Note: Descriptions are shown in the official language in which they were submitted.
CA 02849248 2016-02-12
METHOD OF FRACTURING WITH PHENOTHIAZINE STABILIZER
BACKGROUND OF THE INVENTION
Field of the Invention
[0001] The invention relates to methods and compositions for treating high
temperature
subterranean formations. More particularly, it relates to methods and
compositions for
treating a subterranean formation penetrated by a wellbore into which a high
temperature
energized or foamed well treatment fluid is injected at temperatures of up to
about 500 F
(260 C).
Description of the Related Art
[0002] The continued exploration for hydrocarbon-containing subterranean
formations is
frequently requiring operators to drill significantly deeper than prior
drilling operations.
Besides drilling deeper, operators are always tryimz, to enhance hydrocarbon
production. One
way of enhancing hydrocarbon production from many formations is by hydraulic
fracturing.
In the hydraulic fracturing process, a viscous well treatment fluid is
injected into the wellbore
at such a rate and pressure so that a crack or fracture is opened into the
surrounding
formation.
[0003] Typically, well treatment fluids for hydraulic fracturing contain guar
gum or guar
gum derivatives or viscoelastic surfactants as thickeners to assist in
proppant transport,
friction reduction, fluid loss control, and controlling fracture geometry. The
hydraulic
fracturing fluids generally transport proppant into the fracture to prevent
the fracture from
fully closing. Besides being able to place the proppant in the fracture, the
fluid must be able
to degrade by lowering its viscosity so that a low viscosity fluid results
that can be easily
cleaned out of the fracture just prior to hydrocarbon production.
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
2
[0004] When treating a subterranean formation which is sensitive to water, it
is often
necessary to minimize the amount of water in the well treatment fluid. In such
instances, it is
typically preferred to mix a foaming agent with the treatment fluid. This
allows for a
reduction in the amount of water introduced into the formation without loss of
treatment fluid
volume. Recovery of fluids is thereby enhanced. Suitable foaming agents
include foaming
gases such as nitrogen and carbon dioxide. In some cases, a mixture of such
gases may be
used. A mixture of two of such gases is referred to as a binary composition.
[0005] Typically, the word "energized" refers to a fluid containing two phases
whereby less
than 53 volume percent of the internal phase is either a gas or a liquid (e.g.
nitrogen or liquid
CO2). Typically, the term "foamed" refers to a fluid wherein greater than 53
volume percent
of the internal phase of the fluid is either a gas or a liquid. Energized or
foamed fluids are
particularly applicable to under-pressured gas reservoirs and wells which arc
rich in
swellable and migrating clays.
[0006] As the drilling depths continue to increase, the formation temperatures
also increase.
Unfortunately, as temperatures exceed 325 F (162.8 C), many guar-based
fracturing fluids
(including foamed or energized guar-based fracturing fluids) become
ineffective because they
lose their viscosity in part or in whole. Many guar-based fracturing fluids
degrade at rates
preventing optimum proppant placement, fluid loss control, or fracture
geometry.
[0007] At high temperatures, guar-based polymers readily undergo auto-
degradation by a
number of methods, usually within periods of time shorter than what is
necessary to complete
the fracturing treatment. The degradation generally gets worse as the
temperatures continue
to increase. Increasing temperatures exasperates this behavior. Most
degradation results in
the cleavage of the polymer chains, which simultaneously reduces the fluid's
viscosity. This
can be due to oxidation from residual amounts of air entrained in the fluid,
thermal induced
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
3
cleavage of the acetal linkage along the polymer backbone, hydrolysis of the
polymer, or a
combination thereof.
[0008] A need exists for fracturing fluids that can be used in deeper and
hotter formations
that are in operation while simultaneously being able to degrade in a
controlled manner when
the fracturing process is complete. A need also exists for energized or foamed
fracturing
fluids for use in the treatment of deeper and hotter though water sensitive
formations. It is
further desirable that such fracturing fluids be stable in order to enable the
fracturing fluids to
travel further distances within the fractures.
SUMMARY OF THE INVENTION
[0009] In view of the foregoing, a high temperature well treatment fluid that
is capable of
fracturing a subterranean formation in temperatures of up to about 500 F (260
C) is
provided as an embodiment of the present invention. The high temperature well
treatment
fluid includes water, a high molecular weight synthetic copolymer and a
crosslinking agent.
The high temperature well treatment fluid may further contain a pH buffer.
[0010] In an aspect, the high molecular weight synthetic copolymer is derived
from
acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate. In an
aspect, the
copolymer comprises about 30 ¨ about 80 wt. % acrylamide, about 20 ¨ about 50
wt. %
acrylamidomethylpropanesulfonic acid, and about 1 ¨ about 5 wt. % vinyl
phosphonate. The
pH buffer enables the high temperature well treatment fluid to maintain a pH
in a range of
about 4.5 to about 5.25.
