U.S. patent application number 10/850128 was filed with the patent office on 2005-11-24 for viscosified treatment fluids comprising scleroglucan or diutan and associated methods.
Invention is credited to Pauls, Richard, Robb, Ian D..
Application Number | 20050261138 10/850128 |
Document ID | / |
Family ID | 34679485 |
Filed Date | 2005-11-24 |
United States Patent
Application |
20050261138 |
Kind Code |
A1 |
Robb, Ian D. ; et
al. |
November 24, 2005 |
Viscosified treatment fluids comprising scleroglucan or diutan and
associated methods
Abstract
The present invention relates to viscosified treatment fluids
comprising gelling agents that comprise scleroglucan or diutan, and
their use in industrial and oil field operations. In certain
embodiments, the present invention provides methods of treating a
portion of a subterranean formation with a viscosified treatment
comprising a gelling agent that comprises scleroglucan or diutan.
Methods of fracturing, gravel packing, and producing hydrocarbons
also are provided. Viscosified treatment fluid compositions and
methods of making such exemplary compositions are provided as
well.
Inventors: |
Robb, Ian D.; (Duncan,
OK) ; Pauls, Richard; (Duncan, OK) |
Correspondence
Address: |
Robert A. Kent
Halliburton Energy Services
2600 S. 2nd Street
Duncan
OK
73536-0440
US
|
Family ID: |
34679485 |
Appl. No.: |
10/850128 |
Filed: |
May 20, 2004 |
Current U.S.
Class: |
507/209 |
Current CPC
Class: |
C09K 8/68 20130101; C09K
8/706 20130101; C09K 8/685 20130101; C09K 2208/26 20130101; C09K
8/905 20130101 |
Class at
Publication: |
507/209 |
International
Class: |
E21B 043/00 |
Claims
What is claimed is:
1. A method of treating a portion of a subterranean formation
comprising the steps of: providing a viscosified treatment fluid
that comprises a gelling agent that comprises diutan; treating the
portion of the subterranean formation; and reducing the viscosity
of the viscosified treatment fluid using a breaker that comprises a
peroxide.
2. The method of claim 1 wherein the breaker is present in an
amount sufficient to reduce the viscosity of the viscosified
treatment fluid so as to facilitate the recovery of the fluid at
the surface.
3. The method of claim 1 wherein the peroxide is present in an
amount of from about 0.1 to about 10 gallons of peroxide per 1000
gallons of the viscosified treatment fluid.
4. The method of claim 1 wherein the viscosified treatment fluid
comprises fresh water, salt water, or a brine.
5. The method of claim 1 wherein the viscosified treatment fluid
comprises a monovalent brine.
6. The method of claim 1 wherein the viscosified treatment fluid
comprises a salt.
7. The method of claim 6 wherein the salt comprises potassium
chloride, sodium bromide, ammonium chloride, cesium formate,
potassium formate, sodium formate, sodium nitrate, calcium bromide,
zinc bromide, or sodium chloride.
8. The method of claim 1 wherein the viscosified treatment fluid
comprises a pH control additive, a surfactant, a bactericide, a
crosslinker, a fluid loss control additive, or a combination
thereof.
9. The method of claim 8 wherein the pH control additive comprises
a chelating agent, a base, an acid, a combination of a chelating
agent and an acid, or a combination of a chelating agent and a
base.
10. The method of claim 1 wherein the breaker comprises tert-butyl
hydroperoxide or tert-amyl hydroperoxide.
11. The method of claim 1 wherein the breaker comprises
encapsulated breaker particles that comprise a breaker and a
coating material.
12. The method of claim 11 wherein the coating material comprises a
degradable polymeric material.
13. The method of claim 12 wherein the degradable polymeric
material is a polysaccharide, a chitin, a chitosan, a protein, an
aliphatic polyester, a poly(lactide), a poly(glycolide), a
poly(.epsilon.-caprolactone), a poly(hydroxybutyrate), a
poly(anhydride), an aliphatic polycarbonate, an orthoester, a
poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a
polyphosphazene, or a combination thereof.
14. The method of claim 1 wherein the viscosified treatment fluid
comprises an activator or a retarder that is compatible with the
breaker.
15. The method of claim 14 wherein the retarder comprises sodium
thiosulfate.
16. The method of claim 1 wherein the viscosified treatment fluid
comprises a stabilizer.
17. The method of claim 16 wherein the stabilizer comprises sodium
thiosulfate.
18. A method of reducing the viscosity of a viscosified treatment
fluid that comprises a gelling agent that comprises diutan
comprising contacting the viscosified treatment fluid with a
breaker that comprises a peroxide.
19. The method of claim 18 wherein the breaker is present in an
amount sufficient to reduce the viscosity of the viscosified
treatment fluid so as to facilitate the recovery of the fluid at
the surface.
20. The method of claim 18 wherein the peroxide is present in an
amount of from about 0.1 to about 10 gallons of peroxide per 1000
gallons of the viscosified treatment fluid.
21. The method of claim 18 wherein the breaker comprises tert-butyl
hydroperoxide or tert-amyl hydroperoxide.
22. The method of claim 18 wherein the breaker comprises
encapsulated breaker particles that comprise a breaker and a
coating material.
23. The method of claim 22 wherein the coating material comprises a
degradable polymeric material.
24. The method of claim 23 wherein the degradable polymeric
material is a polysaccharide, a chitin, a chitosan, a protein, an
aliphatic polyester, a poly(lactide), a poly(glycolide), a
poly(.epsilon.-caprolactone), a poly(hydroxybutyrate), a
poly(anhydride), an aliphatic polycarbonate, an orthoester, a
poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a
polyphosphazene, or a combination thereof.
25. A method of making a viscosified treatment fluid comprising
diutan comprising the step of dissolving diutan in an aqueous fluid
to form a viscosified treatment fluid comprising diutan.
26. The method of claim 25 wherein the aqueous fluid comprises a
salt.
27. The method of claim 25 wherein the aqueous fluid comprises
potassium chloride.
28. The method of claim 25 wherein the aqueous fluid is a 20%
potassium chloride solution.
29. The method of claim 25 wherein the viscosified treatment fluid
comprising diutan has a density in the range of from about 8.4
pounds per gallon to about 20.5 pounds per gallon.
