U.S. patent application number 10/832163 was filed with the patent office on 2005-03-17 for treatment fluids and methods of use in subterranean formations.
Invention is credited to Eoff, Larry S., Munoz, Trinidad JR..
Application Number | 20050059556 10/832163 |
Document ID | / |
Family ID | 34274522 |
Filed Date | 2005-03-17 |
United States Patent
Application |
20050059556 |
Kind Code |
A1 |
Munoz, Trinidad JR. ; et
al. |
March 17, 2005 |
Treatment fluids and methods of use in subterranean formations
Abstract
The present invention relates to subterranean treatment
operations, and more particularly to improved bridging agents
comprising a degradable material, improved subterranean treatment
fluids comprising such improved bridging agents, and methods of
using such improved subterranean treatment fluids in subterranean
formations. An example of a method of the present invention is a
method of drilling a well bore in a subterranean formation. Another
example of a method of the present invention is a method of forming
a self-degrading filter cake in a subterranean formation. Another
example of a method of the present invention is a method of
degrading a filter cake in a subterranean formation. An example of
a composition of the present invention is a treatment fluid
including a viscosifier, a fluid loss control additive, and a
bridging agent comprising a degradable material. Another example of
a composition of the present invention is a bridging agent
comprising a degradable material.
Inventors: |
Munoz, Trinidad JR.; (Ducan,
OK) ; Eoff, Larry S.; (Duncan, OK) |
Correspondence
Address: |
Robert A. Kent
Halliburton Energy Services
2600 S. 2nd Street
Duncan
OK
73536-0440
US
|
Family ID: |
34274522 |
Appl. No.: |
10/832163 |
Filed: |
April 26, 2004 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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10832163 |
Apr 26, 2004 |
|
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10664126 |
Sep 17, 2003 |
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Current U.S.
Class: |
507/103 |
Current CPC
Class: |
C09K 8/508 20130101;
C09K 8/52 20130101; C09K 8/03 20130101; C09K 2208/18 20130101; C09K
8/06 20130101; Y10T 428/2982 20150115; C09K 8/5045 20130101 |
Class at
Publication: |
507/103 |
International
Class: |
C09K 007/06 |
Claims
What is claimed is:
1. A method of drilling a well bore in a subterranean formation,
comprising the step of drilling a well bore in a subterranean
formation using a treatment fluid comprising a base fluid, a
viscosifier, a fluid loss control additive, and a bridging agent
that comprises a degradable material.
2. The method of claim 1 further comprising the step of permitting
the bridging agent to form a filter cake in the well bore.
3. The method of claim 2 wherein the step of permitting the
bridging agent to form a filter cake in the well bore comprises
forming the filter cake upon a surface in the formation.
4. The method of claim 2 further comprising the step of permitting
the filter cake to degrade.
5. The method of claim 1 wherein the base fluid comprises an
organic fluid.
6. The method of claim 5 wherein the organic fluid comprises a
mineral oil, a synthetic oil, or an ester.
7. The method of claim 6 wherein the organic fluid is kerosene or
diesel.
8. The method of claim 1 wherein the base fluid is present in the
treatment fluid in an amount sufficient to form a pumpable
treatment fluid.
9. The method of claim 8 wherein the base fluid is present in the
treatment fluid in an amount in the range of from about 20% to
about 99% by volume of the treatment fluid.
10. The method of claim 1 wherein the viscosifier comprises an
organophilic clay, a synthetic oil-soluble polymer, or a polymeric
fatty acid.
11. The method of claim 10 wherein the viscosifier is an
organophilic clay.
12. The method of claim 1 wherein the viscosifier is present in the
treatment fluid in an amount sufficient to provide a desired degree
of solids suspension.
13. The method of claim 1 wherein the viscosifier is present in the
treatment fluid in an amount in the range of from about 1 to about
20 pounds viscosifier per barrel of treatment fluid.
14. The method of claim 1 wherein the fluid loss control additive
comprises a synthetic oil-soluble polymer, a powdered hydrocarbon
resin, or organophilic lignite.
15. The method of claim 1 wherein the fluid loss control additive
is a synthetic, oil-soluble polymer.
16. The method of claim 1 wherein the fluid loss control additive
is present in the treatment fluid in an amount sufficient to
provide a desired degree of fluid loss control.
17. The method of claim 1 wherein the fluid loss control additive
is present in the treatment fluid in an amount in the range of from
about 1 to about 30 pounds of fluid loss control additive per
barrel of treatment fluid.
18. The method of claim 1 wherein the bridging agent is present in
the treatment fluid in an amount sufficient to create an efficient
filter cake.
19. The method of claim 1 wherein the bridging agent is present in
the treatment fluid in an amount in the range of from about 0.1% to
about 32% by weight of the treatment fluid.
20. The method of claim 1 wherein the degradable material comprises
a polysaccharide, a chitin, a chitosan, a protein, an orthoester,
an aliphatic polyester, a poly(glycolide), a poly(lactide), a
poly(.epsilon.-caprolactone), a poly(hydroxybutyrate), a
polyanhydride, an aliphatic polycarbonate, a poly(orthoester), a
poly(amino acid), a poly(ethylene oxide), or a polyphosphazene.
21. The method of claim 1 wherein the degradable material further
comprises a plasticizer or a stereoisomer of a poly(lactide).
22. The method of claim 1 wherein the degradable material comprises
poly(lactic acid).
23. The method of claim 22 wherein the poly(lactic acid) is present
in the degradable material in a stoichiometric amount.
24. The method of claim 1 wherein the degradable material comprises
a degradable aliphatic polyester and a hydrated organic or
inorganic compound.
25. The method of claim 24 wherein the hydrated organic or
inorganic compound comprises sodium acetate trihydrate, L-tartaric
acid disodium salt dihydrate, sodium citrate dihydrate, sodium
tetraborate decahydrate, sodium hydrogen phosphate heptahydrate,
sodium phosphate dodecahydrate, amylose, a starch-based hydrophilic
polymer, or a cellulose-based hydrophilic polymer.
26. The method of claim 24 wherein the degradable aliphatic
polyester is present in the degradable material in a stoichiometric
amount.
