U.S. patent application number 12/720736 was filed with the patent office on 2011-09-15 for methods relating to modifying flow patterns using in-situ barriers.
Invention is credited to Alvin S. Cullick, Loyd E. East, Robert F. Shelley, Mohamed Y. Soliman.
Application Number | 20110220359 12/720736 |
Document ID | / |
Family ID | 43919914 |
Filed Date | 2011-09-15 |
United States Patent
Application |
20110220359 |
Kind Code |
A1 |
Soliman; Mohamed Y. ; et
al. |
September 15, 2011 |
Methods Relating to Modifying Flow Patterns Using In-Situ
Barriers
Abstract
A method comprises providing a fluid source in a subterranean
formation; providing a wellbore in the subterranean formation; and
providing an in-situ barrier, wherein the in-situ barrier is
disposed within the subterranean environment and modifies the flow
pattern of at least one fluid within the subterranean formation
that is provided by the fluid source and flows towards the
wellbore.
Inventors: |
Soliman; Mohamed Y.;
(Cypress, TX) ; Shelley; Robert F.; (Katy, TX)
; Cullick; Alvin S.; (Houston, TX) ; East; Loyd
E.; (Cypress, TX) |
Family ID: |
43919914 |
Appl. No.: |
12/720736 |
Filed: |
March 10, 2010 |
Current U.S.
Class: |
166/305.1 |
Current CPC
Class: |
C09K 8/88 20130101; C09K
8/588 20130101 |
Class at
Publication: |
166/305.1 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Claims
1. A method comprising: providing a fluid source in a subterranean
formation; providing a wellbore in the subterranean formation; and
providing an in-situ barrier, wherein the in-situ barrier is
disposed within the subterranean environment and modifies the flow
pattern of at least one fluid within the subterranean formation
that is provided by the fluid source and flows towards the
wellbore.
2. The method of claim 1 wherein the in-situ barrier comprises a
fracture with a sealant disposed therein.
3. The method of claim 2 wherein the in-situ barrier is a
non-selective barrier.
4. The method of claim 3 wherein the sealant comprises at least one
composition selected from the group consisting of: a cement, a
linear polymer mixture, a linear polymer mixture with a
cross-linker, an in-situ polymerized monomer mixture, a resin-based
fluid, an epoxy based fluid, a magnesium based slurry, a drilling
mud, drilling cuttings, slag, a clay based slurry, an emulsion, a
precipitate, an in-situ precipitate, and any combination
thereof.
5. The method of claim 3 wherein the sealant comprises a swellable
elastomer that swells in the presence of an aqueous-based fluid and
an oil-based fluid, wherein the sealant comprises at least one
swellable elastomer selected from the group consisting of: an
ethylene propylene rubber, an ethylene-propylene-diene terpolymer
rubber, a butyl rubber, a brominated butyl rubber, a chlorinated
butyl rubber, a chlorinated polyethylene, a neoprene rubber, a
styrene butadiene copolymer rubber, a sulphonated polyethylene, an
ethylene acrylate rubber, an epichlorohydrin ethylene oxide
copolymer, a silicone rubber, a fluorosilicone rubber, and any
combination thereof.
6. The method of claim 2 wherein the in-situ barrier is a selective
barrier.
7. The method of claim 6 wherein the sealant comprises a swellable
elastomer that swells in the presence of an aqueous-based fluid,
wherein the sealant comprises at least one swellable elastomer
selected from the group consisting of: a starch-polyacrylate acid
graft copolymer, a polyvinyl alcohol cyclic acid anhydride graft
copolymer, a polyacrylamide, poly(acrylic acid-co-acrylamide), a
poly(2-hydroxyethyl methacrylate), a poly(2-hydroxypropyl
methacrylate), an isobutylene maleic anhydride, an acrylic acid
type polymers, a vinylacetate-acrylate copolymer, a polyethylene
oxide polymer, a carboxymethyl cellulose type polymer, a
starch-polyacrylonitrile graft copolymer, a polymer comprising a
swelling clay mineral, a polymer comprising a salt, and any
combination thereof.
8. The method of claim 6 wherein the sealant comprises a swellable
elastomer that swells in the presence of an oil-based fluid,
wherein the sealant comprises at least one swellable elastomer
selected from the group consisting of: a natural rubber, an
acrylate butadiene rubber, an isoprene rubber, a chloroprene
rubber, a butyl rubber, a brominated butyl rubber, a chlorinated
butyl rubber, a chlorinated polyethylene, a neoprene rubber, a
styrene butadiene copolymer rubber, a chlorinated polyethylene, a
sulphonated polyethylene, an ethylene acrylate rubber, an
epichlorohydrin ethylene oxide copolymer, an epichlorohydrin
terpolymer, an ethylene-propylene rubber, an ethylene vinyl acetate
copolymer, an ethylene-propylene-diene terpolymer rubber, an
ethylene vinyl acetate copolymer, a nitrile rubber, an
acrylonitrile butadiene rubber, a hydrogenated acrylonitrile
butadiene rubber, a carboxylated high-acrylonitrile butadiene
copolymer, a polyvinylchloride-nitrile butadiene blend, a
fluorosilicone rubber, a silicone rubber, a poly 2,2,1-bicyclo
heptene, an alkylstyrene, a polyacrylate rubber, an
ethylene-acrylate terpolymer, a fluorocarbon polymer, a copolymers
of poly(vinylidene fluoride) and hexafluoropropylene, a terpolymer
of poly(vinylidene
fluoride)-hexafluoropropylene-tetrafluoroethylene, a terpolymer of
poly(vinylidene fluoride)-polyvinyl methyl
ether-tetrafluoroethylene, a perfluoroelastomer, a highly
fluorinated elastomer, a butadiene rubber, a polychloroprene
rubber, a polyisoprene rubber, a polysulfide rubber, a
polyurethane, a silicone rubber, a vinyl silicone rubber, a
fluoromethyl silicone rubber, a fluorovinyl silicone rubber, a
phenylmethyl silicone rubber, a styrene-butadiene rubber, a
copolymer of isobutylene and isoprene, a brominated copolymer of
isobutylene and isoprene, a chlorinated copolymer of isobutylene
and isoprene, and any combination thereof.
9. The method of claim 6 wherein the sealant comprises a relative
permeability modifier.
10. The method of claim 9, wherein the relative-permeability
modifier comprises a water-soluble polymer, wherein the
water-soluble polymer comprises a hydrophobically modified polymer,
wherein the hydrophobically modified polymer comprises a polymer
backbone and a hydrophobic branch, and wherein the hydrophobic
branch comprises an alkyl chain of about 4 to about 22 carbons.
11. The method of claim 9, wherein the relative-permeability
modifier comprises a hydrophobically modified polymer, wherein the
relative-permeability modifier comprises a reaction product of at
least one hydrophobic compound and at least one hydrophilic
polymer.
12. The method of claim 9, wherein the relative-permeability
modifier comprises a hydrophobically modified polymer synthesized
from a polymerization reaction that comprises a hydrophilic monomer
and a hydrophobically modified hydrophilic monomer, wherein the
hydrophobically modified polymer comprises a hydrophobic branch,
and wherein the hydrophobic branch comprises an alkyl chain of
about 4 to about 22 carbons.
13. The method of claim 9, wherein the relative-permeability
modifier comprises a hydrophilically modified polymer, wherein the
hydrophilically modified polymer is water soluble.
14. A method comprising: providing a plurality of wellbores in a
subterranean formation, wherein at least one wellbore comprises a
fracture; providing at least one injection wellbore in the
subterranean formation; and providing an in-situ barrier by
disposing a sealant in the fracture of the at least one wellbore
wherein the sealant modifies the flow pattern of at least one fluid
provided by the injection wellbore within the subterranean
formation.
15. The method of claim 14 wherein the in-situ barrier is a
selective barrier.
16. The method of claim 15 wherein the in-situ barrier is a
non-selective barrier.
17. The method of claim 15 wherein the sealant comprises at least
one sealant selected from the group consisting of: a swellable
elastomer that swells in the presence of an aqueous-based fluid, a
swellable elastomer that swells in the presence of an oil-based
fluid, and a relative permeability modifier.
18. A system comprising: a fluid source within a subterranean
formation for providing a fluid driving force within the
subterranean formation; a wellbore disposed in the subterranean
formation for producing a production fluid from the subterranean
formation; and an in-situ barrier disposed within the subterranean
formation, wherein the in-situ barrier modifies the flow of at
least one fluid driven by the fluid driving force within the
subterranean formation.
19. The system of claim 18 wherein fluid source comprises an
injection well.
20. The system of claim 18 wherein the fluid source comprises a
natural fluid source, wherein the natural fluid source comprises at
least one fluid source selected from the group consisting of:
existing water in the subterranean formation, external water
entering the subterranean formation, natural gas pressure within
the subterranean formation, and any combination thereof.
21. The system of claim 18 further comprising a plurality of
in-situ barriers disposed within the subterranean formation,
wherein the plurality of in-situ barriers form a baffle that guides
the at least one fluid driven by the fluid driving force.
22. The system of claim 18 wherein the in-situ barrier comprises a
fracture with sealant disposed therein.
23. The system of claim 22 wherein the sealant comprises at least
one sealant selected from the group consisting of: a swellable
elastomer that swells in the presence of an aqueous-based fluid, a
swellable elastomer that swells in the presence of an oil-based
fluid, and a relative permeability modifier.
