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Publication numberUS20050263283 A1
Publication typeApplication
Application numberUS 10/852,811
Publication dateDec 1, 2005
Filing dateMay 25, 2004
Priority dateMay 25, 2004
Publication number10852811, 852811, US 2005/0263283 A1, US 2005/263283 A1, US 20050263283 A1, US 20050263283A1, US 2005263283 A1, US 2005263283A1, US-A1-20050263283, US-A1-2005263283, US2005/0263283A1, US2005/263283A1, US20050263283 A1, US20050263283A1, US2005263283 A1, US2005263283A1
InventorsPhilip Nguyen
Original AssigneeNguyen Philip D
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Methods for stabilizing and stimulating wells in unconsolidated subterranean formations
US 20050263283 A1
Abstract
The present invention relates to methods of stabilizing an unconsolidated portion in a subterranean formation and stimulating fluid production from the stabilized portion. Some embodiments of the present invention provide methods of substantially stabilizing a portion of a subterranean formation penetrated by a well bore and stimulating fluid production therefrom comprising placing a stabilizing composition into a near well bore area of a portion in a formation to create a stabilized portion; and, stimulating the stabilized portion so as to place the well bore in fluid communication with both the stabilized portion in the near-well bore area and an unstabilized portion of the formation in the far-well bore area.
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Claims(113)
1. A method of substantially stabilizing a portion of a subterranean formation penetrated by a well bore and stimulating fluid production therefrom comprising:
placing a stabilizing composition into a near well bore area of a portion in a formation to create a stabilized portion; and,
stimulating the stabilized portion so as to place the well bore in fluid communication with both the stabilized portion in the near-well bore area and an unstabilized portion of the formation in the far-well bore area.
2. The method of claim 1 wherein the stabilizing composition comprises a curable resin composition.
3. The method of claim 2 wherein the curable resin composition comprises a novolak resin, a polyepoxide resin, a phenol-aldehyde resin, a urea-aldehyde resin, a urethane resin, a phenolic resin, a furan/furfuryl alcohol resin, a phenolic/latex resin, a phenol formaldeyhe resin, a polyester resin, including hybrids and copolymers thereof, a polyurethane resin and hybrids and copolymers thereof, an acrylate resin, or a mixture thereof.
4. The method of claim 2 further comprising an internal catalyst or activator.
5. The method of claim 2 further comprising a time-delayed catalyst or an external catalyst.
6. The method of claim 1 wherein the stabilizing composition comprises a gelable composition.
7. The method of claim 6 wherein the gelable composition comprises a gelable resin composition, a gelable aqueous silicate composition, a polymerizable organic monomer composition, or a crosslinkable aqueous polymer composition.
8. The method of claim 7 wherein the gelable resin composition comprises a curable resin composition that comprises a curable resin, a diluent, and a resin curing agent.
9. The method of claim 8 wherein the curable resin comprises an organic resin that comprises a polyepoxide resin, a polyester resin, a urea-aldehyde resin, a furan resin, a urethane resin, or a mixture thereof.
10. The method of claim 8 wherein the diluent comprises a phenol, a formaldehyde, a furfuryl alcohol, a furfural, an alcohol, an ether, or a mixture thereof.
11. The method of claim 8 wherein the diluent is present in the curable resin composition in an amount in the range of from about 5% to about 75% by weight of the curable resin.
12. The method of claim 8 wherein the resin curing agent comprises an amine, a polyamine, an amide, a polyamide, or a methylene dianiline.
13. The method of claim 8 wherein the resin curing agent is present in the curable resin composition in an amount in the range of from about 5% to about 75% by weight of the curable resin.
14. The method of claim 8 wherein the curable resin composition further comprises a flexibilizer additive.
15. The method of claim 14 wherein the flexibilizer additive comprises an organic ester, an oxygenated organic solvent, an aromatic solvent, or combinations thereof.
16. The method of claim 14 wherein the flexibilizer additive is present in the curable resin composition in an amount in the range of from about 5% to about 80% by weight of the curable resin.
17. The method of claim 7 wherein the gelable aqueous silicate composition comprises an aqueous alkali metal silicate solution and a temperature activated catalyst.
18. The method of claim 17 wherein the aqueous alkali metal silicate solution generally comprises an alkali metal silicate and an aqueous liquid.
19. The method of claim 18 wherein the alkali metal silicate comprises sodium silicate, potassium silicate, lithium silicate, rubidium silicate, or cesium silicate.
20. The method of claim 18 wherein the aqueous liquid comprises fresh water, salt water, brine, or seawater.
21. The method of claim 17 wherein the temperature activated catalyst comprises an ammonium sulfate, a sodium acid pyrophosphate, a citric acid, or an ethyl acetate.
22. The method of claim 7 wherein the polymerizable organic monomer composition comprises an aqueous-base fluid, a water soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.
23. The method of claim 22 wherein the aqueous solvent comprises fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.
24. The method of claim 22 wherein the water soluble polymerizable organic monomer comprises acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2-methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate, 2-triethylammoniumethylmethacrylate chloride, N,N-dimethyl-aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone, vinyl-phosphonic acid, methacryloyloxyethyl trimethylammonium sulfate, or a mixture thereof.
25. The method of claim 22 wherein the water soluble polymerizable organic monomer comprises hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethylmethacrylate, N-hydroxymethylacrylamide, N-hydroxy-methylmethacrylamide, polyethylene acrylate, polyethylene methacrylate, polyethylene glycol acrylate, polyethylene glycol methacrylate, hydroxyethylcellulose-vinyl phosphoric acid, or a mixture thereof.
26. The method of claim 22 wherein the water soluble polymerizable organic monomer is present in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous-base fluid.
27. The method of claim 22 wherein the oxygen scavenger comprises stannous chloride.
28. The method of claim 22 wherein the oxygen scavenger is present in the polymerizable organic monomer composition in an amount in the range of from about 0.005% to about 0.1 % by weight of the polymerizable organic monomer composition.
29. The method of claim 22 wherein the primary initiator comprises an alkali metal persulfate, a peroxide, an oxidation-reduction system employing reducing agents, or an azo polymerization initiator.
30. The method of claim 22 wherein the primary initiator comprises 2,2′-azobis(2-imidazole-2-hydroxyethyl)propane, 2,2′-azobis(2-aminopropane), 4,4′-azobis(4-cyanovaleric acid), or 2,2′-azobis(2-methyl-N-(2-hydroxyethyl)propionamide.
31. The method of claim 22 wherein the polymerizable organic monomer composition further comprises a secondary initiator.