30. A method of placing a gravel pack in a portion of a
subterranean formation comprising: providing a viscosified gravel
pack fluid comprising gravel and a gelling agent that comprises
diutan; contacting the portion of the subterranean formation with
the viscosified gravel pack fluid so as to place a gravel pack in
or near a portion of the subterranean formation; and reducing the
viscosity of the viscosified gravel pack fluid with a breaker
comprising a peroxide.
31. The method of claim 30 wherein the breaker is present in an
amount sufficient to reduce the viscosity of the viscosified
treatment fluid so as to facilitate the recovery of the fluid at
the surface.
32. The method of claim 30 wherein the peroxide is present in an
amount of from about 0.1 to about 10 gallons of peroxide per 1000
gallons of the viscosified treatment fluid.
33. The method of claim 30 wherein the breaker comprises tert-butyl
hydroperoxide or tert-amyl hydroperoxide.
34. The method of claim 30 wherein the breaker comprises
encapsulated breaker particles that comprise a breaker and a
coating material.
35. The method of claim 34 wherein the coating material comprises a
degradable polymeric material.
36. The method of claim 35 wherein the degradable polymeric
material is a polysaccharide, a chitin, a chitosan, a protein, an
aliphatic polyester, a poly(lactide), a poly(glycolide), a
poly(.epsilon.-caprolactone), a poly(hydroxybutyrate), a
poly(anhydride), an aliphatic polycarbonate, an orthoester, a
poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a
polyphosphazene, or a combination thereof.
37. The method of claim 30 wherein the viscosified gravel pack
fluid has a density of about 8.4 pounds per gallon to about 20.5
pounds per gallon.
38. The method of claim 30 wherein the subterranean formation has a
temperature of about 200.degree. F. or higher.
39. The method of claim 30 wherein the breaker is present in an
amount sufficient to reduce the viscosity of the viscosified gravel
pack fluid to facilitate the recovery of the fluid.
40. A method of fracturing a portion of a subterranean formation
comprising: providing a viscosified fracturing fluid comprising a
gelling agent that comprises diutan; contacting the portion of the
subterranean formation with the viscosified fracturing fluid at a
sufficient pressure to create or enhance at least one fracture in
the subterranean formation; and reducing the viscosity of the
viscosified fracturing fluid with a breaker comprising a
peroxide.
41. The method of claim 40 wherein the viscosified fracturing fluid
comprises proppant.
42. The method of claim 40 wherein the breaker is present in an
amount sufficient to reduce the viscosity of the viscosified
treatment fluid so as to facilitate the recovery of the fluid at
the surface.
43. The method of claim 40 wherein the peroxide is present in an
amount of from about 0.1 to about 10 gallons of peroxide per 1000
gallons of the viscosified treatment fluid.
44. The method of claim 40 wherein the breaker comprises tert-butyl
hydroperoxide or tert-amyl hydroperoxide.
45. The method of claim 40 wherein the breaker comprises
encapsulated breaker particles that comprise a breaker and a
coating material.
46. The method of claim 45 wherein the coating material comprises a
degradable polymeric material.
47. The method of claim 46 wherein the degradable polymeric
material is a polysaccharide, a chitin, a chitosan, a protein, an
aliphatic polyester, a poly(lactide), a poly(glycolide), a
poly(.epsilon.-caprolactone), a poly(hydroxybutyrate), a
poly(anhydride), an aliphatic polycarbonate, an orthoester, a
poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a
polyphosphazene, or a combination thereof.
48. The method of claim 40 wherein the viscosified gravel pack
fluid has a density of about 8.4 pounds per gallon to about 20.5
pounds per gallon.
49. The method of claim 40 wherein the subterranean formation has a
temperature of about 200.degree. F. or higher.
50. The method of claim 40 wherein the viscosified fracturing fluid
further comprises a fluid loss control additive.
51. The method of claim 40 wherein the viscosified treatment fluid
comprises a pH control additive, a surfactant, a bactericide, a
crosslinker, a fluid loss control additive, a stabilizer, or a
combination thereof.
52. A method of servicing or completing a portion of a subterranean
formation comprising: providing a viscosified treatment fluid
comprising a gelling agent that comprises scleroglucan; and
servicing or completing at least a portion of the subterranean
formation with the viscosified treatment fluid.
53. The method of claim 52 wherein servicing or completing at least
a portion of the subterranean formation involves stimulating at
least a portion of the subterranean formation.
54. The method of claim 52 further comprising reducing the
viscosity of the viscosified treatment fluid with a breaker after
treating the portion of the subterranean formation.
55. The method of claim 54 wherein the breaker comprises
encapsulated breaker particles that comprise a breaker and a
coating material.
56. The method of claim 55 wherein the coating material comprises a
degradable polymeric material.
57. The method of claim 56 wherein the degradable polymeric
material is a polysaccharide, a chitin, a chitosan, a protein, an
aliphatic polyester, a poly(lactide), a poly(glycolide), a
poly(.epsilon.-caprolactone), a poly(hydroxybutyrate), a
poly(anhydride), an aliphatic polycarbonate, an orthoester, a
poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a
polyphosphazene, or a combination thereof.
58. The method of claim 52 wherein the viscosified treatment fluid
further comprises a surfactant, a breaker, a bactericide, a
crosslinker, a pH control additive, a stabilizer, or a fluid loss
control additive.
59. The method of claim 52 wherein the viscosified treatment fluid
further comprises a salt.
60. The method of claim 57 wherein the pH control additive
comprises a chelating agent, a base, an acid, a combination of a
chelating agent and an acid, or a combination of a chelating agent
and a base.
61. The method of claim 57 wherein the viscosified treatment fluid
further comprises an activator or a retarder.
62. A method of fracturing a portion of a subterranean formation
comprising: providing a viscosified fracturing fluid comprising a
gelling agent that comprises scleroglucan; and contacting the
portion of the subterranean formation with the viscosified
fracturing fluid at a sufficient pressure to create or enhance at
least one fracture in the subterranean formation.
63. A method of producing hydrocarbons from a subterranean
formation wherein a viscosified treatment fluid comprising a
gelling agent that comprises scleroglucan is used in a completion
or a servicing operation.
64. A method of producing hydrocarbons from a subterranean
formation wherein a viscosified treatment fluid comprising a
gelling agent that comprises diutan is used and the subterranean
formation has a temperature greater than or equal to 200.degree.
F.
65. A method of producing hydrocarbons from a subterranean
formation wherein a viscosified treatment fluid comprising a
gelling agent that comprises diutan and a breaker that comprises a
peroxide are used.
