U.S. patent application number 13/662055 was filed with the patent office on 2014-05-01 for wellbore servicing materials and methods of making and using same.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Tingji TANG.
Application Number | 20140116701 13/662055 |
Document ID | / |
Family ID | 49301684 |
Filed Date | 2014-05-01 |
United States Patent
Application |
20140116701 |
Kind Code |
A1 |
TANG; Tingji |
May 1, 2014 |
WELLBORE SERVICING MATERIALS AND METHODS OF MAKING AND USING
SAME
Abstract
A method of servicing a wellbore in a subterranean formation
comprising placing a first wellbore servicing fluid comprising a
self-degrading diverter material into the wellbore wherein the
self-degrading diverter materials comprises (i) a diverting
material and (ii) a degradation accelerator; allowing the
self-degrading diverter material to form a diverter plug at a first
location in the wellbore or subterranean formation; diverting the
flow of a second wellbore servicing fluid to a second location in
the wellbore or subterranean formation; and removing the diverter
plug, wherein the first and second wellbore servicing fluids may be
the same or different.
Inventors: |
TANG; Tingji; (Spring,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
49301684 |
Appl. No.: |
13/662055 |
Filed: |
October 26, 2012 |
Current U.S.
Class: |
166/292 ;
507/260 |
Current CPC
Class: |
C09K 8/725 20130101;
E21B 33/13 20130101; C09K 8/50 20130101; C09K 8/68 20130101; C09K
8/703 20130101 |
Class at
Publication: |
166/292 ;
507/260 |
International
Class: |
E21B 33/13 20060101
E21B033/13; C09K 8/72 20060101 C09K008/72 |
Claims
1. A method of servicing a wellbore in a subterranean formation
comprising: placing a first wellbore servicing fluid comprising a
self-degrading diverter material into the wellbore wherein the
self-degrading diverter material is a composite comprising (i) a
diverting material and (ii) a degradation accelerator; allowing the
self-degrading diverter material to form a diverter plug at a first
location in the wellbore or subterranean formation; diverting the
flow of a second wellbore servicing fluid to a second location in
the wellbore or subterranean formation; and removing the diverter
plug, wherein the first and second wellbore servicing fluids may be
the same or different.
2. The method of claim 1 wherein the diverting material comprises a
degradable material.
3. The method of claim 2 wherein the degradable material comprises
a degradable polymer.
4. The method of claim 3 wherein the degradable polymer comprises
polysaccharides; lignosulfonates; chitins; chitosans; proteins;
proteinous materials; fatty alcohols; fatty esters; fatty acid
salts; aliphatic polyesters; poly(lactides); poly(glycolides);
poly(.epsilon.-caprolactones); polyoxymethylene; polyurethanes;
poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates;
polyvinyl polymers; acrylic-based polymers; poly(amino acids);
poly(aspartic acid); poly(alkylene oxides); poly(ethylene oxides);
polyphosphazenes; poly(orthoesters); poly(hydroxy ester ethers);
polyether esters; polyester amides; polyamides;
polyhydroxyalkanoates; polyethyleneterephthalates;
polybutyleneterephthalates; polyethylenenaphthalenates, or
combinations thereof.
5. The method of claim 4 wherein the aliphatic polyester comprises
a compound represented by general formula I: ##STR00005## where n
is an integer ranging from about 75 to about 10,000 and R comprises
hydrogen, an alkyl group, an aryl group, alkylaryl groups, acetyl
groups, heteroatoms, or combinations thereof.
6. The method of claim 3 wherein the degradable polymer comprises
polylactic acid.
7. The method of claim 1 wherein the degradation accelerator
comprises an inorganic base, an organic base, a base precursor, an
acid, acid precursor, or combinations thereof.
8. The method of claim 7 wherein the inorganic base comprises
sodium hydroxide, potassium hydroxide, magnesium hydroxide,
ammonium hydroxide, calcium carbonate, sodium carbonate, sodium
bicarbonate, magnesium oxide, or combinations thereof.
9. The method of claim 7 wherein the organic base comprises amines,
ethylene diamine, alkanolamines, ethanolamine, thriethanolamine,
secondary amines, tertiary amines, oligomers of aziridine,
triethylene tetramine, tetraethylene pentamine, polyethyleneimine,
or combinations thereof.
10. The method of claim 7 wherein the acid comprises formic acid;
acetic acid; lactic acid; glycolic acid; oxalic acid; propionic
acid; butyric acid; monochloroacetic acid; dichloroacetic acid;
trichloroacetic acid; hydrochloric acid; nitric acid; sulphuric
acid; sulphonic acid; sulphinic acid; phosphoric acid; phosphorous
acid; phosphonic acid; phosphinic acid; sulphamic acid;
p-toluenesulfonic acid; or combinations thereof.
11. The method of claim 7 wherein the acid precursor comprises
aliphatic polyesters; glucono-delta-lactone; glucoheptonic lactone;
poly(.epsilon.-caprolactones); poly(hydroxybutyrates);
poly(anhydrides); aliphatic polycarbonates; poly(amino acids);
polyphosphazenes; poly(ortho esters); orthoesters; monoethylene
monoformate, monoethylene diformate, ethylene glycol monoformate,
ethylene glycol diformate, diethylene glycol monoformate,
diethylene glycol diformate, triethylene glycol diformate, glyceryl
monoformate, glyceryl diformate, glyceryl triformate; formate
esters of pentaerythritol, tri-n-propyl orthoformate, tri-n-butyl
orthoformate, methyl lactate, ethyl lactate, propyl lactate, butyl
lactate, trilactin, polylactic acid, poly(lactides), methyl
acetate, ethyl acetate, propyl acetate, butyl acetate, monoacetin,
diacetin, triacetin, glyceryl diacetate, glyceryl triacetate,
tripropionin (a triester of propionic acid and glycerol), methyl
glycolate, ethyl glycolate, propyl glycolate, butyl glycolate,
poly(glycolides), or combinations thereof.
12. The method of claim 1 wherein the degradation accelerator is
encapsulated.
13. The method of claim 1 wherein the self-degrading diverter
material is present in the wellbore servicing fluid in an amount of
from about 0.01 ppg to about 6 ppg.
14. The method of claim 1 wherein the first wellbore servicing
fluid comprises a diverting fluid and the second wellbore servicing
fluid comprises a fracturing fluid.
15. The method of claim 14 wherein the first portion of the
fracturing fluid is placed into the formation at the first location
before the diverter fluid is placed in the formation at the first
location and a second portion of the fracturing fluid is diverted
from the first location to the second location.
16. The method of claim 1 wherein the self-degrading diverter
material has a particle size of from about 0.1 microns to about
3000 microns.
17. (canceled)
18. (canceled)
19. A method of servicing a wellbore in a subterranean formation
comprising: placing a wellbore servicing fluid into the
subterranean formation at a first location; plugging the first
location with a self-degrading diverter material that is a
composite comprising a diverting material and a degradation
accelerator such that all or a portion of the wellbore servicing
fluid is diverted to a second location in the subterranean
formation; placing the wellbore servicing fluid into the
subterranean formation at the second location; and allowing the
self-degrading diverter material to degrade to provide a flowpath
from the subterranean formation to the wellbore for recovery of
resources from the subterranean formation.
20. The method of claim 19 wherein the wellbore servicing fluid is
a fracturing fluid and the subterranean formation is fractured
thereby at the first and second locations.
21. The method of claim 1 wherein the self-degrading diverter
material is mechanically sized.
22. The method of claim 1 wherein the self-degrading diverter
material is a shaped particle.
23. The method of claim 1 wherein the self-degrading diverter
material degrades in a time range of about 4 hours.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND
[0003] 1. Field
[0004] This disclosure relates to methods of servicing a wellbore.
More specifically, it relates to wellbore servicing fluids
comprising degradable materials and methods of making and using
same.
