U.S. patent application number 14/715727 was filed with the patent office on 2015-09-10 for cross-linkers for hydraulic fracturing fluid.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Richard D. Hutchins, Li Jiang, Christina D. Martin, Michael D. Parris, Javier Sanchez Reyes.
Application Number | 20150252251 14/715727 |
Document ID | / |
Family ID | 46798839 |
Filed Date | 2015-09-10 |
United States Patent
Application |
20150252251 |
Kind Code |
A1 |
Jiang; Li ; et al. |
September 10, 2015 |
CROSS-LINKERS FOR HYDRAULIC FRACTURING FLUID
Abstract
A method of forming a wellbore fluid, the method including
introducing a hydratable polymer and introducing a crosslinker
comprised of at least a silica material, the crosslinker having a
dimension of from about 5 nm to about 100 nm.
Inventors: |
Jiang; Li; (Katy, TX)
; Parris; Michael D.; (Richmond, TX) ; Hutchins;
Richard D.; (Sugar Land, TX) ; Reyes; Javier
Sanchez; (Katy, TX) ; Martin; Christina D.;
(Channelview, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
46798839 |
Appl. No.: |
14/715727 |
Filed: |
May 19, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13414864 |
Mar 8, 2012 |
9062242 |
|
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14715727 |
|
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61450684 |
Mar 9, 2011 |
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Current U.S.
Class: |
507/211 |
Current CPC
Class: |
C09K 2208/10 20130101;
C09K 8/70 20130101; C09K 8/665 20130101; C09K 2208/26 20130101;
C09K 8/887 20130101; C09K 8/5045 20130101; C09K 2208/08 20130101;
C09K 2208/28 20130101; C09K 8/512 20130101; C09K 8/905 20130101;
C09K 8/685 20130101; C09K 8/516 20130101; C09K 8/80 20130101; C09K
8/90 20130101 |
International
Class: |
C09K 8/80 20060101
C09K008/80; C09K 8/88 20060101 C09K008/88; C09K 8/90 20060101
C09K008/90 |
Claims
1. A method of forming a wellbore fluid, the method comprising:
introducing a polymer; and introducing a crosslinker comprised of
at least a silica material, the crosslinker having a dimension of
from about 5 nm to about 100 nm.
2. The method of claim 1, wherein the hydratable polymer is a
polysaccharide.
3. The method of claim 1, wherein the hydratable polymer is present
in an amount of from about 0.05 weight percent to about 10 weight
percent.
4. The method of claim 1, wherein the hydratable polymer is
selected from the group consisting of guar, hydropropyl guar (HPG),
carboxymethyl guar (CMG), carboxymethylhydroxypropyl guar,
cellulose, hydroxyethylcellulose (HEC), hydroxypropylcellulose
(HPC), carboxymethylhydroxyethylcellulose (CMHEC), xanthan, diutan,
whelan gum, polyacrylamide, polyacrylate polymers.
5. The method of claim 1, wherein the crosslinker comprises
particles with a dimension of from about 10 nm to about 20 nm.
6. The method of claim 1, wherein the silica material comprises is
borosilicate.
7. The method of claim 6, wherein the content of boron in the
wellbore fluid is between 0.5 and 10 ppm by weight elemental
boron.
8. The method of claim 6, wherein the wellbore fluid contains not
more than 5 ppm boron for each gram of the hydratable polymer per
liter of the wellbore fluid.
9. The method of claim 1, wherein the silica has a concentration of
20-50 wt % in the crosslinker.
10. The method of claim 1, wherein the crosslinker further
comprises zirconium, titanium, aluminum, or a combination
thereof.
11.-20. (canceled)
21. The method of claim 1, wherein the polymer is a hydratable
polymer.
22. The method of claim 1, wherein an aqueous medium is introduced
to the wellbore fluid.
23. The method of claim 22, wherein a breaker is introduced to the
wellbore fluid.
24. The method of claim 23, wherein the breaker is encapsulated or
in an enclosure.
25. The method of claim 24, wherein a surfactant is introduced to
the wellbore fluid.
26. The method of claim 25, wherein a friction reducer is
introduced to the wellbore fluid.
27. The method of claim 26, wherein an organoamino compound is
introduced to the wellbore fluid.
28. The method of claim 1, wherein a proppant is introduced to the
wellbore fluid.
29. The method of claim 1, wherein a fiber is introduced to the
wellbore fluid.
30. The method of claim 1, wherein a gas is injected into the
wellbore fluid.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application claims priority to U.S. Provisional
Patent Application No. 61/450,684, filed Mar. 9, 2011, the
disclosure of which is incorporated by reference herein in its
entirety.
TECHNICAL FIELD
[0002] This present disclosure relates generally to the field of
crosslinkers for oilfield application, and relates more
particularly, but not by way of limitation, to methods of using
crosslinkers in various oilfield applications.
BACKGROUND
[0003] To enhance or increase the production of oil and gas
hydrocarbons from wells bored into subterranean-formations, it has
been common practice to pump a viscous fluid at high pressures down
into the wellbore to crack the formation and force the fracturing
fluid into those cracks. The fracturing fluid is also used to carry
sand or other types of particles, called proppants, to hold the
cracks open when the pressure is relieved. The cracks held open by
the proppant provide additional paths for the oil or natural gas to
reach the wellbore, which, in turn, increases the production of oil
and/or natural gas from the well.
