U.S. patent application number 10/862000 was filed with the patent office on 2005-12-08 for methods of treating subterranean formations using low-molecular-weight fluids.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES. Invention is credited to Adams, David M., Farabee, Leldon M., Stegent, Neil A..
Application Number | 20050269099 10/862000 |
Document ID | / |
Family ID | 35446439 |
Filed Date | 2005-12-08 |
United States Patent
Application |
20050269099 |
Kind Code |
A1 |
Stegent, Neil A. ; et
al. |
December 8, 2005 |
Methods of treating subterranean formations using
low-molecular-weight fluids
Abstract
The present invention relates to systems and methods useful in
subterranean treatment operations. More particularly, the present
invention relates to systems and methods for treating subterranean
formations using low-molecular weight treatment fluids. Examples of
methods of the present invention include methods of fracturing a
subterranean formation; methods of enhancing production from
multiple subterranean formations penetrated by a well bore during a
single trip through the well bore; methods of enhancing production,
in real time, from multiple subterranean formations penetrated by a
well bore during a single trip through the well bore; and methods
of reducing the cost of enhancing production from multiple
subterranean formations penetrated by a well bore by stimulating
multiple formations, on a single trip through the well bore, with a
fluid that minimizes damage to the formation.
Inventors: |
Stegent, Neil A.; (Kilgore,
TX) ; Adams, David M.; (Katy, TX) ; Farabee,
Leldon M.; (Houston, TX) |
Correspondence
Address: |
Robert A. Kent
Halliburton Energy Services
2600 South Second Street
P.O. Drawer 1431
Duncan
OK
73536-0440
US
|
Assignee: |
HALLIBURTON ENERGY SERVICES
|
Family ID: |
35446439 |
Appl. No.: |
10/862000 |
Filed: |
June 4, 2004 |
Current U.S.
Class: |
166/308.1 |
Current CPC
Class: |
E21B 7/18 20130101; E21B
43/26 20130101 |
Class at
Publication: |
166/308.1 |
International
Class: |
E21B 043/26 |
Claims
What is claimed is:
1. A method of fracturing a subterranean formation comprising the
steps of: positioning a hydrojetting tool having at least one fluid
jet forming nozzle in a portion of the subterranean formation to be
fractured; jetting a low-molecular-weight fluid through the at
least one fluid jet forming nozzle against the formation at a
pressure sufficient to form a cavity in the formation; and further
jetting the low-molecular-weight fluid through the nozzle to create
or enhance at least one fracture in the formation.
2. The method of claim 1 wherein the step of further jetting the
low-molecular-weight fluid through the nozzle to create or enhance
at least one fracture in the formation comprises the step of
permitting stagnation pressure in the cavity to create or enhance
the at least one fracture.
3. The method of claim 1 wherein the pressure sufficient to form a
cavity in the formation is a pressure of about two times the
pressure required to initiate a fracture in the formation, less the
ambient pressure in a well bore adjacent to the formation.
4. The method of claim 1 further comprising the step of aligning
the at least one fluid jet forming nozzle of the hydrojetting tool
with the plane of maximum principal stress in the formation.
5. The method of claim 1 wherein the hydrojetting tool comprises a
plurality of fluid jet forming nozzles.
6. The method of claim 5 wherein the fluid jet forming nozzles are
disposed in a single plane.
7. The method of claim 5 wherein the fluid jet forming nozzles are
disposed in different planes.
8. The method of claim 6 further comprising the step of aligning
the plane of fluid jet forming nozzles with the plane of maximum
principal stress in the formation.
9. The method of claim 1 wherein the low-molecular-weight fluid
further comprises a proppant.
10. The method of claim 9 wherein the proppant is sand.
11. The method of claim 9 further comprising the step of slowly
reducing the jetting pressure of the low-molecular-weight fluid to
thereby allow the at least one created or enhanced fracture to
close on the proppant.
12. The method of claim 1 wherein the low-molecular-weight fluid
has an average molecular weight in the range of from about 100,000
to about 250,000.
13. The method of claim 1 wherein the low-molecular-weight fluid
has a viscosity of at least about 2 cP, where the viscosity is
measured at about 25.degree. C.
14. The method of claim 1 wherein the low-molecular-weight fluid
comprises an acid system.
15. The method of claim 14 wherein the acid system comprises a
viscosifier.
16. The method of claim 15 wherein the viscosifier comprises an
emulsifier or a surfactant.
17. The method of claim 14 wherein the acid system comprises a
hydrochloric acid based delayed carbonate acid system or a
hydrofluoric acid based delayed carbonate acid system.
18. The method of claim 1 wherein the low-molecular-weight fluid
comprises water.
19. The method of claim 1 wherein the low-molecular-weight fluid
comprises water, a substantially fully hydrated depolymerized
polymer, and a crosslinking agent.
20. The method of claim 19 wherein the substantially fully hydrated
depolymerized polymer is a depolymerized polysaccharide.
21. The method of claim 19 wherein the substantially fully hydrated
depolymerized polymer is selected from the group consisting of
hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar, and
carboxymethylhydroxyethylguar.
22. The method of claim 19 wherein the substantially fully hydrated
depolymerized polymer is present in the low-molecular-weight fluid
in an amount in the range of from about 0.2% to about 5% by weight
of the water therein.
23. The method of claim 19 wherein the low-molecular-weight fluid
has a viscosity of at least about 8.5 cP, where the viscosity is
measured at 25.degree. C.
24. The method of claim 19 wherein the crosslinking agent is a
boron-based compound, a compound that comprises zirconium IV ions,
a compound that comprises titanium IV ions, an aluminum compound,
or a compound that comprises antimony ions.
25. The method of claim 19 wherein the crosslinking agent is
present in the low-molecular-weight fluid in an amount in the range
of from about 50 ppm to about 5000 ppm active crosslinker.
26. The method of claim 1 wherein the low-molecular-weight fluid
further comprises a pH-adjusting compound, a delayed delinker, a
buffer, a surfactant, a clay stabilizer, a fluid loss control
agent, a scale inhibitor, a demulsifier, a bactericide, a breaker,
an activator, or a mixture thereof.
27. A method of fracturing a subterranean formation comprising:
positioning a hydrojetting tool having at least one fluid jet
forming nozzle in a portion of the subterranean formation to be
fractured; jetting a fluid through the at least one fluid jet
forming nozzle against the formation at a pressure sufficient to
create at least one fracture in the formation; and pumping a
low-molecular-weight fluid into an annulus between the hydrojetting
tool and the formation at a rate sufficient to raise the annular
pressure to a level sufficient to extend the fracture into the
formation.
28. The method of claim 27 wherein the fluid that is jetted is a
first fluid, and wherein the low-molecular-weight fluid that is
pumped into the annulus is a second fluid, and wherein the first
fluid is the same fluid as the second fluid.
29. The method of claim 28 wherein the second fluid is different
than the first fluid.
30. The method of claim 27 further comprising the steps of: moving
the hydrojetting tool to a different position in the formation;
repositioning the hydrojetting tool in a different portion of the
formation; jetting a fluid through the at least one fluid jet
forming nozzle against the formation at a pressure sufficient to
create at least one fracture in the formation; and pumping a
low-molecular-weight fluid into the annulus between the
hydrojetting tool and the formation at a rate sufficient to raise
the annular pressure to a level sufficient to extend the fracture
into the formation.
31. The method of claim 27 further comprising the step of aligning
the fluid jet forming nozzle of the hydrojetting tool with the
plane of maximum principal stress in the formation.
32. The method of claim 27 wherein the hydrojetting tool comprises
a plurality of fluid jet forming nozzles.
33. The method of claim 32 wherein the fluid jet forming nozzles
are disposed in a single plane.
34. The method of claim 32 wherein the fluid jet forming nozzles
are disposed in different planes.
35. The method of claim 33 further comprising the step of aligning
the plane of fluid jet forming nozzles with the plane of maximum
principal stress in the formation.
36. The method of claim 27 wherein the low-molecular-weight fluid
further comprises a proppant.
37. The method of claim 36 wherein the proppant is sand.
38. The method of claim 27 wherein the low-molecular-weight fluid
has an average molecular weight in the range of from about 100,000
to about 250,000.
