U.S. patent application number 14/705426 was filed with the patent office on 2015-08-20 for alkaline persulfate for low-temperature breaking of multi-chain polymer viscosified fluid.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Achala V. Danait, Ian D. Robb, Lalit P. Salgaonkar.
Application Number | 20150232743 14/705426 |
Document ID | / |
Family ID | 46395711 |
Filed Date | 2015-08-20 |
United States Patent
Application |
20150232743 |
Kind Code |
A1 |
Salgaonkar; Lalit P. ; et
al. |
August 20, 2015 |
ALKALINE PERSULFATE FOR LOW-TEMPERATURE BREAKING OF MULTI-CHAIN
POLYMER VISCOSIFIED FLUID
Abstract
A persulfate compound activated by a strong base is used for
low-temperature breaking of fluids viscosified with a multi-chain
polysaccharide. The breaker system can be used in an oilfield or
pipeline application where a multi-chain polysaccharide may be used
in a fluid.
Inventors: |
Salgaonkar; Lalit P.; (Pune,
IN) ; Danait; Achala V.; (Pune, IN) ; Robb;
Ian D.; (Lawton, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
46395711 |
Appl. No.: |
14/705426 |
Filed: |
May 6, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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13166442 |
Jun 22, 2011 |
9062243 |
|
|
14705426 |
|
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Current U.S.
Class: |
166/278 ;
166/308.3; 507/213 |
Current CPC
Class: |
E21B 43/04 20130101;
C09K 8/685 20130101; C09K 2208/26 20130101; B08B 9/02 20130101;
C09K 8/905 20130101; C09K 8/68 20130101; E21B 43/26 20130101; E21B
43/267 20130101 |
International
Class: |
C09K 8/90 20060101
C09K008/90; E21B 43/267 20060101 E21B043/267; E21B 43/04 20060101
E21B043/04; E21B 43/26 20060101 E21B043/26 |
Claims
1. A method for breaking a fluid having an apparent viscosity
greater than 5 cP, wherein the fluid comprises a water-soluble
multi-chain polysaccharide in water, wherein the multi-chain
polysaccharide is selected from the group consisting of: a xanthan,
a diutan, and any derivative thereof, the method comprising the
step of contacting the fluid with: (i) one or more water-soluble
persulfates; and (ii) one or more strong bases; wherein the step of
contacting is at one or more temperatures less than 100.degree.
F.
2. The method according to claim 1, wherein the water is a
brine.
3. The method according to claim 1, wherein the step of contacting
does not dilute the fluid more than 10 percent by volume.
4. The method according to claim 1, wherein the fluid having an
apparent viscosity greater than 5 cP is selected from the group
consisting of: a flow-back fluid, an unused well fluid, a push
pill, a pipeline cleaning fluid, and any combination thereof.
5. The method according to claim 1, wherein the multi-chain
polysaccharide is in at least a sufficient concentration in the
water such that the fluid has a viscosity greater than 5 cP.
6. The method according to claim 1, wherein the multi-chain
polysaccharide is xanthan.
7. The method according to claim 1, wherein the one or more
persulfates are in a weight ratio of at least 0.5 to 1 of the
multi-chain polysaccharide in the water of the fluid.
8. The method according to claim 1, wherein the one or more strong
bases are in a mole ratio based on hydroxide of at least 0.5 to 1
of the one or more persulfates.
9. A method of treating a well, the method comprising the steps of:
(a) forming a treatment fluid comprising: (i) water; and (ii) one
or more multi-chain polysaccharides, wherein the multi-chain
polysaccharides are selected from the group consisting of: a
xanthan, a diutan, and any derivative thereof, wherein the
multi-chain polysaccharides are at least a sufficient concentration
in the water such that the treatment fluid has a viscosity of at
least 5 cP; (iii) one or more water-soluble persulfates; and (iv)
one or more strong bases; and (b) introducing the treatment fluid
into the well and directing the treatment fluid to a portion of the
well having a design temperature less than 100.degree. F.; wherein
the step of introducing the treatment fluid further comprises
introducing above the fracture pressure of the subterranean
formation.
10. The method according to claim 9, further comprising the steps
of: (a) after the step of introducing, allowing the treatment fluid
to break in the portion of the well; and then (b) flowing back from
the well.
11. The method according to claim 9, wherein the treatment fluid
further comprises proppant or gravel.
12. The method according to claim 9, wherein the step of
introducing the treatment fluid further comprises: gravel
packing.
13. The method according to claim 9, wherein the water is a
brine.
14. The method according to claim 9, wherein the treatment fluid is
selected from the group consisting of: a flow-back fluid, an unused
well fluid, a push pill, a pipeline cleaning fluid, and any
combination thereof.
15. The method according to claim 9, wherein the multi-chain
polysaccharide is xanthan.
16. The method according to claim 9, wherein the one or more
persulfates are in a weight ratio of at least 0.5 to 1 of the
multi-chain polysaccharide in the water of the treatment fluid.