27. The method of claim 26 wherein the hydrated organic or
inorganic compound is present in the degradable material in a
stoichiometric amount.
28. The method of claim 24 wherein the degradable aliphatic
polyester is poly(lactic acid).
29. The method of claim 24 wherein the degradable material further
comprises calcium carbonate.
30. The method of claim 4 wherein the bridging agent does not begin
to degrade until at least about 12 hours after its placement in the
subterranean formation.
31. The method of claim 1 wherein the treatment fluid further
comprises a weighting agent, a salt, an emulsifier, a filtration
control agent, and a pH control agent.
32. The method of claim 4 wherein the base fluid is an organic
fluid, present in the treatment fluid in an amount in the range of
from about 20% to about 99% by volume of the treatment fluid;
wherein the fluid loss control additive is a synthetic, oil-soluble
polymer, present in the treatment fluid in an amount in the range
of from about 1 to about 30 pounds fluid loss control additive per
barrel of treatment fluid; wherein the viscosifier is present in
the treatment fluid in an amount in the range of from about 1 to
about 20 pounds per barrel of treatment fluid; wherein the bridging
agent is present in the treatment fluid in an amount in the range
of from about 0.1% to about 32% by weight of the treatment fluid;
and wherein the degradable material comprises a degradable
aliphatic polyester and a hydrated organic or inorganic
compound.
33. A method of forming a self-degrading filter cake in a
subterranean formation, comprising the steps of: placing a
treatment fluid in a subterranean formation, the treatment fluid
comprising a base fluid, a viscosifier, a fluid loss control
additive, and a bridging agent that comprises a degradable
material; and permitting the bridging agent to form a
self-degrading filter cake upon a surface in the formation, whereby
fluid loss to the formation through the self-degrading filter cake
is reduced.
34. The method of claim 33 wherein the step of permitting the
bridging agent to form a filter cake in the well bore comprises
forming the filter cake upon a surface in the formation itself.
35. The method of claim 33 wherein the base fluid comprises an
organic fluid.
36. The method of claim 35 wherein the organic fluid comprises a
mineral oil, a synthetic oil, or an ester.
37. The method of claim 36 wherein the organic fluid is kerosene or
diesel.
38. The method of claim 33 wherein the base fluid is present in the
treatment fluid in an amount in the range of from about 20% to
about 99% by volume of the treatment fluid.
39. The method of claim 33 wherein the viscosifier is present in
the treatment fluid in an amount in the range of from about 1 to
about 20 pounds viscosifier per barrel of treatment fluid.
40. The method of claim 33 wherein the fluid loss control additive
is present in the treatment fluid in an amount in the range of from
about 1 to about 30 pounds fluid loss control additive per barrel
of treatment fluid.
41. The method of claim 33 wherein the bridging agent is present in
the treatment fluid in an amount in the range of from about 0.1% to
about 32% by weight of the treatment fluid.
42. The method of claim 33 wherein the degradable material
comprises poly(lactic acid).
43. The method of claim 33 wherein the degradable material
comprises a degradable aliphatic polyester and a hydrated organic
or inorganic compound.
44. The method of claim 43 wherein the degradable aliphatic
polyester is poly(lactic acid).
45. The method of claim 33 wherein the base fluid is an organic
fluid, present in the treatment fluid in an amount in the range of
from about 20% to about 99% by volume of the treatment fluid;
wherein the fluid loss control additive is a synthetic, oil-soluble
polymer, present in the treatment fluid in an amount in the range
of from about 1 to about 30 pounds fluid loss control additive per
barrel of treatment fluid; wherein the viscosifier is present in
the treatment fluid in an amount in the range of from about 1 to
about 20 pounds per barrel of treatment fluid; wherein the bridging
agent is present in the treatment fluid in an amount in the range
of from about 0.1% to about 32% by weight of the treatment fluid;
and wherein the degradable material comprises a degradable
aliphatic polyester and a hydrated organic or inorganic
compound.
46. A method of degrading a filter cake in a subterranean
formation, the filter cake having been deposited therein by a
treatment fluid comprising a bridging agent, comprising the steps
of: utilizing a bridging agent comprising a degradable material;
and permitting the degradable material to degrade.
47. The method of claim 46 wherein the treatment fluid further
comprises a base fluid, a viscosifier, and a fluid loss control
additive.
48. The method of claim 47 wherein the base fluid comprises an
organic fluid.
49. The method of claim 48 wherein the organic fluid comprises a
mineral oil, a synthetic oil, or an ester.
50. The method of claim 49 wherein the organic fluid is kerosene or
diesel.
51. The method of claim 46 wherein the base fluid is present in the
treatment fluid in an amount in the range of from about 20% to
about 99% by volume of the treatment fluid.
52. The method of claim 47 wherein the viscosifier is present in
the treatment fluid in an amount in the range of from about 1 to
about 20 pounds per barrel of treatment fluid.
53. The method of claim 47 wherein the fluid loss control additive
is present in the treatment fluid in an amount in the range of from
about 1 to about 30 pounds fluid loss control additive per barrel
of treatment fluid.
54. The method of claim 46 wherein the bridging agent is present in
the treatment fluid in an amount in the range of from about 0.1% to
about 32% by weight of the treatment fluid.
55. The method of claim 46 wherein the degradable material
comprises poly(lactic acid).
56. The method of claim 46 wherein the degradable material
comprises a degradable aliphatic polyester and a hydrated organic
or inorganic compound.
57. The method of claim 56 wherein the degradable aliphatic
polyester is poly(lactic acid).
58. The method of claim 47 wherein the base fluid is an organic
fluid, present in the treatment fluid in an amount in the range of
from about 20% to about 99% by volume of the treatment fluid;
wherein the fluid loss control additive is a synthetic, oil-soluble
polymer, present in the treatment fluid in an amount in the range
of from about 1 to about 30 pounds fluid loss control additive per
barrel of treatment fluid; wherein the viscosifier is present in
the treatment fluid in an amount in the range of from about 1 to
about 20 pounds per barrel of treatment fluid; wherein the bridging
agent is present in the treatment fluid in an amount in the range
of from about 0.1% to about 32% by weight of the treatment fluid;
and wherein the degradable material comprises a degradable
aliphatic polyester and a hydrated organic or inorganic
compound.