[0011] A high temperature foamed or energized well treatment fluid is also
capable of
fracturing a subterranean formation in temperatures of up to about 500 F (260
C) is
provided as an embodiment of the present invention. The high temperature
foamed or
4
energized well treatment fluid includes water, a high molecular weight
synthetic copolymer, a
crosslinking agent and, optionally, a pH buffer and a foaming agent such as a
foaming gas
like nitrogen and carbon dioxide and, optionally, a non-gaseous foaming agent.
The pH of the
high temperature well treatment fluid may be between from about 4.0 and about
6.0 and the
pH buffer enables the high temperature well treatment fluid to maintain the pH
range.
[0012] In an aspect, the foamed or energized fluid contains a high molecular
weight synthetic
copolymer derived from acrylamide, aerylamidomethylpropanesulfonic acid, and
vinyl
phosphonate. In an aspect, the copolymer comprises about 30 - about 80 wt. %
acrylamide,
about 20 - about 50 wt. % acrylarnidomethylpropanesulfonic acid, and about 1 -
about 5 wt.
% vinyl phosphonate.
[0013] Accordingly, in one aspect there is provided a method of fracturing a
subterranean
formation having a temperature of from about 300 F (149 C) to about 500 F
(260 C), the
method comprising contacting a high temperature well treatment fluid
comprising water; a
high molecular weight copolymer derived from
acrylamide,
acrylamidomethylpropanesulfonie acid, and vinyl phosphonate; a crosslinking
agent; a
stabilizer comprising phenothiazine or a combination of sodium thiosulfate and
phenothiazine; and a foaming agent, with at least a portion of the
subterranean formation at
pressures sufficient to fracture the subterranean formation.
[0014] According to another aspect there is provided a method of fracturing a
subterranean
formation having a temperature of from about 300 F (149 C) to about 500 F
(260 C), the
method comprising contacting at least a portion of the subterranean formation
with a
crosslinked foamed or energized well treatment fluid at a pressure sufficient
to create or
enlarge a fracture, the crosslinked foamed or energized well treatment fluid
being derived
from water; a high molecular weight copolymer derived from acrylamide,
acrylamiclomethylpropanesulfonic acid, and vinyl phosphonate; a crosslinking
agent; a
CA 2849248 2017-08-17
5
stabilizer comprising phenothiazine or a combination of sodium thiosulfate and
phenothiazine; and a foaming agent and further wherein the amount of foaming
agent in the
foamed or energized fluid provides between from 5 to 53 percent by volume
internal gas for
energized fluids or between from about 53 to 96 percent by volume internal gas
for foamed
fluids.
[0015] According to another aspect there is provided a method of fracturing a
subterranean
formation having a temperature of from about 300 F (149 C) to about 500 F
(260 C), the
method comprising (a) providing a foamed or energized well treatment fluid
comprising
water, a high molecular weight copolymer derived from acrylamidc,
acrylamidomethylpropanesulfonic acid, and vinyl phosphonate, a crosslinking
agent, a
stabilizer comprising phenothiazine or a combination of sodium thiosulfate and
phenothiazine, and a pH buffer for maintaining a pH of the fluid in a range of
about 4.0 to
about 6.0; and, (b) contacting at least a portion of the subterranean
formation with the foamed
or energized well treatment fluid at pressures sufficient to create or enlarge
fractures in the
formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] FIG. I is a graph of the apparent viscosity of the high temperature
well treatment fluid
with and without a breaker versus time at various temperatures in accordance
with
embodiments of the present invention;
[0017] FIG. 2 is a graph of the apparent viscosity of the high temperature
well treatment fluid
with and without a breaker versus time at 350 F (176.7 C) in accordance with
embodiments
of the present invention;
[0018] FIG. 3 is a graph of the apparent viscosity of the high temperature
well treatment fluid
with various amounts of copolymer and temperatures in accordance with
embodiments of the
present invention;
CA 2849248 2017-08-17
CA 02849248 2016-02-12
6
[0019] FIG. 4 is a graph of the apparent viscosity of the high temperature
well treatment
fluid with 63 volume percent nitrogen in accordance with embodiments of the
present
invention; and
[0020] FIG. 5 is a graph of the apparent viscosity of a high temperature well
treatment fluid
energized with 30 volume percent carbon dioxide in accordance with embodiments
of the
present invention.
[0021] While the invention is susceptible to various modifications and
alternative forms,
specific embodiments have been shown by way of' example in the drawings and
will be
described in detail herein. However, it should be understood that the
invention is not
intended to be limited to the particular forms disclosed. The scope of the
claims should
not be limited by the preferred embodiments and examples, but should be given
the
broadest interpretation consistent with the description as a whole,
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
[0022] Illustrative embodiments of the invention are described below as they
might be
employed in the hydrocarbon recovery operation and in the treatment of well
bores. In the
interest of clarity, not all features of an actual implementation arc
described in this
specification. It will of course be appreciated that in the development of any
such actual
embodiment, numerous implementation-specific decisions must be made to achieve
the
developers' specific goals, 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. Further aspects and advantages of the various
embodiments of
the invention will become apparent from consideration of the following
description.
