives that may be suitable for a particular
application of the present
invention.
[0047] 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, 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,
for example,
copper ions, iron ions, or certain types of organic materials (e.g., lignin).
In certain
embodiments, the density of the aqueous base fluid can be increased, among
other purposes,
to provide additional particle transport and suspension in the treatment
fluids of the present
invention. In certain embodiments, the pH of the aqueous base fluid may be
adjusted (e.g.,
by a buffer or other pH adjusting agent), among other purposes, to activate a
crosslinldng
agent, and/or to reduce the viscosity of the treatment fluid (e.g., activate a
breaker, deactivate
a crosslinldng agent). In these embodiments, the pH may be adjusted to a
specific level,
which may depend on, among other factors, the types of gelling agents,
crosslinldng agents,
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and/or breakers included in the treatment fluid. One of ordinary skill in the
art, with the
benefit of this disclosure, will recognize when such density and/or pH
adjustments are
appropriate.
[0048] A gelling agent may be utilized in a treatment fluid of the present
invention and may comprise any polymeric material capable of increasing the
viscosity of
an aqueous fluid. In certain embodiments, the gelling agent may comprise
polymers that
have at least two molecules that may be 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, synthetic, or a combination thereof. In certain
embodiments,
suitable gelling agents may comprise polysaccharides, and 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), and combinations thereof In certain
embodiments,
the gelling agents comprise an organic carboxylated polymer, such as CMHPG. In
certain
embodiments, the derivatized cellulose is a cellulose grafted with an allyl or
a vinyl
monomer, such as those disclosed in United States Patent Nos. 4,982,793;
5,067,565; and
5,122,549. 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.
[0049] The gelling agent may be present in the treatment fluids of the
present invention in an amount sufficient to provide the desired viscosity. In
some
embodiments, the gelling agents may be present in an amount in the range of
from about
0.10% to about 4.0% by weight of the treatment fluid. In certain embodiments,
the gelling
agents may be present in an amount in the range of from about 0.18% to about
0.72% by
weight of the treatment fluid.
[0050] In those embodiments of the present invention wherein it is desirable
to crosslink the gelling agent, the treatment fluid may comprise one or more
of the
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crosslinking agents. The crosslinking agents may comprise a metal ion that is
capable of
crosslinking at least two molecules of the gelling agent. Examples of suitable
crosslinking
agents include, but are not limited to, borate ions, zirconium IV ions,
titanium IV ions,
aluminum ions, antimony ions, chromium ions, iron ions, copper ions, and zinc
ions. These
ions may be provided by providing any compound that is capable of producing
one or more
of these ions; examples of such compounds include, but are not limited to,
boric acid,
disodium octaborate tetrahydrate, sodium diborate, pentaborates, ulexite,
colemanite,
zirconium lactate, zirconium triethanol amine, zirconium lactate
triethanolamine, zirconium
carbonate, zirconium acetylacetonate, zirconium maleate, zirconium citrate,
zirconium
diisopropylamine lactate, zirconium glycolate, zirconium triethanol amine
glycolate,
zirconium lactate glycolate, titanium lactate, titanium malate, titanium
citrate, titanium
ammonium lactate, titanium triethanolamine, and titanium acetylacetonate,
aluminum lactate,
aluminum citrate, antimony compounds, chromium compounds, iron compounds,
copper
compounds, zinc compounds, and combinations thereof In certain embodiments of
the
present invention, the crosslinking agent may be formulated to remain inactive
until it is
"activated" by, among other things, certain conditions in the fluid (e.g., pH,
temperature, etc.)
and/or contact with some other substance. In some embodiments, the
crosslinking agent may
be delayed by encapsulation with a coating (e.g., a porous coating through
which the breaker
may diffuse slowly, or a degradable coating that degrades downhole) that
delays the release
of the crosslinking agent until a desired time or place. The choice of a
particular crosslinking
agent will be governed by several considerations that will be recognized by
one skilled in the
art, including but not limited to the following: the type of gelling agent
included, the
molecular weight of the gelling agent(s), the pH of the treatment fluid,
temperature, and/or
the desired time for the crosslinking agent to crosslink the gelling agent
molecules.