[0004] In order to form the viscous fluid, a thickening agent (or a
viscosifying agent), such as a polymer, is incorporated into water
or an aqueous solution. A number of polymers are known for this
purpose including a number of polysaccharides. Viscosity can then
be increased considerably, giving a viscoelastic gel, by
cross-linking the polymer molecules. This has particular
application in connection with the extraction of hydrocarbons such
as oil and natural gas from a reservoir which is a subterranean
geologic formation by means of a drilled well that penetrates the
hydrocarbon-bearing reservoir formation. In this field, one
commercially very significant application of thickened fluids is
for hydraulic fracturing of a subterranean formation. The polymeric
thickening agent may (1) assist in controlling leak-off of the
fluid into the formation, (2) aid in the transfer of hydraulic
fracturing pressure to the rock surfaces and (3) facilitate the
suspension and transfer into the formation of proppant materials
that remain in the fracture and thereby hold the fracture open when
the hydraulic pressure is released.
[0005] Further applications of thickened fluids in connection with
hydrocarbon extraction may include acidizing, control of fluid
loss, diversion, zonal isolation, and the placing of gravel packs.
Gravel packing is a process of placing a volume of particulate
material, frequently coarse sand, within the wellbore and possibly
extending slightly into the surrounding formation. The particulate
material used to form a gravel pack may be transported into place
in suspension in a thickened fluid. When it is in place, the gravel
pack acts as a filter for fine particles so that they are not
entrained in the produced fluid.
[0006] Crosslinking of the polymeric materials then serves to
increase the viscosity and proppant carrying ability of the fluid,
as well as to increase its high temperature stability. Typical
crosslinking agents comprise soluble boron, zirconium, and titanium
compounds. Chromium and aluminum compounds have also been used. The
viscosity of solutions of guar gum and similar thickeners can be
greatly enhanced by crosslinking them with boric acid or other
boron containing materials. Thus, boron crosslinked guar gum
solutions are useful as fracturing fluids.
[0007] Historically, as described in U.S. Pat. Nos. 6,310,104 and
6,372,805, the disclosures of which are incorporated by reference
herein in their entirety, amorphous borosilicate particles in the
size domain of 10-20 nm and in the concentration range of 20-40 wt
% in water solvent have been used in the paper industry. The
mono-dispersion is achieved by adding aqueous silicic acid to an
aqueous boric oxide solution with extended agitation, followed by
recovering the aqueous colloids containing amorphous, not glassy,
borosilicate nano-spheres. These products have been used in paper
industry to increase the conversion of trees to paper by insuring
that raw material fibers used in the process are retained and
become part of the final paper sheet. They also facilitate the
capture of raw material fibers in the produced paper sheet and
minimize the loss of value resources to the generation of waste. In
addition, they enhance the removal of water from municipal sludges
which reduces fuel consumption during transportation of the
sludges. However, neither of the above references described that
amorphous borosilicate may be used a crosslinker for a wellbore
composition used to treat a subterranean formation.
[0008] The viscosity of these crosslinked gels can be reduced by
mechanical shearing (i.e., they are shear thinning) but gels
cross-linked with boron compounds may reform spontaneously after
exposure to high shear. This property of being reversible makes
boron-crosslinked gels particularly attractive and they have been
widely used. Furthermore, the overall performance of a fracturing
fluid intimately depends on the cross-linking chemistry that forms
the viscous gel. Borate crosslinked gel fracturing fluid typically
utilize the borate anion to crosslink the hydrated polysaccharide
polymers and thus provide increased viscosity. The crosslinked
polymer may then be rendered chemically reversible by altering the
pH of the fluid system. It is this reversible characteristic of
crosslinked borate polymer fluids that may improve the
effectiveness of the subsequent clean up step more effectively, and
thus potentially result in good regained permeability and
conductivity.
[0009] It is generally desirable to achieve the desired viscosity
with a low concentration of thickening materials so as to reduce
cost of materials and reduce the amount of material which is
delivered below ground and may need to be removed in a subsequent
cleanup operation. Also, boron and metals, in sufficient
concentration, can be toxic to the environment and so it is also
desirable to minimize the amount of boron or metallic cross-linking
agent which is used.
[0010] Additionally, it is desirable to develop a new cross-linker
material that is completely free of boron or, alternatively, to use
an insoluble form of boron with an identical electronic
configuration of borax so that the well established boron crosslink
chemistry can remain intact.
SUMMARY OF THE DISCLOSURE
[0011] There is a need, addressed by the subject matter described
herein, for a wellbore composition and a method of forming and/or
applying a wellbore composition, to resolves the above issues.
[0012] The above and other issues are addressed by the present
application, wherein in embodiments, the application relates to a
method of forming a wellbore fluid, the method comprising:
introducing a hydratable polymer; and introducing a crosslinker
comprised of at least a silica material, the crosslinker having a
dimension of from about 5 nm to about 100 nm.
[0013] In embodiments, described herein is a method of treatment of
a wellbore or a subterranean formation penetrated by a wellbore,
the method comprising: introducing a wellbore composition to the
wellbore or the subterranean formation, the wellbore composition
comprised of at least a hydratable polymer and a crosslinker,
wherein the crosslinker is comprised of at least a silica material,
the crosslinker having a dimension of from about 5 nm to about 100
nm.
