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Publication numberUS20040023816 A1
Publication typeApplication
Application numberUS 10/211,984
Publication dateFeb 5, 2004
Filing dateAug 1, 2002
Priority dateAug 1, 2002
Publication number10211984, 211984, US 2004/0023816 A1, US 2004/023816 A1, US 20040023816 A1, US 20040023816A1, US 2004023816 A1, US 2004023816A1, US-A1-20040023816, US-A1-2004023816, US2004/0023816A1, US2004/023816A1, US20040023816 A1, US20040023816A1, US2004023816 A1, US2004023816A1
InventorsBoyce Burts
Original AssigneeBurts Boyce Donald
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Hydraulic fracturing additive, hydraulic fracturing treatment fluid made therefrom, and method of hydraulically fracturing a subterranean formation
US 20040023816 A1
Abstract
For hydraulic fracturing treatment to increase productivity of subterranean hydrocarbon bearing formation, a hydraulic fracturing additive including a dry mixture of water soluble crosslinkable polymer, a crosslinking agent, and a filter aid which is preferably diatomaceous earth. The method of forming a hydraulic fracturing fluid includes contacting the additive with water or an aqueous solution, with a method of hydraulically fracturing the formation further including the step of injecting the fluid into the wellbore.
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Claims(63)
I claim:
1. A hydraulic fracturing additive comprising a dry mixture of water soluble crosslinkable polymer, a crosslinking agent, and a filter aid.
2. The additive of claim 1, wherein the filter aid is selected from the group consisting of diatomaceous earth, perlite, glass beads, magnesium silicate, solid thermoplastic or thermoset polymer beads, talc, and calcium silicate.
3. The additive of claim 2, wherein the polymer is an a carboxylate-containing polymer, and the crosslinking agent is selected from the group consisting of chromium (III) carboxylate complexes, aldehydes, dialdehydes, formaldehydes, glutaraldehyde, dichromates, titanium chelates, phenols, substituted phenols, ethers, aluminum citrate, and aluminates.
4. The additive of claim 3, wherein the filter aid comprises at least one of diatomaceous earth or pearlite.
5. The additive of claim 4, wherein the polymer comprises a low molecular weight polymer having a molecular weight less than 500,000, and a high molecular weight polymer having a molecular weight of at least 500,000.
6. The additive of claim 4, wherein the polymer is a water soluble, carboxylate containing acrylamide, and the crosslinking agent is a chromium (III) carboxylate complex.
7. The additive of claim 6, wherein the filter aid is diatomaceous earth.
8. The additive of claim 6, wherein the filter aid is pearlite.
9. The additive of claim 6, further comprising reinforcing material selected from the group consisting of hydrophilic fibers, hydrophobic fibers, and comminuted plant material.
10. A well fluid comprising a hydraulic fracturing fluid, water soluble crosslinkable polymer, a crosslinking agent, and a filter aid.
11. The well fluid of claim 10, wherein the filter aid is selected from the group consisting of diatomaceous earth, perlite, glass beads, magnesium silicate, solid thermoplastic or thermoset polymer beads, talc, and calcium silicate.
12. The well fluid of claim 11, wherein the polymer is an a carboxylate-containing polymer, and the crosslinking agent is selected from the group consisting of chromium (III) carboxylate complexes, aldehydes, dialdehydes, formaldehydes, glutaraldehyde, dichromates, titanium chelates, phenols, substituted phenols, ethers, aluminum citrate, and aluminates.
13. The well fluid of claim 12, wherein the filter aid comprises at least one of diatomaceous earth or pearlite.
14. The well fluid of claim 13, wherein the polymer comprises a low molecular weight polymer having a molecular weight less than 500,000, and a high molecular weight polymer having a molecular weight of at least 500,000.
15. The well fluid of claim 13, wherein the polymer is a water soluble, carboxylate containing acrylamide, and the crosslinking agent is a chromium (III) carboxylate complex.
16. The well fluid of claim 15, wherein the filter aid is diatomaceous earth.
17. The well fluid of claim 15, wherein the filter aid is pearlite.
18. The well fluid of claim 15, further comprising reinforcing material selected from the group consisting of hydrophilic fibers, hydrophobic fibers, and comminuted plant material.
19. A method of modifying a hydraulic fracturing fluid comprising:
(a) contacting the hydraulic fracturing fluid with a water soluble crosslinkable polymer, crosslinking agent, and filter aid to form a modified hydraulic fracturing fluid.
20. The method of claim 19, wherein the filter aid is selected from the group consisting of diatomaceous earth, perlite, glass beads, magnesium silicate, solid thermoplastic or thermoset polymer beads, talc, and calcium silicate.
21. The method of claim 20, wherein the polymer is an a carboxylate-containing polymer, and the crosslinking agent is selected from the group consisting of chromium (III) carboxylate complexes, aldehydes, dialdehydes, formaldehydes, glutaraldehyde, dichromates, titanium chelates, phenols, substituted phenols, ethers, aluminum citrate, and aluminates.
22. The method of claim 21, wherein the filter aid comprises at least one of diatomaceous earth or pearlite.
23. The method of claim 22, wherein the polymer comprises a low molecular weight polymer having a molecular weight less than 1,000,000, and a high molecular weight polymer having a molecular weight of at least 1,000,000.
24. The method of claim 22, wherein the polymer is a water soluble, carboxylate containing acrylamide, and the crosslinking agent is a chromium (III) carboxylate complex.
25. The method of claim 24, wherein the filter aid is diatomaceous earth.
26. The method of claim 24, wherein the filter aid is pearlite.
27. The method of claim 19, wherein the water soluble crosslinkable polymer, crosslinking agent, and filter aid, are all in solid form.
28. A method for hydraulically fracturing a subterranean hydrocarbon bearing formation below an earthen surface in fluid communication with a wellbore comprising:
(a) providing a hydraulic fracturing fluid comprising water soluble crosslinkable polymer, a crosslinking agent, and filter aid; and
(b) injecting the hydraulic fracturing fluid into said formation via said wellbore at a pressure sufficient to hydraulically fracture said formation.
29. The method of claim 28, wherein the filter aid is selected from the group consisting of diatomaceous earth, perlite, glass beads, magnesium silicate, solid thermoplastic or thermoset polymer beads, talc, and calcium silicate.
30. The method of claim 29, wherein the polymer is an a carboxylate-containing polymer, and the crosslinking agent is selected from the group consisting of chromium (III) carboxylate complexes, aldehydes, dialdehydes, formaldehydes, glutaraldehyde, dichromates, titanium chelates, phenols, substituted phenols, ethers, aluminum citrate, and aluminates.
31. The method of claim 30, wherein the filter aid comprises at least one of diatomaceous earth or pearlite.
32. The method of claim 31, wherein the polymer comprises a low molecular weight polymer having a molecular weight less than 500,000, and a high molecular weight polymer having a molecular weight of at least 500,000.
33. The method of claim 31, wherein the polymer is a water soluble, carboxylate containing acrylamide, and the crosslinking agent is a chromium (III) carboxylate complex.
34. The method of claim 33, wherein the filter aid is diatomaceous earth.
35. The method of claim 33, wherein the filter aid is pearlite.
36. The method of claim 33, further comprising reinforcing material selected from the group consisting of hydrophilic fibers, hydrophobic fibers, and comminuted plant material.
37. A method for hydraulically fracturing a subterranean hydrocarbon bearing formation below an earthen surface in fluid communication with a wellbore comprising:
(a) providing a hydraulic fracturing additive comprising a dry mixture of water soluble crosslinkable polymer, a crosslinking agent, and filter aid;
(b) contacting the hydraulic fracturing additive with water or an aqueous solution to form a hydraulic fracturing fluid; and
(c) injecting the hydraulic fracturing fluid into said formation via said wellbore at a pressure sufficient to hydraulically fracture said formation.
38. The method of claim 37, wherein the filter aid is selected from the group consisting of diatomaceous earth, perlite, glass beads, magnesium silicate, solid thermoplastic or thermoset polymer beads, talc, and calcium silicate.
39. The method of claim 38, wherein the polymer is an a carboxylate-containing polymer, and the crosslinking agent is selected from the group consisting of chromium (III) carboxylate complexes, aldehydes, dialdehydes, formaldehydes, glutaraldehyde, dichromates, titanium chelates, phenols, substituted phenols, ethers, aluminum citrate, and aluminates.
40. The method of claim 39, wherein the filter aid comprises at least one of diatomaceous earth or pearlite.
41. The method of claim 40, wherein the polymer comprises a low molecular weight polymer having a molecular weight less than 500,000, and a high molecular weight polymer having a molecular weight of at least 500,000.
42. The method of claim 40, wherein the polymer is a water soluble, carboxylate containing acrylamide, and the crosslinking agent is a chromium (III) carboxylate complex.
43. The method of claim 42, wherein the filter aid is diatomaceous earth.
44. The method of claim 42, wherein the filter aid is pearlite.
45. The method of claim 42, further comprising reinforcing material selected from the group consisting of hydrophilic fibers, hydrophobic fibers, and comminuted plant material.
46. A method of circulating a hydraulic fracturing fluid in a welbore penetrating a subterranean formation, comprising:
(a) providing a hydraulic fracturing fluid comprising water or an aqueous solution, water soluble crosslinkable polymer, a crosslinking agent, and a filter aid;
(b) circulating the hydraulic fracturing fluid in the wellbore.
47. The method of claim 46, wherein the filter aid is selected from the group consisting of diatomaceous earth, perlite, glass beads, magnesium silicate, solid thermoplastic or thermoset polymer beads, talc, and calcium silicate.
48. The method of claim 47, wherein the polymer is an a carboxylate-containing polymer, and the crosslinking agent is selected from the group consisting of chromium (III) carboxylate complexes, aldehydes, dialdehydes, formaldehydes, glutaraldehyde, dichromates, titanium chelates, phenols, substituted phenols, ethers, aluminum citrate, and aluminates.
49. The method of claim 48, wherein the filter aid comprises at least one of diatomaceous earth or pearlite.
50. The method of claim 49, wherein the polymer comprises a low molecular weight polymer having a molecular weight less than 500,000, and a high molecular weight polymer having a molecular weight of at least 500,000.
51. The method of claim 49, wherein the polymer is a water soluble, carboxylate containing acrylamide, and the crosslinking agent is a chromium (III) carboxylate complex.
52. The method of claim 51, wherein the filter aid is diatomaceous earth.
53. The method of claim 51, wherein the filter aid is pearlite.
54. The method of claim 51, further comprising reinforcing material selected from the group consisting of hydrophilic fibers, hydrophobic fibers, and comminuted plant material.
55. A method of modifying a hydraulic fracturing fluid circulating in a wellbore penetrating a subterranean formation, comprising:
(a) introducing a water soluble crosslinkable polymer, crosslinking agent, and filter aid to the circulating hydraulic fracturing fluid.
56. The method of claim 55, wherein the filter aid is selected from the group consisting of diatomaceous earth, perlite, glass beads, magnesium silicate, solid thermoplastic or thermoset polymer beads, talc, and calcium silicate.
57. The method of claim 56, wherein the polymer is an a carboxylate-containing polymer, and the crosslinking agent is selected from the group consisting of chromium (III) carboxylate complexes, aldehydes, dialdehydes, formaldehydes, glutaraldehyde, dichromates, titanium chelates, phenols, substituted phenols, ethers, aluminum citrate, and aluminates.
58. The method of claim 57, wherein the filter aid comprises at least one of diatomaceous earth or pearlite.
59. The method of claim 58, wherein the polymer comprises a low molecular weight polymer having a molecular weight less than 500,000, and a high molecular weight polymer having a molecular weight of at least 500,000.
60. The method of claim 58, wherein the polymer is a water soluble, carboxylate containing acrylamide, and the crosslinking agent is a chromium (III) carboxylate complex.
61. The method of claim 60, wherein the filter aid is diatomaceous earth.
62. The method of claim 60, wherein the filter aid is pearlite.
63. The method of claim 55, wherein the water soluble crosslinkable polymer, crosslinking agent, and filter aid, are all in solid form.
Description
BACKGROUND OF THE INVENTION