[0051] When included, suitable crosslinking agents may be present in the
treatment fluids of the present invention in an amount sufficient to provide,
inter alia, the
desired degree of crosslinking between molecules of the gelling agent. In
certain
embodiments, the crosslinking agent may be present in the treatment fluids of
the present
invention in an amount in the range of from about 0.0005% to about 0.2% by
weight of the
treatment fluid. In certain embodiments, the crosslinking agent may be present
in the
treatment fluids of the present invention in an amount in the range of from
about 0.001% to
about 0.05% by weight of the treatment fluid. One of ordinary skill in the
art, with the
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14
benefit of this disclosure, will recognize the appropriate amount of
crosslinking agent to
include in a treatment fluid of the present invention based on, among other
things, the
temperature conditions of a particular application, the type of gelling agents
used, the
molecular weight of the gelling agents, the desired degree of viscosification,
and/or the pH of
the treatment fluid.
[0052] In an embodiment, a base fluid may contain a gel breaker, which may
be useful for reducing the viscosity of the viscosified fracturing fluid at a
specified time. A
gel breaker may comprise any compound capable of lowering the viscosity of a
viscosified
fluid. The term "break" (and its derivatives) as used herein refers to a
reduction in the
viscosity of the viscosified treatment fluid, e.g., by the breaking or
reversing of the crosslinks
between polymer molecules or some reduction of the size of the gelling agent
polymers. No
particular mechanism is implied by the term. Suitable gel breaking agents for
specific
applications and gelled fluids are known to one skilled in the arts.
Nonlimiting examples of
suitable breakers include oxidizers, peroxides, enzymes, acids, and the like.
Some viscosified
fluids also may break with sufficient exposure of time and temperature.
[0053] In some embodiments, the fracturing fluid or a fluid used to place a
gravel pack may comprise a plurality of proppant particulates, inter alia, to
stabilize the
fractures created or enhanced. Particulates suitable for use in the present
invention may
comprise any material suitable for use in subterranean operations. Suitable
materials for
these particulates may include, but are not limited to, sand, gravel, bauxite,
ceramic materials,
glass materials, polymer materials, polytetrafluoroethylene materials, 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, alumina, 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 mean particulate size
generally
may range from about 2 mesh (11.2 mm) to about 400 mesh (0.037 mm) on the U.S.
Sieve
Series; however, in certain circumstances, other mean particulate sizes may be
desired and
will be entirely suitable for practice of the present invention. In particular
embodiments,
preferred mean particulates size distribution ranges are one or more of 6/12
(3.35/1.68 mm),
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8/16 (2.38/1.2 mm), 12/20 (1.68/0.85 mm), 16/30 (1.2/0.60 mm), 20/40(0.85/0.42
mm),
30/50 (0.60/0.30 mm), 40/60 (0.42/0.25 mm), 40/70 (0.42/0.21 mm), or 50/70
mesh
(0.30/0.21 mm). 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 (such as cubic materials),
and mixtures
thereof. Moreover, fibrous materials, that may or may not be used to bear the
pressure of a
closed fracture, may be included in certain embodiments of the present
invention. 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.
In certain embodiments, the particulates may be present in the fluids of the
present invention
in an amount in the range of from about 0.5 pounds per gallon ("ppg") (0.06
kgl-1) to about
30 ppg (3.6 kg-1) by volume of the treatment fluid.
[0054] A method of the present invention may include treating a subterranean
formation with a first treatment fluid, where the first treatment fluid treats
a first treated zone;
introducing a degradable diverting material into the subterranean formation;
and treating the
subterranean formation with a second treatment fluid, where the degradable
diverting
material diverts at least a portion of the second treatment fluid away from
the first treated
zone. In an embodiment, the treatment of the formation may be a fracturing
treatment
performed with a fracturing fluid. In this embodiment, the degradable
diverting material may
be used to divert fracturing fluid to untreated perforations in order to
create a plurality of
fractures in the subterranean formation.