17. The method according to claim 9, wherein the one or more strong
bases are in a mole ratio based on hydroxide of at least 0.5 to 1
of the one or more persulfates.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to and is a divisional
application of U.S. application Ser. No. 13/166,442 filed on Jun.
22, 2011 entitled "Alkaline Persulfate for Low-Temperature Breaking
of Multi-Chain Polymer Viscosified Fluid," the entire disclosure of
which is incorporated by reference.
BACKGROUND
[0002] 1. Technical Field
[0003] The present disclosure is in the field of producing crude
oil or natural gas and to pipeline transmission of oil or gas.
[0004] 2. Background Art
Water-Soluble Polymers Used in Treatment Fluids
[0005] Common water-soluble polymers used in well treatment fluids
include polysaccharides and synthetic polymers.
[0006] As used herein, a "polysaccharide" can broadly include a
modified or derivative polysaccharide. As used herein, "modified"
or "derivative" means a compound or substance formed by a chemical
process from a parent compound or substance, wherein the chemical
skeleton of the parent is retained in the derivative. Substitution
is an example of a modification or derivatization process.
Substitution on a polymeric material may be partial or
complete.
[0007] A polymer can be classified as being single chain or multi
chain, based on its solution structure in aqueous liquid media.
Examples of single-chain polysaccharides that are commonly used in
the oilfield industry include guar, guar derivatives, and cellulose
derivatives. Guar polymer, which is derived from the beans of a
guar plant, is referred to chemically as a galactomannan gum.
Examples of multi-chain polysaccharides include xanthan, diutan,
and scleroglucan, and derivatives of any of these. Without being
limited by any theory, it is currently believed that the
multi-chain polysaccharides have a solution structure similar to a
helix or are otherwise intertwined.
[0008] Xanthan gum (commonly referred to simply as xanthan) is a
polysaccharide, derived from the bacterial coat of Xanthomonas
campestris. It is produced by fermentation of glucose, sucrose, or
lactose by the Xanthomonas campestris bacterium. Diutan gum
(commonly referred to simply as diutan) is another multi-chain
polysaccharide that is sometimes used to increase viscosity in well
fluids.
[0009] An example of a water-soluble synthetic polymer that is
commonly used in wells is polyacrylamide or derivative of
polyacrylamide. Certain polyacrylamides or derivatives can be
classified as multi-chain polymers.
Potential Sources of Water for Use in Treatment Fluids
[0010] Non-freshwater sources of water for use in well treatment
fluids can include surface water ranging from brackish water to
seawater, brine, returned water (sometimes referred to as flowback
water) from the delivery of a well fluid into a well, unused well
fluid, and produced water. As used herein, a brine refers to a
water having at least 40,000 mg/L total dissolved solids.
[0011] Another potential source of water for use in well treatment
fluids can include push pills, that is, slugs of water that have
been viscosified with a multi-chain polysaccharide used to push
fluids to clean out an oil or gas transmission pipeline located at
or near the surface of the ground or seafloor.
[0012] In some cases, however, a flowback water can have an
undesirably high viscosity due to a residual viscosity-increasing
polymer, which may or may not be cross-linked, that was not
completely broken in the well before flowing back. Similarly, a
push pill can have an undesirably high viscosity for use in a well
treatment fluid. To use such a flowback water or push pill in
forming another well treatment fluid, it may be necessary to break
the residual viscosity.
Breaker for Polysaccharide or Crosslinked Polysaccharide
[0013] Reducing the viscosity of a viscosified fluid is referred to
as "breaking" the fluid. Chemicals used to reduce the viscosity of
fracturing fluids are called breakers. Other types of viscosified
well fluids also need to be broken for removal from the wellbore or
subterranean formation.
[0014] No particular mechanism is necessarily implied by the term
"breaking." For example, in the case of a crosslinked
viscosity-increasing agent, for example, one way to diminish the
viscosity is by breaking the crosslinks. By way of another example,
a breaker can reduce the molecular weight of a water-soluble
polymer by cutting the long polymer chain. As the length of the
polymer chain is cut, the viscosity of the fluid is reduced. This
process can occur independently of any crosslinking bonds existing
between polymer chains.
[0015] Breakers must be selected to meet the needs of each
situation. First, it is important to understand the general
performance criteria of breakers. For example, in reducing the
viscosity of a fracturing fluid or gravel packing fluid to a near
water-thin viscosity, the breaker must maintain a critical balance.
Premature reduction of viscosity during the pumping of the
treatment fluid can jeopardize the treatment. Inadequate reduction
of fluid viscosity after pumping can also reduce production if the
required conductivity is not obtained.
[0016] Chemical breakers used to reduce viscosity of a fluid
viscosified with a viscosifying polymer, such as guar and
derivatized guar polymers, used in fracturing or other subterranean
applications are generally grouped into three classes: oxidizers,
enzymes, and acids. All of these materials reduce the viscosity of
the fluid by breaking the polymer chain. The breakers operate by
cleaving the backbone of polymer either by hydrolysis of acetyl
group, cleavage of glycosidic bonds, oxidative/reductive cleavage,
free radical breakage or combination of these processes. A breaker
should be selected based on its performance in the temperature, pH,
time, and desired viscosity profile for each specific
treatment.
