U.S. patent application number 17/217811 was filed with the patent office on 2021-07-15 for methods of treatment of a subterranean formation with polymeric structures formed in situ.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Patrice Abivin, Brent Busby, Marie Cambournac, Jazmin Godoy-Vargas, Sergey Makarychev-Mikhailov, Philip Sullivan.
Application Number | 20210215026 17/217811 |
Document ID | / |
Family ID | 1000005490043 |
Filed Date | 2021-07-15 |
United States Patent
Application |
20210215026 |
Kind Code |
A1 |
Godoy-Vargas; Jazmin ; et
al. |
July 15, 2021 |
METHODS OF TREATMENT OF A SUBTERRANEAN FORMATION WITH POLYMERIC
STRUCTURES FORMED IN SITU
Abstract
Methods of treating a subterranean formation are disclosed that
include placing a treatment fluid into a subterranean formation,
the treatment fluid containing a one or more polymers capable of
consolidating to form a polymeric structure at a downhole location.
Also disclosed are treatment fluids including a polymeric structure
for treating a subterranean formation.
Inventors: |
Godoy-Vargas; Jazmin;
(Stafford, TX) ; Makarychev-Mikhailov; Sergey;
(St. Petersburg, RU) ; Busby; Brent; (Katy,
TX) ; Sullivan; Philip; (Bellaire, TX) ;
Abivin; Patrice; (Houston, TX) ; Cambournac;
Marie; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Family ID: |
1000005490043 |
Appl. No.: |
17/217811 |
Filed: |
March 30, 2021 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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14338722 |
Jul 23, 2014 |
10961832 |
|
|
17217811 |
|
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|
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61857539 |
Jul 23, 2013 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C09K 8/64 20130101; E21B
43/25 20130101; C09K 8/502 20130101; C09K 2208/08 20130101; C09K
8/528 20130101; C09K 8/512 20130101; C09K 8/90 20130101; C09K 8/035
20130101; C09K 8/887 20130101; C09K 8/82 20130101; C09K 8/685
20130101 |
International
Class: |
E21B 43/25 20060101
E21B043/25; C09K 8/90 20060101 C09K008/90; C09K 8/512 20060101
C09K008/512; C09K 8/68 20060101 C09K008/68; C09K 8/64 20060101
C09K008/64; C09K 8/502 20060101 C09K008/502; C09K 8/035 20060101
C09K008/035; C09K 8/82 20060101 C09K008/82; C09K 8/88 20060101
C09K008/88; C09K 8/528 20060101 C09K008/528 |
Claims
1. A fluid for treating a subterranean formation comprising: a
solvent; and a polymeric structure comprising one or more polymers;
wherein the polymeric structure is formed by consolidating the one
or more polymers during a shear event.
2. The fluid for treating the subterranean formation of claim 1,
wherein the fluid is selected from the group consisting of a fluid
loss control pill, a water control treatment fluid, a scale
inhibition treatment fluid, a fracturing fluid, a gravel packing
fluid, a drilling fluid, and a drill-in fluid.
3. The fluid for treating the subterranean formation of claim 1,
wherein the polymeric structure comprises one or more pH sensitive
polymers.
4. The fluid for treating the subterranean formation of claim 1,
wherein the polymeric structure comprises a seed particle or seed
fiber.
5. The fluid for treating the subterranean formation of claim 1,
wherein the polymeric structure comprises one or more proppant
particles.
6. The fluid for treating the subterranean formation of claim 1,
wherein the polymeric structure has an aspect ratio of at least
2:1.
7. The fluid for treating the subterranean formation of claim 1,
wherein the polymeric structure is a solid.
8. The fluid for treating the subterranean formation of claim 1,
wherein the polymeric structure is a gel.
9. The fluid for treating the subterranean formation of claim 1,
wherein the polymeric structure comprises one or more crosslinked
polymers.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation of co-pending U.S. patent
application Ser. No. 14/338,722 filed 23 Jul. 2014, now U.S. Pat.
No. 10,961,832, which application claims the benefit of U.S.
Provisional Application Ser. No. 61/857,539 filed Jul. 23, 2013,
each of which are herein incorporated by reference.
BACKGROUND
[0002] Hydrocarbons (oil, natural gas, etc.) may be obtained from a
subterranean geologic formation (a "reservoir") by drilling a well
that penetrates the hydrocarbon-bearing formation. Well treatment
methods often are used to increase hydrocarbon production by using
a treatment fluid to interact with a subterranean formation in a
manner that ultimately increases oil or gas flow from the formation
to the wellbore for removal to the surface.
[0003] Many of such treatment fluids use fibers. For example,
wellbore treatments that employ treatment fluids containing fibers
may include, for example, drilling, reservoir stimulation, and
cementing, among others. A variety of fibers may be incorporated
into the treatment fluid, with different physical and chemical
properties. However, the selection of materials may be limited by
the commercial availability and various compatibility issues, such
as with surface storage and handling. In addition, concerns remain
regarding the addition of fibers into fluids (at the surface) and
potential clogging of various wellbore equipment.
SUMMARY
[0004] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the subject matter described herein, nor is
it intended to be used as an aid in limiting the scope of the
subject matter described herein. Indeed, this disclosure may
encompass a variety of aspects that may not be set forth below.
[0005] In some embodiments, the present disclosure relates to
methods for treating a subterranean formation. Such methods may
include, in any order: placing a treatment fluid including at least
one or more polymers into a subterranean formation via a wellbore;
adjusting at least one parameter of the treatment fluid; exposing
the treatment fluid to a shear event; and consolidating the one or
more polymers into at least one polymeric structure.
[0006] In some embodiments, the present disclosure relates to
treatment fluids including a solvent, and a polymeric structure
containing at least one polymer, where the polymeric structure is
formed by consolidating the one or more polymers during a shear
event.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] Various aspects of this disclosure may be better understood
upon reading the following detailed description and upon reference
to the drawings in which:
[0008] FIG. 1 is a schematic illustration of a device that may be
used to generate a shear event.
[0009] FIG. 2 is a schematic illustration of a device with an
impeller that may be used generate a shear event.
[0010] FIG. 3 is a schematic illustration of a conduit that may be
used generate a shear event.
[0011] FIG. 4 is a schematic illustration of a structure including
a conduit with perforations that may be used generate a shear
event.
[0012] FIG. 5 is a schematic illustration of a structure with inner
and outer conduits deployed in a wellbore that may be used generate
a shear event.
[0013] FIG. 6A is an image of the polymeric structures obtained
from consolidation of guar with isopropanol, and FIG. 6B is a
stereo microscope image of these polymeric structures.
[0014] FIG. 7A is an image of the polymeric structures obtained
from consolidation of guar with methanol in presence of 4% KCl; and
FIGS. 7B and 7C are stereo microscope images of these polymeric
structures.
[0015] FIG. 8A is an image of the polymeric structures obtained
adding alginate solution to ethylene glycol butyl ether, and FIG.
8B is a stereo microscope image of these polymeric structures.
[0016] FIG. 9A is an image of PLA polymeric structures obtained
from consolidation in water, and FIG. 9B is a stereo microscope
image of these polymeric structures.
[0017] FIG. 10 is an image of CMC polymeric structures obtained
from a crosslinking reaction.
[0018] FIG. 11 is a stereo microscope image of polyHEMA polymeric
structure, which was formed in deionized water.
[0019] FIG. 12A is an image of HPC elongated polymeric structures
obtained by adding HPC solution to hot distilled water, and FIG.
12B is a stereo microscope image of these fiber-like polymeric
structures.
[0020] FIG. 13 and FIG. 14 are images of polymeric structures
formed by the complex of CMC and ADBAC.
[0021] FIG. 15 is an image of a polymeric structures formed by the
complex of CMC and ADBAC along with proppant.
[0022] FIG. 16 is an image of a polymeric structure formed from the
addition of a colloidal suspension of nanosized particles of
colloidal alumina to a solution of CMC.
[0023] FIG. 17 is a stereo microscope image of a polymeric
structure formed from chitosan and SDS.
[0024] FIG. 18 is a stereo microscope image of a polymeric
structure formed from crosslinking CMC with aluminum chloride.
[0025] FIG. 19 is a stereo microscope image of a polymeric
structure formed from crosslinking carrageenan with calcium.
[0026] FIG. 20A is an image of polymeric structures formed from
sodium alginate crosslinked with calcium, and FIG. 20B is a stereo
microscope image of these polymeric structures.
[0027] FIG. 21 is an image of polymeric structures formed from the
polyelectrolyte complex (PEC) of chitosan and xanthan.
[0028] FIG. 22 is a stereo microscope image of polymeric structures
formed from the polyelectrolyte complex (PEC) of chitosan and
CMC.
[0029] FIG. 23 is a stereo microscope image of polymeric structures
formed through the co-annular flow comprised of ADBAC and CMC.
[0030] FIG. 24 is an image of polymeric structures formed through
the co-annular flow comprised of ADBAC and CMC and KCl, and FIG. 25
is a stereo microscope image of these polymeric structures.
[0031] FIG. 26 is a schematic illustration of tailoring the length
of the polymeric structure.
[0032] FIGS. 27 A-D are stereo microscope images of various
chitosan fibers to illustrate the effect that shear rate has on the
diameter of the polymeric structure.
[0033] FIG. 28 is a schematic illustration of a possible method of
forming polymeric structures on the surface of the subterranean
formation.
[0034] FIGS. 29 A-D are schematic illustrations of various mixing
arrangements to form polymeric structures.
[0035] FIG. 30 is a schematic illustration of a possible method of
forming polymeric structures on the surface of the subterranean
formation.
[0036] FIG. 31 is a schematic illustrate of a possible method of
forming a polymeric structure.
DETAILED DESCRIPTION
[0037] In the following description, numerous details are set forth
to provide an understanding of the present disclosure. However, it
may be understood by those skilled in the art that the methods of
the present disclosure may be practiced without these details and
that numerous variations or modifications from the described
embodiments may be possible.
[0038] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation-specific
decisions may be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure. In addition, the composition
used/disclosed herein can also comprise some components other than
those cited. In the summary and this detailed description, each
numerical value should be read once as modified by the term "about"
(unless already expressly so modified), and then read again as not
so modified unless otherwise indicated in context. The term about
should be understood as any amount or range within 10% of the
recited amount or range (for example, a range from about 1 to about
10 encompasses a range from 0.9 to 11). Also, in the summary and
this detailed description, it should be understood that a range
listed or described as being useful, suitable, or the like, is
intended to include support for any conceivable sub-range within
the range at least because every point within the range, including
the end points, is to be considered as having been stated. For
example, "a range of from 1 to 10" is to be read as indicating each
possible number along the continuum between about 1 and about 10.
Furthermore, one or more of the data points in the present examples
may be combined together, or may be combined with one of the data
points in the specification to create a range, and thus include
each possible value or number within this range. Thus, (1) even if
numerous specific data points within the range are explicitly
identified, (2) even if reference is made to a few specific data
points within the range, or (3) even when no data points within the
range are explicitly identified, it is to be understood (i) that
the inventors appreciate and understand that any conceivable data
point within the range is to be considered to have been specified,
and (ii) that the inventors possessed knowledge of the entire
range, each conceivable sub-range within the range, and each
conceivable point within the range. Furthermore, the subject matter
of this application illustratively disclosed herein suitably may be
practiced in the absence of any element(s) that are not
specifically disclosed herein.
[0039] Fibers are well known to be used for various purposes in
oilfield treatment operations. For example, methods such as fiber
assisted transport have been used to improve particle transport in
fracturing and wellbore cleanout operations while reducing the
amount of other fluid viscosifiers employed. The methods of the
present disclosure employ polymeric structures (comprising one or
more polymers) formed in situ.
[0040] In some embodiments, the consolidation of the one or more
polymers occurs while the treatment fluid is exposed to a shear
event of a predetermined shear rate in order to form a polymeric
structure with a desired shape and size, such as a polymeric
structure in which the polymeric structure is formed with one
dimension being longer than the other dimensions as a result of the
application of a shear event to the treatment fluid.
[0041] The term "shear event" refers to the exertion of a force (or
energy), such as in the form of shear flow, applied to a pumpable
and/or flowable treatment fluid (or treatment fluid system
including a mixture of two or more treatment fluids) resulting in
shearing deformation. In some embodiments, the pumpable and/or
flowable treatment fluid may have any suitable viscosity, such as a
viscosity of from about 1 cP to about 10,000 cP (such as from about
10 cP to about 1000 cP, or from about 10 cP to about 100 cP) at the
treating temperature, which may range from a surface temperature to
a bottom-hole static (reservoir) temperature, such as from about
-40.degree. C. to about 150.degree. C., or from about 10.degree. C.
to about 120.degree. C., or from about 25.degree. C. to about
100.degree. C., and a shear rate (for the definition of shear rate
reference is made to, for example, Introduction to Rheology,
Barnes, H.; Hutton, J. F; Walters, K. Elsevier, 1989, the
disclosure of which is herein incorporated by reference in its
entirety), during the application of a shear event, in a range of
from about 1 s.sup.-1 to about 100000 s.sup.-1, such as a shear
rate in a range of from about 100 s.sup.-1 to about 10000 s.sup.-1,
or a shear rate in a range of from about 500 s.sup.-1 to about 5000
s.sup.-1 as measured by common methods, such as those described in
textbooks on rheology, including, for example, Rheology:
Principles, Measurements and Applications, Macosko, C. W., VCH
Publishers, Inc. 1994, the disclosure of which is herein
incorporated by reference in its entirety.
[0042] Forming polymeric structures in-situ during a downhole
treatment operation may allow for the production of filaments or
fibers (fiber-like precipitates) with unique morphologies and/or
properties that are not present in filaments or fibers produced by
conventional synthesis methods. Making the polymeric structures
(may also referred to herein as a "fiber-like structure" or
"elongated" provided that the aspect ratio is at least 2:1, unless
otherwise specified) in situ may also reduce the risk of clogging
of wellbore and subterranean structures, and equipment. In
addition, the in-situ formation processes of the present disclosure
may allow for the use of materials that may be incompatible with
surface addition equipment, such as for example, materials that
either stick to the equipment or materials that would not survive
the mixing conditions.
[0043] As used herein, the term "treatment fluid," refers to any
pumpable and/or flowable fluid used in a subterranean operation in
conjunction with a desired function and/or for a desired purpose.
Such fluids may be modified to contain a composition containing a
one or more polymers that may be exposed to a shear event to form
the polymeric structure, which may ultimately become a fiber-like
structure (formed at any time during the treatment operation), such
as by adjusting at least one parameter of the treatment fluid while
exposing the treatment fluid to a shear event to form the polymeric
structure. For example, the treatment fluid may be exposed to a
shear event in which an effective shear rate is being applied to
the treatment fluid while the at least one parameter is adjusted in
order to generate the polymeric structure. In some embodiments, the
treatment fluids of the present disclosure do not contain an
emulsion and/or are of a single phase, for example, either aqueous
or organic.
[0044] In embodiments, the methods of the present disclosure may
include the following actions, in any order: placing a treatment
fluid including at least one or more polymers into a subterranean
formation via a wellbore; adjusting at least one parameter of the
treatment fluid; and exposing the treatment fluid to a shear event
to consolidate the one or more polymers into at least one polymeric
structure. The terms "placing" or "placed" refer to the addition of
a treatment fluid to a subterranean formation by any suitable means
and, unless stated otherwise, do not imply any order by which the
actions occur. Furthermore, the terms "adjusting", "adjusted",
"exposing" "exposed" and "consolidating" and "consolidated", unless
stated otherwise also do not imply any order. The term "introduced"
refers when used in connection with the addition of a treatment
fluid to a subterranean formation may or may not imply an order of
accomplishing the recited actions, if not stated otherwise.
[0045] The term "one or more polymers" refers to one or more
polymeric entities or species that may be used to form polymeric
structures (fiber-like precipitates) in situ during a treatment
operation. For example, polymeric structures of the one or more
polymers, and/or a reaction product thereof, may form upon
adjusting one or more of the parameters of the treatment fluid such
that the one or more polymers consolidates in the treatment fluid
while the treatment fluid is exposed to a predetermined shear rate
in a treatment operation of a subterranean formation, such as a
downhole treatment operation of a subterranean formation. In
embodiments, an identified dissolvable polymer may be used as the
one or more polymers in the treatment fluids and methods of present
disclosure. Such dissolvable polymers may have any desired
molecular weight. For example, the dissolvable polymers suitable
for use as the one or more polymers in the treatment fluids and
methods of present disclosure may have a weight average molecular
weight greater than about 5000 Daltons up to about 20,000,000
Daltons or more, or from about 10,000 Daltons to about 2,000,000.
Specific examples of the one or more polymers are described
below.
[0046] As used herein, the terms "consolidation event" or
"consolidation triggering event" refer to any action that is
sufficient to initiate the consolidation (in the treatment fluid)
of the one or more polymers and/or a reaction product thereof. For
example, the term "consolidating event" as used herein, may include
subjecting the one or more polymers to a mechanical means, physical
means, chemical means, thermal means and other means to initiate,
catalyze, or otherwise induce or cause the one or more polymers to
transform from a dissolved form to an insoluble form. In some
embodiments, consolidating event may be any condition that results
in the consolidation of the one or more polymers comprising one or
more polymers and/or a reaction product thereof, such as, for
example, a pH change, a temperature change, a change in the ionic
concentration (including formation of polyelectrolyte complexes), a
change in hydrophobicity, a change in the solvent composition,
and/or a change in the molecular weight (such as a cross-linking
reactions).
[0047] As used herein, the terms "consolidate"; "consolidation" or
"consolidating" refer to the formation of one or more polymeric
materials into a compact mass. Example of various types of
consolidation include precipitation, amorphous gel formation,
flocculation, coagulation, syneresis, aggregation, crystallization,
coalescence, agglomeration and or combinations thereof. In some
embodiments, the treatment fluid may act as a vehicle that
contains, and optionally chemically isolates, one or more polymers
while it is being transported into the subterranean formation until
the conditions are sufficient for the consolidation to occur.
[0048] The term "treatment," or "treating," does not imply any
particular action by the fluid. For example, a treatment fluid
placed or introduced into a subterranean formation subsequent to a
leading-edge fluid may be a hydraulic fracturing fluid, an
acidizing fluid (acid fracturing, acid diverting fluid), a
stimulation fluid, a sand control fluid, a completion fluid, a
wellbore consolidation fluid, a remediation treatment fluid, a
cementing fluid, a driller fluid, a frac-packing fluid, or gravel
packing fluid. The methods of the present disclosure include
forming a polymeric structure by exposing the treatment fluid
comprising one or more polymers to a shear event effective to form
a polymeric structure (or fiber-like precipitate) of a desired
dimension. The treatment fluids comprising a composition including
a one or more polymers that may be adjusted to form a polymeric
structure upon being induced to consolidate and exposed to a
predetermined amount of shear, may be used in full-scale
operations, pills, or any combination thereof. As used herein, a
"pill" is a type of relatively small volume of specially prepared
treatment fluid placed or circulated in the wellbore.