39. The method of claim 27 wherein the low-molecular-weight fluid
has a viscosity of at least about 2 cP, where the viscosity is
measured at about 25.degree. C.
40. The method of claim 27 wherein the low-molecular-weight fluid
comprises an acid system.
41. The method of claim 40 wherein the acid system comprises a
viscosifier.
42. The method of claim 40 wherein the acid system comprises a
hydrochloric acid based delayed carbonate acid system or a
hydrofluoric acid based delayed carbonate acid system.
43. The method of claim 27 wherein the low-molecular-weight fluid
comprises water.
44. The method of claim 27 wherein the low-molecular-weight fluid
comprises water, a substantially fully hydrated depolymerized
polymer, and a crosslinking agent.
45. The method of claim 44 wherein the substantially fully hydrated
depolymerized polymer is a depolymerized polysaccharide.
46. The method of claim 44 wherein the substantially fully hydrated
depolymerized polymer is selected from the group consisting of
hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar, and
carboxymethylhydroxyethylguar.
47. The method of claim 44 wherein the substantially fully hydrated
depolymerized polymer is present in the low-molecular-weight fluid
in an amount in the range of from about 0.2% to about 5% by weight
of the water therein.
48. A method of enhancing production from multiple subterranean
formations penetrated by a well bore during a single trip through
the well bore, comprising: positioning a hydrojetting tool having
at least one fluid jet forming nozzle in a portion of the
subterranean formation to be fractured; jetting a fluid through the
at least one fluid jet forming nozzle against the formation at a
pressure sufficient to create at least one fracture in the
formation; pumping a low-molecular-weight fluid into an annulus
between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation; repositioning the
hydrojetting tool in a different portion of the formation; and
repeating the steps of jetting a fluid through the at least one
fluid jet forming nozzle against the formation at a pressure
sufficient to create at least one fracture in the formation and
pumping a low-molecular-weight fluid into the annulus between the
hydrojetting tool and the formation at a rate sufficient to raise
the annular pressure to a level sufficient to extend the fracture
into the formation.
49. The method of claim 48 wherein the fluid that is jetted is a
first fluid, and wherein the low-molecular-weight fluid that is
pumped into the annulus is a second fluid, and wherein the first
fluid is the same fluid as the second fluid.
50. The method of claim 49 wherein the second fluid is different
than the first fluid.
51. The method of claim 48 wherein the low-molecular-weight fluid
further comprises a proppant.
52. The method of claim 51 wherein the proppant is sand.
53. The method of claim 48 wherein the low-molecular-weight fluid
has an average molecular weight in the range of from about 100,000
to about 250,000.
54. The method of claim 48 wherein the low-molecular-weight fluid
has a viscosity of at least about 2 cP, where the viscosity is
measured at about 25.degree. C.
55. The method of claim 48 wherein the low-molecular-weight fluid
comprises an acid system.
56. The method of claim 55 wherein the acid system comprises a
viscosifier.
57. The method of claim 55 wherein the acid system comprises a
hydrochloric acid based delayed carbonate acid system or a
hydrofluoric acid based delayed carbonate acid system.
58. The method of claim 48 wherein the low-molecular-weight fluid
comprises water.
59. The method of claim 48 wherein the low-molecular-weight fluid
comprises water, a substantially fully hydrated depolymerized
polymer, and a crosslinking agent.
60. The method of claim 59 wherein the substantially fully hydrated
depolymerized polymer is a depolymerized polysaccharide.
61. The method of claim 59 wherein the substantially fully hydrated
depolymerized polymer is selected from the group consisting of
hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar, and
carboxymethylhydroxyethylguar.
62. The method of claim 59 wherein the substantially fully hydrated
depolymerized polymer is present in the low-molecular-weight fluid
in an amount in the range of from about 0.2% to about 5% by weight
of the water therein.
63. A method of enhancing production, in real time, from multiple
subterranean formations penetrated by a well bore during a single
trip through the well bore, comprising positioning a hydrojetting
tool having at least one fluid jet forming nozzle in a portion of
the subterranean formation to be fractured; jetting a fluid through
the at least one fluid jet forming nozzle against the formation at
a pressure sufficient to create at least one fracture in the
formation; pumping a low-molecular-weight fluid into an annulus
between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation; determining, in real time,
at least one parameter related to the creation or enhancement of
the fracture; repositioning the hydrojetting tool in a different
portion of the formation; and repeating the steps of jetting a
fluid through the at least one fluid jet forming nozzle against the
formation at a pressure sufficient to create at least one fracture
in the formation and pumping a low-molecular-weight fluid into the
annulus between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation.
64. The method of claim 63 wherein the fluid that is jetted is a
first fluid, and wherein the low-molecular-weight fluid that is
pumped into the annulus is a second fluid, and wherein the first
fluid is the same fluid as the second fluid.
65. The method of claim 64 wherein the second fluid is different
than the first fluid.
66. The method of claim 63 wherein the step of determining, in real
time, at least one parameter related to the creation or enhancement
of the fracture comprises determining, in real time, that at least
one fracture therein has been created or enhanced to a desired
extent.
67. The method of claim 63 wherein the step of relocating the
hydrojetting tool within the well bore to another desired location
in the same, or different, formation is performed after the step of
determining, in real time, that at least one fracture therein has
been created or enhanced to a desired extent.
68. The method of claim 63 further comprising performing a
remediative step after the step of determining, in real time, at
least one parameter related to the creation or enhancement of the
fracture.
69. The method of claim 68 wherein the remediative step comprises
reducing the concentration of a proppant present in the
low-molecular-weight fluid.
70. The method of claim 68 wherein the remediative step comprises
reducing the viscosity of the low-molecular-weight fluid.
71. The method of claim 63 wherein the low-molecular-weight fluid
further comprises a proppant.
72. The method of claim 71 wherein the proppant is sand.
73. The method of claim 63 wherein the low-molecular-weight fluid
has an average molecular weight in the range of from about 100,000
to about 250,000.
74. The method of claim 63 wherein the low-molecular-weight fluid
has a viscosity of at least about 2 cP, where the viscosity is
measured at about 25.degree. C.
75. The method of claim 63 wherein the low-molecular-weight fluid
comprises an acid system.
76. The method of claim 75 wherein the acid system comprises a
viscosifier.
77. The method of claim 75 wherein the acid system comprises a
hydrochloric acid based delayed carbonate acid system or a
hydrofluoric acid based delayed carbonate acid system.
78. The method of claim 63 wherein the low-molecular-weight fluid
comprises water.
79. The method of claim 63 wherein the low-molecular-weight fluid
comprises water, a substantially fully hydrated depolymerized
polymer, and a crosslinking agent.
80. The method of claim 79 wherein the substantially fully hydrated
depolymerized polymer is a depolymerized polysaccharide.
81. The method of claim 79 wherein the substantially fully hydrated
depolymerized polymer is selected from the group consisting of
hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar, and
carboxymethylhydroxyethylguar.
82. The method of claim 79 wherein the substantially fully hydrated
depolymerized polymer is present in the low-molecular-weight fluid
in an amount in the range of from about 0.2% to about 5% by weight
of the water therein.
83. A method of reducing the cost of enhancing production from
multiple subterranean formations penetrated by a well bore by
stimulating multiple formations, on a single trip through the well
bore, with a fluid that minimizes damage to the formation
comprising: positioning a hydrojetting tool having at least one
fluid jet forming nozzle in a portion of the subterranean formation
to be fractured; jetting a fluid through the at least one fluid jet
forming nozzle against the formation at a pressure sufficient to
create at least one fracture in the formation; pumping a
low-molecular-weight fluid into an annulus between the hydrojetting
tool and the formation at a rate sufficient to raise the annular
pressure to a level sufficient to extend the fracture into the
formation; repositioning the hydrojetting tool in a different
portion of the formation; and repeating the steps of jetting a
fluid through the at least one fluid jet forming nozzle against the
formation at a pressure sufficient to create at least one fracture
in the formation and pumping a low-molecular-weight fluid into the
annulus between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation; wherein the
low-molecular-weight fluid enhances the regain permeability of the
subterranean formation.