Description
BACKGROUND
[0001] The present invention relates generally to hydrocarbon
production, and more particularly to a method of increasing
hydrocarbon production in an existing well by forming an in-situ
barrier to the flow of one or more fluids to modify flow
patterns.
[0002] In certain subterranean formations, fluid is injected into a
reservoir to displace or sweep the hydrocarbons out of the
reservoir. This method of stimulating production is sometimes
referred to as a method of "Enhanced Oil Recovery" ("EOR") and may
be called water flooding, gas flooding, steam injection, etc. For
the purpose of this specification, the general process will be
defined as injecting a fluid (gas or liquid) into a reservoir in
order to displace, drive, or increase the production of the
existing hydrocarbons into a producing well. The primary issue with
injecting fluid to enhance oil recovery is how to sweep the
reservoir of the hydrocarbon in the most efficient manner possible.
Because of geological differences in a reservoir, the permeability
within the reservoir may not be homogenous. Because of such
permeability differences between the vertical and horizontal
directions or the existence of higher permeability streaks, the
injecting fluid may bypass some of the reservoir and create a path
into the producing well.
[0003] The industry has come up with methods to improve the sweep
efficiency in individual wells. These methods include fracturing
and the use of deviated wells. The industry currently uses
horizontal wells as injectors in an attempt to expose more of the
reservoir to the injecting fluid. The goal is to create a movement
of injection fluid evenly across the reservoir. This is sometimes
referred to as line drive.
[0004] Part of the efficiency of the sweep is reducing the
production of the injection fluid. The industry has created several
techniques involving the use of chemicals that block the injection
fluid, to injection fluids that improve the matrix flow through the
reservoir to reduce channeling. As used herein, "channeling" refers
to a condition in which a fluid flows through a high permeability
pathway rather than flowing uniformly through a region or zone.
Some injection programs include attempts to plug high permeability
streaks and natural fractures in the reservoir. This is done to
force the injection fluid out into more of the reservoir to
displace hydrocarbons.
[0005] When the injection fluid is produced, such as water, it is
usually removed from the hydrocarbons at the surface using
multi-phase separation devices. A drawback of these devices is that
they can require additional maintenance or repair if solids are
part of the produced fluid stream. A further, and perhaps greatest
drawback of these solutions, is that they do not increase or
maximize the amount of hydrocarbons being produced. Their focus is
removing the water from the production.
[0006] Specialized downhole tools have also been developed, which
separate the water from the hydrocarbons downhole. These tools are
designed to leave the water in the formation as the hydrocarbons
are produced. While these devices can remove a significant amount
of water from the hydrocarbons, they are also often less than
perfect in removing the water from the hydrocarbons. They also
suffer from the same drawback of the surface separation devices in
that they do nothing to increase or maximize the amount of
hydrocarbons being produced.
SUMMARY
[0007] The present invention relates generally to hydrocarbon
production, and more particularly to a method of increasing
hydrocarbon production in an existing well by forming an in-situ
barrier to the flow of one or more fluids to modify flow
patterns.
[0008] In an embodiment, a method comprises providing a fluid
source in a subterranean formation; providing a wellbore in the
subterranean formation; and providing an in-situ barrier, wherein
the in-situ barrier is disposed within the subterranean environment
and modifies the flow pattern of at least one fluid within the
subterranean formation that is provided by the fluid source and
flows towards the wellbore.
[0009] In another embodiment, a method comprises providing a
plurality of wellbores in a subterranean formation, wherein at
least one wellbore comprises a fracture; providing at least one
injection wellbore in the subterranean formation; and providing an
in-situ barrier by disposing a sealant in the fracture of the at
least one wellbore; wherein the sealant modifies the flow pattern
of at least one fluid provided by the injection wellbore within the
subterranean formation.
[0010] In still another embodiment, a system comprises a fluid
source within a subterranean formation for providing a fluid
driving force within the subterranean formation; a wellbore
disposed in the subterranean formation for producing a production
fluid from the subterranean formation; and an in-situ barrier
disposed within the subterranean formation, wherein the in-situ
barrier modifies the flow of at least one fluid driven by the fluid
driving force within the subterranean formation.
[0011] The features and advantages of the present invention will be
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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] These drawings illustrate certain aspects of some of the
embodiments of the present invention, and should not be used to
limit or define the invention.
[0013] FIG. 1 illustrates a cross-sectional view of an embodiment
of a subterranean environment with a wellbore disposed therein.
[0014] FIG. 2 illustrates another cross-sectional view of an
embodiment of a subterranean environment with a wellbore disposed
therein.
[0015] FIG. 3 illustrates an aerial view of a water saturation
profile of a subterranean formation.
[0016] FIG. 4 illustrates an aerial view of a water saturation
profile of a subterranean formation according to an embodiment of
the present invention.
[0017] FIG. 5 illustrates a set of simulated results for total oil
production according to an embodiment of the present invention.
[0018] FIG. 6 illustrates a set of simulated results for total
water production according to an embodiment of the present
invention.
[0019] FIG. 7 illustrates a side view of a water saturation profile
of a subterranean formation according to an embodiment of the
present invention.
[0020] FIG. 8 illustrates an aerial view of a water saturation
profile of a subterranean formation according to an embodiment of
the present invention.
[0021] FIG. 9 illustrates a set of simulated results for total oil
production according to an embodiment of the present invention.
[0022] FIG. 10 illustrates a set of simulated results for total
water production according to an embodiment of the present
invention.
[0023] FIG. 11 illustrates an aerial view of a water saturation
profile of a subterranean formation according to an embodiment of
the present invention.
[0024] FIG. 12 illustrates an aerial view of a water saturation
profile of a subterranean formation.
[0025] FIG. 13 illustrates a set of simulated results for total oil
production according to an embodiment of the present invention.
[0026] FIG. 14 illustrates a set of simulated results for total
water production according to an embodiment of the present
invention.
[0027] FIG. 15 illustrates an aerial view of a simulated
subterranean wellbore layout useful to show an embodiment of the
present invention.
[0028] FIG. 16 illustrates an aerial view of a water saturation
profile of a subterranean formation according to an embodiment of
the present invention.
[0029] FIG. 17 illustrates another aerial view of a water
saturation profile of a subterranean formation according to an
embodiment of the present invention.
[0030] FIG. 18 illustrates still another aerial view of a water
saturation profile of a subterranean formation according to an
embodiment of the present invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0031] The present invention relates generally to hydrocarbon
production, and more particularly to a method and system for
increasing hydrocarbon production in an existing well by forming an
in-situ barrier to the flow of one or more fluids to modify flow
patterns.
[0032] The methods and systems disclosed herein may be
advantageously used to modify the flow pattern within a reservoir
to increase the amount of hydrocarbons recovered from the
subterranean formation and decreasing the amount of water produced
from the subterranean formation. The system and method described
herein may be used with an existing well in an existing formation
to allow for the additional recovery of hydrocarbons without having
to drill new wells, though new wells can be used in an embodiment.
A number of exemplary ways of performing these functions are
disclosed herein.
[0033] In an embodiment, the present invention improves the
production efficiency of hydrocarbons from a producing reservoir
by: providing a fluid source in a subterranean formation, providing
a wellbore in the subterranean formation, providing an in-situ
barrier in the subterranean formation that modifies the flow
pattern of at least one fluid provided by the fluid source that
flows toward the wellbore.
[0034] The present invention provides improved methods, systems,
and materials for modifying the flow pattern in a reservoir. The
methods, systems, and materials can be used in either vertical,
deviated or horizontal wellbores, in consolidated and
unconsolidated formations, in "open-hole" and/or under reamed
completions, as well as in cased wells. If used in a cased
wellbore, the casing may be perforated to provide for fluid
communication between the wellbore and the subterranean formation.
The term "vertical wellbore" is used herein to mean the portion of
a wellbore to be completed which is substantially vertical or
deviated from vertical in an amount up to about 15.degree.. The
term "horizontal wellbore" is used herein to mean the portion of a
wellbore to be completed which is substantially horizontal, or at
an angle from vertical in the range of from about 75.degree. to
about 105.degree.. All other angular positioning relates to a
deviated or inclined wellbore. Since the present invention is
applicable in horizontal and inclined wellbores, the terms "upper
and lower" and "top and bottom" as used herein are relative terms
and are intended to apply to the respective positions within a
particular wellbore, while the term "levels" is meant to refer to
respective spaced positions along the wellbore. In the present
description, the terms "upper," "top," and "above" refer to the
portion of a wellbore nearer to the surface or wellhead while the
terms "lower," "bottom," and "below" refer to the portion of a
wellbore further from the surface or wellhead, irrespective of the
true vertical depth of any portion of the wellbore.
[0035] The present invention can be used in forming an in-situ
barrier to fluid flow in a subterranean formation. For purposes of
illustration, the present invention may be described in the context
of a typical water contamination problem in which water is produced
with the hydrocarbons. However, the methods and materials of the
present invention may have application to other situations where
blocking the flow of fluids other than water or all fluids is
needed. Such applications include, without limitation, any EOR
operation including water flooding, gas flooding, steam injection,
in-situ combustion operations, or any other operation designed to
increase the production of hydrocarbons using a fluid.