[0017] Fluids viscosified with a multi-chain polysaccharide can be
more difficult to break than fluids viscosified with a single-chain
polysaccharide. In particular, there are few methods available to
break the fluid viscosity of a fluid viscosified with a multi-chain
polysaccharide at low temperatures (below 120.degree. F. or
49.degree. C.), and they suffer from various problems. For example,
the use of hypochlorite poses corrosion concerns and may not
provide sufficient delay of the break. The current use of
persulfate requires high concentrations at lower temperatures. The
use of oxidizers such as sodium chlorite is limited to
high-temperature applications and may react violently to cause a
fire when reducing agents are used in the process. Enzymes do not
work well on multi-chain polysaccharides such as xanthan at low
temperatures.
[0018] Sodium perborate and ethyl acetoacetate ("EAA") have been
reported as being capable of breaking the viscosity of a fluid
viscosified with a typical xanthan gum ("XANVIS") down to
80.degree. F. (27.degree. C.). See Kelco Oilfield Group in its
Technical Bulletin entitled "Breaker Applications," revised January
2004. However, it has previously been reported that such
compositions were unable to break a fluid viscosified with xanthan
at very low temperature using the published recipe and the
publication does not provide sufficient detail to allow the user to
optimize the breaker recipe for a given set of conditions.
[0019] A treatment fluid for use in a well can optionally comprise
an activator or a retarder to, among other things, optimize the
break rate provided by a breaker. Previously known examples of such
activators include acid generating materials, chelated iron,
copper, cobalt, and reducing sugars. Previously known examples of
retarders include sodium thiosulfate, methanol, and
diethylenetriamine.
DETAILED DESCRIPTION OF EMBODIMENTS
General Definitions and Usages
[0020] As used herein, the words "comprise," "have," "include," and
all grammatical variations thereof are each intended to have an
open, non-limiting meaning that does not exclude additional
elements or steps.
[0021] As used herein, if not otherwise specifically stated, the
physical state (e.g., solid or fluid) of a substance (or mixture of
substances) and other physical properties are determined at a
temperature of 77.degree. F. (25.degree. C.) and a pressure of 1
atmosphere (Standard Laboratory Conditions) under no shear.
[0022] Most well fluids are non-Newtonian fluids. Accordingly, the
apparent viscosity of a fluid applies only under a particular set
of conditions including shear stress versus shear rate, which must
be specified or understood from the context. Unless otherwise
specified, as used herein the apparent viscosity of a fluid
(excluding any suspended solid particulate larger than silt) is
measured with a Fann Model 35 type viscometer at a shear rate of
511 1/s and at 77.degree. F. (25.degree. C.) and a pressure of 1
atmosphere. Apparent viscosity is reported in units of centipoise
(cP). For reference, the viscosity of pure water is 1 cP. In the
oilfield and as used herein, unless the context otherwise requires
it is understood that "viscosity" is actually a reference to
apparent viscosity.
[0023] As used herein, if not otherwise specifically stated, a
material is considered to be "soluble" in a liquid if at least 10
grains of the material can be dissolved in one liter of the liquid
when tested at 77.degree. F. and 1 atmosphere pressure for 2 hours
and considered to be "insoluble" if less soluble than this. As will
be appreciated by a person of skill in the art, the solubility in
water of a certain material may be dependent on the salinity, pH,
or other additives in the water. Accordingly, the salinity, pH,
additive selection of the water can be modified to facilitate the
solubility in aqueous solution.
[0024] Unless otherwise specified, any doubt regarding whether
units are in U.S. or Imperial units, where there is any difference
U.S. units are intended herein. For example, "gal/Mgal" means U.S.
gallons per thousand U.S. gallons.
[0025] As used herein, "first," "second," or "third" may be
arbitrarily assigned and are merely intended to differentiate
between two or more fluids, aqueous solutions, etc., as the case
may be, that may be used according to the present disclosure.
Accordingly, it is to be understood that the mere use of the term
"first" does not require that there be any "second," and the mere
use of the word "second" does not require that there by any
"third," etc. Further, it is to be understood that the mere use of
the term "first" does not require that the element or step be the
very first in any sequence, merely that it is at least one of the
elements or steps. Similarly, the mere use of the terms "first" and
"second" does not necessarily require any sequence, for example, a
"first" is not required to precede a "second." In addition, the
mere use of such terms does not exclude intervening elements or
steps between the "first" and "second" elements or steps, etc.
General Purposes and Applications of the Present Disclosure
[0026] According to an embodiment of the present disclosure, a
persulfate compound activated by a strong base can be used for
low-temperature breaking of a fluid viscosified with a multi-chain
polysaccharide. According to certain embodiments, the breaker
system can be used in an oilfield or pipeline application where a
multi-chain polysaccharide is in a fluid having an undesirably high
viscosity. It is particularly useful at low and very low
temperatures.