BRIEF DESCRIPTIONS OF DRAWINGS
[0014] FIG. 1 represents the rheological profile for Example 1
comprised of a 5 ppm borosilicate colloidal dispersion crosslinked
with 30 lbm/1,000 gal US guar at 130.degree. F. at a constant
pressure of 200 psia and at a shear rate 100/s (pH 9.1).
[0015] FIG. 2 represents the rheological profile for Example 2
comprised of a 12.4 ppm borosilicate colloidal dispersion
crosslinked with 30 lbm/1,000 gal US guar at 120.degree. F. at
multiple pressure rampings between ambient and 20,000 psia and at a
shear rate 100/s (pH 9.4).
DETAILED DESCRIPTION
[0016] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation--specific
decisions must 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 of the application 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. Also, in the summary of the invention and this detailed
description, it should be understood that a concentration range
listed or described as being useful, suitable, or the like, is
intended that any and every concentration 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 and every possible number along the continuum
between about 1 and about 10. Thus, even if specific data points
within the range, or even no data points within the range, are
explicitly identified or refer to only a few specific, it is to be
understood that inventors appreciate and understand that any and
all data points within the range are to be considered to have been
specified, and that inventors possessed knowledge of the entire
range and all points within the range.
[0017] As used in the specification and claims, "near" is inclusive
of "at."
[0018] The following definitions are provided in order to aid those
skilled in the art in understanding the detailed description.
[0019] The term "treatment", or "treating", refers to any
subterranean operation that uses a fluid in conjunction with a
desired function and/or for a desired purpose. The term
"treatment", or "treating", does not imply any particular action by
the fluid.
[0020] The term "fracturing" refers to the process and methods of
breaking down a geological formation and creating a fracture, i.e.,
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
otherwise use conventional techniques known in the art.
[0021] A "crosslinker" or "crosslinking agent" is a compound mixed
with a base-gel fluid to create a viscous gel. Under proper
conditions, the crosslinker reacts with a multiple-strand polymer
to couple the molecules, creating a crosslinked polymer fluid of
high, but closely controlled, viscosity.
[0022] The term "hydraulic fracturing" as used in the present
application refers to a technique that involves pumping fluids into
a well at pressures and flow rates high enough to split the rock
and create opposing cracks extending up to 300 m (1000 feet) or
more from either side of the borehole. Later, sand or ceramic
particulates, called "proppant," are carried by the fluid to pack
the fracture, keeping it open once pumping stops and pressures
decline.
[0023] As used herein, the new numbering scheme for the Periodic
Table Groups are used as in Chemical and Engineering News, 63(5),
27 (1985).
[0024] As used herein, the term "liquid composition" or "liquid
medium" refers to a material which is liquid under the conditions
of use. For example, a liquid medium may refer to water, and/or an
organic solvent which is above the freezing point and below the
boiling point of the material at a particular pressure. A liquid
medium may also refer to a supercritical fluid.
[0025] As used herein, the term "polymer" or "oligomer" is used
interchangeably unless otherwise specified, and both refer to
homopolymers, copolymers, interpolymers, terpolymers, and the like.
Likewise, a copolymer may refer to a polymer comprising at least
two monomers, optionally with other monomers. When a polymer is
referred to as comprising a monomer, the monomer is present in the
polymer in the polymerized form of the monomer or in the derivative
form of the monomer. However, for ease of reference the phrase
comprising the (respective) monomer or the like is used as
shorthand.
[0026] The terminology and phraseology used herein is solely used
for descriptive purposes and should not be construed as limiting in
scope. Language such as "including," "comprising," "having,"
"containing," or "involving," and variations thereof, is intended
to be broad and encompass the subject matter listed thereafter,
equivalents, and additional subject matter not recited.
[0027] Described herein is a method of well treatment, that
includes a method of forming a wellbore fluid, the method
comprising: introducing a hydratable polymer; and introducing a
crosslinker comprised of at least a silica material, the
crosslinker having a dimension of from about 5 nm to about 100
nm.
Polymer
[0028] In certain embodiments of the present application, the well
treatment fluid comprises at least one polymer (also referred to as
a "viscosifier") and at least one crosslinker, the polymer and
crosslinker reacting under proper conditions to form a crosslinked
polymer. The polymer should not prematurely crosslink before the
desired set time. The polymer may be a hydratable polymer, such as
a polysaccharide.
[0029] The hydratable polymer may be a high molecular weight
water-soluble polysaccharide containing cis-hydroxyl groups that
can complex the crosslinking agent. Without limitation, suitable
polysaccharides include those polysaccharides having a molecular
weight in the range of about 200,000 to about 3,000,000 Daltons,
such as, for example, from about 500,000 to about 2,500,000 Daltons
and from about 1,500,000 and 2,500,000 Daltons.