[0005] 2. Background
[0006] Natural resources (e.g., oil or gas) residing in the
subterranean formation may be recovered by driving resources from
the formation into the wellbore using, for example, a pressure
gradient that exists between the formation and the wellbore, the
force of gravity, displacement of the resources from the formation
using a pump or the force of another fluid injected into the well
or an adjacent well. The production of fluid in the formation may
be increased by hydraulically fracturing the formation. That is, a
viscous fracturing fluid may be pumped down the wellbore at a rate
and a pressure sufficient to form fractures that extend into the
formation, providing additional pathways through which the oil or
gas can flow to the well.
[0007] Unfortunately, water rather than oil or gas may eventually
be produced by the formation through the fractures therein. To
provide for the production of more oil or gas, a fracturing fluid
may again be pumped into the formation to form additional fractures
therein. However, the previously used fractures first must be
plugged to prevent the loss of the fracturing fluid into the
formation via those fractures.
[0008] Traditional fracturing operations, also termed plug and
perforate operations, to increase the productivity of the
subterranean formation employ a perforation of the subterranean
formation followed by setting of a fracturing plug with typical
operation times ranging from 3-5 hours. Additionally to achieve a
user and/or process desired goal, the fracturing may need to be
repeated numerous times resulting in lengthy equipment stand by
times. Once the process is complete the fracturing plugs are
typically removed, for example by drilling out. Alternative methods
employ processes such as the ACESSFRAC PD service which utilizes
perforation in conjunction with degradable diverting materials
(e.g., BIOVERT NWB) and the resultant process provides numerous
benefits in terms of reduced operation time, reduced equipment
standby time, increased safety, reduced risk of premature setting
of the fracturing plug, avoiding the need to drill out the plug
before production and reducing the time for fluid flow back when
compared to fracture plugs which set into place. While processes
such as ACCESSFRAC PD provide advantages over the use of fracture
plugs, one challenge in these operations is that the degradable
diverting materials utilized also need to be removed prior to
production. An ongoing need exists for improved compositions and
methods for fracturing operations.
SUMMARY
[0009] Disclosed herein is a method of servicing a wellbore in a
subterranean formation comprising placing a first wellbore
servicing fluid comprising a self-degrading diverter material into
the wellbore wherein the self-degrading diverter materials
comprises (i) a diverting material and (ii) a degradation
accelerator; allowing the self-degrading diverter material to form
a diverter plug at a first location in the wellbore or subterranean
formation; diverting the flow of a second wellbore servicing fluid
to a second location in the wellbore or subterranean formation; and
removing the diverter plug, wherein the first and second wellbore
servicing fluids may be the same or different.
[0010] Also disclosed herein is a wellbore servicing fluid
comprising self-degrading diverter material wherein the
self-degrading diverter material comprises polylactide, sodium
carbonate and a carrier fluid.
[0011] Further disclosed herein is a method of servicing a wellbore
in a subterranean formation comprising placing a wellbore servicing
fluid into the subterranean formation at a first location; plugging
the first location with a self-degrading diverter material
comprising a diverting material and a degradation accelerator such
that all or a portion of the wellbore servicing fluid is diverted
to a second location in the subterranean formation; placing the
wellbore servicing fluid into the subterranean formation at the
second location; and allowing the self-degrading diverter material
to degrade to provide a flowpath from the subterranean formation to
the wellbore for recovery of resources from the subterranean
formation.
[0012] The foregoing has outlined rather broadly the features and
technical advantages of the present invention in order that the
detailed description of the invention that follows may be better
understood. Additional features and advantages of the invention
will be described hereinafter that form the subject of the claims
of the invention. It should be appreciated by those skilled in the
art that the conception and the specific embodiments disclosed may
be readily utilized as a basis for modifying or designing other
structures for carrying out the same purposes of the present
invention. It should also be realized by those skilled in the art
that such equivalent constructions do not depart from the spirit
and scope of the invention as set forth in the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] For a more complete understanding of the present disclosure
and the advantages thereof, reference is now made to the following
brief description, taken in connection with the accompanying
drawings and detailed description, wherein like reference numerals
represent like parts.
[0014] FIGS. 1A and 1B are schematics of embodiments for use of the
self-degrading diverter materials disclosed herein.
DETAILED DESCRIPTION
[0015] It should be understood at the outset that although an
illustrative implementation of one or more embodiments are provided
below, the disclosed systems and/or methods may be implemented
using any number of techniques, whether currently known or in
existence. The disclosure should in no way be limited to the
illustrative implementations, drawings, and techniques below,
including the exemplary designs and implementations illustrated and
described herein, but may be modified within the scope of the
appended claims along with their full scope of equivalents.
[0016] Disclosed herein are wellbore servicing fluids or
compositions comprising a diverting material and a degradation
accelerator. Compositions comprising a diverting material (DM) and
a degradation accelerator (DA) are herein termed self-degrading
diverter materials and designated (SDDM). Utilization of a SDDM in
the methods disclosed herein may advantageously facilitate removal
of a diverter material from a fluid flow path subsequent to the
diverter material performing its intended function.
[0017] In an embodiment, the DM comprises any material suitable for
distribution within or into a flowpath (e.g., a subterranean
flowpath within a wellbore and/or surrounding formation), for
example, so as to form a pack, a bridge, a plug or a filter cake
and thereby obstruct fluid movement via that flowpath. In an
embodiment, the DM is configured to reduce the fluid flow via a
given flowpath (i.e., reduce the fluid permeability of a point of
entry for fluids into the formation) such that fluid movement is
diverted (e.g., redirected) to another flowpath within the wellbore
and/or surrounding formation, for example during a fracturing
operation.
[0018] In an embodiment, the DM is comprised of a
naturally-occurring material. Alternatively, the DM comprises a
synthetic material. Alternatively, the DM comprises a mixture of a
naturally-occurring and synthetic material.
[0019] In an embodiment, the DM comprises a degradable material
that may undergo irreversible degradation downhole. As used herein
"degradation" refers to the separation of the material into simpler
compounds that do not retain all the characteristics of the
starting material. The terms "degradation" or "degradable" may
refer to either or both of heterogeneous degradation (or bulk
erosion) and/or homogeneous degradation (or surface erosion),
and/or to any stage of degradation in between these two. Not
intending to be bound by theory, degradation may be a result of,
inter alia, an external stimuli (e.g., heat, temperature, pH,
etc.). As used herein, the term "irreversible" means that the
degradable material, once degraded downhole, should not
recrystallize or reconsolidate while downhole.
[0020] In an embodiment, the DM comprises a degradable polymer.
Herein the disclosure may refer to a polymer and/or a polymeric
material. It is to be understood that the terms polymer and/or
polymeric material herein are used interchangeably and are meant to
each refer to compositions comprising at least one polymerized
monomer in the presence or absence of other additives traditionally
included in such materials. Examples of degradable polymers
suitable for use as the DM include, but are not limited to
homopolymers, random, block, graft, star- and hyper-branched
aliphatic polyesters, copolymers thereof, derivatives thereof, or
combinations thereof. The term "derivative" is defined herein to
include any compound that is made from one or more of the diverting
materials, for example, by replacing one atom in the diverting
material with another atom or group of atoms, rearranging two or
more atoms in the diverting material, ionizing one of the diverting
materials, or creating a salt of one of the diverting materials.
The term "copolymer" as used herein is not limited to the
combination of two polymers, but includes any combination of any
number of polymers, e.g., graft polymers, terpolymers and the
like.
[0021] In an embodiment, the degradable polymer comprises
polysaccharides; lignosulfonates; chitins; chitosans; proteins;
proteinous materials; fatty alcohols; fatty esters; fatty acid
salts; aliphatic polyesters; poly(lactides); poly(glycolides);
poly(.epsilon.-caprolactones); polyoxymethylene; polyurethanes;
poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates;
polyvinyl polymers; acrylic-based polymers; poly(amino acids);
poly(aspartic acid); poly(alkylene oxides); poly(ethylene oxides);
polyphosphazenes; poly(orthoesters); poly(hydroxy ester ethers);
polyether esters; polyester amides; polyamides;
polyhydroxyalkanoates; polyethyleneterephthalates;
polybutyleneterephthalates; polyethylenenaphthalenates, and
copolymers, blends, derivatives, or combinations thereof. In an
embodiment, the DM comprises BIOFOAM. BIOFOAM is a biodegradable
plant-based foam commercially available from Synbra.
