U.S. patent application number 11/418617 was filed with the patent office on 2007-11-08 for methods of treating a subterranean formation with a treatment fluid having surfactant effective to increase the thermal stability of the fluid.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to David M. Barrick, Jason Bryant, David E. Griffin, Malcom Talbot, Thomas D. Welton.
Application Number | 20070256836 11/418617 |
Document ID | / |
Family ID | 38660190 |
Filed Date | 2007-11-08 |
United States Patent
Application |
20070256836 |
Kind Code |
A1 |
Welton; Thomas D. ; et
al. |
November 8, 2007 |
Methods of treating a subterranean formation with a treatment fluid
having surfactant effective to increase the thermal stability of
the fluid
Abstract
Methods of treating a subterranean formation penetrated by a
wellbore are provided, the methods comprising the steps of: (a) for
a treatment fluid to be used in treating a subterranean formation,
establishing a desired viscosity at a desired temperature for a
desired time; (b) forming a treatment fluid that has the desired
viscosity at the desired temperature for the desired time, wherein
the treatment fluid comprises: (i) a base fluid; (ii) a
viscosifying agent comprising a polymer; and (iii) a surfactant;
and (c) introducing the treatment fluid into a subterranean
formation. According to one aspect, an otherwise substantially
identical treatment fluid with a lower concentration of the
surfactant would not achieve the desired viscosity at the desired
temperature for the desired time. According to another aspect, the
polymer is at a lower concentration in the base fluid than would be
required for an otherwise substantially identical treatment fluid
with a lower concentration of the surfactant to achieve the desired
viscosity at the desired temperature for the desired time.
Inventors: |
Welton; Thomas D.; (Duncan,
OK) ; Griffin; David E.; (Marlow, OK) ;
Barrick; David M.; (Duncan, OK) ; Bryant; Jason;
(Duncan, OK) ; Talbot; Malcom; (Duncan,
OK) |
Correspondence
Address: |
Halliburton Energy Services, Inc.
2600 S. 2nd Street
Duncan
OK
73536-0440
US
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
38660190 |
Appl. No.: |
11/418617 |
Filed: |
May 5, 2006 |
Current U.S.
Class: |
166/303 ;
166/305.1; 507/211 |
Current CPC
Class: |
C09K 8/602 20130101;
C09K 8/887 20130101; C09K 8/90 20130101; C09K 8/68 20130101; C09K
8/685 20130101 |
Class at
Publication: |
166/303 ;
507/211; 166/305.1 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 43/22 20060101 E21B043/22 |
Claims
1. A method of treating a subterranean formation penetrated by a
welbore, the method comprising the steps of: a. for a treatment
fluid to be used in treating a subterranean formation establishing
a desired viscosity at a desired temperature for a desired time; b.
forming a treatment fluid that has the desired viscosity at the
desired temperature for the desired time, wherein the treatment
fluid comprises; i. a base fluid; ii. a viscosifying agent
comprising a polysaccharide; and iii. a surfactant; wherein an
otherwise substantially identical treatment fluid with a lower
concentration of the surfactant would not achieve the desired
viscosity at the desired temperature for the desired time; and c.
introducing the treatment fluid into a subterranean formation.
2. The method according to claim 1, wherein: a. the desired
viscosity is at least 100 cP at a shear rate of at least 1/sec; b.
the desired temperature is at least 175.degree. F. (80.degree. C.);
and c. the desired time is at least 0.5 hour
3. The method according to claim 2, wherein: a. the desired
viscosity is in the range of 100-5,000 cP at a shear rate in the
range of 1-1,000/sec; b. the desired temperature is in the range of
175-400.degree. F. (80-205.degree. C.); and c. the desired time is
in the range of about 0.5-8 hours.
4. The method according to claim 3, wherein: a. the desired
viscosity is at least 500 cP at a shear rate of at least 81/sec; b.
the desired temperature is at least 220.degree. F. (105.degree.
C.); and c. the desired time is at least 1 hour.
5. The method according to claim 4, wherein: a. the desired
viscosity is in the range of 500-2,500 cP at a shear rate of
81/sec; b. the desired temperature is in the range of
220-300.degree. F. (105-149.degree. C.); and c. the desired time is
in the range of 2-4 hours.
6. The method according to claim 1, wherein the base fluid
comprises water.
7. The method according to claim 6, wherein the viscosifying agent
comprises: a water-soluble polysaccharide.
8. The method according to claim 1, wherein an otherwise
substantially identical treatment fluid without any of the
surfactant would not achieve the desired viscosity at the desired
temperature for the desired time.
9. canceled.
10. canceled.
11. The method according to claim 1, wherein the surfactant
comprises: a non-ionic surfactant.
12. The method according to claim 11, wherein the non-ionic
surfactant is selected from the group consisting of: linear
ethoxylates, branched ethoxylates, linear alkyl ethoxylated
alcohols, branched alkyl ethoxylated alcohols, linear propoxylates,
linear alkyl propoxylated alcohols, phenol-formaldehyde non-ionic
resin blends, and any combination in any proportion of the
foregoing.
13. The method according to claim 1, wherein the surfactant
comprises: an anionic surfactant.
14. The method according to claim 13, wherein the anionic
surfactant is selected from the group consisting of: sulfonic acid,
salt of a sulfonic acid, sulfonate, fatty acid, and salt of fatty
acid, and any combination in any proportion of the foregoing.
15. The method according to claim 1, wherein the treatment fluid
further comprises: a non-surfactant thermal stabilizer.