66. A subterranean well treatment system comprising a viscosified
treatment fluid that comprises diutan and a breaker that comprises
a peroxide breaker.
67. The system of claim 66 wherein the breaker comprises tert-butyl
hydroperoxide or tert-amyl hydroperoxide
68. The system of claim 66 wherein at least a portion of the
breaker is encapsulated by a coating.
69. The system of claim 68 wherein the coating comprises a
polysaccharide, a chitin, a chitosan, a protein, an aliphatic
polyester, a poly(lactide), a poly(glycolide), a
poly(.epsilon.-caprolactone), a poly(hydroxybutyrate), a
poly(anhydride), an aliphatic polycarbonate, an orthoester, a
poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a
polyphosphazene, or a combination thereof.
70. The system of claim 66 wherein the breaker is present in an
amount sufficient to reduce the viscosity of the viscosified
treatment fluid to facilitate the recovery of the fluid.
71. The system of claim 66 wherein the viscosified treatment fluid
comprises fresh water, salt water, or a brine.
72. The system of claim 66 wherein the viscosified treatment fluid
comprises a monovalent brine.
73. The system of claim 66 wherein the viscosified treatment fluid
comprises a salt.
74. The system of claim 66 wherein the viscosified treatment fluid
comprises a pH control additive, a surfactant, a bactericide, a
crosslinker, a fluid loss control additive, proppant, gravel, or a
combination thereof.
75. A subterranean well servicing or completion fluid comprising a
gelling agent that comprises scleroglucan.
76. The composition of claim 75 wherein the subterranean well
servicing or completion fluid comprises proppant.
77. The composition of claim 75 wherein the subterranean well
servicing or completion fluid further comprises a surfactant, a
breaker, a bactericide, a crosslinker, a pH control additive, or a
fluid loss control additive.
78. The composition of claim 75 wherein the subterranean well
servicing or completion fluid comprises fresh water, salt water, or
a brine.
79. The composition of claim 75 wherein the subterranean well
treatment fluid further comprises a salt.
80. The composition of claim 79 wherein the salt comprises
potassium chloride, sodium bromide, ammonium chloride, cesium
formate, potassium formate, sodium formate, sodium nitrate, calcium
bromide, zinc bromide, or sodium chloride.
81. The composition of claim 76 wherein the pH control additive
comprises a chelating agent, a base, an acid, a combination of a
chelating agent and an acid, or a combination of a chelating agent
and a base.
82. A method of making a treatment fluid comprising a scleroglucan
gelling agent comprising: dissolving scleroglucan in water to
produce a solution; neutralizing the solution from a pH of about 13
to one of a pH of less than about 12 to form a viscosified
treatment fluid comprising a scleroglucan gelling agent.
83. The method of claim 82 wherein the water comprises a salt.
84. The method of claim 82 wherein the water has a pH of about
13.
85. A viscosified treatment fluid made by the method of claim 82.
Description
BACKGROUND OF THE INVENTION
[0001] The present invention relates to viscosified treatment
fluids used in industrial and oil field operations, and more
particularly, to viscosified treatment fluids comprising gelling
agents that comprise scleroglucan or diutan, and their use in
industrial and oil field operations.
[0002] In industrial and oil field operation, viscosified treatment
fluids are often used to carry particulates into subterranean
formations for various purposes, e.g., to deliver particulates to a
desired location within a well bore. Examples of subterranean
operations that use such viscosified treatment fluids include
servicing and completion operations such as fracturing and gravel
packing. In fracturing, generally, a viscosified fracturing fluid
is used to carry proppant to fractures within the formation, inter
alia, to maintain the integrity of those fractures to enhance the
flow of desirable fluids to a well bore. In sand control operations
such as gravel packing operations, oftentimes a screen, slotted
liner, or other mechanical device is placed into a portion of a
well bore. A viscosified gravel pack fluid is used to deposit
particulates referred to as gravel into the annulus between the
mechanical device and the formation or casing to inhibit the flow
of particulates from a portion of the subterranean formation to the
well bore.
[0003] In most instances, a viscosified treatment fluid should
maintain its viscosity in a subterranean operation until that
operation is completed, after which the fluid may be "broken"
(i.e., its viscosity may be reduced), e.g., so as to drop
particulates from the fluid into a desired location within the
subterranean formation and/or to reclaim it from the subterranean
formation.
[0004] The treatment fluids used in subterranean operations are
predominantly water-based liquids comprising polymeric gelling
agents that may increase their viscosities, inter alia, to enhance
the treatment fluids' sand suspension capabilities. These gelling
agents are usually biopolymers or synthetic polymers that, when
hydrated and at a sufficient concentration, are capable of forming
a viscous solution. Common gelling agents include polysaccharides
such as galactomannan gums, cellulosic polymers, and xanthan.
Viscosified treatment fluids comprising xanthan generally have
sufficient sand suspension properties for lower temperature
operations. At elevated temperatures (e.g., those above about
200.degree. F.), however, the sand suspension properties of such
xanthan treatment fluids are diminished. Consequently, xanthan may
not be a suitable gelling agent for viscosified treatment fluids,
such as fracturing fluid or gravel pack fluids, when those fluids
are used in well bores that comprise elevated temperatures.
SUMMARY OF THE INVENTION
[0005] The present invention relates to viscosified treatment
fluids used in industrial and oil field operations, and more
particularly, to viscosified treatment fluids comprising gelling
agents that comprise scleroglucan or diutan, and their use in
industrial and oil field operations.
[0006] In one embodiment, the present invention provides a method
of treating a portion of a subterranean formation comprising the
steps of: providing a viscosified treatment fluid that comprises a
gelling agent that comprises diutan; treating the portion of the
subterranean formation; and reducing the viscosity of the
viscosified treatment fluid using a breaker that comprises a
peroxide.
[0007] In another embodiment, the present invention provides a
method of reducing the viscosity of a viscosified treatment fluid
that comprises a gelling agent that comprises diutan comprising
contacting the viscosified treatment fluid with a breaker that
comprises a peroxide.
[0008] In another embodiment, the present invention provides a
method of making a viscosified treatment fluid comprising diutan
comprising the step of dissolving diutan in an aqueous fluid to
form a viscosified treatment fluid comprising diutan.
