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Publication numberUS20050194142 A1
Publication typeApplication
Application numberUS 10/793,711
Publication dateSep 8, 2005
Filing dateMar 5, 2004
Priority dateMar 5, 2004
Also published asCA2558055A1, WO2005085594A1
Publication number10793711, 793711, US 2005/0194142 A1, US 2005/194142 A1, US 20050194142 A1, US 20050194142A1, US 2005194142 A1, US 2005194142A1, US-A1-20050194142, US-A1-2005194142, US2005/0194142A1, US2005/194142A1, US20050194142 A1, US20050194142A1, US2005194142 A1, US2005194142A1
InventorsPhilip Nguyen, Johnny Barton, David Brown
Original AssigneeNguyen Philip D., Barton Johnny A., Brown David L.
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Compositions and methods for controlling unconsolidated particulates
US 20050194142 A1
Abstract
The present invention relates to methods for stabilizing an unconsolidated or weakly consolidated zone of a subterranean formation. One embodiment provides a method of stabilizing a subterranean formation comprising the steps of placing a gelable liquid composition into the subterranean formation, wherein the gelable liquid composition is capable of forming a gelled substance after placement; and, allowing the gelable liquid composition to convert into a gelled substance that stabilizes unconsolidated or weakly consolidated particles within the subterranean formation. Another embodiment provides a method of stimulating production from a subterranean formation comprising the steps of placing a gelable liquid composition into the subterranean formation; allowing the gelable liquid composition to convert into a gelled substance; creating at least one fracture in the subterranean formation extending from the well bore, through the gelled substance, and into an untreated zone of the subterranean formation; depositing proppant into at least one such fracture.
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Claims(68)
1. A method of stabilizing an unconsolidated or weakly consolidated subterranean formation comprising the steps of:
placing a gelable liquid composition into the subterranean formation; and,
allowing the gelable liquid composition to convert into a gelled substance that stabilizes unconsolidated or weakly consolidated particles within the subterranean formation.
2. The method of claim 1 wherein the gelable liquid composition comprises a curable resin composition, a gelable aqueous silicate composition, or a polymerizable organic monomer composition.
3. The method of claim 1 wherein the gelable liquid composition comprises a curable resin composition that comprises a curable resin, a diluent, and a resin curing agent.
4. The method of claim 3 wherein curable resin comprises an organic resin that comprises a bisphenol A-epichlorihydrin resin, a polyepoxide resin, a polyester resin, a urea-aldehyde resin, a furan resin, a urethane resin, or a mixture thereof.
5. The method of claim 3 wherein the diluent comprises a phenol, a formaldehyde, a furfuryl alcohol, a furfural, an alcohol, an ether, or a mixture thereof.
6. The method of claim 3 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.
7. The method of claim 3 wherein the resin curing agent comprises an amine, a polyamine, an amide, a polyamide, or a methylene dianiline.
8. The method of claim 3 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.
9. The method of claim 3 wherein the curable resin composition further comprises a flexibilizer additive.
10. The method of claim 9 wherein the flexibilizer additive comprises an organic ester, an oxygenated organic solvent, or an aromatic solvent.
11. The method of claim 9 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.
12. The method of claim 1 wherein the gelable liquid composition comprises a gelable aqueous silicate composition that comprises an aqueous alkali metal silicate solution and a temperature activated catalyst for gelling the aqueous alkali metal silicate solution.
13. The method of claim 12 wherein the alkali metal silicate solution comprises sodium silicate, potassium silicate, lithium silicate, rubidium silicate, or cesium silicate.
14. The method of claim 12 wherein the temperature activated catalyst comprises an ammonium sulfate, a sodium acid pyrophosphate, a citric acid, or an ethyl acetate.