16. A method of treating a subterranean formation penetrated by a
wellbore, the method comprising the steps of: a. for a treatment
fluid to be used in treating a subterranean formation, establishing
a desired viscosity at a desired temperature for a desired time; b.
forming a treatment fluid that has the desired viscosity at the
desired temperature for the desired time, wherein the treatment
fluid comprises: i. a base fluid; ii. a viscosifying agent
comprising a polysaccharide; and iii. a surfactant; wherein the
polysaccharide is at a lower concentration in the base fluid than
would be required for an otherwise substantially identical
treatment fluid with a lower concentration of the surfactant to
achieve the desired viscosity at the desired temperature for the
desired time; and c. introducing the treatment fluid into a
subterranean formation.
17. The method according to claim 16, wherein: a. the desired
viscosity is at least 100 cP at a shear rate of at least 1/sec; b.
the desired temperature is at least 175.degree. F. (80.degree. C.);
and c. the desired time is at least 0.5 hour.
18. The method according to claim 17, wherein: a. the desired
viscostiy is in the range of 100-5,000 cP at a shear rate in the
range of 1-1,000/sec; b. the desired temperature is in the range of
175-400.degree. F. (80-205.degree. C.); and c. the desired time is
in the range of about 0.5-8 hours.
19. The method according to claim 18, wherein: a. the desired
viscosity is at least 500 cP at a shear rate of at least 81/sec; b.
the desired temperature is at least 220.degree. F. (105.degree.
C.); and c. the desired time is at least 1 hour.
20. The method according to claim 19, wherein: a. the desired
viscosity is in the range of 500-2,500 cP at a shear rate of
81/sec; b. the desired temperature is in the range of
220-300.degree. F. (105-149.degree. C.); and c. the desired time is
in the range of 2-4 hours.
21. The method according to claim 16, wherein the base fluid
comprises water.
22. The method according to claim 21, wherein the viscosifying
agent comprises: a water-soluble polysaccharide.
23. The method according to claim 16, wherein the polysaccharide is
at a lower concentration in the base fluid than would be required
for an otherwise substantially identical treatment fluid without
any of the surfactant to achieve the desired viscosity at the
desired temperature for the desired time.
24. canceled.
25. canceled.
26. The method according to claim 16, wherein the surfactant
comprises: a non-ionic surfactant.
27. The method according to claim 26, wherein the non-ionic
surfactant is selected from the group consisting of: linear
ethoxylates, branched ethoxylates, linear alkyl ethoxylated
alcohols, branched alkyl ethoxylated alcohols, linear propoxylates,
linear alkyl propoxylated alcohols, phenol-formaldehyde non-ionic
resin blends, and any combination in any proportion of the
foregoing.
28. The method according to claim 16, wherein the surfactant
comprises: an anionic surfactant.
29. The method according to claim 28, wherein the anionic
surfactant is selected from the group consisting of: sulfonic acid,
salt of a sulfonic acid, sulfonate, fatty acid, and salt of fatty
acid, and any combination in any proportion of the foregoing.
30. The method according to claim 16, wherein the treatment fluid
further comprises: a non-surfactant thermal stabilizer.
31. A method of treating a subterranean formation penetrated by a
wellbore, the method comprising the steps of: a. forming a
treatment fluid comprising: i. a base fluid; ii. a viscosity agent
comprising a polysaccharide; iii. a surfactant; and iv. a
non-surfactant thermal stabilizer; and b. introducing the treatment
fluid into a subterranean formation.
32. The method according to claim 31, wherein the base fluid
comprises water.
33. The method according to claim 32, wherein the viscosifying
agent comprises: a water-soluble polysaccharide.
34. The method according to claim 32, wherein the non-surfactant
thermal stabilizer is selected from the group consisting of:
thiosulfates, methanol, formate brines, and any combination thereof
in any combination.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not Applicable.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not Applicable.
REFERENCE TO A MICROFICHE APPENDIX
[0003] Not applicable.
TECHNICAL FIELD
[0004] The invention generally relates to methods of treating a
hydrocarbon-bearing subterranean formation with viscosified fluids
for various purposes, such as gravel packing and hydraulic
fracturing. Such treatment fluids are viscosified with polymeric
materials that are sensitive to elevated temperatures. The
invention relates to using a surfactant to increase the thermal
stability of such viscosified treatment fluids.
BACKGROUND
[0005] Hydrocarbon (e.g. crude oil and natural gas) is used for
making various grades of fuels and oils. Hydrocarbon is obtained
from a hydrocarbon-bearing subterranean formation by drilling a
wellbore into the earth, either on land or under the sea, that
penetrates the hydrocarbon-bearing formation. Typically, such a
wellbore must be drilled thousands of feet into the earth to reach
the hydrocarbon-bearing formations. Usually, the greater the depth
of the well, the hotter the natural temperature of the
formation.
[0006] Of course, it is desirable to maximize both the rate of flow
and the overall amount of flow of hydrocarbon from the subterranean
formation to the surface. The higher temperatures can be a problem
for the gels used in various treatments on a subterranean formation
to improve the flow of hydrocarbon.
[0007] For example, a treatment performed to restore or enhance the
productivity of a well is called a stimulation treatment.
Stimulation treatments fall into two main groups, hydraulic
fracturing treatments and matrix treatments.
[0008] Fracturing treatments are performed above the fracture
pressure of the reservoir formation and create a highly conductive
flow path between the reservoir and the wellbore. In general,
hydraulic fracturing involves injecting a fracturing fluid through
the wellbore and into an oil and gas bearing subterranean formation
at a sufficiently high rate of fluid flow and at a sufficiently
high pressure to initiate and extend one or more fractures in the
formation. To conduct hydraulic pressure through the wellbore, the
fracturing fluid must be substantially incompressible. In addition,
because of the large quantities of fracturing fluid required, the
fracturing fluid is preferably based on readily-available and
plentiful fluid. Thus, the typical fracturing fluid is based on
water.
