U.S. patent application number 12/360562 was filed with the patent office on 2010-07-29 for methods for servicing well bores with hardenable resin compositions.
Invention is credited to D. Chad Brenneis, Jeffery Karcher, Rickey Lynn Morgan.
Application Number | 20100186956 12/360562 |
Document ID | / |
Family ID | 42077502 |
Filed Date | 2010-07-29 |
United States Patent
Application |
20100186956 |
Kind Code |
A1 |
Morgan; Rickey Lynn ; et
al. |
July 29, 2010 |
Methods for Servicing Well Bores with Hardenable Resin
Compositions
Abstract
Methods for servicing well bores with hardenable resin
compositions are provided. In one embodiment, a method of servicing
a well bore includes providing a hydrophobic well bore servicing
composition comprising a liquid hardenable resin, a hardening
agent, and a weighting material selected to impart a desired first
density to the well bore servicing composition; introducing the
well bore servicing composition into a well bore comprising a well
bore fluid having a second density; allowing the well bore
servicing composition to migrate through the well bore fluid to a
desired location in the well bore based at least in part upon a
difference between the first and second densities; and allowing the
liquid hardenable resin to at least partially harden to form a well
bore plug at the desired location in the well bore.
Inventors: |
Morgan; Rickey Lynn;
(Duncan, OK) ; Brenneis; D. Chad; (Marlow, OK)
; Karcher; Jeffery; (Duncan, OK) |
Correspondence
Address: |
CRAIG W. RODDY;HALLIBURTON ENERGY SERVICES
P.O. BOX 1431
DUNCAN
OK
73536-0440
US
|
Family ID: |
42077502 |
Appl. No.: |
12/360562 |
Filed: |
January 27, 2009 |
Current U.S.
Class: |
166/293 ;
166/295; 507/220; 507/239; 507/269; 507/271 |
Current CPC
Class: |
C09K 8/506 20130101;
C09K 8/426 20130101 |
Class at
Publication: |
166/293 ;
166/295; 507/220; 507/239; 507/271; 507/269 |
International
Class: |
E21B 33/13 20060101
E21B033/13; E21B 33/12 20060101 E21B033/12 |
Claims
1. A method of servicing a well bore comprising: providing a
hydrophobic well bore servicing composition comprising a liquid
hardenable resin, a hardening agent, and a weighting material
selected to impart a desired first density to the well bore
servicing composition; introducing the well bore servicing
composition into a well bore comprising a well bore fluid having a
second density; allowing the well bore servicing composition to
migrate through the well bore fluid to a desired location in the
well bore based at least in part upon a difference between the
first and second densities; and allowing the liquid hardenable
resin to at least partially harden to form a well bore plug at the
desired location in the well bore.
2. The method of claim 1, wherein the liquid hardenable resin
comprises a component selected from the group consisting of
epoxy-based resins, novolak resins, polyepoxide resins,
phenol-aldehyde resins, urea-aldehyde resins, urethane resins,
phenolic resins, furan resins, furan/furfuryl alcohol resins,
phenolic/latex resins, phenol formaldehyde resins, polyester resins
and hybrids and copolymers thereof, polyurethane resins and hybrids
and copolymers thereof, and acrylate resins.
3. The method of claim 1, wherein the hardening agent comprises a
component selected from the group consisting of aliphatic amines,
aliphatic tertiary amines, aromatic amines, cycloaliphatic amines,
heterocyclic amines, amido amines, polyamides, polyethyl amines,
polyether amines, polyoxyalkylene amines, carboxylic anhydrides,
triethylenetetraamine, ethylene diamine, N-cocoalkyltrimethylene,
isophorone diamine, Naminophenyl piperazine, imidazoline,
1,2-diaminocyclohexane, polytheramine, diethyltoluenediamine,
4,4'-diaminodiphenyl methane, methyltetrahydrophthalic anhydride,
hexahydrophthalic anhydride, maleic anhydride, polyazelaic
polyanhydride, and phthalic anhydride.
4. The method of claim 1, wherein the weighting material comprises
a component selected from the group consisting of hollow mineral
glass spheres, hollow glass microspheres, cenospheres, ceramic
microspheres, polymeric microspheres, plastic microspheres, silica,
ilmenite, hematite, barite, Portland cement, and manganese
tetraoxide.
5. The method of claim 1, wherein the well bore servicing
composition comprises swellable particles.
6. The method of claim 1, wherein the well bore servicing
composition comprises a component selected from the group
consisting of cellulose fibers, carbon fibers, glass fibers,
mineral fibers, plastic fibers, metallic fibers, metal shavings,
Kevlar fibers, basalt fibers, wollastonite, and micas.
7. The method of claim 1, wherein the weighting material comprises
a low-density weighting material.
8. (canceled)
9. (canceled)
10. The method of claim 7, wherein the weighting material comprises
a component selected from the group consisting of hollow mineral
glass spheres, hollow glass microspheres, cenospheres, ceramic
microspheres, polymeric microspheres, and plastic microspheres.
11. (canceled)
12. (canceled)
13. The method of claim 1, wherein providing the well bore
servicing composition comprises batch-mixing the liquid hardenable
resin, hardening agent, and weighting material to form the well
bore servicing composition.
14. The method of claim 1, wherein the weighting material comprises
a high-density weighting material.
15. (canceled)
16. (canceled)
17. The method of claim 14, wherein the weighting material
comprises a component selected from the group consisting of silica,
ilmenite, hematite, barite, Portland cement, and manganese
tetraoxide.
18-27. (canceled)
28. The method of claim 7, wherein the weighting material is placed
below a desired location in the well bore comprising a well bore
fluid.
29. The method of claim 14, wherein the weighting material is
placed above a desired location in the well bore comprising a well
bore fluid.
Description
BACKGROUND
[0001] The present invention relates to methods and compositions
for servicing well bores. More particularly, the present invention
relates to methods for servicing well bores with hardenable resin
compositions.
[0002] Natural resources such as gas, oil, and water residing in a
subterranean formation or zone are usually recovered by drilling a
well bore into the subterranean formation while circulating a
drilling fluid in the well bore. After terminating the circulation
of the drilling fluid, a string of pipe (e.g., casing) is run in
the well bore. The drilling fluid is then usually circulated
downward through the interior of the pipe and upward through the
annulus, which is located between the exterior of the pipe and the
walls of the well bore. Next, primary cementing is typically
performed whereby a cement slurry is placed in the annulus and
permitted to set into a hard mass (i.e., sheath) to thereby attach
the string of pipe to the walls of the well bore and seal the
annulus. Subsequent secondary or remedial cementing operations may
also be performed, for example, to repair primary-cementing
problems and/or treat conditions within the well bore after the
well bore has been constructed.