[0049] As used herein, the term "treating temperature," refers to
the temperature of the treatment fluid that is observed while the
treatment fluid is performing its desired function and/or desired
purpose.
[0050] The term "fracturing" refers to the process and methods of
breaking down a geological formation and creating a fracture, such
as the rock formation around a wellbore, by pumping fluid at very
high pressures (pressure above the determined closure pressure of
the formation), in order to increase production rates from or
injection rates into a hydrocarbon reservoir. The fracturing
methods of the present disclosure may include a composition one or
more polymers that may be consolidated to form a polymeric
structure upon exposure to a predetermined shear rate in one or
more of the treatment fluids, but otherwise use conventional
techniques known in the art.
[0051] The treatment fluids of the present disclosure (and
polymeric structures formed during the methods of the present
disclosure) may be introduced during methods that may be applied at
any time in the life cycle of a reservoir, field or oilfield. For
example, the methods and treatment fluids of the present disclosure
may be employed in any desired downhole application (such as, for
example, stimulation) at any time in the life cycle of a reservoir,
field or oilfield.
[0052] In embodiments, the treatment fluids of the present
disclosure, which comprise a composition containing one or more
polymers that may be consolidated to form a polymeric structure
that is capable of elongation upon exposure to a shear event in
which a predetermined shear rate is applied to the treatment fluid,
may be placed or introduced into a wellbore. A "wellbore" may be
any type of well, including, a producing well, a non-producing
well, an injection well, a fluid disposal well, an experimental
well, an exploratory deep well, and the like. Wellbores may be
vertical, horizontal, deviated some angle between vertical and
horizontal, and combinations thereof, for example a vertical well
with a non-vertical component.
[0053] The term "field" includes land-based (surface and
sub-surface) and sub-seabed applications. The term "oilfield," as
used herein, includes hydrocarbon oil and gas reservoirs, and
formations or portions of formations where hydrocarbon oil and gas
are expected but may additionally contain other materials such as
water, brine, or some other composition.
[0054] As used herein, the term "polymeric structure" refers to any
structure or material that consolidated from exposing the one or
more polymers to a shear event or a consolidation event. The
polymeric structures generated by the methods of the present
disclosure are generally straight, however, curved, crimped,
spiral-shaped, branched, irregular-shaped, and other
three-dimensional geometries may also be formed by the methods of
the present disclosure. Examples of other three-dimensional
geometries include spheres, ovals, ellipsoids and ribbon-like
geometries. The polymeric structures formed in situ by the methods
of the present disclosure may have an aspect ratio of at least
about 1:1. These types of polymeric structures are generally
considered to have a spherical shape. As used herein, the aspect
ratio of the polymeric structure is defined as the ratio of its
average length (that is, its longest dimension) to its average
diameter (that is, its shortest dimension). The polymeric
structures formed in situ by the methods of the present disclosure
are considered to be elongated when they possess an aspect ratio
greater than about 2:1. In embodiments, the polymeric structures
formed in situ by the methods of the present disclosure may have an
aspect ratio greater than about 3:1, or greater than about 4:1, or
greater than about 6:1, or greater than about 10:1, or greater than
about 50:1. In some embodiments, the polymeric structures formed in
situ by the methods of the present disclosure may have an aspect
ratio in the range of from about 1:1 to about 100000:1, or an
aspect ratio in the range of from about 2:1 to about 50000:1, or an
aspect ratio in the range of from about 2:1 to about 1000:1, or an
aspect ratio in the range of from about 3:1 to about 100:1, or an
aspect ratio in the range of from about 4:1 to about 50:1.
[0055] In embodiments, the polymeric structures formed in-situ may
have a diameter of about 5 mm or less. In some embodiments, the
polymeric structures in-situ may have a diameter in the range of
from about 0.01 mm to about 5 mm, such as a diameter in the range
of from about 0.1 mm to about 2 mm. In some embodiments, the
polymeric structures (fiber-like precipitates) formed in-situ may
have a diameter in the range of from about 1 .mu.m to about 250
.mu.m, such as a diameter in the range of from about 10 .mu.m to
about 100 .mu.m.
[0056] One method to control the length and/or morphology of the
consolidated polymeric structure is to impart additional tension on
the material at a given point in the shear field. This may be
accomplishing by accelerating the surrounding fluid through a
constriction placed at a specific distance downstream of the
initial point of consolidation. The acceleration of the surrounding
fluid imparts additional shear and tension, parallel to the flow
field, greater than the tensile/yield strength of the consolidating
material consequently breaking at the injection point. The length
of the material can therefore be controlled by the position of the
injection point and the subsequent downstream restriction. The
length of the material produced in this manner is approximately the
length between these two points. In embodiments, the polymeric
structures formed in-situ may have a length in the range of from
about 500 .mu.m to about 50 cm, such as a length in the range of
from about 1 mm to about 50 cm. In some embodiments, the polymeric
structures formed in-situ may have a length in the range of from
about 500 .mu.m to about 1000 .mu.m.
[0057] As mentioned above, the in situ formation of the polymeric
structure, and/or a reaction product thereof, may prevent the
clogging of structures during the treatment operation (for example,
if the polymeric structures are formed downstream of screens or
tools) and/or materials from sticking on the surface mixing
equipment or other structures near the surface. For example, in
some embodiments, the at least one parameter (which may be adjusted
to initiate the consolidation) is adjusted within the wellbore to
consolidate the one or more polymers after the treatment fluid has
been placed or introduced into the wellbore. In such embodiments,
exposing the treatment fluid to a shear event to form a polymeric
structure may occur at one or more underground locations, such as
underground locations selected from the group consisting of the
wellbore and the subterranean formation. Additionally, in some
embodiments, one or more polymers may be added to the treatment
fluid at an underground location within the wellbore. In such
embodiments, the polymeric structure may be formed downhole, such
as before reaching the target treatment zone or target subterranean
formation, but after the treatment fluid is placed or introduced
into the wellbore. Forming the polymeric structures downhole may
prevent the polymeric structures from settling before the fluid
reaches the target treatment zone or target subterranean
formation.
[0058] The methods of the present disclosure generate polymeric
structures downhole by exposing a treatment fluid that is
undergoing a consolidation event of the one or more polymers
comprised therein to a shearing event in which the treatment fluid
is exposed to a predetermined shearing rate. In embodiments, the
methods of the present disclosure may comprise applying a shearing
force of a predetermined shear rate to a treatment fluid present in
a subterranean formation while the one or more polymers is
consolidated out of the treatment fluid in order to generate a
polymeric structure in situ. Such polymeric structures may be used
in any desired treatment operation, such as, for example, drilling,
reservoir stimulation, and cementing, among others. In some
embodiments, the one or more polymers is not extruded at any time
during the treatment operation. In other words, in embodiments, the
one or more polymers is consolidated out of the treatment fluid (in
the bulk of the treatment fluid) in order to generate the polymeric
structures in situ.
[0059] As discussed in more detail below, in embodiments, the
methods of the present disclosure may manipulate (1) the solubility
of the one or more polymers in a treatment fluid, (2) the chemical
composition of the treatment fluid, and/or (3) the shear event
experienced by the treatment fluid containing the one or more
polymers, to generate a polymeric structure comprising the one or
more polymers and/or a reaction product thereof. In some
embodiments, the polymeric structure may be generated by
simultaneously consolidating the one or more polymers (the
consolidation of which is controlled by adjusting the chemical
and/or physical properties of the treatment fluid) while exposing
the treatment fluid to a shear event.
Generating a Shear Event
[0060] Any suitable method may be used to expose the treatment
fluid to a shear event in which an effective shear rate is applied
to the treatment fluid (for example, concurrently with the
consolidation event and optionally continuing until the
consolidation has ceased) in order to produce the polymeric
structures.
[0061] One of the primary mechanisms to control the diameter and
morphology during the consolidation process is to manipulate the
shear field of the system. A certain amount of shear may generate a
controlled shape, and the diameter of the polymeric structures
formed decreases with shear rate, likely due to the higher
extensional force applied on the fluid containing the one or more
polymers. This trend is observed in various experimental setups and
polymer systems (see e.g., Examples 20-22).
[0062] In some embodiments, the treatment fluid comprising the one
or more polymers may be subjected to a shear event in any mixing
vessel, apparatus or device, such as, for example, mixing vessels,
mixing apparatus, pipes, tubing, conduits, dynamic liquid
dispersing or pumping devices, such as centrifugal pumps. The
treatment fluids can also be exposed to a shearing event while
being pumped in a loop through various pipes, tubing, and/or
conduits. In such embodiments, the treatment fluid may pass through
the pumping apparatus, such as a centrifugal pump, several times
until the desired polymeric structures are obtained. Dynamic
dispersing and pumping devices may be, for example, hydrodynamic
flow machines, for example single- or multiple-stage rotary
centrifugal pumps such as radial centrifugal pumps. A few of the
above-mentioned items are described in more detail below.
[0063] In some embodiments, the shear event may occur in a blender
apparatus, such as the blender apparatus illustrated (in part) in
FIG. 1, and described in detail in U.S. Pat. No. 4,614,435, the
disclosure of which is incorporated herein by reference in its
entirety. Briefly, at the top of the blender apparatus is a hopper
10, which provides a container for solid particles, such as
proppants (not shown). In FIG. 1, the hopper 10 is mounted on the
top side of a housing 11 and held in place by supports 10a. As
illustrated in FIG. 1, the bottom end of the hopper, which is the
outlet end 12, terminates just above inlet eye 13 in housing 11.
Sand or other solids from the hopper are dropped into the housing
through the inlet eye. Positioning the outlet end 12 just above the
inlet eye 13 provides an exterior air exhaust space 14 between the
hopper and the inlet eye.
[0064] A drive shaft 15 is positioned inside the hopper 10, such
that the bottom of the shaft extends through the inlet eye 13 and
into housing 11. The shaft is driven by a motor (not shown) the top
end of the shaft. The motor may be supported by rods 17, which may
be fastened into a housing. The mixer elements of the blender
apparatus for exposing the treatment fluid to a shear event may
include a slinger member 18 and an impeller member 19. The impeller
is secured to the bottom end of drive shaft 15 by a bolt fastener
20.
[0065] Slinger 18 has a central opening therein (not shown) that
allows it to fit over the bottom end of the drive shaft 15 above
the bolt fastener 20. The slinger has a toroidal configuration,
including a concave surface that faces toward the top of the
housing 11.
[0066] As illustrated in FIG. 1, the topside concave surface of
slinger 18 is interrupted by several upstanding blade members 18a.
Housing 11 encloses the slinger 18 and impeller 19, and the housing
includes an outlet port 23, for discharging material from the
housing. In the structure illustrated in FIG. 1 an interior air
exhaust means is provided by one or more air exhaust channels 26.
One end of an inlet conduit 24 is connected into the housing 11 and
the opposite end of the conduit is connected into a source for a
fluid composition, such as first treatment fluid, which may be
consolidated to form a polymeric structure 32. During the mixing
operation the first treatment fluid 30 and optionally a second
treatment fluid 31 may be drawn into the housing 11 through the
inlet conduit 24 and a suction-eye inlet 25 at the bottom of the
housing 11. In such embodiments, the flow rate of the treatment
fluid, for example while the treatment fluid is being exposed to
the shear event that generates the polymeric structures, is in a
range of from about 10 Liters/minute (L/min) to about 12000 L/min,
such as from about 80 L/min to about 8000 L/min, or from about 600
L/min to about 4000 L/min.
[0067] In some embodiments, a first treatment fluid may contain the
one or more polymers, and a second treatment fluid being introduced
into the vessel comprising the first treatment fluid may comprise a
triggering additive (to trigger the consolidation of the one or
more polymers). Such fluids may be mixed in such a manner that a
shear event begins and/or is occurring upon mixing of the two
treatment fluids (while the consolidation of the one or more
polymers is occurring). While the treatment fluid is in the blender
apparatus, consolidation of the one or more polymers may be brought
about by, for example, a mechanical means, physical means, chemical
means, thermal means and other means to initiate, catalyze, or
otherwise induce or cause the one or more polymers and/or a
reaction product thereof to transform from a dissolved form to an
insoluble form.
[0068] In such embodiments, the methods of the present disclosure
may be used to tailor the dimensions (length and/or diameter) of
the polymeric structure by selecting the one or more polymers and
setting the shear rate applied to a treatment fluid that is being
triggered to form a polymeric structure comprising one or more
polymers. In such embodiments (as well as the embodiments discussed
below), such a shear rate (assessed under the conditions discussed
above) may be in a range of from about 1 s.sup.-1 to about 100000
s.sup.-1, such as a shear rate in a range of from about 100
s.sup.-1 to about 10000 s.sup.-1, or a shear rate in a range of
from about 500 s.sup.-1 to about 5000 s.sup.-1, and one or more of
the above shear rates may be used to form a polymeric structure
having a diameter of from about 0.01 mm to about 5 mm, such as a
diameter in the range of from about 0.1 mm to about 2 mm, or from
about 1 .mu.m to about 250 .mu.m, or from about 10 .mu.m to about
100 .mu.m.
[0069] In some embodiments, a solid material, such as a proppant
may be mixed with a treatment fluid suitable for injecting into a
fracture to stimulate recovery of oil or gas. At the start of the
mixing operation, the motor may be employed to rotate the drive
shaft 15, slinger 18, and impeller 19. With the slinger and
impeller in motion, a desired amount of proppant is dropped into
hopper 10, so that it flows in a continuous stream through the
inlet eye 13 and drops onto the rotating slinger 19. As the
proppant drops onto the slinger, it is propelled outwardly into the
housing 11. With the vortex impeller rotating at the same speed as
the slinger, the vortex action of the impeller creates a suction
force inside the housing, and this force pulls the treatment into
the housing through the suction-eye inlet 25 and thereby exposing
the treatment to a shear event that may form polymeric structures
(for example, such polymeric structures may be in addition to those
formed above), if a consolidation event is initiated (as discussed
above).
[0070] Additionally, as the treatment fluid is pulled into the
housing 11, it may be pressurized by the impeller and it interfaces
with the proppant being flung outwardly from slinger 18. The result
is a further location where the treatment fluid may be exposed to a
shear event effective to generate additional polymeric structures
33 (upon triggering the treatment fluid to undergo a consolidation
event). The treatment fluid may then be continuously discharged
under pressure through the outlet port 23, which may expose the
treatment fluid to another shear event effective to generate
polymeric structures (not shown) (upon triggering the treatment
fluid to undergo a consolidation event). From port 23 the treatment
fluid is carried into a pumper unit, for injection into a wellhead
and down the wellbore. The pumper unit, the well head, and the
borehole are not illustrated in the drawing. In such embodiments,
the flow rate of the treatment fluid, for example while the
treatment fluid is being exposed to the shear event that generates
the polymeric structures, is in a range of from about 10
Liters/minute (L/min) to about 12000 L/min, such as from about 80
L/min to about 8000 L/min, or from about 600 L/min to about 4000
L/min.
[0071] In some embodiments, the shear event may occur in an
apparatus, such as the apparatus illustrated in FIG. 2, comprising
a vessel 40 in which there is mounted a stirring mechanism 41
adapted to be driven by a motor (not shown). The vessel and/or
stirring mechanism may include a means, such as one or more inlets
42, for placing a first treatment fluid 43 and a second treatment
fluid 44 and/or continuously recirculating treatment fluid through
the vessel. The stirring mechanism shaft 45 of the apparatus of
FIG. 2 may be a hollow elongated shaft (driven in rotation by the
motor) and extending vertically into the vessel.
[0072] While the treatment fluid is in the apparatus the one or
more polymers may be exposed to a mechanical means, physical means,
chemical means, thermal means and other means to initiate,
catalyze, or otherwise induce or cause the one or more polymers
and/or a reaction product thereof to transform from a dissolved
form to an insoluble form. For example, in the apparatus of FIG. 2,
a first treatment fluid may contain the one or more polymers, and a
second treatment fluid being introduced into the vessel comprising
the first treatment fluid may comprise a triggering additive (to
trigger the consolidation of the one or more polymers). Such fluids
may be mixed in such a manner that a shear event occurs upon mixing
of the two treatment fluids (while the consolidation of the one or
more polymers is occurring). In such embodiments, the flow rate of
the treatment fluid, for example, while the treatment fluid is
being exposed to the shear event that generates the polymeric
structures, is in a range of from about 10 Liters/minute (L/min) to
about 12000 L/min, such as from about 80 L/min to about 8000 L/min,
or from about 600 L/min to about 4000 L/min.
[0073] In such embodiments, the methods of the present disclosure
may be used to tailor the dimensions (length and/or diameter) of
the polymeric structure by selecting the appropriate one or more
polymers and setting the shear rate applied to a treatment fluid
that is being triggered to form a polymeric structure comprising
one or more polymers. In such embodiments (as well as the
embodiments discussed below), such a shear rate may be in a range
of from about 50 s.sup.-1 to about 100000 s.sup.-1 (for example,
shear rates toward the upper end of this range may be generated
when the second treatment fluid is introduced into the first
treatment fluid via a nozzle, such as a bit nozzle), such as a
shear rate in a range of from about 100 s.sup.-1 to about 10000
s.sup.-1, or a shear rate in a range of from about 500 s.sup.-1 to
about 5000 s.sup.-1.
[0074] Circulation of the first treatment fluid may be driven by an
impeller 45 (or a plurality of impeller vanes) mounted on the shaft
about its lower or perforated end, the vanes extending outwardly
from the shaft. The impeller 45 may have any geometry that induces
rotational mixing. Rotation of the vane(s) with the shaft creates,
adjacent the lower end of the shaft, a region where a shear event
effective to generate polymeric structures 46 may also occur (upon
triggering the treatment fluid to undergo a consolidation
event).
[0075] In some embodiments, exposure to low and/or high shear may
also be brought about within the tubulars during pumping from the
surface to reservoir depth. For example, as illustrated in FIG. 3,
the shear event effective to generate polymeric structures 52 (upon
triggering the treatment fluid to undergo a consolidation event,
such as, for example, by a change in downhole conditions) may occur
in a pipe 50. For example, in some embodiments, the treatment fluid
comprising one or more polymers may be exposed to the consolidation
event that is brought about by a predetermined downhole condition
(such as, for example, temperature or pressure) or predetermined
downhole environment (such as for example, the surrounding
chemicals, the phase thereof, pH, ionic strength, temperature,
pressure, etc.). In some embodiments, the treatment fluid may
contain the one or more polymers and a triggering additive.