59. A treatment fluid comprising a viscosifier, a fluid loss
control additive, and a bridging agent comprising a degradable
material.
60. The treatment fluid of claim 59 further comprising a base
fluid.
61. The treatment fluid of claim 60 wherein the base fluid
comprises an organic fluid.
62. The treatment fluid of claim 61 wherein the organic fluid
comprises a mineral oil, a synthetic oil, or an ester.
63. The treatment fluid of claim 62 wherein the organic fluid is
kerosene or diesel.
64. The treatment fluid of claim 60 wherein the base fluid is
present in an amount sufficient to form a pumpable treatment
fluid.
65. The treatment fluid of claim 64 wherein the base fluid is
present in an amount in the range of from about 20% to about 99% by
volume of the treatment fluid.
66. The treatment fluid of claim 65 wherein the viscosifier
comprises an organophilic clay, a synthetic, oil-soluble polymer,
or a polymeric fatty acid.
67. The treatment fluid of claim 66 wherein the viscosifier is an
organophilic clay.
68. The treatment fluid of claim 59 wherein the viscosifier is
present in an amount sufficient to provide a desired degree of
solids suspension.
69. The treatment fluid of claim 68 wherein the viscosifier is
present in an amount in the range of from about 1 to about 20
pounds viscosifier per barrel of treatment fluid.
70. The treatment fluid of claim 59 wherein the fluid loss control
additive comprises a synthetic, oil-soluble polymer, a powdered
hydrocarbon resin, or organophilic lignite.
71. The treatment fluid of claim 70 wherein the fluid loss control
additive is a synthetic, oil-soluble polymer.
72. The treatment fluid of claim 59 wherein the fluid loss control
additive is present in an amount sufficient to provide a desired
degree of fluid loss control.
73. The treatment fluid of claim 71 wherein the fluid loss control
additive is present in an amount in the range of from about 1 to
about 30 pounds per barrel of treatment fluid.
74. The treatment fluid of claim 59 wherein the bridging agent
comprising the degradable material is present in an amount
sufficient to create an efficient filter cake.
75. The treatment fluid of claim 74 wherein the bridging agent is
present in an amount in the range of from about 0.1% to about 32%
by weight of the treatment fluid.
76. The treatment fluid of claim 59 wherein the degradable material
comprises a polysaccharide, a chitin, a chitosan, a protein, an
orthoester, an aliphatic polyester, a poly(glycolide), a
poly(lactide), a poly(.epsilon.-caprolactone), a
poly(hydroxybutyrate), a polyanhydride, an aliphatic polycarbonate,
a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), or
a polyphosphazene.
77. The treatment fluid of claim 59 wherein the degradable material
further comprises a plasticizer or a stereoisomer of a
poly(lactide).
78. The treatment fluid of claim 59 wherein the degradable material
comprises
79. The treatment fluid of claim 78 wherein the poly(lactic acid)
is present in the degradable material in a stoichiometric
amount.
80. The treatment fluid of claim 59 wherein the degradable material
comprises a degradable aliphatic polyester and a hydrated organic
or inorganic compound.
81. The treatment fluid of claim 80 wherein the hydrated organic or
inorganic compound comprises sodium acetate trihydrate, L-tartaric
acid disodium salt dihydrate, sodium citrate dihydrate, sodium
tetraborate decahydrate, sodium hydrogen phosphate heptahydrate,
sodium phosphate dodecahydrate, amylose, a starch-based hydrophilic
polymer, or a cellulose-based hydrophilic polymer.
82. The treatment fluid of claim 80 wherein the degradable
aliphatic polyester is present in the degradable material in a
stoichiometric amount.
83. The treatment fluid of claim 80 wherein the hydrated organic or
inorganic compound is present in the degradable material in a
stoichiometric amount.
84. The treatment fluid of claim 80 wherein the degradable
aliphatic polyester is poly(lactic acid).
85. The treatment fluid of claim 80 wherein the degradable material
further comprises calcium carbonate.
86. The treatment fluid of claim 59 wherein the bridging agent does
not begin to degrade until at least about 12 hours after it has
been placed in a subterranean formation.
87. The treatment fluid of claim 59 wherein the treatment fluid
further comprises a weighting agent, a salt, an emulsifier, a
filtration control agent, and a pH control agent.
88. The treatment fluid of claim 59 wherein the base fluid is an
organic fluid, present in the treatment fluid in an amount in the
range of from about 20% to about 99% by volume of the treatment
fluid; wherein the fluid loss control additive is an oil-soluble
polymer, present in the treatment fluid in an amount in the range
of from about 1 to about 30 pounds fluid loss control additive per
barrel of treatment fluid; wherein the viscosifier is present in
the treatment fluid in an amount in the range of from about 1 to
about 20 pounds per barrel of treatment fluid; wherein the bridging
agent is present in the treatment fluid in an amount in the range
of from about 0.1% to about 32% by weight of the treatment fluid;
and wherein the degradable material comprises a degradable
aliphatic polyester and a hydrated organic or inorganic
compound.
89. A bridging agent comprising a degradable material.
90. The bridging agent of claim 89 wherein the degradable material
comprises a polysaccharide, a chitin, a chitosan, a protein, an
orthoester, an aliphatic polyester, a poly(glycolide), a
poly(lactide), a poly(.epsilon.-caprolactone), a
poly(hydroxybutyrate), a polyanhydride, an aliphatic polycarbonate,
a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), or
a polyphosphazene.
91. The bridging agent of claim 89 wherein the degradable material
comprises poly(lactic acid).
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is a continuation-in-part of U.S. patent
application Ser. No. 10/664,126 entitled "Improved Subterranean
Treatment Fluids and Methods of Treating Subterranean Formations,"
filed Sep. 17, 2003, incorporated by reference herein for all
purposes, and from which priority is claimed pursuant to 35 U.S.C.
.sctn. 120.
BACKGROUND OF THE INVENTION
[0002] The present invention relates to subterranean treatment
operations, and more particularly, to improved bridging agents
comprising a degradable material, to improved subterranean
treatment fluids comprising such improved bridging agents, and to
methods of using such improved subterranean treatment fluids in
subterranean formations.
