U.S. patent application number 10/146326 was filed with the patent office on 2003-01-09 for method and product for use of guar powder in treating subterranean formations.
This patent application is currently assigned to Economy Mud Products Company. Invention is credited to Chowdhary, Manjit S., White, Walter M..
Application Number | 20030008780 10/146326 |
Document ID | / |
Family ID | 27053850 |
Filed Date | 2003-01-09 |
United States Patent
Application |
20030008780 |
Kind Code |
A1 |
Chowdhary, Manjit S. ; et
al. |
January 9, 2003 |
Method and product for use of guar powder in treating subterranean
formations
Abstract
A method of treating a subterranean formation using a
well-treating fluid is provided, the subterranean formation
penetrated by a wellbore, the method comprising preparing the
well-treating fluid by admixing a fast-hydrating high-viscosity
guar powder to a hydrating liquid to prepare the well-treating
fluid; hydrating the guar powder; admixing a cross-linker to the
well-treating fluid; and introducing the well-treating fluid to the
wellbore at a temperature and a pressure sufficient to treat the
subterranean formation. A product is also provided comprising a
well-treating fluid for use in treating subterranean formations
with the well-treating fluid comprising a hydrating liquid; a
gelling agent, the gelling agent comprising a fast-hydrating
high-viscosity guar powder; and a cross-linker.
Inventors: |
Chowdhary, Manjit S.;
(Princeton Junction, NJ) ; White, Walter M.;
(Houston, TX) |
Correspondence
Address: |
VINSON & ELKINS L.L.P.
1001 FANNIN STREET
2300 FIRST CITY TOWER
HOUSTON
TX
77002-6760
US
|
Assignee: |
Economy Mud Products
Company
435 E. Anderson Road
Houston
TX
77047
|
Family ID: |
27053850 |
Appl. No.: |
10/146326 |
Filed: |
May 14, 2002 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10146326 |
May 14, 2002 |
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09991356 |
Nov 19, 2001 |
|
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09991356 |
Nov 19, 2001 |
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09501559 |
Feb 9, 2000 |
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Current U.S.
Class: |
507/209 |
Current CPC
Class: |
C08B 37/0096 20130101;
C09K 8/62 20130101; C09K 8/04 20130101 |
Class at
Publication: |
507/209 |
International
Class: |
E21B 001/00 |
Claims
I claim:
1. A method of treating a subterranean formation using a
well-treating fluid, the subterranean formation penetrated by a
wellbore, the method comprising: (A) preparing the well-treating
fluid by admixing a fast-hydrating high-viscosity guar powder to a
hydrating liquid to prepare the well-treating fluid; (B) hydrating
the guar powder; (C) admixing a cross-linker to the well-treating
fluid; and (D) introducing the well-treating fluid to the wellbore
at a temperature and a pressure sufficient to treat the
subterranean formation.
2. The method of claim 1, wherein (A) further comprises admixing
the guar powder in an amount comprising from about 0.05 to about
1.0 percent by weight of the hydrating liquid.
3. The method of claim 1, wherein (A) further comprises admixing
the guar powder in an amount comprising from about 0.15 to about
0.3 percent by weight of the hydrating liquid.
4. The method of claim 1, wherein the guar powder of (A) is
selected from the group consisting of: (1) a de-polymerized
fast-hydrating high-viscosity guar powder; and (2) a derivative of
the fast-hydrating high-viscosity guar powder.
5. The method of claim 4, wherein the derivative of the
fast-hydrating high-viscosity guar powder is selected from the
group consisting of: (1) hydroxy propyl guar powder; (2) carboxy
methyl guar powder; and (3) carboxy methyl hydroxy propyl guar
powder.
6. The method of claim 1, wherein (C) comprises using a
cross-linker comprising a cross-linking agent.
7. The method of claim 6, wherein a delaying agent is admixed to
the well-treating fluid prior to the admixing of the
cross-linker.
8. The method of claim 1, wherein (C) comprises using a
cross-linker comprising a cross-linking agent and a delaying
agent.
9. The method of claim 8, wherein the cross-linker is disposed to
delay the cross-linking until after the well-treating fluid is
introduced into the wellbore.
10. The method of claim 8, wherein the cross-linking agent
comprises from about 10.0 to about 40.0 percent by weight of the
guar powder.
11. The method of claim 8, wherein the cross-linking agent
comprises from about 20.0 to about 35.0 percent by weight of the
guar powder.
12. The method of claim 8, wherein the delaying agent comprises
from about 0.5 to about 25.0 percent by weight of the guar
powder.
13. The method of claim 8, wherein the delaying agent comprises
from about 2.0 to about 10.0 percent by weight of the guar
powder.
14. The method of claim 1, wherein (C) further comprises admixing a
delayed breaking agent to the well-treating fluid.
15. The method of claim 14, wherein (C) further comprises admixing
the delayed breaking agent in an amount comprising from about 0.01
to about 2.5 percent by weight of the hydrating liquid.
16. The method of claim 14, wherein (C) further comprises admixing
a propping agent to the well-treating fluid.
17. The method of claim 1, wherein (C) further comprises admixing a
propping agent to the well-treating fluid.
18. The method of claim 1, wherein (D) further comprises admixing a
propping agent to the well-treating fluid before introduction of
the well-treating fluid into the wellbore.
19. The method of claim 18, wherein (D) further comprises admixing
a delayed breaking agent to the well-treating fluid before
introduction of the well-treating fluid into the wellbore.
20. The method of claim 19, wherein the delayed breaking agent is
admixed in an amount comprising from about 0.01 to about 2.5
percent by weight of the hydrating liquid.
21. The method of claim 1, wherein (D) further comprises admixing a
delayed breaking agent to the well-treating fluid before
introduction of the well-treating fluid into the wellbore.
22. The method of claim 21, wherein the delayed breaking agent is
admixed in an amount comprising from about 0.01 to about 2.5
percent by weight of the hydrating liquid.
23. The method of claim 1, further comprising: (E) introducing a
breaking agent to the wellbore, the breaking agent introduced after
the subterranean formation has been treated with the well-treating
fluid.
24. A well-treating fluid for use in treating subterranean
formations, the well-treating fluid comprising: a hydrating liquid;
a gelling agent, the gelling agent comprising a fast-hydrating
high-viscosity guar powder; and a cross-linker.
25. The well-treating fluid of claim 24, wherein the guar powder
comprises from about 0.05 to about 1.0 percent by weight of the
hydrating liquid.
26. The well-treating fluid of claim 24, wherein the guar powder
comprises from about 0.15 to about 0.3 percent by weight of the
hydrating liquid.
27. The well-treating fluid of claim 24, wherein the guar powder is
selected from the group consisting of: (1) a de-polymerized
fast-hydrating high-viscosity guar powder; and (2) a derivative of
the fast-hydrating high-viscosity guar powder.