[0030] Polysaccharides having adjacent cis-hydroxyl groups for the
purposes of the present application include such polysaccharides as
the galactomannans. The term galactomannans refers in various
aspects to natural occurring polysaccharides derived from various
endosperms of seeds. They are primarily composed of D-mannose and
D-galactose units. They generally have similar physical properties,
such as being soluble in water to form thick, highly viscous
solutions which usually can be gelled (crosslinked) by the addition
of such inorganic salts as borax. Examples of some plants producing
seeds containing galactomannan gums include Tara, Huizache, locust
bean, Pola verde, Flame tree, guar bean plant, Honey locust,
Lucerne, Kentucky coffee bean, Japanese pagoda tree, Indigo, Jenna,
Rattlehox, Clover, Fenergruk seeds and soy bean hulls. The gum is
provided in a convenient particulate form, wherein examples of
polysaccharide include guar and its derivatives. These include guar
gum, carboxymethylguar, hydroxyethylguar,
carboxymethylhydroxyethylguar, hydroxypropylguar (HPG),
carboxymethylhydroxypropylguar, and combinations thereof. As a
galactomannan, guar gum is a branched copolymer containing a
mannose backbone with galactose branches.
[0031] Upon hydrolysis, galactomannans may yield the two simple
sugars, mannose, and galactose. Analyses have indicated that such
polysaccharides are long chain polymers of D-mannopyranose units
linked at the .beta.-1,4 position which have D-galactopyranose
units located as side chains on the molecule. The D-galactopyranose
units are connected to the C.sub.6 atoms of the D-mannose units
that make up the main structural framework. The ratio of
D-galactose to D-mannose in the galactomannans generally varies
from about 1:1.2 to about 1:2, depending upon the particular
vegetable source from which the material is derived. In all cases,
however, the mannose residues have cis-hydroxyl groups at the
C.sub.2 and C.sub.3 positions, accounting for the crosslinking
reactions obtained with the galactomannans and making them useful
for the purposes of the present application.
[0032] As discussed above, some nonlimiting examples of suitable
polymers include guar gums, high-molecular weight polysaccharides
composed of mannose and galactose sugars, or guar derivatives such
as hydropropyl guar (HPG), carboxymethyl guar (CMG), and
carboxymethylhydroxypropyl guar (CMHPG). Cellulose derivatives such
as hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC) and
carboxymethylhydroxyethylcellulose (CMHEC) may also be used, and
have been shown to be useful as viscosifying agents as well.
Biopolymers such as xanthan, diutan, whelan gum and scleroglucan
may also be used. Synthetic polymers such as polyacrylamide and
polyacrylate polymers and copolymers, as well as diutans, may be
useful for high-temperature applications. Additional examples of
suitable polymers are described in U.S. Pat. No. 5,981,446, U.S.
Pat. No. 7,497,263 and U.S. Pat. No. 7,968,501, the disclosures of
which are incorporated by reference herein in their entirety.
[0033] The polymer may be present in the wellbore fluid in an
amount of from about 0.05 weight percent to about 10 weight
percent, from about 0.1 weight percent to about 5 weight percent,
from about 0.1 weight percent to about 2 weight percent and from
about 0.1 weight percent to about 0.5 weight percent, based upon
the total weight of the wellbore fluid.
Crosslinker
[0034] The wellbore fluid described herein may also include a
crosslinker. As discussed above, fracturing fluid must be
chemically stable and sufficiently viscous to suspend the proppant
while it is sheared and heated in surface equipment, well tubulars,
perforations and the fracture; otherwise, premature settling of the
proppant occurs, jeopardizing the treatment. Crosslinkers join
polymer chains for greater thickening.
[0035] The overall performance of a fracturing fluid intimately
depends on the cross-linking chemistry that forms the viscous gel.
Borate crosslinked gel fracturing fluid utilizes borate anion to
crosslink the hydrated polysaccharide polymers and provide
increased viscosity. The crosslink obtained by using borate is
chemically reversible as triggered by altering the pH of the fluid
system. The reversible characteristic of the crosslink in borate
fluids helps subsequent clean up step more effectively, resulting
in good retained permeability and conductivity.
[0036] It is desirable to use an insoluble form of boron with an
identical electronic configuration of borax so that the well
established boron crosslink chemistry can remain intact, together
with the vast engineering procedures related to its application in
stimulation industry.
[0037] When the crosslinker contain boron, the concentration of
boron in the fluid may be in a range of from 0.5 ppm to 700 ppm
elemental boron, from about 1.0 ppm to about 500 ppm, from about
5.0 ppm to about 250 ppm, from about 10 ppm to about 100 ppm, from
about 15 ppm to about 75 ppm and from about 15 ppm to about 50 ppm.
This also means that the proportion of boron to the polymer to be
crosslinked may be low. Thus the amounts of the polymer and boron
in the fluid may be such that the amount of boron is not more than
0.002 or 0.001 times the amount of the polymer. Expressing this in
terms of concentrations, the content of boron may be not more than
2 ppm, possibly not more than 1 ppm for each gram of polymer in 1
liter of solution. For a solution containing 4 gm/liter of polymer
to be crosslinked this would be no more than 8 ppm, possibly not
more than 4 ppm boron in the solution. The quantity of cross
linking agent may be no more than 30%, possibly no more than 20, 15
or 10% by weight of the polymer to be crosslinked.
[0038] In embodiments, the crosslinker includes at least silica and
has a dimension of from about 5 nm to about 100 nm. In other
embodiments, the crosslinker may have a dimension of from 10 nm to
about 75 nm, from about 20 nm to about 60 nm, from about 25 nm to
about 50 nm and from about 30 nm to about 40 nm. The cross-linking
agents and any of the supporting structures within them may have at
least one dimension which is at least 5 nanometer (5 nm). Whilst
they may or may not have a spherical shape or a cylindrical shape,
they may have a particle size, which is expressed as the diameter
of an equivalent sphere, of at least 5 nm, possibly at least 10, 20
or 25 nm.