[0003] A subterranean treatment fluid used in connection with a
subterranean formation may be any number of fluids (gaseous or
liquid) or mixtures of fluids and solids (e.g., solid suspensions,
mixtures and emulsions of liquids, gases and solids) used in
subterranean operations. An example of a subterranean treatment
fluid is a drilling fluid. Drilling fluids are used, inter alia,
during subterranean well-drilling operations to, e.g., cool the
drill bit, lubricate the rotating drill pipe to prevent it from
sticking to the walls of the well bore, prevent blowouts by serving
as a hydrostatic head to counteract the sudden entrance into the
well bore of high pressure formation fluids, and also remove drill
cuttings from the well bore. Another example of a subterranean
treatment fluid is a "drill-in and servicing fluid." "Drill-in and
servicing fluids," as referred to herein, will be understood to
include fluids placed in a subterranean formation from which
production has been, is being, or may be cultivated. For example,
an operator may begin drilling a subterranean borehole using a
drilling fluid, cease drilling at a depth just above that of a
potentially productive formation, circulate a sufficient quantity
of a drill-in and servicing fluid through the bore hole to
completely flush out the drilling fluid, then proceed to drill into
the desired formation using the well drill-in and servicing fluid.
Drill-in and servicing fluids often are utilized, inter alia, to
minimize damage to the permeability of such formations.
[0004] Subterranean treatment fluids generally are aqueous-based or
oil-based, and may comprise additives such as viscosifiers (e.g.,
xanthan) and fluid loss control additives (e.g., starches).
Subterranean treatment fluids further may comprise bridging agents,
which may aid in preventing or reducing loss of the treatment fluid
to, inter alia, natural fractures within the subterranean
formation. Calcium carbonate is an example of a conventional
bridging agent. In certain circumstances, a bridging agent may be
designed to form a filter cake so as to plug off a "thief zone" (a
portion of a subterranean formation, most commonly encountered
during drilling operations, into which a drilling fluid may be
lost). Generally, bridging agents are designed to form fast and
efficient filter cakes on the walls of the well bores within the
producing formations to minimize potential leak-off and damage.
Generally, the filter cakes are removed before hydrocarbons are
produced from the formation.
[0005] Conventionally, the filter cakes are removed from well bore
walls by contacting the filter cake with one or more subsequent
fluids. For example, where an aqueous-based treatment fluid
comprising bridging agents is used to establish a filter cake,
operators conventionally have employed enzymes and oxidizers to
remove the viscosifier and fluid loss control additive, and then
used an acid, or a delayed-generation acid, to clean up the calcium
carbonate bridging agent. The removal of filter cakes established
by oil-based treatment fluids, however, is often much more
difficult.
[0006] When an oil-based treatment fluid comprising bridging agents
is placed in a subterranean formation, a filter cake often results
that covers the walls of the well bore. Because the fluids that
subsequently will be placed in the well bore often will be
aqueous-based, an operator ordinarily might prefer to remove this
filter cake with an aqueous-based cleanup fluid that may be
compatible with the subsequent fluids. However, attempts to remove
the filter cake with an aqueous-based cleanup fluid generally have
been unsuccessful, due at least in part to the fact that oil and
water are immiscible, which may impair the aqueous-based cleanup
fluid's ability to clean the filter cake off the well bore walls.
Accordingly, operators have attempted to introduce acid into the
well bore, to try to dissolve the calcium carbonate bridging agents
which are acid-soluble. This method has been problematic, however,
because such calcium carbonate bridging agents are generally
well-mixed within the filter cake. Multi-stage cleanup operations
usually ensue, and may include, in a first stage, the introduction
of water-wetting and oil-penetrating surfactants, followed by
multiple stages that involve the introduction of an acid solution
into the well bore. Additionally, some operators have attempted to
use an oil-based treatment fluid having a particular pH to
establish a filter cake (which, as noted above, is essentially a
water-in-oil emulsion when formed by an oil-based treatment fluid),
and followed the oil-based treatment fluid with a cleanup fluid
having a pH that is sufficiently different to invert the emulsion
(e.g., the filter cake) to become water-external, thereby
water-wetting the bridging particles within the filter cake.
[0007] These conventional methods have been costly, laborious to
perform, and generally have not produced the desired results,
largely because the filter cake is not cleaned evenly-rather, the
cleanup methods described above generally only achieve "pinpricks"
in the filter cake itself. These pinpricks may be problematic
because the well bore is typically under hydrostatic pressure from
the column of treatment fluid, which may be lost through these
pinpricks where the filter cake has been penetrated. Thus, any
fluid that subsequently is placed within the well bore may be lost
into the formation, as such fluid may follow the path of least
resistance, possibly through the pinpricks.
SUMMARY OF THE INVENTION
[0008] The present invention relates to subterranean treatment
operations, and more particularly, to improved bridging agents
comprising a degradable material, to improved subterranean
treatment fluids comprising such improved bridging agents, and to
methods of using such improved subterranean treatment fluids in
subterranean formations.
[0009] An example of a method of the present invention is a method
of drilling a well bore in a subterranean formation, comprising the
step of drilling a well bore in a subterranean formation using a
treatment fluid comprising a base fluid, a viscosifier, a fluid
loss control additive, and a bridging agent that comprises a
degradable material.
[0010] Another example of a method of the present invention is a
method of forming a self-degrading filter cake in a subterranean
formation, comprising the steps of: placing a treatment fluid in a
subterranean formation, the treatment fluid comprising a base
fluid, a viscosifier, a fluid loss control additive, and a bridging
agent comprising a degradable material; and permitting the bridging
agent to form a self-degrading filter cake upon a surface in the
formation, whereby fluid loss to the formation through the
self-degrading filter cake is reduced.
[0011] Another example of a method of the present invention is a
method of degrading a filter cake in a subterranean formation, the
filter cake having been deposited therein by a treatment fluid
comprising a bridging agent, comprising the steps of: utilizing a
bridging agent comprising a degradable material; and permitting the
degradable material to degrade.