84. The method of claim 83 wherein the fluid that is jetted is a
first fluid, and wherein the low-molecular-weight fluid that is
pumped into the annulus is a second fluid, and wherein the first
fluid is the same fluid as the second fluid.
85. The method of claim 84 wherein the second fluid is different
than the first fluid.
86. The method of claim 83 wherein the low-molecular-weight fluid
further comprises a proppant.
87. The method of claim 86 wherein the proppant is sand.
88. The method of claim 83 wherein the low-molecular-weight fluid
has an average molecular weight in the range of from about 100,000
to about 250,000.
89. The method of claim 83 wherein the low-molecular-weight fluid
has a viscosity of at least about 2 cP, where the viscosity is
measured at about 25.degree. C.
90. The method of claim 83 wherein the low-molecular-weight fluid
comprises an acid system.
91. The method of claim 90 wherein the acid system comprises a
viscosifier.
92. The method of claim 90 wherein the acid system comprises a
hydrochloric acid based delayed carbonate acid system or a
hydrofluoric acid based delayed carbonate acid system.
93. The method of claim 83 wherein the low-molecular-weight fluid
comprises water.
94. The method of claim 83 wherein the low-molecular-weight fluid
comprises water, a substantially fully hydrated depolymerized
polymer, and a crosslinking agent.
95. The method of claim 94 wherein the substantially fully hydrated
depolymerized polymer is a depolymerized polysaccharide.
96. The method of claim 94 wherein the substantially fully hydrated
depolymerized polymer is selected from the group consisting of
hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar, and
carboxymethylhydroxyethylguar.
97. The method of claim 94 wherein the substantially fully hydrated
depolymerized polymer is present in the low-molecular-weight fluid
in an amount in the range of from about 0.2% to about 5% by weight
of the water therein.
Description
BACKGROUND OF THE INVENTION TECHNOLOGY
[0001] The present invention relates to systems and methods useful
in subterranean treatment operations. More particularly, the
present invention relates to systems and methods for treating
subterranean formations using low-molecular weight treatment
fluids.
[0002] Hydrocarbon-bearing subterranean formations penetrated by
well bores often may be treated to increase their permeability or
conductivity, and thereby facilitate greater hydrocarbon production
therefrom. One such production stimulation treatment, known as
"fracturing," involves injecting a treatment fluid (e.g., a
"fracturing fluid") into a subterranean formation or zone at a rate
and pressure sufficient to create or enhance at least one fracture
therein. Fracturing fluids commonly comprise a proppant material
(e.g., sand, or other particulate material) suspended within the
fracturing fluid, which may be deposited into the created
fractures. The proppant material functions, inter alia, to prevent
the formed fractures from re-closing upon termination of the
fracturing operation. Upon placement of the proppant in the formed
fractures, conductive channels may remain within the zone or
formation, through which channels produced fluids readily may flow
to the well bore upon completion of the fracturing operation.
[0003] Because most fracturing fluids should suspend proppant
material, the viscosity of fracturing fluids often has been
increased through inclusion of a viscosifier. After a viscosified
fracturing fluid has been pumped into the formation to create or
enhance at least one fracture therein, the fracturing fluid
generally may be "broken" (e.g., caused to revert into a low
viscosity fluid), to facilitate its removal from the formation. The
breaking of viscosified fracturing fluids commonly has been
accomplished by including a breaker within the fracturing
fluid.
[0004] The fracturing fluids utilized heretofore predominantly have
been water-based liquids containing a viscosifier that comprises a
polysaccharide (e.g., guar gum). Guar, and derivatized guar
polymers such as hydroxypropylguar, are water-soluble polymers that
may be used to create high viscosity in an aqueous fracturing
fluid, and that readily may be crosslinked to further increase the
viscosity of the fracturing fluid. While the use of gelled and
crosslinked polysaccharide-containing fracturing fluids has been
successful, such fracturing fluids often have not been thermally
stable at temperatures above about 200.degree. F. That is, the
viscosity of the highly viscous gelled and crosslinked fluids may
decrease over time at high temperatures. To offset the decreased
viscosity, the concentration of the viscosifier often may be
increased, which may result in, inter alia, increased costs and
increased friction pressure in the tubing through which the
fracturing fluid is injected into a subterranean formation. This
may increase the difficulty of pumping the fracturing fluids.
Thermal stabilizers, such as sodium thiosulfate, often have been
included in fracturing fluids, inter alia, to scavenge oxygen and
thereby increase the stabilities of fracturing fluids at high
temperatures. However, the use of thermal stabilizers also may
increase the cost of the fracturing fluids.
[0005] Certain types of subterranean formations, such as certain
types of shales and coals, may respond unfavorably to fracturing
with conventional fracturing fluids. For example, in addition to
opening a main, dominant fracture, the fracturing fluid may further
invade numerous natural fractures (or "butts" and "cleats," where
the formation comprises coal) that may intersect the main fracture,
which may cause conventional viscosifiers within the fracturing
fluid to invade intersecting natural fractures. When the natural
fractures re-close at the conclusion of the fracturing operation,
the conventional viscosifiers may become trapped therein, and may
obstruct the flow of hydrocarbons from the natural fractures to the
main fracture. Further, even in circumstances where the viscosifier
does not become trapped within the natural fractures, a thin
coating of gel nevertheless may remain on the surface of the
natural fractures after the conclusion of the fracturing operation.
This may be problematic, inter alia, where the production of
hydrocarbons from the subterranean formation involves processes
such as desorption of the hydrocarbon from the surface of the
formation. Previous attempts to solve these problems have involved
the use of less viscous fracturing fluids, such as non-gelled
water. However, this may be problematic, inter alia, because such
fluids may prematurely dilate natural fractures perpendicular to
the main fracture--a problem often referred to as "near well bore
fracture complexity," or "near well bore tortuosity." This may be
problematic because the creation of multiple fractures, as opposed
to one or a few dominant fractures, may result in reduced
penetration into the formation, e.g., for a given injection rate,
many short fractures may be created rather than one, or a few,
lengthy fracture(s). This may be problematic because in low
permeability formations, the driving factor to increase
productivity often is the fracture length. Furthermore, the use of
less viscous fracturing fluids also may require excessive fluid
volumes, and/or excessive injection pressure. Excessive injection
pressure may frustrate attempts to place proppant into the
fracture, thereby reducing the likelihood that the fracturing
operation will increase hydrocarbon production.
[0006] It often is desirable to selectively treat hydrocarbon
zones, or formations, to extract hydrocarbons therefrom while
isolating the formation from other intervals in a well bore. Such
selective treatment operations may include perforating well casing
that may be installed in the well bore, and introducing a
fracturing fluid through tubing into a tool assembly in the casing,
and to a ported sub, or the like, connected in the tool assembly.
The fracturing fluid generally discharges from the ported sub at a
relatively high pressure, and passes through the perforations in
the well casing and into the formation to create or enhance at
least one fracture therein. Often, the formation may be isolated by
setting packers above, and below, the ported sub to isolate the
zone during the fracturing operation.
[0007] However, these types of techniques may be problematic. For
example, the use of a packer above the ported sub may create a high
pressure differential between the formation and the area of the
well above the packer, which may cause the packer to unseat during
operation, possibly resulting in an unsuccessful fracture
treatment, tool damage, and loss of well control.
[0008] Also, the introduction of fracturing fluid through the
tubing and tool assembly may create additional problems, not the
least of which may be the fluid friction created by the flow of the
fracturing fluid, which may lead to mechanical failure of both the
tubing and tool assembly.
SUMMARY OF THE INVENTION
[0009] The present invention relates to systems and methods useful
in subterranean treatment operations. More particularly, the
present invention relates to systems and methods for treating
subterranean formations using low-molecular weight treatment
fluids.
[0010] An example of a method of the present invention is a method
of fracturing a subterranean formation comprising the steps of:
positioning a hydrojetting tool having at least one fluid jet
forming nozzle in a portion of the subterranean formation to be
fractured; jetting a low-molecular-weight fluid through the at
least one fluid jet forming nozzle against the formation at a
pressure sufficient to form a cavity in the formation; and further
jetting the low-molecular-weight fluid through the nozzle to create
or enhance at least one fracture in the formation.