28. The well-treating fluid of claim 27, wherein the derivative of
the fast-hydrating high-viscosity guar powder is selected from the
group consisting of: (1) hydroxy propyl guar powder; (2) carboxy
methyl guar powder; and (3) carboxy methyl hydroxy propyl guar
powder.
29. The well-treating fluid of claim 24, wherein the cross-linker
comprises a cross-linking agent.
30. The well-treating fluid of claim 29, wherein the well-treating
fluid further comprises a delaying agent.
31. The well-treating fluid of claim 24, wherein the cross-linker
comprises a cross-linking agent and a delaying agent.
32. The well-treating fluid of claim 31, wherein the cross-linking
agent comprises from about 10.0 to about 40.0 percent by weight of
the guar powder.
33. The well-treating fluid of claim 31, wherein the cross-linking
agent comprises from about 20.0 to about 35.0 percent by weight of
the guar powder.
34. The well-treating fluid of claim 31, wherein the delaying agent
comprises from about 0.5 to about 25.0 percent by weight of the
guar powder.
35. The well-treating fluid of claim 31, wherein the delaying agent
comprises from about 2.0 to about 10.0 percent by weight of the
guar powder.
36. The well-treating fluid of claim 24, wherein the well-treating
fluid further comprises a delayed breaking agent.
37. The well-treating fluid of claim 36, wherein the delayed
breaking agent comprises from about 0.01 to about 2.5 percent by
weight of the hydrating liquid.
38. The well-treating fluid of claim 36, wherein the well-treating
fluid further comprises a propping agent.
39. The well-treating fluid of claim 24, wherein the well-treating
fluid further comprises a propping agent.
40. A well-treating fluid for use in treating subterranean
formations, the treatment comprising a fracture stimulation, the
well-treating fluid comprising: a hydrating liquid; a gelling
agent, the gelling agent comprising a fast-hydrating high-viscosity
guar powder; a cross-linker; and a propping agent.
41. The well-treating fluid of claim 40, wherein the guar powder
comprises from about 0.05 to about 1.0 percent by weight of the
hydrating liquid.
42. The well-treating fluid of claim 40, wherein the guar powder
comprises from about 0.15 to about 0.3 percent by weight of the
hydrating liquid.
43. The well-treating fluid of claim 40, wherein the guar powder is
selected from the group consisting of: (1) a de-polymerized
fast-hydrating high-viscosity guar powder; and (2) a derivative of
the fast-hydrating high-viscosity guar powder.
44. The well-treating fluid of claim 43, wherein the derivative of
the fast-hydrating high-viscosity guar powder is selected from the
group consisting of: (1) hydroxy propyl guar powder; (2) carboxy
methyl guar powder; and (3) carboxy methyl hydroxy propyl guar
powder.
45. The well-treating fluid of claim 40, wherein the cross-linker
comprises a cross-linking agent.
46. The well-treating fluid of claim 45, wherein the well-treating
fluid further comprises a delaying agent.
47. The well-treating fluid of claim 40, wherein the cross-linker
comprises a cross-linking agent and a delaying agent.
48. The well-treating fluid of claim 47, wherein the cross-linking
agent comprises from about 10.0 to about 40.0 percent by weight of
the guar powder.
49. The well-treating fluid of claim 47, wherein the cross-linking
agent comprises from about 20.0 to about 35.0 percent by weight of
the guar powder.
50. The well-treating fluid of claim 47, wherein the delaying agent
comprises from about 0.5 to about 25.0 percent by weight of the
guar powder.
51. The well-treating fluid of claim 47, wherein the delaying agent
comprises from about 2.0 to about 10.0 percent by weight of the
guar powder.
52. The well-treating fluid of claim 40, wherein the well-treating
fluid further comprises a delayed breaking agent.
53. The well-treating fluid of claim 52, wherein the delayed
breaking agent comprises from about 0.01 to about 2.5 percent by
weight of the hydrating liquid.
54. A well-treating fluid for use in treating subterranean
formations, the treatment comprising a fracture stimulation, the
well-treating fluid comprising: a hydrating liquid; a gelling
agent, the gelling agent comprising a fast-hydrating high-viscosity
guar powder; a cross-linker, the cross-linker comprising a
cross-linking agent and a delaying agent; a delayed breaking agent;
and a propping agent.
55. The well-treating fluid of claim 54, wherein the guar powder
further comprises from about 0.05 to about 1.0 percent by weight of
the hydrating liquid.
56. The well-treating fluid of claim 54, wherein the guar powder
further comprises from about 0.15 to about 0.3 percent by weight of
the hydrating liquid.
57. The well-treating fluid of claim 54, wherein the guar powder is
selected from the group consisting of: (1) a de-polymerized
fast-hydrating high-viscosity guar powder; and (2) a derivative of
the fast-hydrating high-viscosity guar powder.
58. The well-treating fluid of claim 57, wherein the derivative of
the fast-hydrating high-viscosity guar powder is selected from the
group consisting of: (1) hydroxy propyl guar powder; (2) carboxy
methyl guar powder; and (3) carboxy methyl hydroxy propyl guar
powder.
59. The well-treating fluid of claim 54, wherein the cross-linking
agent comprises from about 10.0 to about 40.0 percent by weight of
the guar powder.
60. The well-treating fluid of claim 54, wherein the cross-linking
agent comprises from about 20.0 to about 35.0 percent by weight of
the guar powder.
61. The well-treating fluid of claim 54, wherein the delaying agent
comprises from about 0.5 to about 25.0 percent by weight of the
guar powder.
62. The well-treating fluid of claim 54, wherein the delaying agent
comprises from about 2.0 to about 10.0 percent by weight of the
guar powder.
63. The well-treating fluid of claim 54, wherein the delayed
breaking agent comprises from about 0.01 to about 2.5 percent by
weight of the hydrating liquid.
64. A method of treating a subterranean formation using a
well-treating fluid, the subterranean formation penetrated by a
wellbore, the method comprising: (A) preparing the well-treating
fluid by admixing a fast-hydrating high-viscosity guar powder to a
hydrating liquid to prepare the well-treating fluid; (B) hydrating
the guar powder; (C) admixing a cross-linker and a delayed breaking
agent to the well-treating fluid; and (D) introducing the
well-treating fluid to the wellbore at a temperature and a pressure
sufficient to treat the subterranean formation.
65. The method of claim 64, wherein (A) further comprises admixing
the guar powder in an amount comprising from about 0.05 to about
1.0 percent by weight of the hydrating liquid.
66. The method of claim 64, wherein (A) further comprises admixing
the guar powder in an amount comprising from about 0.15 to about
0.3 percent by weight of the hydrating liquid.