[0009] In another embodiment, the present invention provides a
method of placing a gravel pack in a portion of a subterranean
formation comprising: providing a viscosified gravel pack fluid
comprising gravel and a gelling agent that comprises diutan;
contacting the portion of the subterranean formation with the
viscosified gravel pack fluid so as to place a gravel pack in or
near a portion of the subterranean formation; and reducing the
viscosity of the viscosified gravel pack fluid with a breaker
comprising a peroxide.
[0010] In another embodiment, the present invention provides a
method of fracturing a portion of a subterranean formation
comprising: providing a viscosified fracturing fluid comprising a
gelling agent that comprises diutan; contacting the portion of the
subterranean formation with the viscosified fracturing fluid at a
sufficient pressure to create or enhance at least one fracture in
the subterranean formation; and reducing the viscosity of the
viscosified fracturing fluid with a breaker comprising a
peroxide.
[0011] In another embodiment, the present invention provides a
method of treating a portion of a subterranean formation
comprising: providing a viscosified treatment fluid comprising a
gelling agent that comprises scleroglucan; and treating at least a
portion of the subterranean formation with the viscosified
treatment fluid.
[0012] In another embodiment, the present invention provides a
method of fracturing a portion of a subterranean formation
comprising: providing a viscosified fracturing fluid comprising a
gelling agent that comprises scleroglucan; and contacting the
portion of the subterranean formation with the viscosified
fracturing fluid at a sufficient pressure to create or enhance at
least one fracture in the subterranean formation.
[0013] In another embodiment, the present invention provides a
method of producing hydrocarbons from a subterranean formation
wherein a viscosified treatment fluid comprising a gelling agent
that comprises scleroglucan is used.
[0014] In another embodiment, the present invention provides a
method of producing hydrocarbons from a subterranean formation
wherein a viscosified treatment fluid comprising a gelling agent
that comprises diutan is used and the subterranean formation has a
temperature greater than or equal to 200.degree. F.
[0015] In another embodiment, the present invention provides a
method of producing hydrocarbons from a subterranean formation
wherein a viscosified treatment fluid comprising a gelling agent
that comprises diutan and a breaker that comprises a peroxide are
used.
[0016] In another embodiment, the present invention provides a
subterranean well treatment system comprising a viscosified
treatment fluid that comprises diutan and a breaker that comprises
a peroxide breaker.
[0017] In another embodiment, the present invention provides a
subterranean well treatment fluid comprising a gelling agent that
comprises scleroglucan.
[0018] In another embodiment, the present invention provides a
method of making a treatment fluid comprising a scleroglucan
gelling agent comprising: dissolving scleroglucan in water to
produce a solution; neutralizing the solution from a pH of about 13
to one of a pH of less than about 12 to form a viscosified
treatment fluid comprising a scleroglucan gelling agent.
[0019] The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the
description of the preferred embodiments that follows.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0020] The present invention relates to viscosified treatment
fluids used in industrial and oil field operations, and more
particularly, to viscosified treatment fluids comprising gelling
agents that comprise scleroglucan or diutan, and their use in
industrial and oil field operations. In certain embodiments, the
present invention provides compositions and methods that are
especially suitable for use in well bores comprising elevated
temperatures such as those above 200.degree. F.
[0021] The viscosified treatment fluids of the present invention
generally comprise an aqueous base fluid and a gelling agent that
comprises scleroglucan or diutan. The viscosified treatment fluids
of the present invention may vary widely in density. One of
ordinary skill in the art with the benefit of this disclosure will
recognize the particular density that is most appropriate for a
particular application. The density of the viscosified treatment
fluids of the present invention may range from about 8.4 pounds per
gallon ("ppg") to about 20.5 ppg. The desired density for a
particular viscosified treatment fluid may depend on
characteristics of the subterranean formation, including, inter
alia, the hydrostatic pressure required to control the fluids of
the subterranean formation during placement of the viscosified
treatment fluids, and the hydrostatic pressure which will damage
the subterranean formation. The gelling agents of the present
invention that comprise diutan may be useful in a wide variety of
subterranean treatment operations. The gelling agents of the
present invention that comprise scleroglucan, although useful in a
wide variety of subterranean treatment operations, may be most
suited for stimulation operations and the like.
[0022] Scleroglucan is a neutral fungal polysaccharide.
Scleroglucan is a hydrophilic colloid, which has a tendency to
thicken and stabilize water-based systems by conferring on them a
relatively high viscosity, generally higher than that obtained in
the case of xanthan, for example, at temperatures at or above about
200.degree. F., for identical concentrations of active compounds.
Scleroglucan also appears to be more resistant to pH and
temperature changes than xanthan, and therefore, may impart more
stable viscosities in such conditions. In certain aspects, the
viscosity of a scleroglucan fluid may be virtually independent of
pH between a pH of about 1 and about 12.5 up to a temperature limit
of about 270.degree. F. Generally, the main backbone polymer chain
of scleroglucan comprises (1.fwdarw.3).beta.-D-glucopyranosyl units
with a single .beta.-D-glucopyranosyl group attached to every third
unit on the backbone. Scleroglucan is thought to be resistant to
degradation, even at high temperatures such as those at or above
about 200.degree. F., even after, e.g., 500 days in seawater.
Viscosity data (see Table 1 and Table 2) show that dilute solutions
(e.g., about 0.5% may be shear thinning and stable to at least
250.degree. F. These viscosities illustrate, inter alia,
scleroglucan's suitability for sand suspension and transport
applications.
1TABLE 1 Viscosities (cP) of 1% Scleroglucan, Measured at Various
Temperatures (.degree. C.) and Shear Rates (s.sup.-1), using a
Brookfield PVS Rheometer Shear Rate (s.sup.-1) 70.degree. C.
80.degree. C. 99.degree. C. 108.degree. C. 118.degree. C.