[0011] Another example of a method of the present invention is a
method of fracturing a subterranean formation comprising:
positioning a hydrojetting tool having at least one fluid jet
forming nozzle in a portion of the subterranean formation to be
fractured; jetting a fluid through the at least one fluid jet
forming nozzle against the formation at a pressure sufficient to
create at least one fracture in the formation; and pumping a
low-molecular-weight fluid into an annulus between the hydrojetting
tool and the formation at a rate sufficient to raise the annular
pressure to a level sufficient to extend the fracture into the
formation.
[0012] Another example of a method of the present invention is a
method of enhancing production from multiple subterranean
formations penetrated by a well bore during a single trip through
the well bore, comprising: positioning a hydrojetting tool having
at least one fluid jet forming nozzle in a portion of the
subterranean formation to be fractured; jetting a fluid through the
at least one fluid jet forming nozzle against the formation at a
pressure sufficient to create at least one fracture in the
formation; pumping a low-molecular-weight fluid into an annulus
between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation; repositioning the
hydrojetting tool in a different portion of the formation; and
repeating the steps of jetting a fluid through the at least one
fluid jet forming nozzle against the formation at a pressure
sufficient to create at least one fracture in the formation and
pumping a low-molecular-weight fluid into the annulus between the
hydrojetting tool and the formation at a rate sufficient to raise
the annular pressure to a level sufficient to extend the fracture
into the formation.
[0013] Yet another example of a method of the present invention is
a method of enhancing production, in real time, from multiple
subterranean formations penetrated by a well bore during a single
trip through the well bore, comprising: positioning a hydrojetting
tool having at least one fluid jet forming nozzle in a portion of
the subterranean formation to be fractured; jetting a fluid through
the at least one fluid jet forming nozzle against the formation at
a pressure sufficient to create at least one fracture in the
formation; pumping a low-molecular-weight fluid into an annulus
between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation; determining, in real time,
at least one parameter related to the creation or enhancement of
the fracture; repositioning the hydrojetting tool in a different
portion of the formation; and repeating the steps of jetting a
fluid through the at least one fluid jet forming nozzle against the
formation at a pressure sufficient to create at least one fracture
in the formation and pumping a low-molecular-weight fluid into the
annulus between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation.
[0014] Still another example of a method of the present invention
is a method of reducing the cost of enhancing production from
multiple subterranean formations penetrated by a well bore by
stimulating multiple formations, on a single trip through the well
bore, with a fluid that minimizes damage to the formation
comprising: positioning a hydrojetting tool having at least one
fluid jet forming nozzle in a portion of the subterranean formation
to be fractured; jetting a fluid through the at least one fluid jet
forming nozzle against the formation at a pressure sufficient to
create at least one fracture in the formation; pumping a
low-molecular-weight fluid into an annulus between the hydrojetting
tool and the formation at a rate sufficient to raise the annular
pressure to a level sufficient to extend the fracture into the
formation; repositioning the hydrojetting tool in a different
portion of the formation; and repeating the steps of jetting a
fluid through the at least one fluid jet forming nozzle against the
formation at a pressure sufficient to create at least one fracture
in the formation and pumping a low-molecular-weight fluid into the
annulus between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation; wherein the
low-molecular-weight fluid enhances the regain permeability of the
subterranean formation.
[0015] 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] A more complete understanding of the present disclosure and
advantages thereof may be acquired by referring to the following
description taken in conjunction with the accompanying drawings,
wherein:
[0017] FIG. 1 depicts an embodiment of a tool assembly that may be
used with the methods of the present invention.
[0018] FIG. 2 is a side cross sectional partial view of a deviated
well bore having an embodiment of a tool assembly that may be used
with the methods of the present invention therein.
[0019] FIG. 3 is a side cross sectional view of the deviated well
bore of FIG. 2, after a plurality of microfractures and extended
fractures have been created therein in accordance with certain
embodiments of the present invention.
[0020] FIG. 4 is a cross sectional view taken along line 4-4 of
FIG. 2.
[0021] While the present invention is susceptible to various
modifications and alternative forms, specific embodiments thereof
have been shown in the drawings and are herein described. It should
be understood, however, that the description herein of specific
embodiments is not intended to limit the invention to the
particular forms disclosed, but on the contrary, the intention is
to cover all modifications, equivalents, and alternatives falling
within the spirit and scope of the invention as defined by the
appended claims.
DETAILED DESCRIPTION OF EMBODIMENTS
[0022] The present invention relates to systems and methods useful
in subterranean treatment operations. More particularly, the
present invention relates to systems and methods for treating
subterranean formations using low-molecular-weight fluids. As
referred to herein, the term "low-molecular-weight fluid" is
defined to mean a fluid that has an average molecular weight of
less than about 1,000,000. Certain embodiments of the
low-molecular-weight fluids useful in accordance with the present
invention may have a viscosity, measured at a reference temperature
of about 25.degree. C., of at least about 2 cP; such viscosity may
be measured on, for example, a Fann Model 35 viscometer, or the
like. Certain other embodiments of low-molecular-weight fluids
useful with the present invention may have a lower viscosity, such
as, for example, when the low-molecular-weight fluid is water.
[0023] In certain embodiments of the present invention, the use of
a low-molecular-weight fluid in the methods and systems of the
present invention may result in, among other things, improved
cleanup of the low-molecular-weight fluid at the conclusion of the
treatment operation, and reduced loss of the low-molecular-weight
fluid into the subterranean formation during the treatment
operation. The subterranean formation also may exhibit improved
"regain permeability" upon the conclusion of the treatment
operation. As referred to herein, the term "regain permeability"
will be understood to mean the degree to which the permeability of
a formation that has been exposed to a treatment fluid approaches
the original permeability of the formation. For example, a
determination that a subterranean formation evidences "100% regain
permeability" at the conclusion of a treatment operation indicates
that the permeability of the formation, post-operation, is equal to
its permeability before the treatment operation. In certain
embodiments of the present invention, the methods and systems of
the present invention may permit, inter alia, highly accurate,
"pinpoint" placement of a fracture that has been created or
enhanced through the injection of a low-molecular-weight fluid at a
desired location in a reservoir.
[0024] In certain embodiments of the present invention, the
low-molecular-weight fluid may comprise an acid system. The acid
system may be polymer-based or nonpolymer-based. In certain
embodiments, the acid system may comprise a viscosifier (sometimes
referred to as a "gelling agent."). Where the acid system comprises
a viscosifier, a broad variety of viscosifiers may be used,
including, but not limited to, emulsifiers and surfactants.
Examples of suitable viscosifiers include, but are not limited to,
those that are commercially available from Halliburton Energy
Services, Inc., under the trade names SGA-HT, SGA-I, and SGA-II. In
certain embodiments wherein the low-molecular-weight fluid used in
the methods and systems of the present invention is an acid system
that comprises a viscosifier, the viscosifier may be present in the
acid system in an amount in the range of from about 0.001% to about
0.035% by volume. Examples of other acid systems that may be
suitable include, but are not limited to, a hydrochloric acid based
delayed carbonate acid system that is commercially available from
Halliburton Energy Services, Inc., under the trade name CARBONATE
20/20, and a hydrofluoric acid based delayed carbonate acid system
that is commercially available from Halliburton Energy Services,
Inc., under the trade name SANDSTONE 2000.
[0025] Another example of a suitable low-molecular-weight fluid
that may be used with the methods and systems of the present
invention is water. Generally, the water may be from any
source.
[0026] Another example of a suitable low-molecular-weight fluid is
described in U.S. Pat. No. 6,488,091, the relevant disclosure of
which is hereby incorporated by reference. Such
low-molecular-weight fluid has an average molecular weight in the
range of from about 100,000 to about 250,000, generally has a
viscosity (measured at a reference temperature of about 25.degree.