[0012] An example of a composition of the present invention is a
treatment fluid comprising a viscosifier, a fluid loss control
additive, and a bridging agent comprising a degradable
material.
[0013] Another example of a composition of the present invention is
a bridging agent comprising a degradable material.
[0014] The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the
description of exemplary embodiments, which follows.
DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS
[0015] The present invention relates to subterranean treatment
operations, and more particularly, to improved bridging agents
comprising a degradable material, to improved subterranean
treatment fluids comprising such improved bridging agents, and to
methods of using such improved subterranean treatment fluids in
subterranean formations. While the compositions and methods of the
present invention are useful in a variety of subterranean
applications, they may be particularly useful in subterranean
drilling operations.
[0016] The subterranean treatment fluids of the present invention
generally comprise a base fluid, a viscosifier, a fluid loss
control additive, and a bridging agent of the present invention,
the bridging agent comprising a degradable material capable of
undergoing an irreversible degradation downhole. Optionally, other
additives may be added as desired.
[0017] The base fluid may comprise any number of organic fluids.
Examples of suitable organic fluids include, but are not limited
to, mineral oils, synthetic oils, esters, kerosene, diesel, and the
like. Generally, these organic fluids may be referred to
generically as "oils." Where a treatment fluid of the present
invention comprises one or more of these organic fluids, and is
used as a drilling fluid in drilling operations, such drilling
fluid may be referred to as an "oil-based fluid" or an "oil-based
mud." Generally, any oil in which a water solution of salts can be
emulsified may be suitable for use as a base fluid in the treatment
fluids of the present invention. Generally, the base fluid may be
present in an amount sufficient to form a pumpable treatment fluid.
More particularly, the base fluid typically is present in the
treatment fluid in an amount in the range of from about 20% to
about 99% by volume of the treatment fluid. In certain exemplary
embodiments, the base fluid may be present in the treatment fluid
in an amount in the range of from about 20% to about 95% by volume
of the treatment fluid.
[0018] The treatment fluids of the present invention comprise a
viscosifier. A broad variety of viscosifiers may be suitable. For
example, the viscosifier may be an organophilic clay, a synthetic
oil-soluble polymer, or a polymeric fatty acid. An example of a
synthetic oil-soluble polymer is commercially available from
Halliburton Energy Services, Inc., of Houston, Tex., under the
trade name "BARAPAK." An example of a polymeric fatty acid is
commercially available from Halliburton Energy Services, Inc., of
Houston, Tex., under the trade name "X-VIS." Generally, the
viscosifier is present in the treatment fluids of the present
invention in an amount sufficient to provide a desired capability
for solids suspension. In certain exemplary embodiments, the
viscosifier may be present in the treatment fluid in an amount in
the range of from about 1 to 20 pounds of viscosifier per barrel of
treatment fluid. In certain exemplary embodiments, the viscosifier
may be present in the treatment fluid in an amount in the range of
from about 2 to about 15 pounds of viscosifier per barrel of
treatment fluid.
[0019] The treatment fluids of the present invention further
comprise a fluid loss control additive. Generally, any fluid loss
control additive may be suitable for use in the treatment fluids of
the present invention. Examples of suitable fluid loss control
additives include, but are not limited to, synthetic oil-soluble
polymers, powdered hydrocarbon resins, and organophilic lignite. An
example of a synthetic oil-soluble polymer is commercially
available from Halliburton Energy Services, Inc., of Houston, Tex.,
under the trade name "BARAPAK." In certain exemplary embodiments,
the fluid loss control additive may be a synthetic oil-soluble
copolymer commercially available from Halliburton Energy Services,
Inc., under the trade name "ADAPTA." Generally, the fluid loss
control additive is present in the treatment fluid in an amount
sufficient to provide a desired degree of fluid loss control. In
certain exemplary embodiments, the fluid loss control additive is
present in the treatment fluid in an amount in the range of from
about 1 to about 30 pounds of fluid loss control additive per
barrel of treatment fluid. In certain exemplary embodiments, the
fluid loss control additive is present in the treatment fluid in an
amount in the range of from about 2 to about 20 pounds of fluid
loss control additive per barrel of treatment fluid.
[0020] The treatment fluids of the present invention further
comprise a bridging agent of the present invention that comprises a
degradable material capable of undergoing an irreversible
degradation downhole. The term "irreversible," as used herein,
means that the degradable material once degraded should not
recrystallize or reconsolidate while downhole, e.g., the degradable
material should degrade in situ but should not recrystallize or
reconsolidate in situ. The terms "degradation" or "degradable"
refer to both the two relatively extreme cases of hydrolytic
degradation that the degradable material may undergo, e.g., bulk
erosion and surface erosion, and any stage of degradation in
between these two. This degradation can be a result of, inter alia,
a chemical or thermal reaction, or a reaction induced by
radiation.
[0021] The bridging agent of the present invention becomes
suspended in the treatment fluid and, as the treatment fluid begins
to form a filter cake within the subterranean formation, the
bridging agent becomes distributed throughout the resulting filter
cake. In certain exemplary embodiments, the filter cake forms upon
the face of the formation itself. After the requisite time period
dictated by the characteristics of the particular degradable
material utilized, the degradable material undergoes an
irreversible degradation. This degradation, in effect, causes the
degradable material to substantially be removed from the filter
cake. As a result, voids are created in the filter cake. Removal of
the degradable material from the filter cake allows produced fluids
to flow more freely.
[0022] Generally, the bridging agent comprising the degradable
material is present in the treatment fluids of the present
invention in an amount sufficient to assist in creating an
efficient filter cake. As referred to herein, the term "efficient
filter cake" will be understood to mean a filter cake comprising no
material beyond that required to provide a desired level of fluid
loss control. In certain embodiments, the bridging agent comprising
the degradable material is present in the treatment fluid in an
amount ranging from about 0.1% to about 32% by weight. In certain
exemplary embodiments, the bridging agent comprising the degradable
material is present in the treatment fluid in the range of from
about 3% and about 10% by weight. In certain exemplary embodiments,
the bridging agent is present in the treatment fluid in an amount
sufficient to provide a fluid loss of less than about 15 mL in
tests conducted according to the procedures set forth by API
Recommended Practice (RP) 13. One of ordinary skill in the art with
the benefit of this disclosure will recognize an optimum
concentration of degradable material that provides desirable values
in terms of enhanced ease of removal of the filter cake at the
desired time without undermining the stability of the filter cake
during its period of intended use.