67. The method of claim 64, wherein the guar powder of (A) is
selected from the group consisting of: (1) a de-polymerized
fast-hydrating high-viscosity guar powder; and (2) a derivative of
the fast-hydrating high-viscosity guar powder.
68. The method of claim 67, wherein the derivative of the
fast-hydrating high-viscosity guar powder is selected from the
group consisting of: (1) hydroxy propyl guar powder; (2) carboxy
methyl guar powder; and (3) carboxy methyl hydroxy propyl guar
powder.
69. The method of claim 64, wherein (C) comprises using a
cross-linker comprising a cross-linking agent.
70. The method of claim 69, wherein a delaying agent is admixed to
the well-treating fluid prior to the admixing of the
cross-linker.
71. The method of claim 64, wherein (C) comprises using a
cross-linker comprising a cross-linking agent and a delaying
agent.
72. The method of claim 71, wherein the cross-linker is disposed to
delay the cross-linking until after the well-treating fluid is
introduced into the wellbore.
73. The method of claim 71, wherein the cross-linking agent
comprises from about 10.0 to about 40.0 percent by weight of the
guar powder.
74. The method of claim 71, wherein the cross-linking agent
comprises from about 20.0 to about 35.0 percent by weight of the
guar powder.
75. The method of claim 71, wherein the delaying agent comprises
from about 0.5 to about 25.0 percent by weight of the guar
powder.
76. The method of claim 71, wherein the delaying agent comprises
from about 2.0 to about 10.0 percent by weight of the guar
powder.
77. The method of claim 64, wherein (C) further comprises admixing
the delayed breaking agent in an amount comprising from about 0.01
to about 2.5 percent by weight of the hydrating liquid.
78. The method of claim 64, wherein (C) further comprises admixing
a propping agent to the well-treating fluid.
79. The method of claim 64, wherein (D) further comprises admixing
a propping agent to the well-treating fluid.
80. A method of performing a fracture treatment in a subterranean
formation using a well-treating fluid, the subterranean formation
penetrated by a wellbore, the method comprising: (A) preparing the
well-treating fluid by admixing a fast-hydrating high-viscosity
guar powder to a hydrating liquid to prepare the well-treating
fluid; (B) hydrating the guar powder; (C) admixing a cross-linker
and a propping agent to the well-treating fluid; and (D)
introducing the well-treating fluid to the wellbore at a
temperature and a pressure sufficient to stimulate the fracture
treatment of the subterranean formation.
81. The method of claim 80, wherein (A) further comprises admixing
the guar powder in an amount comprising from about 0.05 to about
1.0 percent by weight of the hydrating liquid.
82. The method of claim 80, wherein (A) further comprises admixing
the guar powder in an amount comprising from about 0.15 to about
0.3 percent by weight of the hydrating liquid.
83. The method of claim 80, wherein the guar powder of (A) is
selected from the group consisting of: (1) a de-polymerized
fast-hydrating high-viscosity guar powder; and (2) a derivative of
the fast-hydrating high-viscosity guar powder.
84. The method of claim 83, wherein the derivative of the
fast-hydrating high-viscosity guar powder is selected from the
group consisting of: (1) hydroxy propyl guar powder; (2) carboxy
methyl guar powder; and (3) carboxy methyl hydroxy propyl guar
powder.
85. The method of claim 80, wherein (C) comprises using a
cross-linker comprising a cross-linking agent.
86. The method of claim 85, wherein a delaying agent is admixed to
the well-treating fluid prior to the admixing of the
cross-linker.
87. The method of claim 80, wherein (C) comprises using a
cross-linker comprising a cross-linking agent and a delaying
agent.
88. The method of claim 87, in which the cross-linker is disposed
to delay the cross-linking until after the well-treating fluid is
introduced into the wellbore.
89. The method of claim 87, wherein the delaying agent comprises
from about 0.5 to about 25.0 percent by weight of the guar
powder.
90. The method of claim 87, wherein the delaying agent comprises
from about 2.0 to about 10.0 percent by weight of the guar
powder.
91. The method of claim 87, wherein the cross-linking agent
comprises from about 10.0 to about 40.0 percent by weight of the
guar powder.
92. The method of claim 87, wherein the cross-linking agent
comprises from about 20.0 to about 35.0 percent by weight of the
guar powder.
93. The method of claim 80, wherein (C) further comprises admixing
a delayed breaking agent to the well-treating fluid.
94. The method of claim 93, wherein (C) further comprises admixing
the delayed breaking agent in an amount comprising from about 0.01
to about 2.5 percent by weight of the hydrating liquid.
95. The method of 80, further comprising: (E) introducing a
breaking agent to the wellbore.
96. A method of performing a fracture treatment to a subterranean
formation using a well-treating fluid, the subterranean formation
penetrated by a wellbore, the method comprising: (A) preparing the
well-treating fluid by admixing a fast-hydrating high-viscosity
guar powder to a hydrating liquid to prepare the well-treating
fluid; (B) hydrating the guar powder; (C) admixing a cross-linker,
a propping agent, and a delayed breaking agent to the well-treating
fluid, wherein the cross-linker comprises a delaying agent and a
cross-linking agent, and wherein the cross-linker is disposed to
delay the cross-linking until after the well-treating fluid is
introduced to the wellbore; (D) introducing the well-treating fluid
to the wellbore at a temperature and a pressure sufficient to
stimulate the fracture treatment of the subterranean formation; and
(E) breaking the well-treating fluid with the delayed breaking
agent, the delayed breaking agent disposed to delay breaking of the
well-treating fluid until after stimulation of the fracture
treatment.
97. The method of claim 96, wherein (A) further comprises admixing
the guar powder in an amount comprising from about 0.05 to about
1.0 percent by weight of the hydrating liquid.
98. The method of claim 96, wherein (A) further comprises admixing
the guar powder in an amount comprising from about 0.15 to about
0.3 percent by weight of the hydrating liquid.
99. The method of claim 96, wherein the guar powder of (A) is
selected from the group consisting of: (1) a de-polymerized
fast-hydrating high-viscosity guar powder; and (2) a derivative of
the fast-hydrating high-viscosity guar powder.
100. The method of claim 99, wherein the derivative of the
fast-hydrating high-viscosity guar powder is selected from the
group consisting of: (1) hydroxy propyl guar powder; (2) carboxy
methyl guar powder; and (3) carboxy methyl hydroxy propyl guar
powder.
101. The method of claim 96, wherein the cross-linking agent
comprises from about 10.0 to about 40.0 percent by weight of the
guar powder.
102. The method of claim 96, wherein the cross-linking agent
comprises from about 20.0 to about 35.0 percent by weight of the
guar powder.
103. The method of claim 96, wherein the delaying agent comprises
from about 0.5 to about 25.0 percent by weight of the guar
powder.