[0003] A variety of well bore servicing compositions, including
non-cementatious sealants, such as polymer-, resin-, or latex-based
sealants, have been used in these secondary or remedial cementing
operations. These compositions may be circulated through the well
bore to plug a void or crack in the conduit or cement sheath or an
opening between the two. Occasionally, well bores may be shut-in,
for example, when the produced fluids cannot be handled or sold
economically due to low hydrocarbon demand. During this time,
conditions within the well bore may change, resulting in the
formation of voids or cracks in the conduit or cement sheath or
between the two. However, because the well bore is shut-in, it may
not be possible to circulate a well bore servicing composition
through the well bore to repair these conditions. Without the
ability to circulate such a composition through the well bore, it
may be difficult to adequately repair these voids or cracks, if at
all.
SUMMARY
[0004] The present invention relates to methods and compositions
for servicing well bores. More particularly, the present invention
relates to methods for servicing well bores with hardenable resin
compositions.
[0005] In one embodiment of the present invention, the invention
provides a method of servicing a well bore comprising providing a
hydrophobic well bore servicing composition comprising a liquid
hardenable resin, a hardening agent, and a weighting material
selected to impart a desired first density to the well bore
servicing composition; introducing the well bore servicing
composition into a well bore comprising a well bore fluid having a
second density; allowing the well bore servicing composition to
migrate through the well bore fluid to a desired location in the
well bore based at least in part upon a difference between the
first and second densities; and allowing the liquid hardenable
resin to at least partially harden to form a well bore plug at the
desired location in the well bore.
[0006] In another embodiment of the present invention, the
invention provides a method of servicing a well bore comprising
providing a hydrophobic well bore servicing composition comprising
a liquid hardenable resin, a hardening agent, and a low-density
weighting material; introducing the well bore servicing composition
into a well bore below a desired location, the well bore comprising
a well bore fluid; allowing the well bore servicing composition to
migrate through the well bore fluid to the desired location in the
well bore; and allowing the liquid hardenable resin to at least
partially harden to form a well bore plug at the desired location
in the well bore.
[0007] In yet another embodiment of the present invention, the
invention provides a method of servicing a well bore comprising
providing a hydrophobic well bore servicing composition comprising
a liquid hardenable resin, a hardening agent, and a high-density
weighting material; introducing the well bore servicing composition
into a well bore above a desired location, the well bore comprising
a well bore fluid; allowing the well bore servicing composition to
migrate through the well bore fluid to the desired location in the
well bore; and allowing the liquid hardenable resin to at least
partially harden to form a well bore plug at the desired location
in the well bore.
[0008] In still another embodiment of the present invention, the
invention provides a method comprising providing a hydrophobic well
bore servicing composition comprising a liquid hardenable resin, a
hardening agent, and a weighting material; introducing the well
bore servicing composition into an annulus between a pipe string
and a subterranean formation; and allowing the well bore servicing
composition to at least partially harden within the annulus.
[0009] The features and advantages of the present invention will be
readily apparent to those skilled in the art. While numerous
changes may be made by those skilled in the art, such changes are
within the spirit of the invention.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0010] The present invention relates to methods and compositions
for servicing well bores. More particularly, the present invention
relates to methods for servicing well bores with hardenable resin
compositions.
[0011] In particular embodiments, the well bore servicing
compositions of the present invention may be used in the primary
cementing of a well bore, or to create a well bore plug in a well
bore that has been shut-in. As used herein, a "well bore servicing
composition" refers to a fluid used to drill, complete, work over,
repair, or in any way prepare a well bore for the recovery of
materials residing in a subterranean formation penetrated by the
well bore. Examples of well bore servicing compositions include,
but are not limited to cement slurries, lost circulation pills,
settable fluids, servicing compositions for plug-and-abandon
purposes, chemical packers, temporary plugs, spacer fluids,
completion fluids, and remedial fluids.
[0012] Generally, the well bore servicing compositions of the
present invention comprise a liquid hardenable resin component, a
liquid hardening agent component, and a weighting material. In
particular embodiments, the weighting material may be selected to
have low density so that the servicing composition may be
introduced into a well bore below a desired location and allowed to
float up into place in the desired location. In other embodiments,
the weighting material may be selected to have a high density so
that the servicing composition may be introduced into a well bore
above a desired location and allowed to sink into place in the
desired location. Accordingly, in particular embodiments of the
present invention, the servicing compositions may be used to
service well bores that have been shut-in, where it is not possible
to circulate a fluid through the well bore. In other embodiments,
the well bore servicing composition may be used in primary
cementing operations to cement a pipe string in place. Furthermore,
in particular embodiments, the well bore servicing composition may
be selected to be hydrophobic, so that the composition does not
disperse in water and may be selectively placed within the well
bore using the buoyancy of the weighting material to facilitate the
placement of the composition in a desired location.
[0013] In particular embodiments of the present, the liquid
hardenable resin component of the well bore servicing composition
may comprise a hardenable resin, an optional solvent, and an
optional aqueous diluent or carrier fluid. As used herein, the term
"resin" refers to any of a number of physically similar polymerized
synthetics or chemically modified natural resins including
thermoplastic materials and thermosetting materials. Examples of
hardenable resins that may be used in the liquid hardenable resin
component include, but are not limited to, epoxy-based resins,
novolak resins, polyepoxide resins, phenol-aldehyde resins,
urea-aldehyde resins, urethane resins, phenolic resins, furan
resins, furan/furfuryl alcohol resins, phenolic/latex resins,
phenol formaldehyde resins, bisphenol A diglycidyl ether resins,
butoxymethyl butyl glycidyl ether resins, bisphenol
A-epichlorohydrin resins, bisphenol F resins, glycidyl ether
resins, polyester resins and hybrids and copolymers thereof,
polyurethane resins and hybrids and copolymers thereof, acrylate
resins, and mixtures thereof Some suitable resins, such as epoxy
resins, may be cured with an internal catalyst or activator so that
when pumped down hole, they may be cured using only time and
temperature. Other suitable resins, such as furan resins generally
require a time-delayed catalyst or an external catalyst to help
activate the polymerization of the resins if the cure temperature
is low (i.e., less than 250.degree. F.), but will cure under the
effect of time and temperature if the formation temperature is
above about 250.degree. F., preferably above about 300.degree. F.