127.degree. C. 8.5 1500 1450 1480 1460 1330 1540 25 520 540 540 550
500 -- 85 180 180 178 175 165 -- 170 100 98 99 93 92 --
[0023]
2TABLE 2 Elastic Moduli G' (Pa) Measured Using a Haake RS 150
Controlled Stress Rheometer at 25.degree. C.; Measurements Made at
1 Hz in the Linear Viscoelastic Region. Xanthan Scleroglucan 1.0%
38 35 0.5% 9 13
[0024] Diutan gum is a polysaccharide designated S-657, which is
prepared by fermentation of a strain of sphingomonas. Its structure
has been elucidated as a hexasaccharide having a tetrasaccharide
repeat unit in the backbone that comprises glucose and rhamnose
units and di-rhamnose side chain. It is believed to have
thickening, suspending, and stabilizing properties in aqueous
solutions. Polysaccharide S-657 is composed principally of
carbohydrates, about 12% protein, and about 7% (calculated as
O-acetyl) acyl groups, the carbohydrate portion containing about
19% glucuronic acid, and the neutral sugars rhamnose and glucose in
the approximate molar ratio of about 2:1. Details of the diutan gum
structure may be found in an article by Diltz et al., "Location of
O-acetyl Groups in S-657 Using the Reductive-Cleavage Method,"
CARBOHYDRATE RESEARCH, Vol. 331, p. 265-270 (2001), which is hereby
incorporated by reference in its entirety. Details of preparing
diutan gum may be found in U.S. Pat. No. 5,175,278, which is hereby
incorporated by reference in its entirety. A suitable source of
diutan is "GEOVIS XT," which is commercially available from Kelco
Oil Field Group, Houston, Tex. The elastic moduli of some diutan
solutions as compared to xanthan solutions are shown in Table
3.
3TABLE 3 Elastic Moduli (G') of Diutan and Xanthan Solutions
Solution Composition G'(Pa) 0.5% Diutan in water 15.0 0.5% Xanthan
in water 11.8 0.5% Diutan in 6% NaCl 19.0 0.5% Xanthan in 6% NaCl
12.8 0.75% Diutan in water 33.0 0.75% Diutan in 20% KCl 29.0
[0025] The aqueous base fluids of the treatment fluids of the
present invention generally comprise fresh water, salt water, or a
brine (e.g., a saturated salt water). Other water sources may be
used, including those comprising divalent or trivalent cations,
e.g., magnesium, calcium, zinc, or iron. If a water source is used
which contains such divalent or trivalent cations in concentrations
sufficiently high to be problematic, then such divalent or
trivalent salts may be removed, either by a process such as reverse
osmosis, or by raising the pH of the water in order to precipitate
out such divalent salts to lower the concentration of such salts in
the water before the water is used. Monovalent brines are preferred
and, where used, may be of any weight. Salts may be added to the
water source, inter alia, to provide a brine to produce a treatment
fluid having a desired density or other characteristics. One of
ordinary skill in the art with the benefit of this disclosure will
recognize the particular type of salt appropriate for a particular
application, given considerations such as protection of the
formation, the presence or absence of reactive clays in the
formation adjacent to the well bore, and the factors affecting
wellhead control. A wide variety of salts may be suitable. Examples
of suitable salts include, inter alia, potassium chloride, sodium
bromide, ammonium chloride, cesium formate, potassium formate,
sodium formate, sodium nitrate, calcium bromide, zinc bromide, and
sodium chloride. An artisan of ordinary skill with the benefit of
this disclosure will recognize the appropriate concentration of a
particular salt to achieve a desired density given factors such as
the environmental regulations that may pertain. Also, the
composition of the water used also will dictate whether and what
type of salt is appropriate.
[0026] In certain embodiments, the viscosified treatment fluids of
the present invention also may comprise pH control additives,
surfactants, breakers, bactericides, crosslinkers, fluid loss
control additives, stabilizers, combinations thereof, or the like.
In a preferred embodiment, a gelling agent comprising diutan and a
breaker comprising a peroxide are included in a treatment fluid of
the present invention.
[0027] Suitable pH control additives, in certain embodiments, may
comprise bases, chelating agents, acids, or combinations of
chelating agents and acids or bases. A pH control additive may be
necessary to maintain the pH of the treatment fluid at a desired
level, e.g., to improve the dispersion of the gelling agent in the
aqueous base fluid. In some instances, it may be beneficial to
maintain the pH at neutral or above 7.
[0028] In some embodiments, the pH control additive may be a
chelating agent. When added to the treatment fluids of the present
invention, such a chelating agent may chelate any dissolved iron
that may be present in the water. Such chelating may prevent free
iron from crosslinking the gelling agent molecules. Such
crosslinking may be problematic because, inter alia, it may cause
severe filtration problems. Any suitable chelating agent may be
used with the present invention. Examples of suitable chelating
agents include an anhydrous form of citric acid, commercially
available under the tradename "FE-2.TM." Iron Sequestering Agent
from Halliburton Energy Services, Inc., of Duncan, Okla. Another
example of a suitable chelating agent is a solution of citric acid
dissolved in water, commercially available under the tradename
"FE-2A.TM." from Halliburton Energy Services, Inc., of Duncan,
Okla. Other chelating agents that are suitable for use with the
present invention include, inter alia, nitrilotriacetic acid and
any acid form of ethylene diamine tetracetic acid ("EDTA").
Generally, the chelating agent is present in an amount sufficient
to prevent crosslinking of the gelling agent molecules by any free
iron that may be present. In one embodiment, the chelating agent
may be present in an amount of from about 0.02% to about 2.0% by
weight of the treatment fluid. In another embodiment, the chelating
agent is present in an amount in the range of from about 0.02% to
about 0.5% by weight of the treatment fluid. One of ordinary skill
in the art with the benefit of this disclosure will be able to
determine the proper concentration of chelating agents for a
particular application.
[0029] In another embodiment, the pH control additive may be an
acid. Any known acid may be suitable with the treatment fluids of
the present invention. Examples of suitable acids include, inter
alia, hydrochloric acid, acetic acid, formic acid and citric
acid.
[0030] The pH control additive also may comprise a base to elevate
the pH of the mixture that is formed once the gelling agent has
been added to and dispersed within the treatment fluid. It may be
desirable to elevate the pH of the mixture, inter alia, to achieve
a desired dispersion of the gelling agent. Generally, a base may be
used to elevate the pH of the mixture to greater than or equal to
about 7. In one embodiment, a base may be used to elevate the pH of
the mixture to greater than or equal to about 13. Any known base
that is compatible with the gelling agents of the present invention
can be used in the viscosified treatment fluids of the present
invention. Examples of suitable bases include sodium hydroxide,
potassium carbonate, potassium hydroxide and sodium carbonate. An
example of a suitable base is a solution of 25% sodium hydroxide
commercially available from Halliburton Energy Services, Inc., of
Duncan, Okla., under the tradename "MO-67.TM." pH Controlling
Additive. One of ordinary skill in the art with the benefit of this
disclosure will recognize the suitable bases that may be used to
achieve a desired pH elevation.