[0001] 1. Field of the Invention

[0002] The present invention relates to hydraulic fracturing additives and to methods of making such additives, to hydraulic fracturing treatment fluids made therefrom and methods of making such fluids, to methods of modifying a well fluid with such additives and/or fluids, to methods of operating a well with such additives and/or fluids, to methods of hydraulically fracturing a well with such additives and/or fluids. In another aspect, the present invention relates to hydraulic fracturing additives comprising polymer, crosslinking agent, a filter aid, and optionally reinforcing materials and to methods of making such additives, to hydraulic fracturing treatment fluids made therefrom and methods of making such fluids, to methods of modifying a well fluid with such additives and/or fluids, to methods of operating a well with such additives and/or fluids, to methods of hydraulically fracturing a well with such additives and/or fluids. In even another aspect, the present invention relates to hydraulic fracturing additives comprising a dry mixture of polymer, crosslinking agent, a filter aid, and optionally reinforcing materials and to methods of making such additives, to hydraulic fracturing treatment fluids made therefrom and methods of making such fluids, to methods of modifying a well fluid with such additives and/or fluids, to methods of operating a well with such additives and/or fluids, to methods of hydraulically fracturing a well with such additives and/or fluids. In still another aspect, the present invention relates to hydraulic fracturing fracturing additives comprising polymer and diatomaceous earth (“DE”) and to methods of making such additives, to hydraulic fracturing treatment fluids made therefrom and methods of making such fluids, to methods of modifying a well fluid with such additives and/or fluids, to methods of operating a well with such additives and/or fluids, to methods of hydraulically fracturing a well with such additives and/or fluids.

[0003] 2. Description of the Related Art

[0004] The productivity or injectivity of a wellbore in fluid communication with a subterranean hydrocarbon-bearing formation may be undesirably low due to a number of causes, including low permeability of the formation rock, placement of casing cement, plugging by previously injected materials, clay damage, or produced fluid damage. Productivity or injectivity may be increased by hydraulically fracturing the formation.

[0005] Hydraulic fracturing generally entails injecting a fluid into the wellbore at a sufficient rate and pressure to overcome the tensile strength of the formation and the overburden pressure. The injected fluid creates cracks or fractures extending from the wellbore out into the formation which are usually propped open with a solid proppant entrained in the fluid. The fractures permit the flow of hydrocarbons and other fluids into or out of the wellbore.

[0006] U.S. Pat. No. 3,816,151 to Podlas, U.S. Pat. No. 3,938,594 to Rhudy et al and U.S. Pat. No. 4,137,182 to Golinkin disclose hydraulic fracturing processes using a number of crosslinked polymer solutions as fracturing fluids.

[0007] U.S. Pat. No. 4,779,680, issued Oct. 25, 1988 to Sydansk, notes that many of the then prior art crosslinking reactions prescribed were very difficult to control. Sydansk further notes that uncontrolled crosslinking can occur too rapidly, producing a non-homogeneous suspension of highly viscous gel balls in a watery solution, or in the other extreme crosslinking can fail to occur at all. In either case, the result is an ineffective fracturing fluid.