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
7
[0023] A high temperature well treatment fluid that is capable of fracturing a
subterranean
formation in temperatures of up to about 500 F (260 C) is provided as an
embodiment of
the present invention. In this embodiment, the high temperature well treatment
fluid
comprises water, a high molecular weight synthetic copolymer, a crosslinking
agent, and
optionally a pH buffer.
[0024] In another embodiment, the high temperature well treatment fluid may be
foamed or
energized with a foaming agent, such as a foaming gas and, optionally, a non-
gaseous
foaming agent. The resulting fluid contains two phases ¨ a liquid phase and a
gaseous phase.
When the gaseous internal phase is less than about 53 volume percent, the
fluid is referred to
as an "energized fluid". When the gaseous internal phase is greater than 53
volume percent,
the fluid is referred to as a "foamed fluid".
[0025] The high molecular weight synthetic copolymer is derived from
acrylamidc,
acrylamidomethylpropanesulfonic acid, and vinyl phosphonate. In an aspect, the
acrylamide
can be derived from at least one amide of an ethylenically unsaturated
carboxylic acid. In an
aspect, the high molecular weight synthetic copolymer has a K-value of greater
than about
375. In an aspect, the K-value ranges between about 50 to about 750; or
alternatively,
between about 150 to about 350. The K-value (i.e. Fikentscher's K-value) is a
measure of a
polymer's average molecular weight. The test method generally used by those
skilled in the
art to calculate the K-value is determined by ISO 1628-2 (DIN 53726). In
embodiments of
the present invention, the high temperature well treatment fluid comprises
about 25 wt. % of
the high molecular weight copolymer in an emulsion. The high molecular weight
copolymer
in emulsion can be present in a range of about 10 gallons per 1,000 gallons
high temperature
well treatment fluid at temperatures of less than 350 F (176.7 C) to about
25 gallons per
1,000 gallons high temperature well treatment fluid at 500 F (260 C). The
concentration of
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
8
the high molecular weight synthetic copolymer depends upon the temperature of
the
subterranean formation and the duration in which the high molecular weight
synthetic
copolymer will be exposed to the elevated temperatures. In general, more high
molecular
weight synthetic copolymer is required at higher temperatures than at the
lower temperatures.
[0026] In an aspect, the copolymer is derived from about 20 ¨ about 90 wt. %
acrylamide,
about 9 ¨ about 80 wt. % acrylamidomethylpropanesulfonic acid, and about 0.1 ¨
about 20
wt. % vinyl phosphonate; alternatively, about 30 ¨ about 80 wt. % acrylamide,
about 25 ¨
about 60 wt. % acrylamidomethylpropanesulfonic acid, and about 0.2 ¨ about 10
wt. % vinyl
phosphonate; alternatively, about 40 ¨ about 70 wt. % acrylamide, about 30 ¨
about 40 wt. %
acrylamidomethylpropanesulfonic acid, and about 1 ¨ about 3 wt. % vinyl
phosphonate; or
alternatively, about 50 wt. % acrylamide, about 30 wt. %
acrylamidomethylpropanesulfonic
acid, about 2 wt. % vinyl phosphonate, and a remainder of copolymers of
acrylamide and
acrylamidomethylpropanesulfonic acid.
[0027] The high temperature well treatment fluid may further be foamed or
energized with a
suitable gas or liquid or emulsified with a suitable liquid. Foamed and
energized fluids
reduce the density by reducing the amount of water without loss of treatment
fluid volume
and increase the viscosity of the well treatment fluid. Their use is
especially desirable when
treating a subterranean formation which is sensitive to water (such as under-
pressured gas
reservoirs like dry coal beds and wells which are which are rich in swellable
and migrating
clays)) where it is desired to minimize the amount of water in the fluid.
While nitrogen and
liquid CO2 are more common for use as the suitable foaming agent for foamed
and energized
fluids, any other gas or fluid, such as inert gases, like argon, or natural
gas, known in the art
may be utilized. In an aspect, the foaming agent is present in a quantity to
provide, 53
volume percent to in excess of 96 volume percent internal gas for foamed
fluids and from 5
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
9
to 53 volume percent of internal gas for energized fluids. In a preferred
embodiment, the
amount of foaming agent in the treatment fluid is such to provide an energized
fluid between
from about 20% to 50% by volume of internal gas or a foamed fluid having from
about 63 to
about 94% by volume of internal gas.
[0028] In some instances, it may be desirable to add a non-gaseous foaming
agent to the
treatment fluid. When used, such non-gaseous foaming agents are typically used
in
conjunction with a foaming gas. Non-gaseous foaming agents often contribute to
the stability
of the resulting fluid and reduce the requisite amount of water in the fluid.
In addition, such
agents typically increase the viscosity of the fluid. For instance, when the
amount of internal
gas in the treatment fluid exceeds 30% by volume, a non-gaseous foaming agent
may further
be added to the fluid in order to create a foamed fluid. The addition of a non-
gaseous
foaming agent typically increases the viscosity of the treatment fluid. In
addition to
increasing viscosity, the non-gaseous foaming agent further contributes to the
stability of the
resulting fluid. Non-gaseous foaming agents may be amphoteric, cationic or
anionic and may
include surfactants based on betaines, alpha olefin sulfonates, sulfate
ethers, ethoxylated
sulfate ethers and ethoxylates.