[0009] The fracturing fluid is injected through the wellbore at
such a high flow rate and under such high pressure that the rock of
the subterranean formation that is subjected to the hydraulic
treatment literally cracks apart or fractures under the strain.
When the formation fractures, the pressure is relieved as the
fracturing fluid starts to move quickly through the fracture and
out into the formation. The theoretical objective of forming such a
fracture in the rock of the formation is to create a large surface
area of the faces of the fracture. The large surface area allows
oil and gas to flow from the rock of the subterranean formation
into the facture, which provides an easy path for the oil and gas
to easily flow into the well.
[0010] However, once the high pressure is relieved by the escape of
the fracturing fluid through the created fracture and out further
into the subterranean formation, the fracture has a tendency to be
squeezed closed by the natural pressures on the rock within the
deep subterranean formation. To keep the fracture open, some kind
of material must be placed in the fracture to prop the faces of the
fracture apart.
[0011] The desirable material for the purpose of propping the
fracture apart must meet several criteria. For example, the
material must have a sufficient strength not to be entirely crushed
by the natural forces tending to push the fracture closed. The
material must be capable of being fluidized so that it can flow
with or immediately following the fracturing fluid. Additionally,
the material also must itself not block or seal the fracture. Thus,
a typical material used for the purpose of propping open a fracture
is sand. Sand, in the aggregate, has a sufficiently high mechanical
strength to prop open a fracture in a subterranean formation at
typical depths and natural subterranean pressures; it can behave as
a fluid in that it can be poured and flow; and the particles, even
when tightly compacted, have a network of void spaces between them
that can provide high porosity to fluid flow.
[0012] While sand is the most commonly used material for the
purpose of propping the fracture open, many other materials of the
appropriate size range and mechanical strength can be used. In the
oil and gas industry, any suitable particulate material that is
used for the purpose of propping open a fracture produced by
hydraulic fracturing is called a "proppant."
[0013] To be able to carry and place a proppant into a
newly-created fracture, a fluid must have a sufficient viscosity to
suspend and carry the proppant. In a low viscosity fluid, for
example, the proppant would have a tendency to simply fall under
gravity toward the bottom of the well instead of being carried with
the fracturing fluid out into the newly-created fracture. For a
fluid to be able to carry the proppant instead of having the
proppant fall out of the fluid, the fracturing fluid needs to be
made to have a much higher viscosity than that of water.
Preferably, the fracturing fluid is a gel, which has a very high
viscosity and great capacity for carrying a proppant suspended in
the fluid.
[0014] Using a water-soluble polymeric material, such as a gum, is
one of the ways to build viscosity in aqueous systems. Such a gum
can be mixed with an aqueous fluid for use in a well to increase
fluid viscosity. A sufficient concentration of the gum in an
aqueous system can form a linear gel. Furthermore, the gum also can
be crosslinked with other compounds, such as borates or various
metals, to create a viscous fluid, which is highly advantageous to
transporting a proppant in a hydraulic fracturing procedure.
[0015] Matrix treatments are performed below the reservoir fracture
pressure and generally are designed to restore or enhance the
natural permeability of the reservoir in the near-wellbore area.
Matrix operations can include treating the formation with an acid
to dissolve some of the acid soluble rock material. It is sometimes
desirable to perform a matrix treatment with a gelled fluid.
[0016] Another type of treatment for a subterranean formation is
gravel packing, which is used to help control fines migrations.
"Fines" are tiny particles that have a tendency to flow through the
formation with the production of hydrocarbon. The fines have a
tendency to plug small pore spaces in the formation and block the
flow of oil. As all the hydrocarbon is flowing from a relatively
large region around the wellbore region toward a relatively small
area around the wellbore, the fines have a tendency to become
densely packed and screen out or plug the area immediately around
the wellbore. Moreover, the fines are highly abrasive and can be
very harmful to pumping equipment.
[0017] In general, gravel packing involves placing sand or gravel
around the wellbore to help screen out the fines. Like with placing
a proppant in a subterranean formation during hydraulic fracturing,
a gelled fluid is used to help place the gravel in a gravel packing
operation. Gravel packing can also be done in conjunction with
other treatments including hydraulic fracturing such as the
FracPac.sup.SM service.
[0018] Other examples of uses of gelled fluids include but are not
limited to spacers for cements and/or muds, fluid loss pills, and
gelled pipeline clean-out fluids ("pigs").
[0019] In all the various types of treatments for a subterranean
formation that involve the use of a gelled fluid, the gels are
sensitive to temperature. Many of the subterranean formations to be
treated have a natural formation temperature greater than
175.degree. F. (80.degree. C.), and most are within the range of
175-550.degree. F. (80-288.degree. C.). Many of the polymer-based
gels are sensitive to temperatures above about 220.degree. F.
(105.degree. C.). Especially the gels that are based on natural
polymeric materials, such as guar or cellulose, which are the most
economical in the large quantities required for a treatment of a
subterranean formation, are sensitive to such high
temperatures.
[0020] Efforts have been made to improve the thermal stability of
gels, but greater thermal stability is always desirable.
SUMMARY OF THE INVENTION
[0021] According to the invention, methods are provided for
treating a subterranean penetrated by a wellbore with a treatment
fluid that is thermally stabilized by a surfactant.