[0076] Any suitable pipe shape, such as a cylindrical pipe 50, as
illustrated in FIG. 3, in which an effective shear rate may be
generated may be used. In embodiments, the shear rate in the pipe
may depend on the geometry of the pipe and the flow rate of the
treatment fluid 51. In some embodiments, the flow rate of the
treatment fluid, for example while the treatment fluid is being
exposed to the shear event that contributes to the generation of
the polymeric structures, is in a range of from about 10
Liters/minute (L/min) to about 20000 L/min, such as from about 80
L/min to about 16000 L/min, or from about 800 L/min to about 12000
L/min.
[0077] In some embodiments, exposing the treatment fluid to a shear
event may involve pumping the one or more fluids downhole via
tubing or a pipe having a perforated portion, as illustrated in
FIG. 4. For example, as shown in FIG. 4, an inner pipe 60 with a
perforated end 61 comprising a plurality of openings 62 may be used
to generate polymeric structures 63 (upon triggering the treatment
fluid undergo a consolidation event, as discussed above). For
example, a first treatment fluid 64 being introduced into the inner
pipe 60 may contain the one or more polymers, and a second
treatment fluid 65 being introduced into the wellbore annulus 66
may comprise a triggering additive (to trigger the consolidation of
the one or more polymers upon the coannular mixing of the first and
second treatment fluids). In such embodiments, the above-mentioned
first treatment fluid may be introduced into the wellbore annulus
66 and the above-mentioned second treatment fluid may be introduced
into the inner pipe 60. In such embodiments, the flow rate of the
first and second treatment fluid, for example while the first and
second treatment fluid is being exposed to the shear event that
generates the polymeric structures, is in a range of from about 10
Liters/minute (L/min) to about 20000 L/min, such as from about 80
L/min to about 16000 L/min, or from about 800 L/min to about 12000
L/min.
[0078] In some embodiments, as illustrated in FIG. 5, the shear
event may generated due to the presence of a perforations 70 in the
wellbore adjacent to the formation 71, such as perforations in a
wellbore casing or a perforated pipe. In embodiments, the width may
be made narrow to keep out particulate contaminants while
maintaining acceptable flow rates to ensure an adequate shear rate
may be obtained to generate the polymeric structure.
[0079] In embodiments, a first treatment fluid 72 being introduced
into the inner pipe 73 may contain the one or more polymers, and a
second treatment fluid 74 being introduced into the wellbore
annulus 75 may comprise a triggering additive (to trigger the
consolidation of the one or more polymers upon the coannular mixing
of the first and second treatment fluids). If desired, the first
treatment fluid and the second treatment fluid may be the same. In
such embodiments, the treatment fluid comprising the one or more
polymers may be exposed to the consolidation event that is brought
about by a predetermined downhole condition (such as, for example,
temperature or pressure) or predetermined downhole environment
(such as for example, the surrounding chemicals, the phase thereof,
pH, ionic strength, temperature, pressure, etc.). In such
embodiments, the flow rate of the treatment fluid through the
perforations, and while the treatment fluid is being exposed to the
shear event that generates the polymeric structures, is in a range
of from about 10 Liters/minute (L/min) to about 20000 L/min, such
as from about 80 L/min to about 16000 L/min, or from about 800
L/min to about 12000 L/min.
[0080] In embodiments, conduits, coiled tubing with a perforated
end, or a pipe with one or more bit nozzles may also be used in a
similar manner to generate polymeric structures (upon triggering
the treatment fluid undergo a consolidation event, as discussed
above). In embodiments, a pumping apparatus (positioned either at
the surface of the wellbore or down hole, or both) may be used in
connection with conduits having a perforated portion, such as, for
example, a perforated end; tubing or a pipe having a perforated
portion, such as, for example, a pipe with a perforated end; coiled
tubing having a perforated portion, such as, for example, a
perforated end; or a pipe with one or more bit nozzles.
[0081] For example, in some embodiments, the pumping apparatus may
be connected to a first conduit and a second conduit. For example,
the pumping apparatus may be connected to concentric coil tubing.
Concentric coil tubing may be transported on a truck mounted coil
or reel. Concentric coil tubing may have an inner tube and an outer
tube. In embodiments, the inner tube serves as the first conduit,
which may contain the treatment fluid of the present disclosure,
and/or a component that triggers the consolidation of the one or
more polymers. An annulus formed between the inner tube and the
outer tube can serve as the second conduit, which may contain the
treatment fluid of the present disclosure, and/or a component that
triggers the consolidation of the one or more polymers. In some
embodiments, a pump truck may also be used to supply the desired
pumping force to generate an effective shear event.
[0082] In some embodiments, the methods of the present disclosure
may comprise activating an additional pumping apparatus to increase
the pressure in one or more of the conduits until a shear rate
effective to form polymeric structures during a consolidation
event. Such a shear rate may be created by a condition in which
pressure in the inner tube is greater than pressure within outer
tube and wellbore. This induces a shearing event as the fluids in
the inner tube are pushed from the inner tube into a stagnate
and/or more slowly moving treatment fluids of outer tube (or
wellbore). The shear rate induced by such a shearing event may
depend on a variety of factors, such as, the viscosity of the
treatment fluids and the amount of the pressure differential
(and/or flow velocities (or flow rates) of the treatment
fluids).
[0083] In some embodiments, the treatment fluid may be pumped into
wellbore via an inner tube that serves to transport the treatment
fluid to one or more nozzles that may be used to expose the
treatment fluid to an effective shear event to enable polymeric
structures to be formed in an annulus that serves as the second
conduit.
[0084] In some embodiments, the pumping apparatus may be equipped
with an electronics package, containing a plurality of sensors. It
is contemplated that the various operating parameters sensed would
include pressure in the wellbore, temperature changes in the
wellbore, and the relative percentage of various components present
in the treatment fluids that are being pumped into the wellbore.
The flow rates of the fluids at various locations in the wellbore,
such as through the perforations and/or the one or more nozzles may
be estimated by mathematical calculation. The flow rate of
treatment fluids is monitored, and the shear rate the treatment
fluids are being exposed to is estimated. The shear rate the
treatment fluids are being exposed to may be adjusted by altering
the flow rate, if desired. In some embodiments, once an appropriate
shear rate has been achieved, at least one parameter of the
treatment fluid may be adjusted to trigger consolidation of the one
or more polymers.
[0085] The application of a predetermined effective shear rate
while the one or more polymers is consolidating out of the
treatment fluid helps to ensure that the one or more polymers will
not merely consolidate and disperse into an undesired morphology in
the treatment fluid. The sensing of the flow rate through multiple
sensors may assist in determining when that condition has been
achieved.
[0086] As discussed above, the polymeric structures may be formed
on the surface of the subterranean formation and subsequently
placed into the subterranean formation. One example process for the
surface creation of the polymeric structures is illustrated in FIG.
28. In FIG. 28, carboxymethyl cellulose (CMC) is shown as an
illustrative chemistry, although many of the one or more polymers
described above may also be employed with an expectation of similar
result. The polymer (CMC) is mixed with water and hydrated in a
tank or a continuous mix hydration device 2801, such as, a
precision-continuous mix (PCM) unit. All or a portion of the
polymer may then be sent via a first stream 2802 (may also be
referred to as first treatment fluid) to a mixing arrangement 2803,
which governs the morphology of the polymeric structure. At the
mixing arrangement 2803, the first stream 2802 is mixed with a
second stream 2804 (which may be a surfactant or second
polymer--may also be referred to as second treatment fluid) to
create consolidated polymeric structures 2805 in the fluid. For the
CMC chemistry example, the surfactant or second polymer would
typically be cationic materials to complex with the polymer.
[0087] Once formed, the polymeric structures 2805 can be combined
with additional polymer solution 2806 to increase the fluid
viscosity. The resulting suspension of polymeric structures 2807 in
a viscous fluid may then be delivered to a blending device 2808,
such as a POD blender, as described in U.S. Pat. Nos. 4,453,829,
4,671,665, 4,614,435, 4,838,701, 4,808,004, 5,046,856, 5,667,012,
7,845,516 and 7,740,447, and U.S. Patent Application Pub. Nos.
2008/0212397, 2011/0235460 and 2012/0298210, the disclosures of
which are incorporated by reference herein in their entirety, where
sand or proppant can be added to the fluid. After this, the fluid
may then be delivered through the high pressure pumps 2809 to the
wellhead (not shown) for flow downhole into the subterranean
formation.
[0088] As discussed above, the morphology of the polymeric
structure may be influenced by the mixing arrangement 2803 of
streams 2802 and 2804 in FIG. 28. FIG. 29A-D illustrates some
options for mixing arrangements. FIG. 29A illustrates an impinging
tee, where streams 2802 and 2804 mix to form polymeric structures
2805. FIG. 29B illustrates a side stream injection in a tubular,
where streams 2802 and 2804 combine to form polymeric structures
2805.
[0089] FIG. 29C illustrates the formation of polymeric structures
with a nozzle as the mixing arrangement 2803. As shown in FIG. 29C,
an inner pipe 2901 may be used to generate polymeric structures
2805 (upon triggering the treatment fluid to undergo a
consolidation event, as discussed above). For example, a first
treatment fluid 2802 being introduced into the inner pipe 2901 may
contain the one or more polymers, and a second treatment fluid 2804
being introduced into the annulus 2902 of outer pipe 2903 may
comprise a triggering additive (to trigger the consolidation of the
one or more polymers upon the coannular mixing of the first and
second treatment fluids). In such embodiments, the above-mentioned
first treatment fluid 2802 may be introduced into the annulus 2902
and the above-mentioned second treatment fluid 2804 may be
introduced into the inner pipe 2901 (not shown).
[0090] FIG. 29D illustrates the formation of polymeric structures
with a perforated nozzle as the mixing arrangement 2803. A similar
embodiment is described above in FIG. 4. In some embodiments,
exposing the treatment fluid to a shear event may involve pumping
the one or more fluids via a pipe having a perforated portion, as
illustrated in FIG. 29D. For example, as shown in FIG. 29D, an
inner pipe 2901 comprising a plurality of openings or perforations
2904 may be used to generate polymeric structures 2805 (upon
triggering the treatment fluid to undergo a consolidation event, as
discussed above). For example, a first treatment fluid 2802 being
introduced into the inner pipe 2901 may contain the one or more
polymers, and a second treatment fluid 2804 being introduced into
the annulus 2902 of the outer pipe 2903 may comprise a triggering
additive (to trigger the consolidation of the one or more polymers
upon the coannular mixing of the first and second treatment
fluids). In such embodiments, the above-mentioned first treatment
fluid 2802 may be introduced into the annulus 2902 and the
above-mentioned second treatment fluid 2804 may be introduced into
the inner pipe 2901 (not shown).
[0091] Another example process for the surface creation of the
polymeric structures is illustrated in FIG. 30. In FIG. 30, sodium
alginate is shown as an illustrative chemistry, although many of
the one or more polymers described above may also be employed with
an expectation of similar result. The first polymer (sodium
alginate) is mixed with water and hydrated in a tank or a
continuous mix hydration device 2801, such as, a
precision-continuous mix (PCM) unit. The second polymer (guar) is
mixed with water and hydrated in a tank or a continuous mix
hydration device 3001, such as, a precision-continuous mix (PCM)
unit. All or a portion of the first polymer may then be sent via a
first stream 2802 (may also be referred to as first treatment
fluid) to a mixing arrangement 2803, which governs the morphology
of the polymeric structure. At the mixing arrangement 2803, the
first stream 2802 is mixed with a second stream 2804 containing the
triggering additive and a second polymer (may also be referred to
as second treatment fluid) to create consolidated polymeric
structures 2805 in the fluid. For the sodium alginate chemistry
example, the second polymer would typically be a viscosifying
polymer that would not react with the first polymer, such as a
polysaccharide like guar. The resulting suspension of polymeric
structures 2807 in a viscous fluid may then be delivered to a
blending device 2808, such as a POD blender where sand or proppant
can be added to the fluid. After this, the fluid may then be
delivered through the high pressure pumps 2809 to the wellhead (not
shown) for flow downhole into the subterranean formation.
Furthermore, the one or more polymers in the first treatment fluid
may be referred to as "shape polymer", which is the polymer that
may undergo consolidation. The triggering additive may also be
referred to as a "viscosifying polymer" and is essentially inert
under the wellbore conditions such that it does not become a part
of the polymeric structure.
Selection of the One or More Polymers
[0092] Selection of the one or more polymers for use in the methods
of the present disclosure may depend on many factors, such as the
anticipated changes to the treatment fluid parameters and/or
composition during a treatment operation in order to induce
consolidation by one or more of the above-mentioned consolidation
events. Additional factors include the desired characteristics of
the ultimate polymeric structure being formed, including its
chemistry, its dimensions and morphology, and its desired
concentration, among other factors, including the specific
treatment operation and/or the way in which the polymeric structure
will be used.
[0093] The selection of the one or more polymers may also take into
account the nature of the subterranean operation, for example,
whether or not fluid loss control is desired, the temperature, the
nature of the formation, and the time desired before a break occurs
and/or the time desired by which a break has occurred.
[0094] In some embodiments, the one or more polymers for use in the
methods of the present disclosure may be selected such that the
chemical comprised in the treatment fluid may have predetermined
condition, such as temperature, pH, salinity, ionic concentration,
solvent composition, etc., at which the one or more polymers
consolidates out of the treatment fluid. In other words, one or
more polymers suitable for use in the methods of the present
disclosure may be selected to have defined chemical and/or physical
conditions (that can be replicated downhole) under which it
consolidates.
[0095] In some embodiments, the consolidation of the one or more
polymers, and/or a reaction product thereof, may be selected
because the particular one or more polymers may be controlled by
adjusting a single chemical or physical condition alone, such as by
adjusting the temperature, salinity, ionic concentration (for
example, formation of polyelectrolyte complexes), pH,
hydrophobicity, solvent composition, or molecular weight (for
example, cross-linking reactions). In such embodiments, methods of
the present disclosure may comprise applying a shearing force of a
predetermined shear rate to a treatment fluid present in a
subterranean formation while the one or more polymers is
consolidating out of the treatment fluid (in response to the
adjustment of the single chemical condition) in order to generate
elongated (fiber-like) consolidates in situ.
[0096] In embodiments, the treatment fluid and the one or more
polymers may be selected to avoid premature consolidation. Then,
when it is desired to consolidate the one or more polymers the
environmental conditions may be altered, such as by placing a
second (or subsequent) treatment fluid, and/or and additional
component, to modify treatment fluid such that conditions under
which the one or more polymers will consolidate are generated.
[0097] In some embodiments, a component in the treatment fluid
pumped into the wellbore, or an additional component added to the
treatment fluid downhole, triggers the consolidation of the one or
more polymers, and/or a reaction product thereof. This component
and/or additional component may optionally be coated to slow the
initiation of the consolidation of the one or more polymers.
Suitable coatings are known and may include polycaprolate (a
copolymer of glycolide and .epsilon.-caprolactone), and calcium
stearate, both of which are hydrophobic. Generating a hydrophobic
layer on the surface of the component and/or additional component
(by any means) may also be used delays the consolidation of the one
or more polymers. The term "coating", as described herein may refer
to encapsulation or simply to changing the surface by chemical
reaction or by forming or adding a thin film of another material.
Any other suitable method for delaying the consolidation of the one
or more polymers may also be employed, as desired.
[0098] In embodiments, the one or more polymers may be selected
such that it dissolves in the treatment fluid under downhole
conditions, but may be triggered to consolidate by one or more of
the means described above. The concentration of the one or more
polymers that is dissolved in the initial treatment fluid may
depend on a number of factors, such as the particular chemical and
physical make-up of the one or more polymers, and the end use of
the polymeric structures. In embodiments, the treatment fluids used
in the methods of the present disclosure may contain the one or
more polymers in any desired amount that is sufficient to form the
desired concentration of fiber-like consolidate downhole. In some
embodiments, the amount of fiber-like consolidate may be in a range
of from about 0.01 wt. % to about 10 wt. %, or in a range of from
about 0.01 wt. % to about 4.0 wt. %, such as in a range of from
about 0.05 wt. % to about 2.0 wt. %. In embodiments where proppant
is present, the amount of fiber-like consolidate may be in a range
of from about 1.5 g/L to about 3.0 g/L (or in a range of from about
2.2 g/L to about 2.6 g/L) for proppant loadings of about 0.12 to
about 0.36 kg/L (about 1 to about 3 PPA); in a range of from about
2.5 g/L to about 4.5 g/L (or in a range of from about 3.4 g/L to
about 3.8 g/L) for proppant loadings of about 0.36 to about 0.6
kg/L (about 3 to about 5 PPA); and in a range of from about 4.0 g/L
to about 5.8 g/L (or in a range of from about 4.6 g/L to about 5.0
g/L) for proppant loadings of over 0.6 kg/L (about 5 PPA).
[0099] In embodiments, the treatment fluids used in the methods of
the present disclosure may contain the dissolved one or more
polymers in amounts of from about 0.1% to about 20% by weight of
the treatment fluid, or in amounts of from about 0.5% to about 10%
by weight of the treatment fluid, and in amounts of from about 1%
to about 6% by weight of the treatment fluid. In some embodiments,
the treatment fluids used in the methods of the present disclosure
may contain the one or more polymers, and the one or more polymers
may be present in the treatment fluid in amounts of from about 0.1%
to about 20% by weight of the treatment fluid, or in amounts of
from about 0.5% to about 10% by weight of the treatment fluid, and
in amounts of from about 1% to about 6% by weight of the treatment
fluid. In some embodiments, the one or more polymers may be added
to the treatment fluid downhole, while its concentration in the
surface prepared treatment fluid is effectively zero.
[0100] In some embodiments, most of the one or more polymers
initially dissolved and/or dispersed in the treatment fluid arrives
at the target treatment zone or target subterranean formation after
consolidating and forming a polymeric structure (after being
exposed to a predetermined shear rate), for example, at least about
0.1% by weight of the one or more polymers initially dissolved
and/or dispersed in the treatment fluid, or at least about 1.0% by
weight of the one or more polymers initially dissolved and/or
dispersed in the treatment fluid, or at least about 10.0% by weight
of the one or more polymers initially dissolved in the treatment
fluid, may arrive at the target treatment zone or target
subterranean formation in a polymeric structure formed while being
exposed to a predetermined shear rate.
[0101] In some embodiments, the one or more polymers may be added
separately to the treatment fluid, after the treatment fluid has
been pumped downhole. The concentration of the one or more polymers
that is added to the treatment fluid downhole may depend on a
number of factors, such as the particular chemical and physical
properties of the one or more polymers, and the end use of the
polymeric structures.
