CA2585077A1 - Cementing well bore pipe with activator on outer surface - Google Patents

Cementing well bore pipe with activator on outer surface Download PDF

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Publication number
CA2585077A1
CA2585077A1 CA 2585077 CA2585077A CA2585077A1 CA 2585077 A1 CA2585077 A1 CA 2585077A1 CA 2585077 CA2585077 CA 2585077 CA 2585077 A CA2585077 A CA 2585077A CA 2585077 A1 CA2585077 A1 CA 2585077A1
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CA
Canada
Prior art keywords
activator
fluid
cement
pipe string
well
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Granted
Application number
CA 2585077
Other languages
French (fr)
Other versions
CA2585077C (en
Inventor
Raghava B. Reddy
Anthony M. Badalamenti
Simon Turton
Karl W. Blanchard
Ronald R. Faul
Michael G. Crowder
Henry E. Rogers
James E. Griffith
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Halliburton Energy Services Inc
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Individual
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Filing date
Publication date
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Publication of CA2585077A1 publication Critical patent/CA2585077A1/en
Application granted granted Critical
Publication of CA2585077C publication Critical patent/CA2585077C/en
Expired - Fee Related legal-status Critical Current
Anticipated expiration legal-status Critical

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/46—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
    • C09K8/467—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement containing additives for specific purposes
    • C—CHEMISTRY; METALLURGY
    • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B28/00—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements
    • C04B28/02—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing hydraulic cements other than calcium sulfates
    • C—CHEMISTRY; METALLURGY
    • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B40/00—Processes, in general, for influencing or modifying the properties of mortars, concrete or artificial stone compositions, e.g. their setting or hardening ability
    • C04B40/06—Inhibiting the setting, e.g. mortars of the deferred action type containing water in breakable containers ; Inhibiting the action of active ingredients
    • C04B40/0658—Retarder inhibited mortars activated by the addition of accelerators or retarder-neutralising agents
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices, or the like
    • E21B33/14—Methods or devices for cementing, for plugging holes, crevices, or the like for cementing casings into boreholes
    • C—CHEMISTRY; METALLURGY
    • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B2103/00—Function or property of ingredients for mortars, concrete or artificial stone
    • C04B2103/20—Retarders
    • C04B2103/22—Set retarders
    • C—CHEMISTRY; METALLURGY
    • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B2103/00—Function or property of ingredients for mortars, concrete or artificial stone
    • C04B2103/40—Surface-active agents, dispersants
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02W—CLIMATE CHANGE MITIGATION TECHNOLOGIES RELATED TO WASTEWATER TREATMENT OR WASTE MANAGEMENT
    • Y02W30/00—Technologies for solid waste management
    • Y02W30/50—Reuse, recycling or recovery technologies
    • Y02W30/91—Use of waste materials as fillers for mortars or concrete
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10S—TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10S106/00—Compositions: coating or plastic
    • Y10S106/01—Fly ash
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10S—TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10S166/00—Wells
    • Y10S166/902—Wells for inhibiting corrosion or coating
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10S—TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10S507/00—Earth boring, well treating, and oil field chemistry
    • Y10S507/927—Well cleaning fluid
    • Y10S507/928—Spacing slug or preflush fluid

Abstract

Improved casing strings, and methods of using improved casing strings (4) in subterranean operations, are provided. An example of a method is a method of cementing a pipe string in a subterranean formation. Another example of a method is a method of cementing a pipe string in a well bore (10). An example of an apparatus is an improved pipe string comprising at least one pipe section; and a delivery system of an activator; wherein the delivery system of an activator is disposed adjacent an outer surface of the at least one pipe section.

Claims (77)

1. A method of cementing a pipe string in a subterranean formation, comprising:
providing a well bore having a first fluid disposed therein;
placing a second fluid into the well bore so as to displace at least a portion of the first fluid therefrom, the second fluid comprising a hydraulic cement, a set retarder, and an invert emulsion of oil, water, and an emulsifying agent;
placing in the well bore a pipe string having an activator disposed on an outer surface thereof;