[0022] According to one aspect of the invention, a method of
treating a subterranean formation penetrated by a wellbore is
provided, the method comprising the steps of: (a) for a treatment
fluid to be used in treating a subterranean formation, establishing
a desired viscosity at a desired temperature for a desired time;
(b) forming a treatment fluid that has the desired viscosity at the
desired temperature for the desired time, wherein the treatment
fluid comprises: (i) a base fluid; (ii) a viscosifying agent
comprising a polymer; and (iii) a surfactant; wherein an otherwise
substantially identical treatment fluid with a lower concentration
of the surfactant would not achieve the desired viscosity at the
desired temperature for the desired time; and (c) introducing the
treatment fluid into a subterranean formation.
[0023] According to another aspect of the invention, a method of
treating a subterranean formation penetrated by a wellbore is
provided, the method comprising the steps of: (a) for a treatment
fluid to be used in treating a subterranean formation, establishing
a desired viscosity at a desired temperature for a desired time;
(b) forming a treatment fluid that has the desired viscosity at the
desired temperature for the desired time, wherein the treatment
fluid comprises: (i) a base fluid; (ii) a viscosifying agent
comprising a polymer; and (iii) a surfactant; wherein the polymer
is at a lower concentration in the base fluid than would be
required for an otherwise substantially identical treatment fluid
with a lower concentration of the surfactant to achieve the desired
viscosity at the desired temperature for the desired time; and (c)
introducing the treatment fluid into a subterranean formation.
[0024] These and other aspects of the invention will be apparent to
one skilled in the art upon reading the following detailed
description. While the invention is susceptible to various
modifications and alternative forms, specific embodiments thereof
will be described in detail and shown by way of example. It should
be understood, however, that it is not intended to limit the
invention to the particular forms disclosed, but, on the contrary,
the invention is to cover all modifications and alternatives
falling within the spirit and scope of the invention as expressed
in the appended claims
BRIEF DESCRIPTION OF THE DRAWING
[0025] The accompanying drawings are incorporated into and form a
part of the specification to illustrate several examples of the
present inventions. These drawings together with the description
serve to explain the principles of the inventions. The drawings are
only for illustrating preferred and alternative examples of how the
inventions can be made and used and are not to be construed as
limiting the inventions to the illustrated and described examples.
The various advantages and features of the present inventions will
be apparent from a consideration of the drawings in which:
[0026] FIG. 1 is a graph of the viscosity measurements in cP at a
shear rate of 81/sec vs. time as the sample was rapidly heated from
room temperature to 240.degree. F. in about 20 minutes and then
held at 240.degree. F. (115.degree. C.) on samples of a
borate-crosslinked hydroxypropyl guar in 4% KCl water at a pH of
about 10.5, where Sample 1 is without any of the surfactant blend
and Sample 2 has 1 gal/Mgal of the surfactant blend.
[0027] FIG. 2 is a graph of the viscosity measurements in cP at a
shear rate of 81/sec vs. time as the sample was rapidly heated from
room temperature to 285.degree. F. (140.degree. C.) in about 20
minutes and then held at 285.degree. F. (140.degree. C.) on samples
of a borate-crosslinked hydroxypropyl guar in 4% KCl water at a pH
of about 10.5, where Sample 2 contained 1 gal/Mgal of the
surfactant blend, Sample 3 contained 2 gal/Mgal of the surfactant
blend, and Sample 4 contained 3 gal/Mgal of the surfactant
blend.
[0028] FIG. 3 is a graph of the viscosity measurements in cP at a
shear rate of 81/sec vs. time as the sample was rapidly heated from
room temperature to 285.degree. F. (140.degree. C.) in about 20
minutes and then held at 285.degree. F. (140.degree. C.) on samples
of a borate-crosslinked hydroxypropyl guar in 4% KCl water at a pH
of about 10.5, where Sample 5 contained none of the surfactant
blend and no sodium thiosulfate, Sample 6 contained 3 gal/Mgal of
the surfactant blend and no sodium thiosulfate, Sample 7 contained
none of the surfactant blend and 1 lb/Mgal of sodium thiosulfate,
and Sample 8 contained 3 gal/Mgal of the surfactant blend and 1
lb/Mgal of sodium thiosulfate. The graph of FIG. 3 also shows the
temperature of the sample vs. time.
[0029] FIG. 4 is a graph of viscosity measurements in cP vs. shear
rates ranging from about 0.1 to about 1,000 sec.sup.-1 measured at
room temperature before and after heating the sample for 15 minutes
at 285.degree. F. (140.degree. C.) on samples of the uncrosslinked
HPG gel, where Sample 9, denoted as Sample 9a before heating and as
Sample 9b after heating, contained 3 gal/Mgal of the surfactant
blend, and where Sample 10, denoted as Sample 10a before heating
and as Sample 10b after heating, contained no surfactant blend.
While not being limited to one theory, one potential explanation to
the polymer-surfactant interaction is that the degradation of
polymer chains is delayed with the addition of surfactant as
illustrated by the viscosities before and after the samples were
heated.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0030] As used herein and in the appended claims, the words
"comprise," "has," and "include" and all grammatical variations
thereof are each intended to have an open, non-limiting meaning
that does not exclude additional elements or parts of an assembly,
subassembly, or structural element.
[0031] As used herein, the natural temperature of the subterranean
formation is the temperature as unaffected by temporarily flooding
of the formation with a fluid at a different temperature that would
temporarily change the natural temperature of the formation.