C., on, for example, a Fann Model 35 viscometer) of at least about
8 cP, and generally comprises water, a substantially fully hydrated
depolymerized polymer, and a crosslinking agent for crosslinking
the substantially fully hydrated depolymerized polymer. The water
can be selected from fresh water, unsaturated salt water (e.g.,
brines and seawater), and saturated salt water. The substantially
fully hydrated depolymerized polymer in the low-molecular-weight
fluid may be, inter alia, a depolymerized polysaccharide. In
certain embodiments, the substantially fully hydrated depolymerized
polymer is a substantially fully hydrated depolymerized guar
derivative polymer selected from the group consisting of
hydroxypropylguar, carboxymethylhydroxypropylguar,
carboxymethylguar, hydroxyethylguar and
carboxymethylhydroxyethylguar. In certain embodiments, the
substantially fully hydrated depolymerized polymer is substantially
fully hydrated depolymerized hydroxypropylguar. Generally, where
the low-molecular-weight fluid comprises water, a substantially
fully hydrated depolymerized polymer, and a crosslinking agent, the
substantially fully hydrated depolymerized polymer is present in
the low-molecular-weight fluid in an amount in the range of from
about 0.2% to about 5% by weight of the water therein.
[0027] Optionally, the low-molecular-weight fluids suitable for use
with the present invention may further comprise a crosslinking
agent. A broad variety of crosslinking agents may be suitable for
use in accordance with the methods and systems of the present
invention. For example, where the low-molecular-weight fluids
useful in the present invention comprise water, and a substantially
fully hydrated depolymerized polymer, suitable crosslinking agents
include, but are not limited to, boron-based compounds (e.g., boric
acid, ulexite, colemanite, disodium octaborate tetrahydrate, sodium
diborate and pentaborates). The crosslinking of the substantially
fully hydrated depolymerized polymer that may be achieved by these
crosslinking agents generally is fully reversible (e.g., the
crosslinked, substantially fully hydrated polymer easily may be
delinked if and when desired). Metal-based crosslinking agents also
may be suitable, bearing in mind that crosslinking of the
substantially fully hydrated depolymerized polymer that may be
achieved by these crosslinking agents generally is less reversible.
Examples of suitable metal-based crosslinking agents include, but
are not limited to, compounds that can supply zirconium IV ions
(e.g., zirconium lactate, zirconium lactate triethanolamine,
zirconium carbonate, zirconium acetylacetonate and zirconium
diisopropylamine lactate), compounds that can supply titanium IV
ions (e.g., titanium ammonium lactate, titanium triethanolamine,
and titanium acetylacetonate), aluminum compounds (e.g., aluminum
lactate or aluminum citrate), or compounds that can supply antimony
ions. In certain embodiments, the crosslinking agent is a borate
compound. The exact type and amount of crosslinking agent, or
agents, used depends upon, inter alia, the specific substantially
fully hydrated depolymerized polymer to be crosslinked, formation
temperature conditions and other factors known to those individuals
skilled in the art. Where included, the optional crosslinking agent
may be present in the low-molecular-weight fluid in an amount in
the range of from about 50 ppm to about 5000 ppm active
crosslinker.
[0028] Optionally, when the low-molecular-weight fluids useful with
this invention are used to carry out a fracture stimulation
procedure, proppant material may be included in at least a portion
of the low-molecular-weight fluid as it is pumped into the
subterranean formation to be fractured and into fractures created
therein. For example, the proppant material may be metered into the
low-molecular-weight fluid as the low-molecular-weight fluid is
formed. The quantity of proppant material per volume of
low-molecular-weight fluid can be changed, as desired, in real
time. Examples of proppant material that may be utilized include,
but are not limited to, resin-coated or uncoated sand, sintered
bauxite, ceramic materials or glass beads. Suitable materials are
commercially available from Carboceramics, Inc., of Irving, Tex.;
Sintex Minerals & Services, Inc., of Houston, Tex.; and
Norton-Alcoa Proppants, of Fort Smith, Ark. Examples of
intermediate strength ceramic proppants that may be suitable
include, but are not limited to, EconoProp.RTM., Carbo Lite.RTM.,
Carbo Prop.RTM., Interprop.RTM., Naplite.RTM., and Valuprop.RTM..
Examples of high strength ceramic proppants include, but are not
limited to, Carbo HSP.RTM., Sintered Bauxite and SinterBall.RTM..
Where included, the proppant material utilized may be present in
the low-molecular-weight fluid in an amount in the range of from
about 0.25 to about 24 pounds of proppant material per gallon of
the low-molecular-weight fluid.
[0029] Optionally, in certain embodiments wherein the
low-molecular-weight fluid comprises water, a crosslinking agent,
and a substantially fully hydrated depolymerized polymer, a
pH-adjusting compound for adjusting the pH of the
low-molecular-weight fluid to the optimum pH for crosslinking may
be included in the low-molecular-weight treating fluid. The
pH-adjusting compound can be selected from sodium hydroxide,
potassium hydroxide, lithium hydroxide, fumaric acid, formic acid,
acetic acid, hydrochloric acid, acetic anhydride and the like. In
certain embodiments, the pH-adjusting compound is sodium hydroxide.
Where included, the pH-adjusting compound may be present in the
low-molecular-weight fluid in an amount in the range of from about
0.01% to about 0.3% by weight of the water in the
low-molecular-weight fluid. In certain embodiments wherein the
pH-adjusting compound comprises a borate compound, the pH-adjusting
compound is utilized to elevate the pH of the low-molecular-weight
fluid to above about 9. At that pH, the borate compound
crosslinking agent crosslinks the short chain hydrated polymer
segments. When the pH of the crosslinked low-molecular-weight fluid
falls below about 9, the crosslinked sites are no longer
crosslinked. Thus, when the crosslinked low-molecular-weight fluid
contacts the subterranean formation being treated, the pH may be
lowered to some degree, which may begin the breaking process.
[0030] Optionally, in certain embodiments wherein the
low-molecular-weight fluid comprises water, a crosslinking agent,
and a substantially fully hydrated depolymerized polymer, the
low-molecular-weight fluid may comprise a delayed delinker capable
of lowering the pH of the low-molecular-weight fluid. In certain
embodiments, the presence of the delayed delinker in the
low-molecular-weight fluid may cause the low-molecular-weight fluid
to completely revert to a thin fluid in a short period of time.
Examples of delayed delinkers that may be utilized include, but are
not limited to, various lactones, esters, encapsulated acids and
slowly-soluble acid-generating compounds, oxidizers which produce
acids upon reaction with water, water-reactive metals such as
aluminum, lithium and magnesium and the like. In certain
embodiments, the delayed delinker comprises an ester. Where
included, the delayed delinker may be present in the
low-molecular-weight fluid in an amount in the range of from about
0.01% to about 1% by weight of the water therein. Alternatively,
any of the conventionally used delayed breakers employed with metal
ion crosslinkers can be utilized, for example, oxidizers such as
sodium chlorite, sodium bromate, sodium persulfate, ammonium
persulfate, encapsulated sodium persulfate, potassium persulfate,
or ammonium persulfate, and the like, as well as magnesium
peroxide, and encapsulated acids. Enzyme breakers that may be
employed include alpha and beta amylases, amyloglucosidase,
invertase, maltase, cellulase and hemicellulase. The specific
breaker or delinker utilized, whether or not it is encapsulated, as
well as the amount thereof employed will depend upon factors
including, inter alia, the breaking time desired, the nature of the
polymer and crosslinking agent, and formation characteristics and
conditions.
[0031] Optionally, the low-molecular-weight fluid also may include
a surfactant. The inclusion of a surfactant in the
low-molecular-weight fluid may, inter alia, prevent the formation
of emulsions between the low-molecular-weight fluid and
subterranean formation fluids contacted by the low-molecular-weight
fluid. Examples of such surfactants include, but are not limited
to, alkyl sulfonates, alkyl aryl sulfonates (e.g., alkyl benzyl
sulfonates such as salts of dodecylbenzene sulfonic acid), alkyl
trimethylammonium chloride, branched alkyl ethoxylated alcohols,
phenol-formaldehyde anionic resin blends, cocobetaines, dioctyl
sodium sulfosuccinate, imidazolines, alpha olefin sulfonates,
linear alkyl ethoxylated alcohols, trialkyl benzylammonium
chloride, and the like. In certain embodiments, the surfactant may
comprise methanol. An example of a suitable surfactant is
commercially available from Halliburton Energy Services, Inc.,
under the trade name "LO-SURF 300." In certain embodiments, the
surfactant comprises dodecylbenzene sulfonic acid salts. Where
included, the surfactant generally is present in the
low-molecular-weight fluid in an amount in the range of from about
0.001% to about 0.5% by weight of the water therein.