[0039] The crosslinker may also include a non-aqueous solvated
crosslinker, such as borosilicate. Borosilicate is a material
having a mole ratio of boron to silicon ranging from about 1:100 to
about 2:5 and/or a mole ratio of sodium to silicon ranging from
about 6:1000 to 1.04:1. The crosslinker may also be a colloid of
borosilicate having a chemistry similar to that of borosilicate
glass, such as, for example, an aqueous colloid. This colloid may
be generally prepared by reacting an alkali metal salt of a boron
containing compound with silicic acid under conditions resulting in
the formation of a colloid. The surface area of the borosilicate
should be in the range of from about 15 to about 3000 m.sup.2/g,
from about 50 to about 3000 m.sup.2/g, from about 250 to 3000
m.sup.2/g and from about 700 to 3000 m.sup.2/g.
[0040] As described in U.S. Pat. No. 6,310,104, the disclosure of
which is incorporated by reference herein in its entirety,
colloidal borosilicate materials may be prepared by first preparing
silicic acid. This may be advantageously accomplished by contacting
an alkali metal silicate solution, such as a dilute solution of the
alkali metal silicate with a commercial cation exchange resin, such
as a so called strong acid resin, in the hydrogen form and
recovering a dilute solution of silicic acid. The silicic acid may
then be added, with agitation to a dilute solution of an alkali
metal borate at a pH of from 6-14, and a colloidal borosilicate
product suspended in water is recovered. Alternatively, the alkali
metal borate and the silicic acid may be added simultaneously to
prepare suitable materials. The concentration of the silicic acid
solution utilized is generally from 3 to 8 percent by weight
SiO.sub.2, and from about 5 to about 7 percent by weight SiO.sub.2.
The weight percent of the borate solution utilized is generally
0.01 to 30 and from 0.4 to 20 weight percent as B.sub.2O.sub.3. The
borate salt utilized may range over a wide variety of compounds,
wherein examples of the borate salt include commercial borax,
sodium tetraborate decahydrate, or sodium tetraborate pentahydrate.
Other water soluble borate materials may be utilized. The
preparation of the colloidal borosilicate material of this
application may be accomplished with or without pH adjustment as it
is sometimes advisable to conduct the reaction at a pH of 7.5 to
10.5 or of 8 to 9.5 through the addition of an appropriate alkali
metal hydroxide, such as sodium hydroxide, to the reaction mixture.
Other methods of preparing the colloidal borosilicates of this
application may also be utilized. These methods could encompass
preparing the colloidal borosilicate as above and spray drying the
particles followed by grinding, or other methods which would yield
a borosilicate material meeting the parameters set forth above.
[0041] Embodiments of the borosilicate include, among others,
silicon dioxide (SiO.sub.2), boric oxide (B.sub.2O.sub.3), aluminum
oxide (Al.sub.2O.sub.3), and at least one alkali oxide. The alkali
oxide in the borosilicate may include lithium oxide (Li.sub.2O),
potassium oxide (K.sub.2O), and sodium oxide (Na.sub.2O). Not
intending to be bound by theory, the Al.sub.2O.sub.3 may play a
role in inhibiting the formation of cristobalite and tridymite
crystals during the sintering of the borosilicate glass
composition. In addition, the B.sub.2O.sub.3 may increase the
meltability of the borosilicate and potentially act as an efficient
flux without significantly increasing the coefficient of thermal
expansion (CTE) of the borosilicate glass, while the alkali oxide
may increase the CTE of the borosilicate glass. The borosilicate
colloidal particles may have the ability to crosslink guar (and
other polysaccharide polymers) effectively since its great
population of surface accessible boron atoms retains essentially
identical electronic configuration to tetrahedral borate anion
which, in an appropriate pH domain, enables the formation of
complex associations with the abundant cis-hydroxyl groups in sugar
residues.
[0042] The crosslinker may further include one or more transition
metals, such as zirconium, titanium and aluminum. One or more of
the above crosslinkers may be included in the wellbore composition
such that a "combination" of these materials is included in the
wellbore composition. In some embodiments, the silica has a
concentration of 20-50 wt % in the crosslinker.
[0043] Furthermore, in certain instances, a delay in crosslinking
may be advantageous. For example, a delayed crosslinker can be
placed downhole prior to crosslinking; the gel fluid is prepared on
the surface, then crosslinks after being introduced into a wellbore
which penetrates a subterranean formation, forming a high viscosity
treating fluid therein. The delay in crosslinking is beneficial in
that the amount of energy required to pump the fluids can be
reduced, the penetration of certain fluids can be improved, and
shear and friction damage to polymers can be reduced. By delaying
crosslinking, crosslinkers can be more thoroughly mixed with the
polymer fluid prior to crosslink initiation, providing more
effective crosslinks, more uniform distribution of crosslinks, and
better gel properties.