It is within the ability of one skilled in the art, with the
benefit of this disclosure, to select a suitable resin for use in
embodiments of the present invention and to determine whether a
catalyst is required to trigger curing. One resin that may be used
in particular embodiments of the present invention is the
consolidation agent commercially available from Halliburton Energy
Services, Inc., of Duncan, Okla., under the trade name
"EXPEDITE.TM.."
[0014] Selection of a suitable resin may be affected by the
temperature of the subterranean formation to which the fluid will
be introduced. By way of example, for subterranean formations
having a bottom hole static temperature ("BHST") ranging from about
60.degree. F. to about 250.degree. F., two-component epoxy-based
resins comprising a hardenable resin component and a hardening
agent component containing specific hardening agents may be
preferred. For subterranean formations having a BHST ranging from
about 300.degree. F. to about 600.degree. F., a furan-based resin
may be preferred. For subterranean formations having a BHST ranging
from about 200.degree. F. to about 400.degree. F., either a
phenolic-based resin or a one-component HT epoxy-based resin may be
suitable. For subterranean formations having a BHST of at least
about 175.degree. F., a phenol/phenol formaldehyde/furfuryl alcohol
resin may also be suitable.
[0015] Generally, the hardenable resin may be included in the
liquid hardenable resin component in an amount in the range of
about 5% to about 100% by volume of the liquid hardenable resin
component. In particular embodiments, the hardenable resin may be
included in the liquid hardenable resin component in an amount of
about 75% to about 100% by volume of the liquid hardenable resin
component. It is within the ability of one skilled in the art with
the benefit of this disclosure to determine how much of the liquid
hardenable resin may be needed to achieve the desired results.
Factors that may affect this decision include the type of liquid
hardenable resin and liquid hardening agent used in a particular
application.
[0016] In some embodiments, a solvent may be added to the resin to
reduce its viscosity for ease of handling, mixing and transferring.
However, in particular embodiments, it may be desirable not to use
such a solvent for environmental or safety reasons. It is within
the ability of one skilled in the art with the benefit of this
disclosure to determine if and how much solvent may be needed to
achieve a viscosity suitable to the subterranean conditions of a
particular application. Factors that may affect this decision
include geographic location of the well, the surrounding weather
conditions, and the desired long-term stability of the well bore
servicing fluid.
[0017] Generally, any solvent that is compatible with the
hardenable resin and that achieves the desired viscosity effect may
be suitable for use in the liquid hardenable resin component of the
well bore servicing fluid. Suitable solvents may include, but are
not limited to, polyethylene glycol, butyl lactate, dipropylene
glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl
formamide, diethyleneglycol methyl ether, ethyleneglycol butyl
ether, diethyleneglycol butyl ether, propylene carbonate,
d'limonene, fatty acid methyl esters, and combinations thereof
Selection of an appropriate solvent may be dependent on the resin
composition chosen. With the benefit of this disclosure, the
selection of an appropriate solvent should be within the ability of
one skilled in the art. In some embodiments, the amount of the
solvent used in the liquid hardenable resin component may be in the
range of about 0.1% to about 30% by weight of the liquid hardenable
resin component. Optionally, the liquid hardenable resin component
may be heated to reduce its viscosity, in place of, or in addition
to, using a solvent.
[0018] In some embodiments, the liquid hardenable resin component
may also comprise an aqueous diluent or carrier fluid to reduce the
viscosity of the liquid hardenable resin component and/or help to
wet the weighting material. The aqueous fluids used in the
consolidation fluids of the present invention may comprise fresh
water, saltwater (e.g., water containing one or more salts
dissolved therein), brine (e.g., saturated saltwater), seawater, or
combinations thereof, and may be from any source, provided that
they do not contain components that might adversely affect the
stability and/or performance of the well bore servicing fluid. In
some embodiments, the aqueous diluent or carrier fluid may be
present in the liquid hardenable resin component in an amount from
about 0.1% to about 25% by volume of the liquid hardenable resin
component. In other embodiments, the aqueous diluent or carrier
fluid may be present in the liquid hardenable resin component in an
amount from about 0.1% to about 5% by volume of the liquid
hardenable resin component.
[0019] Generally, the liquid hardenable resin component may be
included in the well bore servicing composition in an amount from
about 5% to about 90% by volume of the well bore servicing
composition. In particular embodiments, the liquid hardenable resin
component may be included in the well bore servicing composition in
an amount from about 50% to about 75% by volume of the well bore
servicing composition. In particular embodiments, the liquid
hardenable resin component may be included in the well bore
servicing composition in an amount of about 58.3% by volume of the
well bore servicing composition.
[0020] The well bore servicing composition of the present invention
also includes a liquid hardening agent component comprising a
hardening agent and an optional silane coupling agent. As used
herein, "hardening agent" refers to any substance capable of
transforming the hardenable resin into a hardened, consolidated
mass. Examples of suitable hardening agents include, but are not
limited to, aliphatic amines, aliphatic tertiary amines, aromatic
amines, cycloaliphatic amines, heterocyclic amines, amido amines,
polyamides, polyethyl amines, polyether amines, polyoxyalkylene
amines, carboxylic anhydrides, triethylenetetraamine, ethylene
diamine, N-cocoalkyltrimethylene, isophorone diamine, N-aminophenyl
piperazine, imidazoline, 1,2-diaminocyclohexane, polytheramine,
diethyltoluenediamine, 4,4'-diaminodiphenyl methane,
methyltetrahydrophthalic anhydride, hexahydrophthalic anhydride,
maleic anhydride, polyazelaic polyanhydride, phthalic anhydride,
and combinations thereof Suitable, commercially available hardening
agents may include, but are not limited to, ETHACURE.RTM. 100,
available from Albemarle Corp. of Baton Rouge, La., and
JEFFAMINE.RTM. D-230, available from Huntsman Corp. of The
Woodlands, Tex. The hardening agent may be included in the liquid
hardening agent component in an amount sufficient to at least
partially harden the resin composition. In some embodiments of the
present invention, the hardening agent used may be included in the
liquid hardening agent component in the range of about 5% to about
100% by volume of the liquid hardening agent component. In other
embodiments, the hardening agent used may be included in the liquid
hardening agent component in an amount of about 50% to about 75% by
volume of the liquid hardening agent component. In other
embodiments, the hardening agent used may be included in the liquid
hardening agent component in an amount of about 62.5% by volume of
the liquid hardening agent component.