15. The method of claim 1 wherein the gelable liquid composition is a polymerizable organic monomer composition that comprises an aqueous-base fluid, a water soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.
16. The method of claim 15 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.
17. The method of claim 15 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, or a mixture thereof.
18. The method of claim 15 wherein the water soluble polymerizable organic monomer comprises hydroxyethylcellulose-vinyl phosphoric acid.
19. The method of claim 15 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 30% by weight of the aqueous-base fluid.
20. The method of claim 15 wherein the oxygen scavenger comprises stannous chloride.
21. The method of claim 15 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.
22. The method of claim 15 wherein the primary initiator comprises an alkali metal persulfate, a peroxide, an oxidation-reduction system employing reducing agent, or an azo polymerization initiator.
23. The method of claim 15 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.
24. The method of claim 15 wherein the polymerizable organic monomer composition further comprises a secondary initiator.
25. The method of claim 15 wherein the polymerizable organic monomer composition further comprises a crosslinking agent.
26. The method of claim 1 further comprising the step of placing an after-flush fluid into the subterranean formation after placement of the gelable liquid composition into the subterranean formation.
27. The method of claim 26 wherein the after-flush fluid comprises an aqueous-based fluid or a hydrocarbon-based fluid.
28. The method of claim 1 further comprising the step of, after allowing the gelable liquid composition to convert into a gelled substance, creating at least one fracture in the subterranean formation extending from the well bore, through the gelled substance, and into an untreated portion of the subterranean formation.
29. The method of claim 1 further comprising the step of shutting in the subterranean formation for a chosen period of time after placing the liquid composition into the subterranean formation.
30. The method of claim 29 wherein the chosen period of time is from about 0.5 hours to about 72 hours.
31. A method of stimulating production from an unconsolidated or weakly consolidated subterranean formation penetrated by a well bore comprising the steps of:
placing a liquid composition into the subterranean formation;
allowing the gelable liquid composition to convert into a gelled substance;
creating at least one fracture in the subterranean formation extending through the gelled substance, and into an untreated zone of the subterranean formation; and
depositing proppant into a fracture.
32. The method of claim 31 wherein the gelable liquid composition comprises a curable resin composition that comprises a curable resin, a diluent, and a resin curing agent.
33. The method of claim 32 wherein the curable resin comprises an organic resin that comprises a bisphenol A-epichlorihydrin resin, a polyepoxide resin, a polyester resin, a urea-aldehyde resin, a furan resin, a urethane resin, or a mixture thereof.
34. The method of claim 32 wherein the diluent comprises a phenol, a formaldehyde, a furfuryl alcohol, a furfural, an alcohol, an ether, or a mixture thereof.
35. The method of claim 32 wherein the diluent comprises butyl lactate.
36. The method of claim 32 wherein the resin curing agent comprises an amine, a polyamine, a polyamide, or a methylene dianiline.
37. The method of claim 32 wherein the curable resin composition further comprises a flexibilizer additive.
38. The method of claim 37 wherein the flexibilizer additive comprises an organic ester, an oxygenated organic solvent, or an aromatic solvent.
39. The method of claim 31 wherein the gelable liquid composition comprises a gelable aqueous silicate composition that comprises an aqueous alkali metal silicate solution, and a temperature activated catalyst.
40. The method of claim 39 wherein the alkali metal silicate solution comprises sodium silicate, potassium silicate, lithium silicate, rubidium silicate, or cesium silicate.
41. The method of claim 39 wherein the temperature activated catalyst comprises an ammonium sulfate, a sodium acid pyrophosphate, a citric acid, or an ethyl acetate.