[0029] Suitable anionic non-gaseous foaming agents include alkyl ether
sulfates, ethoxylated
ether sulfates, phosphate esters, alkyl ether phosphates, ethoxylated alcohol
phosphate esters,
alkyl sulfates and alpha olefin sulfonates. Preferred as alpha-olefin
sulfonates are salts of a
monovalent cation such as an alkali metal ion like sodium, lithium or
potassium, an
ammonium ion or an alkyl-substituent or hydroxyalkyl substitute ammonium in
which the
alkyl substituents may contain from I to 3 carbon atoms in each substituent.
The alpha-olefin
moiety typically has from 12 to 16 carbon atoms.
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
[0030] Preferred alkyl ether sulfates are also salts of the monovalent cations
referenced
above. The alkyl ether sulfate may be an alkylpolyether sulfate and contains
from 8 to 16
carbon atoms in the alkyl ether moiety. Preferred as anionic surfactants are
sodium lauryl
ether sulfate (2-3 moles ethylene oxide), C8-C10 ammonium ether sulfate (2-3
moles ethylene
oxide) and a C14-C16 sodium alpha-olefin sulfonate and mixtures thereof.
Especially
preferred are ammonium ether sulfates.
[0031] Suitable cationic non-gaseous foaming agents include alkyl quaternary
ammonium
salts, alkyl benzyl quaternary ammonium salts and alkyl amido amine quaternary
ammonium
salts.
[0032] Preferred as non-gaseous foaming agent are alkyl ether sulfates,
alkoxylated ether
sulfates, phosphate esters, alkyl ether phosphates, alkoxylated alcohol
phosphate esters, alkyl
sulfates and alpha olefin sulfonates.
[0033] Typically, the amount of foaming agent in the well treatment fluid is
that amount
sufficient to provide a foam quality between from about 30 to about 98,
preferably 90 percent
or higher. The foam quality is a measurement of the lowest amount of liquid
volume of well
treatment fluid that is required to effectuate the desired result. Thus, a 90
percent quality
foam refers to the use of 100 ml of foamed well treatment fluid which, upon
destabilization,
rendered 10 ml of liquid well treatment fluid.
[0034] The pH buffer of the present invention helps maintain a low pH of the
high
temperature well treatment fluid in a range of about 4.0 to about 6Ø The pH
buffer may
comprise acetic acid and sodium acetate or a combination of acetic acid,
sodium acetate, or
formic acid.
[0035] In an aspect, the amount of pH buffer that is needed is the amount that
will effectively
maintain a pH of the high temperature well treatment fluid in a range of about
4.5 to about
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
11
5.25; or alternatively, in a range of about 4.75 to about 5; or alternatively,
about 5. In an
aspect, the pH buffer is a true pH buffer, as opposed to a pH adjuster, as
will be understood
by those of skill in the art. The low pH of the systems and methods described
herein aid in
clean up of the fluid after well treatment processes.
[0036] In an aspect where the high temperature well treatment fluid is foamed
or energized,
the amount of pH buffer that is needed is the amount that will effectively
maintain a pH of
the high temperature well treatment fluid in a range of about 5.3 to about
5.75 when the
foaming gas is nitrogen and from about 4.1 to about 4.5 when the foaming gas
is carbon
dioxide.
[0037] At temperatures above 400 F (204.4 C), a pH buffer comprising acetic
acid and
sodium acetate having a pH of about 5 at 25% can be used. At temperatures
below 400 F
(204.4 C), other pH buffers can be used, such as acetic acid and formic acid
buffers.
Generally, any pH buffer capable of maintaining a pH of the high temperature
well treatment
fluid within in a range of about 4.5 to about 5.25 and without interfering
with the remaining
components of the high temperature well treatment fluids can be used. Other
suitable pH
buffers will be apparent to those of skill in the art and are to be considered
within the scope
of the present invention.
[0038] The pH buffer comprising acetic acid and sodium acetate having a pH of
about 5 can
be used in a concentration ranging from about 1 gallon per 1,000 gallons high
temperature
well treatment fluid to about 3 gallons per 1,000 gallons high temperature
well treatment
fluid, depending upon the temperature of the subterranean formation.