[0055] In another embodiment, a method of the present invention may include
introducing the treating fluid into the subterranean zone to create a
fracture. A degradable
diverting material may then be packed in the perforation tunnels wherein it
may degrade over
time. A treating fluid may be introduced into the subterranean zone by way of
the perforation
tunnels, wherein it may be diverted by the degradable diverting material and
create another
fracture. The degradable diverting material may then degrade when exposed to
the
conditions in the subterranean zone.
[0056] An exemplary well completed in a subterranean formation is shown in
Figure la. As shown, a well bore 10 may penetrate a hydrocarbon-bearing zone
12. Even
though Figure 1 depicts the well bore 10 as a vertical well bore, the methods
of the present
invention may be suitable for use in deviated, horizontal, or otherwise formed
portions of
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16
well bores. Moreover, as those of ordinary skill in the art will appreciate,
exemplary
embodiments of the present invention may be applicable for the treatment of
both production
and injection wells. In the illustrated embodiment, well bore 10 may be lined
with casing 16
that may be cemented to the subterranean formation to create a sheath of
cement 18. A
completed well may include perforations 22 in an interval of the well bore 10.
The
perforations 22 may generally comprise holes or passageways through the casing
16 and the
cement 18 into the subterranean formation 12. Perforations 22 may generally be
formed
using perforating guns, which fire shaped charges from within the well bore 10
to form the
perforations 22. In another embodiment shown in Figure lb, a jetting tool may
be used create
a perforation by utilizing a focused fluid stream containing an abrasive to
erode one or more
perforations 22 into the subterranean formation 12. The resulting perforations
22 may
include perforation tunnels 20 that extend outward from the casing 16 and
cement 18 into the
formation 12. In an embodiment, the perforations 22 may generally range in
size from about
1/10 of an inch (2.5 mm) to about 1.5 inches (37.5 mm) in diameter. The
perforation tunnels
20 may extend through the casing 16 into the subterranean formation 12 from
about 6 inches
(15 cm) to about 36 inches (90 cm). As shown in Figure lb, a well may also
include a work
string 14 disposed within the well for disposing tools within the well and
delivering fluids or
materials to a zone within the subterranean formation 12. For example, the
work string 14
may include, but is not limited to, coiled tubing, jointed pipe, a wireline,
or a slickline. A
variety of tools may be disposed within the well bore 10 using the work string
14 including,
but not limited to, packers, plugs, perforating tools, and injection tools,
such as jetting tools.
[0057] In an embodiment of the present invention, a variety of treatments may
be performed using the degradable diverting materials. Suitable subterranean
applications
may include, but are not limited to, drilling operations, production
stimulation operations
(e.g., hydraulic fracturing), and well completion operations (e.g., gravel
packing or
cementing). These treatments may generally be applied to the well bore and
formation
through the perforations in the casing. Each of these treatments may benefit
from the ability
to divert a portion of a treatment fluid flow from one or more perforations to
other
perforations using degradable diverting materials. The diversion of the
treatment fluids may
help ensure that the treatment fluids are more uniformly distributed among the
target
perforations or treatment interval than if the degradable diverting materials
were not used.
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17
[0058] In an embodiment, the treatment may be a fracturing operation. In this
embodiment, one or more fractures may be created or enhanced through the
subterranean
formation to at least partially increase the effective permeability of the
surrounding
formation. An exemplary well bore with a fracture is shown in Figure 2a. The
fracturing of
the subterranean formation 12 may be accomplished by any suitable methodology.
By way
of example, a hydraulic-fracturing treatment may be used that includes
introducing a
fracturing fluid into the target zone in the well bore 10 at a pressure
sufficient to create or
enhance one or more fractures 30. In an exemplary embodiment, the fracturing
fluid may be
introduced to the target zone by pumping the fluid through the casing 16 to
the target zone.