42. The method of claim 31 wherein the gelable liquid composition comprises a crosslinkable aqueous polymer composition that comprises an aqueous solvent, a crosslinkable polymer, and a crosslinking agent.
43. The method of claim 42 wherein the crosslinkable polymer comprises an acrylamide-containing polymer.
44. The method of claim 42 wherein the crosslinkable polymer comprises polyacrylamide, partially hydrolyzed polyacrylamide, a copolymer of acrylamide and acrylate, a carboxylate-containing terpolymer, or a tetrapolymer of acrylate.
45. The method of claim 42 wherein the crosslinkable polymer comprises a guar gum, a locust bean gum, tara, konjak, tamarind, a starch, a cellulose, karaya, xanthan, tragacanth, carrageenan, derivatives of the above, or combinations thereof
46. The method of claim 42 wherein the crosslinkable polymer comprises a polyacrylate, a polymethacrylate, a polyacrylamide, a maleic anhydride, a methylvinyl ether polymer, a polyvinyl alcohol, or a polyvinylpyrolidone.
47. The method of claim 42 wherein the crosslinking agent comprises a transition metal cation-containing crosslinking agent.
48. The method of claim 31 wherein the gelable liquid composition comprises a polymerizable organic monomer composition that comprises an aqueous-base fluid, a water soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.
49. The method of claim 48 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.
50. The method of claim 48 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, or a mixture thereof.
51. The method of claim 48 wherein the water soluble polymerizable organic monomer comprises hydroxyethylcellulose-vinyl phosphoric acid.
52. The method of claim 48 wherein the oxygen scavenger comprises stannous chloride.
53. The method of claim 48 wherein the primary initiator comprises an alkali metal persulfate, a peroxide, an oxidation-reduction system employing reducing agents, or an azo polymerization initiator.
54. The method of claim 48 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.
55. The method of claim 48 wherein the polymerizable organic monomer composition further comprises a secondary initiator.
56. The method of claim 48 wherein the polymerizable organic monomer composition further comprises a crosslinking agent.
57. The method of claim 31 further comprising the step of placing an after-flush fluid into the subterranean formation after placement of the gelable liquid composition into the subterranean formation.
58. The method of claim 57 wherein the after-flush fluid comprises an aqueous-based fluid or a hydrocarbon fluid.
59. The method of claim 31 wherein the at least one fracture is created by pumping a fracturing fluid into the subterranean formation at a sufficient rate and pressure to fracture the subterranean formation.
60. The method of claim 59 wherein proppant is suspended in the fracturing fluid
61. The method of claim 59 wherein the proppant comprises a hardenable resin coating.
62. The method of claim 31 further comprising the step of shutting in the subterranean formation for a chosen period of time after placing the gelable liquid composition into the subterranean formation.
63. The method of claim 62 wherein the chosen period of time is from about 0.5 hours to about 72 hours.
64. A method of stimulating production from an unconsolidated or weakly consolidated subterranean formation penetrated by a well bore comprising the steps of:
placing a gelable liquid composition into the subterranean formation, wherein the gelable liquid composition comprises a polyepoxide resin, a diluent, a flexibilizer additive, and a resin curing agent;
allowing the gelable liquid composition to convert into a gelled substance;
creating at least one fracture in the subterranean formation extending from the well bore through the gelled substance and into an untreated zone of the subterranean formation; and
depositing proppant into the at least one fracture.
65. The method of claim 64 wherein the polyepoxide resin comprises bisphenol A-epichlorihydrin resin.
66. The method of claim 64 wherein the diluent comprises butyl lactate.
67. The method of claim 64 wherein the flexibilizer additive comprises dibutyl phthalate.
68. The method of claim 64 wherein the resin curing agent comprises methylene dianiline.
Description
BACKGROUND