[0022] In an embodiment, the degradable polymer comprises
substituted or unsubstituted lactides, glycolides, polylactic acid
(PLA), polyglycolic acid (PGA), copolymers of PLA and PGA,
copolymers of glycolic acid with other hydroxy-, carboxylic acid-,
or hydroxycarboxylic acid-containing moieties, copolymers of lactic
acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic
acid-containing moieties, or combinations thereof.
[0023] In an embodiment, the degradable polymer comprises an
aliphatic polyester which may be represented by the general formula
of repeating units shown in Formula I:
##STR00001##
where n is an integer ranging from about 75 to about 10,000,
alternatively from about 100 to about 500, or alternatively from
about 200 to about 2000 and R comprises hydrogen, an alkyl group,
an aryl group, alkylaryl groups, acetyl groups, heteroatoms, or
combinations thereof.
[0024] In an embodiment, the aliphatic polyester comprises
poly(lactic acid) or polylactide (PLA). Because 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 formed (e.g., from lactides,
lactic acid, or oligomers) and without reference to the degree of
polymerization or level of plasticization.
[0025] Also, as will be understood by one of ordinary skill in the
art, the lactide monomer may exist, generally, in one of 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 suitable for use in the present disclosure may
be represented by general Formula II:
##STR00002##
where m is an integer 2.ltoreq.m.ltoreq.75, alternatively, m is an
integer and 2.ltoreq.m.ltoreq.10. In such an embodiment, the
molecular weight of the PLA may be less than about 5,400 g/mole,
alternatively, less than about 720 g/mole, respectively. The
stereoisomers of lactic acid may be used individually or combined
to be used in accordance with the present disclosure.
[0026] In an additional embodiment, the degradable polymer
comprises a copolymer of lactic acid. A copolymer of lactic acid
may be formed by copolymerizing one or more stereoisomers of lactic
acid with, for example, glycolide, .epsilon.-caprolactone,
1,5-dioxepan-2-one, or trimethylene carbonate, so as to obtain
polymers with different physical and/or mechanical properties that
are also suitable for use in the present disclosure. In an
embodiment, degradable polymers suitable for use in the present
disclosure are formed by blending, copolymerizing or otherwise
mixing the stereoisomers of lactic acid. Alternatively, degradable
polymers suitable for use in the present disclosure are formed by
blending, copolymerizing or otherwise mixing high and/or low
molecular weight polylactides. Alternatively, degradable polymers
suitable for use in the present disclosure are formed by blending,
copolymerizing or otherwise mixing polylactide with other
polyesters. In an embodiment, the degradable polymer comprises PLA
which may be synthesized using any suitable methodology. For
example, PLA may be synthesized either from lactic acid by a
condensation reaction or by a ring-opening polymerization of a
cyclic lactide monomer. Methodologies for the preparation of PLA
are described in U.S. Pat. Nos. 6,323,307; 5,216,050; 4,387,769;
3,912,692; and 2,703,316, each of which is incorporated by
reference herein in its entirety. Additional descriptions of
degradable polymers suitable for use in the present disclosure may
be found in the publication of Advances in Polymer Science, Vol.
157 entitled "Degradable Aliphatic Polyesters" edited by A. C.
Albertsson, which is incorporated herein in its entirety.
[0027] In an embodiment, the degradable polymer comprises a
polyanhydride. Examples of polyanhydrides suitable for use in the
present disclosure include, but are not limited to, poly(adipic
anhydride), poly(suberic anhydride), poly(sebacic anhydride),
poly(dodecanedioic anhydride), poly(maleic anhydride), poly(benzoic
anhydride), or combinations thereof.
[0028] In an embodiment, the degradable polymer comprises
polysaccharides, such as starches, cellulose, dextran, substituted
or unsubstituted galactomannans, guar gums, high-molecular weight
polysaccharides composed of mannose and galactose sugars,
heteropolysaccharides obtained by the fermentation of
starch-derived sugar (e.g., xanthan gum), diutan, scleroglucan,
derivatives thereof, or combinations thereof.
[0029] In an embodiment, the degradable polymer comprises guar or a
guar derivative. Nonlimiting examples of guar derivatives suitable
for use in the present disclosure include hydroxypropyl guar,
carboxymethylhydroxypropyl guar, carboxymethyl guar,
hydrophobically modified guars, guar-containing compounds,
synthetic polymers, or combinations thereof.
[0030] In an embodiment, the degradable polymer comprises cellulose
or a cellulose derivative. Nonlimiting examples of cellulose
derivatives suitable for use in the present disclosure include
cellulose ethers, carboxycelluloses, carboxyalkylhydroxyethyl
celluloses, hydroxyethylcellulose, hydroxypropylcellulose,
carboxymethylhydroxyethylcellulose, carboxymethylcellulose, or
combinations thereof.
[0031] In an embodiment, the degradable polymer comprises a starch.
Nonlimiting examples of starches suitable for use in the present
disclosure include native starches, reclaimed starches, waxy
starches, modified starches, pre-gelatinized starches, or
combinations thereof.
[0032] In an embodiment, the degradable polymer comprises
acrylic-based polymers, such as acrylic acid polymers, acrylamide
polymers, acrylic acid-acrylamide copolymers, acrylic
acid-methacrylamide copolymers, polyacrylamides,
polymethacrylamides, partially hydrolyzed polyacrylamides,
partially hydrolyzed polymethacrylamides, ammonium and alkali metal
salts thereof, or combinations thereof.
[0033] In an embodiment, the degradable polymer comprises
polyamides, such as polycaprolactam derivatives, poly-paraphenylene
terephthalamide or combinations thereof. In an embodiment, the
degradable polymer comprises nylon 6,6; nylon 6; KEVLAR, or
combinations thereof.
[0034] The physical properties associated with the degradable
polymer may depend upon several factors including, but not limited
to, the composition of the repeating units, flexibility of the
polymer chain, the presence or absence of polar groups, polymer
molecular mass, the degree of branching, polymer crystallinity,
polymer orientation, or the like. For example, a polymer having
substantial short chain branching may exhibit reduced crystallinity
while a polymer having substantial long chain branching may exhibit
for example, a lower melt viscosity and impart, inter alia,
elongational viscosity with tension-stiffening behavior. The
properties of the degradable polymer may be further tailored to
meet some user and/or process designated goal using any suitable
methodology such as blending and/or copolymerizing the degradable
polymer with another polymer, or by changing the macromolecular
architecture of the degradable polymer (e.g., hyper-branched
polymers, star-shaped, or dendrimers, etc.).
[0035] In an embodiment, in choosing the appropriate degradable
polymer, an operator may consider the degradation products that
will result. For example, an operator may choose the degradable
polymer such that the resulting degradation products do not
adversely affect one or more other operations, treatment
components, the formation, or combinations thereof. Additionally,
the choice of degradable polymer may also depend, at least in part,
upon the conditions of the well.
[0036] Nonlimiting examples of additional degradable polymers
suitable for use in conjunction with the methods of this disclosure
are described in more detail in U.S. Pat. Nos. 7,565,929 and
8,109,335, and U.S. Patent Publication Nos. 20100273685 A1,
20110005761 A1, 20110056684 A1 and 20110227254 A1, each of which is
incorporated by reference herein in its entirety.
[0037] In an embodiment, the degradable polymer further comprises a
plasticizer. The plasticizer may be present in an amount sufficient
to provide one or more desired characteristics, for example, (a)
more effective compatibilization of the melt blend components, (b)
improved processing characteristics during the blending and
processing steps, (c) control and/or regulation of the sensitivity
and degradation of the polymer by moisture, (d) control and/or
adjust one or more properties of the foam (e.g., strength,
stiffness, etc.), or combinations thereof. Plasticizers suitable
for use in the present disclosure include, but are not limited to,
derivatives of oligomeric lactic acid, such as those represented by
the formula:
##STR00003##
where R and/or R' are each a hydrogen, an alkyl group, an aryl
group, an alkylaryl group, an acetyl group, a heteroatom, or
combinations thereof provided that R and R' cannot both be hydrogen
and that both R and R' are saturated; q is an integer where the
value of q ranges from greater than or equal to 2 to less than or
equal to 75 or alternatively from greater than or equal to 2 to
less than or equal to 10. As used herein the term "derivatives of
oligomeric lactic acid" may include derivatives of oligomeric
lactide. In an embodiment where a plasticizer of the type disclosed
herein is used, the plasticizer may be intimately incorporated
within the degradable polymeric materials.