[0021] In some embodiments the hardening agent may comprise a
mixture of hardening agents selected to impart particular qualities
to the well bore servicing composition. For example, in particular
embodiments, the hardening agent may comprise a fast-setting
hardening agent and a slow-setting hardening agent. As used herein,
"fast-setting hardening agent" and "slow-setting hardening agent"
do not imply any specific rate at which the agents set a hardenable
resin; instead, the terms merely indicate the relative rates at
which the hardening agents initiate hardening of the resin. Whether
a particular hardening agent is considered fast-setting or
slow-setting may depend on the other hardening agent(s) with which
it is used. In a particular embodiment, ETHACURE.RTM. 100 may be
used as a slow-setting hardening agent and JEFFAMINE.RTM. D-230,
may be used as a fast-setting hardening agent. In some embodiments,
the ratio of fast-setting hardening agent to slow-setting hardening
agent may be selected to achieve a desired behavior of liquid
hardening agent component. For example, in some embodiments, the
fast-setting hardening agent may be included in the liquid
hardening agent component in a ratio of approximately 1:5, by
volume, with the slow-setting hardening agent. With the benefit of
this disclosure, one of ordinary skill in the art should be able to
select the appropriate ratio of hardening agents for use in a
particular application
[0022] The liquid hardening agent component of the well bore
servicing composition may also include an optional silane coupling
agent. The silane coupling agent may be used, among other things,
to act as a mediator to help bond the resin to weighting material,
the surface of the subterranean formation, and/or the surface of
the well bore. Examples of suitable silane coupling agents include,
but are not limited to,
N-2-(aminoethyl)-3-aminopropyltrimethoxysilane;
3-glycidoxypropyltrimethoxysilane;
gamma-aminopropyltriethoxysilane;
N-beta-(aminoethyl)-gamma-aminopropyltrimethoxysilanes;
aminoethyl-N-beta-(aminoethyl)-gamma-aminopropyl-trimethoxysilanes;
gamma-ureidopropyl-triethoxysilanes; beta-(3-4
epoxy-cyclohexyl)-ethyl-trimethoxysilane;
gamma-glycidoxypropyltrimethoxysilanes; vinyltrichlorosilane;
vinyltris(beta-methoxyethoxy)silane; vinyltriethoxysilane;
vinyltrimethoxysilane; 3-metacryloxypropyltrimethoxysilane;
beta-(3,4 epoxycyclohexyl)-ethyltrimethoxysilane;
r-glycidoxypropyltrimethoxysilane;
r-glycidoxypropylmethylidiethoxysilane;
N-beta-(aminoethyl)-r-aminopropyl-trimethoxysilane;
N-beta-(aminoethyl)-r-aminopropylmethyldimethoxysilane;
3-aminopropyl-triethoxysilane;
N-phenyl-r-aminopropyltrimethoxysilane;
r-mercaptopropyltrimethoxysilane; r-chloropropyltrimethoxysilane;
vinyltrichlorosilane; vinyltris(beta-methoxyethoxy)silane;
vinyltrimethoxysilane; r-metacryloxypropyltrimethoxysilane;
beta-(3,4 epoxycyclohexyl)-ethyltrimethoxysila;
r-glycidoxypropyltrimethoxysilane;
r-glycidoxypropylmethylidiethoxysilane;
N-beta-(aminoethyl)-r-aminopropyltrimethoxysilane;
N-beta-(aminoethyl)-r-aminopropylmethyldimethoxysilane;
r-aminopropyltriethoxysilane;
N-phenyl-r-aminopropyltrimethoxysilane;
r-mercaptopropyltrimethoxysilane; r-chloropropyltrimethoxysilane;
N-[3-(trimethoxysilyl)propyl]-ethylenediamine; substituted silanes
where one or more of the substitutions contains a different
functional group; and combinations thereof Generally, the silane
coupling agent may be included in the liquid hardening agent
component in an amount capable of sufficiently bonding the resin to
the particulate. In some embodiments of the present invention, the
silane coupling agent may be included in the liquid hardening agent
component in the range of about 0.1% to about 95% by volume of the
liquid hardening agent component. In other embodiments, the
fast-setting hardening agent may be included in the liquid
hardening agent component in an amount of about 5% to about 50% by
volume of the liquid hardening agent component. In other
embodiments, the fast-setting hardening agent may be included in
the liquid hardening agent component in an amount of about 25% by
volume of the liquid hardening agent component.
[0023] An optional diluent or liquid carrier fluid may also be used
in the liquid hardening agent component to, among other things,
reduce the viscosity of the liquid hardening agent component for
ease of handling, mixing and transferring. However, in some
embodiments, it may be desirable, for environmental or safety
reasons, not to use a solvent. Any suitable carrier fluid that is
compatible with the liquid hardening agent component and achieves
the desired viscosity effects may be suitable for use in the
present invention. Some suitable liquid carrier fluids are those
having high flash points (e.g. above about 125.degree. F.) because
of, among other things, environmental and safety concerns; such
solvents may include, but are not limited to, polyethylene glycol,
butyl lactate, butylglycidyl ether, dipropylene glycol methyl
ether, dipropylene glycol dimethyl ether, dimethyl formamide,
diethyleneglycol methyl ether, ethyleneglycol butyl ether,
diethyleneglycol butyl ether, propylene carbonate, d'limonene,
fatty acid methyl esters, and combinations thereof In particular
embodiments, selection of an appropriate liquid carrier fluid may
be dependent on, inter alias the resin composition chosen.
[0024] Generally, the liquid hardening agent component may be
included in the well bore servicing composition in an amount from
about 1% to about 50% by volume of the well bore servicing
composition. In particular embodiments, the liquid hardening agent
component may be included in the well bore servicing composition in
an amount from about 5% to about 25% by volume of the well bore
servicing composition. In particular embodiments, the liquid
hardening agent component may be included in the well bore
servicing composition in an amount of about 11.6% by volume of the
well bore servicing composition. In some embodiments, the liquid
hardening agent component may be included in the well bore
servicing composition in an approximately 1:5 ratio, by volume,
with the liquid hardenable resin component.