[0027] The features and advantages of the present disclosure will
be apparent to those skilled in the art. While numerous changes may
be made by those skilled in the art, such changes are within the
spirit of the disclosure.
[0028] Fluids viscosified with a multi-chain polysaccharide are
very commonly used in gravel packing operations, sometimes in
fracturing operations, and occasionally in other well treatments.
Examples of multi-chain polysaccharide include diutan,
scleroglucan, and xanthan.
[0029] There are some situations where it would be valuable to be
able to break a fluid viscosified with a multi-chain polysaccharide
at low temperatures. Surface or near surface applications at
temperatures typically below 100.degree. F., include, for example:
[0030] (a) breaking a flow-back fluid from a well, in which a
multi-chain polysaccharide was used to increase viscosity of a well
fluid used in the well. [0031] (b) breaking unused well fluids that
were viscosified with a multi-chain polysaccharide but not actually
introduced into the well. This occurs, for example, when all the
made-up fluid was not actually needed. [0032] (c) breaking of push
pills, that is, where a slug viscosified with a multi-chain
polysaccharide is used to push fluids to clean out an oil or gas
transmission pipeline located at or near the surface of the ground
or seafloor.
[0033] Surface applications would be conveniently performed on or
near the well site. Such applications would be more economical if
it were not necessary to heat the fluid to effect the break of
undesired viscosity.
[0034] Downhole well applications at temperatures that can be below
100.degree. F., include, for example: (a) gravel pack fluids used
in shallow wells; and (b) push pills, for example as a slug, to
push other fluids in a well or subterranean formation.
[0035] Such downhole applications would be more economical if it
were not necessary to heat the well fluid to effect the break of
undesired viscosity.
[0036] For example, in some well applications, it is desirable to
have a delayed break of the fluid viscosified with a multi-chain
polysaccharide in the well at less than 100.degree. F.
[0037] Multi-chain polysaccharides are typically more difficult to
break than single-chain polysaccharides. This is especially a
problem at low temperatures. Generally, to break fluid viscosified
with polysaccharide requires the generation of a certain number of
cleavages in the polymer backbone so as to break the polymer and
cause the desired reduction in viscosity of the fluid. The
multi-chain polysaccharides require more cleavages of the polymer
backbone than for a single-chain polysaccharide to break the
viscosity.
[0038] It is known in the art, however, that the effectiveness of
an oxidizer for breaking a polysaccharide decreases with decreasing
temperature. Various oxidizer systems are available to break a
fluid viscosified with xanthan at high and even moderate
temperatures; however, most of them cannot achieve similar breaking
results at low temperatures, which in this context means less than
100.degree. F. Known oxidizers are essentially ineffective for this
purpose at low temperatures of less than 100.degree. F.
[0039] For example, oxidizers such as hypochlorites are commonly
used to break viscosified fluids at moderate or higher
temperatures, in this context meaning greater than 100.degree. F.
However, at low temperatures below 100.degree. F., their activity
is low. Hence, high concentrations and excessive volumes of
hypochlorites are required for initiating the breaking action. Even
in these situations, it is difficult to achieve viscosities
comparable to those of water (1.0 cP), which is the ideal
objective. In field applications where large quantities of fluid
viscosified with xanthan are required to be broken, using enormous
quantities of hypochlorite breakers becomes highly impractical and
expensive.
[0040] In cases where a delayed break is desired, such as a
downhole well application, at moderate temperatures above
100.degree. F. (38.degree. C.) and higher, this can be achieved by
a reduction of the concentration of the oxidizer. However, there is
a limit to the degree to which the concentration of the oxidizer
can be reduced because, as noted above, there are a certain number
of cleavages in the polymer backbone that are necessary to achieve
the desired reduction in viscosity.
[0041] Therefore, especially at low or very low temperatures, to
achieve a delayed break, a control mechanism other than the
concentration of strong oxidizer alone is necessary.
[0042] A prior patent application of Halliburton discloses the
method of using a composition comprising of water, a source of
hydrogen peroxide (e.g., sodium perborate), and an activator for
the source of hydrogen peroxide to break viscosified fluids used
for treating portions of wellbore or formation at temperatures
below 100.degree. F. US patent Publication No. US 2008/0176770 A1,
published Jul. 24, 2008, having for named inventors Michael W.
Sanders, Jeffrey L. Mundy, Fong Fong Foo, and Rajesh K. Saini,
entitled "Compositions & Methods for breaking a viscosity
increasing polymer at very low temperature used in downhole well
applications".
[0043] The purpose of this disclosure is to provide a breaker
system that can effectively break a fluid viscosified with a
multi-chain polysaccharide. The method is especially useful at low
temperatures, which in this context means at less than 100.degree.
F. Preferably, a breaker system should be able to effectively break
such multi-chain polysaccharides at very low temperatures, which in
this context means at less than 90.degree. F. Other oxidizing
systems such as peroxides with catalysts have been used though with
little success at low temperatures, and especially at very low
temperatures. Another purpose is to provide a breaker system that
is simple to use and inexpensive.