[0031] In still another embodiment, the pH control additive may
comprise a combination of an acid and a chelating agent or a base
and a chelating agent. Such combinations may be suitable when,
inter alia, the addition of a chelating agent (in an amount
sufficient to chelate the iron present) is insufficient by itself
to achieve the desired pH reduction.
[0032] In some embodiments, the viscosified treatment fluids of the
present invention may include surfactants, e.g., to improve the
compatibility of the viscosified treatment fluids of the present
invention with other fluids (like any formation fluids) that may be
present in the well bore. An artisan of ordinary skill with the
benefit of this disclosure will be able to identify the type of
surfactant as well as the appropriate concentration of surfactant
to be used. Suitable surfactants may be used in a liquid or powder
form. Where used, the surfactants are present in the viscosified
treatment fluid in an amount sufficient to prevent incompatibility
with formation fluids or well bore fluids. In an embodiment where
liquid surfactants are used, the surfactants are generally present
in an amount in the range of from about 0.01% to about 5.0% by
volume of the viscosified treatment fluid. In one embodiment, the
liquid surfactants are present in an amount in the range of from
about 0.1% to about 2.0% by volume of the viscosified treatment
fluid. In embodiments where powdered surfactants are used, the
surfactants may be present in an amount in the range of from about
0.001% to about 0.5% by weight of the viscosified treatment fluid.
Examples of suitable surfactants are non-emulsifiers commercially
available from Halliburton Energy Services, Inc., of Duncan, Okla.,
under the tradenames "LOSURF-259.TM.," "LOSURF-300.TM.,"
"LOSURF-357.TM.," and "LOSURF-400.TM.." Another example of a
suitable surfactant is a non-emulsifier commercially available from
Halliburton Energy Services, Inc., of Duncan, Okla., under the
tradename "NEA-96M.TM." Surfactant.
[0033] In some embodiments, the viscosified treatment fluids of the
present invention may contain bactericides, inter alia, to protect
both the subterranean formation as well as the viscosified
treatment fluid from attack by bacteria. Such attacks may be
problematic because they may lower the viscosity of the viscosified
treatment fluid, resulting in poorer performance, such as poorer
sand suspension properties, for example. Any bactericides known in
the art are suitable. An artisan of ordinary skill with the benefit
of this disclosure will be able to identify a suitable bactericide
and the proper concentration of such bactericide for a given
application. Where used, such bactericides are present in an amount
sufficient to destroy all bacteria that may be present. Examples of
suitable bactericides include a 2,2-dibromo-3-nitrilopropionamide,
commercially available under the tradename "BE-3S.TM." Surfactant
from Halliburton Energy Services, Inc., of Duncan, Okla., and a
2-bromo-2-nitro-1,3-propanediol commercially available under the
tradename "BE-6.TM." Surfactant from Halliburton Energy Services,
Inc., of Duncan, Okla. In one embodiment, the bactericides are
present in the viscosified treatment fluid in an amount in the
range of from about 0.001% to about 0.003% by weight of the
viscosified treatment fluid. Another example of a suitable
bactericide is a solution of sodium hypochlorite, commercially
available under the tradename "CAT-1.TM." chemical from Halliburton
Energy Services, Inc., of Duncan, Okla. In certain embodiments,
such bactericides may be present in the viscosified treatment fluid
in an amount in the range of from about 0.01% to about 0.1% by
volume of the viscosified treatment fluid. In certain preferred
embodiments, when bactericides are used in the viscosified
treatment fluids of the present invention, they are added to the
viscosified treatment fluid before the gelling agent is added.
[0034] The viscosified treatment fluids of the present invention
also (optionally) may comprise a crosslinker to crosslink the
polymeric components of the gelling agent in the viscosified
treatment fluid. Suitable crosslinkers include boron derivatives;
potassium derivatives, including but not limited to, potassium
periodate or potassium iodate; ferric iron derivatives; magnesium
derivatives; and the like. Such crosslinking of the polymeric
components of the gelling agent may be desirable where it is
desirable to make a treatment fluid more viscous. One of ordinary
skill in the art with the benefit of this disclosure will recognize
when such crosslinkers are appropriate and what particular
crosslinker will be most suitable. It should be noted that suitable
viscosities could be obtained for viscosified treatment fluids that
comprise gelling agents that comprise diutan without using
crosslinkers.
[0035] The viscosified treatment fluids of the present invention
also may comprise breakers capable of reducing the viscosity of the
viscosified treatment fluid at a desired time. Examples of such
suitable breakers for viscosified treatment fluids of the present
invention that include a gelling agent that comprises scleroglucan
include, but are not limited to, sodium chlorite, hypochlorite,
perborate, persulfates, peroxides, including organic peroxides.
Other suitable breakers include suitable acids. Preferred examples
of suitable breakers for viscosified treatment fluids of the
present invention that include a gelling agent that comprises
diutan include peroxide breakers. Preferred examples include
tert-butyl hydroperoxide and tert-amyl hydroperoxide. Sodium
persulfate and sodium chlorite are not preferred breakers for
viscosified treatment fluids of the present invention that include
a gelling agent that comprises diutan because optimal degradation
generally may not occur within a desirable time period. A breaker
may be included in a viscosified treatment fluid of the present
invention in an amount and form sufficient to achieve the desired
viscosity reduction at a desired time. The breaker may be
formulated to provide a delayed break, if desired. For example, a
suitable breaker may be encapsulated if desired. Suitable
encapsulation methods are known to those skilled in the art. One
suitable encapsulation method that may be used involves coating the
chosen breakers with a material that will degrade when downhole so
as to release the breaker when desired. Resins that may be suitable
include, but are not limited to, polymeric materials that will
degrade when downhole. The terms "degrade," "degradation," or
"degradable" refer to both the two relatively extreme cases of
hydrolytic degradation that the degradable material may undergo,
i.e., heterogeneous (or bulk erosion) and homogeneous (or surface
erosion), and any stage of degradation in between these two. This
degradation can be a result of, inter alia, a chemical or thermal
reaction or a reaction induced by radiation. Suitable examples
include polysaccharides such as dextran or cellulose; chitins;
chitosans; proteins; aliphatic polyesters; poly(lactides);
poly(glycolides); poly(.epsilon.-caprolactones);
poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates;
orthoesters, poly(orthoesters); poly(amino acids); poly(ethylene
oxides); and polyphosphazenes. If used, a breaker should be
included in a composition of the present invention in an amount
sufficient to facilitate the desired reduction in viscosity in a
viscosifier treatment fluid. For instance, peroxide concentrations
that may be used vary from about 0.1 to about 10 gallons of
peroxide per 1000 gallons of the viscosified treatment fluid.