[0025] In particular embodiments, the amount of liquid hardening
agent composition may be selected to impart a desired elasticity or
compressibility to a resulting well bore plug. Generally, the lower
the amount of hardening agent present in the well bore servicing
composition, the greater the elasticity or compressibility of a
resulting well bore plug. With the benefit of this disclosure, it
should be within the skill of one or ordinary skill in the art to
select an appropriate amount of hardening agent to achieve a
desired elasticity or compressibility for a particular
application.
[0026] The well bore servicing compositions of the present
invention also comprise a weighting material. As used herein,
"weighting material" refers to any particulate matter added to the
well bore servicing composition to affect its buoyancy, and does
not imply any particular weight, density, or specific gravity. In
some embodiments, the weighting material may comprise a low-density
weighting material that is sufficiently buoyant to allow the well
bore servicing composition to float in fresh water, seawater,
brine, and/or hydrocarbon. In other embodiments of the present
invention, the weighting material may comprise a high-density
weighting material that is dense enough to allow the well bore
servicing composition to sink in fresh water, seawater, brine,
and/or hydrocarbon. In yet other embodiments, the weighting
material may comprise a mixture of low-density and high-density
weighting material selected to achieve a desired buoyancy. As used
herein, "low-density weighting material" refers to any suitable
weighting material that has a specific gravity of less than about
1.0, whereas "high-density weighting material" refers to any
suitable weighting material that has a specific gravity greater
than about 1.0. Examples of suitable low-density weighting
materials include, but are not limited to hollow microspheres.
Examples of suitable hollow microspheres include, but are not
limited to, hollow mineral glass spheres, such as "SPHERELITE.TM."
commercially available from Halliburton Energy Services of Duncan,
Okla.; silica and alumina cenospheres, such as "CENOLITE.RTM."
commercially available from Microspheres S.A. of South Africa;
hollow glass microspheres, such as "SCOTCHLITE.TM." commercially
available from the 3M Company of St. Paul, Minn.; ceramic
microspheres, such as "Z-LIGHT SPHERES.TM." commercially available
from the 3M Company of St. Paul, Minn.; polymeric microspheres,
such as "EXPANCEL.RTM." commercially available from Akzo Nobel of
The Netherlands; and plastic microspheres, such as
"LUBRA-BEADS.RTM." commercially available from Halliburton Energy
Services of Duncan, Okla. Examples of suitable high-density
weighting materials include, but are not limited to, silica,
ilmenite, hematite, barite, Portland cement, manganese tetraoxide,
and combinations thereof Suitable, commercially available
high-density weighting materials include, but are not limited to,
MICROSAND.TM., a crystalline silica weighting material, and
HI-DENSE.RTM., a hematite weighting material, both commercially
available from Halliburton Energy Services, Inc. of Duncan,
Okla.
[0027] The mean particulate sizes of the weighting material may
generally range from about 2 nanometers to about 3000 microns in
diameter; however, in certain circumstances, other mean particulate
sizes may be desired and will be entirely suitable for practice of
the present invention. It should be understood that the term
"particulate," as used in this disclosure, includes all known
shapes of materials, including substantially spherical materials,
fibrous materials, polygonal materials (such as cubic materials),
and mixtures thereof In particular embodiments, the particulate
size of the weighting material may be selected to impart a desired
viscosity to the well bore servicing composition. Moreover, in
particular embodiments, weighting materials having different
particulate sizes may be mixed to achieve a desired viscosity of
the well bore servicing composition.
[0028] Generally, the weighting material may be included in the
well bore servicing composition in an amount from about 1% to about
60% by volume of the well bore servicing composition. In particular
embodiments, the weighting material may be included in the well
bore servicing composition in an amount from about 20% to about 40%
by volume of the well bore servicing composition. In particular
embodiments, the weighting material may be included in the well
bore servicing composition in an amount of about 30% by volume of
the well bore servicing composition.
[0029] In some embodiments, the well bore servicing compositions
may also include swellable particles. These particles, however, are
optional and need not be included within a well bore servicing
composition for that composition to fall within the teachings of
the present invention. As used herein, a "swellable particle"
refers to any particle that swells upon contact with oil and/or an
aqueous fluid (e.g. water). Swellable particles suitable for use in
embodiments of the present invention may generally swell by up to
about 50% of their original size at the surface. Under downhole
conditions, the amount of swelling may vary depending on the
conditions presented. For example, in some embodiments, the amount
of swelling may be at least 10% under downhole conditions. In
particular embodiments, the amount of swelling may be up to about
50% under downhole conditions. However, as those of ordinary skill
in the art, with the benefit of this disclosure, will appreciate,
the actual amount of swelling when the swellable particles are
included in a well bore servicing composition may depend on the
concentration of the swellable particles included in the
composition, among other factors. In accordance with particular
embodiments of the present invention, the swellable particles may
be included in the well bore servicing composition, for example, to
counteract the formation of cracks in a resultant well bore plug
and/or micro-annulus between the well bore plug and the pipe string
or the formation. In general, the swellable particles are capable
of swelling when contacted by aqueous fluids and/or oil to inhibit
fluid flow through the crack and/or micro-annulus. Accordingly, the
swellable particles may prevent and/or reduce the loss of zonal
isolation in spite of the formation of cracks and/or micro-annulus,
potentially resulting in an improved annular seal for the well bore
servicing compositions.
[0030] Some specific examples of suitable swellable elastomers
include, but are not limited to, natural rubber, acrylate butadiene
rubber, polyacrylate rubber, isoprene rubber, choloroprene rubber,
butyl rubber (IIR), brominated butyl rubber (BIIR), chlorinated
butyl rubber (CIIR), chlorinated polyethylene (CM/CPE), neoprene
rubber (CR), styrene butadiene copolymer rubber (SBR), sulphonated
polyethylene (CSM), ethylene acrylate rubber (EAM/AEM),
epichlorohydrin ethylene oxide copolymer (CO, ECO),
ethylene-propylene rubber (EPM and EDPM), ethylene-propylene-diene
terpolymer rubber (EPT), ethylene vinyl acetate copolymer,
fluorosilicone rubbers (FVMQ), silicone rubbers (VMQ), poly
2,2,1-bicyclo heptene (polynorborneane), and alkylstyrene. One
example of a suitable swellable elastomer comprises a block
copolymer of a styrene butadiene rubber. Examples of suitable
elastomers that swell when contacted by oil include, but are not
limited to, nitrile rubber (NBR), hydrogenated nitrile rubber
(HNBR, HNS), fluoro rubbers (FKM), perfluoro rubbers (FFKM),
tetrafluorethylene/propylene (TFE/P), isobutylene maleic anhydride.