permitting the second fluid and the activator to contact each other; and permitting the second fluid to set in the well bore.
2. The method of claim 1 wherein the first fluid is a drilling fluid.
3. The method of claim 1 further comprising placing a cement composition into the well bore to displace at least a portion of the second fluid therefrom, wherein placing a cement composition into the well bore to displace at least a portion of the second fluid therefrom is performed before permitting the second fluid to set in the well bore.
4. The method of claim 3 further comprising permitting the cement composition to set in the well bore, wherein permitting the cement composition to set in the well bore is performed before permitting the second fluid to set in the well bore.
5. The method of claim 1 wherein the invert emulsion is present in the second fluid in an amount in the range of from about 20% to about 60% by weight of the second fluid.
6. The method of claim 1 wherein the water is present in the second fluid in an amount in the range of from about 30% to about 60% by volume of the invert emulsion.
7. The method of claim 1 wherein the hydraulic cement comprises at least one of a Portland cement, pozzolanic cement, gypsum cement, high alumina cement, silica cement and a high alkalinity cement.
8. The method of claim 1 wherein the hydraulic cement comprises shale or blast furnace slag.
9. The method of claim 1 wherein the set retarder comprises at least one of a lignosulfonate, an organic acid, phosphonic acid, a phosphonic acid derivative, a salt, a carboxymethylated hydroxyethylated cellulose, a synthetic co- or ter-polymer comprising sulfonate and carboxylic acid groups, and a borate compound.
10. The method of claim 9 wherein the borate compound comprises sodium tetraborate or potassium pentaborate.
11. The method of claim 1 wherein the set retarder is present in the second fluid in an amount in the range of from about 0.1% to about 10% by weight of the hydraulic cement.
12. The method of claim 1 wherein the emulsifying agent comprises a blend of oxidized tall oil fatty acids.
13. The method of claim 1 wherein the emulsifying agent comprises a tall oil diethanolamide.
14. The method of claim 1 wherein the second fluid further comprises a surfactant, a dispersant, mica, fibers, a bactericide, a formation conditioning agent, a fixed-density weighting agent, fumed silica, bentonite, fly ash, a fluid loss control additive, an expanding additive, a defoamer, a viscosifier, hollow microspheres, or a mixture thereof.
15. The method of claim 1 wherein the activator is an amine compound.
16. The method of claim 15 wherein the amine compound is triethanol amine, diethanol amine, tripropanol amine, tri-isopropanol amine, or a mixture thereof.
17. The method of claim 1 wherein the activator is a salt of a material selected from the group consisting of: calcium, sodium, magnesium, and aluminum.
18. The method of claim 1 wherein the activator is calcium chloride, sodium chloride, sodium aluminate, sodium silicate, magnesium chloride, or a mixture thereof.
19. The method of claim 1 wherein providing a pipe string comprising an activator on an outer surface of the pipe string further comprises spraying the activator onto the outer surface of the pipe string, and permitting the activator to dry.
20. The method of claim 19 further comprising encapsulating the activator in an activator-encapsulant.
21. The method of claim 1 wherein providing a pipe string comprising an activator on an outer surface of the pipe string further comprises affixing the activator to a first side of a substrate having two sides, and affixing the second side of the substrate to the outer surface of the pipe string.
22. The method of claim 21 further comprising encapsulating the activator in an activator-encapsulant.
23. The method of claim 22 wherein the activator-encapsulant comprises a thermoplastic material.
24. The method of claim 23 wherein the thermoplastic material comprises a base-hydrolyzable functional group.
25. The method of claim 24 wherein the base-hydrolyzable functional group comprises an ester, an amide, or an anhydride.
26. The method of claim 22 wherein the activator-encapsulant comprises: a polyester;
a 3-hydroxybutyrate/3-hydroxyvalerate copolymer; a polymer comprising lactic acid or glycolic acid; a polycaprolactone; a polyethylene succinate; a polybutylene succinate; a poly(ethylene vinylacetate); a poly(vinylacetate); a polymer comprising dioxanone; a cellulose ester; an ethylene-carbon-monoxide polymer; polyglycine;
polycaprolactam;
poly(gamma-glutamic acid); a polyurethane; a polyamide; or a polymer comprising bisphenol-A.
27. The method of claim 22 wherein the activator-encapsulant comprises a-latex composition comprising a crosslinker.
28. The method of claim 22 wherein the activator-encapsulant comprises a polymer comprising an oxidizable monomer.
29. The method of claim 28 wherein the oxidizable monomer is butadiene.
30. The method of claim 28 wherein the activator-encapsulant comprises a styrene-butadiene copolymer, or a butadiene acrylonitrile copolymer.
31. The method of claim 28 further comprising dissolving or degrading the activator-encapsulant by contacting the activator-encapsulant with an oxidizer.
32. The method of claim 31 wherein dissolving or degrading the activator-encapsulant by contacting the activator-encapsulant with an oxidizer is performed before permitting the second fluid and the activator to contact each other.