Optionally, the viscosified treatment fluid may contain an
activator or a retarder, inter alia, to optimize the break rate
provided by the breaker. Any known activator or retarder that is
compatible with the particular breaker used is suitable for use in
the present invention. Examples of such suitable activators
include, but are not limited to, chelated iron, copper, cobalt, and
reducing sugars. An example of a suitable retarder includes sodium
thiosulfate diethylene triamine. In some embodiments, the sodium
thiosulfate may be used in a range of from about 5 to about 2000
lbs. per 1000 gallons of viscosified treatment fluid. An artisan of
ordinary skill with the benefit of this disclosure will be able to
identify a suitable activator or retarder and the proper
concentration of such activator or retarder for a given
application.
[0036] If desired, stabilizers may be added to the viscosified
treatment fluids of the present invention, e.g., in
high-temperature gravel packing operations. Suitable stabilizers
include sodium thiosulfate. Such stabilizers may be useful when the
viscosified treatment fluids of the present invention are utilized
in a subterranean formation having a temperature above about
200.degree. F.
[0037] In certain preferred embodiments, certain embodiments of the
viscosified treatment fluids of the present invention may be
prepared according to the following process. The scleroglucan may
be dissolved in water or a salt solution (e.g., a 20% KCl salt
solution) or preferably in a solution at a pH of about 13. The
solution is then neutralized to a pH below about 12, and then salt
may be added. This process is suitable for viscosified treatment
fluids comprising a concentration of scleroglucan from about 0.1%
to about 10% of the viscosified treatment fluid.
[0038] In certain preferred embodiments, diutan may be dissolved in
water or salt solutions. For instance, diutan dissolves in water or
20% KCl by simply stirring.
[0039] In one embodiment, the present invention provides a method
of treating a portion of a subterranean formation comprising the
steps of: providing a viscosified treatment fluid that comprises a
gelling agent that comprises diutan; treating the portion of the
subterranean formation; and reducing the viscosity of the
viscosified treatment fluid using a breaker that comprises a
peroxide.
[0040] In another embodiment, the present invention provides a
method of making a viscosified treatment fluid comprising diutan
comprising the step of dissolving diutan in an aqueous fluid to
form a viscosified treatment fluid comprising diutan.
[0041] In another embodiment, the present invention provides a
method of placing a gravel pack in a portion of a subterranean
formation comprising: providing a viscosified gravel pack fluid
comprising gravel and a gelling agent that comprises diutan;
contacting the portion of the subterranean formation with the
viscosified gravel pack fluid so as to place a gravel pack in or
near a portion of the subterranean formation; and reducing the
viscosity of the viscosified gravel pack fluid with a breaker
comprising a peroxide.
[0042] In another embodiment, the present invention provides a
method of fracturing a portion of a subterranean formation
comprising: providing a viscosified fracturing fluid comprising a
gelling agent that comprises diutan; contacting the portion of the
subterranean formation with the viscosified fracturing fluid at a
sufficient pressure to create or enhance at least one fracture in
the subterranean formation; and reducing the viscosity of the
viscosified fracturing fluid with a breaker comprising a
peroxide.
[0043] In another embodiment, the present invention provides a
method of treating a subterranean formation comprising: providing a
viscosified treatment fluid comprising a gelling agent that
comprises scleroglucan; and treating at least a portion of the
subterranean formation with the viscosified treatment fluid.
[0044] In another embodiment, the present invention provides a
method of fracturing a portion of a subterranean formation
comprising: providing a viscosified fracturing fluid comprising a
gelling agent that comprises scleroglucan; and contacting the
portion of the subterranean formation with the viscosified
fracturing fluid at a sufficient pressure to create or enhance at
least one fracture in the subterranean formation.
[0045] In another embodiment, the present invention provides a
subterranean well treatment system comprising a viscosified
treatment fluid that comprises diutan and a breaker that comprises
a peroxide breaker.
[0046] In another embodiment, the present invention provides a
method of producing hydrocarbons comprising the steps of: providing
a viscosified treatment fluid that comprises a gelling agent that
comprises diutan, using the viscosified treatment fluid in a
subterranean operation, and reducing the viscosity of the
viscosified treatment fluid using a breaker that comprises a
peroxide.
[0047] In another embodiment, the present invention provides a
subterranean well stimulation or completion fluid comprising a
gelling agent that comprises scleroglucan.
[0048] In another embodiment, the present invention provides a
method of making a treatment fluid comprising a scleroglucan
gelling agent comprising: dissolving scleroglucan in water to
produce a solution; neutralizing the solution from a pH of about 13
to one of a pH of less than about 12 to form a viscosified
treatment fluid comprising a scleroglucan gelling agent.
[0049] To facilitate a better understanding of the present
invention, the following examples of some of the preferred
embodiments are given. In no way should such examples be read to
limit, or define, the scope of the invention.
EXAMPLES
[0050] Solutions of diutan in water at room temperature show an
elastic rheological modulus (G') of 15 Pa at 0.5%, while at 0.75%
G' is 33 Pa. Sand suspension tests at 220.degree. F. show that the
diutan viscosified treatment fluid suspends sand for at least 2
hours. Thus, a viscosified treatment fluid of the present invention
comprising diutan is satisfactory for suspending particulates such
as proppant or gravel that may be used in subterranean
operations.
[0051] To illustrate, inter alia, the breaking characteristics of
diutan with various oxidizing and breaking agents (referred to as
"breakers" below), the following tests were performed. "GEOVIS XT"
(commercially available from Kelco Oil Field Group, Houston, Tex.)
was the source of the diutan polymers used in these examples.
[0052] Sodium persulfate at about 1 pound to about 1000 gallons is
well known to effectively degrade guar and guar derivatives at
temperatures above about 135.degree. F. Various concentrations of
sodium persulfate breaker were tried initially with a solution of
GEOVIS XT (0.7 g) dissolved in KCl/NaCl brine (200 ml of 9.7
lbs./gal). The GEOVIS XT was dissolved in the brine, the sodium
persulfate breaker was added, and the resulting solution was kept
at 230.degree. F. for 24 hours. The solutions were cooled before
the viscosities were measured at ambient temperatures. For
comparison, a guar solution of a similar concentration to this
sample could have a viscosity of less than 2 cP after 24 hours of
treatment at 230.degree. F. with lb./1000 gal of a sodium
persulfate breaker. The results are shown in Table 4 below.