[0036] Referring more particularly to the drawing, FIG. 1
illustrates a wellbore 110 for producing hydrocarbons from a
subterranean formation. Wellbore 110 can be drilled using
conventional drilling techniques, for example directional drilling
techniques or other similar methods. The precise method used is not
an important aspect of the present invention. In one certain
exemplary embodiment, the wellbore 110 lined with a casing string.
The casing string may then be cemented to the formation. There are
a number of factors that go into the decision of whether to case
the wellbore 110 and whether to cement the casing to the formation.
A person of ordinary skill in the art should know whether the
wellbore 110 needs to be cased. In most cases, it will be
beneficial to do so.
[0037] The wellbore 110 may extend through a hydrocarbon-containing
subterranean formation area 112 and into a water-bearing area 114.
As used herein, the term "water" refers to any aqueous fluid and
may include, for example, fresh water, saltwater (e.g., water
containing one or more salts dissolved therein), brine (e.g.,
saturated saltwater), or any combination thereof. As is commonly
known in the art, there is generally no distinct water-hydrocarbon
boundary. The boundary may be more like an area composed of a
mixture of varying proportions of water and hydrocarbons. For the
purpose of description, the water-hydrocarbon boundary area is
illustrated as a broad line 116, it being understood, of course,
that the water-hydrocarbon boundary area may be much more irregular
and larger than the line. In an embodiment, the water may come from
a variety of sources, including but not limited to, in-situ water,
injected water, or water entering the reservoir from an external
source. For example, the water may be introduced into the formation
through an injection wellbore 124 that may inject water into the
reservoir through one or more fractures 126 as part of an EOR
operation.
[0038] The lower end of the wellbore is illustrated extending to a
location beneath the boundary 116. Typically, as hydrocarbons are
produced (removed) from the area surrounding the well, the water
boundary 116 rises until it is in contact with fractures at the
lower end of the wellbore 118. Indeed, hydrocarbons can be produced
at a rate that will cause the water boundary to extend upward or
"cone" around the wellbore, speeding up the production of
significant volumes of water with the hydrocarbons.
[0039] According to the present invention, a fracture 120 is opened
up to extend from the wellbore and may generally be located above
the water boundary 116. The fracture 120 in this case is generally
disk shaped extending from the wellbore 110 in all directions. As
will be described, fracturing technology exists to create open
fractures from wellbores extending in selected directions,
distances and having selected shapes. In an embodiment, the
fracture is formed to extend from all sides about 500 ft to about
1,000 ft from the wellbore though longer fractures may be possible.
In this embodiment, the fracture 120 is filled with a sealant 122.
Any fractures located below the water boundary, for example,
fracture 118, may also be filled with a sealant. The sealant 122
may be pumped into the fracture 120 as part of a treatment fluid,
for example, in a slurry form and also into any flow paths in the
form of voids intersecting the fracture 120.
[0040] One or more fractures may be formed in or along the wellbore
110 using a variety of techniques. In one exemplary embodiment, the
plurality of fractures are formed by using a hydra jetting tool,
such as that used in the SurgiFrac.RTM. fracturing service offered
by Halliburton Energy Services in Duncan, Okla. In this embodiment,
the hydra jetting tool forms each fracture, one at a time. Each
fracture may be formed by the following steps: (i) positioning the
hydra jetting tool in the wellbore at the location where the
fracture is to be formed, (ii) perforating the reservoir at the
location where the fracture is to be formed, and (iii) injecting a
fracture fluid into the perforation at sufficient pressure to form
a fracture along the perforation. As those of ordinary skill in the
art will appreciate, there are many variations on this embodiment.
For example, fracture fluid can be simultaneously pumped down the
annulus while it is being pumped out of the hydra jetting tool to
initiate the fracture. Alternatively, the fracturing fluid may be
pumped down the annulus and not through the hydra jetting tool to
initiate and propagate the fracture. In this version, the hydra
jetting tool primarily forms the perforations.
[0041] In an embodiment, one or more fractures may be formed by
staged fracturing. Staged fracturing may be performed by a method
comprising (i) detonating a charge in the wellbore 110 at the
location where a fracture is to be formed so as to form at least
one perforation in the reservoir at that location, (ii) pumping a
fracture fluid into the perforation at sufficient pressure to
propagate the fracture, (iii) installing a plug in the wellbore
uphole of the fracture, (iv) repeating steps (i) through (iii)
until the desired number of fractures have been formed; and (v)
removing the plugs following the completion of step (iv). As those
of ordinary skill in the art will appreciate, there are many
variants on the staged fracture method.
[0042] The fractures may take a variety of geometries including,
but not limited to, transverse fractures, longitudinal fractures
(e.g., curtain wall fractures), or fractures extending at an angle
with respect to the wellbore longitudinal axis (e.g., deviated
fractures that may extend along natural fracture lines). In some
embodiments, the fractures may be formed along natural fracture
lines and may generally be parallel to one another. The fracture's
shape, size and orientation can be determined by the orientation of
the fluid nozzles and movement thereof. Using hydrajetting radially
from a vertical wellbore, a transversely extending fracture can be
formed and may extend from about 50 ft to about 1000 ft from the
wellbore. In other applications such as water flooding,
longitudinal extending fractures (e.g., parallel to the wellbore)
may be formed to create a curtain wall fracture that may be used to
form a curtain wall in-situ barrier. In an embodiment, fractures
used to form in-situ barriers in multiple adjacent wells may be
used to form co-operating in-situ barriers.
[0043] After the wellbore 110 has been cased and a fracture has
been formed, the fracture may have a sealant disposed therein. The
sealant may be disposed in the fracture by squeezing it into the
fracture. This may be accomplished by first isolating the
perforations adjacent to the fracture using a packer (e.g., a
hydraulically set drillable, retrievable or inflatable packer) on
the end of tubing and setting the packer in the casing; then
pumping the sealant in a fluid state through the tubing, then
through the perforations and into the fracture to be sealed until a
sufficient volume of sealant has been placed into the transverse
fracture to provide the in-situ barrier to flow.
[0044] In an embodiment, the sealant used to provide the in-situ
barrier may be any material capable of selectively or
non-selectively reducing the flow of one or more fluids within a
subterranean formation. As used in this context a non-selective
barrier is an in-situ barrier intended to substantially seal the
fracture. A selective barrier is an in-situ barrier intended to
modify the permeability or relative permeability (as described
above) to allow fluids to selectively flow through the fracture.
The sealant may comprise a cement, a linear polymer mixture, a
linear polymer mixture with cross-linker, an in-situ polymerized
monomer mixture, a resin-based fluid, an epoxy based fluid, a
magnesium based slurry, a clay based slurry (e.g., a bentonite
based slurry), an emulsion, a precipitate (e.g., a polymeric
precipitate), or an in-situ precipitate. As used herein, an in-situ
precipitate is a precipitate formed within the subterranean
formation, for example, using a polymeric solution that is
introduced into a subterranean formation followed by an activator.
All of these sealants are capable of being placed in a fluid state
with the property of becoming a viscous fluid or solid barrier to
fluid migration after or during placement into the fracture. In one
embodiment, the sealant is H.sub.2Zero.TM. available from
Halliburton Energy Services, Inc., Duncan, Okla. Other sealants
could include particles, drilling mud, cuttings, and slag.
Exemplary particles could be ground cuttings so that a wide range
of particle sizes would exist and produce a low permeability as
compared to the surrounding reservoir. As used herein, the term
drilling mud includes all types of drilling mud known to those of
ordinary skill in the art including, but not limited to, oil based
muds, invert emulsions, polymer based muds, clay based muds (e.g.,
bentonite based drilling mud), and weighted muds.
[0045] In an embodiment, the sealant may comprise swellable
particles. As used herein, a particle is characterized as swellable
when it swells upon contact with an aqueous fluid (e.g., water), an
oil-based fluid (e.g., oil), or a gas. Suitable swellable particles
are described in the following references, each of which is
incorporated by reference herein in its entirety: U.S. Pat. No.
3,385,367, U.S. Pat. No. 7,059,415, U.S. Pat. No. 7,578,347, U.S.
Pat. App. No. 2004/0020662, U.S. Pat. App. No. 2007/0246225, U.S.
Pat. App. No. 2009/0032260 and WO2005/116394.
[0046] Swellable particles suitable for use with embodiments of the
present invention may generally swell by up to about 200% of their
original size at the surface. Under downhole conditions, this
swelling may be more, or less, depending on the conditions present.
For example, the swelling may be at least 10% under downhole
conditions. In some embodiments, the swelling may be up to about
50% under downhole conditions. Although the rate of swelling may be
hours in some embodiments, in certain embodiments the rate of
swelling may be measured in minutes. The rate of swelling is
defined as the amount of time required for the swelled composition
to substantially reach an equilibrium state, where swelling is
within 5% of its final equilibrium state. However, as those of
ordinary skill in the art, with the benefit of this disclosure,
will appreciate, the actual swelling when the swellable particles
are included in a sealant may depend on, for example, the
concentration of the swellable particles included in the sealant,
the temperature, the pressure, and the other components present in
the wellbore.