[0008] Sydansk even further notes that at that time, a process is needed for hydraulically fracturing a subterranean hydrocarbon-bearing formation with a stable homogeneous viscous fracturing fluid having satisfactory performance properties to meet the demands of the fracture treatment.

[0009] As a solution to the deficiencies and needs of the prior art, Sydansk, discloses the use of a water soluble carboxylate crosslinking polymer along with a chromic carboxylate complex crosslinking agent as a lost circulation material.

[0010] While U.S. Pat. No. 5,377,760, issued Jan. 3, 1995 to Merrill discloses addition of fibers to an aqueous solution of partially hydrolyzed polyacrylamide polymer, with subsequent injection into the subterranean to improve conformance, the requirements of a hydraulic fracturing fluid are so different from a conformance fluid, that such would not necessarily work for hydraulic fracturing treatment.

[0011] Additionally, Merrill's conformance treatment method of mixing the fibers with the polymer solution followed by injection, requires a multiplicity of storage and mixing tanks, and a metering system which must be operated during the operation of the well. Specifically, a first tank will store a water and polymer solution, a second tank will store a water and cross-linking solution, and a third tank will be used to mix fibers with polymer solution from the first tank to create a polymer/fiber slurry. This polymer/fiber slurry is then metered from the third tank and combined with cross-linking solution metered from the second tank to the well bore.

[0012] As an advance over the above prior art, U.S. Pat. No. 6,016,871, issued Jan. 25, 2000, to Boyce D. Burts, Jr., for “Hydraulic fracturing additive, hydraulic fracturing treatment fluid made therefrom, and method of hydraulically fracturing a subterranean formation,” discloses an additive including a dry mixture of water soluble crosslinkable polymer, a crosslinking agent, and a reinforcing material of fibers and/or comminuted plant materials. The method of forming a fluid includes contacting the additive with water or an aqueous solution, with a method of treating the formation further including the step of injecting the fluid into the formation.

[0013] While not believed to be related prior art because they relate to different types of well operations, for completeness, attention is directed to five other similar “dry mixture” patents by Boyce D. Burts, Jr., which were filed on the same day (Oct. 31, 1997) as the '871 patent: U.S. Pat. No. 6,218,343, issued Apr. 17, 2001, for “Additive for, treatment fluid for, and method of plugging a tubing/casing annulus in a well bore,” U.S. Pat. No. 6,102,121, issued Aug. 15, 2000, for “Conformance improvement additive, conformance treatment fluid made therefrom, method of improving conformance in a subterranean formation,” U.S. Pat. No. 6,098,712, issued Aug. 8, 2000, for “Method of plugging a well,” U.S. Pat. No. 6,016,879, issued Jan. 25, 2000, for “Lost circulation additive, lost circulation treatment fluid made therefrom, and method of minimizing lost circulation in a subterranean formation,” and U.S. Pat. No. 6,016,869, issued Jan. 25, 2000, for “Well kill additive, well kill treatment fluid made therefrom, and method of killing a well.”

[0014] A number of patents discuss the use of diatomaceous earth (“DE”) in a well operation.

[0015] U.S. Pat. No. 3,380,542, issued Apr. 30, 1968 to Clear, for restoring lost circulation discloses a oil-based drilling fluid, containing a slurry of diatomite and asbestos, used to restore lost circulation during well drilling operations.

[0016] U.S. Pat. No. 4,369,844, issued Jan. 25, 1983 to Clear, discloses that various formation sealing agents have been used in the art to form formation seals and/or filter cakes on the wall of a well bore, including diatomaceous earth.

[0017] U.S. Pat. No. 4,110,225, issued Aug. 29, 1978 to Cagle, discloses that zones of lost circulation and other undesired fluid communication channels into a wellbore are sealed by isolating a volume in the well including such a zone and applying greater than formation pressure to a novel slurry spotted in the zone until it hardens into a solid, drillable seal. The slurry contains per barrel from 5-50 pounds diatomaceous mix, from about 35 to about 350 pounds of oil well cement, and at a minimum about 5 to 6 pounds of a flake type lost-circulation agent. This '225 patent cites a number of patents that disclose cement/diatomaceous earth compositions, including U.S. Pat. Nos. 2,585,336; 2,793,957; 2,961,044; 3,467,198; and 3,558,335.

[0018] Regarding these patents, the '225 patent notes the following:

[0019] Regarding U.S. Pat. No. 2,585,336, the '225 patent notes, “a mixture is made using from 2% to 100% diatomaceous earth, compared to the content of the cement in the slurry. The aim of the inventors was to prevent perlite from settling and to produce a lightweight cement. The diatomaceous earth-cement described in the disclosure is a mixture of Portland cement, perlite and diatomaceous earth, lime, and asbestos fibers.”

[0020] Regarding U.S. Pat. No. 2,793,957, the '225 patent notes, “refers to a highly permeable cement formed by use of the same basic mixtures of diatomaceous earth with Portland cement, the diatomaceous earth present being from five to seven times the proportion of the Portland cement in the slurry. The aim of the inventors was to produce a light highly permeable cement, entirely opposite to the purpose of my invention.”

[0021] Regarding U.S. Pat. No. 2,961,044, the '225 patent notes, “discusses and claims a cement composition which has diatomaceous earth in the amounts of from 30% to 70% of the Portland cement. The reason for using the diatomaceous earth was to prevent the strength retrogression of a salt-saturated cement. Thus, while Shell wishes (among other uses) to employ his mixture for squeeze cementing, he produces a relatively high-strength cement plug. There is a real tendency when redrilling such a plug for the bit to be deflected or sidetracked so that the new hole is beside rather than through the bore and the seal is ineffective. This is completely different from my invention which minimizes such tendency by producing a plug at least as drillable as the formation in which it is set. Also, Shell is directed to operations using salt-saturated cement slurries, while I prefer using a fresh or brackish water slurry. I employ lost-circulation agents; he makes no teaching of using such additives. Accordingly, his teaching is quite far from mine.”

[0022] Regarding both U.S. Pat. Nos. 3,467,198 and 3,558,335, the '225 patent notes, “describe cement compositions having diatomaceous mix present in the amounts from 0.5% to 10% of the amount of Portland cement present to prevent solids-settling.”

[0023] U.S. Pat. No. 4,369,844, issued Jan. 25, 1983 to Clear, discloses slurries to seal permeable earth formations encountered in the drilling of wells, comprising finely divided paper, diatomaceous earth, and in a further embodiment, lime. A slug of the slurry is spotted at the locus of the permeable formation and defluidized to form a formation seal on which a mud sheath is then deposited.

[0024] U.S. Pat. No. 4,505,751, issued Mar. 19, 1985, discloses a silicate/silica cement in oil field applications, including diatomaceous earth as a species of silica compound.

[0025] While not believed to be analogous prior art because it relates to earthen pits (for example a ditch) and not to subterrean wellbores nor well operations, U.S. Pat. No. 5,947,644, issued Sep. 7, 1999 to Gibbons et al., is included herein for completeness because it discloses a gelable slurry of aqueous solvent, a crosslinkable polymer, a crosslinking agent, and unconsolidated solids such as diatomaceous earth. This gelable slurry is placed in an earthen pit and allowed to form into a fluid impermeable barrier wall in the earthen pit. The polymer serves to bind the unconsolidated solids to convert the gelable slurry to a nondeformable gelled continuum of consolidated solids, which forms the barrier wall in the earthen pit. As disclosed in the '644 patent in the Summary of the Invention section, at col. 1, lines 57-67, this gelable slurry is prepared by first forming a liquid gelation solution of the polymer and crosslinking agent, to which is subsequently mixed with the unconsolidated solids, or alternatively, by sequentially mixing the aqueous solvent, crosslinkable polymer, and polymer crosslinking agent with the unconsolidated solids.