[0102] The one or more polymers dissolved in the treatment fluid
may be composed of a single monodisperse polymer, a single
polydisperse polymer, or the one or more polymers dissolved in the
treatment fluid may include a mixture of two or more polydisperse
polymers, where at least one of the polymers may be triggered to be
insoluble in the solvent or mixture of solvents of the treatment
fluid. At least one of the dissolvable polymers used in the
treatment fluid should be able to exist in a solid and/or gel form
under conditions where the polymer is not dissolved.
[0103] Initially, the one or more polymers may be dissolved in the
treatment fluid by altering conditions or parameters of the
treatment fluid such as temperature, salinity, ionic concentration
(formation of polyelectrolyte complexes), pH, hydrophobicity,
solvent composition, and/or molecular weight (of the one or more
polymers, such as a cross-linking reactions) to ensure the one or
more polymers are able to fulfill its soluble-state function, such
as for example, mixing with other components in the treatment fluid
and being introduced to the wellbore and/or subterranean
formation.
[0104] The one or more polymers may be natural polymers, synthetic
polymers, polyelectrolytes or biopolymers (or derivatives thereof)
or mixtures thereof that comprise a crosslinkable moiety, for
example, substituted galactomannans, guar gums, high-molecular
weight polysaccharides composed of mannose and galactose sugars, or
guar derivatives, such as hydrophobically modified guars,
guar-containing compounds, and synthetic polymers. Suitable polymer
chemical entities may comprise a guar gum, a locust bean gum, a
tara gum, a honey locust gum, a tamarind gum, a karaya gum, an
arabic gum, a ghatti gum, a tragacanth gum, a carrageenen, a
succinoglycan, a xanthan, a diutan, scleroglucan, alginates, a
hydroxylethyl guar, a hydroxypropyl guar (HPG), a
carboxymethylhydroxyethyl guar, a carboxymethylhydroxypropyl guar
(CMHPG), polyanionic cellulose (PAC), a carboxyalkyl cellulose,
such as carboxymethyl cellulose (CMC) or carboxyethyl cellulose, an
alkylcarboxyalkyl cellulose, an alkyl cellulose, an
alkylhydroxyalkyl cellulose, a carboxyalkyl cellulose ether, a
hydroxyethylcellulose (HEC), hydroxypropylcellulose (HPC), a
carboxymethylhydroxyethyl cellulose (CMHEC), a carboxymethyl
starch, a copolymer of 2-acrylamido-2methyl-propane sulfonic acid
and acrylamide, a terpolymer of 2-acrylamido-2methyl-propane
sulfonic acid, acrylic acid, acrylamide, or derivative thereof. The
polymer may be a cationic polymer such as chitosan, cationic guar,
gelatin, collagen, or other polypeptide, polyethyleneimine (PEI),
diallyldimethylammonium chloride (DADMAC), polyvinyl pyrrolidone
(PVP), polyvinylamine (PVA), or other polyamine. The polymer may
also be a synthetic polymer such as, for example, a polyacrylamide
including partially hydrolyzed polyacrylamide (PHPA); polyvinyl
alcohol; polyethylene glycol; polypropylene glycol; polyacrylic
acid or polymethacrylic acid; as well as copolymers and mixtures
thereof.
[0105] In embodiments, the one or more polymers may present at
about 0.01% to about 4.0% by weight based on the total weight of
the treatment fluid, such as at about 0.10% to about 2.0% by weight
based on the total weight of the treatment fluid.
[0106] In embodiments, the one or more polymers may be
functionalized, such as hydrophobically modified to inhibit or
delay solubilization and/or consolidation. For example, in
embodiments where the one or more polymers of the one or more
polymers may include a polyol, the polyol may be hydrophobically
modified by including hydrocarbyl substituents, such as, for
example, alkyl, aryl, alkaryl or aralkyl moieties and/or side
chains having from about 2 to about 30 carbon atoms, or about 4 to
about 20 carbon atoms.
[0107] In embodiments, the one or more polymers may be modified to
include carboxylic acid groups, thiol groups, paraffin groups,
silane groups, sulfuric acid groups, acetoacetylate groups,
polyethylene oxide groups, and/or quaternary amine groups. Such
modifications may be used to influence one or more properties of
the polymer, which may be used to adjust the solubilization and/or
consolidation properties of the polymer. For example, such
modifications may be used to modify the one or more polymer's
sensitivity to salinity, pH, ionic strength and/or solvent
compositions. Such modifications may also introduce crosslinking
functionalities (such as hydroxyl groups and silanol groups, which
are chelates that can crosslink with common crosslinkers).
Conventional methods of making such modifications are known.
[0108] In the methods of the present disclosure, after the one or
more polymers has fulfilled its soluble-state function, the
conditions under which at least one of the one or more polymers
were dissolved are altered such that at least one of the one or
more polymers consolidates. During this consolidation process the
treatment fluid in which the one or more polymers are dissolved is
exposed to a predetermined shear rate to form a polymeric structure
in situ. After this polymeric structure (also referred to herein as
a "fiber-like consolidate", unless otherwise specified) is formed
in situ, the polymeric structure (comprising the one or more
polymers) may perform its solid-form function (or gel-form
function) as a fiber-like component of a treatment fluid, such as,
for example, a fluid loss control pill, a water control treatment
fluid, a scale inhibition treatment fluid, a fracturing fluid, a
gravel packing fluid, a drilling fluid, a drill-in fluid, or
cementing fluid.
[0109] The methods of the present disclosure (such as drilling,
fracturing, cementing, or completion methods) may include a
composition containing one or more polymers that may be triggered
to undergo a consolidation event such that the consolidate that is
formed is a polymeric structure (which forms in situ when the
treatment fluid is exposed to a predetermined effective shear rate
during the consolidation event), but otherwise use conventional
techniques known in the art.
[0110] In some embodiments, the formation of the polymeric
structures (generated by the methods of the present disclosure) is
reversible. The resulting dissolved chemical entities may be used
as a breaker for various crosslinked systems, such as crosslinked
guar based or other polymer-viscosified fluids. For example, the
action of the re-dissolved one or more polymers may effectively act
to take borate, titanate, zirconate and similar ions away from the
guar based molecules, thereby reducing the viscosity of the
crosslinked polymer to that of a linear gel.
[0111] While the methods and treatment fluids of the present
disclosure are described herein as comprising the above-mentioned
components, it should be understood that the methods and fluids of
the present disclosure may optionally comprise other additional
materials, such as the materials and additional components
discussed below, which relate to various methods of forming
polymeric structures from the one or more polymers.
[0112] As discussed in more detail below, after the polymeric
structure is formed it may perform its intended solid-state
function and/or application, for example, as a fiber-like component
in a drilling fluid, a fracturing fluid, cement slurry, or a
completion fluid. Such materials are described in U.S. Pat. Nos.
5,330,005, 5,439,055; 5,501,275; 6,172,011; and 6,419,019, the
disclosures of which are hereby incorporated by reference in their
entireties. Furthermore, any additives normally used in such
treatments may be included, provided that they are compatible with
the other components and the desired results of the treatment. Such
additives may include anti-oxidants, crosslinkers, corrosion
inhibitors, delay agents, biocides, buffers, fluid loss additives,
etc.
Use of Dispersants to Increase Viscosity of the Slurry Mixture
[0113] In addition to the different methods for delivering
reactants to the wellbore, it may be useful to improve the flow of
the slurry by introducing one or more dispersants to the slurry may
decrease the viscosity of the slurry. This will improve the
pumpability of the slurry and make it easier to be delivered into
the wellbore. By employing dispersants, the reactants may be
dispersed more evenly throughout the slurry. As such, the reactants
may be ignited throughout the volume of the slurry and may
contribute to a greater volumetric expansion of the slurry to
further open the surrounding fractures.
[0114] After the thermite reactions are ignited, the thermite
reactions may generally sustain itself. In other words, after the
thermite reaction is ignited, the thermite reaction may produce
enough heat to continue to react until the reactants are
substantially exhausted (e.g., the reaction is substantially
complete). The ignition and propagation of the thermite reaction a
carrier fluid may be complicated by a heat loss of the reactants to
the carrier fluid. As such, when the heat lost by thermite
reactants to the carrier fluid exceeds a threshold, the thermite
reaction may not continue to propagate.
[0115] The heat lost by the thermite reactants to the surrounding
carrier fluid may be balanced against the volume of carrier fluid
that is utilized to ensure that the slurry mixture remains
pumpable. In other words, it may be desirable to create the slurry
mixture such that the lowest possible fluid volume fraction is
utilized while the slurry mixture is still pumpable. As described
above, one such method to increase the pumpability of the slurry
mixture is to add one or more dispersants to the slurry mixture.
The dispersants may be added to the slurry mixture in any suitable
manner, including but not limited to: preparing the
dispersant-slurry mixture in a batch mixing tank followed by
injecting the dispersant-slurry mixture into the wellbore, pumping
a carrier-fluid and dispersant solution to the wellbore and later
adding the thermite reactants to the carrier-fluid and dispersant
solution on the fly in a relatively continuous manner, and/or
pumping a carrier-fluid to the wellbore and later adding the
thermite reactants and the dispersants to the carrier-fluid on the
fly in a relatively continuous manner.
[0116] In certain embodiments, the dispersants may be polymers
(e.g., polyacrylic acid), polyacrylates (e.g., ammonium, sodium,
potassium polyacrylates), polymethacrylic acid, polymethacrylates
(e.g., ammonium, sodium, potassium polymethacrylates),
polycarboxylates, polyvinylpyrolidones, polystyrene sulfonate,
polynaphthalene sulfonates, lignosulfonates, other sulfonates,
polyacrylamides, poly(2-acrylamido-2-methyl-1-propanesulfonic acid)
(e.g., polyAMPS), as well as derivatives, copolymers, and any
mixtures of the above polymers.
[0117] Other examples of dispersants may be small molecule
surfactants, such as sulfonates, phosphates, carboxylates (e.g.
acrylates, methacrylates, etc.), dodecylbenzene sodium sulfonate,
trisodium phosphate, aurintricarboxylic acid ammonium salt,
4-5-dihydroxy-1, 3-benzenedisulfonic acid disodium salt, and sodium
hexametaphosphate, as well as derivatives and mixtures of the above
surfactants.
[0118] The benefits of adding the dispersants to the slurry mixture
may be further understood with reference to the following examples.
In one non-limiting example, 5 grams (g) of a thermite mixture was
prepared by mixing 1.25 g of aluminum and 3.75 g of iron (III)
oxide. Approximately 1.06 g of deionized water and 0.14 g of a 25%
aqueous solution of ammonium polymethacrylate were added to the
thermite mixture and mixed. When the dispersant (e.g., ammonium
polymethacrylate) was added to the thermite mixture, the resulting
thermite mixture became pumpable. In this example, the volume
fraction of the thermite in the mixture was approximately 0.50.
However, without the addition of the dispersant, a mixture composed
of 0.50 volume fraction thermite was a crumbly powder, i.e. it was
not pumpable. In other words, without the addition of the
dispersant to the thermite mixture, the thermite mixture was not
pumpable.
[0119] In another non-limiting example, 5 g of a thermite mixture
was prepared by mixing 1.25 grams (g) of aluminum) and 3.75 g of
iron (III) oxide. Approximately 1.13 g of deionized water and 0.07
g of a 43% aqueous solution of sodium polyacrylate) was added to
the thermite mixture, the resulting thermite mixture was able to be
pumped (i.e., pumpable). In this example, the volume fraction of
the thermites in this solution was approximately 0.50. As in the
example above, without the addition of the dispersant to the
solution, the thermite mixture may be a crumbly powder. In other
words, without the addition of the dispersant to the thermite
mixture, the thermite mixture was not pumpable.
[0120] It may be appreciated that the amount of dispersants added
to the slurry mixture may range from approximately 0.1 to 10%
weight percent of the dispersant, 1 to 5% weight percent, or any
weight percentage there between.
Treatment Fluid
[0121] As discussed above, the treatment fluid carrying the one or
more polymers may be any well treatment fluid, such as a fluid loss
control pill, a water control treatment fluid, a scale inhibition
treatment fluid, a fracturing fluid, a gravel packing fluid, a
drilling fluid, and a drill-in fluid. The carrier solvent for the
treatment fluid may be a pure solvent or a mixture. Suitable
solvents for use with the methods of the present disclosure, such
as for forming the treatment fluids disclosed herein, may be
aqueous or organic based. Aqueous solvents may include at least one
of fresh water, sea water, brine, mixtures of water and
water-soluble organic compounds and mixtures thereof. Organic
solvents may include any organic solvent that is able to dissolve
or suspend the various components, such as the chemical entities
and/or components of the treatment fluid.
[0122] Suitable organic solvents may include, for example,
alcohols, glycols, esters, ketones, nitrites, amides, amines,
cyclic ethers, glycol ethers, acetone, acetonitrile, 1-butanol,
2-butanol, 2-butanone, t-butyl alcohol, cyclohexane, diethyl ether,
diethylene glycol, diethylene glycol dimethyl ether,
1,2-dimethoxy-ethane (DME), dimethylether, dibutylether, dimethyl
sulfoxide (DMSO), dioxane, ethanol, ethyl acetate, ethylene glycol,
glycerin, heptanes, hexamethylphosphorous triamide (HMPT), hexane,
methanol, methyl t-butyl ether (MTBE), N-methyl-2-pyrrolidinone
(NMP), nitromethane, pentane, petroleum ether (ligroine),
1-propanol, 2-propanol, pyridine, tetrahydrofuran (THF), toluene,
triethyl amine, o-xylene, m-xylene, p-xylene, ethylene glycol
monobutyl ether, polyglycol ethers, pyrrolidones, N-(alkyl or
cycloalkyl)-2-pyrrolidones, N-alkyl piperidones, N, N-dialkyl
alkanolamides, N,N,N',N'-tetra alkyl ureas, dialkylsulfoxides,
pyridines, hexaalkylphosphoric triamides,
1,3-dimethyl-2-imidazolidinone, nitroalkanes, nitro-compounds of
aromatic hydrocarbons, sulfolanes, butyrolactones, alkylene
carbonates, alkyl carbonates, N-(alkyl or
cycloalkyl)-2-pyrrolidones, pyridine and alkylpyridines,
diethylether, dimethoxyethane, methyl formate, ethyl formate,
methyl propionate, acetonitrile, benzonitrile, dimethylformamide,
N-methylpyrrolidone, ethylene carbonate, dimethyl carbonate,
propylene carbonate, diethyl carbonate, ethylmethyl carbonate,
dibutyl carbonate, lactones, nitromethane, nitrobenzene sulfones,
tetrahydrofuran, dioxane, dioxolane, methyltetrahydrofuran,
dimethylsulfone, tetramethylene sulfone, diesel oil, kerosene,
paraffinic oil, crude oil, liquefied petroleum gas (LPG), mineral
oil, biodiesel, vegetable oil, animal oil, aromatic petroleum cuts,
terpenes, mixtures thereof.
[0123] While the treatment fluids of the present disclosure are
described herein as comprising the above-mentioned components, it
should be understood that the fluids of the present disclosure may
optionally comprise other chemically different materials. In
embodiments, the fluid may further comprise stabilizing agents,
surfactants, diverting agents, or other additives. Additionally,
the treatment fluid may comprise a mixture various other
crosslinking agents, and/or other additives, such as fibers or
fillers, provided that the other components chosen for the mixture
are compatible with the intended use of forming a polymeric
structure. In embodiments, the treatment fluid of the present
disclosure may further comprise one or more components such as, for
example, a gel breaker, a buffer, a proppant, a clay stabilizer, a
gel stabilizer, a chelating agent, an oxygen scavenger and a
bactericide. Furthermore, the treatment fluid or treatment fluid
may include buffers, pH control agents, and various other additives
added to promote the stability or the functionality of the fluid.
The treatment fluid or treatment fluid may be based on an aqueous
or non-aqueous solution. The components of the treatment fluid or
treatment fluid may be selected such that they may or may not react
with the subterranean formation that is to be treated.
[0124] In this regard, the treatment fluid may include components
independently selected from any solids, liquids, gases, and
combinations thereof, such as slurries, gas-saturated or
non-gas-saturated liquids, mixtures of two or more miscible or
immiscible liquids, and the like, as long as such additional
components allow for the formation of a polymeric structure. For
example, the fluid or treatment fluid may comprise organic
chemicals, inorganic chemicals, and any combinations thereof.
Organic chemicals may be monomeric, oligomeric, polymeric,
crosslinked, and combinations, while polymers may be thermoplastic,
thermosetting, moisture setting, elastomeric, and the like.
Inorganic chemicals may be metals, alkaline and alkaline earth
chemicals, minerals, and the like. Fibrous materials may also be
included in the fluid or treatment fluid. Suitable fibrous
materials may be woven or nonwoven, and may be comprised of organic
fibers, inorganic fibers, mixtures thereof and combinations
thereof.
[0125] Surfactants can be added to promote dispersion or
emulsification of components of the fluid, or to provide foaming of
the crosslinked component upon its formation downhole. Suitable
surfactants include alkyl polyethylene oxide sulfates, alkyl
alkylolamine sulfates, modified ether alcohol sulfate sodium salts,
or sodium lauryl sulfate, among others. Any surfactant which aids
the dispersion and/or stabilization of a gas component in the fluid
to form an energized fluid can be used. Viscoelastic surfactants,
such as those described in U.S. Pat. Nos. 6,703,352, 6,239,183,
6,506,710, 7,303,018 and 6,482,866, each of which are incorporated
by reference herein in their entirety, are also suitable for use in
fluids in some embodiments. Examples of suitable surfactants also
include, but are not limited to, amphoteric surfactants or
zwitterionic surfactants. Alkyl betaines, alkyl amido betaines,
alkyl imidazolines, alkyl amine oxides and alkyl quaternary
ammonium carboxylates are some examples of zwitterionic
surfactants. An example of a useful surfactant is the amphoteric
alkyl amine contained in the surfactant solution AQUAT 944.RTM.
(available from Baker Petrolite of Sugar Land, Tex.). A surfactant
may be added to the fluid in an amount in the range of about 0.01
wt. % to about 10 wt. %, such as about 0.1 wt. % to about 2 wt. %
based upon total weight of the treatment fluid.
[0126] Charge screening surfactants may be employed. In some
embodiments, the anionic surfactants such as alkyl carboxylates,
alkyl ether carboxylates, alkyl sulfates, alkyl ether sulfates,
alkyl sulfonates, .alpha.-olefin sulfonates, alkyl ether sulfates,
alkyl phosphates and alkyl ether phosphates may be used. Anionic
surfactants have a negatively charged moiety and a hydrophobic or
aliphatic tail, and can be used to charge screen cationic polymers.