32. The method of claim 22 wherein the polymerizable organic monomer composition further comprises a crosslinking agent.
33. The method of claim 7 wherein the crosslinkable aqueous polymer comprises an aqueous solvent, a crosslinkable polymer, and a crosslinking agent.
34. The method of claim 33 wherein the aqueous solvent comprises fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.
35. The method of claim 33 wherein the crosslinkable polymer composition is present in the crosslinkable aqueous polymer composition in an amount in the range of from about 1% to about 30% by weight of the aqueous solvent.
36. The method of claim 33 wherein the crosslinkable polymer comprises a carboxylate-containing polymer or an acrylamide-containing polymer.
37. The method of claim 33 wherein the crosslinkable polymer is a polyacrylamide, a partially hydrolyzed polyacrylamide, a copolymer of acrylamide and acrylate, or a carboxylate-containing terpolymers and tetrapolymers of acrylate.
38. The method of claim 33 wherein the crosslinking agent comprises a molecule or complex containing a reactive transition metal cation.
39. The method of claim 33 wherein the crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water.
40. The method of claim 33 wherein the crosslinking agent is present in the aqueous crosslinkable polymer composition in an amount in the range of from about 0.001% to about 5% by weight of the crosslinkable polymer composition.
41. The method of claim 32 wherein the crosslinkable aqueous polymer further comprises a crosslinking delaying agent.
42. The method of claim 41 wherein the crosslinking delaying agent comprises a polysaccharide crosslinking delaying agent.
43. The method of claim 1 wherein the stabilizing composition penetrates into the near well bore area of a portion in a formation to a depth of from about a few inches to about three well bore diameters.
44. The method of claim 1 wherein the stimulating step comprises hydrajetting, puncturing, fracturing, or a combinations thereof.
45. The method of claim 1 further comprising the step of, after stimulating the stabilized portion, placing proppant into the area or fluid communication.
46. The method of claim 45 wherein the proppant comprises a hardenable resin coating.
47. The method of claim 45 wherein the proppant comprises a tackyfier coating.
48. The method of claim 1 wherein the well bore comprises an open hole well bore.
49. The method of claim 1 wherein the well bore comprises a cased well bore.
50. A method of controlling formation sands in a portion of a formation penetrated by a well bore and stimulating fluid production therefrom comprising:
placing a stabilizing composition into a near well bore area of a portion in a formation to create a stabilized portion; and,
stimulating the stabilized portion so as to place the well bore in fluid communication with both the stabilized portion in the near-well bore area and an unstabilized portion of the formation in the far-well bore area.
51. The method of claim 50 wherein the stabilizing composition comprises a curable resin composition.
52. The method of claim 51 wherein the curable resin composition comprises a novolak resin, a polyepoxide resin, a phenol-aldehyde resin, a urea-aldehyde resin, a urethane resin, a phenolic resin, a furan/furfuryl alcohol resin, a phenolic/latex resin, a phenol formaldeyhe resin, a polyester resin, including hybrids and copolymers thereof, a polyurethane resin and hybrids and copolymers thereof, an acrylate resin, or mixtures thereof.
53. The method of claim 51 further comprising an internal catalyst, an activator, a time-delayed catalyst, or an external catalyst.
54. The method of claim 50 wherein the stabilizing composition comprises a gelable composition.
55. The method of claim 54 wherein the gelable composition comprises a gelable resin composition, a gelable aqueous silicate composition, a polymerizable organic monomer composition, or a crosslinkable aqueous polymer composition.
56. The method of claim 55 wherein the gelable resin composition comprises a curable resin composition that comprises a curable resin, a diluent, and a resin curing agent.
57. The method of claim 56 wherein the curable resin comprises an organic resin that comprises a polyepoxide resin, a polyester resin, a urea-aldehyde resin, a furan resin, a urethane resin, or a mixture thereof.
58. The method of claim 56 wherein the diluent comprises a phenol, a formaldehyde, a furfuryl alcohol, a furfural, an alcohol, an ether, or a mixture thereof.
59. The method of claim 56 wherein the resin curing agent comprises an amine, a polyamine, an amide, a polyamide, or a methylene dianiline.
60. The method of claim 56 wherein the curable resin composition further comprises a flexibilizer additive, wherein the flexibilizer additive comprises an organic ester, an oxygenated organic solvent, an aromatic solvent, or combinations thereof.
61. The method of claim 55 wherein the gelable aqueous silicate composition comprises an aqueous alkali metal silicate solution and a temperature activated catalyst.
62. The method of claim 61 wherein the aqueous alkali metal silicate solution generally comprises an aqueous liquid and an alkali metal silicate selected from the group consisting of sodium silicate, potassium silicate, lithium silicate, rubidium silicate, and cesium silicate.
63. The method of claim 61 wherein the temperature activated catalyst comprises an ammonium sulfate, a sodium acid pyrophosphate, a citric acid, or an ethyl acetate.
64. The method of claim 55 wherein the polymerizable organic monomer composition comprises an aqueous-base fluid, a water soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.
65. The method of claim 64 wherein the water soluble polymerizable organic monomer comprises acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2-methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate, 2-triethylammoniumethylmethacrylate chloride, N,N-dimethyl-aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone, vinyl-phosphonic acid, methacryloyloxyethyl trimethylammonium sulfate, or a mixture thereof.
66. The method of claim 64 wherein the water soluble polymerizable organic monomer comprises hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethylmethacrylate, N-hydroxymethylacrylamide, N-hydroxy-methylmethacrylamide, polyethylene acrylate, polyethylene methacrylate, polyethylene glycol acrylate, polyethylene glycol methacrylate, hydroxyethylcellulose-vinyl phosphoric acid, or a mixture thereof.
67. The method of claim 64 wherein the oxygen scavenger comprises stannous chloride.
68. The method of claim 64 wherein the primary initiator comprises an alkali metal persulfate, a peroxide, an oxidation-reduction system employing reducing agents, or an azo polymerization initiator.
69. The method of claim 64 wherein the primary initiator comprises 2,2′-azobis(2-imidazole-2-hydroxyethyl)propane, 2,2′-azobis(2-aminopropane), 4,4′-azobis(4-cyanovaleric acid), or 2,2′-azobis(2-methyl-N-(2-hydroxyethyl)propionamide.
70. The method of claim 55 wherein the crosslinkable aqueous polymer composition comprises an aqueous solvent, a crosslinkable polymer, and a crosslinking agent.
71. The method of claim 70 wherein the aqueous solvent comprises fresh water, salt water, brine, or seawater.