[0047] An example of a swellable particle that may be suitable for
use with embodiments of the present invention comprises a swellable
elastomer that swells in the presence of an oil-based fluid or an
aqueous-based fluid. Some specific examples of suitable swellable
elastomers that swell in the presence of an oil-based fluids
include, but are not limited to, natural rubbers, acrylate
butadiene rubbers, isoprene rubbers, chloroprene rubbers, butyl
rubbers, brominated butyl rubbers, chlorinated butyl rubbers,
chlorinated polyethylenes, neoprene rubbers, styrene butadiene
copolymer rubbers, chlorinated polyethylene, sulphonated
polyethylenes, ethylene acrylate rubbers, epichlorohydrin ethylene
oxide copolymers, epichlorohydrin terpolymer, ethylene-propylene
rubbers, ethylene vinyl acetate copolymers,
ethylene-propylene-diene terpolymer rubbers, ethylene vinyl acetate
copolymer, nitrile rubbers, acrylonitrile butadiene rubbers,
hydrogenated acrylonitrile butadiene rubbers, carboxylated
high-acrylonitrile butadiene copolymers, polyvinylchloride-nitrile
butadiene blends, fluorosilicone rubbers, silicone rubbers, poly
2,2,1-bicyclo heptenes (polynorbornene), alkylstyrenes,
polyacrylate rubbers such as ethylene-acrylate copolymer,
ethylene-acrylate terpolymers, fluorocarbon polymers, copolymers of
poly(vinylidene fluoride) and hexafluoropropylene, terpolymers of
poly(vinylidene fluoride), hexafluoropropylene, and
tetrafluoroethylene, terpolymers of poly(vinylidene fluoride),
polyvinyl methyl ether and tetrafluoroethylene, perfluoroelastomers
such as tetrafluoroethylene perfluoroelastomers, highly fluorinated
elastomers, butadiene rubber, polychloroprene rubber, polyisoprene
rubber, polynorbornenes, polysulfide rubbers, polyurethanes,
silicone rubbers, vinyl silicone rubbers, fluoromethyl silicone
rubber, fluorovinyl silicone rubbers, phenylmethyl silicone
rubbers, styrene-butadiene rubbers, copolymers of isobutylene and
isoprene known as butyl rubbers, brominated copolymers of
isobutylene and isoprene, chlorinated copolymers of isobutylene and
isoprene, and any combination thereof. An example of a commercially
available product comprising such swellable particles may include a
commercially available product from Easy Well Solutions of Norway,
under the trade name "EASYWELL."
[0048] Suitable examples of useable fluoroelastomers that swell in
the presence of an oil-based fluid are copolymers of vinylidene
fluoride and hexafluoropropylene and terpolymers of vinylidene
fluoride, hexafluoropropylene and tetrafluoroethylene. The
fluoroelastomers suitable for use in the disclosed invention are
elastomers that may comprise one or more vinylidene fluoride units
("VF.sub.2" or "VdF"), one or more hexafluoropropylene units
("HFP"), one or more tetrafluoroethylene units ("TFE"), one or more
chlorotrifluoroethylene ("CTFE") units, and/or one or more
perfluoro(alkyl vinyl ether) units ("PAVE"), such as
perfluoro(methyl vinyl ether) ("PMVE"), perfluoro(ethyl vinyl
ether) ("PEVE"), and perfluoropropyl vinyl ether ("PPVE"). These
elastomers can be homopolymers or copolymers. Particularly suitable
are fluoroelastomers containing vinylidene fluoride units,
hexafluoropropylene units, and, optionally, tetrafluoroethylene
units and fluoroelastomers containing vinylidene fluoride units,
perfluoroalkyl perfluorovinyl ether units, and tetrafluoroethylene
units, such as the vinylidene fluoride type fluoroelastomer known
under the trade designation "AFLAS.RTM." available from Asahi Glass
Co., Ltd. Of Tokyo, Japan. Especially suitable are copolymers of
vinylidene fluoride and hexafluoropropylene units. If the
fluoropolymers contain vinylidene fluoride units, the polymers may
contain up to 40 mole % VF.sub.2 units, e.g., 30-40 mole %. If the
fluoropolymers contain hexafluoropropylene units, the polymers may
contain up to 70 mole % HFP units. If the fluoropolymers contain
tetrafluoroethylene units, the polymers may contain up to 10 mole %
TFE units. When the fluoropolymers contain chlorotrifluoroethylene
the polymers may contain up to 10 mole % CTFE units. When the
fluoropolymers contain perfluoro(methyl vinyl ether) units, the
polymers may contain up to 5 mole % PMVE units. When the
fluoropolymers contain perfluoro(ethyl vinyl ether) units, the
polymers may contain up to 5 mole % PEVE units. When the
fluoropolymers contain perfluoro(propyl vinyl ether) units, the
polymers may contain up to 5 mole % PPVE units. The fluoropolymers
may contain 66%-70% fluorine. One suitable commercially available
fluoroelastomer is that known under the trade designation
"TECHNOFLON FOR HS.RTM." sold by Ausimont USA of Thorofare, N.J.
This material contains "Bisphenol AF" manufactured by Halocarbon
Products Corp. of River Edge, N.J. Another commercially available
fluoroelastomer is known under the trade designation "VITON.RTM. AL
200," by DuPont Performance Elastomers of La Place, La., which is a
terpolymer of VF.sub.2, HFP, and TFE monomers containing 67%
fluorine. Another suitable commercially available fluoroelastomer
is "VITON.RTM. AL 300," by DuPont Performance Elastomers of La
Place, La. A blend of the terpolymers known under the trade
designations "VITON.RTM. AL 300" and "VITON.RTM. AL 600" can also
be used (e.g., one-third AL-600 and two-thirds AL-300); both are
available from DuPont Performance Elastomers of La Place, La. Other
useful elastomers include products known under the trade
designations "7182B" and "7182D" from Seals Eastern of Red Bank,
N.J.; the product known under the trade designation "FL80-4"
available from Oil States Industries, Inc. of Arlington, Tex.; and
the product known under the trade designation "DMS005" available
from Duromould, Ltd. of Londonderry, Northern Ireland.
[0049] One process for making a swellable elastomer useful in the
present invention may involve grafting an unsaturated organic acid
molecule. A common example of an unsaturated organic acid used for
this purpose is maleic acid. Other molecules that can be used
include mono- and di-sodium salts of maleic acid and potassium
salts of maleic acid. Although in principle other unsaturated
carboxylic acids may also be grafted onto commercial unsaturated
elastomers, acids that exist in solid form may not require
additional steps or manipulation, as will be readily apparent to
those having reasonable skill in the chemical art. Mixing other
unsaturated acids such as acrylic acid and methacrylic acid is also
possible but may be more difficult since they are liquids at room
temperature. Unsaturated acids such as palmitoleic acid, oleic
acid, linoleic acid, and linolenic acid may also be used. The
initial reaction leads to a relatively non-porous "acid-grafted
rubber." In order to enhance the swelling of elastomers, addition
of a small amount of alkali such as soda ash, along with or
separate from the unsaturated acid, leads to formation of a porous,
swellable acid grafted rubber. Micro-porosities are formed in the
composition, allowing a fluid to rapidly reach the interior region
of a molded part and increase the rate and extent of swelling. An
organic peroxide vulcanizing agent may be employed to produce a
vulcanized, porous, swellable acid-grafted rubber formulation. In
one embodiment, 100 phr of EPDM, 5-100 phr of maleic acid, 5-50 phr
of sodium carbonate, and 1-10 phr of dicumyl peroxide as
vulcanizing agent showed at least 150 percent swelling of elastomer
when exposed to both water at 100.degree. C. for 24 hrs and at room
temperature for 24 hrs in kerosene. Other commercially available
grades of organic peroxides, as well as other vulcanization agents,
may be employed. The resulting elastomeric compositions may be
described as non-porous, or porous and swelled, acid-grafted
rubbers, which may or may not be vulcanized. The terms "vulcanized"
and "crosslinked" are used interchangeably herein, although
vulcanization technically refers to a physicochemical change
resulting from crosslinking of the unsaturated hydrocarbon chain of
polyisoprene with sulfur, usually with the application of heat. The
relatively hydrophobic linear or branched chain polymers and
relatively hydrophilic water-soluble monomers, either grafted onto
the polymer backbone or blended therein, may act together to
cost-effectively increase the water- and/or oil-swellability of
oilfield elements that comprise one or more apparatus of the
invention. In particular, the use of unsaturated organic acids,
anhydrides, and their salts (for example maleic acid, maleic
anhydride, and theirs salts), offer a commercially feasible way to
develop inexpensive composites materials with good water, and/or
hydrocarbon fluid swellability, depending on the type of inorganic
additives and monomers used.