[0039] The high molecular weight synthetic copolymer can be further
copolymerized with
other monomers to provide various advantages related to the stability of the
high temperature
well treatment fluid. Similar to guar-based high temperature well treatment
fluids, the
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
12
viscosity of the high temperature well treatment fluid of the present
invention can be
significantly enhanced when first copolymerized with small amounts of monomers
and
crosslinked, at the wellsite, with transition metals, such as iron, titanium,
zirconium,
chromium, hafnium, aluminum, and combinations thereof. Suitable monomers that
can be
copolymerized with the high molecular weight synthetic polymer include
monomers selected
from the group consisting of an alkali metal of
acrylamidomethylpropanesulfonic acid, an
ammonium salt of acrylamidomethylpropanesulfonic acid, styrene sulfonate,
vinyl sulfonate,
N-vinylpyrolidone, N-vinylformamide, N-
vinylacetamide, N,N-diallylacetamide,
methacrylamide, acrylamide, N,N-dimethylacrylamide, methacrylamide, a divalent
cation
from calcium salt, a divalent cation from magnesium salt, and combinations
thereof. For
example, alkali metal or ammonium salts of acrylamidomethylpropanesulfonic
acid (AMPS),
styrene sulfonate or vinyl sulfonate can be copolymerized to add salt
tolerance to the high
molecular weight synthetic polymer. Divalent cations from calcium salt and
magnesium salt
are also useful for adding salt tolerance to the high molecular weight
synthetic polymer. As
another example, monomers such as N-vinylamides, N-vinylpyrolidone, N-
vinylformamide,
N-vinylacetamide, and N-diallylacetamide can also be copolymerized with the
high
molecular weight synthetic polymer to assist in proppant transport by
adsorbing onto the
proppant surface. The copolymers of the high molecular weight synthetic
copolymer can be
made by any polymerization method necessary to produce high molecular weight
copolymers. A particularly effective method of producing the copolymers is by
invert
polymer emulsion because it can be easily metered into a flowing stream of
water during
fracturing processes and it can be made to rapidly hydrate, which may reduce
the amount of
equipment needed at the wellsite.
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
13
[0040] The high temperature well treatment fluid of the present invention can
also include a
stabilizer to help the high temperature well treatment fluids perform for
extended periods of
time. One manner in which stabilizers assist in extending run times of high
temperature well
treatment fluids is by maintaining the viscosity of the high temperature well
treatment fluid
for longer periods of time than the high temperature well treatment fluid
would be capable of
doing without the stabilizer. In an aspect, the stabilizer is sodium
thiosulfate, phenothiazine,
or combinations thereof. The use of phenothiazine as a stabilizer is described
in co-pending
U.S. Patent Application Serial No. 12/020,755, filed on January 28, 2008.
Another suitable
stabilizer is a gel stabilizer that is commercially available as GS-1L that
contains sodium
thiosulfate from Baker Hughes Incorporated.
[0041] In general, any stabilizer compound capable of maintaining viscosity of
the high
temperature well treatment fluid long enough to perform the fracturing process
can be used.
The amount of stabilizer that can be used includes an effective amount that is
capable of
maintaining viscosity, i.e. preventing thermal degradation, of the high
temperature well
treatment fluid long enough to perform the fracturing process.
[0042] In an aspect, the high temperature well treatment fluid of the present
invention can
also include a crosslinking agent. A suitable crosslinking agent can be any
compound that
increases the viscosity of the high temperature well treatment fluid by
chemical crosslinking,
physical crosslinking, or any other mechanisms. For example, the gellation of
the high
molecular weight synthetic copolymer can be achieved by crosslinking the high
molecular
weight synthetic copolymer with metal ions including boron, zirconium, and
titanium
containing compounds, or mixtures thereof. One class of suitable crosslinking
agents is
zirconium-based crosslinking agents. Suitable crosslinking agents can include
zirconium
oxychloride, zirconium acetate, zirconium lactate, zirconium malate, zirconium
glycolate,
CA 02849248 2016-02-12
14
zirconium lactate triethanolamine, zirconium citrate, titanium lactate,
titanium malate,
titanium citrate, titanium, aluminum, iron, antimony, a zirconate-based
compound, zirconium
tricthanolaminc, an organozirconate, or combinations thereof. XLW-14 is a
particularly
suitable zirconate-based crosslinking agent that is commercially available
from Baker
Hughes Incorporated and described in U.S. Patent No. 4,534,870.
[0043] The amount of the crosslinking agent needed in the high temperature
well treatment
fluid depends upon the well conditions and the type of treatment to be
effected, but is
generally in the range of from about 10 ppm to about 1000 ppm of metal ion of
the
crosslinking agent in the high molecular weight synthetic polymer fluid. In an
aspect, the
amount of crosslinking agent that can be used includes an effective amount
that is capable of
increasing the viscosity of the high temperature well treatment fluid to
enable it to perform
adequately in fracturing processes. In some applications, the aqueous polymer
solution is
crosslinked immediately upon addition of the crosslinking agent to form a
highly viscous gel.
In other applications, the reaction of the crosslinking agent can be retarded
so that viscous gel
formation does not occur until the desired time.
[0044] When zirconium is used as a crosslinking agent, zirconium has a built-
in delay and is
used from 1 gallon per 1,000 gallons to 2 gallons per 1,000 gallons depending
on the
temperature and high molecular weight synthetic polymer concentration in the
high
temperature well treatment fluid. If extra stability time is required, an
additional stabilizer,
such as sodium thiosulfate (e.g.. GS-1L from BJ Services), can be used in a
ranee of about 1
gallon per 1,000 gallons high temperature well treatment fluid to about 3
gallons per 1,000
gallons high temperature well treatment fluid.