[0032] Optionally, the low-molecular-weight fluid also may include
a clay stabilizer selected, for example, from the group consisting
of potassium chloride, sodium chloride, ammonium chloride,
tetramethyl ammonium chloride, and the like. An example of a
suitable clay stabilizer is commercially available from Halliburton
Energy Services, Inc., under the trade name "CLA-STA XP." In
certain embodiments, the clay stabilizer is potassium chloride or
tetramethyl ammonium chloride. Where included, the clay stabilizer
is generally present in the low-molecular-weight fluid in an amount
in the range of from about 0.001% to about 1% by weight of the
water therein.
[0033] Optionally, the low-molecular-weight fluid may comprise a
fluid loss control agent. Examples of fluid loss control agents
that may be used include, but are not limited to, silica flour,
starches, waxes, diesels, and resins. An example of a suitable
silica flour is commercially available from Halliburton Energy
Services, Inc., under the trade name "WAC-9." An example of a
suitable starch is commercially available from Halliburton Energy
Services, Inc., under the trade name "ADOMITE AQUA." Where
included, the fluid loss control agent may be present in the
low-molecular-weight fluid in an amount in the range of from about
0.01% to about 1% by weight of water therein.
[0034] Optionally, the low-molecular-weight fluid also may include
compounds for retarding the movement of the proppant within the
created or enhanced fracture. For example, materials in the form of
fibers, flakes, ribbons, beads, shavings, platelets and the like
that comprise glass, ceramics, carbon composite, natural or
synthetic polymers, resins, or metals and the like can be admixed
with the low-molecular-weight fluid and proppant. A more detailed
description of such materials is disclosed in, for example, U.S.
Pat. Nos. 5,330,005; 5,439,055; and 5,501,275 the relevant
disclosures of which are incorporated herein by reference. Examples
of suitable epoxy resins include those that are commercially
available from Halliburton Energy Services, Inc., under the trade
names "EXPEDITE" and "SAND WEDGE." Alternatively, or in addition to
the prior materials, a material comprising a tackifying compound
may be admixed with the low-molecular-weight fluid or the proppant
particulates to coat at least a portion of the proppant
particulates, or other solid materials identified above, such that
the coated material and particulate adjacent thereto will adhere
together to form agglomerates that may bridge in the created
fracture to prevent particulate flowback. The tackifying compound
also may be introduced into the formation with the
low-molecular-weight fluid before or after the introduction of the
proppant particulates into the formation. The coated material may
be effective in inhibiting the flowback of fine particulate in the
proppant pack having a size ranging from about that of the proppant
to less than about 600 mesh. The coated proppant or other material
is effective in consolidating fine particulates in the formation in
the form of agglomerates to prevent the movement of the fines
during production of the formation fluids from the well bore
subsequent to the treatment. A more detailed description of the use
of such tackifying compound and methods of use thereof are
disclosed in U.S. Pat. Nos. 5,775,415; 5,787,986; 5,833,000;
5,839,510; 5,871,049; 5,853,048; and 6,047,772, the relevant
disclosures of which are incorporated herein by reference
thereto.
[0035] Optionally, additional additives may be included in the
low-molecular-weight fluids including, but not limited to, scale
inhibitors, demulsifiers, bactericides, breakers, activators and
the like. An example of a suitable scale inhibitor is commercially
available from Halliburton Energy Services, Inc., under the trade
name "SCA 110." An example of a suitable breaker is commercially
available from Halliburton Energy Services, Inc., under the trade
name "VICON." Another example of a suitable breaker is commercially
available from Halliburton Energy Services, Inc., under the trade
name "HMP DE-LINK." Examples of suitable bactericides are
commercially available from Halliburton Energy Services, Inc.,
under the trade names "BE-3" and "BE-6."
[0036] In one embodiment, the present invention provides a system
that advantageously may be used with a low-molecular-weight fluid
to perform a variety of functions in a subterranean formation.
Referring now to FIG. 1, illustrated therein is a hydrojetting tool
assembly 150, which in certain embodiments may comprise a tubular
hydrojetting tool 140 and a tubular, ball-activated, flow control
device 160. The tubular hydrojetting tool 140 generally includes an
axial fluid flow passageway 180 extending therethrough and
communicating with at least one angularly spaced lateral port 202
disposed through the sides of the tubular hydrojetting tubular
hydrojetting tool 140. In certain embodiments, the axial fluid flow
passageway 180 communicates with as many angularly spaced lateral
ports 202 as may be feasible. A fluid jet forming nozzle 220
generally is connected within each of the lateral ports 202. In
certain embodiments, the fluid jet forming nozzles 220 may be
disposed in a single plane that may be positioned at a
predetermined orientation with respect to the longitudinal axis of
the tubular hydrojetting tool 140. Such orientation of the plane of
the fluid jet forming nozzles 220 may coincide with the orientation
of the plane of maximum principal stress in the formation to be
fractured relative to the longitudinal axis of the well bore
penetrating the formation.
[0037] The tubular, ball-activated, flow control device 160
generally includes a longitudinal flow passageway 260 extending
therethrough, and may be threadedly connected to the end of the
tubular hydrojetting tool 140 opposite from the coiled or jointed
tubing 225. The longitudinal flow passageway 260 may comprise a
relatively small diameter longitudinal bore 240 through an exterior
end portion of the tubular, ball-activated, flow control device 160
and a larger diameter counter bore 280 through the forward portion
of the tubular, ball-activated, flow control device 160, which may
form an annular seating surface 290 in the tubular, ball-activated,
flow control device 160 for receiving a ball 300. As will be
understood by those skilled in the art with the benefit of this
disclosure, before ball 300 is seated on the annular seating
surface 290 in the tubular, ball-activated, flow control device
160, fluid may freely flow through the tubular hydrojetting tool
140 and the tubular, ball-activated, flow control device 160. After
ball 300 is seated on the annular seating surface 290 in the
tubular, ball-activated, flow control device 160 as illustrated in
FIG. 1, flow through the tubular, ball-activated, flow control
device 160 may be terminated, which may cause fluid pumped into the
coiled or jointed tubing 225 and into the tubular hydrojetting tool
140 to exit the tubular hydrojetting tool 140 by way of the fluid
jet forming nozzles 220 thereof. When an operator desires to
reverse-circulate fluids through the tubular, ball-activated, flow
control device 160, the tubular hydrojetting tool 140 and the
coiled or jointed tubing 225, the fluid pressure exerted within the
coiled or jointed tubing 225 may be reduced, whereby higher
pressure fluid surrounding the tubular hydrojetting tool 140 and
tubular, ball-activated, flow control device 160 may freely flow
through the tubular, ball-activated, flow control device 160,
causing the ball 300 to disengage from annular seating surface 290,
and through the fluid jet forming nozzles 220 into and through the
coiled or jointed tubing 225.
[0038] Optionally, an operator may elect to employ a pressure
sensor (not shown) or flow meter (not shown) as part of the
hydrojetting tool assembly 150. A wide variety of pressure sensors
or flow meters may be used. In certain embodiments, the pressure
sensor or flow meter may be capable of storing data that may be
generated during a subterranean operation until a desired time,
e.g., until the completion of the operation when the pressure
sensor or flow meter is removed from the subterranean function. In
certain embodiments of the present invention, the incorporation of
a pressure sensor or flow meter into the hydrojetting tool assembly
150 may permit an operator to evaluate conditions in the
subterranean formation (which conditions may include, but are not
limited to, parameters related to the creation or enhancement of
the fracture) in real time or near-real-time, and, inter alia, to
undertake a remediative step in real time or near-real-time.