Additional Materials
[0044] The wellbore fluid of the present application may also
include additional constituents or material. One additional
material that may be included is a breaker. The purpose of this
material is to "break" or diminish the viscosity of the crosslinked
fluid so that this fluid is more easily recovered from the
formation during cleanup. The breaker degrades the crosslinked
polymer to reduce its molecular weight. If the polymer is a
polysaccharide, the breaker may be a peroxide with oxygen-oxygen
single bonds in the molecular structure. These peroxide breakers
may be hydrogen peroxide or other material such as a metal peroxide
that provides peroxide or hydrogen peroxide for reaction in
solution. A peroxide breaker may be a so-called stabilized peroxide
breaker in which hydrogen peroxide is bound or inhibited by another
compound or molecule(s) prior to its addition to water but is
released into solution when added to water.
[0045] Examples of suitable stabilized peroxide breakers include
the adducts of hydrogen peroxide with other molecules, and may
include carbamide peroxide or urea peroxide
(CH.sub.4N.sub.2O.H.sub.2O.sub.2), percarbonates, such as sodium
percarbonate (2Na.sub.2CO.sub.3.3H.sub.2O.sub.2), potassium
percarbonate and ammonium percarbonate. The stabilized peroxide
breakers may also include those compounds that undergo hydrolysis
in water to release hydrogen peroxide, such sodium perborate. A
stabilized peroxide breaker may be an encapsulated peroxide. The
encapsulation material may be a polymer that can degrade over a
period of time to release the breaker and may be chosen depending
on the release rate desired. Degradation of the polymer can occur,
for example, by hydrolysis, solvolysis, melting, or other
mechanisms. The polymers may be selected from homopolymers and
copolymers of glycolate and lactate, polycarbonates,
polyanhydrides, polyorthoesters, and polyphosphacenes. The
encapsulated peroxides may be encapsulated hydrogen peroxide,
encapsulated metal peroxides, such as sodium peroxide, calcium
peroxide, zinc peroxide, etc. or any of the peroxides described
herein that are encapsulated in an appropriate material to inhibit
or reduce reaction of the peroxide prior to its addition to
water.
[0046] The peroxide breaker, stabilized or unstabilized, is used in
an amount sufficient to break the heteropolysaccharide polymer or
diutan. This may depend upon the amount of heteropolysaccharide
used and the conditions of the treatment. Lower temperatures may
require greater amounts of the breaker. In many, if not most
applications, the peroxide breaker may be used in an amount of from
about 0.001% to about 20% by weight of the treatment fluid, more
particularly from about 0.005% to about 5% by weight of the
treatment fluid, and more particularly from about 0.01% to about 2%
by weight of the treatment fluid. The peroxide breaker may be
effective in the presence of mineral oil or other hydrocarbon
carrier fluids or other commonly used chemicals when such fluids
are used with the heteropolysaccharide.
[0047] The breaker may also be encapsulated or in an enclosure to
the delay the release of the breaker, such as those disclosed in
U.S. Pat. No. 4,741,401 (Walles, et. al), hereinafter incorporated
by reference in its entirety. Additional examples of breakers
include: ammonium, sodium or potassium persulfate; sodium peroxide;
sodium chlorite; sodium, lithium or calcium hypochlorite; bromates;
perborates; permanganates; chlorinated lime; potassium
perphosphate; magnesium monoperoxyphthalate hexahydrate; and a
number of organic chlorine derivatives such as
N,N'-dichlorodimethylhydantoin and N-chlorocyanuric acid and/or
salts thereof. The specific breaker employed may depend on the
temperature to which polymer gel is subjected. At temperatures
ranging from about 50.degree. C. to about 95.degree. C., an
inorganic breaker or oxidizing agent, such as, for example,
KBrO.sub.3, and other similar materials, such as KClO.sub.3,
KlO.sub.3, perborates, persulfates, permanganates (for example,
ammonium persulfate, sodium persulfate, and potassium persulfate)
and the like, are used to control degradation of the polymer gel.
At about 90 to 95.degree. C. and above, typical breakers include
suitable breaker, an example of which is sodium bromate.
[0048] Breaking aids or catalysts may be used with the peroxide
breaker. The breaker aid may be an iron-containing breaking aid
that acts as a catalyst. The iron catalyst is a ferrous iron (II)
compound. Examples of suitable iron (II) compounds include, but are
not limited to, iron (II) sulfate and its hydrates (such as, for
example, ferrous sulfate heptahydrate), iron (II) chloride, and
iron (II) gluconate. Iron powder in combination with a pH adjusting
agent that provides an acidic pH may also be used. Other transition
metal ions can also be used as the breaking aid or catalyst, such
as manganese (Mn).
[0049] Some fluids according to the present application may also
include a surfactant. Any surfactant for which its ability to aid
the dispersion and/or stabilization of the gas component into the
base fluid to form an energized fluid is readily apparent to those
skilled in the art may be used. Viscoelastic surfactants, such as
those described in U.S. Pat. No. 6,703,352 (Dahayanake et al.) and
U.S. Pat. No. 6,482,866 (Dahayanake et al.), both incorporated
herein by reference in their entirety, are also suitable for use in
wellbore fluids.
[0050] In some embodiments, the surfactant may be an ionic
surfactant. Examples of suitable ionic surfactants include 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. Examples of suitable ionic surfactants
also include cationic surfactants such as alkyl amines, alkyl
diamines, alkyl ether amines, alkyl quaternary ammonium, dialkyl
quaternary ammonium and ester quaternary ammonium compounds.