CA 02849248 2016-02-12
[00451 The high temperature well treatment fluid of the present invention can
also include a
surfactant to aid in well treatment processes. Surfactants typically aid in
the hydration of the
high molecular weight synthetic polymer. Without the surfactant, the high
temperature well
treatment fluids of the present invention can take up to about 20 to 30
minutes to adequately
hydrate. With the addition of the surfactant, the hydration time is
substantially reduced.
With the surfactant, the hydration can take less than 5 minutes. 90 ¨ 95 % of
the high
temperature well treatment fluid of the present invention can be hydrated in
about 1 to 2
minutes with a suitable surfactant. The type and concentration of the
surfactant can control
the hydration time of the high temperature well treatment fluid. Any suitable
surfactant can
be used, as will be apparent to those of skill in the art. In an aspect, a
nonionic surfactant
such as an ethoxylated alcohol can be used. A suitable surfactant that can be
used in the
present invention is a proprietary blend of two different surfactants
commercially available
from Rhodia. The Rhodia blend contains 50 wt. % RhodasurfTM BC 720, which is
an
alkoxypoly(ethyleneoxy)ethanol surfactant, and an ethoxylated long chain
alcohol having
between 10 and 18 carbon molecules. In an aspect, the surfactant comprises
alkoxypoly(ethyleneoxy)ethanol, an ethoxylated alcohol having from 10 to 18
carbon
molecules, and combinations thereof. Effective types and amounts of suitable
surfactants
will be apparent to those of skill in the art and arc to be considered within
the scope of the
present invention.
[0046] In an aspect of the present invention, the high temperature well
treatment fluid also
includes a breaker that is capable of degrading the high temperature well
treatment fluid in a
controlled manner to assist operators in clean up and removal of the high
temperature well
treatment fluid when the well treatment process is complete. For example, the
breakers can
assist in clean-up efforts after fracturing treatments. Viscometer tests have
shown that most
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
16
breakers that contain oxidizing agents are useful in the degradation of the
fluid. Suitable
oxidizing agents can include sodium bromate, ammonium persulfate, sodium
persulfate,
sodium perborate, sodium percarbonate, calcium peroxide, magnesium peroxide
and sodium
periodate. Controlled degradation can be recognized because it results in a
simultaneous and
controlled reduction in fluid viscosity. Testing suggests that the stability
of the high
temperature well treatment fluid of the present invention, even with the
intentional addition
of the breakers that contain oxidizing agents, greatly exceeds that obtained
by guar-based
well treatment fluids, allowing optimized treatments to be employed at well
temperatures
ranging from 250 F(121.1 C) to 500 F (260 C).
[0047] In an aspect, the breaker comprises sodium bromate, either as is or
encapsulated.
Sodium bromate has been shown to easily degrade the high temperature well
treatment fluid
in a controlled manner. In an aspect, the breaker comprises sodium bromate,
ammonium
persulate, sodium persulfate, sodium perborate, sodium percarbonate, calcium
peroxide,
magnesium peroxide, sodium periodate, an alkaline earth metal percarbonate, an
alkaline
earth metal perborate, an alkaline earth metal peroxide, an alkaline earth
metal perphosphate,
a zinc peroxide, a zinc perphosphate, a zinc perborate, a zinc percarbonate, a
boron
compound, a perborate, a peroxide, a perphosphate, or combinations thereof.
the breaker
comprising sodium bromate, ammonium persulate, sodium persulfate, sodium
perborate,
sodium percarbonate, calcium peroxide, magnesium peroxide, sodium periodate,
or
combinations thereof Other types and amounts of suitable breakers that can be
used in the
present invention will be apparent to those of skill in the art are to be
considered within the
scope of the present invention.
[0048] When sodium bromate is used to break the high temperature well
treatment fluid of
the present invention, the concentration of the sodium bromate can be from
about 0.5 ppt
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
17
high temperature well treatment fluid to 20 ppt high temperature well
treatment fluid. The
concentration will depend on if the sodium bromate is run as a solid, a
solution, or
encapsulated, such as High Perm BRTm Gel Breaker from Baker Hughes
Incorporated.
[0049] The pH buffers, stabilizers, crosslinking agents, breakers, monomers,
and other
additives described herein can be used in the method embodiments as well as
the
compositional embodiments of the present invention. Other suitable compounds
for high
temperature well treatment fluids, such as proppant and other additives, will
be apparent to
those of skill in the art and are to be considered within the scope of the
present invention.
[0050] Besides the compositions of the high temperature well treatment fluid,
methods of
fracturing a subterranean formation having a temperature of up to about 500 F
(260 C) are
provided as embodiments of the present invention. In one embodiment, a high
temperature
well treatment fluid is contacted with at least a portion of the subterranean
formation at
pressures sufficient to fracture the subterranean formation. In an aspect, the
high temperature
well treatment fluid includes water; a high molecular weight polymer
comprising acrylamide,
acrylamidomethylpropanesulfonic acid, and vinyl phosphonate; a crosslinking
agent; and a
pH buffer that maintains a pH of the high temperature well treatment fluid in
a range of about
4.5 to about 5.25.