104. The method of claim 96, wherein the delaying agent comprises
from about 2.0 to about 10.0 percent by weight of the guar
powder.
105. The method of claim 96, wherein (C) further comprises admixing
the delayed breaking agent in an amount comprising from about 0.01
to about 2.5 percent by weight of the guar powder.
Description
RELATED APPLICATION(S)
[0001] This application is a continuation-in-part of commonly
assigned U.S. patent application GUAR GUM POWDER POSSESSING
IMPROVED HYDRATION CHARACTERISTICS, Ser. No. 09/991,356, filed Nov.
19, 2001, which is a division of commonly assigned U.S. patent
application IMPROVED HYDRATION OF GUAR GUM POWDER, Ser. No.
09/501,559, filed Feb. 9, 2000.
TECHNICAL FIELD OF THE INVENTION
[0002] This application relates generally to the field of
subterranean drilling and more specifically to the use of guar
powder in "on-the fly" treatment of subterranean formations.
BACKGROUND OF THE INVENTION
[0003] Oil and natural gas ("gas") are typically found in
subterranean formations. To obtain the oil or gas, the subterranean
formation must be penetrated, thereby allowing the oil or gas to be
produced through a wellbore.
[0004] In standard operations, a wellbore is drilled from the
surface to the subterranean formation. The wellbore penetrates the
subterranean formation, which allows the oil or gas to flow from
the subterranean formation to the surface via the wellbore. For the
oil or gas to escape the subterranean formation and flow to the
wellbore, the oil or gas must have a sufficiently unimpeded path
from the subterranean formation to the wellbore. Typically, this
path is through the formation rock, which usually comprises
sandstone or carbonates. For the formation rock to enable a
sufficient oil or gas flow, the formation rock must have a
sufficient number of pores with a size and connectivity to provide
the proper conduit for the oil or gas.
[0005] Frequently, the oil or gas is not able to escape the
subterranean formation and flow through the wellbore, or oil or gas
may only escape in less than optimal amounts. For instance, damage
to the subterranean formation may plug the pores of the formation
rock. Damage may be caused by fluids that were injected into the
wellbore during drilling of the wellbore or injected during
treatments of the subterranean formation. Typically, portions of
these fluids may remain in the wellbore after the injection and may
dehydrate and take solid form over time. These dehydrated fluids
may then coat the wellbore or pores of the formation rock, which
may result in stopping or reducing the flow of gas or oil.
Additional reasons for reduced flow of oil or gas include pores
with less than optimal size or number. With such pores, the
formation rock may have a low permeability to the flow of oil or
gas.
[0006] One method for increasing the flow of oil or gas from the
subterranean formation is to "stimulate" the subterranean
formation. Stimulation of the subterranean formation involves
fracturing the subterranean formation, thereby causing cracks that
extend from the wellbore to the subterranean formation. Typically,
this fracturing of the subterranean formation involves injecting a
well-treating fluid that comprises chemicals in gel form through
the wellbore and to the formation at pressures sufficient to
fracture the formation. The standard components of the gelled
well-treating fluid comprise a carrier fluid, a polymer, a
cross-linker, and a propping agent. The well-treating fluid is
inserted into the wellbore at a temperature and pressure sufficient
to stimulate one or more fractures of the surface of the
subterranean formation. Typically, the gel is inserted in 17 lb (8
kg) or 30 lb (14 kg) injections. After the fracture is sufficiently
open, the well-treating fluid flows into the fracture and deposits
the propping agent. A breaking agent is then introduced to the
wellbore, and the breaking agent breaks the gelled well-treating
fluid into a thin fluid, which allows for its removal from the
wellbore. Alternatively, the well-treating fluid may further
comprise a delayed breaking agent that breaks the well-treating
fluid at a time after the fracture of the subterranean formation.
After the well-treating fluid is broken and removed, the propping
agent remains in the fractures. The propping agent keeps the
fractures from closing after the broken well-treating fluid is
removed. The propping agent also increases the flow of oil or gas
through the fracture by providing channels through which the oil or
gas may flow to the wellbore. Alternatively, the gelled
well-treating fluid that stimulates the fracture of the formation
may not comprise any propping agent. Instead, the propping agent is
not added to the well-treating fluid until after the subterranean
formation is stimulated and thereafter is introduced in to the
fractures.
[0007] High viscosity is an important aspect to these cross-linked
gels. For instance, the width of the fracture may be proportional
to the viscosity of the fracturing fluid. In addition, a high
viscosity enables the well-treating fluid to transport the propping
agents without the propping agents settling out of the
well-treating fluid.
[0008] The standard polymer in the well-treating fluid is guar gum.
Guar gum comes from a plant that is grown primarily in India and
Pakistan, although other climates are also friendly to its
cultivation. Guar is a legume-type plant that produces a pod, much
like a green bean. In the pod, there are seeds that, upon heating,
split open, exposing the endosperm and meal. The exposed endosperm
contains a polymer that is of great use for thickening industrial
and commercial fluids. The polymer is a polysaccharide material
known as polygalactomannan. This material develops a high viscosity
via hydration of the fluid to be thickened.
[0009] The original process for making the gelled well-treating
fluid involved an operator mixing bags of guar powder with water in
a hopper and then transferring the mixture to a storage tank. The
guar powder was allowed to hydrate in the storage tank for a period
of time that typically spanned several hours. After the mixture was
sufficiently gelled, the gelled fluid was then pumped into the
wellbore. One serious drawback to this process was the large
expense involved in such a large amount of time expended to hydrate
the guar powder. In addition, the large amounts of guar powder that
were required to have a sufficient viscosity added significantly to
the cost in producing the oil or gas.
[0010] To increase efficiency over this original process, the
industry developed an "on-the-fly" process to make the gelled
well-treating fluid. In this process, a liquid slurry comprising
guar powder, a carrier fluid, and suspending agents is prepared
remote from the wellbore site. The carrier fluid typically
comprises a diesel fuel or mineral oil. The suspending agents,
which are used to suspend the slurry, are inorganic and non-soluble
in water. This liquid slurry is then taken to the wellbore site and
mixed in hydration tanks with water to form the gelled
well-treating fluid. These hydration tanks are also called
on-the-fly hydration units. In these on-the-fly hydration units,
the guar powder in the liquid slurry is allowed to hydrate for
about seven to ten minutes. A cross-linker and any other additives
are then added to the liquid slurry and then the gel is introduced
to the wellbore.
[0011] U.S. Pat. No. 4,336,145 (the "'145 Patent") also discloses a
pre-prepared liquid slurry, but instead discloses water as the
carrier fluid. In the '145 Patent, the gel is prepared by
suspending the polymer in water by using an inhibitor to retard the
hydration rate of the polymer. When the gel is then later mixed
with additional water, the inhibitor reverses and the hydration of
the polymer commences.