[0038] In an embodiment, the DM comprises one or more components of
BIOVERT NWB diverting agent, BIOVERT CF diverting agents, BIOVERT
H150 diverter and fluid loss control material or combinations
thereof. BIOVERT NWB diverting agent is a near-wellbore
biodegradable diverting agent; BIOVERT H150 diverter and fluid loss
control material and BIOVERT CF is a complex fracture biodegradable
diverting agent; each of which is commercially available from
Halliburton Energy Services.
[0039] In an embodiment, a DA may comprise a material suitable for
placement in a wellbore formation concurrently with a DM that
functions to enhance the rate of degradation of a DM. The DM may be
degraded via hydrolytic or aminolytic degradation in the presence
of a DA. In an embodiment, the DA comprises an inorganic base, an
organic base, an acid, a pH-modifying material precursor (e.g.,
base precursor, acid precursor), or combinations thereof.
[0040] In an embodiment, the DA comprises a pH-modifying material
precursor. Herein a pH-modifying material precursor (e.g., base
precursor, acid precursor) is defined as a material or combination
of materials that provides for delayed release of one or more
acidic or basic species. Such pH-modifying material precursors may
also be referred to as time-delayed and/or time-released acids or
bases. In some embodiments, the pH-modifying material precursors
comprise a material or combination of materials that may react to
generate and/or liberate an acid or a base after a period of time
has elapsed. The liberation of the acidic or basic species from the
pH-modifying material precursor may be accomplished through any
means known to one of ordinary skill in the art with the benefits
of this disclosure and compatible with the user-desired
applications.
[0041] In some embodiments, pH-modifying material precursors may be
formed by modifying acids or bases via the addition of an operable
functionality or substituent, physical encapsulation or packaging,
or combinations thereof. The operable functionality or substituent
may be acted upon in any fashion (e.g., chemically, physically,
thermally, etc.) and under any conditions compatible with the
components of the process in order to release the acid or the base
at a some user and/or process desired time and/or under desired
conditions such as in situ wellbore conditions. In an embodiment,
the pH-modifying material precursor may comprise at least one
modified acid or base (e.g., having an operable functionality,
encapsulation, packaging, etc.) such that when acted upon and/or in
response to pre-defined conditions (e.g., in situ wellbore
conditions such as temperature, pressure, chemical environment), an
acid or base is released. In an embodiment, the pH-modifying
material precursor may comprise an acidic or basic species that is
released after exposure to an elevated temperature such as an
elevated wellbore temperature (e.g., greater than about 120.degree.
F.). In an embodiment, the pH-modifying material precursor
comprises a material which reacts with one or more components of
the wellbore servicing fluid (e.g., reacts with an aqueous fluid
present in the WSF) to liberate at least one acidic or basic
species.
[0042] A pH-modifying material precursor as used herein generally
refers to a component, which itself does not act as an acid or base
by significantly modifying the pH of a solution into which it is
introduced, but which, upon degradation, will yield one or more
components capable of acting as an acid or a base by modifying the
pH of that solution. For example, in an embodiment a pH-modifying
material precursor may yield one or more components capable of
modifying the pH of a solution by about 0.1 pH units, alternatively
about 0.2 pH units, alternatively about 0.5 pH units, alternatively
about 1.0 pH units, alternatively about 1.5 pH units, alternatively
about 2.0 pH units, alternatively about 2.5 pH units, alternatively
about 3.0 pH units, alternatively about 4.0 pH units, alternatively
about 5.0 pH units, alternatively about 6.0 pH units, or
alternatively about 7.0 or more pH units and such modifications may
be an increase or decrease in pH.
[0043] In an embodiment, the pH-modifying material precursor may be
characterized as exhibiting a suitable delay time. As used herein,
the term "delay time" refers to the period of time from when a
pH-modifying material precursor, or a combination of pH-modifying
material precursors, is introduced into an operational environment
until the pH-modifying material precursor or combination of
precursors begins to alter (e.g., begins to degrade) the DM, as
will be disclosed herein. In an embodiment, the pH-modifying
material precursor may exhibit an average delay time of at least
about 1 hour, alternatively at least about 2 hours, alternatively
at least about 4 hours, alternatively at least about 8 hours,
alternatively at least about 12 hours, or alternatively at least
about 24 hours.
[0044] In an embodiment, the pH-modifying material precursor may be
characterized as operable, as disclosed herein, within a suitable
temperature range. As will be appreciated by one of skill in the
art viewing this disclosure, differing pH-modifying material
precursors may exhibit varying temperature ranges of operability.
As such, in an embodiment, a pH-modifying material precursor, or
combination of pH-modifying material precursors, may be selected
for inclusion in the SDDM such that the pH-modifying material
precursor(s) exhibit a desired operable temperature range (e.g., an
ambient downhole temperature for a given wellbore). In addition, as
will also be appreciated by one of skill in the art viewing this
disclose, the degradation of the pH-modifying material precursor
may be influenced by the temperature of the operational
environment. For example, generally the rate of degradation of a
given pH-modifying material precursor will be higher at higher
temperatures. As such, the rate of degradation of a given
pH-modifying material precursor may be generally higher when
exposed to the environment within the wellbore. In an embodiment,
the pH-modifying material precursor suitable for use in the present
disclosure may exhibit an operable temperature range of from about
80.degree. F. to about 400.degree. F., alternatively from about
100.degree. F. to about 300.degree. F., or alternatively from about
120.degree. F. to about 250.degree. F.
[0045] In an embodiment, the pH-modifying material precursor is an
acid precursor. In an embodiment, the acid precursor comprises a
reactive ester. Hereinafter, the disclosure will focus on the use
of a reactive ester as the acid precursor with the understanding
that other acid precursors may be used in various embodiments. The
reactive ester may be converted to an acidic species by hydrolysis
of the ester linkage, for example by contact with water present in
the WSF and/or water present in situ in the wellbore. In an
embodiment, the acid precursor may comprise a lactone or lactide, a
lactate ester, an acetate ester, a polyester, or combinations
thereof.
[0046] In an embodiment, the acid precursor comprises esters and/or
polyesters of acids of the type described previously herein; esters
and/or polyesters of polyols (e.g., glycerol, glycols) with acids
of the type described previously herein; aliphatic polyesters;
glucono-delta-lactone; glucoheptonic lactone;
poly(.epsilon.-caprolactones); poly(hydroxybutyrates);
poly(anhydrides); aliphatic polycarbonates; poly(amino acids);
polyphosphazenes; poly(ortho esters); orthoesters (which may also
be known as "poly ortho esters" or "ortho esters; or combinations
thereof. Nonlimiting examples of acid precursors suitable for use
in the present disclosure include monoethylene monoformate,
monoethylene diformate, ethylene glycol monoformate, ethylene
glycol diformate, diethylene glycol monoformate, diethylene glycol
diformate, triethylene glycol diformate, glyceryl monoformate,
glyceryl diformate, glyceryl triformate; formate esters of
pentaerythritol, tri-n-propyl orthoformate, tri-n-butyl
orthoformate, methyl lactate, ethyl lactate, propyl lactate, butyl
lactate, trilactin, polylactic acid, poly(lactides), methyl
acetate, ethyl acetate, propyl acetate, butyl acetate, monoacetin,
diacetin, triacetin, glyceryl diacetate, glyceryl triacetate,
tripropionin (a triester of propionic acid and glycerol), methyl
glycolate, ethyl glycolate, propyl glycolate, butyl glycolate,
poly(glycolides), or combinations thereof. Other examples of acid
precursors suitable for use as DAs in this disclosure are described
in more detail in U.S. Pat. Nos. 6,877,563; 7,021,383 and 7,455,112
and U.S. Patent Application Nos. 2007/0169938 A1 and 20070173416
A1, each of which is incorporated by reference herein.
