U.S. patent application number 12/378935 was filed with the patent office on 2010-08-26 for method for diversion of hydraulic fracture treatments.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Dwight D. Fulton, Shane L. Milson, John Terracina.
Application Number | 20100212906 12/378935 |
Document ID | / |
Family ID | 42154624 |
Filed Date | 2010-08-26 |
United States Patent
Application |
20100212906 |
Kind Code |
A1 |
Fulton; Dwight D. ; et
al. |
August 26, 2010 |
Method for diversion of hydraulic fracture treatments
Abstract
Disclosed herein are methods that include a method for treating
a well bore including treating a subterranean formation with a
first treatment fluid, wherein the first treatment fluid treats a
first treated zone. A degradable diverting material may then be
introduced into the subterranean formation. The subterranean
formation may be treated 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.
Inventors: |
Fulton; Dwight D.; (Duncan,
OK) ; Terracina; John; (Duncan, OK) ; Milson;
Shane L.; (Duncan, OK) |
Correspondence
Address: |
ROBERT A. KENT
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
42154624 |
Appl. No.: |
12/378935 |
Filed: |
February 20, 2009 |
Current U.S.
Class: |
166/308.5 |
Current CPC
Class: |
C09K 8/68 20130101; C09K
8/62 20130101 |
Class at
Publication: |
166/308.5 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A method for treating a well bore comprising: 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.
2. The method of claim 1 wherein the degradable diverting material
comprises at least one substance selected from the group consisting
of: a, a chitin, a chitosan; a protein, an aliphatic polyester a
poly(lactide), a poly(lactic acid); a poly(glycolide), a
poly(.epsilon.-caprolactones), a poly(hydroxybutyrate), a
poly(anhydride), an aliphatic polycarbonate; a poly(orthoester), a
poly(amino acid), a poly(ethylene oxide), a polyphosphazene, and a
derivative thereof.
3. The method of claim 1 wherein the degradable diverting material
comprises a particulate, wherein the particulate has a diameter of
about 100 mesh to about one-quarter of one inch.
4. The method of claim 1 wherein the first treatment fluid
comprises at least one fluid selected from the group consisting of:
an acid solutions, a scale inhibitor material solutions, a water
blocking material solutions, a clay stabilizer solutions, a
chelating agent solutions, a surfactant solutions, a fracturing
fluid, a paraffin removal solution, an oil based foam, a drilling
fluid, and a derivative thereof.
5. The method of claim 1 further comprising: introducing a first
treatment fluid to the subterranean formation prior to introducing
the degradable diverting material into the subterranean
formation.
6. The method of claim 1 further comprising: reintroducing the
degradable diverting material into the subterranean formation after
the second treatment fluid; and treating the subterranean formation
with a third treatment fluid, wherein the degradable diverting
material diverts at least a portion of the third treatment
fluid.
7. The method of claim 1 further comprising: degrading at least a
portion of the degradable diverting material to allow it to be
removed from the well bore.
8. 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.
9. The method of claim 8 wherein the degradable diverting material
comprises at least one substance selected from the group consisting
of: a, a chitin, a chitosan; a protein, an aliphatic polyester a
poly(lactide), a poly(lactic acid); a poly(glycolide), a
poly(.epsilon.-caprolactones), a poly(hydroxybutyrate), a
poly(anhydride), an aliphatic polycarbonate; a poly(orthoester), a
poly(amino acid), a poly(ethylene oxide), a polyphosphazene, and a
derivative thereof.
10. The method of claim 8 wherein the introducing a degradable
diverting material into the first perforation tunnel occurs at a
matrix flow rate.
11. The method of claim 8 further comprising: introducing the
degradable diverting material into the subterranean formation after
the second treatment fluid; and treating the subterranean formation
with a third treatment fluid, wherein the degradable diverting
material diverts at least a portion of the third treatment fluid
away from the first treated zone and the second treated zone.
12. The method of claim 8 further comprising: degrading at least a
portion of the degradable diverting material to allow it to be
removed from the well bore.
13. The method of claim 8 wherein the fracturing the subterranean
formation comprises using a jetting tool to create or enhance the
first fracture.
14. The method of claim 10 wherein the proppant particulate is
substantially coated with a resin or tackifying agent.
15. 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 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.
16. The method of claim 15 wherein the degradable diverting
material comprises at least one substance selected from the group
consisting of: a, a chitin, a chitosan; a protein, an aliphatic
polyester a poly(lactide), a poly(lactic acid); a poly(glycolide),
a poly(.epsilon.-caprolactones), a poly(hydroxybutyrate), a
poly(anhydride), an aliphatic polycarbonate; a poly(orthoester), a
poly(amino acid), a poly(ethylene oxide), a polyphosphazene, and a
derivative thereof.
17. The method of claim 16 wherein the degradable diverting
material comprises a plasticizer selected from the group defined by
the formula: ##STR00004## wherein R comprises at least one
substance selected from the group consisting of: hydrogen, alkyl,
aryl, alkylaryl, acetyl, and a derivative thereof; where R'
comprises at least one substance selected from the group consisting
of: hydrogen, alkyl, aryl, alkylaryl, acetyl, and a derivative
thereof; wherein R and R' cannot both be hydrogen; and wherein q is
an integer between about 2 and 75.