[0051] Another method of fracturing a subterranean formation is provided as
another
embodiment of the present invention. In this embodiment, water is contacted
with a high
molecular weight copolymer derived from acrylamide,
acrylamidomethylpropanesulfonic
acid, and vinyl phosphonate to form a water-soluble polymer that is then
contacted with a
crosslinking agent and a pH buffer to produce a gelling fluid. The gelling
fluid is then
contacted with at least a portion of the subterranean formation at pressures
sufficient to
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
18
fracture the formation. As with other embodiments of the present invention,
the pH buffer
maintains a pH of the gelling fluid in a range of about 4.5 to about of about
5.25.
[0052] Another method of fracturing a subterranean formation is provided as
another
embodiment of the present invention. In this embodiment, water is contacted
with a high
molecular weight copolymer derived from acryl am i de, acryl am i dom ethyl
propan esul foni c
acid, and vinyl phosphonate to form a water-soluble polymer. The water-soluble
polymer is
contacted with a crosslinking agent and a foaming agent to produce a foamed or
energized
fluid. At least a portion of the subterranean formation is contacted with the
foamed or
energized fluid at pressures sufficient to fracture the formation. The foamed
or energized
fluid may further contain a pH buffer, preferably to maintain the pH of the
foamed or
energized fluid in a range of about 4.0 to about 6Ø
[0053] The compositions and methods described herein perform well when
compared with
traditional guar-based well treatment fluids. Well treatment fluids require
sufficient viscosity
that lasts long enough for the well treatment fluid to complete the well
treatment process,
such as fracturing. The compositions and methods describe herein are
stabilized for much
longer than most prior art well treatment fluids at elevated temperatures. For
example, the
high temperature well treatment fluid of the present invention can be pumped
at a
temperature of up to about 500 F (260 C) for a period of up to about 2
hours. The high
temperature well treatment fluid can be pumped at a temperature of up to about
425 F (218.3
C) for a period of up to about 4 hours. The high temperature well treatment
fluid can be
pumped at a temperature of up to about 400 F (204.4 C) for a period of up to
about 6 hours.
[0054] The methods and compositions of the present invention do not require
any new or
additional equipment. Traditional well treatment fluid equipment can be used
without any
modification. The methods and compositions of the present invention can be
used in
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
19
subterranean formations having higher temperatures than many prior art well
treatment fluids
are capable of functioning properly.
EXAMPLES
Example 1
[0055] Samples of the high temperature well treatment fluid of the present
invention were
prepared by mixing 40 pounds of copolymer derived from acrylamide and
acrylamidomethylpropanesulfonic acid in one thousand gallons (ppt) tap water
and allowed
to hydrate for 30 minutes. A suitable copolymer that was used in this example
is
commercially available as Allessan0 AG 5028P from Allessa Chemie. The order of
addition
of the additives is as it appears in FIG. 1. As shown in FIG. 1, the apparent
viscosity in
ccntipoises (cP) was measured and plotted for the high temperature well
treatment fluid at
temperatures ranging from 300 F (148.9 C) to 500 F (260 C) using a R1 B5
bob and cup
combination against time in minutes. FIG. 1 shows stability of the high
temperature well
treatment fluid of the present invention without the use of breakers. The pH
was controlled
using two different pH buffers. As indicated in FIG. 1, some of the samples
were added as a
dry powder to the fracturing fluid, while others were prepared in an emulsion.
A pH of 4.5
with acetic acid (BF-10L by Baker Hughes Incorporated) was used in the samples
up to 400
F (204.4 C). A pH of 4.76 with a true buffer of pH 4.5 (BF-18L by Baker
Hughes
Incorporated) was used in the samples that were greater than 400 F (204.4
C). 2.5 to 3.0
gpt of a zirconate-based crosslinking agent (XLW-14 by Baker Hughes
Incorporated) was
used in the samples. Two samples were made and measured at 400 F (204.4 C),
one of the
samples was prepared with 0.06 wt. % sodium thiosulfate gel stabilizer and the
other sample
was prepared without the stabilizer. As can be seen in FIG. 1, the sample at
400 F (204.4
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
C) with the stabilizer performed much better than the sample without the
stabilizer, i.e., it
maintained its viscosity for a longer period of time than the sample without
the stabilizer.
Example 2
[0056] Three samples of the high temperature well treatment fluid of the
present invention
were prepared by mixing 40 pounds of copolymer derived from acrylamide,
acrylamidomethylpropanesulfonic acid, and vinyl phosphonate in one thousand
gallons tap
water (Allessan0 AG 5028P from Allessa Chemie) and allowed to hydrate for 30
minutes.