[0044] It has been discovered that a persulfate compound activated
by a strong base can break a fluid viscosified with a multi-chain
polysaccharide at low and very low temperatures.
[0045] A breaker system according to the present disclosure can be
used in an oilfield or pipeline application where a multi-chain
polysaccharide may be used in a fluid. It is particularly useful at
low and very low temperatures.
[0046] A commonly used multi-chain viscosity-increasing
polysaccharide is xanthan. For example, xanthan is typically used
in the range of from about 0.25% to about 1.5% by weight of the
water in well fluids. Xanthan is being used, for example, in
low-temperature gravel pack and frac-pack applications. For
example, 0.2% xanthan exhibits some elasticity, and elasticity is
expected to be observable down to about 0.1% by weight xanthan in
water. Any returned fluid from a well or any unused well fluid
exhibiting viscosity greater than 5 cP would be a candidate for
low-temperature breaking of the fluid before other use,
particularly for other use in a well or disposal.
[0047] An added advantage of this breaker system is the use of
small relative volumes, which makes this system attractive and
practical for field conditions. The breaker system can be a simple
and inexpensive two-component system.
[0048] Another advantage of the compositions and methods according
to the present disclosure is the ability to break a fluid
viscosified with a multi-chain polysaccharide in a controlled
manner at low temperature or very low temperature, that is, the
rate of degradation of the polymer is not immediate and can be
relatively slow. The rate of degradation of the fluid can be
controlled, including by varying the concentration of persulfate or
the mole ratio of persulfate to alkali.
[0049] Certain embodiments of the present disclosure use a simple
two-component breaker system comprising sodium persulfate and
sodium hydroxide. This breaker system can break a fluid of 60
lb/Mgal xanthan to a very low viscosity of 3 cP or less at
85.degree. F. within a very short time of 24 hrs.
[0050] Without being limited by any theory, it is believed that the
persulfate anion can be induced to form a sulfate free radical,
which has an estimated redox potential of 2.6 V. These species can
then initiate a free radical reaction to affect the breaking of
viscosified fluids. According to the breaker system of the present
disclosure, combination of the persulfate and the alkali generates
free radicals that can break xanthan.
[0051] The apparent viscosity of the fluid to be broken is greater
than 5 cP. Preferably, the apparent viscosity of the fluid to be
broken is greater than 10 cP. More preferably, the apparent
viscosity of the fluid to be broken is in the range of 10 cP to 50
cP.
[0052] Preferably the multi-chain polysaccharide is present in at
least 0.24% by weight of the water (20 lb/Mgal) in the fluid, and
more preferably in the range of 0.24% by weight of the water (20
lb/Mgal) to about 1% by weight of the water (about 80 lb/Mgal).
[0053] The persulfate is present in a sufficient concentration to
break the viscosity of a fluid comprising water and the multi-chain
polysaccharide. The concentration of the persulfate and the strong
base can be adjusted to help control the break times. For example,
the persulfate is preferably present in at least about 0.4% by
weight (about 30 lb/Mgal) of the water, and more preferably in the
range of about 0.5% by weight (about 40 lb/Mgal) to about 3% by
weight (about 250 lb/Mgal) of the water of the fluid to be
broken.
[0054] A well fluid according to the present disclosure is
preferably injected at a temperature of less than 150.degree. F.
(65.degree. C.). This temperature range is within the normal
ambient temperature range at the wellhead and avoids any need for
heating the treatment fluid. The treatment fluid has particular
application when injected at a temperature below 100.degree. F.
(38.degree. C.). The treatment fluids and methods according to the
present disclosure are especially useful at low temperatures, at
which fluids viscosified with xanthan are more difficult to break,
such as where the design temperature of the subterranean formation
is less than 100.degree. F. (38.degree. C.).
[0055] In addition, it is presently believed that this breaker
system of persulfate and strong base would work on other
water-soluble polymers. More particularly, it is presently expected
that this breaker system would be effective to break water-soluble
synthetic polymers, such as those used as friction reducers in well
fluids. Still more particularly, it is presently expected that this
breaker system would be effective to break a fluid of a
water-soluble polyacrylamide or derivative thereof.
Surface or Subsurface Applications
[0056] According to an embodiment, methods are provided for
breaking the viscosity of a fluid having an apparent viscosity
greater than 5 cP, wherein the viscous fluid comprises a
multi-chain polysaccharide in water. The method includes the step
of contacting the viscous fluid with: (i) one or more water-soluble
persulfates; and (ii) one or more strong bases. Preferably, the
step of contacting is at one or more temperatures less than
150.degree. F. More preferably, the step of contacting is at one or
more temperatures less than 100.degree. F.
[0057] The methods are useful at very low temperatures, wherein the
step of contacting is at one or more temperatures less than
90.degree. F. Most preferably, the step of contacting is at one or
more temperatures less than 80.degree. F.
[0058] As discussed in more detail, the methods are useful in
several applications, including, for example, treating of flow-back
water, unused treatment fluid, pipeline cleaning, etc.