[0032] As used herein, the solubility of a substance is its
concentration in a saturated solution. A substance having a
solubility of less than 1 g/100 mL of solvent is usually considered
insoluble. The solubility is sometimes called "equilibrium
solubility" because the rates at which solute dissolves and is
deposited out of solution are equal at this concentration.
[0033] The methods according to the present invention will be
described by referring to and showing various examples of how the
invention can be made and used.
[0034] According to one aspect of the invention, a method of
treating a subterranean formation penetrated by a wellbore is
provided, the method comprising the steps of: (a) for a treatment
fluid to be used in treating a subterranean formation, establishing
a desired viscosity at a desired temperature for a desired time;
(b) forming a treatment fluid that has the desired viscosity at the
desired temperature for the desired time, wherein the treatment
fluid comprises: (i) a base fluid; (ii) a viscosifying agent
comprising a polymer; and (iii) a surfactant; wherein an otherwise
substantially identical treatment fluid with a lower concentration
of the surfactant would not achieve the desired viscosity at the
desired temperature for the desired time; and (c) introducing the
treatment fluid into a subterranean formation.
[0035] According to another aspect of the invention, a method of
treating a subterranean formation penetrated by a wellbore is
provided, the method comprising the steps of: (a) for a treatment
fluid to be used in treating a subterranean formation, establishing
a desired viscosity at a desired temperature for a desired time;
(b) forming a treatment fluid that has the desired viscosity at the
desired temperature for the desired time, wherein the treatment
fluid comprises: (i) a base fluid; (ii) a viscosifying agent
comprising a polymer; and (iii) a surfactant; wherein the polymer
is at a lower concentration in the base fluid than would be
required for an otherwise substantially identical treatment fluid
with a lower concentration of the surfactant to achieve the desired
viscosity at the desired temperature for the desired time; and (c)
introducing the treatment fluid into a subterranean formation.
[0036] According to either aspect of the invention, the step of
establishing a desired viscosity at a desired temperature for a
desired time comprises: ascertaining the temperature of the
subterranean formation. The invention offers advantages when the
subterranean formation has a temperature that is greater than
175.degree. F. (80.degree. C.) and it is desired to have a
treatment fluid be able to maintain a desired viscosity and be
thermally stable at or above this temperature. While some gels are
sufficiently stable at such moderately high temperatures, the
invention has particular advantages, when a desired viscosity is
desired to have a thermally stability of at least 220.degree. F.
(105.degree. C.).
[0037] Preferably, the desired viscosity is at least 100 cP at a
shear rate of at least 1/sec; the desired temperature is at least
175.degree. F. (80.degree. C.); and the desired time is at least
0.5 hour. More particularly, the desired viscosity is in the range
of 100-5,000 cP at a shear rate in the range of 1-1,000/sec; the
desired temperature is in the range of 175-400.degree. F.
(80-205.degree. C.); and the desired time is in the range of about
0.5-8 hours.
[0038] More preferably, the desired viscosity is at least 500 cP at
a shear rate of at least 81/sec; the desired temperature is at
least 220.degree. F. (105.degree. C.); and the desired time is at
least 1 hour. More particularly, the desired viscosity is in the
range of 500-2,500 cP at a shear rate of 81/sec; the desired
temperature is in the range of 220-300.degree. F. (105-149.degree.
C.); and the desired time is in the range of 2-4 hours.
[0039] In the methods according to the invention, the viscosity of
the treatment fluid can be measured according to a modified API2
test procedure, which is well know to persons of skill in the art
of making treatment fluids for treating a subterranean formation.
Further, for example, the viscosity of the treatment fluid can be
measured with a Nordman Model 50 viscometer. It is to be
understood, of course, that measurement of viscosity is somewhat
dependent on the exact testing procedure and equipment
employed.
[0040] In most situations, the base fluid comprises water. The
water can be selected from the group consisting of: fresh water,
brackish water, seawater, unsaturated salt water, brine, and any
combination thereof in any proportion. It should be understood, of
course, that the base fluid can also comprise a gas. The use of a
gas can be useful, for example, in making a foamed treatment
fluid.
[0041] When the base fluid comprises water, the viscosifying agent
preferably comprises: a water-soluble polymeric material. More
preferably, the water-soluble polymeric material is a
polysaccharide. For example, the viscosifying agent can be selected
from the group consisting of: guar, hydroxylalkyl guar,
carboxyalkylhydroxyalkyl guar, carboxyalkyl cellulose,
carboxyalkylhydroxyalkyl cellulose, hydroxyethyl cellulose,
hydroxypropyl cellulose, carboxymethyl guar, xanthans,
scleroglucan, diutan, succinoglycan, welan, derivatives of any of
the foregoing, and any combination thereof in any proportion. More
preferably, the viscosifying agent is selected from the group
consisting of hydroxypropyl guar, carboxypropylhydroxypropyl guar,
carboxymethylcellulose, carboxymethyhydroxymethyl cellulose, and
any combination thereof in any proportion.
[0042] The viscosifying agent preferably further comprises: a
crosslinking agent. The crosslinking agent can help crosslink the
polymeric material and increase the viscosity of the fluid. For
example, the crosslinking agent can be present in the treatment
fluid in an amount in the range of from about 50 ppm to about
10,000 ppm.
[0043] When a crosslinking agent is employed, the crosslinking
agent is preferably selected from the group consisting of:
crosslinking agent is selected from the group consisting of boron
compounds, compounds that supply zirconium IV ions, compounds that
supply titanium IV ions, aluminum compounds, iron compounds,
chromium, compounds that supply antimony ions, and any combination
thereof in any proportion.