33. The method of claim 31 wherein the oxidizer comprises sodium persulfate, potassium persulfate, sodium perborate, sodium peroxide, sodium hypochlorite, or sodium chlorite.
34. The method of claim 1 further comprising encapsulating the activator in an activator-encapsulant, wherein the pipe string comprises an expandable tubular, and wherein permitting the second fluid and the activator to contact each other so as to cause the second fluid to set in the well bore comprises expanding the pipe string, whereby the activator-encapsulant is broken to expose the activator.
35. The method of claim 1 wherein the activator is an initiator.
36. The method of claim 1 wherein the activator is an initiator that comprises lime.
37. A method of cementing a pipe string in a subterranean formation, comprising:
providing a well bore having a first fluid disposed therein;
placing a second fluid into the well bore so as to displace at least a portion of the first fluid therefrom, the second fluid comprising a hydraulic settable component, a gel strength inhibiting agent, a set retarder, and a water source;
providing a pipe string having an activator disposed on an outer surface thereof, placing the pipe string in the well bore;
permitting the second fluid and the activator to contact each other; and permitting the second fluid to set in the well bore.
38. The method of claim 37 wherein the first fluid is a drilling fluid.
39. The method of claim 37 further comprising placing a cement composition into the well bore to displace at least a portion of the second fluid therefrom, wherein placing a cement composition into the well bore to displace at least a portion of the second fluid therefrom is performed before permitting the second fluid to set in the well bore.
40. The method of claim 39 further comprising permitting the cement composition to set in the well bore, wherein permitting the cement composition to set in the well bore is performed before permitting the second fluid to set in the well bore.
41. The method of claim 37 wherein the hydraulic settable component comprises ASTM Class C fly ash or ASTM Class F fly ash.
42. The method of claim 37 wherein providing a pipe string comprising an activator on an outer surface of the pipe string further comprises spraying the activator onto the outer surface of the pipe string, and permitting the activator to dry.
43. The method of claim 42 further comprising encapsulating the activator in an activator-encapsulant.
44. The method of claim 37 wherein providing a pipe string comprising an activator on an outer surface of the pipe string further comprises affixing the activator to a first side of a substrate having two sides, and affixing the second side of the substrate to the outer surface of the pipe string.
45. The method of claim 44 further comprising encapsulating the activator in an activator-encapsulant.
46. The method of claim 45 further comprising dissolving or degrading the activator-encapsulant by contacting the activator-encapsulant with an oxidizer.
47. The method of claim 46 wherein dissolving or degrading the activator-encapsulant by contacting the activator-encapsulant with an oxidizer is performed before permitting the second fluid and the activator to contact each other.
48. The method of claim 46 wherein the oxidizer comprises sodium persulfate, potassium persulfate, sodium perborate, sodium peroxide, sodium hypochlorite, or sodium chlorite.
49. The method of claim 37, further comprising encapsulating the activator in a suitable activator-encapsulant, wherein the pipe string comprises an expandable tubular, and wherein permitting the second fluid and the activator to contact each other so as to cause the second fluid to set in the well bore comprises expanding the pipe string, whereby the activator-encapsulant is broken to expose the activator.
50. A method of cementing a pipe string in a well bore, comprising:
placing a well fluid into the well bore;
placing in the well bore a pipe string having a cement-composition-activator and a well-fluid-activator disposed on an outer surface thereof, placing a cement composition in the well bore;
permitting the cement composition and the cement-composition-activator to contact each other;
permitting the well fluid and the well-fluid-activator to contact each other;
permitting the cement composition to set in the well bore; and permitting the well fluid to set in the well bore.
51. The method of claim 50 wherein the well fluid comprises a hydraulic settable component, a gel strength inhibiting agent, a set retarder, and a water source.
52. The method of claim 51 wherein the hydraulic settable component comprises ASTM Class C fly ash or ASTM Class F fly ash.
53. The method of claim 50 wherein the well fluid comprises a hydraulic cement, a set retarder, and an invert emulsion of oil, water, and an emulsifying surfactant.
54. The method of claim 53 wherein the invert emulsion is present in the well fluid in an amount in the range of from about 20% to about 60% by weight of the well fluid.
55. The method of claim 53 wherein the water is present in the well fluid in an amount in the range of from about 30% to about 60% by volume of the invert emulsion.
56. The method of claim 53 wherein the hydraulic cement comprises at least one of a Portland cement, pozzolanic cement, gypsum cement, high alumina cement, silica cement and a high alkalinity cement.