72. The method of claim 70 wherein the crosslinkable polymer comprises a carboxylate-containing polymer or an acrylamide-containing polymer.
73. The method of claim 70 wherein the crosslinkable polymer is a polyacrylamide, a partially hydrolyzed polyacrylamide, a copolymer of acrylamide and acrylate, or a carboxylate-containing terpolymers and tetrapolymers of acrylate.
74. The method of claim 70 wherein the crosslinkable aqueous polymer further comprises a crosslinking delaying agent.
76. The method of claim 50 wherein the stabilizing composition penetrates into the near well bore area of a portion in a formation to a depth of from about a few inches to about three well bore diameters.
77. The method of claim 50 wherein the stimulating step comprises hydrajetting, puncturing, fracturing, or a combinations thereof.
78. The method of claim 50 further comprising the step of, after stimulating the stabilized portion, placing proppant into the area or fluid communication.
79. The method of claim 78 wherein the proppant comprises a hardenable resin coating.
80. The method of claim 78 wherein the proppant comprises a tackyfier coating.
81. The method of claim 50 wherein the well bore comprises an open hole well bore.
82. The method of claim 50 wherein the well bore comprises a cased well bore.
83. A system for stabilizing and stimulating a portion of a subterranean formation penetrated by a well bore comprising:
placing a stabilizing composition into a near well bore area of a portion in a formation to create a stabilized portion; and,
stimulating the stabilized portion so as to place the well bore in fluid communication with both the stabilized portion in the near-well bore area and an unstabilized portion of the formation in the far-well bore area.
84. The method of claim 83 wherein the stabilizing composition comprises a curable resin composition.
85. The method of claim 84 wherein the curable resin composition comprises a novolak resin, a polyepoxide resin, a phenol-aldehyde resin, a urea-aldehyde resin, a urethane resin, a phenolic resin, a furan/furfuryl alcohol resin, a phenolic/latex resin, a phenol formaldeyhe resin, a polyester resin, including hybrids and copolymers thereof, a polyurethane resin and hybrids and copolymers thereof, an acrylate resin, or mixtures thereof.
86. The method of claim 84 further comprising an internal catalyst, an activator, a time-delayed catalyst, or an external catalyst.
87. The method of claim 83 wherein the stabilizing composition comprises a gelable composition.
88. The method of claim 87 wherein the gelable composition comprises a gelable resin composition, a gelable aqueous silicate composition, a polymerizable organic monomer composition, or a crosslinkable aqueous polymer composition.
89. The method of claim 88 wherein the gelable resin composition comprises a curable resin composition that comprises a curable resin, a diluent, and a resin curing agent.
90. The method of claim 89 wherein the curable resin comprises an organic resin that comprises a polyepoxide resin, a polyester resin, a urea-aldehyde resin, a furan resin, a urethane resin, or a mixture thereof.
91. The method of claim 89 wherein the diluent comprises a phenol, a formaldehyde, a furfuryl alcohol, a furfural, an alcohol, an ether, or a mixture thereof.
92. The method of claim 89 wherein the resin curing agent comprises an amine, a polyamine, an amide, a polyamide, or a methylene dianiline.
93. The method of claim 89 wherein the curable resin composition further comprises a flexibilizer additive wherein the flexibilizer additive comprises an organic ester, an oxygenated organic solvent, an aromatic solvent, or combinations thereof.
94. The method of claim 88 wherein the gelable aqueous silicate composition comprises an aqueous alkali metal silicate solution and a temperature activated catalyst.
95. The method of claim 94 wherein the aqueous alkali metal silicate solution comprises an aqueous liquid and an alkali metal silicate selected from the group consisting of sodium silicate, potassium silicate, lithium silicate, rubidium silicate, and cesium silicate.
96. The method of claim 94 wherein the temperature activated catalyst comprises an ammonium sulfate, a sodium acid pyrophosphate, a citric acid, or an ethyl acetate.
97. The method of claim 88 wherein the polymerizable organic monomer composition comprises an aqueous-base fluid, a water soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.
98. The method of claim 97 wherein the water soluble polymerizable organic monomer comprises acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2-methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate, 2-triethylammoniumethylmethacrylate chloride, N,N-dimethyl-aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone, vinyl-phosphonic acid, methacryloyloxyethyl trimethylammonium sulfate, or a mixture thereof.
99. The method of claim 97 wherein the water soluble polymerizable organic monomer comprises hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethylmethacrylate, N-hydroxymethylacrylamide, N-hydroxy-methylmethacrylamide, polyethylene acrylate, polyethylene methacrylate, polyethylene glycol acrylate, polyethylene glycol methacrylate, hydroxyethylcellulose-vinyl phosphoric acid, or a mixture thereof.
100. The method of claim 97 wherein the oxygen scavenger comprises stannous chloride.
101. The method of claim 97 wherein the primary initiator comprises an alkali metal persulfate, a peroxide, an oxidation-reduction system employing reducing agents, or an azo polymerization initiator.
102. The method of claim 97 wherein the primary initiator comprises 2,2′-azobis(2-imidazole-2-hydroxyethyl)propane, 2,2′-azobis(2-aminopropane), 4,4′-azobis(4-cyanovaleric acid), or 2,2′-azobis(2-methyl-N-(2-hydroxyethyl)propionamide.
103. The method of claim 88 wherein the crosslinkable aqueous polymer composition comprises an aqueous solvent, a crosslinkable polymer, and a crosslinking agent.
104. The method of claim 103 wherein the aqueous solvent comprises fresh water, salt water, brine, or seawater.
105. The method of claim 103 wherein the crosslinkable polymer comprises a carboxylate-containing polymer or an acrylamide-containing polymer.
106. The method of claim 103 wherein the crosslinkable polymer is a polyacrylamide, a partially hydrolyzed polyacrylamide, a copolymer of acrylamide and acrylate, or a carboxylate-containing terpolymers and tetrapolymers of acrylate.
107. The method of claim 103 wherein the aqueous crosslinkable polymer composition further comprises a crosslinking delaying agent.
108. The method of claim 83 wherein the stabilizing composition penetrates into the near well bore area of a portion in a formation to a depth of from about a few inches to about three well bore diameters.
109. The method of claim 83 wherein the stimulating step comprises hydrajetting, puncturing, fracturing, or a combinations thereof.
110. The method of claim 83 further comprising the step of, after stimulating the stabilized portion, placing proppant into the area or fluid communication.
111. The method of claim 110 wherein the proppant comprises a hardenable resin coating.
112. The method of claim 110 wherein the proppant comprises a tackyfier coating.
113. The method of claim 83 wherein the well bore comprises an open hole well bore.
114. The method of claim 83 wherein the well bore comprises a cased well bore.
Description
BACKGROUND OF THE INVENTION