[0047] In an embodiment, the DA comprises an acid. Nonlimiting
examples of acids suitable for use in the present disclosure
include formic acid; acetic acid; lactic acid; glycolic acid;
oxalic acid; propionic acid; butyric acid; monochloroacetic acid;
dichloroacetic acid; trichloroacetic acid; hydrochloric acid;
nitric acid; sulphuric acid; sulphonic acid; sulphinic acid;
phosphoric acid; phosphorous acid; phosphonic acid; phosphinic
acid; sulphamic acid; p-toluenesulfonic acid; or combinations
thereof.
[0048] In an embodiment, the DA comprises an inorganic base (e.g.,
bases, basic salts). Nonlimiting examples of inorganic bases
suitable for use in this disclosure include sodium hydroxide,
potassium hydroxide, magnesium hydroxide, ammonium hydroxide,
calcium carbonate, sodium carbonate, sodium bicarbonate, magnesium
oxide, or combinations thereof.
[0049] In an embodiment, the DA comprises an organic base. In an
embodiment, the organic base comprises amines, ethylene diamine,
alkanolamines, ethanolamine, thriethanolamine, secondary amines,
tertiary amines, oligomers of aziridine, triethylene tetramine,
tetraethylene pentamine, polyethyleneimine, or combinations
thereof. Other examples of bases suitable for use as DAs in this
disclosure are described in more detail in U.S. Patent Publication
No. 20100273685 A1 and U.S. patent application Ser. No. 13/660,740
filed Oct. 25, 2012 and entitled "Wellbore Servicing Methods and
Compositions Comprising Degradable Polymers," each of which is
incorporated by reference herein in its entirety.
[0050] In an embodiment, the DM and the DA are each present in the
SDDM in amounts effective to perform its intended function. Thus,
the amount of DM may range from about 10 wt. % to about 99 wt. %,
alternatively from about 20 wt. % to about 80 wt. %, or
alternatively from about 40 wt. % to about 70 wt. %, based on the
total mass of the SDDM, while the amount of DA may range from about
1 wt. % to about 80 wt. %, alternatively from about 10 wt. % to
about 60 wt. %, or alternatively from about 20 wt. % to about 50
wt. %, based on the total mass of SDDM.
[0051] In an embodiment, a DM of the type disclosed herein is
associated with a DA of the type disclosed herein using any
suitable methodology to form an SDDM.
[0052] In an embodiment, the SDDM is prepared by contacting the DM
with the DA, and thoroughly mixing the components for example by
compounding, injection molding, extrusion molding, extrusion, melt
extrusion, compression molding, or any suitable combination of
these methods.
[0053] In an embodiment, the DM is plasticized or melted by heating
in an extruder and is contacted and mixed thoroughly with a DA of
the type disclosed herein at a temperature of about greater than
the melt temperature of the DM, the DA, or both. Alternatively, the
DM may be contacted with the DA prior to introduction of the
mixture to the extruder (e.g., via bulk mixing), during the
introduction of the DM to an extruder, or combinations thereof.
[0054] The SDDMs of this disclosure may be converted to SDDM
particles by any suitable method (e.g., chipping, cutting, milling,
grinding, etc.) The SDDM particles may be produced about
concurrently with the assembling of the SDDMs (e.g., on a
sequential, integrated process line) or may be produced subsequent
to the assembling of the SDDMs (e.g., on a separate process line
such as an end use compounding and/or thermoforming line). In an
embodiment, the SDDM is assembled via extrusion as previously
described herein and the molten SDDM is fed to a shaping process
(e.g., mold, die, lay down bar, etc.) where the SDDM is shaped. The
assembling of the SDDM (e.g., contacting/mixing of the DM and DA)
may occur prior to, during, or subsequent to the shaping.
[0055] In an embodiment, the SDDMs are further processed by
mechanically sizing, cutting, or chopping the SDDM into particles
using any suitable methodologies for such processes. The SDDMs
suitable for use in this disclosure comprise SDDM particles of any
suitable geometry, including without limitation beads, hollow
beads, spheres, ovals, fibers, rods, pellets, platelets, disks,
plates, ribbons, and the like, or combinations thereof.
[0056] In an embodiment, the SDDM comprises particles having an
average particle size ranging from about 0.1 micron to about 3000
microns, alternatively from about 5 microns to about 2000 microns,
alternatively from about 1 micron to about 500 microns, or
alternatively from about 10 microns to about 100 microns. The
average particle size of the SDDM may be determined using any
suitable methodology or instrumentation such as a Malvern particle
size analyzer.
[0057] In an embodiment, the DM comprises BIOVERT NWB diverting
agent and the DA comprises sodium bicarbonate. FIG. 1B displays a
schematic of an SDDM particle 30. The SDDM 30 may be formed by
contacting a DM 15 (e.g., a continuous phase) and a DA 40 (e.g., a
discontinuous phase such as particles) both of the type disclosed
herein, and compounding the components together into SDDM particles
30 having an average size of from about 50 microns to about 2000
microns.
[0058] In an embodiment, the DM comprises BIOVERT CF diverting
agent and the DA comprises encapsulated sodium hydroxide. The SDDM
in FIG. 1B may be formed by contacting the DM 15 and the DA 40, and
subjecting the mixture to the process of injection molding. The
SDDM may be further mechanically sized into SDDM particles 30
having an average size of from about 5 microns to about 200 microns
by using any suitable methodology (e.g., cutting, chopping, and the
like).
[0059] An SDDM of the type disclosed herein may be included in any
suitable wellbore servicing fluid. As used herein, a "servicing
fluid" refers to a fluid used to drill, complete, work over,
fracture, repair, or in any way prepare a wellbore for the recovery
of materials residing in a subterranean formation penetrated by the
wellbore. Examples of wellbore servicing fluids include, but are
not limited to, cement slurries, drilling fluids or muds, spacer
fluids, lost circulation fluids, fracturing fluids, diverting
fluids or completion fluids. The servicing fluid is for use in a
wellbore that penetrates a subterranean formation. It is to be
understood that "subterranean formation" encompasses both areas
below exposed earth and areas below earth covered by water such as
ocean or fresh water. In an embodiment, the SDDM may be present in
a wellbore servicing fluid in an amount of from about 0.01 pounds
per gallon (ppg) to about 6 ppg, alternatively from about 0.1 ppg
to about 2 ppg, or alternatively from about 0.1 ppg to about 1
ppg.
[0060] In an embodiment, the DM and the DA are manufactured and
then contacted together at the well site, forming the SDDM as
previously described herein. Alternatively, the DM and the DA are
manufactured and then contacted together either off-site or
on-the-fly (e.g., in real time or on-location), forming the SDDM as
previously described herein. In another embodiment, either the DM
or the DA is preformed and the other one would be made on-the-fly,
and the two materials would then be contacted together on-the-fly,
forming the SDDM as previously described herein. When manufactured
or assembled off site, the DM, DA and/or SDDM may be transported to
the well site.
[0061] Alternatively, the SDDM may be assembled and prepared as a
slurry in the form of a liquid additive. In an embodiment, the SDDM
and a wellbore servicing fluid may be blended until the SDDM
particulates are distributed throughout the fluid. By way of
example, the SDDM particulates and a wellbore servicing fluid may
be blended using a blender, a mixer, a stirrer, a jet mixing
system, or other suitable device. In an embodiment, a recirculation
system keeps the SDDM particulates uniformly distributed throughout
the wellbore servicing fluid (e.g., a concentrated solution or
slurry).
[0062] When it is desirable to prepare a wellbore servicing fluid
comprising an SDDM of the type disclosed herein (i.e., a diverting
fluid) for use in a wellbore, the diverting fluid prepared at the
wellsite or previously transported to and, if necessary, stored at
the on-site location may be combined with the SDDM, additional
water and optional other additives to form the diverting fluid. In
an embodiment, additional diverting materials may be added to the
diverting fluid on-the-fly along with the other
components/additives. The resulting diverting fluid may be pumped
downhole where it may function as intended.