[0044] For a guar-based viscosifying agent, one of the preferred
crosslinking agents comprises a boron compound. When a boron
compound is employed as a crosslinking agent, the treatment fluid
preferably further comprises a pH adjusting agent for elevating the
pH of the treating fluid. This is important because borate
crosslinking agents require a high pH to function. Preferably, the
pH adjusting agent is selected from the group consisting of sodium
hydroxide, potassium hydroxide and lithium hydroxide. The pH
adjusting agent is preferably in the treating fluid in an amount in
the range of from about 0.1% to about 0.3% by weight of the water
therein. Regardless of the amount by weight, the pH adjusting agent
is most preferably present in at least a sufficient concentration
to increase the pH of the water to at least 9.
[0045] The treatment fluid preferably further comprises a breaker
for the viscosifying agent. When the treatment fluid comprises a
borate crosslinker, which operates at a relatively high pH, the
breaker preferably comprises a delayed release acid. The delayed
release acid is preferably in at least a sufficient concentration
in the base fluid to lower the pH of the water to less than 9.
[0046] As the term is used herein, a "surfactant" (a contraction of
the term surface-active agent) is a substance that, when present in
a low concentration in a system, has the property of adsorbing onto
the surfaces or interfaces of the system and of altering to a
marked degree the surface or interfacial free energies of those
surfaces or interfaces. See "Surfactants and Interfacial
Phenomena," Rosen, 3.sup.rd Edition (ISBN 0-471-47818-0).
Structurally, a surfactant is an organic compound that contains at
least one lyophilic ("solvent-loving") and one lyophobic
("solvent-fearing") group in the molecule.
[0047] According to a preferred embodiment of the invention wherein
the base fluid comprises water, the surfactant is present in the
treatment fluid in an amount in the range of from about 1-45
lb/Mgal of the water. According to another preferred embodiment of
the invention, the surfactant is present in at least the critical
micelle concentration, that is, the concentration required for the
surfactant to form a micelle.
[0048] It has been discovered that a surfactant has an unexpected
effect on improving the thermal stability of a viscosified fluid.
This provides two applications that are believed to have been
unknown.
[0049] First, this allows a treatment fluid to be formulated to
achieve a desired viscosity at a desired temperature for a desired
time that had until now not been believed to be achievable. This
greatly expands the useful ranges for a viscosified treatment fluid
having a particular formulation beyond the limits previously
thought practical. The ability to use a particular polymeric
viscosified system at a higher temperature and/or for a longer time
has the benefit of allowing less expensive viscosifying agents to
be used in higher temperature applications. This also provides the
benefit of being able to use the system at such higher temperatures
without the use of other non-surfactant thermal stabilizers, as
hereinafter described in more detail.
[0050] Second, this allows a treatment fluid to be formulated with
a lower polymer loading to achieve a desired viscosity at a desired
temperature for a desired time than had until now had not been
believed to be achievable with such lower polymer loadings. This
also greatly expands the useful ranges for a viscosified treatment
fluid having a particular polymer loading beyond the limits
previously thought practical. The use of lower polymer loading to
achieve a particular desired viscosity at a desired temperature for
a desired time has the benefit of reducing the amount of polymer
damage to a subterranean formation to be treated with a viscosified
fluid.
[0051] It should be understood that the use of surfactant or
increased concentrations of surfactant is not itself required to
appreciably increase the viscosity of the viscosified fluid.
Rather, the surfactant, acting as a thermal stabilizer for the
polymer, permits a lower loading of the polymer to achieve a
desired viscosity at a desired temperature for a desired time.
Previously, one of the approaches for combating the thermal
degradation of the polymer of the viscosifying agent was to simply
increase the loading of the polymer.
[0052] According to the invention, these benefits permit the use of
formulations for a treatment fluid with a surfactant or an
increased concentration of a surfactant under conditions that are
beyond the viscosity parameters that have been previously used with
substantially identical formulations with such concentrations of
the surfactant. Thus, the formulations of viscosified treatment
fluid according to the invention have not been previously employed
in treating a subterranean formation that is desired to be treated
with a fluid capable of achieving a particularly desired viscosity
at a desired temperature for a desired time that was previously
believed to be beyond the useful parameters of the treatment fluid.
The relationship between the concentration of the surfactant and
the increased thermal stability of the treatment fluid had not been
previously recognized in the art. Therefore, the formulations
according to the invention had not been previously used in
treatments of subterranean formations that required a certain
viscosity with a greater temperature and time stability than
heretofore though possible for such a formulation.
[0053] The surfactant can be, and often is, in a blend with one or
more solvents prior to mixing the surfactant with the base fluid in
making a treatment fluid. The solvent is selected for properties
that help improve the handling characteristics of the surfactant.
Preferably, the amount of the solvent in the surfactant blend is at
least sufficient to substantially improve the handling
characteristics of the surfactant, but not in such concentration as
to unnecessarily dilute the surfactant. Preferably, the solvent in
the surfactant blend does not substantially affect the viscosity or
thermal stability of the treatment fluid. Because the concentration
of the solvent in the surfactant blend preferably does not unduly
dilute the surfactant, when the relatively low loading of the
surfactant blend is mixed with the base fluid to form the treatment
fluid, the solvent in the surfactant is also in relatively low
concentration in the base fluid and would not be expected to
substantially affect the viscosity or thermal stability of the
treatment fluid.