The present invention relates to methods of stabilizing an unconsolidated portion in a subterranean formation and stimulating fluid production from the stabilized portion.

One method of stimulating fluid production from a portion of a subterranean formation along a producing zone of a well bore, known as hydrajetting, involves the use of hydraulic jets, inter alia, that increases the permeability and production capabilities of a formation. In an example of a common hydrajetting operation, a hydrajetting tool having at least one fluid jet forming nozzle is positioned adjacent to a formation to be fractured, and proppant slurry is then jetted through the nozzle against the formation at a pressure sufficient to form a cavity, or slot therein to fracture the formation, e.g., by stagnation pressure in the cavity. U.S. Pat. Nos. 5,765,642, 5,494,103, and 5,361,856, the relevant portions of which are herein incorporated by reference, describe suitable hydrajetting tools known in the art. Hydrajetting provides the ability to selectively form a desired number of fractures at desired intervals.

Another method of stimulating fluid production from a subterranean formation is hydraulic fracturing, wherein a formation is treated to increase its permeability by hydraulically fracturing the formation to create or enhance one or more cracks or “fractures.” In most cases, a hydraulic fracturing treatment involves pumping a proppant-free, viscous fluid (known as a pad fluid) into a subterranean formation faster than the fluid can escape into the formation so that the pressure in the formation rises, creating artificial fractures or enlarging natural fractures. Thereafter, proppant slurry oftentimes is pumped into the formation to place proppant inside the created fractures to keep them opened even after the hydraulic pressure has been released.

Stimulation techniques, such as fracturing and hydrajetting, are most successfully performed on portions of a subterranean formation that are substantially consolidated. However, hydrocarbon wells are often located in unconsolidated portions, that is, portions having loose particulates or particulates bonded together with insufficient strength to remain bonded when a fluid (such as produced oil) flows through the portion. The presence of particulates, such as formation sand, in produced fluids may be disadvantageous and undesirable in that the particulates may abrade pumping and other producing equipment and reduce the fluid production capabilities of the producing zones. Thus, it is often desirable to control, or “stabilize,” particulates in relatively unconsolidated areas in a subterranean formation before performing a stimulation treatment.

One method of stabilizing particulates in unconsolidated subterranean portions has been to produce fluids from such formations at low flow rates, whereby the near well stability of sand bridges and the like may be preserved. However, the collapse of such sand bridges may occur due to unintentionally high production rates and/or pressure cycling (as may occur from frequent shut-ins and start ups of a well). The frequency of pressure cycling is very critical to the longevity of the near well formation, especially during the depletion stage of the well when the pore pressure of the formation has been significantly reduced.

Another method of controlling the migration of particulates so that they are not produced along with the produced fluids is gravel packing. Gravel packing involves placing a filtration bed containing gravel near the well bore in order to present a physical barrier to the transport of unconsolidated formation fines with the production of hydrocarbons. Typically, gravel packing operations involve the pumping and placement of a quantity of a desired particulate into the unconsolidated formation in an area adjacent to a well bore. Such packs are often time consuming and expensive to install. In some situations, the processes of fracturing and gravel packing are combined into a single treatment to provide a stimulated production and an annular gravel pack to prevent formation sand production. Such treatments are often referred to as “frac pack” operations.

Another method used to stabilize particulates in unconsolidated formations involves consolidating unconsolidated subterranean producing zones by applying a resin followed by a spacer fluid and then a catalyst. Such resin application may be problematic when, for example, an insufficient amount of spacer fluid is used between the application of the resin and the application of the external catalyst. The resin may come into contact with the external catalyst in the well bore itself rather than in the unconsolidated subterranean producing zone. When resin is contacted with an external catalyst an exothermic reaction occurs that may result in rapid polymerization, potentially damaging the formation by plugging the pore channels, halting pumping when the well bore is plugged with solid material, or resulting in a down hole explosion as a result of the heat of polymerization.

SUMMARY OF THE INVENTION

The present invention relates to methods of stabilizing an unconsolidated portion in a subterranean formation and stimulating fluid production from the stabilized portion.

One embodiment of the present invention provides a method of substantially stabilizing a portion of a subterranean formation penetrated by a well bore and stimulating fluid production therefrom comprising placing a stabilizing composition into a near well bore area of a portion in a formation to create a stabilized portion; and, stimulating the stabilized portion so as to place the well bore in fluid communication with both the stabilized portion in the near-well bore area and an unstabilized portion of the formation in the far-well bore area.

Other embodiments of the present invention provide methods of controlling formation sands in a portion of a formation penetrated by a well bore and stimulating fluid production therefrom comprising placing a stabilizing composition into a near well bore area of a portion in a formation to create a stabilized portion; and, stimulating the stabilized portion so as to place the well bore in fluid communication with both the stabilized portion in the near-well bore area and an unstabilized portion of the formation in the far-well bore area.

Other embodiments of the present invention provide systems for stabilizing and stimulating a portion of a subterranean formation penetrated by a well bore comprising placing a stabilizing composition into a near well bore area of a portion in a formation to create a stabilized portion; and, stimulating the stabilized portion so as to place the well bore in fluid communication with both the stabilized portion in the near-well bore area and an unstabilized portion of the formation in the far-well bore area.

Other and further features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of preferred embodiments which follows.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates near-well bore and far-well bore areas and how fluid communication may be established.

DETAILED DESCRIPTION

The present invention relates to methods of stabilizing an unconsolidated portion in a subterranean formation and stimulating fluid production from the stabilized portion.

Some embodiments of the present invention provide methods of stabilizing subterranean formations and stimulating fluid production comprising the steps of: injecting a stabilizing composition into a near well bore area of a portion in a subterranean formation; allowing the stabilizing composition to substantially cure to form a stabilized portion; stimulating the stabilized portion so as to place the well bore in fluid communication with both the stabilized portion in the near-well bore area and an unstabilized portion of the formation in the far-well bore area. As used herein the term “near well bore area” refers to a distance up to about three well bore diameters from the surface of the well bore into the formation. The term “far well bore area” refers to distances beyond the near well bore area. The methods of the present invention may result in hydrocarbon production at a higher rate with less risk of producing particulates from the formation that may be problematic.

Stabilizing Compositions

Stabilizing compositions suitable for use in the present invention include curable resin compositions that are capable of curing to form hardened substances and gelable substances that cure to form a semi-solid, gel-like substance. Regardless of whether a curable resin composition that cures to form hardened substance is chosen or a gelable substance that cures to form a semi-solid, gel-like substance is chosen, generally, a desirable depth of penetration of the stabilizing composition into the formation surrounding the well bore is from about a few inches in some embodiments to about three well bore diameters in other embodiments.