[0012] It is highly advantageous to have a well-treating fluid and
a method for using the well-treating fluid that uses a
fast-hydrating and high-viscosity polymer. The time involved in
preparing the well-treating fluid for introduction to the wellbore
is directly related to the increased efficiency, and, thereby,
reduced expenses, in the production of oil and gas. The liquid
slurry process has reduced the several hours time required of the
original process. However, the liquid slurry is a pre-prepared
mixture. The time and effort involved in preparing the liquid
slurry decreases the cost efficiency of the production. A further
drawback of the liquid slurry process includes the introduction of
the non-soluble suspending agents to the wellbore, where the
non-soluble suspending agents are not broken by the breaking agent.
Therefore, these suspending agents remain in the fractures along
with the propping agents and may lead to clogging of the pores,
which may reduce or stop the flow of the oil or gas. In addition,
the large amount of suspending agent required to suspend the slurry
increases the cost of the production operation. Moreover, the
suspending agents may interfere with cross-linking of the polymer.
Drawbacks also include environmental concerns and additional cost
increases. For instance, the inhibitor introduced to the wellbore
in the '145 patent presents harmful chemicals to the environment
and the removal of such harmful chemicals poses storage problems.
The added cost of storing and removing these chemicals and the
initial cost of using these chemicals also decreases the cost
efficiency of the production. In addition, the use of diesel in the
liquid slurry is also potentially harmful to the environment. The
large amount of diesel used may be cost prohibitive due to the
initial cost of using the diesel and the added cost in removing the
diesel. A further drawback includes the amount of polymer or guar
powder that must be used to have a viscosity high enough to
transport the propping agent. To increase the viscosity of the
gelled well-treating fluid, operators typically add additional guar
powder or polymer to attain the desired viscosity, which increases
costs.
[0013] Consequently, there is a need for a well-treating fluid that
comprises a high-viscosity and fast-hydrating polymer. There is a
need for a method of producing and using such a well-treating
fluid. Further, there is a need for a way to minimize the amount of
polymer used in preparing a well-treating fluid. In addition, there
is a need for reducing the amount of harmful pollutants introduced
to the environment during the treatment of a subterranean
formation.
SUMMARY OF THE INVENTION
[0014] These and other needs in the art are addressed in various
aspects of the present invention. In one aspect, an inventive
method of treating a subterranean formation using a well-treating
fluid is provided, the subterranean formation penetrated by a
wellbore, the method comprising (A) preparing the well-treating
fluid by admixing a fast-hydrating high-viscosity guar powder to a
hydrating liquid to prepare the well-treating fluid; (B) hydrating
the guar powder; (C) admixing a cross-linker to the well-treating
fluid; and (D) introducing the well-treating fluid to the wellbore
at a temperature and a pressure sufficient to treat the
subterranean formation.
[0015] In another aspect of the present invention, a well-treating
fluid for use in treating subterranean formations is provided, the
well-treating fluid comprising a hydrating liquid; a gelling agent,
the gelling agent comprising a fast-hydrating high-viscosity guar
powder; and a cross-linker.
[0016] In a third aspect of the present invention, a well-treating
fluid for use in treating subterranean formations is provided, the
treatment comprising a fracture stimulation, the well-treating
fluid comprising a hydrating liquid; a gelling agent, the gelling
agent comprising a fast-hydrating high-viscosity guar powder; a
cross-linker; and a propping agent.
[0017] In a fourth aspect of the present invention, a well-treating
fluid for use in treating subterranean formations is provided, the
treatment comprising a fracture stimulation, the well-treating
fluid comprising a hydrating liquid; a gelling agent, the gelling
agent comprising a fast-hydrating high-viscosity guar powder; a
cross-linker, the cross-linker comprising a cross-linking agent and
a delaying agent; a delayed breaking agent; and a propping
agent.
[0018] In a fifth aspect of the present invention, a method of
treating a subterranean formation using a well-treating fluid is
provided, the subterranean formation penetrated by a wellbore, the
method comprising (A) preparing the well-treating fluid by admixing
a fast-hydrating high-viscosity guar powder to a hydrating liquid
to prepare the well-treating fluid; (B) hydrating the guar powder;
(C) admixing a cross-linker and a delayed breaking agent to the
well-treating fluid; and (D) introducing the well-treating fluid to
the wellbore at a temperature and a pressure sufficient to treat
the subterranean formation.
[0019] In a sixth aspect of the present invention, a method of
performing a fracture treatment in a subterranean formation using a
well-treating fluid is provided, the subterranean formation
penetrated by a wellbore, the method comprising (A) preparing the
well-treating fluid by admixing a fast-hydrating high-viscosity
guar powder to a hydrating liquid to prepare the well-treating
fluid; (B) hydrating the guar powder; (C) admixing a cross-linker
and a propping agent to the well-treating fluid; and (D)
introducing the well-treating fluid to the wellbore at a
temperature and a pressure sufficient to stimulate the fracture
treatment of the subterranean formation.
[0020] In a seventh aspect of the present invention, a method of
performing a fracture treatment to a subterranean formation using a
well-treating fluid is provided, the subterranean formation
penetrated by a wellbore, the method comprising (A) preparing the
well-treating fluid by admixing a fast-hydrating high-viscosity
guar powder to a hydrating liquid to prepare the well-treating
fluid; (B) hydrating the guar powder; (C) admixing a cross-linker,
a propping agent, and a delayed breaking agent to the well-treating
fluid, wherein the cross-linker comprises a delaying agent and a
cross-linking agent, and wherein the cross-linker is disposed to
delay the cross-linking until after the well-treating fluid is
introduced to the wellbore; (D) introducing the well-treating fluid
to the wellbore at a temperature and a pressure sufficient to
stimulate the fracture treatment of the subterranean formation; and
(E) breaking the well-treating fluid with the delayed breaking
agent, the delayed breaking agent disposed to delay breaking of the
well-treating fluid until after stimulation of the fracture
treatment.
[0021] The foregoing has outlined rather broadly many of the
features and technical advantages of the present invention in order
that the detailed description of the invention that follows may be
better understood. Additional features and advantages of the
invention will be described hereinafter which form the subject of
the claims of the invention. It should be appreciated by those
skilled in the art that the conception and the specific embodiments
disclosed may be readily utilized as a basis for modifying or
designing other structures for carrying out the same purposes of
the present invention. It should also be realized by those skilled
in the art that such equivalent constructions do not depart from
the spirit and scope of the invention as set forth in the appended
claims.
BRIEF DESCRIPTION OF THE DRAWING
[0022] For a more complete understanding of the present invention,
and the advantages thereof, reference is now made to the following
descriptions taken in conjunction with the accompanying drawing, in
which:
[0023] the drawing illustrates a processing unit for well-treating
fluids.