The present invention relates to the stabilization of subterranean formations. More particularly, the present invention relates to improved methods for stabilizing unconsolidated or weakly consolidated zones of a subterranean formation.

Hydrocarbon wells are often located in subterranean zones that contain unconsolidated particulates that may migrate out of the subterranean formation with the oil, gas, water, and/or other fluids produced by the wells. The presence of particulates, such as formation sand, in produced fluids is undesirable in that the particulates may abrade pumping and other producing equipment and reduce the fluid production capabilities of the producing zones. Unconsolidated subterranean zones include those that contain loose particulates and those wherein the bonded particulates have insufficient bond strength to withstand the forces produced by the production of fluids through the zones.

One method of controlling particulates in such unconsolidated subterranean zones has been to produce fluids from the formations at low flow rates, whereby the near well stability of sand bridges and the like may be substantially preserved. However, the collapse of such sand bridges may occur due to unintentionally high production rates and/or pressure cycling as may occur from repeated 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 already been significantly reduced.

Another method of controlling particulates in unconsolidated subterranean zones 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 an area adjacent to a well bore in an unconsolidated or weakly consolidated formation. Such packs may be time consuming and expensive to install. Weakly consolidated formations also have been treated by creating fractures in the formations and depositing proppant in the fractures wherein the proppant is consolidated within the fractures into hard, permeable masses using a resin or tackifying composition to reduce the migration of sand. 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 control particulates in unconsolidated formations involves consolidating unconsolidated subterranean producing zones into hard permeable masses by applying a resin followed by a spacer fluid and then a catalyst. Such methods 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. In that case, 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. Also, using resins to consolidate unconsolidated zones may not be practical due, at least in part, to the high cost of most suitable resins.

Thus, there is a need for improved methods of stabilizing and stimulating fluid production from unconsolidated or weakly consolidated zones of subterranean formations while preventing the undesired migration of formation particulates with fluids produced therefrom.

SUMMARY OF THE INVENTION

The present invention relates to the stabilization of subterranean formations. More particularly, the present invention relates to improved methods for stabilizing unconsolidated or weakly consolidated zones of a subterranean formation.

One embodiment of the present invention provides a method of stabilizing an unconsolidated or weakly consolidated subterranean formation comprising the steps of placing a gelable liquid composition into the subterranean formation; and, allowing the gelable liquid composition to convert into a gelled substance that at least partially stabilizes unconsolidated or weakly consolidated particles within the subterranean formation.

Another embodiment of the present invention provides a method of stimulating production from an unconsolidated or weakly consolidated subterranean formation penetrated by a well bore comprising the steps of placing a gelable liquid composition into the subterranean formation; allowing the gelable liquid composition to form a gelled substance; creating at least one fracture in the subterranean formation that extends through the gelled substance, and into a zone of the subterranean formation; and depositing proppant into the fracture.

Another embodiment of the present invention provides a method of stimulating production from an unconsolidated or weakly consolidated subterranean formation penetrated by a well bore comprising the steps of placing a gelable liquid composition into the subterranean formation, wherein the gelable liquid composition comprises a polyepoxide resin, a diluent, a flexibilizer additive, and a resin curing agent; allowing the gelable liquid composition to form a gelled substance; creating at least one fracture in the subterranean formation extending through the gelled substance and into a zone of the subterranean formation; and depositing proppant into the fracture.

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 that follows.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to the stabilization of subterranean formations. More particularly, the present invention relates to improved methods for stabilizing unconsolidated or weakly consolidated zones of a subterranean formation.

Certain embodiments of the present invention comprise placing a gelable liquid composition into a subterranean formation, and allowing the gelable liquid composition to convert into a gelled substance that stabilizes unconsolidated or weakly consolidated particles within the subterranean formation.

The gelable liquid 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. That is, the gelled substance should negatively impact the ability of the formation to produce desirable fluids such as hydrocarbons. As referred to herein, the term “flexible” refers to a state wherein the treated formation is relatively malleable and elastic and able to withstand substantial pressure cycling without substantial breakdown of the formation. Thus, the resultant gelled substance should be a semi-solid, immovable, gel-like substance, which, among other things, 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 formation sands. Examples of suitable gelable liquid compositions include, but are not limited to, resin compositions that cure to form flexible gels, gelable aqueous silicate compositions, crosslinkable aqueous polymer compositions, and polymerizable organic monomer compositions.

Certain embodiments of the gelable liquid compositions of the present invention comprise curable resin compositions. Curable resin compositions are well known to those skilled in the art and have been used to consolidate portions of unconsolidated formations and to consolidate proppant materials into hard, permeable masses. While the curable resin compositions used in accordance with the present invention may be similar to those previously used to consolidate sand and proppant into hard, permeable masses, they are distinct in that resins suitable for use with the present invention do not cure into hard, permeable masses; rather they cure into flexible, gelled substances. That is, suitable curable resin compositions form resilient gelled substances between the particulates of the treated zone of the unconsolidated formation and thereby allow that portion of the formation to remain flexible and to resist breakdown. It is not necessary or desirable for the cured resin composition to solidify and harden to provide high consolidation strength to the treated portion of the formation. On the contrary, upon being cured, the curable resin compositions useful in accordance with this invention form semi-solid, immovable, gelled substances.