Example of remediative steps include, inter alia, swapping from a
proppant-laden fluid to a linear fluid, reducing the concentration
of a proppant present in the fluid, and reducing the viscosity of
the fluid. In certain embodiments of the present invention, the
operator may be able to determine, in real-time, that the fracture
in the subterranean formation has been created or enhanced to a
desired extent. In certain embodiments, the operator may move
hydrojetting tool assembly 150 to a different zone in the same, or
different, formation after determining, in real time, that the
fracture has been created or enhanced to a desired extent. As
referred to herein, the term "real time" will be understood to mean
a time frame in which the occurrence of an event and the reporting
or analysis of it are almost simultaneous; e.g., within a maximum
duration of not more than two periods of a particular signal (e.g.,
a pressure signal, electrical signal, or the like) being evaluated.
For example, an operator may view, in real time, a plot of the
pressure in the formation that has been transmitted by the optional
pressure sensor (not shown), and determine, at a particular time
during the fracturing operation, that an increase, or multiple
increases, in the slope of the pressure indicate the need to
perform a remediative step such as those described above. One of
ordinary skill in the art, with the benefit of this disclosure,
will be able to evaluate a real time plot of the pressure in the
formation, and evaluate conditions in the formation, and determine
the appropriate remediative step to perform in response. For
example, an operator may use the flow meter, in real time, to
compare the flow of fluid past the end of the hydrojetting tool
assembly 150 to determine the quantity of fluid that is flowing
into the at least one fracture in the subterranean formation, and
to determine the quantity of fluid that is flowing past the
hydrojetting tool assembly 150 and that may be leaking off into
other areas; the operator may evaluate such data from the flow
meter, and adjust the fluid flow rate and jetting pressure
accordingly. One of ordinary skill in the art, with the benefit of
this disclosure, will be able to evaluate data from the flow meter,
and determine the appropriate adjustments to make to the fluid flow
rate and jetting pressure.
[0039] Referring now to FIG. 2, a hydrocarbon-producing
subterranean formation 400 is illustrated penetrated by a deviated
open hole well bore 420. The deviated well bore 420 includes a
substantially vertical portion 440 which extends to the surface,
and a substantially horizontal portion 460 which extends into the
formation 400. Though FIG. 2 illustrates an open hole well bore, it
will be understood that the systems and methods of the present
invention also may be used in well bores having casing disposed
therein; it further will be understood that the systems and methods
of the present invention also may be used in a variety of well bore
configurations, including, but not limited to, those that are
entirely vertical and those that are substantially vertical.
[0040] The coiled or jointed tubing 225 having the hydrojetting
tool assembly 150, and an optional centralizer 480, attached
thereto is shown disposed in the well bore 420. Prior to placing
the hydrojetting tool assembly 150, the optional centralizer 480
and the coiled or jointed tubing 225 into the well bore 420, an
operator may determine the orientation of the plane of maximum
principal stress in the formation 400 to be fractured with respect
to the longitudinal direction of the well bore 420 utilizing known
information or techniques and tools available to those of ordinary
skill in the art. Thereafter, the tubular hydrojetting tool 140 may
be selected having the fluid jet forming nozzles 220 disposed in a
plane oriented with respect to the longitudinal axis of the tubular
hydrojetting tool 140 in a manner that aligns the plane containing
the fluid jet forming nozzles 220 with the plane of the maximum
principal stress in the formation 400 when the tubular hydrojetting
tool 140 is positioned in the well bore 420. As is well understood
in the art, when the fluid jet forming nozzles 220 are aligned in
the plane of the maximum principal stress in the formation 400 to
be fractured and a fracture is formed therein, a single
microfracture may be formed that may extend outwardly from and
around the well bore 420 in the plane of maximum principal stress.
In certain embodiments of the present invention, an operator may
elect not to align the fluid jet forming nozzles 220 of the tubular
hydrojetting tool 140 with the plane of maximum principal stress in
the formation 400; in such embodiments, each fluid jet may form an
individual cavity and fracture in the formation 400.
[0041] Once the hydrojetting tool assembly 150 has been placed in
the well bore 420, a low-molecular-weight fluid, such as those that
have been described herein, may be circulated through the coiled or
jointed tubing 225 and through the hydrojetting tool assembly 150
so as to flow through the open tubular, ball-activated, flow
control device 160 and circulate through the well bore 420. In
certain embodiments, the circulation may be continued for a period
of time sufficient to clean out debris, pipe dope and other
materials from inside the coiled or jointed tubing 225 and from the
well bore 420. Once a desired volume of low-molecular-weight fluid
has been placed in well bore 420, and hydrojetting tool assembly
150 has been positioned adjacent the formation 400 that is to be
fractured, ball 300 (shown in FIG. 1) may be caused to seat on the
annular seating surface 290 (shown in FIG. 1) in the tubular,
ball-activated, flow control device 160, thereby directing the
entirety of the low-molecular-weight fluid through the fluid jet
forming nozzles 220 of the tubular hydrojetting tool 140. In
certain embodiments, ball 300 may be caused to seat on annular
seating surface 290 by dropping ball 300 through coiled or jointed
225, through the tubular hydrojetting tool 140 and into the
tubular, ball-activated, flow control device 160 while the
low-molecular-weight fluid continues to flow through the coiled or
jointed tubing 225 and the hydrojetting tool assembly 150; in
certain other embodiments, ball 300 may be trapped in the tubular
hydrojetting tool 140, and will seat when fluid flows through
coiled or jointed tubing 225, forcing fluid out the fluid jet
forming nozzles 220. After ball 300 has been caused to seat on
annular seating surface 290, the rate of circulation of the
low-molecular weight fluid into the coiled or jointed tubing 225
and through the tubular hydrojetting tool 140 may be increased to a
level whereby the pressure of the low-molecular-weight fluid that
is jetted through the fluid jet forming nozzles 220 may reach a
jetting pressure sufficient to perforate the walls of well bore 420
and cause the creation of cavities 500 and microfractures 520 in
the subterranean formation 400 as illustrated in FIGS. 2 and 4.
Once a cavity 500 is formed, the operator may, inter alia, close in
the annulus, which may increase the pressure and thereby assist in
creating a dominant fracture adjacent the tubular hydrojetting tool
140. Fluid may be flowed through the annulus to increase the flow
rate of fluid into the fracture, thereby assisting in propagating
the fracture. Flowing fluid through the annulus also may assist in
overcoming any leak-off of fluid into other perforations that may
occur. Generally, the jet differential pressure at which the
low-molecular-weight fluid is jetted from the fluid jet forming
nozzles 220 of the tubular hydrojetting tool 140 to result in the
formation of cavities 500 and microfractures 520 in the formation
400 is a pressure in the range of from about 500 to about 5,000
psi. In certain embodiments, the jet differential pressure at which
the low-molecular-weight fluid is jetted from the fluid jet forming
nozzles 220 of the tubular hydrojetting tool 140 is a pressure of
approximately two times the pressure required to initiate a
fracture in the formation, less the ambient pressure in the well
bore adjacent to the formation. The pressure required to initiate a
fracture in a particular formation may depend upon, inter alia, the
particular type of rock and/or other materials that form the
formation and other factors known to those skilled in the art. Once
one or more dominant fractures have been created, a valve on the
annulus may be opened, and fluid flow into the annulus may be
initiated so as to further enhance or extend the one or more
dominant fractures. Among other things, flowing a
low-molecular-weight fluid through the annulus, as well as through
coiled or jointed tubing 225, may provide the largest possible flow
path for the low-molecular-weight fluid, thereby increasing the
rate at which the low-molecular-weight fluid may be forced into
formation 400. Among other things, flowing the low-molecular-weight
fluid through both the annulus and through coiled or jointed tubing
225 may reduce erosion of fluid jet forming nozzles 220 when the
low-molecular-weight fluid is proppant-laden.
[0042] Once one or more dominant fractures in formation 400 have
been created and then extended or enhanced to a desired extent,
hydrojetting tool assembly 150 may be moved within well bore 420 to
other zones in the same, or different, formation and the process
described above may be repeated so as to create perforations in the
walls of well bore 420 adjacent such other zones, and to create or
enhance dominant fractures in such other zones, as previously
described herein.