[0023] Nonlimiting examples of suitable degradable materials that
may be used in conjunction with the present invention include, but
are not limited to, degradable polymers, hydrated organic or
inorganic compounds, and/or mixtures of the two. In choosing the
appropriate degradable material, one should consider the
degradation products that will result. Also, these degradation
products should not adversely affect other operations or
components. One of ordinary skill in the art, with the benefit of
this disclosure, will be able to recognize when particular
components of the treatment fluids of the present invention would
be incompatible or would produce degradation products that would
adversely affect other operations or components.
[0024] As for degradable polymers, a polymer is considered to be
"degradable" herein if the degradation is due to, inter alia,
chemical and/or radical process such as hydrolysis, oxidation,
enzymatic degradation, or UV radiation. The degradability of a
polymer depends, at least in part, on its backbone structure. For
instance, the presence of hydrolyzable and/or oxidizable linkages
in the backbone often yields a material that will degrade as
described herein. The rates at which such polymers degrade are
dependent on, inter alia, the type of repetitive unit, composition,
sequence, length, molecular geometry, molecular weight, morphology
(e.g., crystallinity, size of spherulites, and orientation),
hydrophilicity, hydrophobicity, surface area, and additives. The
manner in which the polymer degrades also may be affected by the
environment to which the polymer is subjected (e.g., temperature,
presence of moisture, oxygen, microorganisms, enzymes, pH, and the
like).
[0025] Suitable examples of degradable polymers that may be used in
accordance with the present invention include, but are not limited
to, those described in the publication of Advances in Polymer
Science, Vol. 157 entitled "Degradable Aliphatic Polyesters" edited
by A. C. Albertsson, pages 1-138. Specific examples include
homopolymers, random, block, graft, and star- and hyper-branched
aliphatic polyesters. Such suitable polymers may be prepared by
polycondensation reactions, ring-opening polymerizations, free
radical polymerizations, anionic polymerizations, carbocationic
polymerizations, and coordinative ring-opening polymerization for,
e.g., lactones, and any other suitable process. Specific examples
of suitable polymers include, but are not limited to,
polysaccharides such as dextran or cellulose; chitin; chitosan;
proteins; orthoesters; aliphatic polyesters; poly(lactide);
poly(glycolide); poly(.epsilon.-caprolactone);
poly(hydroxybutyrate); poly(anhydrides); aliphatic polycarbonates;
poly(orthoesters); poly(amino acids); poly(ethylene oxide); and
polyphosphazenes. Of these suitable polymers, aliphatic polyesters
and polyanhydrides may be preferred in many situations.
[0026] Suitable aliphatic polyesters have the general formula of
repeating units shown below: 1
[0027] where n is an integer between 75 and 10,000 and R is
selected from the group consisting of hydrogen, alkyl, aryl,
alkylaryl, acetyl, heteroatoms, and mixtures thereof. Of the
suitable aliphatic polyesters, poly(lactide) is preferred.
Poly(lactide) is synthesized either from lactic acid by a
condensation reaction or more commonly by ring-opening
polymerization of cyclic lactide monomer. Since both lactic acid
and lactide can achieve the same repeating unit, the general term
poly(lactic acid) as used herein refers to writ of formula I
without any limitation as to how the polymer was made (such as from
lactides, lactic acid, or oligomers), and without reference to the
degree of polymerization or level of plasticization.
[0028] The lactide monomer exists generally in three different
forms: two stereoisomers L- and D-lactide and racemic D,L-lactide
(meso-lactide). The oligomers of lactic acid, and oligomers of
lactide are defined by the formula: 2
[0029] where m is an integer: 2.ltoreq.m.ltoreq.75. In certain
exemplary embodiments, m is an integer: 2.ltoreq.m.ltoreq.10. These
limits correspond to number average molecular weights below about
5,400 and below about 720, respectively. The chirality of the
lactide units provides a means to adjust, inter alia, degradation
rates, as well as physical and mechanical properties.
Poly(L-lactide), for instance, is a semicrystalline polymer with a
relatively slow hydrolysis rate. This could be desirable in
applications of the present invention where a slower degradation of
the degradable material is desired. Poly(D,L-lactide) may be a more
amorphous polymer with a resultant faster hydrolysis rate. This may
be suitable for other applications where a more rapid degradation
may be appropriate. The stereoisomers of lactic acid may be used
individually or combined in accordance with the present invention.
Additionally, they may be copolymerized with, for example,
glycolide or other monomers like .epsilon.-caprolactone,
1,5-dioxepan-2-one, trimethylene carbonate, or other suitable
monomers to obtain polymers with different properties or
degradation times. Additionally, the lactic acid stereoisomers can
be modified by blending high and low molecular weight polylactide
or by blending polylactide with other polyesters.
[0030] Plasticizers may be present in the polymeric degradable
materials of the present invention. The plasticizers may be present
in an amount sufficient to provide the desired characteristics, for
example, (a) more effective compatibilization of the melt blend
components, (b) improved processing characteristics during the
blending and processing steps, and (c) control and regulation of
the sensitivity and degradation of the polymer by moisture.
Suitable plasticizers include, but are not limited to, derivatives
of oligomeric lactic acid, selected from the group defined by the
formula: 3
[0031] where R is a hydrogen, alkyl, aryl, alkylaryl, acetyl,
heteroatom, or a mixture thereof and R is saturated, where R' is a
hydrogen, alkyl, aryl, alkylaryl, acetyl, heteroatom, or a mixture
thereof and R' is saturated, where R and R' cannot both be
hydrogen, where q is an integer: 2.ltoreq.q.ltoreq.75; and mixtures
thereof. In certain exemplary embodiments, q is an integer:
2.ltoreq.q.ltoreq.10. As used herein, the term "derivatives of
oligomeric lactic acid" includes derivatives of oligomeric
lactide.