Generally, the curable 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, immovable, 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 curable resins that can be used in the curable resin compositions of 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 curable resin and achieves the desired viscosity effect is suitable for use in the present invention. Examples of diluents that may be used in the curable 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 curable resin composition to 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 curable resin composition in an amount sufficient to provide the desired viscosity effect. Generally, the diluent used is included in the curable 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 curable resin composition to convert into a semi-solid, immovable, 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 curable 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 curable 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 should be used where the resin curing agent chosen would cause the organic resin composition to cure into a hard and brittle material—not the desired gelled substances described herein. 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 curable resin composition in an amount in the range of from about 5% to about 80% by weight of the curable 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.

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 comprises 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, immovable, gelled 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 which 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.

In other embodiments, the gelable liquid compositions of the present invention comprises crosslinkable aqueous polymer compositions. Generally, suitable crosslinkable aqueous polymer compositions comprise an aqueous solvent, a crosslinkable polymer, and a crosslinking agent.

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 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 agents 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 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.

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-base 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(s) are 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(s) are 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 which 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(s) 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 monomers(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).

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).

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.

In certain embodiments of the present invention, an optional pre-flush fluid may be placed into the subterranean formation prior to the placement of the gelable liquid compositions into the subterranean formation. The pre-flush fluid acts, inter alia, to prepare the subterranean formation for the later placement of the gelable liquid composition. Generally, the volume of the pre-flush fluid placed into the formation is between 0.1 to 50 times the volume of the gelable liquid composition.

The pre-flush fluid may be any fluid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation. For example, the pre-flush fluid may be an aqueous-based fluid or a hydrocarbon-based fluid. In certain embodiments of the present invention, the pre-flush fluid may comprise an aqueous liquid and a surfactant. The aqueous-liquid component may be fresh water, salt water, brine, or seawater, or any other aqueous-based liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation. Any surfactant compatible with the later-used gelable liquid composition and capable of aiding the gelable liquid composition in flowing to the contact points between adjacent particulates in the formation may be used in the present invention. Such surfactants include, but are not limited to, ethoxylated nonyl phenol phosphate esters, mixtures of one or more cationic surfactants, one or more non-ionic surfactants, and an alkyl phosphonate surfactant. Suitable mixtures of one or more cationic and nonionic surfactants are described in U.S. Pat. No. 6,311,773 issued to Todd et al. on Nov. 6, 2001, the disclosure of which is incorporated herein by reference. A C12-C22 alkyl phosphonate surfactant is preferred. The surfactant or surfactants used are included in the pre-flush fluid in an amount sufficient to prepare the subterranean formation to receive a treatment of an immature aqueous gel. In some embodiments of the present invention, the surfactant is present in the pre-flush fluid in an amount in the range of from about 0.1% to about 3% by weight of the aqueous liquid.

In certain embodiments of the present invention, after the placement of the gelable liquid composition into the subterranean formation, an optional after-flush fluid may be placed into the subterranean formation, inter alia, to restore the permeability of the treated portion of the subterranean formation. The after-flush fluid is preferably placed into the subterranean formation while the gelable liquid composition is still in a flowing state. Among other things, the after-flush fluid acts to displace at least a portion of the gelable liquid composition from the pore channels of the subterranean formation and to force the displaced portion of the gelable liquid composition further into the subterranean formation where it may have negligible impact on subsequent hydrocarbon production. Generally, the after-flush fluid may be any fluid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation. The after-flush may be an aqueous-based brine or a hydrocarbon fluid, such as kerosene, diesel, or crude oil. The after-flush fluid may be placed into the formation at a matrix flow rate such that a sufficient portion of the gelable liquid composition may be displaced from the pore channels to restore the formation to a desired permeability. However, a substantial amount of the gelable liquid composition should not be displaced therein. For example, sufficient amounts of the gelable liquid composition should remain in the treated zone to provide effective stabilization of the unconsolidated zones therein.

Generally, the volume of after-flush fluid placed in the subterranean formation ranges from about 0.1 to about 50 times the volume of the gelable liquid composition. In some embodiments of the present invention, the volume of after-flush fluid placed in the subterranean formation ranges from about 2 to about 5 times the volume of the gelable liquid composition.