[0026] Thus, in spite of the advancements in the prior art, there still need for further innovation in the hydraulic fracturing additives.

[0027] There is need for further innovation for hydraulic fracturing additives utilizing a water soluble polymer.

[0028] There is another need for a hydraulic fracturing additive which would allow for simplification of the mixing equipment.

[0029] These and other needs in the art will become apparent to those of skill in the art upon review of this specification, including its drawings and claims.

SUMMARY OF THE INVENTION

[0030] It is an object of the present invention to provide for further innovation in hydraulic fracturing additives.

[0031] It is an another object of the present invention to provide for further innovation for hydraulic fracturing additives utilizing a water soluble polymer.

[0032] It is even another object of the present invention to provide for a hydraulic fracturing additive which would allow for simplification of the mixing equipment.

[0033] These and other objects of the present invention will become apparent to those of skill in the art upon review of this specification, including its drawings and claims.

[0034] According to one embodiment of the present invention, there is provided a hydraulic fracturing additive comprising a dry mixture of water soluble crosslinkable polymer, a crosslinking agent, and a filter aid.

[0035] According to another embodiment of the present invention, there is provided a well fluid comprising a hydraulic fracturing fluid, water soluble crosslinkable polymer, a crosslinking agent, and a filter aid.

[0036] According to even another embodiment of the present invention, there is provided a method of modifying a hydraulic fracturing fluid. The method includes contacting the hydraulic fracturing fluid with a water soluble crosslinkable polymer, crosslinking agent, and filter aid to form a modified hydraulic fracturing fluid.

[0037] According to still another embodiment of the present invention, there is provided a method for hydraulically fracturing a subterranean hydrocarbon bearing formation below an earthen surface in fluid communication with a wellbore. The method includes providing a hydraulic fracturing fluid comprising water soluble crosslinkable polymer, a crosslinking agent, and filter aid. The method also includes injecting the hydraulic fracturing fluid into said formation via said wellbore at a pressure sufficient to hydraulically fracture said formation.

[0038] According to yet another embodiment of the present invention, there is provided a method for hydraulically fracturing a subterranean hydrocarbon bearing formation below an earthen surface in fluid communication with a wellbore. The method includes providing a hydraulic fracturing additive comprising a dry mixture of water soluble crosslinkable polymer, a crosslinking agent, and filter aid. The method also includes contacting the hydraulic fracturing additive with water or an aqueous solution to form a hydraulic fracturing fluid. The method also includes injecting the hydraulic fracturing fluid into said formation via said wellbore at a pressure sufficient to hydraulically fracture said formation.

[0039] According to even still another embodiment of the present invention, there is provided a method of circulating a hydraulic fracturing fluid in a welbore penetrating a subterranean formation. The method includes providing a hydraulic fracturing fluid comprising water or an aqueous solution, water soluble crosslinkable polymer, a crosslinking agent, and a filter aid. The method also includes circulating the hydraulic fracturing fluid in the wellbore.

[0040] According to even yet another embodiment of the present invention, there is provided a method of modifying a hydraulic fracturing fluid circulating in a wellbore penetrating a subterranean formation. The method includes introducing a water soluble crosslinkable polymer, crosslinking agent, and filter aid to the circulating hydraulic fracturing fluid.

[0041] Various further embodiments of any or all of the above embodiments include any or all of the following in any combination: the filter aid is selected from the group consisting of diatomaceous earth, perlite, glass beads, magnesium silicate, solid thermoplastic or thermoset polymer beads, talc, and calcium silicate; or the polymer is an a carboxylate-containing polymer, and the crosslinking agent is selected from the group consisting of chromium (III) carboxylate complexes, aldehydes, dialdehydes, formaldehydes, glutaraldehyde, dichromates, titanium chelates, phenols, substituted phenols, ethers, aluminum citrate, and aluminates; the filter aid comprises at least one of diatomaceous earth or pearlite; the polymer comprises a low molecular weight polymer having a molecular weight less than 500,000, and a high molecular weight polymer having a molecular weight of at least 500,000; the polymer is a water soluble, carboxylate containing acrylamide, and the crosslinking agent is a chromium (III) carboxylate complex; the filter aid is diatomaceous earth; the filter aid is pearlite; the reinforcing material selected from the group consisting of hydrophilic fibers, hydrophobic fibers, and comminuted plant material; and/or various weight percentages are in the range of about 4 to about 35 weight percent polymer, in the range of about 1 to about 10 weight percent cross linking agent, and in the range of about 55 to about 95 weight percent filter aid, based on the total weight of the polymer, cross linking agent and filter aid.

[0042] These and other embodiments of the present invention will become apparent to those of skill in the art upon review of this specification and claims.

DETAILED DESCRIPTION OF THE INVENTION

[0043] The hydraulic fracturing additive of the present invention includes polymer, cross-linking agent, filter aid, and optionally a reinforcing material, preferably either fibers or comminuted particles of plant materials, and optionally any other materials that are known in the art. It is to be understood that the hydraulic fracturing additive of the present invention may be in the form of a dry mixture or a slurry. In a preferred embodiment of the present invention, the hydraulic fracturing additive is a dry mixture.

[0044] A well fluid of the present invention includes well fluid components plus the additive of the present invention, and optionally conventional proppants as are known in the art.

[0045] Any suitable relative amounts of the polymer, cross-linking agent, filter aid and the optional reinforcing materials may be utilized in the present invention provided that the desired hydraulic fracturing results are achieved. Generally, the relative amounts of each will be determined based on the particular application to which the additive is to be subjected. A suitable amount of crosslinking agent is provided to reach the desired amount of crosslinking. The amount of reinforcing material is selected to provide desired physical properties.

[0046] Any suitable types of filter aid materials as are known in the filtration art may be utilized as the filter aid component in the present invention. All that is necessary is that the filter aid will function to be “squeezed” and allow migration of the solution of polymer and crosslinking agent into the formation, and will form a plug of the filter aid that will hold the solution in place until it sufficiently crosslinks. Non-limiting examples of which include diatomaceous earth (“DE” or diatomite), perlite (or pearlite), glass beads, magnesium silicate, solid thermoplastic or thermoset polymers generally in powder form, talc (naturally occuring form of hydrous magnesium silicate containing varying proportions of such associated minerals as alpha-quartz, calcite, chlorite, dolomite, kaolin, magnesite, and phlogopite), and calcium silicate (for example, see, U.S. Pat. No. 5,750,038, issued May 12, 1998, to Tsunematsu, for “Method for the preparation of acid-resistant calcium silicate,” incorporate herein by reference). Preferably, the filter aid is selected from the group consisting of diatomaceous earth perlite (or pearlite), magnesium silicate, and talc. More preferably, the filter aid is a mineral based type of filter aid, non-limiting examples of which include diatomaceous earth, pearlite, magnesium silicate, talc and calcium silicate. Even more preferably, the filter aid comprises pearlite and/or diatomaceous earth. Still more preferably, the filter aid comprises diatomaceous earth.

[0047] The amount of filter aid to be utilized is generally not dependent upon the amount of polymer or crosslinking agent, but rather, is that amount sufficient to form a plug to retain the polymer in place until it crosslinks sufficiently to remain in place on its own. However, in an effort to quantify the amount of filter aid, a weight ratio of filter aid to polymer is provided for convenience.