[0050] Elastomers such as nitrile rubber, hydrogenated nitrile
rubber (HNBR), fluoroelastomers, or acrylate-based elastomers, or
their precursors, if added in variable amounts to an EPDM polymer
or its precursor monomer mixture, along with a sufficient amount
(from about 1 to 10 phr) of an unsaturated organic acid, anhydride,
or salt thereof, such as maleic acid, optionally combined with a
sufficient amount (from 1 about to 10 phr) an inorganic swelling
agent such as sodium carbonate, may produce a water-swellable
elastomer having variable low-oil swellability. Addition to the
monomer mixture, or to the elastomer after polymerization, of a
sufficient amount (from about 0.5 to 5 phr) of a highly acidic
unsaturated compound such as 2-acrylamido-2-methylpropane sulfonic
acid (AMPS), results in a water-swellable elastomer having variable
oil-swellability, and which is further swellable in low pH fluids
such as completion fluids containing zinc bromide. A second
addition of a sufficient amount (from 1 to 10 phr more than the
original addition) of inorganic swelling agent enhances
swellability in low pH, high concentration brines. Finally, the
addition of a sufficient amount (from 1 to 20 phr) of zwitterionic
polymer or copolymer of a zwitterionic monomer with an unsaturated
monomer, results in a cross-linked elastomer. The amounts of the
various ingredients at each stage may be varied as suited for the
particular purpose at hand. For example, if one simply wishes to
produce a highly cross-linked, moderately water-swellable (about
100 percent swell) elastomer having very low oil-swellability but
very high swellability in low pH fluids, one would use a recipe of
60 to 80 phr of EPDM, and 20 to 40 phr of nitrile or HNBR, and 4 to
5 phr of AMPS, as well as about 15 to 20 phr of a zwitterionic
polymer or monomer.
[0051] Another reaction scheme useful in the present invention,
enabling a low-cost procedure for making swellable elastomers,
involves the use of AMPS monomer and like sulfonic acid monomers.
Since AMPS monomer is chemically stable up to at least 350.degree.
F. (177.degree. C.), mixtures of EPDM and AMPS monomer which may or
may not be grafted on to EPDM will function as a high-temperature
resistant water-swellable elastomer. The use of AMPS and like
monomers maybe used in like fashion to functionalize any commercial
elastomer to make a high-temperature water-swellable elastomer. An
advantage of using AMPS is that it is routinely used in oilfield
industry in loss circulation fluids and is very resistant to down
hole chemicals and environments.
[0052] Other swellable elastomers that behave in a similar fashion
with respect to aqueous fluids also may be suitable. Some specific
examples of suitable swellable elastomers that swell in the
presence of an aqueous-based fluid, include, but are not limited to
starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic
acid anhydride graft copolymer, polyacrylamide, poly(acrylic
acid-co-acrylamide), poly(2-hydroxyethyl methacrylate),
poly(2-hydroxypropyl methacrylate), isobutylene maleic anhydride,
acrylic acid type polymers, vinylacetate-acrylate copolymer,
polyethylene oxide polymers, carboxymethyl cellulose type polymers,
starch-polyacrylonitrile graft copolymers and the like, and highly
swelling clay minerals such as sodium bentonite having
montmorillonite as main ingredient, and any combination
thereof.
[0053] Additional water swellable particles may comprise
particulate matter embedded in a matrix material. One example of
such particulate matter is salt, preferably dissociating salt,
which can be uniformly compounded into a base rubber. Suitable
salts may include, but are not limited to, acetates, bicarbonates,
carbonates, formates, halides (M.times.Hy) (H=Cl, Br or I),
hydrosulphides, hydroxides, imides, nitrates, nitrides, nitrites,
phosphates, sulphides, sulphates, and any combination thereof.
Also, other salts can be applied wherein the cation is a non-metal
like NH.sub.4Cl. CaCl.sub.2 may be useful in view of its divalent
characteristic and because of its reduced tendency to leach out
from a base rubber due to reduced mobility of the relatively large
Ca atom in the base rubber.
[0054] To limit leaching out of the salt from the swellable
elastomer, suitably the swellable particles include a hydrophilic
polymer containing polar groups of either oxygen or nitrogen in the
backbone or side groups of the polymer matrix material. These side
groups can be partially or fully neutralized. Hydrophilic polymers
of such type are, for example, alcohols, acrylates, methacrylates,
acetates, aldehydes, ketones, sulfonates, anhydrides, maleic
anhydrides, nitriles, acrylonitriles, amines, amides, oxides
(polyethylene oxide), cellulose types including all derivatives of
these types, all copolymers including one of the above all grafted
variants. In one instance, a ternary system may be applied which
includes an elastomer, a polar SAP and a salt, whereby the polar
SAP is grafted onto the backbone of the elastomer. Such system has
the advantage that the polar SAP particles tend to retain the salt
particles in the elastomer matrix thereby reducing leaching of the
salt from the elastomer. The polar salt is attracted by
electrostatic forces to the polar SAP molecules which are grafted
onto the backbone of the rubber.
[0055] Combinations of suitable swellable elastomers may also be
used. In certain embodiments, some of the elastomers that swell in
oil-based fluids may also swell in aqueous-based fluids. Suitable
elastomers that may swell in both aqueous-based and oil-based
fluids, include, but are not limited to ethylene propylene rubbers,
ethylene-propylene-diene terpolymer rubbers, butyl rubbers,
brominated butyl rubbers, chlorinated butyl rubbers, chlorinated
polyethylene, neoprene rubbers, styrene butadiene copolymer
rubbers, sulphonated polyethylenes, ethylene acrylate rubbers,
epichlorohydrin ethylene oxide copolymer, silicone rubbers and
fluorosilicone rubbers, and any combination thereof. Those of
ordinary skill in the art, with the benefit of this disclosure,
will know the appropriate fluid to use in order to swell the a
particular swellable elastomer composition.
[0056] In certain embodiments, the swellable elastomers may be
crosslinked and/or lightly crosslinked. Other swellable elastomers
that behave in a similar fashion with respect to fluids may also be
suitable. Those of ordinary skill in the art, with the benefit of
this disclosure, will be able to select appropriate swellable
elastomers based on a variety of factors, including the application
in which the composition will be used and the desired swelling
characteristics.
[0057] Where used, the swellable particles generally may be
included in the embodiments of the sealant in an amount sufficient
to provide the desired barrier properties. In some embodiments, the
swellable particles may be placed in a fracture or void in a
treatment fluid comprising an amount up to about 50% by volume of
the treatment fluid. In some embodiments, the swellable particles
may be present in a range of about 5% to about 95% by volume of the
treatment fluid used to place the particles.
[0058] In addition, the swellable particles that are utilized may
have a wide variety of shapes and sizes of individual particles
suitable for use 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.
[0059] In an embodiment, the sealant may comprise a cement. Any
suitable cement known in the art may be used as the sealant. An
example of a suitable cement includes hydraulic cement, which may
comprise calcium, aluminum, silicon, oxygen, and/or sulfur and
which sets and hardens by reaction with water. Examples of
hydraulic cements include, but are not limited to a Portland
cement, a pozzolan cement, a gypsum cement, a high alumina content
cement, a silica cement, a high alkalinity cement, or combinations
thereof. Preferred hydraulic cements are Portland cements of the
type described in American Petroleum Institute (API) Specification
10, 5.sup.th Edition, Jul. 1, 1990, which is incorporated by
reference herein in its entirety. The cement may be, for example, a
class A, B, C, G, or H Portland cement. Another example of a
suitable cement is microfine cement, for example, MICRODUR RU
microfine cement available from Dyckerhoff GmBH of Lengerich,
Germany. Combinations of cements and swellable particles may also
be used.
[0060] In an embodiment, the sealant may comprise a water soluble
relative permeability modifier. As used herein, "relative
permeability modifier" refers to a compound that is capable of
reducing the permeability of a subterranean formation to
aqueous-based fluids without substantially changing its
permeability to hydrocarbons. Generally, the water-soluble relative
permeability modifiers suitable for use with the present invention
may be any suitable water-soluble relative permeability modifier
that is suitable for use in subterranean operations. In some
embodiments, the water-soluble relative permeability modifiers
comprise a hydrophobically modified polymer. As used herein,
"hydrophobically modified" refers to the incorporation into the
hydrophilic polymer structure of hydrophobic groups, wherein the
alkyl chain length is from about 4 to about 22 carbons. In other
embodiments, the water-soluble relative permeability modifiers
comprise a hydrophilically modified polymer. As used herein,
"hydrophilically modified" refers to the incorporation into the
hydrophilic polymer structure of hydrophilic groups. In yet another
embodiment, the water-soluble relative permeability modifiers
comprise a water-soluble polymer without hydrophobic or hydrophilic
modification.
[0061] The hydrophobically modified polymers suitable for use in
the present invention typically have molecular weights in the range
of from about 100,000 to about 10,000,000. In some embodiments, a
mole ratio of a hydrophilic monomer to the hydrophobic compound in
the hydrophobically modified polymer is in the range of from about
99.98:0.02 to about 90:10, wherein the hydrophilic monomer is a
calculated amount present in the hydrophilic polymer. In certain
embodiments, the hydrophobically modified polymers may comprise a
polymer backbone, the polymer backbone comprising polar
heteroatoms. Generally, the polar heteroatoms present within the
polymer backbone of the hydrophobically modified polymers include,
but are not limited to, oxygen, nitrogen, sulfur, or
phosphorous.