In another embodiment of the present invention, no after-flush fluid is placed into the subterranean formation after placement of the immature aqueous gel into the subterranean formation. Whether to omit an after-flush fluid is based, in part, on the initial permeability of the subterranean formation. For example, it may be desirable to not use an after-flush where the initial permeability of the formation is less than about 10 milli-darcies (“mD”) for gas wells, or less than about 50 mD for oil wells. Where no after-flush is used, the permeability of the subterranean formation is significantly reduced because the gelable liquid composition remains in the pore spaces therein and converts into a gelled substance. While there is a significant reduction in the permeability, the unconsolidated zones of the formation may be stabilized due, inter alia, to the gelled substance remaining in the pore spaces of the formation.

In some embodiments of the present invention, after the gelable liquid composition is allowed to form a gelled substance, one or more fractures may be created in the subterranean formation extending through the gelled substance and into untreated zones of the subterranean formation. In certain embodiments, the fracture or fractures are created after the after-flush fluid is placed into the subterranean formation. The fracture or fractures may be created by pumping a viscous fracturing fluid comprising a proppant into the subterranean formation at a rate and pressure sufficient to create one or more fractures therein. The continued pumping of the fracturing fluid extends the fractures into the subterranean formation and carries the proppant into the fracture or fractures formed. Upon reduction of the flow of the fracturing fluid and the pressure exerted on the subterranean formation, the proppant is deposited in the fracture or fractures. The fracture or fractures may be prevented from closing by the presence of the proppant therein.

The fracturing fluids that may be used in accordance with the present invention include any fracturing fluid that is suitable for use in subterranean operations, such as gelled water-based fluids, hydrocarbon-based fluids, foams, and emulsions. In one embodiment of the present invention, the fracturing fluid used to create the one or more fractures may be a viscoelastic surfactant fluid comprising worm-like micelles. In another embodiment of the present invention, the fracturing fluid may be a gelled fracturing fluid that comprises water (e.g., fresh water, salt water, brine, or sea water) and a gelling agent for increasing the viscosity of the fracturing fluid. The increased viscosity reduces fluid loss and allows the fracturing fluid to transport significant concentrations of proppant into the created fractures. The selection of an appropriate fracturing fluid is within the ability of one of ordinary skill in the art.

As mentioned, the proppant deposited in the one or more fractures formed in a subterranean formation functions to prevent the fractures from closing due to overburden pressures, whereby produced fluids can flow through the fractures. Proppant used in accordance with the present invention are generally particulate materials of a size such that formation particulates that may migrate with produced fluids are prevented from being produced from the subterranean formation, e.g., the proppant may filter out migrating sand. A wide variety of particulate materials may be used as proppant in accordance with the present invention, including, but not limited to, sand; bauxite; ceramic materials; glass materials; polymer materials; “TEFLON™” materials; 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. Preferred sand particle size distribution ranges are one or more of 10-20 mesh, 20-40 mesh, 40-60 mesh or 50-70 mesh, depending on the particle size and distribution of the formation particulates to be screened out by the proppant.

The proppant used in accordance with the present invention may be coated with a hardenable resin composition. In some embodiments, the hardenable resin composition is preferably comprised of a hardenable resin, a diluent, and a silane coupling agent. Generally, the hardenable resin composition should harden after being introduced into fracture or fractures that are formed. The hardening may be caused by heat from the formation or by inclusion of a delayed internal hardening agent in the hardenable resin composition. It is within the ability of one of ordinary skill in the art to determine, with the benefit of this disclosure, the appropriate hardenable resin composition for a particular application.

The proppant may be coated with the hardenable resin composition by any suitable technique; such as by batch mixing methods as the hardenable resin composition is metered directly into the proppant slurry or by coating the hardenable resin composition directly onto the dry proppant through use of auger action. In some embodiments, the fracturing fluid containing proppant coated with the hardenable resin composition may be prepared in a substantially continuous, on the fly, manner.