Stabilizing Compositions: Curable Resin Compositions.

Suitable curable resin compositions include those resins that are capable of forming a hardened, consolidated mass. Such resins include, but are not limited to, novolak resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolic resins, furan/furfuryl alcohol resins, phenolic/latex resins, phenol formaldehyde resins, polyester resins, polyurethane resins and hybrids and copolymers thereof, acrylate resins, and hybrids and copolymers thereof, and mixtures thereof. Some suitable resins, such as epoxy resins, may be cured with an internal catalyst or activator so that when pumped down hole, they may be cured using only time and temperature. Other suitable resins, such as furan resins generally require a time-delayed catalyst or an external catalyst to help activate the polymerization of the resins if the cure temperature is low (i.e., less than 250° F.), but will cure under the effect of time and temperature if the formation temperature is above about 250° F., preferably above about 300° F. It is within the ability of one skilled in the art, with the benefit of this disclosure, to select a suitable resin for use in embodiments of the present invention and to determine whether a catalyst is required to trigger curing.

Stabilizing Compositions: Gelable Compositions.

Gelable compositions suitable for use in the present invention include those compositions that cure to form a semi-solid, gel-like substance. The gelable composition may be any gelable liquid composition capable of converting into a gelled substance capable of substantially plugging the permeability of the formation while allowing the formation to remain flexible. As referred to herein, the term “flexible” refers to a state wherein the treated portion of the formation is relatively malleable and elastic and able to withstand substantial pressure cycling without substantial breakdown of the formation. Thus, the resultant gelled substance stabilizes the treated portion of the formation while allowing the formation to absorb the stresses created during pressure cycling. As a result, the gelled substance may aid in preventing breakdown of the formation both by stabilizing and by adding flexibility to the treated portion. Examples of suitable gelable liquid compositions include, but are not limited to, (1) gelable resin compositions, (2) gelable aqueous silicate compositions, (3) crosslinkable aqueous polymer compositions, and (4) polymerizable organic monomer compositions.

Stabilizing Compositions: Gelable Compositions—Gelable Resin Compositions.

Certain embodiments of the gelable liquid compositions of the present invention comprise gelable resin compositions that cure to form flexible gels. Unlike the curable resin compositions described above, which cure into hardened masses, the gelable resin compositions cure into flexible, gelled substances that form resilient gelled substances between the particulates of the treated zone of the unconsolidated formation. Gelable resin compositions allow the treated portion of the formation to remain flexible and resist breakdown.

Generally, the gelable resin compositions useful in accordance with this invention comprise a curable resin, a diluent, and a resin curing agent. When certain resin curing agents, such as polyamides, are used in the curable resin compositions, the compositions form the semi-solid, gelled substances described above. Where the resin curing agent used may cause the organic resin compositions to form hard, brittle material rather than a desired gelled substance, the curable resin compositions may further comprise one or more “flexibilizer additives” (described in more detail below) to provide flexibility to the cured compositions.

Examples of gelable resins that can be used in the present invention include, but are not limited to, organic resins such as polyepoxide resins (e.g., Bisphenol a-epichlorihydrin resins), polyester resins, urea-aldehyde resins, furan resins, urethane resins, and mixtures thereof. Of these, polyepoxide resins are preferred.

Any diluent that is compatible with the gelable resin and achieves the desired viscosity effect is suitable for use in the present invention. Examples of diluents that may be used in the gelable resin compositions of the present invention include, but are not limited to, phenols; formaldehydes; furfuryl alcohols; furfurals; alcohols; ethers such as butyl glycidyl ether and cresyl glycidyl etherphenyl glycidyl ether; and mixtures thereof. In some embodiments of the present invention, the diluent comprises butyl lactate. The diluent may be used to reduce the viscosity of the gelable resin composition from about 3 to about 3,000 centipoises (“cP”) at 80° F. Among other things, the diluent acts to provide flexibility to the cured composition. The diluent may be included in the gelable resin composition in an amount sufficient to provide the desired viscosity effect. Generally, the diluent used is included in the gelable resin composition in amount in the range of from about 5% to about 75% by weight of the curable resin.

Generally, any resin curing agent that may be used to cure an organic resin is suitable for use in the present invention. When the resin curing agent chosen is an amide or a polyamide, generally no flexibilizer additive will be required because, inter alia, such curing agents cause the gelable resin composition to convert into a semi-solid, gelled substance. Other suitable resin curing agents (such as an amine, a polyamine, methylene dianiline, and other curing agents known in the art) will tend to cure into a hard, brittle material and will thus benefit from the addition of a flexibilizer additive. Generally, the resin curing agent used is included in the gelable resin composition, whether a flexibilizer additive is included or not, in an amount in the range of from about 5% to about 75% by weight of the curable resin. In some embodiments of the present invention, the resin curing agent used is included in the gelable resin composition in an amount in the range of from about 20% to about 75% by weight of the curable resin.

As noted above, flexibilizer additives may be used, inter alia, to provide flexibility to the gelled substances formed from the curable resin compositions. Flexibilizer additives may be used where the resin curing agent chosen would cause the gelable resin composition to cure into a hard and brittle material—rather than a desired gelled substance. For example, flexibilizer additives may be used where the resin curing agent chosen is not an amide or polyamide. Examples of suitable flexibilizer additives include, but are not limited to, an organic ester, an oxygenated organic solvent, an aromatic solvent, and combinations thereof. Of these, ethers, such as dibutyl phthalate, are preferred. Where used, the flexibilizer additive may be included in the gelable resin composition in an amount in the range of from about 5% to about 80% by weight of the gelable resin. In some embodiments of the present invention, the flexibilizer additive may be included in the curable resin composition in an amount in the range of from about 20% to about 45% by weight of the curable resin.

Stabilizing Compositions: Gelable Compositions—Gelable Aqueous Silicate Compositions.

In other embodiments, the gelable liquid compositions of the present invention may comprise a gelable aqueous silicate composition. Generally, the gelable aqueous silicate compositions that are useful in accordance with the present invention generally comprise an aqueous alkali metal silicate solution and a temperature activated catalyst for gelling the aqueous alkali metal silicate solution.