Other swellable elastomers that behave in a similar fashion with
respect to oil or aqueous fluids also may be suitable for use in
particular embodiments of the present invention. Furthermore,
combinations of suitable swellable elastomers may also be used in
particular embodiments of the present invention.
[0031] Some specific examples of suitable water-swellable polymers,
include, but are not limited, to starch-polyacrylate acid graft
copolymer and salts thereof, polyethylene oxide polymer,
carboxymethyl cellulose type polymers, polyacrylamide, poly(acrylic
acid) and salts thereof, poly(acrylic acid-co-acrylamide) and salts
thereof, graft-poly(ethylene oxide) of poly(acrylic acid) and salts
thereof, poly(2-hydroxyethyl methacrylate), poly(2-hydroxypropyl
methacrylate), and combinations thereof. Other water-swellable
polymers that behave in a similar fashion with respect to aqueous
fluids also may be suitable for use in particular embodiments of
the present invention. In certain embodiments, the water-swellable
polymers may be crosslinked and/or lightly crosslinked. Those of
ordinary skill in the art, with the benefit of this disclosure,
will be able to select an appropriate swellable elastomer and/or
water-swellable polymer for use in particular embodiments of the
well bore servicing compositions of the present invention based on
a variety of factors, including the particular application in which
the composition will be used and the desired swelling
characteristics.
[0032] Generally, the swellable particles may be included in the
well bore servicing compositions in an amount sufficient to provide
the desired mechanical properties. In some embodiments, the
swellable particles may be present in the well bore servicing
compositions in an amount up to about 25% by weight of the
hardenable resin. In some embodiments, the swellable particles may
be present in the well bore servicing compositions in a range of
about 5% to about 25% by weight of the hardenable resin. In some
embodiments, the swellable particles may be present in the well
bore servicing compositions in a range of about 15% to about 20% by
weight of the hardenable resin.
[0033] In addition, the swellable particles that may be utilized
may have a wide variety of shapes and sizes of individual particles
suitable for use in accordance with embodiments of the present
invention. By way of example, the swellable particles may have a
well-defined physical shape as well as an irregular geometry,
including the physical shape of platelets, shavings, fibers,
flakes, ribbons, rods, strips, spheroids, beads, pellets, tablets,
or any other physical shape. In some embodiments, the swellable
particles may have a particle size in the range of about 5 microns
to about 1,500 microns. In some embodiments, the swellable
particles may have a particle size in the range of about 20 microns
to about 500 microns. However, particle sizes outside these defined
ranges also may be suitable for particular applications.
[0034] In some embodiments of the present invention, additional
solid materials may also be included in the well bore servicing
composition to enhance the strength, hardness, and/or toughness of
the resulting well bore plug or shealth. As with the swellable
particles discussed above, these materials are optional and need
not be included in a well bore servicing composition for that
composition to fall within the teachings of the present invention.
These solid materials may include both natural and man-made
materials, and may have any shape, including, but not limited to,
beaded, cubic, bar-shaped, cylindrical, or mixtures thereof, and
may be in any form including, but not limited to flake or fiber
form. Suitable materials may include, but are not limited to,
cellulose fibers, carbon fibers, glass fibers, mineral fibers,
plastic fibers (e.g., polypropylene and polyacrylic nitrile
fibers), metallic fibers, metal shavings, Kevlar fibers, basalt
fibers, wollastonite, micas (e.g., phlogopites and muscovites), and
mixtures thereof
[0035] Carbon fibers suitable for use in particular embodiments of
the present invention include high tensile modulus carbon fibers
which have a high tensile strength. In some embodiments, the
tensile modulus of the carbon fibers may exceed 180 GPa, and the
tensile strength of the carbon fibers may exceed 3000 MPa.
Generally, the fibers may have a mean length of about 1 mm or less.
In some embodiments, the mean length of the carbon fibers is from
about 50 to about 500 microns. In particular embodiment, the carbon
fibers have a mean length in the range of from about 100 to about
200 microns. In particular embodiments, the carbon fibers may be
milled carbon fibers. Suitable, commercially available carbon
fibers include, but are not limited to, "AGM-94" and "AGM-99"
carbon fibers both available from Asbury Graphite Mills, Inc., of
Asbury, N.J.
[0036] Metallic fibers suitable for use in particular embodiments
of the present invention may include non-amorphous (i.e.,
crystalline) metallic fibers. In particular embodiments, the
non-amorphous metallic fibers may be obtained by cold drawing steel
wires (i.e., steel wool). Suitable metallic fibers include, but are
not limited to, steel fibers. Generally, the length and diameter of
the metallic fibers may be adjusted such that the fibers are
flexible and easily dispersible in the well bore servicing
composition, and the well bore servicing composition is easily
pumpable.
[0037] These additional solid materials may be present in the well
bore servicing composition of the present invention individually or
in combination. Additionally, the solid materials of the present
invention may be present in the well bore servicing composition in
a variety of lengths and/or aspect ratios. A person having ordinary
skill in the art, with the benefit of this disclosure, will
recognize the mixtures of type, length, and/or aspect ratio to use
to achieve the desired properties of a well bore servicing
composition for a particular application.
[0038] In particular embodiments of the present invention, the
liquid hardenable resin component, liquid hardening agent
component, weighting material, and/or any optional swellable
particles or solid materials may be either batch-mixed or mixed
on-the-fly. As used herein, the term "on-the-fly" is used herein to
mean that a flowing stream is continuously introduced into another
flowing stream so that the streams are combined and mixed while
continuing to flow as a single stream as part of the on-going
treatment. Such mixing may also be described as "real-time" mixing.
On-the-fly mixing, as opposed to batch or partial batch mixing, may
reduce waste and simplify subterranean treatments. This is due, in
part, to the fact that, in particular embodiments, if the
components are mixed and then circumstances dictate that the
subterranean treatment be stopped or postponed, the mixed
components may become unusable. By having the ability to rapidly
shut down the mixing of streams on-the-fly in such embodiments,
unnecessary waste may be avoided, resulting in, inter alia,
increased efficiency and cost savings. However, other embodiments
of the present invention may allow for batch mixing of the well
bore servicing composition. In these embodiments, the well bore
servicing composition may be sufficiently stable to allow the
composition to be prepared in advance of its introduction into the
well bore without the composition becoming unusable if not promptly
introduced into the well bore.