[0062] In an embodiment, the hydrophobically modified polymers may
be a reaction product of a hydrophilic polymer and a hydrophobic
compound. The hydrophilic polymers suitable for forming the
hydrophobically modified polymers used in the present invention
should be capable of reacting with hydrophobic compounds. Suitable
hydrophilic polymers include, homo-, co-, or terpolymers such as,
but not limited to, polyacrylamides, polyvinylamines,
poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in
general. Additional examples of alkyl acrylate polymers include,
but are not limited to, polydimethy laminoethyl methacrylate,
polydimethylaminopropyl methacrylamide,
poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic
acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl
propane sulfonic acid/dimethylaminoethyl methacrylate),
poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylic
acid/dimethylaminopropyl methacrylamide), and poly(methacrylic
acid/dimethylaminopropyl methacrylamide). In certain embodiments,
the hydrophilic polymers comprise a polymer backbone and reactive
amino groups in the polymer backbone or as pendant groups, the
reactive amino groups capable of reacting with hydrophobic
compounds. In some embodiments, the hydrophilic polymers comprise
dialkyl amino pendant groups. In some embodiments, the hydrophilic
polymers comprise a dimethyl amino pendant group and at least one
monomer comprising dimethylaminoethyl methacrylate or
dimethylaminopropyl methacrylamide. In certain embodiments, the
hydrophilic polymers comprise a polymer backbone, the polymer
backbone comprising polar heteroatoms, wherein the polar
heteroatoms present within the polymer backbone of the hydrophilic
polymers include, but are not limited to, oxygen, nitrogen, sulfur,
or phosphorous. Suitable hydrophilic polymers that comprise polar
heteroatoms within the polymer backbone include homo-, co-, or
terpolymers, such as, but not limited to, celluloses, chitosans,
polyamides, polyetheramines, polyethyleneimines,
polyhydroxyetheramines, polylysines, polysulfones, gums, starches,
and derivatives thereof. In one embodiment, the starch is a
cationic starch. A suitable cationic starch may be formed by
reacting a starch, such as corn, maize, waxy maize, potato, and
tapioca, and the like, with the reaction product of epichlorohydrin
and trialkylamine.
[0063] The hydrophobic compounds that are capable of reacting with
the hydrophilic polymers include, but are not limited to, alkyl
halides, sulfonates, sulfates, and organic acid derivatives.
Examples of suitable organic acid derivatives include, but are not
limited to, octenyl succinic acid; dodecenyl succinic acid; and
anhydrides, esters, and amides of octenyl succinic acid or
dodecenyl succinic acid. In certain embodiments, the hydrophobic
compounds may have an alkyl chain length of from about 4 to about
22 carbons. For example, where the hydrophobic compound is an alkyl
halide, the reaction between the hydrophobic compound and
hydrophilic polymer may result in the quaternization of at least
some of the hydrophilic polymer amino groups with an alkyl halide,
wherein the alkyl chain length is from about 4 to about 22
carbons.
[0064] In other embodiments, the hydrophobically modified polymers
used in the present invention may be prepared from the
polymerization reaction of at least one hydrophilic monomer and at
least one hydrophobically modified hydrophilic monomer. Examples of
suitable methods of their preparation are described in U.S. Pat.
No. 6,476,169, the disclosure of which is incorporated herein by
reference in its entirety.
[0065] A variety of hydrophilic monomers may be used to form the
hydrophobically modified polymers useful in the present invention.
Examples of suitable hydrophilic monomers include, but are not
limited to homo-, co-, and terpolymers of acrylamide,
2-acrylamido-2-methyl propane sulfonic acid,
N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl
methacrylate, acrylic acid, dimethylaminopropylmethacrylamide,
vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate
chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic
acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam,
N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium
halide, itaconic acid, styrene sulfonic acid,
methacrylamidoethyltrimethyl ammonium halide, quaternary salt
derivatives of acrylamide, and quaternary salt derivatives of
acrylic acid.
[0066] A variety of hydrophobically modified hydrophilic monomers
also may be used to form the hydrophobically modified polymers
useful in the present invention. Examples of suitable
hydrophobically modified hydrophilic monomers include, but are not
limited to, alkyl acrylates, alkyl methacrylates, alkyl
acrylamides, alkyl methacrylamides alkyl dimethylammoniumethyl
methacrylate halides, and alkyl dimethylammoniumpropyl
methacrylamide halides, wherein the alkyl groups have from about 4
to about 22 carbon atoms. In certain embodiments, the
hydrophobically modified hydrophilic monomer comprises
octadecyldimethylammoniumethyl methacrylate bromide,
hexadecyldimethylammoniumethyl methacrylate bromide,
hexadecyldimethylammoniumpropyl methacrylamide bromide,
2-ethylhexyl methacrylate, or hexadecyl methacrylamide.
[0067] The hydrophobically modified polymers formed from the
above-described polymerization reaction may have estimated
molecular weights in the range of from about 100,000 to about
10,000,000 and mole ratios of the hydrophilic monomer(s) to the
hydrophobically modified hydrophilic monomer(s) in the range of
from about 99.98:0.02 to about 90:10. Suitable hydrophobically
modified polymers having molecular weights and mole ratios in the
ranges set forth above include, but are not limited to,
acrylamide/octadecyldimethylammoniumethyl methacrylate bromide
copolymer, dimethylaminoethyl
methacrylate/hexadecyldimethylammoniumethyl methacrylate bromide
copolymer, dimethylaminoethyl methacrylate/vinyl
pyrrolidone/hexadecyldimethylammoniumethyl methacrylate bromide
terpolymer and acrylamide/2-acrylamido-2-methyl propane sulfonic
acid/2-ethylhexyl methacrylate terpolymer.
[0068] In other embodiments, the water-soluble relative
permeability modifiers comprise a hydrophilically modified polymer.
The hydrophilically modified polymers suitable for use with the
present invention typically have molecular weights in the range of
from about 100,000 to about 10,000,000. In certain embodiments, the
hydrophilically modified polymers comprise a polymer backbone, the
polymer backbone comprising polar heteroatoms. Generally, the polar
heteroatoms present within the polymer backbone of the
hydrophilically modified polymers include, but are not limited to,
oxygen, nitrogen, sulfur, or phosphorous.
[0069] In certain embodiments, the hydrophilically modified polymer
may be a reaction product of a hydrophilic polymer and a
hydrophilic compound. The hydrophilic polymers suitable for forming
the hydrophilically modified polymers used in the present invention
should be capable of reacting with hydrophilic compounds. In
certain embodiments, suitable hydrophilic polymers include, homo-,
co-, or terpolymers, such as, but not limited to, polyacrylamides,
polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl
acrylate polymers in general. Additional examples of alkyl acrylate
polymers include, but are not limited to, polydimethylaminoethyl
methacrylate, polydimethylaminopropyl methacrylamide,
poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic
acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl
propane sulfonic acid/dimethylaminoethyl methacrylate),
poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylic
acid/dimethylaminopropyl methacrylamide), and poly(methacrylic
acid/dimethylaminopropyl methacrylamide). In certain embodiments,
the hydrophilic polymers comprise a polymer backbone and reactive
amino groups in the polymer backbone or as pendant groups, the
reactive amino groups capable of reacting with hydrophilic
compounds. In some embodiments, the hydrophilic polymers comprise
dialkyl amino pendant groups. In some embodiments, the hydrophilic
polymers comprise a dimethyl amino pendant group and at least one
monomer comprising dimethylaminoethyl methacrylate or
dimethylaminopropyl methacrylamide. In other embodiments, the
hydrophilic polymers comprise a polymer backbone comprising polar
heteroatoms, wherein the polar heteroatoms present within the
polymer backbone of the hydrophilic polymers include, but are not
limited to, oxygen, nitrogen, sulfur, or phosphorous. Suitable
hydrophilic polymers that comprise polar heteroatoms within the
polymer backbone include homo-, co-, or terpolymers, such as, but
not limited to, celluloses, chitosans, polyamides, polyetheramines,
polyethyleneimines, polyhydroxyetheramines, polylysines,
polysulfones, gums, starches, and derivatives thereof. In one
embodiment, the starch is a cationic starch. A suitable cationic
starch may be formed by reacting a starch, such as corn, maize,
waxy maize, potato, tapioca, and the like, with the reaction
product of epichlorohydrin and trialkylamine.
[0070] The hydrophilic compounds suitable for reaction with the
hydrophilic polymers include polyethers that comprise halogens;
sulfonates; sulfates; and organic acid derivatives. Examples of
suitable polyethers include, but are not limited to, polyethylene
oxides, polypropylene oxides, and polybutylene oxides, and
copolymers, terpolymers, and mixtures thereof. In some embodiments,
the polyether comprises an epichlorohydrin-terminated polyethylene
oxide methyl ether.
[0071] The hydrophilically modified polymers formed from the
reaction of a hydrophilic polymer with a hydrophilic compound may
have estimated molecular weights in the range of from about 100,000
to about 10,000,000 and may have weight ratios of the hydrophilic
polymers to the polyethers in the range of from about 1:1 to about
10:1. Suitable hydrophilically modified polymers having molecular
weights and weight ratios in the ranges set forth above include,
but are not limited to, the reaction product of
polydimethylaminoethyl methacrylate and epichlorohydrin-terminated
polyethyleneoxide methyl ether; the reaction product of
polydimethylaminopropyl methacrylamide and
epichlorohydrin-terminated polyethyleneoxide methyl ether; and the
reaction product of poly(acrylamide/dimethylaminopropyl
methacrylamide) and epichlorohydrin-terminated polyethyleneoxide
methyl ether. In some embodiments, the hydrophilically modified
polymer comprises the reaction product of a polydimethylaminoethyl
methacrylate and epichlorohydrin-terminated polyethyleneoxide
methyl ether having a weight ratio of polydimethylaminoethyl
methacrylate to epichlorohydrin-terminated polyethyleneoxide methyl
ether of about 3:1.