[0063] In an embodiment, a concentrated SDDM liquid additive is
mixed with additional water to form a diluted liquid additive,
which is subsequently added to a diverting fluid. The additional
water may comprise fresh water, salt water such as an unsaturated
aqueous salt solution or a saturated aqueous salt solution, or
combinations thereof. In an embodiment, the liquid additive
comprising the SDDM is injected into a delivery pump being used to
supply the additional water to a diverting fluid composition. As
such, the water used to carry the SDDM particulates and this
additional water are both available to the diverting fluid such
that the SDDM may be dispersed throughout the diverting fluid.
[0064] In an alternative embodiment, the SDDM prepared as a liquid
additive is combined with a ready-to-use diverting fluid as the
diverting fluid is being pumped into the wellbore. In such
embodiments, the liquid additive may be injected into the suction
of the pump. In such embodiments, the liquid additive can be added
at a controlled rate to the diverting fluid (e.g., or a component
thereof such as blending water) using a continuous metering system
(CMS) unit. The CMS unit can also be employed to control the rate
at which the liquid additive is introduced to the diverting fluid
or component thereof as well as the rate at which any other
optional additives are introduced to the diverting fluid or
component thereof. As such, the CMS unit can be used to achieve an
accurate and precise ratio of water to SDDM concentration in the
diverting fluid such that the properties of the diverting fluid
(e.g., density, viscosity), are suitable for the downhole
conditions of the wellbore. The concentrations of the components in
the diverting fluid, e.g., the SDDMs, can be adjusted to their
desired amounts before delivering the composition into the
wellbore. Those concentrations thus are not limited to the original
design specification of the diverting fluid and can be varied to
account for changes in the downhole conditions of the wellbore that
may occur before the composition is actually pumped into the
wellbore.
[0065] In an embodiment, the wellbore servicing fluid comprises a
composite treatment fluid. As used herein, the term "composite
treatment fluid" generally refers to a treatment fluid comprising
at least two component fluids. In such an embodiment, the two or
more component fluids may be delivered into the wellbore separately
via different flowpaths (e.g., such as via a flowbore, a wellbore
tubular and/or via an annular space between the wellbore tubular
and a wellbore wall/casing) and substantially intermingled or mixed
within the wellbore (e.g., in situ) so as to form the composite
treatment fluid. Composite treatment fluids are described in more
detail in U.S. Patent Publication No. 2010/0044041 A1 which is
incorporated by reference herein in its entirety.
[0066] In an embodiment, the composite treatment fluid comprises a
diverting fluid (e.g., a wellbore servicing fluid comprising an
SDDM of the type disclosed herein). In such an embodiment, the
diverting fluid may be formed from a first component and a second
component. For example, the first component may comprise a
diverter-laden slurry (e.g., a concentrated diverter-laden slurry
pumped via a tubular flowbore) and the second component may
comprise a fluid with which the diverter-laden slurry may be mixed
to yield the composite diverting fluid, that is, a diluent (e.g.,
an aqueous fluid, such as water pumped via an annulus). In an
embodiment, the diverter-laden slurry comprises an SDDM-laden
slurry.
[0067] In an embodiment, the diverter-laden slurry (e.g., the first
component) comprises a base fluid, and diverting materials (e.g.,
an SDDM of the type disclosed herein). In an embodiment, the base
fluid may comprise a substantially aqueous fluid. As used herein,
the term "substantially aqueous fluid" may refer to a fluid
comprising less than about 25% by weight of a non-aqueous
component, alternatively less than about 20% by weight,
alternatively less than about 15% by weight, alternatively less
than about 10% by weight, alternatively less than about 5% by
weight, alternatively less than about 2.5% by weight, alternatively
less than about 1.0% by weight of a non-aqueous component. Examples
of suitable aqueous fluids include, but are not limited to, water
that is potable or non-potable, untreated water, partially treated
water, treated water, produced water, city water, well-water,
surface water, or combinations thereof. In an alternative or
additional embodiment, the base fluid may comprise an aqueous gel,
a viscoelastic surfactant gel, an oil gel, a foamed gel, an
emulsion, an inverse emulsion, or combinations thereof.
[0068] In an embodiment, the diluent (e.g., the second component)
may comprise a suitable aqueous fluid, aqueous gel, viscoelastic
surfactant gel, oil gel, a foamed gel, emulsion, inverse emulsion,
or combinations thereof. For example, the diluent may comprise one
or more of the compositions disclosed above with reference to the
base fluid. In an embodiment, the diluent may have a composition
substantially similar to that of the base fluid; alternatively, the
diluent may have a composition different from that of the base
fluid.
[0069] In an embodiment, the size and/or shape of the diverting
material may be chosen so as to provide a plug (e.g., filter cake)
within a given flowpath (e.g., within a point of entry into the
wellbore and/or at a given distance from the wellbore within a
fracture) having a given size, shape, and/or orientation. In an
embodiment, the SDDM may be added to the wellbore servicing fluid
to generate a diverting fluid which is then pumped downhole at the
same time with additional diverting material.
[0070] In an embodiment, the SDDM once placed downhole enters the
formation and forms a diverter plug resulting in an increased
pressure in the near wellbore region ranging from about 50 psi to
about 5000 psi.
[0071] In an embodiment, as noted above, the SDDM may be
configured, for example, via selection of a given size and/or
shape, for placement at a given position (e.g., at a given depth of
the wellbore) within such a flowpath. Without wishing to be limited
by theory, where it is desired that a diverter plug forms in the
near-wellbore region, the SDDM may be selected so as to have a
multimodal particle size distribution for example, the DM (e.g.,
BIOVERT NWB diverting agent) may have about 20-25% of the material
at a particle size of about 4 to about 10 mesh; about 50% of the
material may have a particle size in the range of about 20 to about
40 mesh size while the remaining material may have a particle size
of less than about 40 mesh. As used herein, the term "mesh size" is
used to refer to the sizing of a particular screen as defined by as
"ASTM E-11 Specifications" or "ISO 3310-1". Generally, mesh size
may refer approximately to the greatest size of material that will
pass through a particular mesh size, for example, the nominal
opening. The mesh size may also refer to the inside dimension of
each opening in the mesh (e.g., the inside diameter of each
square). Alternatively, where it is desired that a diverter plug
forms in the far-wellbore region, the SDDM may be selected so as to
have a smaller particle size (e.g., smaller than about 100 mesh).
The near-wellbore region delimitation is dependent upon the
formation where the wellbore is located, and is based on the
wellbore surrounding conditions. The far-wellbore region is
different from the near-wellbore region in that it is subjected to
an entirely different set of conditions and/or stimuli. In an
embodiment, the near-wellbore and far-wellbore regions are based on
the fracture length propagating away from the wellbore. In such
embodiments, the near-wellbore region refers to about the first 20%
of the fracture length propagating away from the wellbore (e.g., 50
feet) whereas the far-wellbore region refers to a length that is
greater than about 20% of the fracture length propagating away from
the wellbore (e.g., greater than about 50 feet). Again, without
wishing to be limited by theory, smaller diverter particles may be
carried a greater distance into the formation (e.g., into an
existing and/or extending fracture).
[0072] A method of servicing a wellbore may comprise placing a
wellbore servicing fluid (e.g., fracturing or other stimulation
fluid such as an acidizing fluid) into a portion of a wellbore. In
such embodiments, the fracturing or stimulation fluid may enter
flow paths and perform its intended function of increasing the
production of a desired resource from that portion of the wellbore.
The level of production from the portion of the wellbore that has
been stimulated may taper off over time such that stimulation of a
different portion of the well is desirable. Additionally or
alternatively, previously formed flowpaths may need to be
temporarily plugged in order to fracture or stimulate
additional/alternative intervals or zones during a given wellbore
service or treatment. In an embodiment, an amount of a diverting
fluid (e.g., wellbore servicing fluid comprising an SDDM)
sufficient to effect diversion of a wellbore servicing fluid from a
first flowpath to a second flowpath is delivered to the wellbore.