[0054] Thus, a treatment fluid made with a surfactant in a solvent
blend is expected to be otherwise substantially identical to a
treatment fluid made with less surfactant. According to a preferred
embodiment of one aspect of the invention, an otherwise
substantially identical treatment fluid without any of the
surfactant would not achieve the desired viscosity at the desired
temperature for the desired time. According to a preferred
embodiment of another aspect of the invention, the polymer is at a
lower concentration in the base fluid than would be required for an
otherwise substantially identical treatment fluid without any of
the surfactant to achieve the desired viscosity at the desired
temperature for the desired time.
[0055] According to a preferred embodiment of the invention, the
surfactant is preferably selected to be effective to increase the
thermal stability of the viscosifying agent. According to another
preferred embodiment of the invention, the surfactant is at a
substantially higher concentration than would be used for
surfactant purposes. More particularly, the surfactant is at a
concentration greater than a concentration that would be used for
the emulsion prevention, foaming, or surface tension reduction.
Increasing the concentration above the concentrations used for
these traditional surfactant purposes unexpectedly provides
proportionately increasing thermal stability to a viscosified
treatment fluid.
[0056] One preferred class of surfactants is non-ionic surfactants.
Examples of non-ionic surfactants suitable for use according to the
invention include linear ethoxylates, branched ethoxylates, linear
alkyl ethoxylated alcohols, branched alkyl ethoxylated alcohols,
linear propoxylates, linear alkyl propoxylated alcohols,
phenol-formaldehyde non-ionic resin blends, and any combination in
any proportion of the foregoing. More specific examples include
alkoxylated lanolin oil, castor oil ethoxylate, diethylene glycol
monotallowate, ethoxylated fatty alcohols, ethoxylated nonylphenol,
glyceryl tribehenate, polyglyceryl-3 diisostearate, and tallow
amine ethoxylates. According to a presently most preferred
embodiment of the invention, the non-ionic surfactant comprises a
nonylphenol ethoxylate. According to another presently most
preferred embodiment of the invention, the non-ionic surfactant
comprises an alkyl polyglycoside.
[0057] Another preferred class of surfactants is anionic. Examples
of anionic surfactants suitable for use according to the invention,
the anionic surfactant include sulfonic acid such as dodecylbenzene
sulfonic acid, salts of sulfonic acid, sulfonate such as methyl
ester sulfonate, fatty acid, and salts of fatty acid such as sodium
laurate.
[0058] It is also envisioned that a fluid system can be devised
utilizing cationic, amphoteric, or zwitterionic surfactants.
Finally, it is also readily envisioned that combinations of
nonionic, anionic, cationic, amphoteric, and/or zwitterionic may be
utilized.
[0059] The discovery that a surfactant is capable of increasing the
thermal stability of a viscosified fluid permits higher
concentrations of the surfactant to be used as a thermal stabilizer
instead of traditional non-surfactant stabilizers such as methanol,
oxygen scavengers, or reducing agents. For example, there is a
concern regarding the flammability and health concerns in using
methanol. Further, in some wells there is a concern that sodium
thiosulfate provides a source of sulfates that can contribute to
barium sulfate scaling. Having an alternative to such traditional
thermal stabilizers is of major value.
[0060] According to a further aspect of the invention, it has been
also been discovered that a surfactant provides increased and
synergistic benefits of thermally stabilizing a viscosified fluid
when used in conjunction with a non-surfactant thermal stabilizer.
Preferably, the non-surfactant thermal stabilizer is selected from
the group consisting of: thiosulfates, methanol, formate brines,
and any combination thereof in any combination. According to the
presently most preferred embodiment of the invention, the
non-surfactant thermal stabilizer comprises sodium thiosulfate.
[0061] According to preferred embodiment of the invention, the
treatment fluid further comprises gravel, which can be used, for
example, in gravel packing a subterranean formation for fines
control. According to another preferred embodiment, the treatment
fluid further comprises proppant, which can be used, for example,
in hydraulic fracturing of a subterranean formation. According to
yet another preferred embodiment, the treatment fluid further
comprises resin. It is noted, however, that the viscosity of a
treatment fluid is normally measured without any gravel, proppant,
or resin components.
[0062] According to a preferred embodiment of the invention, the
step of introducing the treatment fluid into a subterranean
formation further comprises introducing the treatment fluid at a
rate and pressure sufficient to form at least one fracture in the
subterranean formation.
[0063] The invention will be illustrated with the following
examples, which in general demonstrate that a surfactant
unexpectedly increases the viscosity and/or thermal stability of a
viscosified treatment fluid. Further, the following examples
demonstrate that a surfactant and a non-surfactant thermal
stabilizer used together unexpectedly and synergistically increase
the viscosity and/or thermal stability of a viscosified treatment
fluid.
EXAMPLES
[0064] In all the following examples, the gel system was a
borate-crosslinked, 50 lb/Mgal hydroxyproyl guar ("HPG") in 4% by
weight KCl water at a pH of about 10.5.
[0065] The surfactant in all the following examples was a non-ionic
surfactant comprising nonylphenol ethoxylates. The surfactant was
in a blend with a non-ionic non-emulsifier of light aromatic
solvent and isopropyl alcohol. Further, additional experiments to
the following examples were conducted that demonstrated the
solvents in the surfactant blend have no effect on the viscosity or
thermal stability of the treatment fluid sample. In addition,
additional experiments to the following examples demonstrated
similar effects on increasing the viscosity and thermal stability
of viscosified fluids to the effects demonstrated by the following
examples are obtained with other surfactants, such as alkyl
polyglycoside.
Example 1
[0066] In Example 1, Sample 1 was a borate-crosslinked HPG gel
prepared without any of the surfactant blend, and Sample 2
contained 1 gal/Mgal of the surfactant blend.