[0072] In yet other embodiments, the water-soluble relative
permeability modifiers comprise a water-soluble polymer without
hydrophobic or hydrophilic modification. Examples of suitable
water-soluble polymers without hydrophobic or hydrophilic
modification include, but are not limited to, homo-, co-, and
terpolymers of acrylamide, 2-acrylamido-2-methyl propane sulfonic
acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl
methacrylate, acrylic acid, dimethylaminopropylmethacrylamide,
vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate
chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic
acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam,
N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium
halide, itaconic acid, styrene sulfonic acid,
methacrylamidoethyltrimethyl ammonium halide, quaternary salt
derivatives of acrylamide, and quaternary salt derivatives of
acrylic acid.
[0073] In an embodiment, a hydrocarbon reservoir in a subterranean
formation may have one or more producing wells. In addition, the
hydrocarbon reservoir may have one or more injection wells for
providing a fluid source to supply a driving force for the
production of hydrocarbons. As used herein, a "fluid source" refers
to any source of one or more fluids that flow through the
subterranean formation between perforations or fractures in an
individual wellbore or between separate wellbores. An injection
wells may be drilled for the specific purpose of injecting fluids
to provide the fluid source, or an existing wellbore may be
converted from producing wells to injecting wells. In another
embodiment, a natural fluid source that provides a driving force
may be present in the subterranean formation in the form of
existing water, external water entering the reservoir, or natural
gas pressure within the subterranean formation. Alternatively,
water may flow into the subterranean formation from a nearby water
source (e.g., an edge water aquifer) to create a fluid source that
provides a driving force within the subterranean formation. In this
case, the subterranean formation may not require injection wells
for the production of hydrocarbons.
[0074] The flow of hydrocarbon fluids within the reservoir may be
modified through the use of an in-situ barrier comprising a
fracture containing a sealant. The use of an in-situ barrier with
selective or non-selective barriers to flow may be used to modify
the flow pattern within an entire reservoir. In an embodiment, a
relative permeability modifier may allow oil to selectively flow
through the in-situ barrier in relation to an aqueous fluid. In
another embodiment, a plurality of in-situ barriers may have
varying permeabilities, whose placement and geometries, may act as
a series of barriers or baffles to guide the flow of at least one
desired fluid to a producing well. Without intending to be limited
by theory, it is believed that a plurality of selectively placed
fractures with selective or non-selective barriers to fluid flow
may be used to modify the flow regime inside the hydrocarbon
reservoir to improve the volumetric sweep efficiency of the
hydrocarbons in the formation. Further, the sealant and fluid used
to provide the driving force for flow and sweep of the hydrocarbon
fluids can be selected to maximize the amount of hydrocarbons
recovered in a hydrocarbon reservoir. The flow patterns within a
hydrocarbon reservoir may be determined through the use of a
simulator program using any simulator capable of calculating the
flow regime within a subterranean environment. Suitable simulators
for use in hydrocarbon reservoirs are known to those skilled in the
art.
[0075] In an embodiment shown in FIG. 1, an injection well 124 may
be drilled remote from, but generally parallel to, existing well
110. In an embodiment, wellbore 110 may be drilled for the purpose
of modifying the flow pattern of at least one fluid within the
subterranean reservoir. In one certain embodiment, injection well
124 is drilled proximate the sealed fractures 118, 120. As those of
ordinary skill in the art will appreciate, the injection well 124
can alternatively be formed prior to the formation of the wellbore
110, or may be a converted producing wellbore. Once the injection
well 124 has been formed and the selected fracture or fractures
118, 120 sealed, flood fluid can be pumped down the injection well
124. As the flood fluid is pumped into the reservoir 112 it forms a
propagating flood front. The flood front may be diverted around the
sealed fracture 120. At the same time, hydrocarbons are drained
into fractures 128. As the producing fracture 128 begins producing
high rates of flood fluid, it may be sealed. A bridge plug or other
zonal isolation device may be installed in the wellbore 110 just
uphole of the fracture 128 when the fracture is sealed. A new
producing fracture may then be created to further produce
hydrocarbons from the hydrocarbon reservoir. This isolation process
is repeated as sufficiently high flood fluid ratios are being
produced from successive transverse fractures until all of the
transverse fractures have been sealed.
[0076] In an embodiment, the flow of the fluids in a hydrocarbon
reservoir may be modified on a field-wide basis. The injection well
124 may be located in an existing injection pattern as known to
those of ordinary skill in the art. For example, existing 5-spot,
7-spot, or line drive injection patterns may have existing
injection wells for use in this method. As will be appreciate by
those of ordinary skill in the arts, the selection of a wellbore
for use as an injection well may change during the life of the
hydrocarbon reservoir. The producing wellbore 110 may be an
existing wellbore or may be drilled for the purpose of recovering
fluids. In another embodiment, the wellbore 110 and any fractures
associated with the wellbore 110 may be drilled or used for the
purpose of modifying the flow pattern of at least one fluid within
a subterranean reservoir without being used to produce a fluid. The
selection of fractures or locations for creating new fractures may
be chosen so as to increase the sweep efficiency of fluids moving
through the formation.
[0077] In one exemplary variant of the method illustrated in FIG.
1, the fracture 120 may only be partially sealed in the near
wellbore area rather than completely sealed all the way to its tip.
The benefit of sealing the near wellbore area is that if the
injection fluid happens to move faster in this area the flow of
injection fluid can be partially diverted to improve sweep.
[0078] Turning to FIG. 2, another embodiment of the method for
increasing hydrocarbon production in accordance with the present
invention is disclosed. In this embodiment, the flood fluid is
introduced into the reservoir 212 through a tubing 260, which is
installed into wellbore 224 rather than a separate injection well.
The tubing 260 injects the flood fluid into the reservoir 212 from
the toe 240 of the wellbore 224, which may include one or more
fractures 242 through which the fluid is injected into the
formation. Hydrocarbons may be produced through one or more
fractures 290 up the annulus 265 formed between the tubing 260 and
the casing 262. Packer 270 may be used to seal the end of the
tubing 260, so the flood fluid does not enter into the annulus 265.
In this embodiment, additional wellbores 210, 280 may be used to
produce fluids which may be driven at least in part by the fluids
injected from wellbore 224. These additional wellbores may have one
or more fractures 286, 288 with a sealant composition 222 placed
therein to affect the flow pattern in the hydrocarbon reservoir. As
will be appreciated by one of ordinary skill in the art, a
plurality of fractures of various shapes may be used to affect the
flow of fluids within the hydrocarbon reservoir. In another
embodiment, the wellbores 210, 280 and any fractures associated
with the wellbores (e.g., fractures 286, 288) may be drilled or
used for the purpose of modifying the flow pattern of at least one
fluid within a subterranean reservoir without being used to produce
a fluid. In this embodiment, additional wellbore (not shown in FIG.
2) may be used to produce one or more fluids from the subterranean
reservoir.
[0079] Once the flood fluid ratio reaches a sufficiently high
value, the fractures used for production 290 may be sealed using
the techniques described above and new production fractures or
perforations may be created. This process may be repeated for
successive fractures as the flood front 216 moves into the area
near a producing well.
[0080] Also disclosed herein is a system that may be useful for
increasing the production of hydrocarbons and/or reducing the
production of water from a subterranean formation. The system
generally comprises a fluid source within a subterranean formation
for providing a fluid driving force within the subterranean
formation, a wellbore disposed in the subterranean formation for
producing a production fluid from the subterranean formation, and
an in-situ barrier disposed within the subterranean formation,
where the in-situ barrier modifies the flow of at least one fluid
driven by the fluid driving force within the subterranean
formation. Each component of the system is as described above and
may include any of the optional features disclosed herein. As those
of ordinary skill in the art will appreciate from the disclosure,
there are many different ways of arranging and providing the wells,
the in-situ barriers to flow, and the fluid provided by the fluid
source, and many different ways of recovering the hydrocarbons from
the reservoir.
[0081] To facilitate a better understanding of the present
invention, the following examples of certain aspects of some
embodiments are given. In no way should the following examples be
read to limit, or define, the scope of the invention.
Example 1
[0082] A reservoir simulation is used to simulate an in-situ
barrier placed in a subterranean formation using a horizontal well
for this prophetic example. One such simulator is a numerical
finite difference simulator QuikLook version 4.1 provided by
Halliburton Energy Services, Inc. The horizontal well has a
production length of about 1560 ft. Input properties for the
subterranean formation simulation include: Area of 2600 ft by 2600
ft., thickness of 490 ft with an average formation porosity of
0.24, horizontal permeability in the longitudinal direction of 30
md, horizontal permeability in the latitudinal direction of 45 md
and vertical permeability of 3 md. The initial water saturation in
the oil zone is 0.37. There is an active edge and bottom-water
aquifer as the source of encroaching water flow to the producing
well.
[0083] FIG. 3 depicts a water saturation profile in the formation
after 911.476 days without an in-situ barrier using the reservoir
simulation. Water saturation is shown on a scale of 0.00 to 1.00
with 1.00 being 100% water saturation. The water saturation scale
is shown in the sidebar. The simulation results show that the water
front is beginning to break through to the production well.