DETAILED DESCRIPTION OF THE INVENTION
[0024] The accompanying drawing illustrates a process for
on-the-fly manufacture of well-treating fluids in which a trailer
10 supports process equipment 15. The process equipment 15
comprises a hydraulic power pack 20, chemical additives tanks 30, a
polymer tank 40, and a hydration unit 50. The hydraulic power pack
20 provides power to the other process equipment 15. The chemical
additives tanks 30 comprise chemical storage tanks that store and
supply the chemical additives to the hydration unit 50. The
chemical additives that are stored in these tanks may comprise
cross-linking agents, breaking agents, delaying agents, buffer
solution additives, and/or any other suitable additives for
admixing to the hydration unit 50.
[0025] The polymer tank 40 contains the polymers for adding to the
hydration unit 50 in the preparation of the well-treating fluid.
The polymer that is stored in the polymer tank 40 and used in
preparing the well-treating fluid of various illustrative
embodiments of the present invention is the fast-hydrating
high-viscosity guar powder disclosed in co-pending, commonly
assigned U.S. patent applications with Ser. Nos. 09/991,356 (the
"'356 application") and 09/501,559 (the "'559 application") of
which this invention is a continuation-in-part application. The
'356 application and the '559 application are hereby incorporated
by reference in their entirety. The polymer that is used in
preparing the well-treating fluid may also comprise a
de-polymerized fast-hydrating high-viscosity guar powder and
derivatives of the fast-hydrating high-viscosity guar powder. Such
derivatives may comprise hydroxy propyl guar powder, carboxy methyl
guar powder, and carboxy methyl hydroxy propyl guar powder. The
fast-hydrating high-viscosity guar powder is stored in the polymer
tank 40 in powder form.
[0026] The hydration unit 50 serves as a storage and mixing unit
for the preparation of the well-treating fluid. In the hydration
unit 50, the guar powder is hydrated with a hydrating liquid and
then mixed with the chemicals from the chemical additives tanks 30
by an agitator 60. A pump 70 pumps the hydrating liquid from a
water supply to the hydration unit 50. An operator on an operator
platform 90 oversees the operation of the process equipment 15.
[0027] The following describes an exemplary illustrative embodiment
of the present invention as illustrated. The trailer 10 is located
near a wellbore (not illustrated). The operator turns on the power
of the hydraulic power pack 20 so that the other process equipment
15 may then be supplied with power. Hydrating liquid from the water
supply is supplied to the hydration unit 50 by the pump 70. The
hydrating liquid may comprise fresh water, brine, or any other
suitable liquid that does not adversely react with other components
of the well-treating fluid. After a certain amount of hydrating
liquid is added to the hydration unit 50, fast-hydrating
high-viscosity guar powder from the polymer tank 40 is added to the
hydration unit 50. The agitator 60 mixes the guar powder with the
hydrating liquid. The guar powder is added to the hydrating liquid
in an amount that may comprise about 0.15 to about 0.30 percent by
weight of the hydrating liquid. The guar powder is not limited to
this percent by weight of the hydrating liquid but, in various
alternative illustrative embodiments, may alternatively comprise
anywhere from about 0.05 to about 1.0 percent by weight of the
hydrating liquid. The guar powder is allowed to hydrate in the
hydrating fluid. In addition, the guar powder and hydrating liquid
mixture form into a gel. The guar powder may be allowed to hydrate
in the hydrating fluid for a time period up to about 5 minutes,
which results in about a 90 percent hydration rate of the guar
powder. Alternatively, the guar powder may be allowed to hydrate
for a longer or a shorter period of time, depending on the
circumstances.
[0028] After the guar powder hydrates in the hydration unit 50, a
cross-linker may be admixed to the guar powder and water mixture to
form the well-treating fluid. The cross-linker may comprise a
cross-linking agent and a delaying agent. The cross-linking agent
and delaying agent may be mixed at the trailer 10 or remote from
the trailer 10. The cross-linking agent may comprise from about
20.0 to about 35.0 percent by weight of the guar powder.
Alternatively, the cross-linking agent may comprise from about 10.0
to about 40.0 percent by weight of the guar powder. The delaying
agent may comprise from about 2.0 to about 10.0 percent by weight
of the guar powder. Alternatively, the delaying agent may comprise
from about 0.5 to about 25.0 percent by weight of the guar powder.
Examples of available cross-linking agents include zirconium,
titanium, chromium, aluminum, antimony, iron, zinc, borate, boron,
and the like. Examples of available delaying agents include
glycerol, erythritol, threitol, ribitol, arabinitol, xylitol,
allitol, altritol, sorbitol, mannitol, dulcitol, iditol, perseitol,
and the like. The cross-linking agent bonds molecules of the guar
together by attaching to the hydroxyl groups of the guar. By such
cross-linking, the viscosity of the well-treating fluid may be
increased. The delaying agents in the cross-linker delay the
cross-linking of the guar molecules until the well-treating fluid
is down the wellbore, thereby maintaining a lower viscosity in the
well-treating fluid while pumping into the wellbore. The delaying
agents may delay the cross-linking from several minutes to several
hours, depending on the requirements of the situation. By delaying
the cross-linking, the amount of pressure needed to pump the
well-treating fluid from the hydration unit 50 to the wellbore may
be substantially decreased. Alternatively, the cross-linker may not
comprise a delaying agent. Instead, the delaying agent may be
admixed to the guar powder and hydrating liquid mixture before the
cross-linking agent is admixed to the mixture. In various
alternative embodiments, the delaying agent may not be admixed to
the well-treating fluid. Consequently, the cross-linking agent may
immediately begin the cross-linking of the guar upon its addition
to the well-treating fluid.
[0029] After admixing the cross-linker in the hydration unit 50 to
form the well-treating fluid, a delayed breaking agent, which may
be stored in the chemical additive tanks 30, may be admixed to the
well-treating fluid in the hydration unit 50. The delayed breaking
agent may be admixed to the well-treating fluid in an amount
comprising from about 0.01 to about 2.5 percent by weight of the
hydrating liquid in the well-treating fluid. The amount of the
delayed breaking agent may be adjusted, depending on the required
breaking time of the gelled well-treating fluid. Delayed breaking
agents that may be used include alkali metal chlorites,
hypochlorites, calcium hypochlorites, and any other suitable
breaking agent. Such delayed breaking agents are described in U.S.
Pat. No. 5,413,178, issued on May 9, 1995; U.S. Pat. No. 5,669,446,
issued on Sep. 23, 1997; and U.S. Pat. No. 5,950,731, issued on
Sep. 14, 1999, the entire disclosures of which are incorporated by
reference. Alternatively, the delayed breaking agent may not be
admixed to the well-treating fluid before the well-treating fluid
is introduced to the wellbore. Instead, the delayed breaking agent
may not be introduced to the wellbore until after the well-treating
fluid has completed the treatment of the subterranean
formation.