[0048] Generally, the weight ratio of filter aid:polymer in the additive is in the range of about 100:1 to about 1:100, preferably in the range of about 50:1 to about 1:50, more preferably in the range of about 15:1 to about 1:15, even more preferably in the range of about 5:1 to about 1:5, and still more preferably in the range of about 5:1 to about 1:1.

[0049] Commercially, it is envisioned that the additive will be packaged in a single bag, to promote ease of use and eliminate the necessity of any measuring and/or mixing at the well site. As a non-limiting example of a commercial embodiment, a 40 pound bag might contain any where from about 1.5 to about 17.5 lbs. polymer, from about 0.4 to about 5 lbs. crosslinking agent, and the balance of from about 17.5 to about 38.1 lbs. filter aid.

[0050] In weight percentage terms, examples of weight percentage ranges include from about 4 to about 35 weight percent polymer, from about 1 to about 10 weight percent cross linking agent, and from about 55 to about 95 weight percent filter aid, based on the total weight of the polymer, cross linking agent and filter aid. Specific non-limiting examples of useful compositions include 4% polymer, 1% cross linker, 95% DE, or 24% polymer, 6% cross linker, 70% DE, or 35% polymer, 10% cross linker, 55% DE.

[0051] The particle size distribution of the filter aid is selected to allow dewatering of the filter aid (i.e., the solution containing polymer and crosslinking agent will separate from the filter aid), and to allow formation of a plug of the filter aid that retains the polymer and crosslinking agent in the reservoir during crosslinking. It is believed that the particle size distribution will be determined by the reservoir conditions.

[0052] Other additives as are known in the well fluid art may be utilized, non limiting examples of which include surfactants, dispersants, retarders, accelerants, weighting agents (such as hematite, barite or calcium carbonate), lost circulation materials and other additives may be provided as necessary or desired.

[0053] The polymer utilized in the practice of the present invention is preferably water soluble and must be capable of being pumped as a liquid and subsequently crosslinked in place to form a substantially non-flowing crosslinked polymer which has sufficient strength to withstand the pressures exerted on it. Moreover, it must have a network structure capable of incorporating reinforcing fibers.

[0054] The crosslinked polymer or “gel” resulting from the crosslinked polymer system of the present invention is a continuous three-dimensional crosslinked polymeric network, having an ultra high molecular weight, which confines the aqueous solvent component in its interstices. The polymeric network and aqueous component form a single phase system which provides the gel with its unique phase behavior.

[0055] The present gel is qualitatively defined as “flowing” because of its ability to flow into the wellbore and formation under injection pressure. Nevertheless, the gel has sufficient structure as a result of its specific crosslinking mechanism to exhibit characteristics desirable of a fracturing fluid. These characteristics include uniformity, high viscosity, shear thinning and stability during the fracture treatment as well as low fluid loss and friction loss.

[0056] The uniform viscous stable gel of the present invention is a particularly effective vehicle for propping agents, which may be employed during the fracture treatment, because the gel is advantageously susceptible to shear thinning. The gel exhibits high apparent viscosity in the wellbore tubulars during injection, but exhibits relatively low apparent viscosity when subjected to high shear as it exits the wellbore perforations and enters the induced fractures. The gel regains its high apparent viscosity as it moves at lower shear through the fractures far into the formation away from the wellbore. The shear thinning gel effectively maintains the proppant in suspension in the wellbore tubulars until the gel enters the induced fractures and again after the gel has traveled into the fractures.

[0057] The gel of the present invention is at least partially gelled upon injection into the wellbore. In a partial gel, as defined herein, the crosslinking agent has reacted incompletely with the polymer and neither all of the polymer nor all of the crosslinking agent in the gel is totally consumed by the crosslinking reaction. Although the partial gel exhibits at least some gel-like structure, it is capable of further crosslinking to completion without the addition of more crosslinking agent.

[0058] “Crosslinked to completion” means that the gel is substantially incapable of further crosslinking because one or both of the required reactants in the initial solution are substantially consumed. Further crosslinking is only possible if either polymer, crosslinking agent, or both are added to the gel. In a preferred embodiment, the gel of the present invention is crosslinked to substantial completion upon injection into the wellbore.

[0059] Complete gelation by the time the gel reaches the induced fractures is advantageous because it promotes efficient proppant transport and reduces fluid loss. Fluid loss can cause significant permeability reduction of the matrix bounding the fracture network which is counterproductive to the fracturing process. Fluid loss can also increase the fracturing fluid requirement of the treatment and cause undesirable proppant bridging in the fractures.

[0060] The polymer utilized in the practice of the present invention is preferably water soluble and must be capable of being pumped as a liquid and subsequently crosslinked in place to form a substantially non-flowing crosslinked polymer which has sufficient strength to withstand the pressures exerted on it. optionally, when reinforcing materials are utilized, it would have a network structure capable of incorporating reinforcing materials.

[0061] While any suitable water soluble polymer may be utilized, the preferred polymer utilized in the practice of the present invention is a water soluble carboxylate-containing polymer, more preferably a water soluble partially hydrolyzed carboxylate-containing polymer. This carboxylate-containing polymer may be any crosslinkable, high molecular weight, water-soluble, synthetic polymer or biopolymer containing one or more carboxylate species.

[0062] For an example of polymers and crosslinking agents suitable for use herein and details regarding their making and use, please see any of the above listed patents to Boyce D. Burts, Jr. all herein incorporated by reference, or please see U.S. Pat. Nos. 4,683,949, 4,723,605, 4,744,418, 4,770,245, 4,844,168, 4,947,935, 4,957,166 and 4,989,673, 5,377,760, 5,415,229, 5,421,411, all herein incorporated by reference.

[0063] The average molecular weight of the carboxylate-containing polymer utilized in the practice of the present invention is in the range of about 10,000 to about 50,000,000, preferably in the range of about 100,000 to about 20,000,000, more preferably in the range of about 200,000 to about 15,000,000, and still more preferably in the range of about 200,000 to about 10,000,000.

[0064] In some instances, a blend of two polymers, a lower molecular weight polymer and a higher molecular weight polymer may be utilized. For example, in some instances where high fluid loss is encountered, such as a hole in the casing, a fault zone, loose sand, unconsolidated zones, or vugular formations, higher molecular weight polymer must be utilized. However, this higher molecular weight polymer causes problems in mixing, pumping and total polymer load. Thus, this higher molecular weight polymer is mixed with a lower molecular weight polymer to provide mixing, pumping and loading as desired.

[0065] Generally, this lower molecular weight polymer has a molecular weight less than 1,000,000, preferably less than 500,000, and more preferably less than 200,000. Generally the lower molecular weight polymer will have a molecular weight in the range of about 20,000 to less than 1,000,000, preferably in the range of about 20,000 to less than 500,000, and more preferably in the range of about 200,000 to less than 500,000. The higher molecular weight polymer generally has a molecular weight of at least 1,000,000, preferably from about 1,000,000 to about 50,000,000, more preferably from about 5,000,000 to about 20,000,000, and even more preferably from about 6,000,000 to about 12,000,000.

[0066] Biopolymers useful in the present invention include polysaccharides and modified polysaccharides. Non-limiting examples of biopolymers are xanthan gum, guar gum, carboxymethylcellulose, o-carboxychitosans, hydroxyethylcellulose, hydroxypropylcellulose, and modified starches. Non-limiting examples of useful synthetic polymers include acrylamide polymers, such as polyacrylamide, partially hydrolyzed polyacrylamide and terpolymers containing acrylamide, acrylate, and a third species. As defined herein, polyacrylamide (PA) is an acrylamide polymer having substantially less than 1% of the acrylamide groups in the form of carboxylate groups. Partially hydrolyzed polyacrylamide (PHPA) is an acrylamide polymer having at least 1%, but not 100%, of the acrylamide groups in the form of carboxylate groups. The acrylamide polymer may be prepared according to any conventional method known in the art, but preferably has the specific properties of acrylamide polymer prepared according to the method disclosed by U.S. Pat. No. Re. 32,114 to Argabright et al incorporated herein by reference.