In certain exemplary embodiments, as shown in Figure 2b, the fracturing step
may utilize a
jetting tool 36. By way of example, the jetting tool 36 may be used to
initiate one or more
fractures 30 in the subterranean formation 12 through one or more perforations
22 in the
casing 16 by way of jetting a fluid through the perforations 22, the
perforation tunnels 20, and
against the formation 12. A fracturing fluid may also be pumped down through
the annulus
38 between the work string 14 and the casing 16 and then into the formation 12
at a pressure
sufficient to create or enhance the one or more fractures 30. The fracturing
fluid may be
pumped down through the annulus 38 concurrently with the jetting of the fluid.
One example
of a suitable fracturing treatment is CobraMaxsm Fracturing Service, available
from
Halliburton Energy Services, Inc. In another embodiment, a packer (not shown)
may be
placed at or near one or more perforations 22 in the casing 16. A fracturing
fluid may then be
pumped down through the work string 14 into the formation 12 at a pressure
sufficient to
create or enhance the one or more fractures 30. In certain exemplary
embodiments, the
fracturing fluid may comprise a viscosified fluid (e.g., a gel or a
crosslinked gel). In certain
embodiments, the fracturing fluid further may comprise proppant 32 that is
deposited in the
one or more fractures 30 to generate propped fractures. In certain exemplary
embodiments,
the proppant 32 may be coated with a consolidating agent (e.g., a curable
resin, a tackifying
agent, etc.) so that the coated proppant forms a bondable, permeable mass in
the one or more
fractures , for example, to mitigate proppant flow back when the well is
placed into
production. By way of example, the proppant may be coated with an ExpediteTm
resin
system, available from Halliburton Energy Services, Inc. In an embodiment
shown in Figure
3a, a final slug of proppant may be placed in the well bore to create a
proppant plug or bridge
34 across the well bore covering one or more perforations 22. As shown in
Figure 3b, a
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jetting tool may be used to place the proppant plug or bridge 34 across the
well bore.
Proppant plugs may be used in deviated, vertical, or horizontal wells.
[0059] Optionally, or in conjunction with, the fracturing treatment, one or
more wash fluids may be used to wash the well bore, the perforation tunnels,
or both. When
used, the wash fluids may be introduced into the well bore after the
fracturing treatment has
ceased and the fracture has been allowed to close. The wash fluid may, inter
alia, be used to
displace any excess proppant in the well bore, the perforation tunnels, or
both. However, the
washing step may be limited in duration in order to ensure that the proppant
disposed in a
fracture is not displaced. Generally, the wash fluid may be any fluid that
does not
undesirably react with the other components used or the subterranean
formation. For
example, the wash fluid may be an aqueous-based fluid (e.g., a brine or
produced water), a
non-aqueous based fluid (e.g., kerosene, toluene, diesel, or crude oil), or a
gas (e.g., nitrogen
or carbon dioxide).
[0060] In an embodiment, the fracturing of a perforated zone in a well bore
may generally treat one or more perforations that have the least resistance to
fracturing fluid
flow. In general, a fracture created during a fracturing treatment will
initiate in the zone or
perforation with the lowest stress and propagate away from the well bore in
length and height
based on several factors. The factors may include, inter alia, stresses in the
adjacent zones,
fluid leakoff, pump rate, fluid used, and formation temperature. A fracture
created during a
fracturing treatment may not intersect all of the productive zones in a
perforated interval. As
such, the initial fracturing treatment in the well bore may not fracture all
of the zones desired
in the formation, and any subsequent attempts at refracturing may result in
the existing
fractures taking fluid without opening new fractures. The use of proppant in
the fractures
may decrease the resistance of the existing fractures to fluid flow as the
proppant may create
a permeable passage for fluids.