[0039] Generally, the well bore servicing compositions of the
present invention may be used for any purpose. In some embodiments,
the well bore servicing composition may be used to service a well
bore that penetrates a subterranean formation. It is to be
understood that "subterranean formation" encompasses both areas
below exposed earth and areas below earth covered by water such as
ocean or fresh water. Servicing a well bore includes, without
limitation, positioning the well bore servicing composition in the
well bore to isolate the subterranean formation from a portion of
the well bore; to support a conduit in the well bore; to plug a
void or crack in the conduit; to plug a void or crack in a cement
sheath disposed in an annulus of the well bore; to plug a
perforation; to plug an opening between the cement sheath and the
conduit; to prevent the loss of aqueous or nonaqueous drilling
fluids into loss circulation zones such as a void, vugular zone, or
fracture; to plug a well for abandonment purposes; a temporary plug
to divert treatment fluids; as a chemical packer to be used as a
fluid in front of cement slurry in cementing operations; and to
seal an annulus between the well bore and an expandable pipe or
pipe string. For instance, the well bore servicing composition may
withstand substantial amounts of pressure, e.g., the hydrostatic
pressure of a drilling fluid or cement slurry, without being
dislodged or extruded. The well bore servicing composition may set
into a flexible, resilient and tough material, which may prevent
further fluid losses when circulation is resumed. The well bore
servicing composition may also form a non-flowing, intact mass
inside the loss-circulation zone. This mass plugs the zone and
inhibits loss of subsequently pumped drilling fluid, which allows
for further drilling.
[0040] In some embodiments, the well bore servicing compositions
may be placed into an annulus of the well bore and allowed to set
such that it isolates the subterranean formation from a different
portion of the well bore. The well bore servicing compositions may
thus form a barrier that prevents fluids in that subterranean
formation from migrating into other subterranean formations. Within
the annulus, the fluid also serves to support a conduit, e.g.,
casing, in the well bore. In other embodiments, the well bore
servicing composition may be positioned in a well bore in a
multilateral well bore configuration including at least two
principal well bores connected by one or more ancillary well bores.
In secondary cementing, often referred to as squeeze cementing, the
well bore servicing composition may be strategically positioned in
the well bore to plug a void or crack in the conduit, to plug a
void or crack in the hardened sealant (e.g., cement sheath)
residing in the annulus, to plug a relatively small opening known
as a microannulus between the hardened sealant and the conduit, and
so forth, thus acting as a sealant composition.
[0041] In particular embodiments, the well bore servicing
compositions of the present invention may be used in primary
cementing operations, to cement a pipe string (e.g., casing,
liners, expandable tubulars, etc.) in place. In such a primary
cementing operation, a well bore servicing composition may be
pumped into an annulus between the walls of the well bore and the
exterior surface of the pipe string disposed therein. The well bore
servicing composition may set in the annular space, thereby forming
an annular sheath of hardened, substantially impermeable resin that
may support and position the pipe string in the well bore and may
bond the exterior surface of the pipe string to the subterranean
formation. Among other things, the sheath surrounding the pipe
string may function to prevent the migration of fluids in the
annulus, as well as protecting the pipe string from corrosion.
[0042] Generally, the well bore servicing compositions of the
present invention may be introduced into a well bore using any
suitable technique. For example, in some embodiments of the present
invention, a well bore servicing compositions may be introduced
into a well bore by drilling an interception well bore to
"intercept" an existing well bore. Once communication with the
existing well is established, the well bore servicing composition
of the present invention may then be pumped into the well bore as
is known in the art. However, if communication cannot be
established, the well bore servicing composition may still be
introduced into the existing well bore by "lubricating" the
existing well bore. In this process, the well bore servicing
composition may be injected into the existing well bore even though
communication has not been established. This results in the
compression of the fluids and material inside the well bore. Once
the composition has been introduced into the well bore to be
serviced, the buoyancy, density, or specific gravity of the
weighting material in the composition may be used to facilitate the
placement of the composition into a desired location within the
well bore.
[0043] In some embodiments, the present invention provides a method
of servicing a well bore comprising providing a hydrophobic well
bore servicing composition comprising a liquid hardenable resin, a
hardening agent, and a weighting material selected to impart a
desired first density to the well bore servicing composition;
introducing the well bore servicing composition into a well bore
comprising a well bore fluid having a second density; allowing the
well bore servicing composition to migrate through the well bore
fluid to a desired location in the well bore based at least in part
upon a difference between the first and second densities; and
allowing the liquid hardenable resin to at least partially harden
to form a well bore plug at the desired location in the well
bore.
[0044] In another embodiment, the present invention provides a
method of servicing a well bore comprising providing a hydrophobic
well bore servicing composition comprising a liquid hardenable
resin, a hardening agent, and a low-density weighting material;
introducing the well bore servicing composition into a well bore
below a desired location, the well bore comprising a well bore
fluid; allowing the well bore servicing composition to migrate
through the well bore fluid to the desired location in the well
bore; and allowing the liquid hardenable resin to at least
partially harden to form a well bore plug at the desired location
in the well bore.
[0045] In yet another embodiment, the present invention provides a
method of servicing a well bore comprising providing a hydrophobic
well bore servicing composition comprising a liquid hardenable
resin, a hardening agent, and a high-density weighting material;
introducing the well bore servicing composition into a well bore
above a desired location, the well bore comprising a well bore
fluid; allowing the well bore servicing composition to migrate
through the well bore fluid to the desired location in the well
bore; and allowing the liquid hardenable resin to at least
partially harden to form a well bore plug at the desired location
in the well bore.
[0046] In another embodiment, the present invention provides a
method comprising providing a hydrophobic well bore servicing
composition comprising a liquid hardenable resin, a hardening
agent, and a weighting material; introducing the well bore
servicing composition into an annulus between a pipe string and a
subterranean formation; and allowing the well bore servicing
composition to at least partially harden within the annulus.
[0047] To facilitate a better understanding of the present
invention, the following examples of specific embodiments are
given. In no way should the following examples be read to limit or
define the entire scope of the invention.
EXAMPLE 1
[0048] In order to illustrate the compressive strengths and pumping
properties of particular embodiments of the present invention,
various samples were prepared and tested using two different
compositions comprising a liquid hardenable resin and either a low-
or high-density weighting material.