After proppant coated with the hardenable resin composition has been deposited within the subterranean formation, the hardenable resin composition may be caused to harden as described above, whereby the proppant is consolidated into a hard permeable mass in the fracture or fractures. The hard, permeable mass functions to prevent the production of formation particulates that may migrate with produced fluids

According to the methods of the present invention, after placement of the gelable liquid composition (or the after-flush fluid where used), the subterranean formation may be shut in for a period of time to allow the gelable liquid composition present in the subterranean formation to form the desired gelled substance therein, inter alia, to stabilize unconsolidated zones of the subterranean formation. The necessary period of time is dependent, among other things, on the composition of the gelable liquid composition used and the temperature of the formation. Generally, the chosen period of time will be between about 0.5 hours and about 72 hours, or longer. In certain embodiments, the fracturing treatment, discussed above, may be performed after the shut in period so that the fractures may be created through the gelled substance. Determining the proper period of time to shut in the formation is within the ability of one skilled in the art with the benefit of this disclosure.

To facilitate a better understanding of the present invention, the following examples of preferred embodiments are given. In no way should the following examples be read to limit, or to define the scope of the invention.

EXAMPLE 1

Tests were conducted using various treatment fluids and a simulated unconsolidated sand core. Brazos River sand was used to simulate a high permeability, unconsolidated formation material. An unconsolidated sand core was prepared by using a 1-inch ID Teflon sleeve. A stainless steel, 80-mesh wire screen was first installed at the bottom of the sleeve before packing 1-inch height of 40/60-mesh Ottawa sand at the bottom of the sleeve, 2.5-inch height of Brazos River sand in the middle, and 1-inch height of 40/60-mesh Ottawa sand at the top of the sleeve.

Treatment fluids were prepared using various concentrations of “PermSeal®” sealant, which comprises a water-soluble polymerizable organic monomer of the present invention and is commercially available from Halliburton Energy Services, Duncan, Okla. The water-soluble polymerizable monomer present in PermSeal® sealant is hydroxyethylacrylate. The concentrations of the water-soluble polymerizable organic monomer present in the treatment fluids range from about 5% to about 20% by volume of the treatment fluid.

The following procedure was used for this series of tests. For each test, the unconsolidated sand core was first pre-flushed and saturated with 2 pore volumes of 2% KCl brine containing 0.25% cationic surfactant at a flow rate of 1 mL/min. Following the pre-flush, a treatment fluid was injected into the core at a flow rate of 1 mL/min. After injection of the treatment fluid into the treated core, an after-flush fluid was injected into the treated core. Next, the treated core was placed inside an oven at 175° F. for 20 hours to allow the monomer to fully polymerize. This polymerization time simulated the shut-in time of a well after being treated with a gelable liquid composition. After the polymerization time, kerosene was injected into the treated core to determine the retained permeability of the treated core. The treated core was then removed from the Teflon sleeve for observation. The above procedure was repeated for a second series of tests where no after-flush fluid was injected into the treated core before the treated core was placed inside the oven. The results of these tests are provided below in Table 1.

TABLE 1
Retained
Treatment After- Permeability Appearance of Treated
Volume % Fluid Hush of Treated Core after
Monomer Volume Volume Core (%) Polymerization Time
20 4 pore 0 plugged rubbery and pliable
volumes
20 1 pore 2 pore   94% rubbery and pliable
volume volumes
10 2 pore 0 plugged rubbery and pliable
volumes
10 1 pore 2 pore   86% rubbery and less pliable
volume volumes
5 2 pore 0 plugged formed, slightly pliable
volumes
5 1 pore 2 pore    100% formed, slightly pliable
volume volumes

This example indicates, inter alia, that a gelable liquid composition of the present invention may completely plug the permeability of an unconsolidated sand core and introduction of an after-flush fluid after the gelable liquid composition should restore permeability to such unconsolidated sand core.

EXAMPLE 2

Brazos River sand with mesh sizes smaller than 200 mesh was used to simulate formation fines. A transparent acrylic tube (8 inches long and 1 inch inside diameter) was used for ease of observation during flow test. A unconsolidated sand core was created in the tube by placing a mixture of Brazos River sand (9 grams) and 20/40-mesh Ottawa sand (6 grams) between 100 grams of 20/40-mesh Ottawa sand on top and 20 grams of 40/60-mesh Ottawa sand at the bottom.