[0032] Aliphatic polyesters useful in the present invention may be
prepared by substantially any of the conventionally known
manufacturing methods, including, but not limited to, those
described in U.S. Pat. Nos. 6,323,307; 5,216,050; 4,387,769;
3,912,692; and 2,703,316, the relevant disclosures of which are
incorporated herein by reference. In addition to the other
qualities above, the plasticizers may enhance the degradation rate
of the degradable polymeric materials.
[0033] Polyanhydrides are another type of particularly suitable
degradable polymer useful in the present invention. Examples of
suitable polyanhydrides include poly(adipic anhydride),
poly(suberic anhydride), poly(sebacic anhydride), and
poly(dodecanedioic anhydride). Other suitable examples include, but
are not limited to, poly(maleic anhydride) and poly(benzoic
anhydride).
[0034] The physical properties of degradable polymers depend on
several factors, including, inter alia, the composition of the
repeat units, flexibility of the chain, presence of polar groups,
molecular mass, degree of branching, crystallinity, and
orientation. For example, short-chain branches reduce the degree of
crystallinity of polymers while long-chain branches lower the melt
viscosity and impart, inter alia, elongational viscosity with
tension-stiffening behavior. The properties of the material
utilized further can be tailored by blending, and copolymerizing it
with another polymer, or by changing the macromolecular
architecture (e.g., hyper-branched polymers, star-shaped, or
dendrimers, etc.). The properties of any such suitable degradable
polymers (e.g., hydrophobicity, hydrophilicity, rate of
degradation, etc.) can be tailored by introducing select functional
groups along the polymer chains. For example, poly(phenyllactide)
will degrade at about 1/5th of the rate of racemic poly(lactide) at
a pH of 7.4 at 55.degree. C. One of ordinary skill in the art, with
the benefit of this disclosure, will be able to determine the
appropriate functional groups to introduce to the polymer chains to
achieve the desired physical properties of the degradable
polymers.
[0035] In certain exemplary embodiments, the bridging agents used
in the treatment fluids of the present invention comprise a
degradable aliphatic polyester and a hydrated organic or inorganic
compound. Examples of such hydrated organic or inorganic compounds
include, but are not limited to, sodium acetate trihydrate,
L-tartaric acid disodium salt dihydrate, sodium citrate dihydrate,
sodium tetraborate decahydrate, sodium hydrogen phosphate
heptahydrate, sodium phosphate dodecahydrate, amylose, starch-based
hydrophilic polymers, or cellulose-based hydrophilic polymers. In
certain exemplary embodiments, the degradable aliphatic polyester
is poly(lactic acid). In certain exemplary embodiments, the
hydrated organic or inorganic compound is sodium acetate
trihydrate. In certain exemplary embodiments, the lactide units of
the aliphatic polyester and releasable water from the hydrated
organic or inorganic compound may be present in stoichiometric
amounts. In certain exemplary embodiments, the bridging agent
comprises a degradable aliphatic polyester and a hydrated organic
or inorganic compound in combination with a bridging agent that
comprises calcium carbonate in an amount in the range of about 1
pound to about 100 pounds of calcium carbonate per barrel of
treatment fluid.
[0036] The choice of degradable material can depend, at least in
part, on the conditions of the well, e.g., well bore temperature.
For instance, lactides have been found to be suitable for lower
temperature wells, including those within the range of about
60.degree. F. to about 150.degree. F., and polylactides have been
found to be suitable for well bore temperatures above this range.
Hydrated organic or inorganic compounds also may be suitable for
higher temperature wells.
[0037] Also, we have found that a preferable result is achieved if
the degradable material degrades slowly over time as opposed to
instantaneously. The slow degradation of the degradable material
helps, inter alia, to maintain the stability of the filter cake.
The time required for degradation of the degradable material may
depend on factors including, but not limited to, the temperature to
which the degradable material is exposed, as well as the type of
degradable material used. In certain exemplary embodiments, a
bridging agent of the present invention comprises a degradable
material that does not begin to degrade until at least about 12 to
about 24 hours after its placement in the subterranean formation.
Certain exemplary embodiments of the treatment fluids of the
present invention may comprise degradable materials that may begin
degrading in less than about 12 hours, or that may not begin
degrading until after greater than about 24 hours.
[0038] The specific features of the degradable material may be
modified so as to maintain the filter cake's filtering capability
when the filter cake is intact while easing the removal of the
filter cake when such removal becomes desirable. In certain
exemplary embodiments, the degradable material has a particle size
distribution in the range of from about 0.1 micron to about 1.0
millimeters. Whichever degradable material is utilized, the
bridging agents may have any shape, including, but not limited to,
particles having the physical shape of platelets, shavings, flakes,
ribbons, rods, strips, spheroids, toroids, pellets, tablets, or any
other physical shape. One of ordinary skill in the art with the
benefit of this disclosure will recognize the specific degradable
material and the preferred size and shape for a given
application.
[0039] The filter cake formed by the treatment fluids of the
present invention is a "self-degrading" filter cake as defined
herein. As referred to herein, the term "self-degrading filter
cake" will be understood to mean a filter cake that may be removed
without the assistance of a separate "clean up" solution or
"breaker" through the well bore, wherein the purpose of such clean
up solution or breaker is solely to degrade the filter cake. Though
the filter cakes formed by the treatment fluids of the present
invention are "self-degrading" filter cakes, an operator
nevertheless occasionally may elect to circulate a separate clean
up solution or breaker through the well bore under certain
circumstances, such as when the operator desires to enhance the
rate of degradation of the filter cake.
[0040] Optionally, the treatment fluids of the present invention
also may comprise additives such as weighting agents, emulsifiers,
salts, filtration control agents, pH control agents, and the like.