Examples of suitable ionic surfactants also include, but are not
limited to, cationic surfactants such as alkyl amines, alkyl
diamines, alkyl ether amines, alkyl quaternary ammonium, dialkyl
quaternary ammonium and ester quaternary ammonium compounds.
Cationic surfactants have a positively charged moiety and a
hydrophobic or aliphatic tail, and can be used to charge screen
anionic polymers such as CMHPG. In the same manner, a charged
surfactant can also be employed to form polymer-surfactant
complexes as a method for generating consolidated structures.
[0127] The treatment fluids described herein may also include one
or more inorganic salts. Examples of these salts include
water-soluble potassium, sodium, and ammonium salts, such as
potassium chloride, ammonium chloride or tetramethyl ammonium
chloride (TMAC). Additionally, sodium chloride, calcium chloride,
potassium chloride, sodium bromide, calcium bromide, potassium
bromide, sodium sulfate, calcium sulfate, sodium phosphate, calcium
phosphate, sodium nitrate, calcium nitrate, cesium chloride, cesium
sulfate, cesium phosphate, cesium nitrate, cesium bromide,
potassium sulfate, potassium phosphate, potassium nitrate salts may
also be used. Any mixtures of the inorganic salts may be used as
well. The inorganic salt may be added to the fluid in an amount of
from about 0.01 wt. % to about 80 wt. %, from about 0.1 wt. % to
about 20 wt. %, from about 0.1 wt. % to about 10 wt. %, based upon
total weight of the treatment fluid.
[0128] In other embodiments, the surfactant is a blend of two or
more of the surfactants described above, or a blend of any of the
surfactant or surfactants described above with one or more nonionic
surfactants. Examples of suitable nonionic surfactants include, but
are not limited to, alkyl alcohol ethoxylates, alkyl phenol
ethoxylates, alkyl acid ethoxylates, alkyl amine ethoxylates,
sorbitan alkanoates and ethoxylated sorbitan alkanoates. Any
effective amount of surfactant or blend of surfactants may be used
in aqueous energized fluids.
[0129] Friction reducers may also be incorporated in any fluid
embodiment. Any suitable friction reducer polymer, such as
polyacrylamide and copolymers, partially hydrolyzed polyacrylamide,
poly(2-acrylamido-2-methyl-1-propane sulfonic acid) (polyAMPS), and
polyethylene oxide may be used. Commercial drag reducing chemicals
such as those sold by Conoco Inc. under the trademark "CDR" as
described in U.S. Pat. No. 3,692,676 or drag reducers such as those
sold by Chemlink designated under the trademarks FLO1003, FLO1004,
FLO1005 and FLO1008 have also been found to be effective. These
polymeric species added as friction reducers or viscosity index
improvers may also act as excellent fluid loss additives reducing
or even eliminating the use of conventional fluid loss additives.
Latex resins or polymer emulsions may be incorporated as fluid loss
additives. Shear recovery agents may also be used in
embodiments.
[0130] Embodiments may also include proppant particles that are
substantially insoluble in the fluids of the formation. Proppant
particles carried by the treatment fluid remain in the fracture
created, thus propping open the fracture when the fracturing
pressure is released and the well is put into production. Suitable
proppant materials include, but are not limited to, sand, walnut
shells, sintered bauxite, glass beads, ceramic materials, naturally
occurring materials, or similar materials. Mixtures of proppants
can be used as well. If sand is used, it may be from about 20 to
about 100 U.S. Standard Mesh in size. With synthetic proppants,
mesh sizes about 8 or greater may be used. Naturally occurring
materials may be underived and/or unprocessed naturally occurring
materials, as well as materials based on naturally occurring
materials that have been processed and/or derived. Suitable
examples of naturally occurring particulate materials for use as
proppants include: ground or crushed shells of nuts such as walnut,
coconut, pecan, almond, ivory nut, brazil nut, etc.; ground or
crushed seed shells (including fruit pits) of seeds of fruits such
as plum, olive, peach, cherry, apricot, etc.; ground or crushed
seed shells of other plants such as maize (e.g., corn cobs or corn
kernels), etc.; processed wood materials such as those derived from
woods such as oak, hickory, walnut, poplar, mahogany, etc.,
including such woods that have been processed by grinding,
chipping, or other form of particulation, processing, etc.
[0131] The concentration of proppant in the fluid can be any
concentration known in the art. For example, the concentration of
proppant in the fluid may be in the range of from about 0.03 to
about 3 kilograms of proppant added per liter of liquid phase.
Also, any of the proppant particles can further be coated with a
resin to potentially improve the strength, clustering ability, and
flow back properties of the proppant.
[0132] A fiber component may be included in the fluids to achieve a
variety of properties including improving particle suspension, and
particle transport capabilities, and gas phase stability. Fibers
used may be hydrophilic or hydrophobic in nature. Fibers can be any
fibrous material, such as, for example, natural organic fibers,
comminuted plant materials, synthetic polymer fibers (by
non-limiting example polyester, polyaramide, polyamide, novoloid or
a novoloid-type polymer), fibrillated synthetic organic fibers,
ceramic fibers, inorganic fibers, metal fibers, metal filaments,
carbon fibers, glass fibers, ceramic fibers, natural polymer
fibers, and any mixtures thereof. Particularly useful fibers are
polyester fibers coated to be highly hydrophilic, such as, but not
limited to, DACRON.RTM. polyethylene terephthalate (PET) fibers
available from Invista Corp. Wichita, Kans., USA, 67220. Other
examples of useful fibers include, but are not limited to,
polylactic acid polyester fibers, polyglycolic acid polyester
fibers, polyvinyl alcohol fibers, and the like. When used in
fluids, the fiber component may be included at concentrations from
about 1 to about 15 grams per liter of the liquid phase of the
fluid, such as a concentration of fibers from about 2 to about 12
grams per liter of liquid, or from about 2 to about 10 grams per
liter of liquid.
[0133] Embodiments may further use fluids containing other
additives and chemicals that are known to be commonly used in
oilfield applications by those skilled in the art. These include
materials such as surfactants in addition to those mentioned
hereinabove, breaker aids in addition to those mentioned
hereinabove, oxygen scavengers, alcohol stabilizers, scale
inhibitors, corrosion inhibitors, fluid-loss additives,
bactericides and biocides such as 2,2-dibromo-3-nitrilopropionamine
or glutaraldehyde, and the like. Also, they may include a
co-surfactant to optimize viscosity or to minimize the formation of
stable emulsions that contain components of crude oil.
[0134] As used herein, the term "alcohol stabilizer" is used in
reference to a certain group of organic molecules substantially or
completely soluble in water containing at least one hydroxyl group,
which are susceptible of providing thermal stability and long term
shelf life stability to aqueous zirconium complexes. Examples of
organic molecules referred as "alcohol stabilizers" include but are
not limited to methanol, ethanol, n-propanol, isopropanol,
n-butanol, tert-butanol, ethyleneglycol monomethyl ether and the
like.
Consolidation Event: Solvent Change Consolidation
[0135] In embodiments, a solvent change consolidation event may be
used in the method for treating a subterranean formation of the
present disclosure. Such methods may include contacting a treatment
fluid comprising a solution of one or more polymers with a solvent
that triggers the consolidation of at least one of the one or more
of the polymers while shearing the polymer solution, thereby
forming polymeric structures in the fluid anywhere between the
surface mixing equipment and the downhole formation. In
embodiments, the treatment fluid carrying the polymer solution may
be a drilling fluid, a fracturing fluid, cement slurry, or a
completion fluid. The consolidating solvent may be a pure solvent
or a mixture, including one of more of the aqueous and/or organic
solvents mentioned above. The polymer solution comprised in the
treatment fluid may be composed of a single polymer, or the polymer
solution may include a mixture of two or more polymers, where at
least one of them is insoluble in the subsequently added solvent or
mixture of solvents.
[0136] In some embodiments, the methods of the present disclosure
may include a first treatment fluid comprising one or more polymers
that are dissolved in a first solvent. Optionally, this first
treatment fluid may be exposed to an ongoing shear event before the
consolidation event is initiated. In embodiments, the consolidation
event may be initiated by adding (and/or mixing) a second treatment
fluid comprising a second solvent (second treatment fluid or
consolidating agent) that renders at least one of the one or more
polymers of the first treatment fluid insoluble. In embodiments,
the event that triggers the consolidation of the one or more
polymers may include placing such a second solvent (second
treatment fluid or consolidating agent), which may be added at the
surface, mixed at the surface, added downhole and/or mixed downhole
with the first treatment fluid.
[0137] In some embodiments, the methods of the present disclosure
may include a first treatment fluid that does not comprise one or
more polymers. Instead, the composition of the first treatment
fluid is selected such that when it is mixed with a second
treatment fluid (containing a dissolved one or more polymers), the
dissolved at least one polymer of the one or more polymers in the
second treatment fluid consolidates. Optionally, the first
treatment fluid may be exposed to an ongoing shear event before the
consolidation event is initiated. The second treatment fluid may be
introduced into the first treatment fluid by adding (and/or mixing)
either at the surface or downhole.
[0138] In some embodiments, the first and/or second treatment
fluids may have any suitable viscosity, such as a viscosity of from
about 1 cP to about 1,000 cP (or from about 10 cP to about 100 cP)
at the treating temperature, which may range from a surface
temperature to a bottom-hole static (reservoir) temperature, such
as from about -40.degree. C. to about 150.degree. C., or from about
10.degree. C. to about 120.degree. C., or from about 25.degree. C.
to about 100.degree. C., and any effective shear rate may be used
during the application of a shear event; in some embodiments, the
shear rate that is observed during the application of a shear event
to the above-mentioned fluid(s) may be in a range of from about 1
s.sup.-1 to about 100,000 s.sup.-1, such as a shear rate in a range
of from about 100 s.sup.-1 to about 10,000 s.sup.-1, or a shear
rate in a range of from about 500 s.sup.-1 to about 5,000 s.sup.-1
as measured by common methods. The magnitude of the effective shear
rate that may be used to form polymeric structures will depend on
the composition of the treatment fluid.
[0139] In some embodiments, the total amount of the polymer in
solution in the treatment fluid may be in the range of from about
0.1 to about 10% by weight of the treatment fluid, such as in the
range of from about 0.2 to about 5% by weight of the treatment
fluid, or in the range of from about 0.5 to about 1.5% by weight of
polymer solution.
[0140] Polymers suitable for solvent change consolidation may be
synthetic or naturally-occurring. Some examples of polymer classes
include polysaccharides and their derivatives, polyamides,
polyethers, polyesters and polyolefins. Examples of consolidating
solvents for such polymers include water, various alcohols such as
methanol, ethanol, and isopropanol, and other organic
water-miscible solvents mentioned above.
[0141] For example, isopropanol-water is a suitable solvent pair to
consolidate guar from a water solution. A ratio of about 1:5
isopropanol:water is suitable to start the consolidation of guar.
Diethylene glycol dimethyl ether (diglyme)-water is a suitable
solvent pair to consolidate polylactic acid from a PLA solution in
pure diglyme. A ratio of about 1:10 diglyme:water is suitable to
start the consolidation of polylactic acid.
Consolidation Event: pH Change Consolidation
[0142] In some embodiments, the treatment fluid may comprise one or
more polymers, where at least one of the one or more polymers is a
pH-sensitive polymer that is dissolved in the treatment fluid
comprising a first solvent capable of dissolving the pH-sensitive
polymer. In such embodiments, the triggering of the consolidation
event may be initiated by either placing a pH triggering agent
(such as an additive that adjusts the pH of the treatment fluid
and/or second solvent having a different pH) that triggers the
consolidation of one or more of the polymers through a change in
the pH of the treatment fluid. In some embodiments, the pH change
that triggers the consolidation of one or more of the polymers is
reversible such that returning the pH of the treatment fluid to its
initial value will re-dissolve the one or more polymers.
[0143] Shearing the treatment fluid at an effective shear rate
while adjusting the pH to a predetermined pH that results in the
consolidation of the one or more polymers forms the polymeric
structure of the one or more polymers. In some embodiments, the
treatment fluid may have any suitable viscosity, such as a
viscosity of from about 1 cP to about 1,000 cP (or from about 10 cP
to about 100 cP) at the treating temperature, which may range from
a surface temperature to a bottom-hole static (reservoir)
temperature, such as from about -40.degree. C. to about 150.degree.
C., or from about 10.degree. C. to about 120.degree. C., or from
about 25.degree. C. to about 100.degree. C., and any effective
shear rate may be used during the application of a shear event; in
some embodiments, the shear rate that is observed during the
application of a shear event to the above-mentioned fluid may be in
a range of from about 1 s.sup.-1 to about 100,000 s.sup.-1, such as
a shear rate in a range of from about 100 s.sup.-1 to about 10,000
s.sup.-1, or a shear rate in a range of from about 500 s.sup.-1 to
about 5,000 s.sup.-1 as measured by common methods. The magnitude
of the effective shear rate that may be used to form polymeric
structures will depend on the composition of the treatment fluid.
For example, in embodiments where consolidation is induced by a pH
change, adding a polymer, such as chitosan, to a consolidating bath
under a very low shear rate, such as less than about 10 s.sup.-1
does not afford a polymeric structure; rather a large agglomerate
of polymer consolidated, which does not constitute a polymeric
structure of the present disclosure.
[0144] Polymeric structures (also referred to herein as a
"fiber-like consolidate", unless otherwise specified) may be formed
in the treatment fluid anywhere including the surface mixing
equipment and the downhole formation to be treated. In some
embodiments, the shear rate applied to the treatment fluid
comprising the pH-sensitive polymer solution may be adjusted as
desired to form a predetermined size of polymeric structures in the
treatment fluid.
[0145] Suitable pH-sensitive polymers include those that exhibit pH
dependent solubility. Examples are alginate, chitosan, cellulose
acetate phthalate, cellulose acetate trimellitate,
hydroxypropylmethylcellulose phthalate, polyacrylic acid,
poly(methyl methacrylate) copolymers, polyamines, and shellac.
Examples of polymer classes that can be mixed with a pH-sensitive
polymer include neutral polysaccharides, polyethers, polyacetals,
polyamides and polyesters.
[0146] Suitable pH control agents, if employed in the treatment
fluid, may include sodium, potassium and ammonium sesquicarbonates,
oxalates, carbonates, hydroxides, bicarbonates, acids and organic
carboxylates such as acetates and polyacetates. Examples are sodium
sesquicarbonate, sodium carbonate, and sodium hydroxide. Soluble
oxides, including slowly soluble oxides such as MgO, may also be
used. Amines and oligomeric amines, such as alkyl amines,
hydroxyalkyl amines, anilines, pyridines, pyrimidines, quinolines,
and pyrrolidines for example triethanolamine and
tetraethylenepentamine, may also be used.
Consolidation Event: Crosslink Induced Consolidation
[0147] In some embodiments, the treatment fluid may comprise one or
more polymers, such as cross-linkable polymers, dissolved in a
solvent. In such embodiments, the triggering of the consolidation
event may be initiated by either placing a component and/or second
solution that triggers the consolidation of one or more of the
polymers by way of a reaction, such as a crosslinking reaction,
with the one or more polymers. In some embodiments, crosslinking
the one of more polymers renders the formed crosslinked polymer
insoluble and thus results in the consolidation of the cross-linked
one or more polymers (the crosslinked polymer).
[0148] Examples of suitable cross-linkable polymers include any
suitable polymer that is capable of consolidating upon being
crosslinked. Such cross-linkable polymers may include synthetic
and/or naturally occurring polymers or polyelectrolytes capable of
dispersing in an aqueous or organic solvent solution (such as those
mentioned above and throughout the present specification) that can
undergo a crosslinking reaction with the introduction of a
crosslinking agent. Suitable polymers may also include
polysaccharides such as substituted galactomannans, such as guar
gums, high-molecular weight polysaccharides composed of mannose and
galactose sugars, or guar derivatives such as hydroxypropyl guar
(HPG), carboxymethylhydroxypropyl guar (CMHPG) and carboxymethyl
guar (CMG), hydrophobically modified guars, guar-containing
compounds, and synthetic polymers. Further details regarding
potential suitable polyelectrolyte complexes and surfactant-polymer
complexes may be found in the following reference, Linear
Viscoelasticity of Polyelectrolyte Complex Coacervates, Evan
Spruijt, Martien A. Cohen Stuart, and Jasper van der Gucht,
Macromolecules 2013, 46 (4), 1633-1641, the disclosure of which is
hereby incorporated by reference in its entirety.
[0149] Other suitable classes of water-soluble polymers that may be
suitable for the methods of the present disclosure include
polyvinyl polymers, polymethacrylamides, cellulose ethers,
lignosulfonates, and their ammonium, alkali metal, and alkaline
earth salts thereof. Further examples of other suitable water
soluble polymers include acrylic acid-acrylamide copolymers,
acrylic acid-methacrylamide copolymers, polyacrylamides, partially
hydrolyzed polyacrylamides, partially hydrolyzed
polymethacrylamides, polyvinyl alcohol, polyalkyleneoxides, other
galactomannans, heteropolysaccharides obtained by the fermentation
of starch-derived sugar and their ammonium and alkali metal salts
thereof. Suitable examples of biopolymers include gellan,
K-carrageenan, sodium alginate, gelatin, agar, agarose,
maltodextrin, chitosan, and combinations thereof. Additional
examples of biopolymers are described in U.S. Pat. Nos. 5,726,138
and 7,169,427, and U.S. Patent Application Pub. No. 2005/0042192,
the disclosure of each of which is incorporated by reference herein
in its entirety.
[0150] Cellulose derivatives such as hydroxyethylcellulose (HEC) or
hydroxypropylcellulose (HPC), carboxymethylhydroxyethylcellulose
(CMHEC) and carboxymethylcellulose (CMC), with or without
crosslinkers, may also be used as water-soluble polymers.
[0151] In embodiments, the treatment fluid may comprise one or more
polymer chemical entities and a cross-linking agent. The phrase
"cross-linking agent" refers, for example, to a compound or mixture
that assists in the formation of a three-dimensional polymerized
structure of the one or more polymers (which may be insoluble)
under at least some downhole conditions, such as after exposure to
a consolidation event, such as, for example, a change in pH. Any
crosslinker may be used, for example, organic crosslinkers,
inorganic crosslinkers, divalent metals, trivalent metals, and
polyvalent metals, such as calcium, iron, chromium, copper, boron,
titanium, zirconium, aluminum and the like. Suitable boron
crosslinked polymers systems include guar and substituted guars
crosslinked with boric acid, sodium tetraborate, and encapsulated
borates; borate crosslinkers may be used with buffers and pH
control agents such as sodium hydroxide, magnesium oxide, sodium
sesquicarbonate, and sodium carbonate, amines (such as hydroxyalkyl
amines, anilines, pyridines, pyrimidines, quinolines, and
pyrrolidines, and carboxylates such as acetates and oxalates) and
with delay agents such as sorbitol, aldehydes, and sodium
gluconate. Suitable zirconium crosslinked polymer systems include
those crosslinked by zirconium lactates (for example sodium
zirconium lactate), triethanolamines, 2,2'-iminodiethanol, and with
mixtures of these ligands, including when adjusted with
bicarbonate. Suitable titanates include lactates and
triethanolamines, and mixtures, for example delayed with
hydroxyacetic acid.