[0059] Preferably, the step of contacting further involves mixing.
The mixing can be by any convenient technique.
[0060] The one or more water-soluble persulfates can be used in any
convenient form, such as solid particulate or pre-dissolved in an
aqueous solution. Similarly, the one or more strong bases can be
used in any convenient form, such as solid particulate or
pre-dissolved in an aqueous solution.
[0061] Preferably, the step of contacting does not dilute the fluid
more than 10 percent by volume. More preferably, the step of
contacting does not dilute the fluid more than 5 percent by
volume.
[0062] The fluid to be broken can be of various sources or types.
Most commonly, it is expected that the fluid to be broken will be
one in which the continuous phase of the fluid comprises the
multi-chain polysaccharide in water. Advantageously, the water the
water can be a brine.
[0063] In an embodiment, the multi-chain polysaccharide is in at
least a sufficient concentration in the water such that the fluid
to be broken has a viscosity greater than 5 cP. Preferably, the
apparent viscosity of the fluid to be broken is greater than about
10 cP. More preferably, the apparent viscosity of the fluid to be
broken is in the range of about 10 cP to about 50 cP. For example,
a fluid of 20 lb/Mgal xanthan in tap water shows 10 cP apparent
viscosity as measured with a Fann 35 viscometer at 300 rpm (511
sec-1 shear rate).
[0064] In an embodiment, the multi-chain polysaccharide is
xanthan.
[0065] Preferably, the one or more persulfates are in a weight
ratio of at least 0.5 to 1 of the multi-chain polysaccharide in the
fluid. In another embodiment, the one or more persulfates are in a
concentration of at least 30 lb/Mgal of the viscous fluid.
[0066] Preferably, the one or more persulfates are selected from
the group consisting of sodium persulfate, potassium persulfate,
ammonium persulfate, and any combination thereof. More preferably,
the one or more persulfates are selected from the group consisting
of sodium, potassium persulfate, and any combination thereof.
[0067] In an embodiment, the one or more strong bases are in a mole
ratio based on hydroxide of at least 0.5 to 1 of the one or more
persulfates.
[0068] Preferably, the one or more strong bases are selected from
the group consisting of sodium hydroxide, potassium hydroxide,
sodium carbonate, potassium carbonate and any combination thereof.
Most preferably, the one or more strong bases are selected from the
group consisting of sodium hydroxide, potassium hydroxide, and any
combination thereof.
Delayed Break in Well Fluid Application
[0069] According to another embodiment, methods are provided of
treating a well, wherein the methods include the steps of: (a)
forming a treatment fluid comprising: (i) water; and (ii) one or
more multi-chain polysaccharides, wherein the multi-chain
polysaccharides are in at least a sufficient concentration in the
water such that the first treatment fluid has a viscosity of at
least 5 cP; (iii) one or more persulfates; and (iv) one or more
strong bases; and (b) introducing the treatment fluid into the well
and directing the treatment fluid to a portion of the well.
Preferably, the portion of the well has a design temperature less
than 150.degree. F. More preferably, the portion of the well has a
design temperature less than 100.degree. F.
[0070] The methods are useful at very low temperatures, wherein the
portion of the well is has a design temperature less than
90.degree. F. Most preferably, the portion of the well has a design
temperature greater than 70.degree. F.
[0071] Preferably, the water is of any convenient source that does
not have any component that would interfere with the chemistry of
hydrating the polysaccharide, the chemistry of the breaking, the
intended use of the viscosified treatment fluid, or the use of the
fluid after breaking.
[0072] Preferably, the methods further include the steps of: (a)
after the step of introducing, allowing the treatment fluid to
break in the portion of the well; and then (b) flowing back from
the well.
[0073] The treatment fluid can further include proppant or
gravel.
[0074] The step of introducing the treatment fluid can further
include introducing above the fracture pressure of the subterranean
formation.
[0075] The step of introducing the treatment fluid can further
include: gravel packing, which is below the fracture pressure of
the subterranean formation.
Stepwise Well Fluid Application
[0076] According to yet another embodiment, methods are provided of
treating a well, wherein the method include the steps of: (a)
forming a first treatment fluid comprising: (i) water; and (ii) one
or more multi-chain polysaccharides, wherein the multi-chain
polysaccharides are in at least a sufficient concentration in the
water such that the first treatment fluid has a viscosity of at
least 5 cP; (b) forming a second treatment fluid comprising: (i)
one or more persulfates; and (ii) one or more strong bases; (c)
introducing the first treatment fluid into the well; (d)
introducing the second treatment fluid into the well; and (e)
directing the first treatment fluid and the second treatment fluid
to contact each other in a portion of the well. Preferably, the
portion of the well has a design temperature less than 150.degree.
F. More preferably, the portion of the well has a design
temperature less than 100.degree. F.
[0077] The methods are useful at very low temperatures, wherein the
portion of the well is has a design temperature less than
90.degree. F. Most preferably, the portion of the well is has a
design temperature greater than 70.degree. F.