4TABLE 4 Sodium Persulfate Breaker Component Test 1 Test 2 Test 3
KCl/NaCl brine 200 ml 200 ml 200 ml (9.7 lbs./gal) Viscosity of
starting 22 cP 22 cP 22 cP GEOVIS XT solution Sodium persulfate
0.024 g 0.12 g 0.24 g breaker (=1 lb./1000 gal) Viscosity after 24
20.5 cP 20.5 cP 10 cP hours at 230.degree. F.
[0053] As can be seen by the data in Table 4, the GEOVIS XT appears
to be relatively poorly degraded by the sodium persulfate
breaker.
[0054] In other set of experiments, tert-butyl hydroperoxide was
used as the breaker. As described above, the GEOVIS XT was
dissolved in the brine, the tert-butyl hydroperoxide breaker was
added, and the resulting solution was kept at 230.degree. F. for 24
hours. The solutions were cooled and then their viscosities were
measured at ambient temperature. Viscosities were measured using a
Chan 35 viscometer at 300 rpm at ambient temperature. The results
are shown in Table 5 below.
5TABLE 5 Tert-butyl Hydroperoxide Breaker Test 1 Test 2 Test 3
tert-butyl 0 0.1 0.3 hydroperoxide breaker (ml/100 ml KCl solution)
Storage Time (hrs): Viscosity (cP) Viscosity (cP) Viscosity (cP) 2
31 32 31 72 35 6 8 96 36 3 5 120 33 2 2 240 33 2 2
[0055] As can be seen from Table 5, the degradation of the GEOVIS
XT using a tert-butyl hydroperoxide breaker was more effective than
using a sodium persulfate breaker.
[0056] We have also found that the degradation of GEOVIS XT by a
tert-butyl hydroperoxide breaker may be delayed if desired by the
inclusion of sodium thiosulfate. This was shown by adding sodium
thiosulfate to solutions of GEOVIS XT and a tert-butyl
hydroperoxide breaker at 1 gal/1000 gals GEOVIS XT (at 0.36% in KCl
brine, having density of 9.7 lbs./gal), and measuring the viscosity
as above after storage at 230.degree. F. for various times. The
data results are shown in Table 6 below.
6TABLE 6 Adding Sodium Thiosulfate to Solution Comprising GEOVIS XT
and a Tert-butyl Hydroperoxide Breaker Test 1 Test 2 Test 3 Test 4
Sodium 0 17.5 37.5 75 Thiosulfate Additive (lbs./1000 gal solution)
Storage Viscosity Time (hrs) (cP) Viscosity (cP) Viscosity (cP)
Viscosity (cP) 0 22 22 22 22 2 4 7.5 14.5 17 24 -- 6.5 13.5 16 48
-- 6 12 15
[0057] As can be seen from the data in Table 6, the addition of
sodium thiosulfate appears to retard the degradation of the GEOVIS
XT, which may allow the timing of the breaking of the GEOVIS XT to
be tuned to suit particular well treatment requirements.
[0058] In another set of experiments, tert-amyl hydroperoxide was
used as the breaker. In these experiments, GEOVIS XT was dissolved
in a KCl solution (1000 ml of 9.7 lbs./gal), and the viscosities
were measured on a Chan 35 viscometer at 300 rpm after storage for
various times at 230.degree. F. as shown in Table 7. The solutions
were cooled before the viscosities were measured at ambient
temperatures.
7TABLE 7 Tert-Amyl Hydroperoxide as Breaker Test 1 Test 2 Test 3
Test 4 Test 5 tert-amyl 0.088% 0.132% 0.176% 0.22% 0.26%
hydroperoxide concentration (%) Viscos- Storage Time Viscosity
Viscosity Viscosity Viscosity ity (hrs) (cP) (cP) (cP) (cP) (cP) 0
20 20 20 20 20 24 11 11 9 13 14 48 10 9.8 10 11 12 72 9.5 9.5 8
10.2 11.5 96 9 9 6.5 10 10.5
[0059] As can be seen from Table 7, tert-amyl hydroperoxide may be
an effective breaker for GEOVIS XT.
[0060] In another set of experiments, another well-known breaker
was tested, sodium chlorite; it is usually used at temperatures
above about 200.degree. F. Concentrations of 1 lb. of sodium
chlorite for 1000 gals of polymer solution are effective in
degrading polymeric materials such as guar. In these experiments,
sodium chlorite was mixed with solutions of GEOVIS XT (3.6 g
dissolved in 1000 ml of KCl solution at 9.7 lb./gal) and stored at
230.degree. F. for various times and the viscosity was measured at
ambient temperature on a Chan 35 viscometer at 300 rpm. The
solutions were cooled before the viscosities were measured at
ambient temperatures. The results are shown in Table 8.
8TABLE 8 Sodium Chlorite as Breaker Test 1 Test 2 Test 3 Test 4
Test 5 Test 6 Test 7 Sodium 0.006 0.012 0.024 0.06 0.12 0.24 0.36
Chlorite Conc. in g/100 ml GEOVIS XT Solution Storage Viscosity
Viscosity Viscosity Viscosity Viscosity Viscosity Viscosity Time
(cP) (cP) (cP) (cP) (cP) (cP) (cP) 0 22 22 22 22 22 22 22 2 21 20
19 19 19 18 19 24 20 20 19.5 09.5 19 13 17
[0061] As shown in Table 8, the results were surprising in that
sodium chlorite appeared to have little effect on the degradation
of GEOVIS XT, contrary to what would have been expected with a guar
viscosifier.
[0062] GEOVIS XT has relatively unusual breaking characteristics.
GEOVIS XT appears to be unaffected by the commonly used sodium
persulfate and sodium chlorite breakers, thought it is degraded by
tert-butyl hydroperoxide and tert-amyl hydroperoxide.
[0063] Therefore, the present invention is well adapted to carry
out the objects and attain the ends and advantages mentioned as
well as those that are inherent therein. While numerous changes may
be made by those skilled in the art, such changes are encompassed
within the spirit of this invention as defined by the appended
claims.
* * * * *