57. The method of claim 53 wherein the hydraulic cement comprises shale or blast furnace slag.
58. The method of claim 53 wherein the set retarder comprises at least one of a lignosulfonate, an organic acid, phosphonic acid, a phosphonic acid derivative, a salt, a carboxymethylated hydroxyethylated cellulose, a synthetic co- or ter-polymer comprising sulfonate and carboxylic acid groups, and a borate compound.
59. The method of claim 53 wherein the set retarder comprises sodium tetraborate or potassium pentaborate.
60. The method of claim 53 wherein the set retarder is present in the well fluid in an amount in the range of from about 0.1% to about 10% by weight of the hydraulic cement.
61. The method of claim 53 wherein the emulsifying surfactant comprises a blend of oxidized tall oil fatty acids.
62. The method of claim 53 wherein the emulsifying surfactant comprises a tall oil diethanolamide.
63. The method of claim 53 wherein the well fluid further comprises a surfactant, a dispersant, mica, fibers, a bactericide, a formation conditioning agent, a fixed-density weighting agent, fumed silica, bentonite, fly ash, a fluid loss control additive, an expanding additive, a defoamer, a viscosifier, hollow microspheres, or a mixture thereof.
64. The method of claim 50 wherein the well-fluid-activator is an amine compound.
65. The method of claim 64 wherein the amine compound is triethanol amine, diethanol amine, tripropanol amine, tri-isopropanol amine, or a mixture thereof.
66. The method of claim 50 wherein the well-fluid-activator is a salt of a material selected from the group consisting of: calcium, sodium, magnesium, and aluminum.
67. The method of claim 50 wherein the well-fluid-activator is calcium chloride, sodium chloride, sodium aluminate, sodium silicate, magnesium chloride, or a mixture thereof.
68. The method of claim 50 wherein providing a pipe string comprising a well-fluid-activator and a cement-composition-activator on an outer surface of the pipe string further comprises spraying at least one of the well-fluid-activator and the cement-composition-activator onto the outer surface of the pipe string, and permitting the at least one of the well-fluid-activator and the cement-composition-activator to dry.
69. The method of claim 50 wherein providing a pipe string comprising a well-fluid-activator and a cement-composition-activator on an outer surface of the pipe string further comprises affixing at least one of the well-fluid-activator and the cement-composition-activator to a first side of a substrate having two sides, and affixing the second side of the substrate to the outer surface of the pipe string.
70. The method of claim 50, further comprising encapsulating the cement-composition-activator and the well-fluid-activator in an activator-encapsulant, wherein the pipe string comprises an expandable tubular, and wherein permitting the cement composition and the cement-composition-activator to contact each other and permitting the well fluid and the well-fluid-activator to contact each other comprises expanding the pipe string, whereby the activator-encapsulant is broken to expose the cement-composition-activator and the well-fluid-activator.
71. The method of claim 50 wherein the well-fluid-activator is an initiator.
72. The method of claim 50 wherein the well-fluid-activator is an initiator that comprises lime.
73. An improved pipe string comprising:
at least one pipe section; and a delivery system of an activator;
wherein the delivery system of an activator is disposed adjacent an outer surface of the at least one pipe section.
74. The pipe string of claim 73, wherein the at least one pipe section is expandable.
75. The pipe string of claim 73, wherein the delivery system of an activator further comprises encapsulant disposed about the activator, whereby the activator is insulated from contact with ambient fluids.
76. The pipe string of claim 73, wherein the activator is an initiator.
77. The pipe string of claim 73, wherein the activator is an initiator that comprises lime.
CA 2585077 2004-10-26 2005-10-06 Cementing well bore pipe with activator on outer surface Expired - Fee Related CA2585077C (en)

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US10/973,331 2004-10-26
US10/973,331 US7284608B2 (en) 2004-10-26 2004-10-26 Casing strings and methods of using such strings in subterranean cementing operations
PCT/GB2005/003849 WO2006045999A1 (en) 2004-10-26 2005-10-06 Casing strings and methods of using such strings in subterranean cementing operations

Publications (2)

Publication Number Publication Date
CA2585077A1 true CA2585077A1 (en) 2006-05-04
CA2585077C CA2585077C (en) 2009-12-22

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ID=35311148

Family Applications (1)

Application Number Title Priority Date Filing Date
CA 2585077 Expired - Fee Related CA2585077C (en) 2004-10-26 2005-10-06 Cementing well bore pipe with activator on outer surface

Country Status (7)

Country Link
US (1) US7284608B2 (en)
EP (1) EP1807603B1 (en)
CA (1) CA2585077C (en)
DE (1) DE602005008463D1 (en)
MX (1) MX2007005015A (en)
NO (1) NO20072064L (en)
WO (1) WO2006045999A1 (en)

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US7284608B2 (en) 2007-10-23
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CA2585077C (en) 2009-12-22
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EP1807603B1 (en) 2008-07-23
US20060086502A1 (en) 2006-04-27

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