[0043] When the well bore 420 is deviated (including horizontal
well bores) as illustrated in FIG. 2, the optional centralizer 480
may be utilized with the hydrojetting tool assembly 150, inter
alia, to insure that each of the fluid jet forming nozzles 220 has
a proper stand-off clearance from the walls of the well bore 420,
(e.g., a stand-off clearance in the range of from about {fraction
(1/4)} inch to about 2 inches). At a stand-off clearance of about
1.5 inches between the face of the fluid jet forming nozzles 220
and the walls of the well bore and when the fluid jets formed flare
outwardly at their cores at an angle of about 20 degrees, the jet
differential pressure required to form the cavities 500 and the
microfractures 520 generally is a pressure of about 2 times the
pressure required to initiate a fracture in the formation less the
ambient pressure in the well bore adjacent to the formation. When
the stand-off clearance and degree of flare of the fluid jets are
different from those given above, an operator may use formulae such
as the following to calculate the jetting pressure:
Pi=Pf-Ph FORMULA I
.DELTA.P/Pi=1.1[d+(s+0.5)tan(flare)].sup.2/d.sup.2 FORMULA II
[0044] wherein;
[0045] Pi=difference between formation fracture pressure and
ambient pressure (psi);
[0046] Pf=formation fracture pressure (psi);
[0047] Ph=ambient pressure (psi);
[0048] .DELTA.P=the jet differential pressure (psi);
[0049] d=diameter of the jet (inches);
[0050] s=stand off clearance (inches); and
[0051] flare=flaring angle of jet (degrees).
[0052] As mentioned above, propping agent may be combined with the
low-molecular-weight fluid being circulated so that it is carried
into the cavities 500, as well as at least partially into the
microfractures 520 connected to the cavities. The propping agent
functions, inter alia, to prop open the microfractures 520 and
thereby prevent them from completely re-closing upon termination of
the hydrojetting process. In order to insure that propping agent
remains in the fractures upon termination of the hydrojetting
process, the jetting pressure preferably may be slowly reduced to
allow the fractures to close upon the propping agent that is held
within the fractures by the fluid jetting during the closure
process. In addition to propping the fractures open, the presence
of the propping agent, (e.g., sand) in the fluid being jetted
facilitates the cutting and erosion of the formation by the fluid
jets. As indicated, additional abrasive material can be included in
the low-molecular-weight fluid, as can one or more acids that may
react with and dissolve formation materials to thereby enlarge the
cavities and fractures as they are formed. Once one or more
microfractures are formed as a result of the above procedure, the
hydrojetting tool assembly 150 may be moved to a different
position, and the hydrojetting procedure may be repeated to form
one or more additional microfractures that may be spaced a distance
from the initial microfracture or microfractures.
[0053] As mentioned above, some or all of the microfractures
produced in a subterranean formation may be extended into the
formation by pumping a fluid into the well bore to raise the
ambient pressure therein. In performing the methods of the present
invention to create and extend at least one fracture in the
subterranean formation, the hydrojetting tool assembly 150 may be
positioned in the well bore 420 adjacent the formation 400 to be
fractured, and fluid may be jetted through the fluid jet forming
nozzles 220 against the formation 400 at a jetting pressure
sufficient to form the cavities 500 and the microfractures 520.
Simultaneously with the hydrojetting of the formation, a fluid may
be pumped into the well bore 420 at a rate sufficient to raise the
ambient pressure in the well bore adjacent the formation to a level
such that the cavities 500 and the microfractures 520 are enlarged
and extended, whereby enlarged and extended fractures 600 (shown in
FIG. 3) are formed. As in an embodiment that is illustrated in FIG.
3, the enlarged and extended fractures 600 may be formed in a
spaced relationship along well bore 420 with groups of the cavities
500 and microfractures 520 formed therebetween.
[0054] Accordingly, an example of a method of the present invention
is a method of fracturing a subterranean formation comprising the
steps of: positioning a hydrojetting tool having at least one fluid
jet forming nozzle in a portion of the subterranean formation to be
fractured; jetting a low-molecular-weight fluid through the at
least one fluid jet forming nozzle against the formation at a
pressure sufficient to form a cavity in the formation; and further
jetting the low-molecular-weight fluid through the nozzle to create
or enhance at least one fracture in the formation.
[0055] Another example of a method of the present invention is a
method of fracturing a subterranean formation comprising:
positioning a hydrojetting tool having at least one fluid jet
forming nozzle in a portion of the subterranean formation to be
fractured; jetting a fluid through the at least one fluid jet
forming nozzle against the formation at a pressure sufficient to
create at least one fracture in the formation; and pumping a
low-molecular-weight fluid into an annulus between the hydrojetting
tool and the formation at a rate sufficient to raise the annular
pressure to a level sufficient to extend the fracture into the
formation.
[0056] Another example of a method of the present invention is a
method of enhancing production from multiple subterranean
formations penetrated by a well bore during a single trip through
the well bore, comprising: positioning a hydrojetting tool having
at least one fluid jet forming nozzle in a portion of the
subterranean formation to be fractured; jetting a fluid through the
at least one fluid jet forming nozzle against the formation at a
pressure sufficient to create at least one fracture in the
formation; pumping a low-molecular-weight fluid into an annulus
between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation; repositioning the
hydrojetting tool in a different portion of the formation; and
repeating the steps of jetting a fluid through the at least one
fluid jet forming nozzle against the formation at a pressure
sufficient to create at least one fracture in the formation and
pumping a low-molecular-weight fluid into the annulus between the
hydrojetting tool and the formation at a rate sufficient to raise
the annular pressure to a level sufficient to extend the fracture
into the formation.
[0057] Yet another example of a method of the present invention is
a method of enhancing production, in real time, from multiple
subterranean formations penetrated by a well bore during a single
trip through the well bore, comprising: positioning a hydrojetting
tool having at least one fluid jet forming nozzle in a portion of
the subterranean formation to be fractured; jetting a fluid through
the at least one fluid jet forming nozzle against the formation at
a pressure sufficient to create at least one fracture in the
formation; pumping a low-molecular-weight fluid into an annulus
between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation; determining, in real time,
at least one parameter related to the creation or enhancement of
the fracture; repositioning the hydrojetting tool in a different
portion of the formation; and repeating the steps of jetting a
fluid through the at least one fluid jet forming nozzle against the
formation at a pressure sufficient to create at least one fracture
in the formation and pumping a low-molecular-weight fluid into the
annulus between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation.
[0058] Still another example of a method of the present invention
is a method of reducing the cost of enhancing production from
multiple subterranean formations penetrated by a well bore by
stimulating multiple formations, on a single trip through the well
bore, with a fluid that minimizes damage to the formation
comprising: positioning a hydrojetting tool having at least one
fluid jet forming nozzle in a portion of the subterranean formation
to be fractured; jetting a fluid through the at least one fluid jet
forming nozzle against the formation at a pressure sufficient to
create at least one fracture in the formation; pumping a
low-molecular-weight fluid into an annulus between the hydrojetting
tool and the formation at a rate sufficient to raise the annular
pressure to a level sufficient to extend the fracture into the
formation; repositioning the hydrojetting tool in a different
portion of the formation; and repeating the steps of jetting a
fluid through the at least one fluid jet forming nozzle against the
formation at a pressure sufficient to create at least one fracture
in the formation and pumping a low-molecular-weight fluid into the
annulus between the hydrojetting tool and the formation at a rate
sufficient to raise the annular pressure to a level sufficient to
extend the fracture into the formation; wherein the
low-molecular-weight fluid enhances the regain permeability of the
subterranean formation.
[0059] 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 the invention has
been depicted and described by reference to particular embodiments
of the invention, such a reference does not imply a limitation on
the invention, and no such limitation is to be inferred. The
invention is capable of considerable modification, alternation, and
equivalents in form and function, as will occur to those ordinarily
skilled in the pertinent arts and having the benefit of this
disclosure. The depicted and described embodiments of the invention
are exemplary only, and are not exhaustive of the scope of the
invention. Consequently, the invention is intended to be limited
only by the spirit and scope of the appended claims, giving full
cognizance to equivalents in all respects.
* * * * *