[0152] The concentration of the crosslinker in the treatment fluid
may be from about 0.001 wt. % to about 10 wt. %, such as about
0.005 wt. % to about 2 wt. %, or about 0.01 wt. % to about 1 wt.
%.
[0153] In some embodiments, a pH change may trigger crosslinking
and the consolidation of one or more of the polymer chemical
entities. Adjusting the pH to a predetermined pH that results in
the crosslinking and consolidation of the one or more polymers
while shearing the treatment fluid (with an effective shear rate)
forms the polymeric structures in situ. In some embodiments, the
treatment fluid in which the crosslinking event is triggered may
have any suitable viscosity, such as a viscosity of from about 1 cP
to about 1,000 cP (or from about 10 cP to about 100 cP) at the
treating temperature, which may range from a surface temperature to
a bottom-hole static (reservoir) temperature, such as from about
-40.degree. C. to about 150.degree. C., or from about 10.degree. C.
to about 120.degree. C., or from about 25.degree. C. to about
100.degree. C., and any effective shear rate may be used during the
application of a shear event; in some embodiments, the shear rate
that is observed during the application of a shear event to the
above-mentioned fluid(s) may be in a range of from about 1 s.sup.-1
to about 100,000 s.sup.-1, such as a shear rate in a range of from
about 100 s.sup.-1 to about 10,000 s.sup.-1, or a shear rate in a
range of from about 500 s.sup.-1 to about 5,000 s.sup.-1 as
measured by common methods. The magnitude of the effective shear
rate that may be used to form polymeric structures will depend on
the composition of the treatment fluid.
[0154] Such polymeric structures may form in the fluid anywhere
within, or inside of the surface mixing equipment, such as a POD
blender, or between the surface mixing equipment and the downhole
formation to be treated. In some embodiments, the shear rate
applied to this polymer solution may be adjusted as desired to form
a predetermined size of polymeric structures in the treatment
fluid.
Consolidation Event: Polyelectrolyte Complexes and Surfactant
Polymer Complexes
[0155] In some embodiments, the treatment fluid may comprise one or
more polymers, such as polyelectrolyte polymers, dissolved in a
solvent. The interaction of two oppositely charged polyelectrolyte
polymers can trigger the consolidation of one or more of the
polymers by way of the formation of a polyelectrolyte complex
(PEC). In some embodiments, the formation of the polyelectrolyte
complex comprising the one or more polymers may render the formed
polymeric structure insoluble. Examples of the polyelectrolyte
polymers may include the one or more polymers described herein.
Specific examples of these polymers are described in U.S. Patent
Application Pub. Nos. 2013/0056213 and 2013/0048283, the
disclosures of which are incorporated by reference herein in their
entirety.
[0156] The consolidation event may be initiated or triggered by
either placing a component and/or second solution containing an
oppositely charged polyelectrolyte polymer, such as a surfactant,
that triggers the consolidation of one or more of the polymers by
way of a reaction, such as an ionic bonding or ionic charge
association. In some embodiments, the formation of the
polyelectrolyte complex comprising the one or more polymers and the
surfactant renders the formed polymer complex insoluble and thus
results in the consolidation of the polyelectrolyte complex. The
surfactant can exist as either an individual molecular entity or as
part of an incorporated micelle structure.
[0157] The polyelectrolyte polymers may be dissolved in a solvent
containing one or more water soluble salts (in addition to the
salts described above, examples include potassium chloride, sodium
chloride, ammonium chloride, sodium sulfate, and the like) along
with an oppositely charged polyelectrolyte polymer or surfactant.
In such embodiments, the consolidation of the one or more polymers
may be inhibited by the presence of the dissolved salt at certain
elevated concentrations, such as, for example, from about 2 wt. %
to about 6 wt. %, from about 2 wt. % to about 5 wt. %, about 3 wt.
% to about 5 wt. % and about 4 wt. % to about 4.5 wt. %. In these
embodiments, the consolidation may be initiated by contacting the
treatment fluid with a low salinity solution (such as fresh water
or water having a salt concentration less than 2 wt. %, such as for
example, from about 0.5 wt. % to about 1.5 wt. %) that allows for
the diffusion of salt ions out of the treatment fluid and thus
reducing the salt concentration of the treatment fluid to a point
where the charge association between the dissolved
polyelectrolyte(s) and/or surfactants is no longer inhibited. This
allows for the formation of the polyelectrolyte complex and
subsequent consolidation event to occur.
Consolidation Event: Solvent Salinity Change Consolidation
[0158] In embodiments, a solvent salinity change consolidation
event may be used in the method for treating a subterranean
formation of the present disclosure. Such methods may include
contacting a treatment fluid comprising a solution of one or more
polymers with an additional treatment fluid that results in a
change in the salinity or ionic concentration (of the treatment
fluid comprising the one or more polymers) that triggers the
consolidation of one or more of the polymers of the treatment fluid
while shearing the polymer solution, thereby forming polymeric
structures. These actions may occur at any time during the methods
of the present disclosure for treating subterranean formation. For
example, these actions may occur anywhere at the well site, such
as, for example, while the treatment fluid is at the surface, such
as in the surface mixing equipment, or while the treatment fluid is
in the downhole formation.
[0159] In some embodiments, the treatment fluid in which the
above-mentioned action occurs may have any suitable viscosity, such
as a viscosity of from about 1 cP to about 1,000 cP (or from about
10 cP to about 100 cP) at the treating temperature, which may range
from a surface temperature to a bottom-hole static (reservoir)
temperature, such as from about -40.degree. C. to about 150.degree.
C., or from about 10.degree. C. to about 120.degree. C., or from
about 25.degree. C. to about 100.degree. C., and any effective
shear rate may be used during the application of a shear event; in
some embodiments, the shear rate that is observed during the
application of a shear event to the above-mentioned fluid(s) may be
in a range of from about 1 s.sup.-1 to about 100000 s.sup.-1, such
as a shear rate in a range of from about 100 s.sup.-1 to about
10000 s.sup.-1, or a shear rate in a range of from about 500
s.sup.-1 to about 5000 s.sup.-1 as measured by common methods. The
magnitude of the effective shear rate will depend on the
composition of the treatment fluid.
[0160] There are two opposite scenarios where a change in salinity
can prompt a consolidation event. The first is the use of one or
more polymers are soluble in low saline solvents that consolidate
with an increase in salinity. In the other, one or more polymers
soluble in high salinity water/solvent can be made insoluble by
mixing with fresh water/solvent.
[0161] The treatment fluid comprising the polymer solution may be a
drilling fluid, a fracturing fluid, cement slurry, completion
fluid, salt brine, and produced or fresh water. The consolidating
medium (or second treatment fluid) may be a pure solvent or a
mixture, and may have higher or lower ionic concentration than the
polymer solution of the treatment fluid. The polymer solution may
be composed of a single polymer, or the polymer solution may
include a mixture of two or more polymers, where at least one of
them is insoluble in the consolidating medium (or second treatment
fluid) with different ionic concentration.
[0162] In some embodiments, the total amount of the polymer in
solution in the treatment fluid may be in the range of from about
0.1 to about 10% by weight of the treatment fluid, such as in the
range of from about 0.2 to about 5% by weight of the treatment
fluid, or in the range of from about 0.5 to about 1.5% by weight of
the treatment fluid. Polymers suitable for ionic change
consolidation (solvent salinity change consolidation) may be
synthetic or naturally-occurring.
[0163] Polyvinyl alcohol (PVA) is an example of a polymer which can
be dissolved initially in fresh water (or low salinity), but will
consolidate out of solution when mixed with a high salinity fluid.
The opposite is true using poly(2-hydroxyethylmethacrylate)
(polyHEMA), which is soluble in water with high salt levels, such
as zinc bromide/calcium bromide brines, but otherwise insoluble in
water with low salt levels. If either case is triggered to
consolidate while being exposed to a shear event in which an
effecting shear rate is being applied to the treatment fluid, a
polymeric structured may be produced for further utilization within
the treatment process or well lifecycle.
Consolidation Event: Temperature Change Consolidation
[0164] In embodiments, a temperature change consolidation event may
be used in the method for treating a subterranean formation of the
present disclosure. Such methods may include increasing the
temperature of a treatment fluid containing one or more polymers in
solution to trigger the consolidation of one or more of the
polymers while shearing the treatment fluid, thereby forming
polymeric structures in the treatment fluid anywhere between the
surface mixing equipment and the downhole formation.
[0165] In some embodiments, the treatment fluid in which a
temperature change is used to trigger the consolidation may have
any suitable viscosity, such as a viscosity of from about 1 cP to
about 1,000 cP (or from about 10 cP to about 100 cP) at the
treating temperature, which may range from a surface temperature to
a bottom-hole static (reservoir) temperature, such as from about
-40.degree. C. to about 150.degree. C., or from about 10.degree. C.
to about 120.degree. C., or from about 25.degree. C. to about
100.degree. C., and any effective shear rate may be used during the
application of a shear event; in some embodiments, the shear rate
that is observed during the application of a shear event to the
above-mentioned fluid(s) may be in a range of from about 1 s.sup.-1
to about 100000 s.sup.-1, such as a shear rate in a range of from
about 100 s.sup.-1 to about 10000 s.sup.-1, or a shear rate in a
range of from about 500 s.sup.-1 to about 5000 s.sup.-1 as measured
by common methods. The magnitude of the effective shear rate that
may be used to form polymeric structures will depend on the
composition of the treatment fluid.
[0166] The treatment fluid comprising the polymer solution may be a
drilling fluid, a fracturing fluid, cement slurry, or a completion
fluid. The temperature may be increased by any suitable means, such
as by heating the treatment fluid comprising polymer solution,
and/or by mixing the treatment fluid comprising the polymer
solution with another treatment fluid, which is at a higher
temperature. The polymer solution of the treatment fluid may be
composed of a single polymer, or a mixture of two or more polymers,
where at least one of the one or more polymers of the one or more
polymers is lower critical solution temperature (LCST) polymer, so
it becomes insoluble after increasing the temperature above a
determined value.
[0167] As used herein, the term "LCST polymer" refers to a polymer
that exhibits a lower critical solution temperature. LCST polymers
are soluble at temperatures below the LCST, but form a cloudy
mixture at the LCST (also referred as the cloud point). A further
temperature increase leads to complete consolidation of the
polymer. In some embodiments, the consolidation may be caused by an
increase in the hydrophobicity of the polymer as the temperature
increases above the LCST.
[0168] In some embodiments, the total amount of the polymer in
solution in the treatment fluid may be in the range of from about
0.1 to about 20% by weight of the treatment fluid, such as in the
range of from about 0.2 to about 10% by weight of the treatment
fluid, or in the range of from about 0.5 to about 5% by weight of
polymer solution. Some examples of LCST polymers include
poly(N-isopropylacrylamide), poly(methyl vinyl ether),
hydroxypropyl cellulose, poly(ethylene glycol), poly(vinyl
caprolactam), and their copolymers.
Proppant Transport
[0169] As discussed above, in some embodiments, the methods and
treatment fluids of the present disclosure may comprise one or more
polymers and a slurry of proppant. Proppant particles carried by
the treatment fluid remain in the fracture created, thus propping
open the fracture when the fracturing pressure is released and the
well is put into production.
[0170] Polymeric structures may be formed in situ, optionally in
the presence of the proppant, when the one or more polymers is
exposed to a consolidation event, such as one or more of those
mentioned above, to generate polymeric structures via a combination
of chemical or physical reactions in the presence of a shear event,
such as a flow-induced shear, for example, in either the surface
mixing, the transport line, and/or in the wellbore. In some
embodiments, the treatment fluid comprising the proppant may have
any suitable viscosity, such as a viscosity of from about 1 cP to
about 1,000 cP (or from about 10 cP to about 100 cP) at the
treating temperature, which may range from a surface temperature to
a bottom-hole static (reservoir) temperature, such as from about
-40.degree. C. to about 150.degree. C., or from about 10.degree. C.
to about 120.degree. C., or from about 25.degree. C. to about
100.degree. C., and any effective shear rate may be used during the
application of a shear event; in some embodiments, the shear rate
that is observed during the application of a shear event to the
above-mentioned fluid may be in a range of from about 1 s.sup.-1 to
about 100000 s.sup.-1, such as a shear rate in a range of from
about 100 s.sup.-1 to about 10000 s.sup.-1, or a shear rate in a
range of from about 500 s.sup.-1 to about 5000 s.sup.-1 as measured
by common methods. The magnitude of the effective shear rate that
may be used to form polymeric structures will depend on the
composition of the treatment fluid.
[0171] In some embodiments, the polymeric structures that are
generated, optionally in the presence of the proppant, may be a
solid material, gel material, or a combination thereof.
[0172] The polymeric structures (also referred to herein as a
"fiber-like precipitate", unless otherwise specified) formed by the
methods of the present disclosure may be used in a variety of well
treatment applications, such as hydraulic fracturing to place
proppant in the fracture. Likewise, the polymeric structures formed
by the methods of the present disclosure may be used in a
non-damaging treatment fluid, such as a drilling fluid, cement
slurry, or a completion fluid. In embodiments, the consolidation
event (of the one or more polymers) that occurs in such fluids may
be based on adjusting the solubility of the one or more polymers by
way of altering the saline concentration, ionic strength and/or
surfactant concentration of the treatment fluid.
[0173] In some embodiments, adjusting (increasing) the salinity of
a low salinity treatment fluid, such as a treatment fluid
comprising fresh water or about 0.5% or less (by weight) of a salt
(such as KCl, K.sub.2SO.sub.4, or NaSO.sub.4) and dissolved
polymer, such as polyvinyl alcohol (PVOH), at a predetermined
temperature (and location) in the wellbore provides a polymer
structure that may be elongated by applying a predetermined shear
rate. In some embodiments, after the elongated polymer consolidates
have performed their solid-form function, the elongated polymer
consolidates generated by the methods of the present disclosure may
be readily removed from the subterranean formation, such as a
proppant pack in a subterranean formation, because they can be
re-dissolved (at normal formation temperatures) when the treatment
fluid is re-adjusted to be a low salinity aqueous fluid again.
Thus, the treatment fluids and methods of the present disclosure
may be used, for example, in gravel packing applications to create
tighter, cleaner packs versus traditional gravel packs.
[0174] In some embodiments, adjusting (decreasing) the salinity of
a low salinity treatment fluid at a predetermined temperature in
the wellbore provides a polymeric structure that may be elongated
by applying a predetermined shear rate. The description hereafter
refers to one or more polymers, such as
poly(2-hydroxyethylmethacrylate) (polyHEMA), as one example of a
polymer and its incorporation into a non-damaging treatment fluid,
such as a drilling fluid, a fracturing fluid, cement slurry, or a
completion fluid, and how adjusting the solubility of this one or
more polymers may occur by way of saline concentration, ionic
strength and/or surfactants. Those skilled in the art will
appreciate that other polymers (besides polyHEMA) may be used in
the treatment fluids and methods of the present disclosure and are
equally applicable to dissolvable polymers that meet the
above-stated condition of having similarly alterable solubility
modes in the context of well treatment fluids and methodology.
[0175] The treatment fluids and methods of the present disclosure
may use polyHEMA in a soluble form while pumping the treatment
fluid downhole and then generate solid fiber-like materials by
adjusting the treatment fluid conditions to form a polyHEMA
polymeric structure while applying a predetermined shear rate
(after the soluble polyHEMA has been transported downhole). By
changing the salinity and/or temperature conditions of the
treatment fluid, the polyHEMA consolidates, the polyHEMA that
consolidates may be acted on by a shear event to elongate the
polyHEMA consolidate and form elongated polyHEMA polymeric
structures in the treatment fluid. The generated elongated polyHEMA
polymeric structures may then be used in, for example, fiber
assisted transport.
[0176] In other embodiments, adjusting (decreasing) the salinity of
a high salinity treatment fluid, such as a treatment fluid
comprising a large amount (by weight; such as a saturated salt
solution or a solution that contains an amount of salt that is at
least about 80%, such as at least about 90% of a weight of a salt
that would be used to make a saturated salt solution) of a salt
(such as KCl, K.sub.2SO.sub.4, or NaSO.sub.4) and dissolved
polyHEMA, at a predetermined temperature (and location) in the
wellbore provides a polyHEMA polymeric structure that may be
elongated by applying a predetermined shear rate. In some
embodiments, after the elongated polyHEMA polymeric structures have
performed their solid-form function, the polymeric structured
polyHEMA fibers generated by the methods of the present disclosure
may be readily removed from the subterranean formation, such as a
proppant pack in a subterranean formation, because they can be
re-dissolved (at normal formation temperatures) when the treatment
fluid is re-adjusted to be a low salinity or aqueous fluid again.
Thus, the treatment fluids and methods of the present disclosure
may be used, for example, in gravel packing applications to create
tighter, cleaner packs versus traditional gravel packs.
[0177] In embodiments, the polyHEMA may have a weight average
molecular weight greater than about 5000 Daltons up to about
500,000 Daltons or more, or from about 10,000 Daltons to about
200,000 Daltons.
[0178] The solubility of the polyHEMA in the treatment fluid may be
influenced by the molecular weight, particle size, and the
like.
[0179] A system comprising a treatment fluid and polyHEMA (and any
other additives) may be batch-mixed or mixed on-the-fly using
otherwise conventional treatment fluid mixing equipment and mixing
techniques.
[0180] If the polymeric structures (also referred to herein as a
"fiber-like precipitate", unless otherwise specified) formed by the
methods of the present disclosure are to be used as a fluid loss
additive, the size of the elongated polyHEMA polymeric structures
may be selected based on the desired fluid loss properties (for
example, spurt and wall building coefficient).
[0181] By using a treatment fluid to provide a low salt
environment, the elongated polyHEMA polymeric structure may be used
to control fluid loss, such as by forming a filter cake. Salt
concentration in the treatment fluid containing the dissolved
polyHEMA may be about 8 percent by weight or greater, or about 10
percent by weight or greater, or at least about 12 percent by
weight or greater. The choice of salt may include any salt that
inhibits the polyHEMA from consolidating and is otherwise suitable
for use in a well treatment fluid. After the consolidation event
occurs (such a salt concentration may be less than about 5 weight
percent, or about 2 percent by weight or less, or the treatment
fluid may be replaced with fresh water), the elongated polyHEMA
polymeric structure may be present in the treatment fluid at a
concentration or loading of from about 0.6 to about 24 g/L (from
about 5 to about 200 ppt), from about 1.2 to about 18 g/L (from
about 10 to about 150 ppt), or from about 2.4 to about 9.6 g/L
(from about 20 to about 80 ppt).