The aqueous alkali metal silicate solution component of the gelable aqueous silicate compositions generally comprise an aqueous liquid and an alkali metal silicate. The aqueous liquid component of the aqueous alkali metal silicate solution generally may be fresh water, salt water (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation. Examples of suitable alkali metal silicates include, but are not limited to, one or more of sodium silicate, potassium silicate, lithium silicate, rubidium silicate, or cesium silicate. Of these, sodium silicate is preferred. While sodium silicate exists in many forms, the sodium silicate used in the aqueous alkali metal silicate solution preferably has a Na2O-to-SiO2 weight ratio in the range of from about 1:2 to about 1:4. Most preferably, the sodium silicate used has a Na2O-to-SiO2 weight ratio in the range of about 1:3.2. Generally, the alkali metal silicate is present in the aqueous alkali metal silicate solution component in an amount in the range of from about 0.1% to about 10% by weight of the aqueous alkali metal silicate solution component.

The temperature-activated catalyst component of the gelable aqueous silicate compositions is used, inter alia, to convert the gelable aqueous silicate compositions into the desired semi-solid, gel-like substance described above. Selection of a temperature-activated catalyst is related, at least in part, to the temperature of the subterranean formation to which the gelable aqueous silicate composition will be introduced. The temperature-activated catalysts that can be used in the gelable aqueous silicate compositions of the present invention include, but are not limited to, ammonium sulfate (which is most suitable in the range of from about 60° F. to about 240° F.); sodium acid pyrophosphate (which is most suitable in the range of from about 60° F. to about 240° F.); citric acid (which is most suitable in the range of from about 60° F. to about 120° F.); and ethyl acetate (which is most suitable in the range of from about 60° F. to about 120° F.). Generally, the temperature-activated catalyst is present in the gelable aqueous silicate composition in the range of from about 0.1% to about 5% by weight of the gelable aqueous silicate composition.

Stabilizing Compositions: Gelable Compositions—Crosslinkable Aqueous Polymer Compositions.

In other embodiments, the gelable liquid compositions of the present invention comprise crosslinkable aqueous polymer compositions. Generally, suitable crosslinkable aqueous polymer compositions comprise an aqueous solvent, a crosslinkable polymer, and a crosslinking agent. Such compositions are similar to those used to form gelled treatment fluids, such as fracturing fluids, but, according to the methods of the present invention, they are not exposed to breakers or de-linkers and so they retain their viscous nature over time.

The aqueous solvent may be any aqueous solvent in which the crosslinkable composition and the crosslinking agent may be dissolved, mixed, suspended, or dispersed therein to facilitate gel formation. For example, the aqueous solvent used may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.

Examples of crosslinkable polymers that can be used in the crosslinkable aqueous polymer compositions include, but are not limited to, carboxylate-containing polymers and acrylamide-containing polymers. Preferred acrylamide-containing polymers include polyacrylamide, partially hydrolyzed polyacrylamide, copolymers of acrylamide and acrylate, and carboxylate-containing terpolymers and tetrapolymers of acrylate. Additional examples of suitable crosslinkable polymers include hydratable polymers comprising polysaccharides and derivatives thereof and that contain one or more of the monosaccharide units galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate. Suitable natural hydratable polymers include, but are not limited to, guar gum, locust bean gum, tara, konjak, tamarind, starch, cellulose, karaya, xanthan, tragacanth, and carrageenan, and derivatives of all of the above. Suitable hydratable synthetic polymers and copolymers that may be used in the crosslinkable aqueous polymer compositions include, but are not limited to, polyacrylates, polymethacrylates, polyacrylamides, maleic anhydride, methylvinyl ether polymers, polyvinyl alcohols, and polyvinylpyrrolidone. The crosslinkable polymer used should be included in the crosslinkable aqueous polymer composition in an amount sufficient to form the desired gelled substance in the subterranean formation. In some embodiments of the present invention, the crosslinkable polymer is included in the crosslinkable aqueous polymer composition in an amount in the range of from about 1% to about 30% by weight of the aqueous solvent. In another embodiment of the present invention, the crosslinkable polymer is included in the crosslinkable aqueous polymer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous solvent.

The crosslinkable aqueous polymer compositions of the present invention further comprise a crosslinking agent for crosslinking the crosslinkable polymers to form the desired gelled substance. In some embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation. A most preferred crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water. Examples of suitable crosslinking agents include, but are not limited to, compounds or complexes containing chromic acetate and/or chromic chloride. Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III, and zirconium IV.

The crosslinking agent should be present in the crosslinkable aqueous polymer compositions of the present invention in an amount sufficient to provide, inter alia, the desired degree of crosslinking. In some embodiments of the present invention, the crosslinking agent is present in the crosslinkable aqueous polymer compositions of the present invention in an amount in the range of from about 0.01% to about 5% by weight of the crosslinkable aqueous polymer composition. The exact type and amount of crosslinking agent or agents used depends upon the specific crosslinkable polymer to be crosslinked, formation temperature conditions, and other factors known to those individuals skilled in the art.

Optionally, the crosslinkable aqueous polymer compositions may further comprise a crosslinking delaying agent, such as a polysaccharide crosslinking delaying agent derived from guar, guar derivatives, or cellulose derivatives. The crosslinking delaying agent may be included in the crosslinkable aqueous polymer compositions, inter alia, to delay crosslinking of the crosslinkable aqueous polymer compositions until desired. One of ordinary skill in the art, with the benefit of this disclosure, will know the appropriate amount of the crosslinking delaying agent to include in the crosslinkable aqueous polymer compositions for a desired application.

Stabilizing Compositions: Gelable Compositions—Polymerization Organic Monomer Compositions.

In other embodiments, the gelled liquid compositions of the present invention comprise polymerizable organic monomer compositions. Generally, suitable polymerizable organic monomer compositions comprise an aqueous-base fluid, a water-soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.

The aqueous-based fluid component of the polymerizable organic monomer composition generally may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.

A variety of monomers are suitable for use as the water-soluble polymerizable organic monomers in the present invention. Examples of suitable monomers include, but are not limited to, acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2-methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate, 2-triethylammoniumethylmethacrylate chloride, N,N-dimethyl-aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone, vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammonium sulfate, and mixtures thereof. Preferably, the water-soluble polymerizable organic monomer should be self-crosslinking. Examples of suitable monomers which are self crosslinking include, but are not limited to, hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethylmethacrylate, N-hydroxymethylacrylamide, N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate, polyethylene glycol methacrylate, polypropylene gylcol acrylate, polypropylene glycol methacrylate, and mixtures thereof. Of these, hydroxyethylacrylate is preferred. An example of a particularly preferable monomer is hydroxyethylcellulose-vinyl phosphoric acid.

The water-soluble polymerizable organic monomer (or monomers where a mixture thereof is used) should be included in the polymerizable organic monomer composition in an amount sufficient to form the desired gelled substance after placement of the polymerizable organic monomer composition into the subterranean formation. In some embodiments of the present invention, the water-soluble polymerizable organic monomer is included in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 30% by weight of the aqueous-base fluid. In another embodiment of the present invention, the water-soluble polymerizable organic monomer is included in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous-base fluid.