Treatment fluids were prepared using various concentrations of “PermSeal®” sealant, wherein the PermSeal® sealant comprises a water-soluble polymerizable organic monomer. The concentrations of the water-soluble polymerizable organic monomer present in the treatment fluids ranges from about 5% to about 10% by volume of the treatment fluid.

The following procedure was used for this series of tests. For test 1, an unconsolidated sand core constructed as described above was first pre-flushed from top down and saturated with 120 mL of kerosene at a flow rate of 10 mL/min. Following the kerosene pre-flush, a treatment fluid comprising PermSeal® was injected into the core at a flow rate of 10 mL/min. After injection of the treatment fluid, an after-flush of kerosene was injected into the treated core. Next, the treated core was let sit at room temperature for 20 hours to allow the monomer to fully gel. After the gel time, kerosene was again injected into the treated core, this time in the reverse direction at increasing increment flow rates, starting from 10 mL/min, to simulate the effect of production flow rates and to help determine if the treatment fluid nas stabilized the Brazos River sand fines and caused them to remain intact without migrating and producing out along with the production fluid. It was found that Brazos River sand remained in place without producing out of the sand pack, even at production rate of 80 mL/min.

For test 2, an unconsolidated sand core constructed as described above was first pre-flushed from top down and saturated with 120 mL of 2% KCl brine containing 0.25% cationic surfactant at a flow rate of 2 mL/min. Following the brine pre-flush, a treatment fluid of PermSeal® was injected into the core at a flow rate of 2 mL/min. After injection of the treatment fluid, an after-flush of 2% KCl brine was injected into the treated core. Next, the treated core was let sit at room temperature for 20 hours to allow the monomer to fully gel. After the gel time, kerosene was injected into the treated core in the reverse direction at increasing increment flow rates, starting from 10 mL/min, to simulate the effect of production flow rates and to help determine if the treatment fluid has stabilized the Brazos River sand fines and caused them to remain intact without migrating and producing out along with the production fluid. Similar to the results obtained in test 1, it was found that Brazos River sand remained in place without producing out of the sand pack, even at a production rate as high as 80 mL/min.

Thus, this example displays the ability of the gelled substances of the present invention to stabilize unconsolidated formation sand and to prevent formation fines from migrating or producing with production fluids.

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
US7934557 *Feb 15, 2007May 3, 2011Halliburton Energy Services, Inc.Methods of completing wells for controlling water and particulate production
US8215393Oct 6, 2009Jul 10, 2012Schlumberger Technology CorporationMethod for treating well bore within a subterranean formation
US8813842Dec 21, 2009Aug 26, 20143M Innovative Properties CompanyParticles comprising blocked isocyanate resin and method of modifying a wellbore using the same
US20100256024 *Jul 15, 2008Oct 7, 2010Trican Well Service Ltd.Resin coated proppant slurry compositions and methods of making and using same
US20130105167 *Oct 27, 2011May 2, 2013Lewis R. NormanNovel Method for Enhancing Fracture Conductivity
EP2302164A1 *Nov 21, 2006Mar 30, 2011Halliburton Energy Services, Inc.Methods of stabilizing unconsolidated subterranean formation
WO2007060407A2 *Nov 21, 2006May 31, 2007Halliburton Energy Serv IncMethods of stabilizing unconsolidated subterranean formations
Classifications
U.S. Classification166/280.2, 166/295, 507/226, 507/222, 166/280.1, 507/903, 507/224, 507/267, 507/219, 507/225, 507/269, 166/300, 507/216, 166/281
International ClassificationC09K8/62, C09K8/50
Cooperative ClassificationC09K8/62, C09K8/50
European ClassificationC09K8/62, C09K8/50
Legal Events
DateCodeEventDescription
Mar 5, 2004ASAssignment
Owner name: HALLIBURTON ENERGY SERVICES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:NGUYEN, PHILIP D.;BARTON, JOHNNY A.;BROWN, DAVID;REEL/FRAME:015051/0936
Effective date: 20040304