18. The method of claim 15 further comprising: washing the well
bore with a washing fluid.
19. The method of claim 15 further comprising: degrading at least a
portion of the degradable diverting material to allow it to be
removed from the well bore.
20. The method of claim 15 wherein the fracturing the subterranean
formation comprises using a jetting tool to create or enhance the
first fracture.
21. The method of claim 15 wherein the fracturing fluid comprises
least one substance selected from the group consisting of: a fluid
loss control additive, a gelling agent, a viscosifier, a gel
stabilizer, a gas, a salt, a pH-adjusting agent, a corrosion
inhibitor, a dispersant, a flocculent, an acid, a foaming agent, an
antifoaming agent, an H.sub.2S scavenger, a lubricant, an oxygen
scavenger, a weighting agent, a scale inhibitor, a surfactant, a
catalyst, a clay control agent, a biocide, a friction reducer, a
particulate, and a derivative thereof.
Description
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. Similarly, sand plugs or bridges are cleaned
out for production; sealing balls are often recovered for
production. These may entail additional steps in the treatment
process leading to additional time and expenses.
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] An embodiment of 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.
[0006] Another embodiment of 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.
[0007] Still another embodiment of 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 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.
[0008] The features and advantages of the present invention will be
apparent to those skilled in the art. While numerous changes may be
made by those skilled in the art, such changes are within the
spirit of the invention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] 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.
[0010] FIG. 1a illustrates a cross-sectional, side view of an
exemplary embodiment of the present invention.
[0011] FIG. 1b 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.
[0012] FIG. 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.
[0013] FIG. 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.
[0014] FIG. 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.
[0015] FIG. 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.
[0016] FIG. 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.
[0017] FIG. 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
[0018] 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.
[0019] 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.
[0020] 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.
[0021] 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.
[0022] 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.
[0023] "Zone," as used herein, simply refers to a portion of the
formation and does not imply a particular geological strata or
composition.
[0024] 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 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.
[0025] 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.
[0026] 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.
[0027] Aliphatic polyesters may degrade chemically, inter alia, by
hydrolytic cleavage. Hydrolysis may be catalyzed by either, acids
or bases. Generally, during the 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.
[0028] Suitable aliphatic polyesters have the general formula of
repeating units shown below:
##STR00001##
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.
[0029] 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.
[0030] 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:
##STR00002##
where m is an integer: 2.ltoreq.m.ltoreq.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 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 .epsilon.-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.
[0031] 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:
##STR00003##
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.ltoreq.q.ltoreq.75; and mixtures thereof.
Preferably q may be an integer: 2.ltoreq.q.ltoreq.10. As used
herein the term "derivatives of oligomeric lactic acid" may include
derivatives of oligomeric lactide.
[0032] 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 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.
[0033] 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.
[0034] 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, the
relevant disclosures of which are incorporated herein by reference
in their entirety.
[0035] 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. 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).
[0036] 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(phenyl)actide) may degrade at about 1/5th
of the rate of racemic poly(lactide) at a pH of about 7.4 at
55.degree. 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.
[0037] 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.degree. F. to about 150.degree. F., 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.
[0038] 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 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 to about one-quarter of an
inch.
[0039] 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.
[0040] 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.
[0041] 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.
[0042] 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 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.
[0043] 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., KCl),
pH-adjusting agents (e.g., buffers), corrosion inhibitors,
dispersants, flocculants, acids, foaming agents, antifoaming
agents, H.sub.2S 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.
[0044] 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 crosslinking agent, and/or to
reduce the viscosity of the treatment fluid (e.g., activate a
breaker, deactivate a crosslinking 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, crosslinking
agents, 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.
[0045] 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 U.S. Pat. Nos. 4,982,793; 5,067,565; and 5,122,549, the relevant
disclosures of which are incorporated herein by reference.
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.
[0046] 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.
[0047] 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 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.
[0048] 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 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.
[0049] 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.
[0050] 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 to about 400
mesh 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, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60,
40/70, or 50/70 mesh. It should be understood that the term
"particulate," as used in this disclosure, includes all known
shapes of materials, including substantially spherical materials,
fibrous materials, polygonal materials (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") to about 30 ppg by volume of
the treatment fluid.
[0051] 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.
[0052] 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.
[0053] An exemplary well completed in a subterranean formation is
shown in FIG. 1a. As shown, a well bore 10 may penetrate a
hydrocarbon-bearing zone 12. Even though FIG. 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 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
FIG. 1b, 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 to about 1.5 inches in diameter.
The perforation tunnels 20 may extend through the casing 16 into
the subterranean formation 12 from about 6 inches to about 36
inches. As shown in FIG. 1b, 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.
[0054] 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.
[0055] 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 FIG.
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 FIG. 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 CobraMax.sup.SM 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
Expedite.TM. resin system, available from Halliburton Energy
Services, Inc. In an embodiment shown in FIG. 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 FIG. 3b, a 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.
[0056] 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).
[0057] 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.
[0058] 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 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.
[0059] In another embodiment shown in FIGS. 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 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.
[0060] 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.
[0061] 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 FIGS. 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 FIG. 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 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 FIGS. 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.
[0062] 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.
[0063] 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-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.
[0064] 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.
[0065] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present invention. 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.
* * * * *