The presence of oxygen in the polymerizable organic monomer composition may inhibit the polymerization process of the water-soluble polymerizable organic monomer or monomers. Therefore, an oxygen scavenger, such as stannous chloride, may be included in the polymerizable monomer composition. In order to improve the solubility of stannous chloride so that it may be readily combined with the polymerizable organic monomer composition on the fly, the stannous chloride may be pre-dissolved in a hydrochloric acid solution. For example, the stannous chloride may be dissolved in a 0.1% by weight aqueous hydrochloric acid solution in an amount of about 10% by weight of the resulting solution. The resulting stannous chloride-hydrochloric acid solution may be included in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 10% by weight of the polymerizable organic monomer composition. Generally, the stannous chloride may be included in the polymerizable organic monomer composition of the present invention in an amount in the range of from about 0.005% to about 0.1% by weight of the polymerizable organic monomer composition.

The primary initiator is used, inter alia, to initiate polymerization of the water-soluble polymerizable organic monomer(s) used in the present invention. Any compound or compounds that form free radicals in aqueous solution may be used as the primary initiator. The free radicals act, inter alia, to initiate polymerization of the water-soluble polymerizable organic monomer present in the polymerizable organic monomer composition. Compounds suitable for use as the primary initiator include, but are not limited to, alkali metal persulfates; peroxides; oxidation-reduction systems employing reducing agents, such as sulfites in combination with oxidizers; and azo polymerization initiators. Preferred azo polymerization initiators include 2,2′-azobis(2-imidazole-2-hydroxyethyl)propane, 2,2′-azobis(2-aminopropane), 4,4′-azobis(4-cyanovaleric acid), and 2,2′-azobis(2-methyl-N-(2-hydroxyethyl)propionamide. Generally, the primary initiator should be present in the polymerizable organic monomer composition in an amount sufficient to initiate polymerization of the water-soluble polymerizable organic monomer(s). In certain embodiments of the present invention, the primary initiator is present in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 5% by weight of the water-soluble polymerizable organic monomer(s). One skilled in the art will recognize that as the polymerization temperature increases, the required level of activator decreases.

Optionally, the polymerizable organic monomer compositions further may comprise a secondary initiator. A secondary initiator may be used, for example, where the immature aqueous gel is placed into a subterranean formation that is relatively cool as compared to the surface mixing, such as when placed below the mud line in offshore operations. The secondary initiator may be any suitable water-soluble compound or compounds that may react with the primary initiator to provide free radicals at a lower temperature. An example of a suitable secondary initiator is triethanolamine. In some embodiments of the present invention, the secondary initiator is present in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 5% by weight of the water-soluble polymerizable organic monomer(s).

Also optionally, the polymerizable organic monomer compositions of the present invention further may comprise a crosslinking agent for crosslinking the polymerizable organic monomer compositions in the desired gelled substance. In some embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation. A most preferred crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water. Examples of suitable crosslinking agents include, but are not limited to, compounds or complexes containing chromic acetate and/or chromic chloride. Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III, and zirconium IV. Generally, the crosslinking agent may be present in polymerizable organic monomer compositions in an amount in the range of from 0.01% to about 5% by weight of the polymerizable organic monomer composition.

Stimulation Treatments.

Once the stabilizing composition is placed into the formation, it is allowed to substantially cure and stabilize the treated portion of the formation. Once the treated portion of the formation is so stabilized, a stimulation treatment is performed.

In certain embodiments, the stimulating step of the methods of the present invention may involve perforating, hydrajetting, fracturing, or some other stimulating method known in the art. One object of the stimulation treatment is to place the well bore in fluid communication with the treated portion of the formation surrounding the well bore and with an untreated portion. This concept is illustrated in FIG. 1 to show how fluid communication may be established where the chosen stimulation treatment is fracturing. FIG. 1 shows a top view of well bore 10 with a stylized fracture 20. Well bore 10 has been stabilized in the near well bore region (30) to a distance of approximately one-half of a well bore diameter, as shown by stabilizing treatment penetration 30.

Stimulation Treatments: Hydrajetting.

One stimulation treatment suitable for use in the methods of the present invention is hydrajetting. Hydrajetting, as described above, refers to a treatment in which a hydrajetting tool having at least one fluid jet forming nozzle is positioned adjacent to a formation to be fractured, and fluid is then jetted through the nozzle against the formation at a pressure sufficient to form a cavity, or slot therein to fracture the formation by stagnation pressure in the cavity. In some embodiments of the present invention, the hydrajetting tool is used to create slots substantially uniformly around the well bore circumference. Because the jetted fluids would have to flow out of the slot in a direction generally opposite to the direction of the incoming jetted fluid, they are trapped in the slot and create a relatively high stagnation pressure at the tip of a cavity. This high stagnation pressure often causes a microfracture to be formed that extends a short distance into the formation. That microfracture may be further extended by pumping a fluid into the well bore to raise the ambient fluid pressure exerted on the formation while the formation is being hydrajetted. Such a fluid in the well bore will flow into the slot and fracture produced by the fluid jet and, if introduced into the well bore at a sufficient rate and pressure, may be used to extend the fracture an additional distance from the well bore into the formation. Then a proppant is generally added to the fluid to form a slurry that is pumped into the fracture to prevent the fracture from closing when the pumping pressure is released. A portion of the proppant may be coated with a tackifying agent, inter alia, to control fines from migrating into the proppant pack. A portion of the proppant may also be coated with curable resin so that, once cured, the placed proppant forms a consolidated mass and prevents the proppant from flowing back during production of the well.

Stimulation Treatments: Hydraulic Fracturing.

Another stimulation treatment suitable for use in some embodiments of the methods of the present invention is hydraulic fracturing, wherein a formation is treated to increase its permeability by hydraulically fracturing the formation to create or enhance one or more cracks or “fractures.” In most cases, a hydraulic fracturing treatment involves pumping a proppant-free, viscous fluid (known as a pad fluid) into a subterranean formation faster than the fluid can escape into the formation so that the pressure in the formation rises and the formation breaks, creating an artificial fracture or enlarging a natural fracture. Similar to hydrajetting, a proppant is then generally added to the fluid to form a slurry that is pumped into the fracture to prevent the fracture from closing when the pumping pressure is released. A portion of the proppant may be coated with a tackifying agent, inter alia, to control fines from migrating into the proppant pack. A portion of the proppant may also be coated with curable resin so that, once cured, the placed proppant forms a consolidated mass and prevents the proppant from flowing back during production of the well.