[0067] Any crosslinking agent suitable for use with the selected polymer may be utilized in the practice of the present invention. Non limiting examples of suitable crosslinking agents includes chromium (III) carboxylate complexes, aldehydes, dialdehydes, formaldehydes, glutaraldehyde, dichromates, titanium chelates, phenols, substituted phenols, ethers, aluminum citrate, and aluminates.

[0068] Preferably, the crosslinking agent utilized in the present invention is a chromic carboxylate complex.

[0069] The term “complex” is defined herein as an ion or molecule containing two or more interassociated ionic, radical or molecular species. A complex ion as a whole has a distinct electrical charge while a complex molecule is electrically neutral. The term “chromic carboxylate complex” encompasses a single complex, mixtures of complexes containing the same carboxylate species, and mixtures of complexes containing differing carboxylate species.

[0070] The chromic carboxylate complex useful in the practice of the present invention includes at least one or more electropositive chromium III species and one or more electronegative carboxylate species. The complex may advantageously also contain one or more electronegative hydroxide and/or oxygen species. It is believed that, when two or more chromium III species are present in the complex, the oxygen or hydroxide species may help to bridge the chromium III species. Each complex optionally contains additional species which are not essential to the polymer crosslinking function of the complex. For example, inorganic mono- and/or divalent ions, which function merely to balance the electrical charge of the complex, or one or more water molecules may be associated with each complex. Non-limiting representative formulae of such complexes include:

[Cr3(CH3CO2)6(OH)2]1+;

[Cr3(CH3CO2)6(OH)2]NO3.6H2O;

[Cr3(CH3CO2)6(OH)2]3+; and

[Cr3(CH3CO2)6(OH)2](CH3CO2)3.H2O.

[0071] “Trivalent chromium” and “chromic ion” are equivalent terms encompassed by the term “chromium III” species as used herein.

[0072] The carboxylate species are advantageously derived from water-soluble salts of carboxylic acids, especially low molecular weight mono-basic acids. Carboxylate species derived from salts of formic, acetic, propionic, and lactic acid, substituted derivatives thereof and mixtures thereof are preferred. The preferred darboxylate species include the following water-soluble species: formate, acetate, propionate, lactate, substituted derivatives thereof, and mixtures thereof. Acetate is the most preferred carboxylate species. Examples of optional inorganic ions include sodium, sulfate, nitrate and chloride ions.

[0073] A host of complexes of the type described above and their method of preparation are well known in the leather tanning art. These complexes are described in Shuttleworth and Russel, Journal of the Society of Leather Trades' Chemists, “The Kinetics of Chrome Tannage Part I.,” United Kingdom, 1965, v. 49, p. 133-154; “Part III.,” United Kingdom, 1965, v. 49, p. 251-260; “Part IV.,” United Kingdom, 1965, v. 49, p. 261-268; and Von Erdman, Das Leder, “Condensation of Mononuclear Chromium (III) Salts to Polynuclear Compounds,” Eduard Roether Verlag, Darmstadt Germany, 1963, v. 14, p. 249; and incorporated herein by reference. Udy, Marvin J., Chromium. Volume 1: Chemistry of Chromium and its Compounds. Reinhold Publishing Corp., N.Y., 1956, pp. 229-233; and Cotton and Wilkinson, Advanced Inorganic Chemistry 3rd Ed., John Wiley and Sons, Inc., N.Y., 1972, pp. 836-839, further describe typical complexes which may be within the scope of the present invention and are incorporated herein by reference. The present invention is not limited to the specific complexes and mixtures thereof described in the references, but may include others satisfying the above-stated definition.

[0074] Salts of chromium and an inorganic monovalent anion, e.g., CrCl3, may also be combined with the crosslinking agent complex to accelerate gelation of the polymer solution, as described in U.S. Pat. No. 4,723,605 to Sydansk, which is incorporated herein by reference.

[0075] The molar ratio of carboxylate species to chromium III in the chromic carboxylate complexes used in the process of the present invention is typically in the range of 1:1 to 3.9:1. The preferred ratio is range of 2:1 to 3.9:1 and the most preferred ratio is 2.5:1 to 3.5:1.

[0076] The optional reinforcing material of the present invention may comprise fibers or comminuted particles of plant materials, and preferably comprises comminuted particles of one or more plant materials.

[0077] Fibers suitable for use in the present invention are selected from among hydrophilic and hydrophobic fibers. Incorporation of hydrophobic fibers will require use of a suitable wetting agent. Preferably, the fibers utilized in the present invention comprise hydrophilic fibers, most preferably both hydrophilic and hydrophobic fibers.

[0078] With respect to any particular fiber employed in the practice of the present invention, it is believed that the longer the fiber, the more difficult it is to be mixed uniformly in solution. It is believed that fibers as long as 12,500 microns may tend to aggregate and form clumps. The shorter the fiber, it is believed the easier it is to mix in solution. On the other hand, the shorter the fiber, the greater the quantity necessary to provide the desired level of strength in a reinforced mature gel. In general, the fibers utilized in the present invention will have a length in the range of 100 microns to 3200 microns, preferable 100 microns to 1000 microns.

[0079] Non-limiting examples of suitable hydrophobic fibers include nylon, rayon, hydrocarbon fibers and mixtures thereof.

[0080] Non-limiting examples of suitable hydrophilic fibers include glass, cellulose, carbon, silicon, graphite, calcined petroleum coke, cotton fibers, and mixtures thereof.

[0081] Non-limiting examples of comminuted particles of plant materials suitable for use in the present invention include any derived from: nut and seed shells or hulls such as those of peanut, almond, brazil, cocoa bean, coconut, cotton, flax, grass, linseed, maize, millet, oat, peach, peanut, rice, rye, soybean, sunflower, walnut, wheat; various portions of rice including the rice tips, rice straw and rice bran; crude pectate pulp; peat moss fibers; flax; cotton; cotton linters; wool; sugar cane; paper; bagasse; bamboo; corn stalks; various tree portions including sawdust, wood or bark; straw; cork; dehydrated vegetable matter (suitably dehydrated carbonhydrates such as citrus pulp, oatmeal, tapioca, rice grains, potatoes, carrots, beets, and various grain sorghams); whole ground corn cobs; or various plant portions the corn cob light density pith core, the corn cob ground woody ring portion, the corn cob coarse or fine chaff portion, cotton seed stems, flax stems, wheat stems, sunflower seed stems, soybean stems, maize stems, rye grass stems, millet stems, and various mixtures of these materials.

[0082] Optionally a dispersant for the comminuted plant material in the range of about 1 to about 20 pounds, preferably in the range of about 5 to about 10 pounds, and more preferably in the range of about 7 to about 8 pounds of dispersant may be utilized per pound of comminuted plant material. A non-limiting example of a dispersant would be NaCl.

[0083] Preferred comminuted materials useful in the practice of the present invention include those derived from peanuts, wood, paper any portion of rice seed or plant, and any portion of corn cobs.

[0084] These various materials can be comminuted to very fine particle sizes by drying the products and using hammer mills, cutter heads, air control mills or other comminution methods as is well known to those of skill in the comminution art. Air classification equipment or other means can be used for separation of desired ranges of particle sizes using techniques well-known in the comminution art.