[0030] After the delayed breaking agent is admixed to the
well-treating fluid in the hydration unit 50, the well-treating
fluid may be removed from the hydration unit 50, and a propping
agent may be admixed and suspended in the well-treating fluid. The
propping agent may be admixed to the well-treating fluid in an
amount comprising from about 1 pound (0.45 kg) to about 10 pounds
(4.5 kg) of propping agent per gallon (4 liters) of well-treating
fluid. This concentration may be increased or decreased, depending
on the circumstances. Propping agents that may be used include
sand, tempered glass beads, aluminum pellets, sintered bauxite,
nylon pellets, and any other suitable propping agent.
Alternatively, the propping agent may be admixed along with the
cross-linker, which may comprise the cross-linking agent and
delaying agent, and simultaneously suspended. In other alternative
embodiments, the propping agent may be admixed along with a
cross-linker, without delaying agents, and simultaneously
suspended.
[0031] The on-the-fly process from the hydration of the guar powder
in the hydrating liquid to the mixing of the well-treating fluid
with the suspended propping agent may take place in a matter of
minutes, with the hydration of the guar powder taking place in a
period of time up to about 5 minutes with about a 90 percent
hydration rate. The process may take more or less time, depending
on the circumstances. After admixing the propping agent, the
well-treating fluid with the suspended propping agent may then be
introduced into the wellbore in 17 lb (8 kg) gel increments.
Alternatively, the well-treating fluid may be introduced to the
wellbore in 30 lb (14 kg) gel increments or in any other suitable
increments. By these 17 lb (8 kg) gel increments, the well-treating
fluid may stimulate the fracture treatment of the subterranean
formation. After the subterranean formation is fractured, the
well-treating fluid may deliver the propping agents to the
fractures of the subterranean formation. Thereafter, the delayed
breaking agent may break the gelled well-treating fluid into a thin
liquid. The broken well-treating fluid may then be removed from the
wellbore. In various alternative embodiments, the propping agent
may not be admixed to the well-treating fluid until after the
well-treating fluid has stimulated the fracture of the subterranean
formation. Upon the fracture, the propping agent may be admixed to
the well-treating fluid, and the well-treating fluid with the
suspended propping agent may be introduced to the wellbore, through
which process the propping agent may be deposited in the
fractures.
[0032] The preparation of the well-treating fluid and its
introduction to the wellbore may be undertaken in ambient
temperatures, which typically range from about 70 degrees F.
(21.degree. C., 294 K) to about 120 degrees F. (49.degree. C., 322
K), and may have similar results in viscosities and hydration rates
in temperatures lower and/or higher than the standard ambient
temperatures. The temperatures in the wellbore and near the
subterranean formation typically range between about 120 degrees F.
(49.degree. C., 322 K) to about 350 degrees F. (232.degree. C., 450
K), which is also a suitable temperature range for various
illustrative embodiments of the present invention.
[0033] In various alternative embodiments, the well-treating fluid
may comprise additional components that may be admixed to the
well-treating fluids described above. For example, conventional
additives such as pH control agents, bactericides, clay
stabilizers, surfactants, and the like, which do not interfere with
the other components, or adversely affect the treatment, may also
be used.
[0034] In addition to the stimulation of subterranean formation
fractures, various illustrative embodiments of the present
invention may be used in other treatments that include well
completion operations, fluid loss control treatments, treatments to
reduce water production, drilling operations, and any other
suitable treatments.
[0035] To further illustrate various illustrative embodiments of
the present invention, the following examples are provided.
EXAMPLE 1
[0036] TABLE 1 illustrates the hydration rate performance of an
improved fast-hydrating high-viscosity guar powder (as disclosed in
the '356 and '559 patent applications) over conventional guar
powder. New Guar 1 and New Guar 2 represent products produced
according to the '356 and '559 patent applications. The Old Guar
represents a guar powder product prepared under the conventional
standard process. In this example, 2.4 g of guar powder was mixed
in 500 ml of tap water by a Waring blender for one minute at 2800
rpm. The resulting mixture corresponds to a 40 lb (18 kg) gel.
Thereafter, about 350 ml of this mixture was measured at 300 rpm by
a FANN-35 viscometer. The resulting viscosities were measured at
varying time increments, and the results for each guar product are
illustrated in TABLE 1. As shown in TABLE 1, the New Guar 1 and New
Guar 2 result in about a 30 percent increase in viscosity over the
Old Guar. In addition, these results indicate that the New Guar 1
and New Guar 2 hydrate at a faster rate than the Old Guar, with the
New Guar 1 and New Guar 2 exhibiting about a 90 percent hydration
rate at 5 minutes.
1 TABLE 1 New Guar 1 New Guar 2 Old Guar Time in Minutes (cps)
(cps) (cps) 3 33-35 42-44 22-24 5 35-39 44-46 24-26 15 39-41 46-48
28-30 60 42-44 48-50 33-36
EXAMPLES 2-10, and 13
[0037] In these examples, different amounts of New Guar 1, New Guar
2, and Old Guar were hydrated with water and mixed with
cross-linking agents. These examples illustrate a procedure for
on-the-fly making of the gelled well-treating fluid. TABLE 2
illustrates the resulting viscosities of the different guar
mixtures of the examples.
2TABLE 2 Cross- 10 20 30 40 50 60 Example Gel linker MIN. MIN. MIN
MIN. MIN. MIN. No. Product (lbs) (mls) (cps) (cps) (cps) (cps)
(cps) (cps) 2 Old Guar 30 0.2 237 343 384 422 483 425 3 Old Guar 30
0.3 237 365 429 490 528 542 4 Old Guar 30 0.35 223 336 415 493 542
551 5 New Guar 1 30 0.35 455 563 626 763 957 914 6 New Guar 1 30
0.4 403 516 657 687 830 1027 7 New Guar 1 30 0.45 461 680 841 1007
1007 1166 8 New Guar 1 30 0.5 756 818 923 1103 1174 1370 9 New Guar
1 30 0.6 821 956 1337 1259 1303 1374 10 New Guar 1 17 0.45 225 237
254 279 295 315 11 New Guar 1 17 1.25 254 263 322 334 339 342 12
New Guar 2 17 1.5 380 440 480 500 510 525 13 New Guar 2 17 0.45 380
395 409 430 415 448 14 New Guar 2 17 0.45 345 355 385 370 390 387
15 New Guar 2 17 0.45 370 360 390 385 400 420 16 Old Guar 30 2.0
774 729 691 727 768 703 17 Old Guar 17 1.25 N/A N/A N/A N/A N/A N/A
18 New Guar 2 17 1.5 300 315 335 320 340 350
[0038] The guar powder was mixed with 150 ml of tap water. To make
a gel that corresponds to a 17.0 lb (8 kg) gel, about 0.3 g of the
guar powder was used to mix in the tap water. To make a gel that
corresponds to a 30.0 lb (14 kg) gel, about 0.53 g of the guar
powder was used to mix in the tap water. The guar powder and water
were shaken for about 30 seconds to mix them together. Thereafter,
about 0.2 ml of pH buffer solution was added into the mixture and
shaken for about 10 seconds. A cross-linking agent was added to the
mixture and then shaken for about 20 more seconds. Within 1 minute,
the resulting cross-linked gel was then placed in a FANN-50
rheometer for viscosity measurements. In the rheometer, a B5
extended bob was used, and the measurements were taken at 95 rpm
and at 140 degrees F. (60.degree. C., 333 K). The viscosity
measurements for 10 minute intervals and the amounts of
cross-linker used are depicted in TABLE 2. From the results shown
in TABLE 2, it may be seen that the New Guar 1 and New Guar 2
exhibit much higher viscosities than the Old Guar. In addition, the
New Guar 1 and New Guar 2 powders maintain their viscosities and
gelled form over time.