Suitable Proppants.

Proppants that may be used in the embodiments of the stimulation treatments of the present invention include a wide variety of particulate materials suitable for use in subterranean applications. Examples include, but are not limited to, man-made proppant; sand; bauxite; ceramic materials; glass materials; polymer materials; plastic materials; “TEFLON™” materials; lightweight particulates; ground or crushed nut shells; ground or crushed seed shells; ground or crushed fruit pits; processed wood; composite particulates prepared from a binder with filler particulate including silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, and solid glass; or mixtures thereof. The proppant used may have a particle size in the range of from about 2 to about 400 mesh, U.S. Sieve Series. Preferably, the proppant is graded sand having a particle size in the range of from about 10 to about 70 mesh, U.S. Sieve Series.

In certain preferred embodiments, the proppant used is coated with either a resin that is capable of consolidating the proppant particles into a hardened, permeable mass; a tackifying agent capable of controlling particulate production from the unstabilized portion of the formation; or a combination thereof. It is well within the ability of one skilled in the art, with the benefit of this disclosure, to select a suitable resin or tackifying agent to coat the proppant used in the present invention.

Resins suitable for use in coating proppant used in the present invention include, but are not limited to, two-component epoxy-based resins, furan-based resins, phenolic-based resins, high-temperature (HT) epoxy-based resins, and phenol/phenol formaldehyde/furfuryl alcohol resins. Selection of a suitable resin coating material may be affected by the temperature of the subterranean formation to which the fluid will be introduced. By way of example, for subterranean formations having a bottom hole static temperature (“BHST”) ranging from about 60° F. to about 250° F., two-component epoxy-based resins comprising a hardenable resin component and a hardening agent component containing specific hardening agents may be preferred. For subterranean formations having a BHST ranging from about 300° F. to about 600° F., a furan-based resin may be preferred. For subterranean formations having a BHST ranging from about 200° F. to about 400° F., either a phenolic-based resin or a one-component HT epoxy-based resin may be suitable. For subterranean formations having a BHST of at least about 175° F., a phenol/phenol formaldehyde/furfuryl alcohol resin also may be suitable.

Tackifying agents suitable for use in coating proppant used in the present invention comprise any compound that, when in liquid form or in a solvent solution, will form a non-hardening coating upon a particulate. A particularly preferred group of tackifying agents comprise polyamides that are liquids or in solution at the temperature of the subterranean formation such that they are, by themselves, non-hardening when introduced into the subterranean formation. A particularly preferred product is a condensation reaction product comprised of commercially available polyacids and a polyamine. Such commercial products include compounds such as mixtures of C36 dibasic acids containing some trimer and higher oligomers and also small amounts of monomer acids that are reacted with polyamines. Other polyacids include trimer acids, synthetic acids produced from fatty acids, maleic anhydride, acrylic acid, and the like. Such acid compounds are commercially available from companies such as Witco Corporation, Union Camp, Chemtall, and Emery Industries. The reaction products are available from, for example, Champion Technologies, Inc. and Witco Corporation. Additional compounds which may be used as tackifying compounds include liquids and solutions of, for example, polyesters, polycarbonates and polycarbamates, natural resins such as shellac and the like. Other suitable tackifying agents are described in U.S. Pat. No. 5,853,048 issued to Weaver, et al. and U.S. Pat. No. 5,833,000 issued to Weaver, et al., the relevant disclosures of which are herein incorporated by reference.

Tackifying agents suitable for use in the present invention may be either used such that they form non-hardening coating or they may be combined with a multifunctional material capable of reacting with the tackifying compound to form a hardened coating. A “hardened coating” as used herein means that the reaction of the tackifying compound with the multifunctional material will result in a substantially non-flowable reaction product that exhibits a higher compressive strength in a consolidated agglomerate than the tackifying compound alone with the particulates. In this instance, the tackifying agent may function similarly to a hardenable resin. Multifunctional materials suitable for use in the present invention include, but are not limited to, aldehydes such as formaldehyde, dialdehydes such as glutaraldehyde, hemiacetals or aldehyde releasing compounds, diacid halides, dihalides such as dichlorides and dibromides, polyacid anhydrides such as citric acid, epoxides, furfuraldehyde, glutaraldehyde or aldehyde condensates and the like, and combinations thereof. In some embodiments of the present invention, the multifunctional material may be mixed with the tackifying compound in an amount of from about 0.01 to about 50 percent by weight of the tackifying compound to effect formation of the reaction product. In some preferable embodiments, the compound is present in an amount of from about 0.5 to about 1 percent by weight of the tackifying compound. Suitable multifunctional materials are described in U.S. Pat. No. 5,839,510 issued to Weaver, et al., the relevant disclosure of which is herein incorporated by reference.

Therefore, the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned as well as those that are inherent therein. While numerous changes may be made by those skilled in the art, such changes are encompassed within the spirit and scope of this invention as defined by the appended claims.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7216711 *Jun 15, 2004May 15, 2007Halliburton Eenrgy Services, Inc.Methods of coating resin and blending resin-coated proppant
US7494711Mar 8, 2006Feb 24, 2009Bj Services CompanyCoated plastic beads and methods of using same to treat a wellbore or subterranean formation
US7934557 *Feb 15, 2007May 3, 2011Halliburton Energy Services, Inc.Methods of completing wells for controlling water and particulate production
DE102006050761A1 *Oct 27, 2006May 8, 2008Construction Research & Technology GmbhHydrophob modifizierte kationische Copolymere
WO2007007039A1 *Jul 4, 2006Jan 18, 2007Halliburton Energy Serv IncMethods and compositions for controlling formation fines and reducing proppant flow-back
WO2011070453A2 *Sep 29, 2010Jun 16, 2011Schlumberger Canada LimitedMethod for increasing fracture area
Classifications
U.S. Classification166/281, 507/267, 507/219, 507/221, 166/280.1, 507/260, 166/295, 166/292, 166/300
International ClassificationE21B43/114, E21B43/267, E21B43/26, C09K8/575, C09K8/80, E21B33/138
Cooperative ClassificationE21B43/114, C09K8/5751, C09K8/5756, E21B43/26, C09K8/80, C09K8/805
European ClassificationC09K8/80B, E21B43/114, C09K8/80, C09K8/575B, E21B43/26, C09K8/575B6
Legal Events
DateCodeEventDescription
May 25, 2004ASAssignment
Owner name: HALLIBURTON ENERGY SERVICES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:NGUYEN, PHILIP D.;REEL/FRAME:015379/0710
Effective date: 20040524