Examples of suitable ionic surfactants also include surfactants
that are usually regarded as zwitterionic surfactants, and in some
cases as amphoteric surfactants, such as alkyl betaines, alkyl
amido betaines, alkyl imidazolines, alkyl amine oxides and alkyl
quaternary ammonium carboxylates. The amphoteric surfactant is a
class of surfactant that has both a positively charged moiety and a
negatively charged moiety over a certain pH range (typically
slightly acidic), only a negatively charged moiety over a certain
pH range (e.g. typically slightly alkaline) and only a positively
charged moiety at a different pH range (e.g. typically moderately
acidic), while a zwitterionic surfactant has a permanently
positively charged moiety in the molecule regardless of pH and a
negatively charged moiety at alkaline pH. In some embodiments, the
surfactant is a cationic, zwitterionic or amphoteric surfactant
containing and amine group or a quaternary ammonium group in its
chemical structure ("amine functional surfactant"). A particularly
useful surfactant is the amphoteric alkyl amine contained in the
surfactant solution AQUAT 944 (available from Baker Petrolite of
12645 W. Airport Blvd, Sugar Land, Tex. 77478 USA). In other
embodiments, the surfactant may be 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 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 the wellbore fluid. These fluids may
incorporate the surfactant or blend of surfactants in an amount of
about 0.02 wt % to about 5 wt % of total liquid phase weight, or
from about 0.05 wt % to about 2 wt % of total liquid phase
weight.
[0051] Other materials which may be included in a wellbore fluid
include electrolyte, such as an organic or inorganic salt, friction
reducers to assist flow when pumping and surfactants.
[0052] A wellbore fluid may be a so-called energized fluid formed
by injecting gas (most commonly nitrogen, carbon dioxide or mixture
of them) into the wellbore concomitantly with the aqueous solution.
Dispersion of the gas into the base fluid in the form of bubbles
increases the viscosity of such fluid and impacts positively its
performance, particularly its ability to effectively induce
hydraulic fracturing of the formation, and capacity to carry
solids. The presence of the gas also enhances the flowback of the
fluid when this is required. In a method of this application the
wellbore fluid may serve as a fracturing fluid or gravel packing
fluid and may be used to suspend a particulate material for
transport down wellbore. This material may in particular be a
proppant used in hydraulic fracturing or gravel used to form a
gravel pack. The most common material used as proppant or gravel is
sand of selected size but ceramic particles and a number of other
materials are known for this purpose.
[0053] Wellbore fluids in accordance with this application may also
be used without suspended proppant in the initial stage of
hydraulic fracturing. Further applications of wellbore fluids in
accordance with this application are in modifying the permeability
of subterranean formations, and the placing of plugs to achieve
zonal isolation and/or prevent fluid loss.
[0054] For some applications a fiber component may be included in
the treatment fluid 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,
but not necessarily limited to, 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 of the application, the
fiber component may be present at concentrations from about 1 to
about 15 grams per liter of the liquid phase, in particular the
concentration of fibers may be from about 2 to about 12 grams per
liter of liquid, and more particularly from about 2 to about 10
grams per liter of liquid.
[0055] Friction reducers may also be incorporated into fluids of
the application. Any friction reducer may be used. Also, polymers
such as polyacrylamide, polyisobutyl methacrylate, polymethyl
methacrylate and polyisobutylene as well as water-soluble friction
reducers such as guar gum, guar gum derivatives, polyacrylamide,
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 (Culter et al.) or
drag reducers such as those sold by Chemlink designated under the
trademarks "FLO 1003, 1004, 1005 & 1008" 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 need for conventional
fluid loss additives.
[0056] Embodiments of the present application 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 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 will typically 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, but are not necessarily limited to:
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 and apricot; ground or crushed seed shells of other
plants such as various forms of corn (corn cobs or corn kernels);
processed wood materials such as those derived from woods such as
oak, hickory, walnut, poplar and mahogany, including such woods
that have been processed by grinding, chipping, or other form of
particalization, processing. Further information on nuts and
composition thereof may be found in Encyclopedia of Chemical
Technology, Edited by Raymond E. Kirk and Donald F. Othmer, Third
Edition, John Wiley & Sons, Volume 16, pages 248-273 (entitled
"Nuts"), Copyright 1981, which is incorporated herein by reference
in its entirety.
[0057] The concentration of proppant in the fluid can be any
concentration known in the art, and 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 be further
coated with a resin to potentially improve the strength, clustering
ability, and flow back properties of the proppant.
[0058] The aqueous medium of the present application may be water
or brine. In those embodiments, the aqueous medium is a brine, the
brine is water comprising an inorganic salt or organic salt.
Examples of inorganic salts include alkali metal halides, such as
potassium chloride. The carrier brine phase may also comprise an
organic salt such as sodium or potassium formate. Preferred
inorganic divalent salts include calcium halides, such as, for
example, calcium chloride or calcium bromide. Sodium bromide,
potassium bromide, or cesium bromide may also be used. The salt is
chosen for compatibility reasons, this determination may be based
upon the reservoir drilling fluid used a particular brine phase and
the completion/clean up fluid brine phase is chosen to have the
same brine phase.
[0059] Fluid embodiments of the present application may further
contain other additives and chemicals that are known to be commonly
used in oilfield applications by those skilled in the art. These
include, but are not necessarily limited to, materials such as
surfactants in addition to those mentioned hereinabove, breaker
aids in addition to those mentioned hereinabove, oxygen scavengers,
alcohols, scale inhibitors, corrosion inhibitors, fluid-loss
additives, bactericides, 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 or the
hydratable polymer.