[0061] A degradable diverting material may be placed in the subterranean
zone or packed into perforation tunnels in the subterranean formation by
introducing a carrier
fluid containing the degradable diverting materials into the subterranean
zone. The
degradable diverting material may be carried into the well bore using a
carrier fluid. The
carrier fluid may contain a gelling agent or viscosifier as necessary in order
to suspend the
degradable diverting material in solution. A variety of carrier fluids may be
utilized
including, but not limited to, fresh water, brines, seawater, formation water,
or a combination
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thereof. In an embodiment, the carrier fluid may be a base fluid used in
fracturing treatments,
including optional additives commonly used in base fluid compositions. In an
embodiment,
the carrier fluid and the degradable diverting material may be combined to
form a slurry and
pumped into the well bore through the work string or the annular space between
the work
string and the casing. The slurry may be pumped into the well bore below the
fracture
pressure of the formation and at sub-fracture pumping rates. Such a fluid flow
rate may be
sufficient to force fluid into the path of least resistance (e.g., an existing
fracture), but not
sufficient to create or enhance a fracture. This type of flow rate is commonly
referred to as a
matrix flow rate. In an embodiment, the slurry containing the degradable
diverting material
may be pumped at a matrix flowrate through a perforation and into a
perforation tunnel. The
perforation tunnel, the fracture, or both may contain proppant particulates
that may act as a
filter, screening the degradable diverting material out of the carrier fluid
as the slurry passes
through. This process may result in a layer or pack of degradable diverting
material forming
on the proppant particulates, the perforation tunnel walls, or both. Pumping
at matrix flow
rates may ensure that the degradable diverting material is not carried into
the fracture where it
may not be capable of diverting a subsequent treatment fluid away from the
fracture. Once
the degradable diverting material is disposed within the perforation tunnel,
the resistance to
flow through the perforation may increase, causing a back pressure that may be
measured at
the surface of the well. A back pressure at the surface sufficient to allow
another fracture to
be formed in the subterranean formation, which may be below the fracture
pressure of the
formation, may indicate that a sufficient plug of degradable diverting
material has been
placed in the well bore.
[0062] In another embodiment shown in Figures 3a and 3b, the fracturing
treatment may result in the placement of a proppant plug 34 within the well
bore, which may
cover one or more perforations 22. The proppant plug 34 may be disposed in the
well bore
by introducing a fracturing fluid containing a slug of proppant particulates
32 as the
fracturing fluid flow rate approaches a matrix flow rate. When a matrix flow
rate is achieved,
the proppant 32 may no longer be carried into the fracture, but rather form a
plug 34 in the
well bore. Methods of forming proppant plugs or bridges are known to those
skilled in the
arts. In this embodiment, a slurry containing a degradable diverting material
may be pumped
through the proppant plug into the perforations at a matrix flow rate,
resulting in the
degradable diverting material accumulating on the proppant plug. The resulting
layer of
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degradable diverting material 40 may be able to divert at least a portion of
the fluid in the
well bore away from the proppant plug and, consequently, the perforations
covered by the
proppant plug. Such diversion may result in a back pressure build up that may
be detected at
the surface to indicate that the degradable diverting material has been
substantially placed in
the well bore. A proppant plug 34 with a degradable diverting material 40
disposed thereon
may be useful in deviated, vertical, and horizontal wells.
.
[0063] In an embodiment, the subterranean formation may be treated after the
degradable diverting material has been placed in the well bore. As understood
by those
skilled in the art, any one of a variety of treating fluids may be introduced
into a subterranean
formation in accordance with this invention. Due to the degradable diverting
material being
placed in the well bore or a plug, a treating fluid may be at least partially
diverted into
another area of the formation, which may be one or more perforations that have
not had a
degradable diverting material placed therein. In an embodiment, a perforation,
a perforation
tunnel, or a proppant plug covering one or more perforations that has a
degradable diverting
material placed therein may have an increased resistance to flow relative to a
perforation or
perforation tunnel that has not had a degradable diverting material placed
therein. As such, a
treating fluid introduced into a subterranean formation may flow to a new zone
or perforation
that has the least resistance to flow, treating the new zone.
[0064] In an embodiment, the treatment may be a fracturing treatment using a
fracturing fluid. An exemplary embodiment of a well bore that may be treated
with a fluid
after having degradable diverting material being placed therein is shown in
Figures 4a and
4b. As discussed above, the fracturing of the subterranean formation 12 may be
accomplished by any suitable methodology. For example, a hydraulic-fracturing
treatment
may be used that includes introducing a fracturing fluid into the target zone
in the well bore
10 at a pressure sufficient to create or enhance one or more fractures 30, 42.