The diverting fluid may form a temporary plug, also known as a
diverter plug or diverter cake, once disposed within the first
flowpath which restricts entry of a wellbore servicing fluid (e.g.,
fracturing or stimulation fluid) into the first flowpath. The
diverter plug deposits onto the face of the formation and creates a
temporary skin or structural, physical and/or chemical obstruction
that decreases the permeability of the zone. The wellbore servicing
fluid restricted from entering the first flowpath may enter one or
more additional flowpaths and perform its intended function. Within
a first treatment stage, the process of introducing a wellbore
servicing fluid into the formation to perform an intended function
(e.g., fracturing or stimulation) and, thereafter, diverting the
wellbore servicing fluid to another flowpath into the formation
and/or to a different location or depth within a given flowpath may
be continued until some user and/or process goal is obtained. In an
additional embodiment, this diverting procedure may be repeated
with respect to each of a second, third, fourth, fifth, sixth, or
more, treatment stages, for example, as disclosed herein with
respect to the first treatment stage.
[0073] In an embodiment, the wellbore service being performed is a
fracturing operation, wherein a fracturing fluid is placed (e.g.,
pumped downhole) at a first location in the formation and an SDDM
is employed to divert the fracturing fluid from the first location
to a second location in the formation such that fracturing can be
carried out at a plurality of locations. The SDDM may be placed
into the first (or any subsequent location) via pumping a slug of a
diverter fluid (e.g., a fluid having a different composition than
the fracturing fluid) containing the SDDM and/or by adding the SDDM
directly to the fracturing fluid, for example to create a slug of
fracturing fluid comprising the SDDM. The SDDM may form a diverter
plug at the first location (and any subsequent location so treated)
such that the fracturing fluid may be selectively placed at one or
more additional locations, for example during a multi-stage
fracturing operation.
[0074] In an embodiment, following a wellbore servicing operation
utilizing a diverting fluid (e.g., a wellbore servicing fluid
comprising an SDDM), the wellbore and/or the subterranean formation
may be prepared for production, for example, production of a
hydrocarbon, therefrom.
[0075] In an embodiment, preparing the wellbore and/or formation
for production may comprise removing an SDDM (which has formed a
temporary plug) from one or more flowpaths, for example, by
allowing the diverting materials therein to degrade and
subsequently recovering hydrocarbons from the formation via the
wellbore.
[0076] In an embodiment the SDDM comprises a degradable polymer of
the type previously disclosed herein, which degrades due to, inter
alia, a chemical and/or radical process such as hydrolysis or
oxidation. As may be appreciated by one of skill in the art upon
viewing this disclosure, the degradability of a polymer may depend
at least in part on its backbone structure. For example, the
presence of hydrolyzable and/or oxidizable linkages within the
backbone structure may yield a material that will degrade as
described herein. As may also be appreciated by one of skill in the
art upon viewing this disclosure, the rates at which such polymers
degrade may be at least partially dependent upon polymer
characteristics such as the type of repetitive unit, composition,
sequence, length, molecular geometry, molecular weight, morphology
(e.g., crystallinity, size of spherulites, and orientation),
hydrophilicity, hydrophobicity, surface area, and type of
additives. Additionally, the ambient downhole environment to which
a given polymer is subjected may also influence how it degrades,
(e.g., temperature, presence of moisture, oxygen, microorganisms,
enzymes, pH, pressure, the like, and combinations thereof).
[0077] In an embodiment, the SDDM is of the type depicted in FIG.
1B. In an embodiment, and SDDM particle 30 comprises a DM 15 and a
DA 40. Upon placement in the wellbore and diverter plug formation,
the DA 40 may accelerate degradation of the DM. For example, an
encapsulated DA may have the structural integrity of the
encapsulating material compromised (e.g., by in situ wellbore
temperatures) such that the DA is contacted with the DM and begins
to degrade the DM. Alternatively, the DA which is in contact with
the DM when placed in the wellbore under ambient surface conditions
may degrade the DM at some rate (x) which is accelerated to a rate
(y) when subjected to in situ wellbore conditions (e.g., elevated
temperatures and/or pressures). As will be appreciated by one of
ordinary skill in the art, the DA (with or without encapsulation)
which has been mixed with the DM is located at discrete locations
within the DM such that SDDM can be envisioned as a composite
material having a continuous phase of DM and a discontinuous phase
of DA. DA disposed within the DM may degrade DM molecules resulting
in the formation of voids within the SDDM. The resultant degraded
SDDM particle 35 may be characterized by the appearance of
voids/pores 60 (i.e., a porous structure). The degraded SDDM
particle 35 has a greater surface area exposed to the wellbore
servicing fluid due to the presence of the pores 60, when compared
to the surface area of the original, undegraded SDDM particle 30.
Degradation 70 of the diverter material 15 may be faster due to
both the altered pH 55 and the increased surface area of the
degraded SDDM particle 35, when compared to the degradation 20 of
diverter particles 10 comprising the same DM 15, but lacking the
pores as seen in FIG. 1A.
[0078] In an embodiment, the degraded SDDM particle 35 comprises a
degradable polymer having an enhanced surface area. Without wishing
to be limited by theory, the larger the surface area exposed to a
medium and/or environment in which the material undergoes a
reaction (e.g., hydrolytic degradation), the shorter the reaction
time frame will be for a fixed amount of material, while keeping
all the other conditions unchanged (e.g., same pressure, same
temperature, etc.). For example, if polymeric material A (e.g., DM)
is a nonporous solid having a mass x and a surface area y, then the
porous diverter material of this disclosure obtained upon DA
dissolution from polymer A that has the same mass x, may have a
surface area of 2y, 5y, 10y, 20y, 50y, or 100y. As a result of
having a larger surface area, the porous diverter material may
display faster degradation times than the original nonporous solid
polymeric material A. In an embodiment, the SDDM may result in a
degraded SDDM particle 35 which displays a surface area that is
increased with respect to the solid diverter material (i.e.,
pore-free solid) by a factor of about 50, alternatively by a factor
of about 100, or alternatively by a factor of about 200. Thus a
mechanism of increasing the degradability of a DM may include
physical alteration of the DM (e.g., induce pores to increase the
surface area) as well as chemical and/or structural alterations
such as cleaving the backbone of the DM, increasing the number of
radicals present that attack the DM's polymer chains, catalyzing
the decomposition reaction, etc.
[0079] In an embodiment, the SDDM when subjected to degradation
conditions of the type disclosed herein (e.g., elevated
temperatures and/or pressures) degrades in a time range of about 4
h, alternatively about 6 h, or alternatively about 12 h.
Alternatively, SDDMs of the type disclosed herein due to the
presence of a DA substantially degrade in a time frame of less than
about 1 week, alternatively less than about 2 days, or
alternatively less than about 1 day.
[0080] In another embodiment, the SDDM comprises a material which
is characterized by the ability to be degraded at bottom hole
temperatures (BHT) of less than about 120.degree. F., alternatively
less than about 250.degree. F., or alternatively less than about
350.degree. F.
[0081] In an embodiment, SDDMs of the type disclosed herein provide
an economic advantage over the use of DMs as the SDDMs utilize a
reduced amount of DM in comparison to provide a similar diverting
capability.
[0082] The following are additional enumerated embodiments of the
concepts disclosed herein.
[0083] A first embodiment which is a method of servicing a wellbore
in a subterranean formation comprising placing a first wellbore
servicing fluid comprising a self-degrading diverter material into
the wellbore wherein the self-degrading diverter materials
comprises (i) a diverting material and (ii) a degradation
accelerator allowing the self-degrading diverter material to form a
diverter plug at a first location in the wellbore or subterranean
formation; diverting the flow of a second wellbore servicing fluid
to a second location in the wellbore or subterranean formation; and
removing the diverter plug, wherein the first and second wellbore
servicing fluids may be the same or different.
[0084] A second embodiment which is the method of the first
embodiment wherein the diverting material comprises a degradable
material.
[0085] A third embodiment which is the method of the second
embodiment wherein the degradable material comprises a degradable
polymer.