[0078] Preferably, the water is of any convenient source that does
not have any component that would interfere with the chemistry of
hydrating the polysaccharide, the chemistry of the breaking, the
intended use of the viscosified treatment fluid, or the use of the
fluid after breaking.
[0079] Preferably, the method further includes the steps of: (a)
after the step of directing the first treatment fluid and the
second treatment fluid to contact each other in a portion of the
well, allowing the second fluid to break the viscosity of the first
fluid in the portion of the well; and then (b) flowing back from
the well.
[0080] The step of introducing the first treatment fluid into the
well can be before the step of introducing the second treatment
fluid into the well. In a different embodiment, the step of
introducing the first treatment fluid into the well is after the
step of introducing the second treatment fluid into the well. Thus,
the second treatment fluid comprising the one or more persulfates
can be introduced according to an overflush technique or according
to a "poison pill" technique.
[0081] In an embodiment, the first treatment fluid further
comprises proppant or gravel.
[0082] In an embodiment, the step of introducing the first
treatment fluid further comprises introducing above the fracture
pressure of the subterranean formation.
[0083] In another embodiment, the step of introducing the first
treatment further comprises: gravel packing, which is below the
fracture pressure of the formation.
Examples
[0084] General procedure: to a blender jar, add the water and
xanthan and allow the xanthan to fully hydrate. Measure the
viscosity of the fluid at the start (that is, upon hydration of the
xanthan); add the sodium persulfate and the sodium hydroxide; place
the test sample in a temperature bath; measure the viscosity over
time.
[0085] Unless otherwise specified, the water used in these examples
is fresh tap water. Sodium persulfate is sometimes reported as
simply "persulfate." Sodium hydroxide is sometimes reported as
simply "hydroxide."
[0086] All temperatures are reported in degrees Fahrenheit
(.degree. F.).
[0087] In all the experiments, apparent viscosity in centiPoise
(cP) was measured on a Fann Model 35 viscometer using R1 rotor, B1
bob, and F1 spring at 300 rpm, equivalent to 511 sec.sup.-1 shear.
Viscosity readings were taken on a 1/5th spring Fann 35 Viscometer.
The initial viscosity readings were taken with the viscosified
fluid at room temperature (about 77.degree. F.). All other readings
were taken with the test sample placed in a temperature bath of the
stated temperature. The samples were placed in the temperature bath
of the stated temperature. Each day, the bottles were removed from
the temperature bath and immediately readings were taken on the
Fann 35 viscometer.
[0088] Xanthan loading used was a 60 lb/Mgal in fresh tap water or
a 9.1 ppg NaCl brine. The initial viscosity of the fluid was 39.0
cP. The persulfate used was sodium persulfate. The hydroxide used
was sodium hydroxide. Concentrations of the persulfate are reported
in pounds per 1000 gallons (lb/Mgal). Concentrations of the
hydroxide concentrations are reported in mole ratio to the
persulfate concentration. The fluid was considered to be broken
when viscosity of 3.0 cP or less was measured.
[0089] For a fluid of 60 lb/Mgal xanthan in tap water at 85.degree.
F., Table 1 shows the effect on the break time of varying the mole
ratio of hydroxide to persulfate, using a persulfate concentration
of 50 lb/Mgal persulfate.
TABLE-US-00001 TABLE 1 Concentration Xanthan Test of Sodium Mole
Ratio Broken Loading Temperature Persulfate Persulfate Hydroxide
Viscosity Break Time 60 lb/Mgal 85.degree. F. 50 lb/Mgal 1.0 0.5
3.0 cP Day 10 (240 hrs) in tap water (0.60% w/v) 1.0 0.6 3.0 cP Day
8 (192 hrs) 1.0 0.7 3.0 cP Day 6 (144 hrs) 1.0 0.8 3.0 cP Day 5
(120 hrs) 1.0 0.9 3.0 cP Day 4 (96 hrs) 1.0 1.0 3.0 cP Day 3 (72
hrs) 1.0 1.1 2.5 cP Day 3 (72 hrs) 1.0 1.2 2.5 cP Day 3 (72 hrs)
1.0 1.3 3.0 cP Day 2 (48 hrs) 1.0 1.4 2.5 cP Day 2 (48 hrs) 1.0 1.5
3.0 cP Day 1 (24 hrs) 1.0 3.0 1.5 cP Day 1 (24 hrs) 1.0 4.5 1.5 cP
Day 1 (24 hrs) 1.0 6.0 1.0 cP Day 1 (24 hrs)
[0090] For a fluid of 60 lb/Mgal xanthan in tap water at 85.degree.
F., Table 2 shows the effect on break time of varying the mole
ratio of hydroxide to persulfate, using a persulfate concentration
of 40 lb/Mgal.