EXAMPLES 11, 12, 16, and 17
[0039] Examples 11, 12, and 17 illustrate a procedure for
on-the-fly making of a 17.0 lb (8 kg) gel. In these examples,
several times more cross-linking agents were admixed to the water
than in the previous examples. The results are also shown in TABLE
2.
[0040] In these examples, 1.02 g of guar powder was hydrated in
500.0 ml of water for about 30 minutes in a Waring blender at about
1200 rpm. A borate cross-linking agent was then added to the fluid
and further mixed for about two minutes. The resulting cross-linked
gel was then placed in a FANN-50 rheometer for viscosity
measurements. In the rheometer, a B5 extended bob was used, and the
measurements were taken at 95 rpm and at 140 degrees F (60.degree.
C., 333 K). The viscosity measurements for 10 minute intervals and
the amounts of cross-linker used are shown in TABLE 2. From the
results shown in TABLE 2, it may be seen that the New Guar 1 and
New Guar 2 exhibit much higher viscosities than the Old Guar, which
did not even exhibit any measurable viscosity. Indeed, Example 17
shows that no cross-linking takes place in using the Old Guar to
make a 17.0 lb (8 kg) gel according to various illustrative
embodiments of the present invention, even with 1.25 ml of borate
used to cross-link.
[0041] Example 16 illustrates the making of a 30.0 lb (14 kg) gel
using the Old Guar and the on-the-fly procedure described above.
Using 2.0 ml of borate to cross-link, Example 16 exhibits a
measurable viscosity and shows that cross-linking took place. For
the sake of comparison, the 17.0 lb (8 kg) gel of Example 17 also
used the Old Guar and the same procedure as Example 16 but did not
exhibit any measurable viscosity. From the results of Examples 11,
12, 16, and 17, it may be seen that the use of the New Guar 1 and
New Guar 2 allows for a measurable viscosity by the use of a 17.0
lb (8 kg) gel in the above procedure, whereas use of the Old Guar
allows for a measurable viscosity by the use of a 30.0 lb (14 kg)
gel in the above procedure but not by the use of a 17.0 lb (14 kg)
gel.
EXAMPLE 14
[0042] In this example, the New Guar 2 was used in the liquid
slurry form of the prior art. The results are also shown in TABLE
2.
[0043] A liquid slurry was made using a 48/50 ratio of New Guar 2
to Diesel No. 2 and about 1.45 ml of this liquid slurry was mixed
with about 150 ml of tap water and shaken for about 30 seconds.
Thereafter, about 0.2 ml of pH buffer solution was added into the
mixture and shaken for about 10 seconds. A cross-linking agent was
added to the mixture and then shaken for about 20 more seconds. The
resulting cross-linked gel was then placed in a FANN-50 rheometer
for viscosity measurements. In the rheometer, a B5 extended bob was
used, and the measurements were taken at 95 rpm and at 140 degrees
F. (60.degree. C., 333 K). As shown in TABLE 2, the liquid slurry
produces a lower viscosity than the on-the-fly gel using the New
Guar 2 powder. For the sake of comparison, example 13 used the same
New Guar 2 powder and the same amount of cross-linking agent but
had a higher resulting viscosity.
EXAMPLE 15
[0044] In this example, about 0.3 g of the New Guar 2 powder was
mixed with 150 ml of tap water in a homogenizer with an open disc
for about 30 seconds, which yields a mixture that is comparable to
a 17.0 lb (8 kg) gel. Thereafter, about 0.2 ml of pH buffer
solution was added into the mixture and mixed for about 10 seconds
in the homogenizer. A cross-linking agent was added to the mixture
and then mixed in the homogenizer for about 20 more seconds. The
resulting cross-linked gel was then placed in a FANN-50 rheometer
for viscosity measurements. In the rheometer, a B5 extended bob was
used, and the measurements were taken at 95 rpm and at 140 degrees
F. (60.degree. C., 333 K). The viscosity measurements for 10 minute
intervals are shown in TABLE 2.
EXAMPLE 18
[0045] This example illustrates a procedure for on-the-fly making
of a 17.0 lb (8 kg) gel with a 30 second mixing of the guar powder
and hydrating liquid. The results are also shown in TABLE 2. In
this example, 1.02 g of New Guar 2 was hydrated in 500.0 ml of
water for about 30 seconds in a Waring blender at about 1200 rpm.
About 1.25 mls of borate cross-linking agent was then added to the
fluid and further mixed for about two minutes. The resulting
cross-linked gel was then placed in a FANN-50 rheometer for
viscosity measurements. In the rheometer, a B5 extended bob was
used, and the measurements were taken at 95 rpm and at 140 degrees
F (60.degree. C., 333 K). The viscosity measurements for 10 minute
intervals and the amounts of cross-linker used are shown in TABLE
2. From the results shown in TABLE 2, it may be seen that the New
Guar 2 exhibits a high viscosity and a fast hydration with only 30
seconds of mixing in the Waring blender. For the sake of
comparison, Example 11, which used New Guar 1, used the same
procedure as this Example 18, except that Example 11 hydrated the
guar powder in the water for about 30 minutes in the Waring
blender, instead of the hydration for about 30 seconds of Example
18. However, the resulting viscosities of Example 11 and 18 are
similar.
[0046] Although the present invention and its advantages have been
described in detail, it should be understood that various changes,
substitutions and alterations can be made herein without departing
from the spirit and scope of the invention as defined by the
appended claims. In particular, every range of values disclosed
herein is to be understood as referring to the power set (the set
of all subsets) of the respective range of values, in the sense of
Georg Cantor. Accordingly, the protection sought herein is as set
forth in the claims below.
* * * * *