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Publication numberUS20050269099 A1
Publication typeApplication
Application numberUS 10/862,000
Publication dateDec 8, 2005
Filing dateJun 4, 2004
Priority dateJun 4, 2004
Publication number10862000, 862000, US 2005/0269099 A1, US 2005/269099 A1, US 20050269099 A1, US 20050269099A1, US 2005269099 A1, US 2005269099A1, US-A1-20050269099, US-A1-2005269099, US2005/0269099A1, US2005/269099A1, US20050269099 A1, US20050269099A1, US2005269099 A1, US2005269099A1
InventorsNeil Stegent, David Adams, Leldon Farabee
Original AssigneeHalliburton Energy Services
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Methods of treating subterranean formations using low-molecular-weight fluids
US 20050269099 A1
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.
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Claims(97)
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° 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° 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° 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° 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° 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° 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

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.

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.

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.

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° 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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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

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:

FIG. 1 depicts an embodiment of a tool assembly that may be used with the methods of the present invention.

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.

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.

FIG. 4 is a cross sectional view taken along line 4-4 of FIG. 2.

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

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° 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.

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.

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.

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.

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° 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.

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.

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®, Carbo Lite®, Carbo Prop®, Interprop®, Naplite®, and Valuprop®. Examples of high strength ceramic proppants include, but are not limited to, Carbo HSP®, Sintered Bauxite and SinterBall®. 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.

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.

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.

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.

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.

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.

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.

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.”

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.

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.

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.

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.

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.

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.

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.

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 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
ΔP/Pi=1.1[d+(s+0.5)tan(flare)]2 /d 2  FORMULA II
wherein;

  • Pi=difference between formation fracture pressure and ambient pressure (psi);
  • Pf=formation fracture pressure (psi);
  • Ph=ambient pressure (psi);
  • ΔP=the jet differential pressure (psi);
  • d=diameter of the jet (inches);
  • s=stand off clearance (inches); and
  • flare=flaring angle of jet (degrees).

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.

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.

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.

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.

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.

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.

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.

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.

Referenced by
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US7683011Dec 12, 2007Mar 23, 2010Du Pontfor plugging permeable zones; subterranean formations
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US7788037Jan 8, 2005Aug 31, 2010Halliburton Energy Services, Inc.Method and system for determining formation properties based on fracture treatment
US7790657Dec 17, 2007Sep 7, 2010E.I. Du Pont De Nemours And Companygenerate an initial viscosity at the surface, followed by a delayed viscosity generation, once the fluid is subjected to higher down-hole temperatures; use in oil field applications such as hydraulic fracturing and plugging of permeable zones (thief zones); varied ratio of triethanolamine to Quadrol
US7795190Dec 14, 2007Sep 14, 2010E.I. Du Pont De Nemours And Companymixing tetraalkyl zirconate with alkanolamine, water and hydroxyalkylene diamine, then with boron compound in alcohol to stabilize; oil fields, plugging permeable zones and leaks of subterranean formations
US7851417Dec 11, 2007Dec 14, 2010E.I. Du Pont De Nemours And Companyfor plugging permeable zones; subterranean formations
US7934557 *Feb 15, 2007May 3, 2011Halliburton Energy Services, Inc.Methods of completing wells for controlling water and particulate production
US8153564Mar 7, 2008Apr 10, 2012Dorf Ketal Speciality Catalysts, LlcZirconium-based cross-linking composition for use with high pH polymer solutions
US8236739Mar 30, 2007Aug 7, 2012Dork Ketal Speciality Catalysts, LLCZirconium-based cross-linker compositions and their use in high pH oil field applications
US8242060Dec 21, 2006Aug 14, 2012Dorf Ketal Specialty Catalysts, LLCStable solutions of zirconium hydroxyalkylethylene diamine complex and use in oil field applications
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Classifications
U.S. Classification166/308.1
International ClassificationE21B43/26, E21B7/18
Cooperative ClassificationE21B7/18, E21B43/26
European ClassificationE21B43/26, E21B7/18
Legal Events
DateCodeEventDescription
Aug 23, 2004ASAssignment
Owner name: HALLIBURTON ENERGY SERVICES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:STEGENT, NEIL A.;ADAMS, DAVID M.;FARABEE, LELDON M.;REEL/FRAME:015723/0576
Effective date: 20040812