[0084] For comparison, FIG. 4 depicts a water saturation profile in
the formation after 914.01 days with an in-situ barrier using the
reservoir simulation. The simulation results show that the water
front is being effectively blocked from the production well. Water
saturation, at about 914 days, is lower at the horizontal
production well than in the case without an in-situ barrier. The
increased sweep of the water is expected to result in an increased
production of hydrocarbons from the well.
[0085] FIG. 5 and FIG. 6 depict the total oil production and total
water production for both the base case without an in-situ barrier
and the comparison case with the in-situ barrier depicted in FIG.
4. The figures show the production of water is greater (line 508)
and the production of oil lower (line 502) without an in-situ
barrier as compared to the production of water (line 506) and the
production of oil (line 504) with an in-situ barrier. The increase
in oil production is about 5.4% and the decrease in water
production is about 6.41%. The increase in oil production is worth
millions of dollars and the decline in water production represents
a significant savings in the cost of waste water disposal.
Example 2
[0086] The same reservoir simulation described above in Example 1,
is used to simulate an injector and a producer in a line drive
configuration for this prophetic example. A well is located between
the injector and producer and is used to dispose an in-situ barrier
into the formation.
[0087] FIG. 7 depicts a side view of a water saturation profile in
the formation after about 3,614 days with an in-situ barrier using
the reservoir simulation. The simulation results show that the
water front is effectively slowed down by the in-situ barrier
between the injector and producer. FIG. 8 depicts an aerial view of
the water saturation profile shown in FIG. 7. FIG. 8 similarly
depicts that the water front is forced to move around the in-situ
barrier in the formation in order to reach the producing well.
[0088] FIG. 9 and FIG. 10 depict the total oil production and total
water production for the simulation shown in FIG. 7 and FIG. 8. In
addition to the simulation results shown in FIG. 7 and FIG. 8, FIG.
9 and FIG. 10 show the results for a simulation without an in-situ
barrier between the producer and injector and for a case in which
the in-situ barrier is moved closer to the producing well. FIG. 9
shows the production of oil is less without an in-situ barrier
(line 510) than either the case with an in-situ barrier (line 514)
or the closer in-situ barrier (line 512). FIG. 10 shows the
production of water is greater without an in-situ barrier (line
520) than either the case with an in-situ barrier (line 516) or the
closer in-situ barrier (line 518). The results indicate that over
about a 20 year production (about 7,300 days), the total oil
production can be increased by over 20% and the total water
production can be reduced by over about 40%. As one of ordinary
skill in the art would understand, this represents a significant
increase in the production of oil from the reservoir and a
significant reduction in the amount of waste water that must be
processed and disposed.
Example 3
[0089] The same reservoir simulation described above in Example 1,
is used to simulate a reservoir with a 5-spot well configuration
for this prophetic example. In this example, a well with an in-situ
barrier is modeled between the injector and a producer.
[0090] FIG. 11 depicts an aerial view of a water saturation profile
in the formation after about 6,378 days with an in-situ barrier
using the reservoir simulation. The simulation results show that
the water front is effectively forced to flow around the in-situ
barrier between the injector and producer. FIG. 12 depicts an
aerial view of the water saturation profile for the configuration
shown in FIG. 11 without an in-situ barrier. FIG. 11 shows that the
water front is further advanced without the in-situ barrier between
the injection well and production well.
[0091] FIG. 13 and FIG. 14 depict the total oil production and
total water production for the simulations shown in FIG. 11 and
FIG. 12. FIG. 13 shows the production of oil is less without an
in-situ barrier (line 522) than the case with an in-situ barrier
(line 524). FIG. 14 shows the production of water is greater
without an in-situ barrier (line 528) than the case with an in-situ
barrier (line 526). The results indicate that over about a 20 year
production, the total oil production can be increased by about 9%
and the total water production can be reduced by about 8% through
the use of an in-situ barrier. As one of ordinary skill in the art
would understand, this represents a significant increase in the
production of oil from the reservoir and a significant reduction in
the amount of waste water that must be processed and disposed.
Example 4
[0092] The same reservoir simulator described above in Example 1,
is used to simulate an in-situ barrier comprising a relative
permeability modifier for this prophetic example. The relative
permeability modifier comprises a compound that is capable of
reducing the permeability of a subterranean formation to
aqueous-based fluids without substantially changing its
permeability to hydrocarbons, as described above. The model also
assumes a change in the wettability of the fracture to be
preferentially oil-wet in the fracture creating a capillary barrier
to the entry of an aqueous fluid. The parameters are essentially
the same as for Example 1 with the additional inclusion of a
high-permeability channel of 500 md.
[0093] In this example, the flow of an aqueous fluid from a strong
edge-water aquifer into a formation penetrated by a horizontal well
is modeled. The horizontal well is modeled in a high permeability
channel in order to simulate a high influx of oil. Such a channel
also acts as a conduit for the influx of an aqueous fluid.
[0094] Three cases are used to model the results of about 2,000
days of production. The first case represented a base production
case with no in-situ barrier. The second case represented an
in-situ barrier that blocked both oil and water. The permeability
of the in-situ barrier is set at 1.times.10.sup.-6 millidarcy (md)
for the second case. Finally, the third case represented an in-situ
barrier using a relative permeability modifier that selectively
blocks the flow of an aqueous fluid relative to oil and affects the
oil-wet state of the formation. For the third case, the absolute
permeability of the in-situ barrier is set at 1 md.
[0095] FIG. 15 depicts an aerial view of a permeability profile in
the formation with respect to the horizontal wellbore and the
high-permeability channel. FIG. 16 depicts an aerial view of the
water saturation profile for the first case with no in-situ
barrier. This first case demonstrates the channeling of water along
the high permeability channel. FIG. 17 depicts an aerial view of a
water saturation profile for the second case comprising an in-situ
barrier. The simulation results show the coning of water around the
in-situ barrier and flowing along the high permeability channel to
the well bore. FIG. 18 depicts an aerial view of a water saturation
profile for the third case with an in-situ barrier comprising a
relative permeability modifier. The simulation results show the
flow of water blocked by the in-situ barrier and a lack of coning
due to the ability of the oil to flow through the barrier but not
the aqueous fluid.
[0096] The resulting cumulative production values after about 2,000
days of oil and water (in millions of barrels or MMBBL) are: 12.8
MMBBL of oil and 7.1 MMBBL of water for the first case with no
in-situ barrier, 17.1 MMBBL of oil and 2.8 MMBBL of water for the
second case with an in-situ barrier, and 18.7 MMBBL of oil and 1.3
MMBBL of water for the third case with an in-situ barrier
comprising a relative permeability modifier. This example shows
potential to "design" the absolute permeability, relative
permeability, and capillary pressure within a subterranean
formation to baffle water, while allowing oil to more
preferentially flow through the in-situ barrier to a producing
well. As one of ordinary skill in the art would understand, this
represents a significant increase in the production of oil from the
reservoir and a significant reduction in the amount of waste water
that must be processed and disposed.
Example 5
[0097] Using the same simulation as described in Example 1 using a
horizontal well with edge water drive, an in-situ barrier is
modeled using a partial flow barrier for this prophetic example.
The production is for about 4,000 days. No high permeability streak
is present in the model. Four cases were modeled to determine the
difference between the various types of in-situ barriers. The first
case was the base case without an in-situ barrier. In the second
case, a partial barrier is modeled having a permeability of 1md and
a relative permeability modifier is not present. In the third case,
a partial barrier is modeled having a permeability of 1md and a
relative permeability modifier is present. In the fourth case, the
in-situ barrier comprised a full barrier to the flow of fluids.
[0098] The resulting cumulative production values after about 4,000
days of oil and water (in millions of barrels or MMBBL) are: 28.8
MMBBL of oil and 11.2 MMBBL of water for the first case with no
in-situ barrier, 30.4 MMBBL of oil and 9.6 MMBBL of water for the
second case with an in-situ partial barrier, 30.7 MMBBL of oil and
9.3 MMBBL of water for the third case with an in-situ partial
barrier comprising a relative permeability modifier, and 30.7 MMBBL
of oil and 9.3 MMBBL of water for the fourth case with an in-situ
barrier comprising full barrier to flow. As one of ordinary skill
in the art would understand, this represents a significant increase
in the production of oil from the reservoir and a significant
reduction in the amount of waste water that must be processed and
disposed.
[0099] 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.
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. While compositions and methods are
described in terms of "comprising," "containing," or "including"
various components or steps, the compositions and methods can also
"consist essentially of" or "consist of" the various components and
steps. All numbers and ranges disclosed above may vary by some
amount. Whenever a numerical range with a lower limit and an upper
limit is disclosed, any number and any included range falling
within the range is specifically disclosed. In particular, every
range of values (of the form, "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 to set
forth every number and range encompassed within the broader range
of values. Also, the terms in the claims have their plain, ordinary
meaning unless otherwise explicitly and clearly defined by the
patentee. Moreover, the indefinite articles "a" or "an", as used in
the claims, are defined herein to mean one or more than one of the
element that it introduces. If there is any conflict in the usages
of a word or term in this specification and one or more patent or
other documents that may be incorporated herein by reference, the
definitions that are consistent with this specification should be
adopted.
* * * * *