TABLE-US-00002 TABLE 2 Concentration Xanthan Test of Sodium Mole
Ratio Broken Loading Temperature Persulfate Persulfate Hydroxide
Viscosity Break Time 60 lb/Mgal 85.degree. F. 40 lb/Mgal 1.0 0.5
Unbroken (5.0 cP) after 12 days in tap water (0.48% w/v) 1.0 0.6
3.0 cP Day 10 (240 hrs) 1.0 0.7 3.0 cP Day 7 (168 hrs) 1.0 0.8 3.0
cP Day 5 (120 hrs) 1.0 0.9 3.0 cP Day 5 (120 hrs) 1.0 1.0 3.0 cP
Day 5 (120 hrs) 1.0 1.1 3.0 cP Day 4 (96 hrs) 1.0 1.2 3.0 cP Day 3
(72 hrs) 1.0 1.3 2.5 cP Day 3 (72 hrs) 1.0 1.4 2.5 cP Day 3 (72
hrs) 1.0 1.5 2.5 cP Day 3 (72 hrs)
[0091] The data in the Tables 1 and 2 show that at a particular
temperature and at a particular persulfate concentration, the break
times can be controlled by adjusting the concentration of the
persulfate and the mole ratio of the hydroxide to the
persulfate.
[0092] For a fluid of 60 lb/Mgal xanthan in tap water at 85.degree.
F., Table 3 shows the effect on break time of varying the
concentration of persulfate, keeping a constant mole ratio of
hydroxide to persulfate.
TABLE-US-00003 TABLE 3 Concentration Xanthan Test of Sodium Mole
Ratio Broken Loading Temperature Persulfate Persulfate Hydroxide
Viscosity Break Time 60 lb/Mgal 85.degree. F. 30 lb/Mgal 1.0 1.0
3.0 cP Day 8 (192 hrs) in tap water (0.36% w/v) 40 lb/Mgal 1.0 1.0
3.0 cP Day 5 (120 hrs) (0.48% w/v) 50 lb/Mgal 1.0 1.0 3.0 cP Day 3
(72 hrs) (0.60% w/v)
[0093] Data in Table 3 shows that at a particular temperature,
break times can be controlled by adjusting the concentration of the
persulfate.
[0094] For a fluid of 60 lb/Mgal xanthan in tap water, Table 4
shows the effect of varying the temperature on the break time
TABLE-US-00004 TABLE 4 Concentration Xanthan Test of Sodium Mole
Ratio Broken Loading Temperature Persulfate Persulfate Hydroxide
Viscosity Break Time 60 lb/Mgal 90.degree. F. 50 lb/Mgal 1.0 1.0
3.0 cP Day 1 (24 hrs) in tap water 85.degree. F. (0.60% w/v) 1.0
1.0 3.0 cP Day 3 (72 hrs) 80.degree. F. 1.0 1.0 3.0 cP Day 6 (144
hrs)
[0095] Data in Table 4 shows that the activated breaker composition
can be used to effectively break fluids viscosified with xanthan at
very low temperatures, in this context meaning down to 80.degree.
F.
[0096] For a fluid of 60 lb/Mgal xanthan in 9.1 ppg NaCl brine at
90.degree. F., Table 5 shows the effect on break time of varying
the mole ratio of hydroxide to persulfate, using a persulfate
concentration of 50 lb/Mgal.
TABLE-US-00005 TABLE 5 Concentration Xanthan Test of Sodium Mole
Ratio Broken Loading Temperature Persulfate Persulfate Hydroxide
Viscosity Break Time 60 lb/Mgal in 90.degree. F. 50 lb/Mgal 1.0 0.8
3.0 cP Day 4 (96 hrs) 9.1 ppg NaCl (0.60% w/v) 1.0 0.9 3.0 cP Day 3
(72 hrs) brine 1.0 1.0 3.0 cP Day 1 (24 hrs)
[0097] Data in Table 5 shows that at a particular temperature and
at a particular persulfate concentration in a brine, the break
times can be controlled by adjusting the ratio of
persulfate:hydroxide. It also shows that the alkaline activated
persulfate mechanism can work to break fluids of xanthan in
brines.
CONCLUSIONS
[0098] It should be appreciated that the various steps according to
the present disclosure can be combined advantageously or practiced
together in various combinations to increase the efficiency and
benefits that can be obtained from the present disclosure.
[0099] Therefore, the present disclosure is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present disclosure may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is, therefore, evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present disclosure. While compositions and methods are
described in terms of "comprising," "containing," or "including"
various components or steps, the compositions and methods also can
"consist essentially of" or "consist of" the various components and
steps. Whenever a numerical range with a lower limit and an upper
limit is disclosed, any number and any included range falling
within the range is specifically disclosed. In particular, every
range of values (of the form, "from a to b," or, equivalently,
"from approximately a to b," or, equivalently, "from approximately
a to b") disclosed herein is to be understood to set forth every
number and range encompassed within the broader range of values.
Also, the terms in the claims have their plain, ordinary meaning
unless otherwise explicitly and clearly defined by the patentee.
Moreover, the indefinite articles "a" or "an", as used in the
claims, are defined herein to mean one or more than one of the
element that it introduces. If there is any conflict in the usages
of a word or term in this specification and one or more patent(s)
or other documents that may be incorporated herein by reference,
the definitions that are consistent with this specification should
be adopted.
* * * * *