[0060] Aqueous fluid embodiments of the present application may
also comprise an organoamino compound. Examples of suitable
organoamino compounds include tetraethylenepentamine,
triethylenetetramine, pentaethylenhexamine, triethanolamine, and
the like, or any mixtures thereof. When organoamino compounds are
used, they may be incorporated at an amount from about 0.01 wt % to
about 2.0 wt % based on total liquid phase weight. Preferably, when
used, the organoamino compound is incorporated at an amount from
about 0.05 wt % to about 1.0 wt % based on total liquid phase
weight. A particularly useful organoamino compound is
tetraethylenepentamine.
[0061] The well treatment composition may then be introduced or
placed in the wellbore or subterranean formation. As used herein,
the term "introducing" or "introduced" refers to mechanism of
locating the well treatment composition in the wellbore or
subterranean formation by various methods and/or with suitable
equipment typically used in various oilfield operations, such as
fracturing and cementing. Examples of "introducing" mechanisms
include such as, for example, pumping the well treatment
composition through the wellbore or through installed
coiltubing.
[0062] The following examples are presented to illustrate the
preparation and properties of aqueous viscoelastic nanotube fluids
and should not be construed to limit the scope of the application,
unless otherwise expressly indicated in the appended claims. All
percentages, concentrations, ratios, parts, etc. are by weight
unless otherwise noted or apparent from the context of their use.
The statements made herein merely provide information related to
the present disclosure and may not constitute prior art, and may
describe some embodiments illustrating the application.
EXAMPLES
Example 1
[0063] The sample was prepared by adding 3 mL borosilicate
colloidal dispersion into 200 mL fully hydrated (Di-water) guar
linear gel, under constant mixing in a conventional glass blender
cup. The vortex was closed within about a minute, which signaled
the transformation from a linear polymer gel to a crosslinked
polymer gel. The pH of the crosslinked polymer gel was then
determined to be 9.1. Then, about a 30 ml volume sample was
transferred to a Couette cup, and assembled onto a M5500 rheometer
(GRACE Instrument Company, Houston, Tex.). The sample was covered
under a 200 psia nitrogen blanket in the headspace to prevent water
from evaporation at elevated temperatures. The polymer gel went
through a process of thermal thinning, characteristic to typical
crosslinked fluid, as the rheometer heated up. Subsequently, the
polymer gel regained the viscosity when the fluid temperature
stabilized. The viscosity was measured at a constant shear rate of
100/s. As shown in FIG. 1, at a normal concentration level of 5 ppm
boron as determined via inductively coupled plasma, the
borosilicate colloidal dispersion crosslinks 30 lbm/1,000 gal US
guar. In comparison to conventional aqueous borate counterpart, it
takes less boron to achieve the same level of overall viscosity,
indicating a more effective crosslinking. Also, it does not require
as high pH for crosslinking
Example 2
[0064] The sample was prepared by adding 3.8 mL borosilicate
colloidal dispersion into 100 mL fully hydrated (Di-water) guar
linear gel, under constant mixing in a conventional glass blender
cup. The vortex was closed within about a minute, which signaled
the transformation from a linear polymer gel to a crosslinked
polymer gel. The pH of the crosslinked polymer gel was then
determined to be 9.7. Then, about a 30 ml volume sample was
transferred to a Couette cup, and assembled onto a M7500 Ultra HTHP
rheometer (GRACE Instrument Company, Houston, Tex.). The viscosity
was measured at a constant shear rate of 100/s. A viscosity loss is
observed when the static pressure ramps up from ambient to 20,000
psia, but is subsequently regained as a result of the pressure
removal. Again, this is a typical pressure effect for boron
crosslinked polymers. But for the borosilicate colloidal
crosslinker, the extent of such an adverse effect is significantly
reduced compared to the aqueous borate counterpart. FIG. 2 shows
the rheological profile of 12.4 ppm boron in borosilicate colloidal
dispersions crosslinking 30 lbm/1,000 galUS guar at 120.degree.
F.
[0065] The foregoing disclosure and description is illustrative and
explanatory thereof and it can be readily appreciated by those
skilled in the art that various changes in the size, shape and
materials, as well as in the details of the illustrated
construction or combinations of the elements described herein can
be made without departing from the spirit of the disclosure.
[0066] While the embodiments have been illustrated and described in
detail in the drawings and foregoing description, the same is to be
considered as illustrative and not restrictive in character, it
being understood that only some embodiments have been shown and
described and that all changes and modifications that come within
the spirit of the applications are desired to be protected. It
should be understood that while the use of words such as
preferable, preferably, preferred, more preferred or exemplary
utilized in the description above indicate that the feature so
described may be more desirable or characteristic, nonetheless may
not be necessary and embodiments lacking the same may be
contemplated as within the scope of the application, the scope
being defined by the claims that follow. In reading the claims, it
is intended that when words such as "a," "an," "at least one," or
"at least one portion" are used there is no intention to limit the
claim to only one item unless specifically stated to the contrary
in the claim. When the language "at least a portion" and/or "a
portion" is used the item can include a portion and/or the entire
item unless specifically stated to the contrary.
[0067] 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 this application. 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, paragraph 6 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.
* * * * *