Weighting agents are typically heavy minerals such as barite,
ilmenite, calcium carbonate, iron carbonate, or the like. Suitable
salts include, but not limited to, salts such as calcium chloride,
potassium chloride, sodium chloride, and sodium nitrate. Examples
of suitable emulsifiers include polyaminated fatty acids,
concentrated tall oil derivatives, blends of oxidized tall oil and
polyaminated fatty acids, and the like. Examples of suitable
polyaminated fatty acids are commercially available from
Halliburton Energy Services, Inc., of Houston, Tex., under the
trade names "EZMUL" and "SUPERMUL." An example of a suitable
concentrated tall oil derivative is commercially available from
Halliburton Energy Services, Inc., of Houston, Tex., under the
trade name "FACTANT." Examples of suitable blends of oxidized tall
oil and polyaminated fatty acids are commercially available from
Halliburton Energy Services, Inc., of Houston, Tex., under the
trade names "INVERMUL.RTM." and "LE MUL." Examples of suitable
filtration control agents include lignites, modified lignites,
powdered resins, and the like. An example of a suitable lignite is
commercially available from Halliburton Energy Services, Inc., of
Houston, Tex., under the trade name "CARBONOX." An example of a
suitable modified lignite is commercially available from
Halliburton Energy Services, Inc., of Houston, Tex., under the
trade name "BARANEX." An example of a suitable powdered resin is
commercially available from Halliburton Energy Services, Inc., of
Houston, Tex., under the trade name "BARABLOK." Examples of
suitable pH control agents include, but are not limited to, calcium
hydroxide, potassium hydroxide, sodium hydroxide, and the like. In
certain exemplary embodiments, the pH control agent is calcium
hydroxide.
[0041] In an exemplary embodiment of a method of the present
invention, a treatment fluid of the present invention may be used
as a drilling fluid in a subterranean formation, e.g., by
circulating the drilling fluid while drilling a well in contact
with a drill bit and a subterranean formation. Accordingly, an
exemplary method of the present invention comprises the step of
drilling a well bore in a subterranean formation using a treatment
fluid comprising a base fluid, a viscosifier, a fluid loss control
additive, and a bridging agent that comprises a degradable
material. Additional steps may include, inter alia, the step of
forming a filter cake in the well bore, and the step of permitting
the filter cake to degrade.
[0042] Another example of a method of the present invention
comprises the steps of: placing a treatment fluid in a subterranean
formation, the treatment fluid comprising a base fluid, a
viscosifier, a fluid loss control additive, and a bridging agent
comprising a degradable material; and permitting the bridging agent
to form a self-degrading filter cake upon a surface within the
formation, whereby fluid loss to the formation through the
self-degrading filter cake is reduced. Another example of a method
of the present invention is a method of degrading a filter cake in
a subterranean formation, the filter cake having been deposited
therein by a treatment fluid comprising a bridging agent,
comprising the steps of utilizing a bridging agent comprising a
degradable material and permitting the degradable material to
degrade.
[0043] An example of a treatment fluid of the present invention
comprises 68.9% ACCOLADE BASE by weight, 20.1% water by weight, 3%
LE SUPERMUL by weight, 1% ADAPTA by weight, and 7% calcium chloride
by weight.
[0044] To facilitate a better understanding of the present
invention, the following examples of some exemplary embodiments are
given. In no way should such examples be read to limit, or to
define, the scope of the invention.
EXAMPLE 1
[0045] A sample drilling fluid was prepared by adding 80 pounds of
calcium carbonate to a barrel of a nonaqueous-based fluid
commercially available under the trade name "ACCOLADE," from
Halliburton Energy Services, Inc., of Houston, Tex. The sample
drilling fluid was tested using a Model 90B dynamic filtration
system that is commercially available from Fann Instruments, Inc.,
of Houston, Tex. The. sample drilling fluid was circulated through
a hollow cylindrical core within the Model 90B, at 100 psi
differential pressure and agitated at a setting of 100 sec-1.
Filtrate was permitted to leak outwards through the core, thereby
building a filter cake on the inside of the core over a time period
of 4.5 hours. Next, the sample drilling fluid was displaced from
the core and replaced with a conventional breaker solution
comprising from 1% to 3% acetic acid by weight. In one test run,
the conventional breaker solution comprised 1% acetic acid; in
another test run, the conventional breaker solution comprised 3%
acetic acid. The conventional breaker solution was permitted to
remain in the core, in contact with the filter cake, under 100 psi
differential pressure, without stirring. For each test run, the
conventional breaker solution fully penetrated the filter cake in
about 30 minutes, determined by observation of rapid fluid loss
through the core, triggering termination of the test. This
simulates, inter alia, the effect of the conventional breaker
solution in a subterranean formation, wherein the conventional
breaker solution in the well bore would be lost into the formation
upon breakthrough of the filter cake.
[0046] Upon inspection of the filter cake, the penetration was
visually observed to have occurred through tiny "pin pricks" within
the filter cake, e.g., the conventional breaker solution did not
achieve significant clean up of the filter cake, but rather,
penetrated through only a very small area. In practice, such
breakthrough would likely be undesirable, because the conventional
breaker solution would penetrate the filter cake and be lost into
the formation through such pinpricks, yet the vast majority of the
filter cake would remain unaffected, thereby potentially blocking
subsequent production of hydrocarbons from the formation.
Accordingly, the above example demonstrates, inter alia, the
limitations of conventional drilling fluids and conventional
breaker solutions.
EXAMPLE 2
[0047] A white, solid, degradable composite material of the present
invention comprising npolylactic acid and sodium acetate trihydrate
was placed in a test cell at 250.degree. F. and covered in mineral
oil. The material was maintained at 250.degree. F. for about 24
hours, during which time a yellow liquid layer of the degraded
composite formed at the base of the cell. This example
demonstrates, inter alia, that the degradable materials used in
exemplary embodiments of the bridging agents of the present
invention may be degraded by heat alone, apart from contact with
any external degrading agent.
[0048] Therefore, the present invention is well adapted to carry
out the objects and attain the ends and advantages mentioned as
well as those that are inherent therein. While the invention has
been depicted and described by reference to certain exemplary
embodiments of the invention, such a reference does not imply a
limitation on the invention, and no such limitation is to be
inferred. The invention is capable of considerable modification,
alternation, and equivalents in form and function, as will occur to
those ordinarily skilled in the pertinent arts and having the
benefit of this disclosure. The depicted and described embodiments
of the invention are exemplary only, and are not exhaustive of the
scope of the invention. Consequently, the invention is intended to
be limited only by the spirit and scope of the appended claims,
giving full cognizance to equivalents in all respects.
* * * * *