[0085] Any suitable size of comminuted material may be utilized in the present invention, along as such size produces results which are desired. Of course, the particle size will be a function of diameter of the porosity passages. While the present invention will find utility for passages on the order of microns in diameter, it will also find utility on larger passages, for example, those with diameters greater than {fraction (1/64)}, {fraction (1/16)} or event ⅛ of an inch.

[0086] In most instances, the size range of the comminuted materials utilized herein will range from below about 8 mesh (“mesh” as used herein refers to standard U.S. mesh), preferably from about −65 mesh to about −100 mesh, and more preferably from about −65 mesh to about −85 mesh. Specifically preferred particle sizes for some materials are provided below.

[0087] Preferred mixtures of comminuted materials useful in the practice of the present invention include a rice fraction and peanut hulls; a rice fraction and wood fiber and/or almond hulls; a rice fraction and a corn cob fraction, preferably a chaff portion; and a corn cob fraction, preferably a pith or chaff portion, a rice fraction, and at least one of wood fiber, nut shells, paper and shredded cellophane.

[0088] Rice is commercially available in the form of rice hulls, rice tips, rice straw and rice bran, as these various parts of the rice plant are separated commercially and are widely available from rice mills. Preferably, the size range of the rice fraction utilized herein will range from below about 8 mesh (“mesh” as used herein refers to standard U.S. mesh) , preferably from about −65 mesh to about −100 mesh, and more preferably from about −65 mesh to about −85 mesh.

[0089] After the corn kernals are removed, corn cobs consist of four principle parts that are arranged concentrically. The central portion is a very light density pith core, that is surrounded by a woody ring, that in turn is surrounded by a coarse chaff portion, that in turn is covered by a fine chaff portion. The coarse and fine chaff portions form the sockets for ancoring the corn kernels to the corncob. The normal methods of grinding corncobs produce a mixture of all four parts enumerated above. It is possible, however, to separate the woody ring material from the remainder of the cob. The chaff portion of the corncob remaining after removal of the woody ring material is known as “bees wings”. In the present invention, any of the pith or chaff portions(“BPC”) are the preferred portions of the corn cob, with the chaff portions being more preferred. A range of particle sizes of pith and chaff can be obtained from comminution, but the size range smaller than about 8 mesh is suitable for this invention. Preferably, a particle size distribution ranging from smaller than 8 mesh to smaller than 100 mesh is utilized.

[0090] Preferred woods for use as comminuted materials in the present invention include any type of hard wood fiber, including cedar fiber, oak fiber, pecan fiber and elm fiber. Preferably the wood fiber comprises cedar fibers.

[0091] Preferred nut shells for use in the present invention include pecan, walnut, and almond. Preferably, the nut shells comprise at least one of pecan or walnut shells.

[0092] Preferred particle sizes for the wood fibers, nut shells, paper and cellophane will generally range from about +10 mesh to −100 mesh. An illustration of a non-limiting particle size distribution for these materials would include particles of +10 mesh, +20 mesh, +30 mesh, +50 mesh, +60 mesh, +100 mesh, and −100 mesh.

[0093] For one of the preferred comminuted plant mixtures comprising a corn cob fraction, a rice fraction, and at least one of wood fiber, nut shells, paper and shredded cellophane, the mixture will generally comprise in the range of about 5 to about 95 weight percent rice, in the range of about 5 to about 95 weight percent corncob pith or chaff, with the total of ground wood fiber, ground nut shells, ground paper and shredded cellophane comprising in the range of about 5 to about 95 weight percent (weight percent based on the total weight of plant material in the mixture. Preferred ranges are about 20 to about 75 weight percent rice, about 5 to about 35 weight percent corncob pith or chaff, with the total of ground wood fiber, ground nut shells, ground paper and shredded cellophane comprising in the range of about 20 to about 75 weight percent. More preferred ranges are about 30 to about 50 weight percent rice, about 10 to about 30 weight percent corncob pith and chaff, with the total of ground wood fiber, ground nut shells, ground paper and shredded cellophane comprising in the range of about 25 to about 50 weight percent.

[0094] As these comminuted materials are to be added to a water base conformance fluid, a small amount of oil may optionally added to the mixture. This optional oil is preferably added while the plant materials are being mixed together. This mixing may take place in a ribbon blender, where the oil in the required amount is applied by a spray bar. The oil wets the particles and adds to their lubricity while at the same time helping to control dust produced by the mixing operation. A variety of oils may be utilized in the practice of the present invention in concentrations generally ranging from about 1 percent to about 5 percent by weight based on the total weight of the mixture of comminuted materials, more preferably ranging from about 1 percent to about 2 percent. A non-limiting example of a commercially available oil suitable for use in the present invention includes ISOPAR V, available from Exxon Corporation.

[0095] In the method of the present invention for forming a hydraulic fracturing additive, the various components of polymer, crosslinking agent and filter aid, may be mixed in any form (dry form, liquid form, or slurry form) in any suitable order utilizing mixing techniques as known to those in the art.

[0096] Specifically, a dry hydraulic fracturing additive may be formed by mixing solid polymer, solid crosslinking agent and solid filter aid to form a solid (dry) hydraulic fracturing additive.

[0097] In the practice of the present invention, liquid hydraulic fracturing additive may be formed by mixing the various components in any form (dry form or liquid or slurry form) in any suitable order utilizing mixing techniques as know to those in the art. If the various components are mixed in dry form, this dry mixture may subsequently may be contacted with water or aqueous solution to form a liquid hydraulic fracturing additive.

[0098] Hydraulic fracturing fluids are known to those of skill in the art, and would generally be of the category of well fluid known as drilling fluids. Generally such fluids are liquids in which a density agent has been included to increase the density of the fluid (generally some type of metal salt), and also may optionally include a solid phase.

[0099] In a method of treating a hydraulic fracturing fluid, the hydraulic fracturing fluid to be treated is contacted with a liquid or solid form of the hydraulic fracturing additive of the present invention. Preferably, the hydraulic fracturing fluid is contacted with a dry mixture (i.e., solid form) of the hydraulic fracturing additive. Of course, the various components of the additive (i.e., polymer, crosslinking agent, and filter aid) may be added individually to the hydraulic fracturing fluid to be treated.

[0100] A well fluid of the present invention comprises an aqueous component, polymer, crosslinking agent, and filter aid. A modified hydraulic fracturing fluid comprises a traditional hydraulic fracturing fluid and the hydraulic fracturing additive or fluid of the present invention.

[0101] In a method of operating a well of the present invention in which a well fluid is circulating down from the surface of the well, through the drill string positioned in a wellbore, and out through openings in the drill bit such that the well fluid is then circulated upwardly in the annulus between the side of the wellbore and the rotating drill string, the present invention includes circulating such a well fluid comprising the hydraulic fracturing additive. The hydraulic fracturing additive can be added to the circulating fluid in liquid or solid form or of course, the individual components may be added to the circulating fluid in liquid or solid form. Alternatively, the hydraulic fracturing additive may be added to the fluid prior to it being circulated.

[0102] In well operation, it is also known to define a vertically limited zone into which a slurry is then pumped and subsequently squeezed by application of pressure (either from the formation itself, or by application of pressure to the zone). In a method of performing a well operation of the present invention, the hydraulic fracturing fluid of the present invention is pumped into a desired vertically defined zone in the well, and then “squeezed” to dewater the fluid such that a plug of the filter aid remains behind and the solution of polymer and crosslinking agent migrates into the formation. The filter aid plug remains in place to prevent or slow down the escape of the solution back into the well allowing time for the solution to form a gel plug. In this well operation, one may start with a well fluid containing the polymer, crosslinking agent and filter aid, or these various components may be introduced to the well fluid in any combination/or of one or more in liquid or dry form, or as the additive or hydraulic fracturing fluid as discussed above.