In another
embodiment shown in Figure 4b, a fracturing fluid may also be pumped down
through the
annulus 38 between the work string 14 and the casing 16 and then into the
formation 12 at a
pressure sufficient to create or enhance the one or more fractures 30, 42. In
still another
embodiment, a packer (not shown) may be used to pump down through the work
string 14
into the formation 12 at a pressure sufficient to create or enhance the one or
more fractures
30, 42. A fracture 30, 42 may be formed in the zone or perforation with the
least resistance,
and the resistance in the treated zone may decrease upon the formation of a
fracture. Upon
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21
introducing the fracturing fluid into the zone, the perforations 44 or
perforation tunnels 46
that are packed with the degradable diverting material 40 may present a
greater resistance to
flow than an untreated perforation 22 or perforation tunnel 20, thus directing
the fracturing
fluid to an untreated perforation 22 or perforation tunnel 20. As similarly
shown in Figures
3a and 3b, a proppant plug 34 with a degradable diverting material 40 disposed
thereon may
present a greater resistance to flow than an untreated perforation 22 or
perforation tunnel 20,
thus directing the fracturing fluid to an untreated perforation 22 or
perforation tunnel 20.
This method may be used to at least partially divert the fracturing fluid into
a perforation 22
or perforation tunnel 20 that has not been treated with a degradable diverting
material 40.
The fracturing fluid may then create or enhance a new fracture 42 in the zone
of interest.
[0065] The process of treating a zone in a well bore followed by introducing a
degradable diverting material into the zone may be repeated as many times as
necessary to
treat as many zones as desired. Each treatment may affect one or more
perforations or
perforation tunnels, and a repetition of the method may be used to ensure that
all of the
perforations, perforation tunnels, or zones in the well bore are treated. Such
repetition of the
method may be performed without moving the work string or placing a plug in
the well bore,
increasing efficiency and reducing costs. For example, in an embodiment in
which the
treatment is a fracturing treatment, the method may be repeated in order to
create a fracture in
each perforation in each zone of interest in the subterranean formation.
[0066] After the treating fluid has been used to treat the zone as desired,
the
degradable diverting material may at least partially degrade, allowing the
formation fluids to
be produced. The degradable diverting materials may degrade according to a
variety of
mechanisms depending on factors such as well bore conditions (e.g.,
temperature, pressure,
fluid composition, etc.), and any externally introduced fluids or chemicals.
For example,
some of the polymeric compositions useful as degradable diverting materials
may degrade in
water released from the formation or introduced during a treatment. When the
degradable
diverting material is self-degradable, the degradable diverting material may
at least partially
degrade heated in the subterranean zone. If the subterranean formation does
not contain
water that may be released, an aqueous fluid may be introduced into the
formation to aid in
degradation of the diverting material. For example, salt water, sea water, or
steam may be
introduced into the subterranean formation to aid in the degradation of the
degradable
diverting material. Thus the degradable diverting material may be suitable
even when non-
CA 02751528 2013-03-06
. .
22
aqueous treating fluids are utilized or when an aqueous treating fluid has
dissipated within
the formation or when an aqueous fluid has otherwise been removed from the
formation
such as by flowback. In an embodiment, a chemical composition may be
introduced into
the formation to aid in the degradation of the degradable diverting material.
Suitable
compositions may include, but are not limited to, acidic fluids, basic fluids,
solvents,
steam, or a combination thereof.
[0067] In another embodiment, other treatments know to those skilled in the
arts may be performed along with those of the disclosed method. For example, a
wash fluid
may be used to clean the well bore after degradation of the degradable
diverting material to
clear the well bore of any remaining degradable diverting material or proppant
that may
impede fluid flow through the well bore.
[0068] Therefore, the present invention is well adapted to attain the ends
and advantages mentioned as well as those that are inherent therein. 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. 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. Also, the terms in the claims have their
plain, ordinary
meaning unless otherwise explicitly and clearly defined by the patentee.