The order of addition of the additives is as it appears in FIG. 2. As shown in
FIG. 2, the
apparent viscosity was measured and plotted for the high temperature well
treatment fluid at
350 F (176.7 C) using a R1B5 bob and cup combination against time in
minutes. The pH
was controlled using 1 gpt of acetic acid to pH 4.5 (e.g., BF-10L by Baker
Hughes
Incorporated). 2.5 gallons per 1,000 gallons high temperature well treatment
fluid (gpt) of a
zirconate-based crosslinking agent (e.g., XLW-14 by Baker Hughes Incorporated)
was used
in the samples. The first sample was made without the use of a breaker. The
second and
third samples were prepared with one and three ppt respectively of an
encapsulated sodium
bromatc labeled as High Perm Br in FIG. 2 (High Perm BRim Gel Breaker from
Baker
Hughes Incorporated). As can be seen in FIG. 2, the viscosity tapers off at a
consistent rate
with each of the samples that contain the sodium bromate breaker, which
indicates that the
high temperature well treatment fluid can be degraded in a controlled manner.
The viscosity
of the second sample with 1 ppt breaker decreased slower than the viscosity of
the third
sample having 3 ppt breaker.
Example 3
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
21
[0057] Three samples of the high temperature well treatment fluid of the
present invention
were prepared by mixing varying amounts of copolymer derived from acrylamide,
acrylamidomethylpropanesulfonic acid, and vinyl phosphonate with tap water
(Allessan0
AG 5028P with a built in stabilizer from Allessa Chemie) and allowed to
hydrate for 30
minutes. The components, order of addition, and conditions in this example are
as follows:
Component/Condition Sample 1 Sample 2 Sample 3
Copolymer (AG 5028P), ppt 25 40 50
Gel stabilizer (GS-1L), gpt 1 2 2
Buffer (BF-65L), gpt 1 1.5 2
Crosslinking agent (XLW-65), gpt 1.5 1.5 2
Temperature , F ( C) 350 (176.7) 400 (204.4) 450 (232.2)
The gel stabilizer GS-1L, buffer BF-65L, and crosslinking agent XLW-65 are all
commercially available from Baker Hughes Incorporated. As shown in FIG. 3, the
apparent
viscosity was measured and plotted for the high temperature well treatment
fluid at
temperatures ranging from 350 F (176.7 C) to 450 F (232.2 C) using a R1B5
bob and cup
combination against time in minutes. The pH was controlled using a true 5.0 pH
buffer (e.g.,
BF-65L by Baker Hughes Incorporated). As can be seen in FIG. 3, the viscosity
tapers off at
a consistent rate with each of the samples, which indicates that the high
temperature well
treatment fluid can be stable for an extended period of time and still be
degraded in a
controlled manner.
Example 4
[0058] Samples of a high temperature well treatment fluid were prepared by
mixing 15
gallons of GW-65L, a copolymer of Baker Hughes Incorporated derived from
acrylamide and
acrylamidomethylpropanesulfonic acid, in one thousand gallons (ppt) tap water
which further
contained about 140 ppm phenothiazine. The fluid was allowed to hydrate for 30
minutes
CA 02849248 2016-02-12
22
with the addition of about 1 gpt of PSA-65L, a product of Baker Hughes
Incorporated. The
pH was controlled using BF-65L buffer and XLW-65 was used as the crosslinker.
FAW-4
foamer, a product of Baker Hughes Incorporated, and nitrogen was introduced to
the fluid to
provide 63 vol. % nitrogen. The order of addition of the additives is as it
appears in FIG, 4.
The rheology of the fluid was then evaluated using a flow-loop rheometer which
was
equipped with a constant volume circulating pump and an independent air driven
pump. The
flow-loop was further fitted with a 10,000 psi site glass for observation. The
foamed fluid
was passed through the closed loop rheometer for 20 minutes. As shown in FIG.
4, the foam
is stable over an extended period of time.
Example 5
[0059] Samples of a high temperature well treatment fluid were prepared by
mixing 15
gallons of GW-65L, a copolymer of Baker Hughes Incorporated derived from
acrylamide and
acrylamidomethylpropanesulfonic acid, in one thousand gallons (ppt) tap water
which further
contained about 140 ppm phenothiazine. The fluid was allowed to hydrate for 30
minutes
with the addition of about 1 gpt of PSA-65L, a product of Baker Hughes
Incorporated. The
pH was controlled using BF-65L buffer and XLW-65 was used as the crosslinker
and
Claytreat-3CTM clay stabilizer, a product of Baker Hughes Incorporated. FAW-4
foamer, a
product of Baker Hughes Incorporated, and carbon dioxide were introduced to
the fluid to
provide 30 volume percent carbon dioxide. The order of addition of the
additives is as it
appears in FIG. 5. The foamed fluid was then passed through a closed loop
rheometer for
approximately 40 minutes. As shown in FIG. 5, fluid exhibited greater
viscosity than the
fluid of Example 4 and the fluid was stable over an extended period of time.
CA 02949248 2014-03-19
WO 2013/043243 PCT/US2012/043308
23
[0060] While the invention has been shown or described in only some of its
forms, it should
be apparent to those skilled in the art that it is not so limited, but is
susceptible to various
changes without departing from the scope of the invention. For example,
various types of
additives can be used in the high temperature well treatment fluid of the
present invention.
As another example, various types of equipment can be used for the well
treatment processes
described herein.