[0086] A fourth embodiment which is the method of the third
embodiment wherein the degradable polymer comprises
polysaccharides; lignosulfonates; chitins; chitosans; proteins;
proteinous materials; fatty alcohols; fatty esters; fatty acid
salts; aliphatic polyesters; poly(lactides); poly(glycolides);
poly(.epsilon.-caprolactones); polyoxymethylene; polyurethanes;
poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates;
polyvinyl polymers; acrylic-based polymers; poly(amino acids);
poly(aspartic acid); poly(alkylene oxides); poly(ethylene oxides);
polyphosphazenes; poly(orthoesters); poly(hydroxy ester ethers);
polyether esters; polyester amides; polyamides;
polyhydroxyalkanoates; polyethyleneterephthalates;
polybutyleneterephthalates; polyethylenenaphthalenates, or
combinations thereof.
[0087] A fifth embodiment which is the method of the fourth
embodiment wherein the aliphatic polyester comprises a compound
represented by general formula I:
##STR00004##
where n is an integer ranging from about 75 to about 10,000 and R
comprises hydrogen, an alkyl group, an aryl group, alkylaryl
groups, acetyl groups, heteroatoms, or combinations thereof.
[0088] A sixth embodiment which is the method of any of the second
through third embodiments wherein the degradable polymer comprises
polylactic acid.
[0089] A seventh embodiment which is the method of any of the first
through sixth embodiments wherein the degradation accelerator
comprises an inorganic base, an organic base, a base precursor, an
acid, acid precursor, or combinations thereof.
[0090] An eighth embodiment which is the method of the seventh
embodiment wherein the inorganic base comprises sodium hydroxide,
potassium hydroxide, magnesium hydroxide, ammonium hydroxide,
calcium carbonate, sodium carbonate, sodium bicarbonate, magnesium
oxide, or combinations thereof.
[0091] A ninth embodiment which is the method of the seventh
embodiment wherein the organic base comprises amines, ethylene
diamine, alkanolamines, ethanolamine, thriethanolamine, secondary
amines, tertiary amines, oligomers of aziridine, triethylene
tetramine, tetraethylene pentamine, polyethyleneimine, or
combinations thereof.
[0092] A tenth embodiment which is the method of the seventh
embodiment wherein the acid comprises formic acid; acetic acid;
lactic acid; glycolic acid; oxalic acid; propionic acid; butyric
acid; monochloroacetic acid; dichloroacetic acid; trichloroacetic
acid; hydrochloric acid; nitric acid; sulphuric acid; sulphonic
acid; sulphinic acid; phosphoric acid; phosphorous acid; phosphonic
acid; phosphinic acid; sulphamic acid; p-toluenesulfonic acid; or
combinations thereof.
[0093] An eleventh embodiment which is the method of the seventh
embodiment wherein the acid precursor comprises aliphatic
polyesters; glucono-delta-lactone; glucoheptonic lactone;
poly(.epsilon.-caprolactones); poly(hydroxybutyrates);
poly(anhydrides); aliphatic polycarbonates; poly(amino acids);
polyphosphazenes; poly(ortho esters); orthoesters; monoethylene
monoformate, monoethylene diformate, ethylene glycol monoformate,
ethylene glycol diformate, diethylene glycol monoformate,
diethylene glycol diformate, triethylene glycol diformate, glyceryl
monoformate, glyceryl diformate, glyceryl triformate; formate
esters of pentaerythritol, tri-n-propyl orthoformate, tri-n-butyl
orthoformate, methyl lactate, ethyl lactate, propyl lactate, butyl
lactate, trilactin, polylactic acid, poly(lactides), methyl
acetate, ethyl acetate, propyl acetate, butyl acetate, monoacetin,
diacetin, triacetin, glyceryl diacetate, glyceryl triacetate,
tripropionin (a triester of propionic acid and glycerol), methyl
glycolate, ethyl glycolate, propyl glycolate, butyl glycolate,
poly(glycolides), or combinations thereof.
[0094] A twelfth embodiment which is the method of any of the first
through eleventh embodiments wherein the degradation accelerator is
encapsulated.
[0095] A thirteenth embodiment which is the method of any of the
first through twelfth embodiments wherein the self-degrading
diverter material is present in the wellbore servicing fluid in an
amount of from about 0.01 ppg to about 6 ppg.
[0096] A fourteenth embodiment which is the method of any of the
first through thirteenth embodiments wherein the first wellbore
servicing fluid comprises a diverting fluid and the second wellbore
servicing fluid comprises a fracturing fluid.
[0097] A fifteenth embodiment which is the method of the fourteenth
embodiment wherein a first portion of the fracturing fluid is
placed into the formation at the first location before the diverter
fluid is placed in the formation at the first location and a second
portion of the fracturing fluid is diverted from the first location
to the second location.
[0098] A sixteenth embodiment which is the method of any of the
first through fourteenth embodiments wherein the self-degrading
diverter materials has a particle size of from about 0.1 microns to
about 3000 microns.
[0099] A seventeenth embodiment which is a wellbore servicing fluid
comprising self-degrading diverter material wherein the
self-degrading diverter material comprises polylactide, sodium
carbonate and a carrier fluid.
[0100] An eighteenth embodiment which is the method of the
seventeenth embodiment wherein the wellbore servicing fluid
comprises a diverting fluid.
[0101] A nineteenth embodiment which is a method of servicing a
wellbore in a subterranean formation comprising placing a wellbore
servicing fluid into the subterranean formation at a first
location; plugging the first location with a self-degrading
diverter material comprising a diverting material and a degradation
accelerator such that all or a portion of the wellbore servicing
fluid is diverted to a second location in the subterranean
formation; placing the wellbore servicing fluid into the
subterranean formation at the second location; and allowing the
self-degrading diverter material to degrade to provide a flowpath
from the subterranean formation to the wellbore for recovery of
resources from the subterranean formation.
[0102] A twentieth embodiment which is the method of the nineteenth
embodiment wherein the wellbore servicing fluid is a fracturing
fluid and the subterranean formation is fractured thereby at the
first and second locations.
[0103] While embodiments of the invention have been shown and
described, modifications thereof can be made by one skilled in the
art without departing from the spirit and teachings of the
invention. The embodiments described herein are exemplary only, and
are not intended to be limiting. Many variations and modifications
of the invention disclosed herein are possible and are within the
scope of the invention. Where numerical ranges or limitations are
expressly stated, such express ranges or limitations should be
understood to include iterative ranges or limitations of like
magnitude falling within the expressly stated ranges or limitations
(e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater
than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a
numerical range with a lower limit, R.sub.L, and an upper limit,
R.sub.u, is disclosed, any number falling within the range is
specifically disclosed. In particular, the following numbers within
the range are specifically disclosed:
R=R.sub.L+k*(R.sub.u-R.sub.L), wherein k is a variable ranging from
1 percent to 100 percent with a 1 percent increment, i.e., k is 1
percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . , 50
percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97
percent, 98 percent, 99 percent, or 100 percent. Moreover, any
numerical range defined by two R numbers as defined in the above is
also specifically disclosed. Use of the term "optionally" with
respect to any element of a claim is intended to mean that the
subject element is required, or alternatively, is not required.
Both alternatives are intended to be within the scope of the claim.
Use of broader terms such as comprises, includes, having, etc.
should be understood to provide support for narrower terms such as
consisting of, consisting essentially of, comprised substantially
of, etc.
[0104] Accordingly, the scope of protection is not limited by the
description set out above but is only limited by the claims which
follow, that scope including all equivalents of the subject matter
of the claims. Each and every claim is incorporated into the
specification as an embodiment of the present invention. Thus, the
claims are a further description and are an addition to the
embodiments of the present invention. The discussion of a reference
in the Description of Related Art is not an admission that it is
prior art to the present invention, especially any reference that
may have a publication date after the priority date of this
application. The disclosures of all patents, patent applications,
and publications cited herein are hereby incorporated by reference,
to the extent that they provide exemplary, procedural or other
details supplementary to those set forth herein.
* * * * *