[0103] The hydraulic fracturing fluid of the present invention may optionally include proppants as are known to those of skill in the art, and/or breakers as are known to those of skill in the art.

[0104] Water or an aqueous may be contacted with the additive to form the hydraulic fracturing fluid. Non-limiting examples of suitable aqueous solutions include deionized water, fresh water or a brine having a total dissolved solids concentration up to the solubility limit of the solids in water.

[0105] The breaker is preferably a composition which is sufficiently reactive to effectively break the gel within about 48 hours after the fracture treatment, yet not so reactive that it significantly diminishes the performance properties of the gel during the fracture treatment. Suitable breakers include those known in the art. The gel breaker reverses the gel to a less viscous solution upon completion of the fracture treatment. The less viscous solution is readily removed from the fractures so that injected or produced fluids may flow into or out of the fractures.

[0106] The propping agent can be any suitable composition known in the art. Conventional propping agents include sand, glass beads, ceramic beads, cracked walnut shells, etc. The proppant keeps the fractures open without substantially blocking fluid flow after the degraded gel is removed.

[0107] The present process enables a practitioner to prepare a fracturing fluid from the above-described components which exhibits effective predetermined performance properties. Effective performance properties include low fluid, low friction loss, high shear thinning, high proppant carrying capacity and a resonable gelation rate.

[0108] With the present invention, one can produce effective fracturing fluids as a function of the gel composition and gelation conditions. Thus, to effect an optimum fracture treatment according to the present process, the practitioner predetermines the performance properties of a gel which are required to meet the fracture treatment demands of the given formation and thereafter produces a gel having these predetermined properties by selecting the gel composition and gelation conditions accordingly.

[0109] The present process is applicable to fracture treatments of formations under most conditions and is specific to fracturing a formation which is in fluid communication with an injection or production well. The gels are produced in a manner which renders them insensitive to most extreme formation conditions. The gels can be stable at formation temperatures up to 115° C. and beyond and at any formation pH contemplated. The gels are relatively insensitive to oil field fluids and the stratigraphy of the rock. The gels can be employed in carbonate and sandstone strata or strata having varying mineralogy.

[0110] Upon completion of the fracturing process, the gels can be removed from the fractures by producing them back through the wellbore. The gels are preferably degraded to a less viscous solution before backflowing. Conventional chemical breakers to degrade the gels are either incorporated into the gelation solution during its preparation or separately injected into the treatment region after the fracture treatment. As an alternative to backflowing, the gels can be degraded and displaced out into the formation away from the treatment region. In any case, the gels do not substantially reduce the permeability of the formation near the wellbore or the resultant fracture after the fracture treatment.

EXAMPLES

[0111] The following examples are provided merely to illustrate some but not all of the embodiments of the present invention, and are not intended to, nor do they, limit the scope of the claims.

[0112] DE

[0113] The DE utilized in this example was that produced by Eagle Picher Minerals, Inc., and sold under the trademark CELATOM® Diatomite ET-905. As measured, the particle size distribution was:

[0114] 8% +200 mesh

[0115] 92% −200 mesh

[0116] Polymer

[0117] The polymers utilized were obtained from Ciba and a water-soluble, crosslinkable, carboxylate-containing acrylamide polymers, CIBA 254 (MW from 300,000 to less than 500,000) and CIBA 935 (MW from 6 to 9 million).

[0118] Crosslinking Agent

[0119] The crosslinking agent was chromium acetate.

[0120] Formulations

[0121] Formulation No. 1

[0122] 17.5 grams 254

[0123] 5 grams CrIII Acetate

[0124] 27.5 grams DE

[0125] Formulation No. 2

[0126] 12 grams 254

[0127] 3 grams CrIII Acetate

[0128] 25 grams DE

[0129] Formulation No. 1

[0130] 5 grams 935

[0131] 3 grams 254

[0132] 1.2 grams CrIII Acetate

[0133] 30.8 grams DE

[0134] Filter Press Test

[0135] This test was run to simulate the dewatering of the DE in a subterranean formation, and subsequent formation of a plug of DE and separate crosslinked polymer.

[0136] 30 ml. of plain tap water was added to a beaker and subjected to mixing at 10,000 rpm in a Hamilton Beach commercial drink mixer with a solid agitator. To this blending water was added the above formulations (three separate runs). The sample was allowed to blend for 5 minutes at 10,000 rpm. After the 5 minutes of blending, this mixture was placed into the cylinder of a filter press in which substantial dewatering of the DE slurry occured without any pressure applied. Subsequently, 80 psi of pressure was applied to further dewater and consolidate the DE. Finally, heat was applied to the filter press to heat the consolidated DE and liquid run off. Both the filter press cylinder and collected run off (water soluble crosslinkable polymer and crosslinking agent-no visible DE) were placed into a 160 deg. F. water bath and allowed to crosslink. Without being limited in theory, applicant believes that residual polymer remaining in the DE after dewatering crosslinks and serves to promote the consolidation of the DE. Once crosslinked, the collected run off for all of the formulations promotes a rigid ringing gel.

[0137] While the illustrative embodiments of the invention have been described with particularity, it will be understood that various other modifications will be apparent to and can be readily made by those skilled in the art without departing from the spirit and scope of the invention. Accordingly, it is not intended that the scope of the claims appended hereto be limited to the examples and descriptions set forth herein but rather that the claims be construed as encompassing all the features of patentable novelty which reside in the present invention, including all features which would be treated as equivalents thereof by those skilled in the art to which this invention pertains.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7056867 *Sep 23, 2003Jun 6, 2006Alpine Mud Products CorpDrilling fluid additive system containing graphite and carrier
US7067461 *Sep 23, 2003Jun 27, 2006Alpine Mud Products Corp.Water-based drilling fluid additive containing graphite and carrier
US7541317Jul 14, 2006Jun 2, 2009Engineered Drilling Solutions Inc.Downhole drilling compositions and methods of preparation
US7686081Oct 30, 2008Mar 30, 2010Bj Services CompanySqueeze process for reactivation of well treatment fluids containing diatomaceous earth
US7795184Jun 1, 2009Sep 14, 2010Engineered Drilling Solutions, Inc.Compositions and methods for preparing downhole drilling fluids
US8336624Mar 25, 2010Dec 25, 2012Baker Hughes IncorporatedSqueeze process for reactivation of well treatment fluids containing a water-insoluble adsorbent
US8701774Jun 23, 2011Apr 22, 2014Ecopuro, LlcHydraulic fracturing
US8813847Jan 6, 2014Aug 26, 2014Ecopuro, LlcHydraulic fracturing
WO2011163529A1 *Jun 23, 2011Dec 29, 2011Ecopuro, LlcHydraulic fracturing
WO2014066135A1 *Oct 17, 2013May 1, 2014Baker Hughes IncorporatedCrosslinkable water soluble compositions and methods of using the same
WO2015027084A1 *Aug 21, 2014Feb 26, 2015Baker Hughes IncorporatedAqueous downhole fluids having charged nano-particles and polymers
WO2015033326A1 *Sep 9, 2014Mar 12, 2015Clearwater International LlcLost circulation and fluid loss materials containing guar chaff and methods for making and using same
Classifications
U.S. Classification507/200
International ClassificationC09K8/68, C09K8/66, E21B43/267
Cooperative ClassificationE21B43/267, C09K8/685, C09K8/68, C09K8/665
European ClassificationE21B43/267, C09K8/68, C09K8/68B, C09K8/66B