[0049] A low-density composition was prepared by mixing 25.0 cc
FDP-S891A, a liquid hardenable resin commercially available from
Halliburton Energy Services of Duncan, Okla.; 0.5 cc water; and 7 g
4000# 3M.TM. Beads, a low-density weighting material commercially
available from the 3M Company of St. Paul, Minn., in a Waring
blender at 3000 rpm for approximately 3 minutes. A hardening agent
composition comprising 2.5 cc ETHACURE.RTM. 100, 0.5 cc
JEFFAMINE.RTM. D-230, and 1.0 cc silane was added to each sample,
and the resulting mixtures were mixed in the Waring blender at 3000
rpm for an additional minute. After mixing, the low-density
composition had a weight of 6.8 ppg.
[0050] Similarly, a high-density composition was prepared by mixing
25.0 cc FDP-S891A; 0.5 cc water; and 21.7 g MICROSAND.TM. in a
Waring blender at 3000 rpm for approximately 3 minutes. A hardening
agent composition comprising 2.5 cc ETHACURE.RTM. 100, 0.5 cc
JEFFAMINE.RTM. D-230, and 1.0 cc silane was added to each sample,
and the resulting mixtures were mixed in the Waring blender at 3000
rpm for an additional minute. After mixing, the high-density
composition had a weight of 12.0 ppg.
[0051] Using samples of these two compositions at either 70 Bc or
100 Bc, pump tests were performed in an atmospheric consistomer at
125.degree. F. and 152.degree. F. to determine how long the
compositions would remain viscous enough to pump. The results of
these tests are shown below in Table 1.
TABLE-US-00001 TABLE 1 Composition Consistency Pump Time Sample No.
Density Temp. (.degree. F.) (Bc) (Hrs) 1 low 125 70 4.66 2 low 125
100 5.5 3 low 152 70 3 4 low 152 100 4.33 5 high 125 70 7 6 high
125 100 Over 7 7 high 152 70 2.8 8 high 152 100 3.5
[0052] As illustrated in Table 1, the lower the temperature, the
longer the composition remained pumpable. For example, the
low-density composition at 125.degree. F. and 70 Bc remained
pumpable for 4.66 hours, whereas at 152.degree. F. and 70 Bc it
only remained pumpable for 3 hours. Similarly, the high-density
composition at 125.degree. F. and 70 Bc remained pumpable for 7
hours, whereas at 152.degree. F. and 70 Bc it only remained
pumpable for 2.8 hours. Also, as shown in Table 1, the greater the
consistency (i.e., the higher the Bearden value) of the
composition, the longer the composition remained pumpable.
EXAMPLE 2
[0053] The compressive strengths and compressibility of the two
compositions were also tested using samples prepared using the same
low- and high-density compositions from Example 1. Each sample was
poured into a 4-inch-long cylinder having a 2-inch inner diameter,
and the samples were allowed to cure for either 1, 2, 3, or 7 days
in a water bath at atmospheric pressure at either 125.degree. F. or
152.degree. F. The compressive strength and compressibility (until
failure) of the resulting plugs was then tested. The results of
these tests are shown below in Table 2.
TABLE-US-00002 TABLE 2 Cure Compressive Sample Composition Time
Temp. Strength Compressibility No. Density (days) (.degree. F.)
(psi) (%) 1 low 1 125 Not Cured N.A. 2 low 1 152 151.7 18.0 3 low 2
125 139 24.0 4 low 3 125 326 18.9 5 low 3 152 733 18.6 6 low 7 125
1129 26.7 7 low 7 152 2430 26.7 8 high 3 125 1358 42.0 9 high 3 152
4090 37.8
[0054] As shown in Table 2, increasing the curing time and/or
curing temperature of the samples resulted in increasingly higher
compressive strengths. For example, increasing the curing time of
low-density composition from 2 days to 3 days to 7 days, while
maintaining a constant curing temperature of 125.degree. F.,
resulted in compressive strengths of 139 psi, 326 psi, and 1129
psi, respectively. Similarly, increasing the curing temperature
from 125.degree. F. to 152.degree. F. on the samples cured 3 days
resulted in a compressive strength of 733 psi at 152.degree. F. as
opposed to 326 psi at 125.degree. F. for the low-density
composition, and a compressive strength of 4090 psi at 152.degree.
F. as opposed to 1358 psi at 125.degree. F. for the high-density
composition. As also shown in Table 2, each of the resultant plugs
illustrated compressibilities of at least 18% before failure. In
particular, sample no. 8 exhibited a compressibility as high as 42%
before failure.
EXAMPLE 3
[0055] Lastly, the shear bond strength of the low-density
composition was tested by placing each of three samples of the
low-density composition into an annulus formed between an 2-inch
outer pipe and 1-inch inner pipe having inner or outer surface
areas, respectively, of approximately 20 square inches. Two of the
samples were then cured for 7 days at either 125.degree. F. or
152.degree. F. at atmospheric pressure. The other sample was cured
for 7 days at 152.degree. F. at 2000 psi. The shear bond strengths
of the compositions were then tested by applying a torque to the
inner pipe until the composition could no longer resist the
movement of the pipe. The results of these tests are shown below in
Table 3.
TABLE-US-00003 TABLE 3 Cure Pressure Cure Temp. Cure Time Shear
Bond Sample No. (psi) (.degree. F.) (days) Strength (psi) 1 14.7
125 7 200 2 2000 152 7 681 3 14.7 152 7 201
[0056] As shown in Table 3, each sample illustrated a shear bond
strength of at least 200 psi. In fact, the sample cured at 2000 psi
illustrated a shear bond strength of 681 psi. Additionally, the
difference in cure temperatures between sample nos. 1 and 3 did not
significantly affect their shear bond strengths.
[0057] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
While numerous changes may be made by those skilled in the art,
such changes are encompassed within the spirit of this invention as
defined by the appended claims. Furthermore, no limitations are
intended to the details of construction or design herein shown,
other than as described in the claims below. It is therefore
evident that the particular illustrative embodiments disclosed
above may be altered or modified and all such variations are
considered within the scope and spirit of the present invention. In
particular, every range of values (e.g. "from about a to about b,"
or, equivalently, "from approximately a to b," or, equivalently,
"from approximately a-b") disclosed herein is to be understood as
referring to the power set (the set of all subsets) of the
respective range of values. The terms in the claims have their
plain, ordinary meaning unless otherwise explicitly and clearly
defined by the patentee.
* * * * *