[0182] In embodiments, the contacting a filter cake comprising the
polymeric structure in a production zone with a solution may
restore permeability of the downhole surface in the subterranean
formation. For example, after the solid-state function of the
elongated polyHEMA polymeric structure has been performed, the salt
concentration of the treatment fluid may be increased (for example,
to a salt concentration at which the elongated polyHEMA polymeric
structure is soluble) to dissolve the elongated polyHEMA polymeric
structure and restore permeability of the downhole surface in the
subterranean formation and/or clean up the surface of the formation
or the filter cake. In embodiments, such a salt concentration may
be any desired salt concentration that makes the polymeric
structure soluble again, such as a salt concentration of about 8
percent by weight or greater, or about 10 percent by weight or
greater, or at least about 12 percent by weight or greater.
[0183] In the methods of the present disclosure, the polymeric
structure, such as an elongated polyHEMA polymeric structure, may
be used as a fluid loss control agent in an otherwise conventional
drilling fluid or fluid loss control pill, for example. As noted
above, the solubility of the polymeric structure, such as an
elongated polyHEMA polymeric structure, in aqueous solution may be
a function of a number of variables. Controlling these parameters
enables the use of the polymeric structure of the present
disclosure, such as an elongated polyHEMA polymeric structure, as a
fluid loss control agent and/or as a temporary formation seal.
[0184] The polymeric structure of the present disclosure, such as
an elongated polyHEMA polymeric structure, may be used as a delayed
viscosity breaker in crosslinked polymer and viscoelastic fluid
systems ("VES"). Upon dissolution, the polymeric structure of the
present disclosure, such as an elongated polyHEMA polymeric
structure, can function as a viscosity breaker. The break can thus
be timed to occur by delaying dissolution of the polymeric
structure of the present disclosure, such as an elongated polyHEMA
polymeric structure.
[0185] In hydraulic fracturing, frac-packing, and gravel packing
embodiments, a VES or crosslinked polymer may be added in the pad,
throughout the treatment or to preselected proppant or gravel
stages. The polymeric structure of the present disclosure, such as
an elongated polyHEMA polymeric structure, may be a polymeric
structure in any of these uses and will retard flowback and
settling of proppant or gravel, and/or of fines if they are
present, until the polymeric structure of the present disclosure,
such as an elongated polyHEMA polymeric structure, dissolves. A
self-destructing fluid loss additive and filter cake is
particularly useful in hydraulic fracturing, frac-packing, and
gravel packing because mechanical removal methods are impossible
and methods involving contacting the fluid loss additive and filter
cake with an additional fluid to react with the filter cake and/or
fluid loss additive are not practical.
[0186] The treatment fluids in which polymeric structure of the
present disclosure, such as an elongated polyHEMA polymeric
structure, are formed and the methods of the present disclosure in
which polymeric structure of the present disclosure, such as an
elongated polyHEMA polymeric structure, are formed may be used in
any of these cases (gravel packing, fracturing followed by gravel
packing, and fracturing for short wide fractures).
[0187] The concentration of the polymeric structure of the present
disclosure, such as an elongated polyHEMA polymeric structure, may
range from about 0.6 g/L (about 5 ppt) to about 9.6 g/L (about 80
ppt), or from about 2.4 g/L (about 20 ppt) to about 7.2 g/L (about
60 ppt).
[0188] In gravel packing, or combined fracturing and gravel
packing, the treatments may be done with or without a screen.
Although the aforementioned methods of the present disclosure are
described in terms of unfoamed fluids, fluids foamed or energized
(for example with nitrogen or carbon dioxide or mixtures of those
gases) may be used. Adjustment of the appropriate concentrations
due to any changes in the fluid properties or proppant
concentration consequent to foaming may be made.
[0189] Any proppant (gravel) may be used, provided that it is
compatible with the polymeric structure of the present disclosure,
such as an elongated polyHEMA polymeric structure, the formation,
the fluid, and the desired results of the treatment. Such proppants
(gravels) may be natural or synthetic (including but not limited to
glass beads, ceramic beads, sand, and bauxite), coated, or contain
chemicals; more than one may be used sequentially or in mixtures of
different sizes or different materials. The proppant may be resin
coated, provided that the resin and any other chemicals in the
coating are compatible with the other chemicals of the present
disclosure, particularly the components of the viscoelastic
surfactant fluid system. Proppants and gravels in the same or
different wells or treatments may be the same material and/or the
same size as one another and the term "proppant" is intended to
include gravel in this discussion. In general the proppant used
will have an average particle size of from about 0.15 mm to about
2.39 mm (about 8 to about 100 U.S. mesh), or of from about 0.25 to
about 0.43 mm (40/60 mesh), or of from about 0.43 to about 0.84 mm
(20/40 mesh), or of from about 0.84 to about 1.19 mm (16/20), or of
from about 0.84 to about 1.68 mm (12/20 mesh) and or of from about
0.84 to about 2.39 mm (8/20 mesh) sized materials. Normally the
proppant will be present in the slurry in a concentration of from
about 0.12 to about 3 kg/L, or about 0.12 to about 1.44 kg/L (about
1 PPA to about 25 PPA, or from about 1 to about 12 PPA; PPA is
"pounds proppant added" per gallon of liquid).
[0190] Optionally, the fracturing fluid may contain materials
designed to limit proppant flowback after the fracturing operation
is complete by forming a porous pack in the fracture zone. Such
materials are described in U.S. Pat. No. 5,501,275, the disclosure
of which is hereby incorporated by reference in its entirety.
Suitable proppant flowback inhibitors include fibers or platelets
of novoloid or novolbid-type polymers, as described in U.S. Pat.
No. 5,782,300, the disclosure of which is herein incorporated by
reference in its entirety.
[0191] Suitable polymeric structures of the present disclosure,
such as an elongated polyHEMA polymeric structure, may assist in
transporting, suspending and placing proppant in hydraulic
fracturing and gravel packing, for example, and may then be
dissolved to minimize or eliminate the presence of fibers in the
proppant pack without releasing degradation products that hinder
fluid flow, or prematurely decreasing the ability of otherwise
suitable metal-crosslinked polymers or VES systems to viscosify the
carrier fluid. As used herein, a system in which suitable polymeric
structures of the present disclosure, such as an elongated polyHEMA
polymeric structure, are used to slurry and transport proppant is
referred to as "fiber-assisted transport." Where the system also
includes a fluid viscosified with a suitable metal-crosslinked
polymer or VES system, it will be referred to as a "fiber/polymer
or viscoelastic surfactant viscosifier" system or an "FPV" system.
Such systems have been described in U.S. Pat. No. 7,275,596, which
is hereby incorporated by reference in its entirety.
[0192] The FPV system is described herein primarily in terms of
hydraulic fracturing, but it is also suitable for gravel packing,
or for fracturing and gravel packing in one operation (called, for
example frac and pack, frac-n-pack, frac-pack, Stimpac treatments,
or other names), which are also used extensively to stimulate the
production of hydrocarbons, water and other fluids from
subterranean formations. These operations involve pumping a slurry
of proppant (natural or synthetic materials that prop open a
fracture after it is created) in hydraulic fracturing, or gravel in
gravel packing. In low permeability formations, the goal of
hydraulic fracturing is generally to form long, high surface area
fractures that greatly increase the magnitude of the pathway of
fluid flow from the formation to the wellbore. In high permeability
formations, the goal of a hydraulic fracturing treatment may be to
create a short, wide, highly conductive fracture, in order to
bypass near-wellbore damage done in drilling and/or completion, to
ensure good fluid communication between the rock and the wellbore
and also to increase the surface area available for fluids to flow
into the wellbore.
[0193] The FPV system is particularly suitable for fracturing tight
gas wells, which may be low-permeability environments with extended
fracture closure times; in such cases the fracture may remain open
for hours after injection ceases, and the carrier fluid may break
and no longer suspend the proppant. The FPV system allows lower
polymer or VES loadings, reduced fracture height growth (because of
the lower viscosity that can be used), reduced proppant settling,
and increased retained permeability (improved dimensionless
fracture conductivity), each of which result in improved production
rates. The FPV system is also particularly suitable for gravel
packing when dense brines are used that contain high concentrations
of calcium or other ions that would polymeric structure with the
degradation products of some degradable fibers (for example up to
12,000 ppm calcium). The salinity in such systems may help delay
polymeric structure of the present disclosure, such as an elongated
polyHEMA polymeric structure, dissolution since the polyHEMA is
insoluble at high salinity conditions.
[0194] In some embodiments, the polymeric structure of the present
disclosure, such as an elongated polyHEMA polymeric structure, and
any other fiber are mixed with a slurry of proppant in crosslinked
polymer fluid in the same way and with the same equipment as is
used for fibers used for sand control and for prevention of
proppant flowback, for example, by the method described in U.S.
Pat. No. 5,667,012, which is hereby incorporated by reference in
its entirety. In fracturing, for proppant transport, suspension,
and placement, the fibers are normally used with proppant or gravel
laden fluids, not normally with pads, flushes or the like.
[0195] While the treatment fluids of the present disclosure are
described herein as comprising the above-mentioned components, it
should be understood that the treatment fluids of the present
disclosure may optionally comprise other chemically different
materials. In embodiments, the treatment fluid may further comprise
stabilizing agents, surfactants, diverting agents, or other
additives. Additionally, a treatment fluid may comprise a mixture
of various crosslinking agents, and/or other additives, such as
fibers or fillers, provided that the other components chosen for
the mixture are compatible with the intended use of the treatment
fluid. Furthermore, the treatment fluid may comprise buffers, pH
control agents, and various other additives added to promote the
stability or the functionality of the treatment fluid. The
treatment fluid may be based on an aqueous or non-aqueous solution.
The components of the treatment fluid may be selected such that
they may or may not react with the subterranean formation that is
to be treated.
[0196] In this regard, the treatment fluid may include components
independently selected from any solids, liquids, gases, and
combinations thereof, such as slurries, gas-saturated or
non-gas-saturated liquids, mixtures of two or more miscible or
immiscible liquids, and the like, as long as such additional
components allow for the consolidation of the one or more polymers
and/or reaction product thereof upon exposure to the consolidation
triggering event. For example, the treatment fluid may comprise
organic chemicals, inorganic chemicals, and any combinations
thereof. Organic chemicals may be monomeric, oligomeric, polymeric,
crosslinked, and combinations, while polymers may be thermoplastic,
thermosetting, moisture setting, elastomeric, and the like.
Inorganic chemicals may be metals, alkaline and alkaline earth
chemicals, minerals, and the like.
[0197] Various other fibrous materials may also be included in the
treatment fluid. Suitable fibrous materials may be woven or
nonwoven, and may be comprised of organic fibers, inorganic fibers,
mixtures thereof and combinations thereof. Such fibers may act as
seeds for the consolidation of the in situ formed polymeric
structures. For example, the polymeric structures that form in the
treatment fluids of the present disclosure may form on and/or
around seed particles (including, for example, proppants) and/or
fibers after exposure to the consolidation triggering event. In
some embodiments, the polymeric structures of the present
disclosure may be otherwise supported by the seed fibers in such a
way that the formed polymeric structure does not easily come loose
from the fibers.
[0198] Stabilizing agents can be added to slow the degradation of
the polymeric structure after its formation downhole. Typical
stabilizing agents may include buffering agents, such as agents
capable of buffering at pH of about 8.0 or greater (such as
water-soluble bicarbonate salts, carbonate salts, phosphate salts,
or mixtures thereof, among others); and chelating agents (such as
ethylenediaminetetraacetic acid (EDTA), nitrilotriacetic acid
(NTA), or diethylenetriaminepentaacetic acid (DTPA),
hydroxyethylethylenediaminetriacetic acid (HEDTA), or
hydroxyethyliminodiacetic acid (HEIDA), among others). Buffering
agents may be added to the treatment fluid in an amount of at least
about 0.05 wt. %, such as from about 0.05 wt. % to about 10 wt. %,
and from about 0.1 wt. % to about 2 wt. %, based upon the total
weight of the treatment fluid. Chelating agents may be added to the
treatment fluid in an amount of at least about 0.75 mole per mole
of metal ions expected to be encountered in the downhole
environment, such as at least about 0.9 mole per mole of metal
ions, based upon the total weight of the treatment fluid.
[0199] In some cases, after the consolidated polymeric structures
have performed their solid-form function, the conditions may be
altered to re-solubilize the consolidated polymeric structures. The
conditions may include a thermal degradation, introduction of a
breaker (such as an enzyme or oxidizer), introduction of a
chelating agent, a change to the solvent salinity, pH, or
hydrophobicity, or any other method allowing the polymeric
structures to degrade or re-solubilize.
[0200] In embodiments, the treatment fluid may be driven into a
wellbore by a pumping system that pumps one or more treatment
fluids into the wellbore. The pumping systems may include mixing or
combining devices, wherein various components, such as fluids,
solids, and/or gases maybe mixed or combined prior to being pumped
into the wellbore. The mixing or combining device may be controlled
in a number of ways, including, but not limited to, using data
obtained either downhole from the wellbore, surface data, or some
combination thereof.
[0201] The foregoing is further illustrated by reference to the
following examples, which are presented for purposes of
illustration and are not intended to limit the scope of the present
disclosure.
Examples
[0202] Example 1 (Solvent change): A solution of guar gum (0.36 wt.
%) was prepared by hydrating the polymer in distilled water while
stirring the mixture for 30 minutes at approximately 1500 rpm in a
blender. Next, the guar solution was transferred to a plastic
beaker. While stirring at 1000 rpm using an overhead mixer,
isopropanol was added via syringe to reach a final concentration of
28% isopropanol. The mixture was stirred for two minutes at 1000
rpm (submitting the fluid to shear rates between 150 to 300
s.sup.-1) following the addition of isopropanol. Guar precipitated
forming white polymeric structures, as illustrated in FIG. 6A,
which is an image of the polymeric structures obtained from
consolidation of guar with isopropanol, and FIG. 6B, which is a
stereo microscope image of the polymeric structures.
[0203] Example 2 (Solvent change): A solution of guar gum (0.54 wt.
%) was prepared by hydrating the polymer in distilled water while
stirring the mixture 30 minutes at approximately 1500 rpm in a
blender. Then potassium chloride was added to obtain a
concentration of 4% KCl in the guar solution. Mixture was stirred
for 15 minutes in a blender. Next, the guar solution was
transferred to a plastic beaker. While stirring at 1000 rpm using
an overhead mixer, methanol was added via syringe to reach a final
concentration of 28% methanol. The mixture was stirred for two
minutes at 1000 rpm (submitting the fluid to shear rates between
150 to 300 s.sup.-1) following the addition of methanol. Guar
precipitated forming white polymeric structures as illustrated in
FIG. 7A (an image of the polymeric structures obtained from
consolidation of guar with methanol in presence of 4% KCl), FIGS.
7B and 7C (stereo microscope images of the polymeric structures).
Although most of the strands are entangled (see FIGS. 7A and 7B),
isolated polymeric structures were also observed (see FIG. 7C).
[0204] Example 3 (solvent change): A sodium alginate solution (1.5
wt. %) (Sigma Aldrich, alginic acid sodium salt from brown
seaweeds) was prepared by adding the polymer powder to distilled
water and stirring the mixture 30 minutes at approximately 1500 rpm
in a blender. Separately, 50 mL of ethylene glycol butyl ether
(Sigma Aldrich) were added to a plastic beaker. While stirring the
ethylene glycol butyl ether at 1000 rpm using an overhead mixer, 10
mL of the alginate solution were added via syringe. The mixture was
stirred 2 minutes at 1000 rpm following the addition of alginate.
The alginate precipitated forming long, white polymeric structures,
as illustrated in FIG. 8A, which is an image of the polymeric
structures obtained adding alginate solution to ethylene glycol
butyl ether, and FIG. 8B, which is a stereo microscope image of the
polymeric structures.
[0205] Example 4 (solvent change): A glass beaker equipped with
magnetic stir bar was charged with 2.0 grams of polylactic acid
(PLA, Sigma Aldrich). The polymer was hydrated in 100 mL of
diethylene glycol dimethyl ether (Sigma Aldrich) by stirring the
mixture 1 hour in a stir plate. Separately, 50 mL of distilled
water were added to a plastic beaker. While stirring the water at
1250 rpm using an overhead mixer, 5 mL of the PLA solution were
added via syringe. The mixture was stirred 2 minutes at 1000 rpm
following the addition of PLA. PLA precipitated forming white
polymeric structures, as illustrated in FIG. 9A (an image of PLA
polymeric structures obtained from consolidation in water, and FIG.
9B (a stereo microscope image of the polymeric structures.
[0206] Example 5 (crosslinking): A base fluid comprising
carboxymethyl cellulose (CMC) (0.5 wt. %) was hydrated in water by
mixing in a laboratory blender for 30-60 minutes until fully
dispersed. A colloidal solution of nanoalumina particles (30 wt. %)
was then added to the polymer solution, at 0.5 vol %, that resulted
in a rapid crosslinking reaction that formed polymeric structures.
The shear provided (approximately 50-100 s.sup.-1) by the blender
induces formation of elongated polymeric structures as illustrated
in FIG. 10 (an image of CMC polymeric structures obtained from the
above crosslinking reaction.
[0207] Example 6 (pH change): A solution of chitosan (0.48 wt. %)
was prepared by hydrating the polymer in 1% acetic acid while
stirring the mixture 30 minutes at approximately 2000 rpm in a
blender. Next, the chitosan solution was transferred to a beaker.
While stirring at 1000 rpm using an overhead mixer, a 30% NaOH
solution was added via syringe to reach a final concentration of 1%
NaOH. The mixture was stirred 2 minutes at 1000 rpm (submitting the
fluid to shear rates between 150 to 300 s.sup.-1) after addition of
NaOH. The chitosan consolidated into white, fiber-like polymeric
structures.
[0208] Example 7 (pH change): Chitosan was hydrated as described in
Example 6. Then hydrolysed guar (0.36 wt. %) was added to the
chitosan solution and the mixture was stirred additional 30 minutes
in a blender at approximately 2000 rpm to allow hydration of the
guar. Then the chitosan-guar solution was transferred to a beaker.
The consolidation was accomplished as described in the previous
example, at 1000 rpm, in which the fluid was exposed to shear rates
between 150 to 300 s.sup.-1. White, fiber-like precipitates
formed.