[0067] Experiments on Samples 1 and 2 were conducted using a
Nordman Model 50 viscometer according to a modified API2 test
procedure as the sample was rapidly heated from room temperature to
240.degree. F. in about 20 minutes and then held at 240.degree. F.
Viscosity was frequently measured at a shear rate of 81/sec over a
period of more than 3 hours.
[0068] The results of these experiments on Sample 1 and Sample 2
shown in the graph of FIG. 1 demonstrate an unexpectedly improved
thermal stability of a borate crosslinked HPG gel with 1 gal/Mgal
of the surfactant blend compared to an otherwise identical
treatment fluid without any of the surfactant blend. In other
words, the improved thermal stability is observed compared to an
otherwise substantially identical treatment fluid without any of
the surfactant.
Example 2
[0069] In Example 2, experiments were conducted to study the effect
of varying the concentration of the surfactant in the
borate-crosslinked HPG gel. Sample 2 contained 1 gal/Mgal of the
surfactant blend. Sample 3 contained 2 gal/Mgal of the surfactant
blend. Sample 4 contained 3 gal/Mgal of the surfactant blend.
[0070] Experiments on Samples 2, 3, and 4 were conducted using a
Nordman Model 50 viscometer according to a modified API2 test
procedure as the sample was rapidly heated from room temperature to
285.degree. F. (140.degree. C.) in about 20 minutes and then held
at 285.degree. F. (140.degree. C.). Viscosity was frequently
measured at a shear rate of 81/sec over a period of more than 3
hours.
[0071] The results shown in the graph of FIG. 2 demonstrate that
increased surfactant concentrations unexpectedly improve the
thermal stability of a borate-crosslinked HPG gel.
Example 3
[0072] In this Example, four gel samples of the borate-crosslinked,
50 lb/Mgal HPG in 4% KCl water at a pH of about 10.5 were prepared
containing varying amounts of the surfactant blend and sodium
thiosulfate, as shown in Table 1: TABLE-US-00001 TABLE 1 Sample #
Gal/Mgal surfactant blend Lb/Mgal sodium thiosulfate 5 0 0 6 3 0 7
0 1 8 3 1
[0073] Samples 5, 6, 7, and 8 were evaluated on a Nordman Model 50
viscometer using a modified API2 test procedure as the sample was
rapidly heated from room temperature to 285.degree. F. (140.degree.
C.) in about 20 minutes and then held at 285.degree. F.
(140.degree. C.). Viscosity was frequently measured at a shear rate
of 81/sec over a period of about 1.5 hours.
[0074] The results shown in the graph of FIG. 3 demonstrate an
unexpected synergistic relationship between a surfactant and sodium
thiosulfate for improving the thermal stability of a borate
crosslinked HPG gel.
Example 4
[0075] In this Example, experiments were conducted to study the
effect of the surfactant on test samples of an HPG base gel before
and after heating the gel. Sample 9 contained 3 gal/Mgal of the
surfactant blend. Sample 10 contained no surfactant blend.
[0076] Before heating, the samples are referred to as Sample 9a and
Sample 10a. The viscosity of Samples 9a and 10a was measured on an
ATS Stresstech Rheometer at room temperature and at shear rates
ranging from about 0.1 to about 1,000 sec.sup.-1.
[0077] After measuring the viscosity of the samples 9a and 10a at
room temperature, each sample was then heated to 285.degree. F. for
15 minutes and allowed to cool back to room temperature. After
heating, the samples are referred to as Sample 9b and Sample 10b.
The viscosity of Samples 9b and 10b was measured on a Stresstech
Rheometer at room temperature and at shear rates ranging from about
0.1 to about 1,000 sec.sup.-1.
[0078] The results of this Example 4 are plotted in the graph of
FIG. 4.
[0079] In considering the results, it is first important to first
observe that there is no appreciable difference between the
viscosity curves of FIG. 4 for Sample 9a with the surfactant blend
and for Sample 10a without the surfactant blend. This is important
because it demonstrates that none of the ingredients of the
surfactant blend at 3 gal/Mgal appreciably affect the viscosity
before heating the fluid. Further, the concentration of the
isopropyl alcohol is too low to affect the viscosity of the
treatment fluid samples. Thus, Sample 9 is otherwise substantially
identical to treatment fluid Sample 10 without any of the
surfactant.
[0080] After heating the samples, however, there is a dramatic
difference between the viscosity curves of FIG. 4 for Sample 9b
with the surfactant blend and for Sample 10b without the surfactant
blend. These results show that the presence of the surfactant slows
down the thermal degradation of a polymer. In fact, the viscosity
of the tested HPG gel with the surfactant was nearly 5 times better
than the gel with no surfactant (Table 2). TABLE-US-00002 TABLE 2
Sample Fluid Visc. @ 1 s.sup.-1 HPG gel with 3 gal/Mgal surfactant
before heating 1436 (sample 9a) HPG gel with no surfactant before
heating 1436 (sample 10a) HPG gel with 3 gal/Mgal surfactant after
heating 420 (sample 9b) HPG gel with no surfactant after heating 87
(sample 10b )
[0081] The foregoing descriptions of specific embodiments of the
present invention have been presented for purposes of illustration
and description. They are not intended to be exhaustive or to limit
the invention to the precise forms disclosed, and obviously many
modifications and variations are possible in light of the above
teaching. The embodiments were chosen and described in order to
best explain the principles of the invention and its practical
application, to thereby enable others skilled in the art to best
utilize the invention and various embodiments with various
modifications as are suited to the particular use contemplated. It
is intended that the scope of the invention be defined by the
claims appended hereto and their equivalents.
* * * * *