[0209] Example 8 (Salinity change): A gel solution of poly
2-hydroxyethylmethacrylate (polyHEMA) was obtained through a free
radical polymerization of 2-hydroxyethylmethacrylate in heavy
brine. 5.0 grams of 2-hydroxyethylmethacrylate were added to 100 mL
of 0.21 wt. % ZnBr.sub.2/CaBr.sub.2 brine. Additionally, 0.1 gram
of 2,2'-Azobis(2-methylpropionamidine) was added as an initiator,
and followed by conditioning the sample at 150.degree. F. in a
water bath for 24 hours. The polymer gel was then allowed to return
to ambient temperature before injecting 20 mL of the polyHEMA
solution via syringe, into 150 mL of de-ionized water while
applying mixing shear. The shear was applied using an overhead
mixer at 600 rpm (corresponding to shear rates between
approximately 80 to 180 s.sup.-1), equipped with a 1.5 inch
diameter mixing cylinder. Variable length fiber-like precipitates
were generated by the rapid consolidation of the polymer while
under shear, as illustrated in FIG. 11 (a stereo microscope image
of polyHEMA polymeric structure in deionized water).
[0210] Example 9 (Temperature change): A solution of hydroxypropyl
cellulose (HPC) (1.0 wt. %) was prepared by hydrating the polymer
in deionized water while stirring the mixture 60 minutes at
approximately 1500 rpm in a blender. Separately, 50 mL of deionized
water were added to a 250 mL beaker. The water was heated to
70.degree. C. using a water bath. While stirring the water at 1000
rpm using an overhead mixer with concentric cylinders setup
(submitting the fluid to shear rates between 150 and 300 s.sup.-1),
5 mL of the HPC solution were added via syringe. Mixing was stopped
immediately after the addition of HPC. Long, white, fiber-like
precipitates formed, as illustrated in FIG. 12A (an image of HPC
fiber-like precipitates obtained by adding HPC solution to hot
distilled water), and FIG. 12B (a stereo microscope image of the
fiber-like precipitates. Air bubbles are entrapped in the
fiber-like precipitates). The fiber-like precipitates can be
manipulated and are stable while kept in water above about
50.degree. C., but swell and eventually dissolve completely after
allowing the mixture to return to room temperature.
[0211] Example 10 (crosslinking): A solution of carboxymethyl
cellulose (CMC) was prepared by adding 2.5 g CMC powder to a
blender containing 500 mL of water and blending for approximately
30 minutes at 1500 rpm to hydrate the gel. In separate container, a
solution of 0.5 wt. % alkyl (C12-16) dimethyl benzyl ammonium
chloride (ADBAC) was prepared in water. The solution of CMC was
stirred with a cylindrical rotor, inducing shear (in a Couette
flow). This was followed by the addition of the ADBAC solution,
resulting in the immediate formation of white polymeric structures
(FIGS. 13-14). As shown in FIG. 15, proppant may be added and
contained within the formed polymeric structure. These structures
keep flowing with the carrier fluid and remain in suspension in the
flow. As the shear is stopped, the solid particles remain dispersed
and stable in the carrier fluid for several minutes/hours.
[0212] Example 11 (crosslinking): A base fluid comprising of 0.5 wt
% carboxymethyl cellulose (CMC) was hydrated in water by mixing 1.0
g CMC power in 200 mL deionized water using a laboratory blender
for 30 minutes. A colloidal solution of nanoalumina particles was
then added to the polymer solution, while mixing at 500 rpm. This
resulted in the rapid formation of structures shown in FIG. 16. The
shear provided by the blender at a high rate induces formation of
the elongated polymeric structures.
[0213] Example 12 (crosslinking): Ionic interactions between
polyelectrolytes and surfactants, containing oppositely charged
reactive sites, have been shown to generate filamentous structures.
A 0.5 wt. % solution of hydrated chitosan polymer was made by
mixing 2.5 g of chitosan powder (high mw, manufactured by
Sigma-Aldrich), 500 mL of deionized water and 2.5 mL of glacial
acetic acid in a Waring blender at 1500 rpm for 30 minutes. The pH
of the mix water was adjusted (pH 3.8) prior to adding the polymer
to effectively hydrate the gel. In a separate beaker a 1.0 wt. %
solution of sodium dodecyl sulfate (SDS) was dissolved in deionized
water. While continuously mixing the SDS solution using an overhead
mixer with a 1.5 inch diameter cylinder attached, the hydrated
chitosan solution was added using a syringe to inject a steady
stream of gel. Individualized polymeric structures were formed that
tended to readily entangle or cluster with each other (FIG.
17).
[0214] Example 13 (crosslinking): As discussed above, solutions of
polyelectrolytes can be crosslinked with multivalent ions from salt
solutions such as, but not limited to, aluminum, zirconium,
titanium, or iron to form elongated polymeric structures. The
elongated polymeric structure illustrated in FIG. 18 was produced
by using 150 mL of a pre-hydrated solution of 0.5 wt. %
carboxymethyl cellulose (CMC) in deionized water that was placed in
beaker and stirred with an overhead mixer using a 2 inch three
blade propeller at 600 rpm. Elongated structures were rapidly
formed by injecting 1.5 mL (20 wt. % solution of
AlCl.sub.3.6H.sub.2O in deionized water) to polymer solution while
continuously mixing. Fiber morphology was highly variable resulting
in random lengths and diameters.
[0215] Example 14 (crosslinking): Certain polyelectrolyte
biopolymers can be readily crosslinked with di-valent cations to
form fibers. 20 mL of a pre-hydrated solution of 1.0 wt. %
carrageenan Iota in deionized water was injected, using a syringe,
into a 150 mL solution of 5.0 wt. % CaCl.sub.2.6H.sub.2O in
deionized while continuously stirring with an overhead mixer at 500
rpm with a 2 inch-3 blade propeller. This produced relatively
uniform individualized gel filaments (FIG. 19). Using this same
method, alginate fibers were also formed using a pre-hydrated 1.5
wt. % solution of sodium alginate (Sigma Aldrich, alginic acid
sodium salt from brown algae) in deionized water injected into 150
mL solution of 5.0 wt. % CaCl.sub.2.6H.sub.2O. Similarly, these
fibers tended to have a relatively uniform diameter (See FIGS. 20A
and 20B).
[0216] Example 15 (Crosslinking): This example demonstrates that
fiber like material can be produced through formation of a
polyelectrolyte complex (PEC). A hydrated solution of 0.5 wt. %
chitosan (Aldrich, high mw) was made by mixing 2.5 g chitosan
powder, 500 mL deionized water containing 0.5 vol % glacial acetic
acid, resulting in a pH in the range (3.8-4.2), for 30 minutes in a
Waring blender at 1500 rpm. Separately a solution 0.5 wt. % xanthan
in deionized water was hydrated at neutral pH (6.8-7.2) under the
same mixing conditions. After hydration, the two gel solutions were
combined in a blender (1:1 volume ratio) for 30 seconds resulting
is formation of a gel complex. After several minutes additional
shear was applied to shear apart the complex and form suspended
"pulp-like" fibrous material (FIG. 21).
[0217] Example 16 (Crosslinking): A hydrated solution of 0.5 wt. %
chitosan (Aldrich, high mw) was made by mixing 2.5 g of chitosan
powder in 500 mL deionized water containing 0.5 vol % glacial
acetic acid, resulting in a pH in the range (3.8-4.2), for 30
minutes in a Waring blender at 1500 rpm. Separately a solution of
0.5 wt. % carboxymethyl cellulose (CMC) in deionized water was
hydrated at neutral pH (6.8-7.2) under the same mixing conditions.
After hydration, the two gel solutions were combined in a blender
(1:1 volume ratio) for 5 seconds resulting is formation of a
fibrous gel complex, as shown in FIG. 22.
[0218] Example 17 (Salinity change): A solution of 4.0 wt. %
polyvinyl alcohol (PVA) in deionized water was made by adding
approximately 8.0 g of dry PVA to 200 mL of deionized water
pre-heated to 60.degree. C. while mixing with an overhead mixer for
1 hour. This solution was then directly injected via a 20 mL
syringe into a beaker containing a salt solution of 0.5 M
Na.sub.2SO.sub.4 while stirring with an overhead mixer at 600 rpm.
Polymeric structures were formed within several seconds.
[0219] Example 18 (crosslinking): A 1.0 wt. % solution of alkyl
dimethyl benzyl ammonium chloride (ADBAC) was made by diluting a
concentrated solution of ADBAC in water and stirring. This solution
was then circulated through a co-annular flow cell with a 1 cm
inner diameter (ID) square outer flow channel at 700 mL/min.
Separately a solution of 0.72 wt. % carboxymethyl cellulose (CMC)
was hydrated in deionized water by adding 0.72 g of CMC to 100 mL
deionized water and mixing in a blender for 30 min. A dye solution
was then added for visualizations purposes. The dyed CMC solution
was injected into the inner flow pipe at 5 mL/min flow rate. The
two streams reacted to form elongated polymeric structures, as
shown below in FIG. 23, as the two streams came in contact at the
exit of the inner nozzle.
[0220] Example 19 (crosslinking): The formation of the elongated
polymeric structure described in example 18 can be inhibited by
adding high amount of KCl salt >4.0 wt. %. In the present
example both reactive components are placed in the same solution
stream by intentionally inhibiting their interactions through the
addition monovalent salt (KCl). A solution of 0.72 wt. %
carboxymethyl cellulose (CMC) was hydrated in a solution of 5.0 wt.
% KCl in water by adding 0.72 g of CMC to 100 mL water and 5.0 wt.
% potassium chloride (KCl) salt and mixing in a blender for 30 min.
4.6 mL of a 50% solution of alkyl dimethyl benzyl ammonium chloride
(ADBAC) was then added to the mixing solution. Deionized water was
then circulated through a co-annular flow cell comprised of a 1 cm
ID square outer flow channel and a 1.0 mm ID inner pipe. The
CMC/ADBAC/salt solution was injected into the inner flow pipe at 5
mL/min flow rate. Elongated polymeric structures, as shown in FIGS.
24 and 25, formed through the contact with fresh water, allowing
the diffusion of salt inhibitor from the polymer solution. The loss
of salt then allowed for polymer complexation and subsequent
structure formation.
[0221] Example 20: A custom-built co-annular flow cell 2600, as
shown in FIG. 26, was constructed of optically clear acrylic
containing a 0.95 cm (3/8 inch) inner diameter (ID) tube outer flow
channel 2605 with a 1/16'' OD, 1.0 mm ID stainless steel tube
centered within the channel. The end (exit) of the inner tubing was
positioned 8.5 cm within a 30 cm long flow cell. O-rings 2603,
reducing the effective diameter to a predetermined diameter 2606
(e.g., 0.44 cm), were placed a predetermined distance 2604 (e.g., 5
cm) downstream of the injection point 2607 of the inner tube
2602.
[0222] A 2.0% sodium alginate solution 2601 was injected through
the injection point 2607 into the outer pipe using a high pressure
ISCO syringe pump at 5.0 mL/min. A solution of 5.0 wt. %
CaCl.sub.2-2H.sub.2O 2608 was simultaneously pumped in the outer
pipe via an impeller pump with variable controller (not shown).
This process results in the polymer crosslinking shortly after
contacting with the calcium in the outer flow. Once the leading
front of the polymeric structure reaches the o-rings 2603, the
increased velocity accelerates the polymeric structure causing it
to break at the weakest point, at the inner nozzle tip. During a
continuous injection, this process is repeated at regular intervals
resulting in the elongated polymeric structures 2609 of a given
length (e.g., 5 cm.+-.0.5 cm).
[0223] Example 21: A custom-built cylindrical bob (4 cm diameter)
made from polyethylene was adapted to an overhead mixer to have a
concentric cylinder setup when used in conjunction with a 200 mL
beaker. The beaker was filled with 50 mL of coagulation bath and
centered in the cylindrical bob. The speed of the bob was
controlled by the digital mixer controller. The gap between the bob
and the beaker wall was 1.2 cm, so the fluid experienced a range of
shear rates. The shear rate at the center of the gap was calculated
using the equation below.
.gamma. . = 2 .times. .omega. .times. R c 2 .times. R b 2 x 2
.function. ( R c 2 - R b 2 ) ##EQU00001##
.omega.=angular velocity of bob
( r .times. a .times. d / s ) = ( 2 .times. .pi. 6 .times. 0 )
.times. N , ##EQU00002##
N=rpm
[0224] R.sub.c=radius of container (cm) R.sub.b=radius of the
spinning bob (cm) x=radius at which shear rate is being calculated
(cm)
[0225] The polymer solution (10 mL) was injected via syringe using
a syringe pump (40 mL/min), while mixing the coagulation bath. A
tube (2 mm outer diameter) was connected to the syringe tip and
pointed to the center of the gap between the bob and the beaker.
Mixing was stopped a few seconds after the polymer addition was
complete because the formation of fibers was immediate.
[0226] A solution of 1.5 wt. % sodium alginate was prepared by
hydrating the polymer in deionized water while stirring the mixture
30 minutes at approximately various speeds (see Table 1 below) in a
blender. 10 mL of the alginate solution was injected into 5 wt. %
CaCl.sub.2.2H.sub.2O using the Couette setup described above. At
low shear rates, (.about.20 s.sup.-1) elongated wavy polymeric
structures were formed. In contrast, regular diameter fiber
polymeric structures were obtained at shear rate 60 s.sup.-1. As
shown below in Table 1, the fiber diameter decreased as the shear
rate was increased.
[0227] Example 22: A solution of 2 wt. % chitosan was prepared by
hydrating the polymer in deionized water while stirring the mixture
30 minutes at various speeds (See Table 1 below) in a blender. 10
mL of the chitosan solution was injected into 1% NaOH using the
Couette setup described above. Chitosan consolidated into long,
white fibers. The fiber diameter decreased at increasing shear
rates, as shown in Table 1. The diameter of fibers made at 400
s.sup.-1 was about 2.times. smaller than those made at 60 s.sup.-1.
In all cases, however, the fibers had a smaller diameter than the
nozzle used (2 mm) (See FIGS. 27A-27D). This trend and actual fiber
diameters were very similar to those obtained with Ca-alginate
fibers.
TABLE-US-00001 TABLE 1 Effect of shear in Couette setup on fiber
diameter. Alginate fibers Chitosan fibers {dot over (.gamma.)}
center diameter (mm) diameter (mm) rpm of gap (s.sup.-1) (Example
21) (Example 22) 300 58.67 1.36 .+-. 0.15 1.32 .+-. 0.09 500 97.79
0.88 .+-. 0.12 1.05 .+-. 0.10 800 156.47 0.80 .+-. 0.08 0.80 .+-.
0.05 1000 195.59 0.75 .+-. 0.06 0.79 .+-. 0.04 1500 293.38 0.64
.+-. 0.11 0.84 .+-. 0.09 2000 391.17 0.46 .+-. 0.10 0.68 .+-.
0.04
[0228] Example 23: A custom-built co-annular flow cell 3100, as
shown in FIG. 31, was constructed of an optically clear acrylic
containing a 1 cm square shaped outer flow channel 3101 with a
1/16'' OD, 1.0 mm ID stainless steel tube 3102 centered within the
channel. The end (exit) of the inner tubing 3103 was positioned 8.5
cm within a 30 cm long flow cell. The discharge 3104 of the flow
cell 3100 was open to atmosphere and collected in a separate
container (not shown).
[0229] A solution of 1 wt % sodium alginate was prepared by
hydrating the polymer in deionized water while stirring the mixture
30 minutes at approximately 1500 rpm in a blender. Using a
co-annular setup similar to that described above and illustrated in
FIG. 31, the alginate solution 3105 was injected at a first flow
rate (Q.sub.i) 3106 into the outer channel 3017. The outer channel
3107 contained a 5 wt % solution of CaCl.sub.2.2H.sub.2O used as
coagulation bath and was injected at a different flow rate
(Q.sub.o) 3108 than 3106 in the outer channel 3107. The diameter of
the resulting calcium-alginate fibers 3109 decreased as the flow
rate 3108 of the coagulation bath in the outer channel 3107 was
increased, as shown below in Table 2.
TABLE-US-00002 TABLE 2 Effect of shear in co-annular setup on fiber
diameter. Q.sub.0 {dot over (.gamma.)} at Fibers diameter (mL/min)
interface (s.sup.-1) using CaC1.sub.2 (mm) 350 16.00 0.97 .+-. 0.16
600 51.43 0.48 .+-. 0.09 750 72.68 0.45 .+-. 0.05 1050 115.19 0.39
.+-. 0.06 1310 152.04 0.36 .+-. 0.03 1700 207.30 0.43 .+-. 0.13
[0230] Example 24: Using the co-annular setup described above and
in FIG. 31, a 1% alginate solution 3105 was injected at a first
flow rate (Q.sub.i) 3106 into the outer channel 3107. The outer
channel 3107 contained a 5 wt % CaCl.sub.2.2H.sub.2O and 0.36 wt %
guar as coagulation bath and was injected at a different flow rate
(Q.sub.o) 3108 than 3106 in the outer channel 3107. Similar to
Example 23, the diameter of the resulting calcium-alginate fibers
3109 decreased as the flow rate 3108 of the coagulation bath in the
outer channel 3107 was increased, as shown below in Table 3.
TABLE-US-00003 TABLE 3 Effect of shear in co-annular setup on fiber
diameter. Q.sub.0 {dot over (.gamma.)} at Fibers diameter using
(mL/min) interface (s.sup.-1) CaCl.sub.2/guar (mm) 300 8.91 0.40
.+-. 0.08 450 30.17 0.38 .+-. 0.08 710 67.01 0.31 .+-. 0.03 900
93.94 0.26 .+-. 0.03
[0231] Although the preceding description has been described herein
with reference to particular means, materials and embodiments, it
is not intended to be limited to the particulars disclosed herein;
rather, it extends to all functionally equivalent structures,
methods and uses, such as are within the scope of the appended
claims. Furthermore, although only a few example embodiments have
been described in detail above, those skilled in the art will
readily appreciate that many modifications are possible in the
example embodiments without materially departing from the
disclosure of METHODS OF TREATMENT OF A SUBTERRANEAN FORMATION WITH
POLYMERIC STRUCTURES FORMED IN SITU. Accordingly, all such
modifications are intended to be included within the scope of this
disclosure as defined in the following claims. In the claims,
means-plus-function clauses are intended to cover the structures
described herein as performing the recited function and not only
structural equivalents, but also equivalent structures. Thus,
although a nail and a screw may not be structural equivalents in
that a nail employs a cylindrical surface to secure wooden parts
together, whereas a screw employs a helical surface, in the
environment of fastening wooden parts, a nail and a screw may be
equivalent structures. It is the express intention of the applicant
not to invoke 35 U.S.C. .sctn. 112(f) for any limitations of any of
the claims herein, except for those in which the claim expressly
uses the words `means for` together with an associated
function.
* * * * *