U.S. patent application number 16/519846 was filed with the patent office on 2020-02-20 for boil-off gas recycle subsystem in natural gas liquefaction plants.
The applicant listed for this patent is ExxonMobil Upstream Research Company. Invention is credited to Brett L. Ryberg, Kenichi Tadano, Naoki Watanabe, Stephen Wright.
Application Number | 20200056838 16/519846 |
Document ID | / |
Family ID | 67544409 |
Filed Date | 2020-02-20 |
United States Patent
Application |
20200056838 |
Kind Code |
A1 |
Ryberg; Brett L. ; et
al. |
February 20, 2020 |
BOIL-OFF GAS RECYCLE SUBSYSTEM IN NATURAL GAS LIQUEFACTION
PLANTS
Abstract
A method of recycling liquefied natural gas (LNG) boil-off gas
(BOG) in natural gas liquefaction plants can include: supplying a
feed gas to a liquefaction subsystem; liquefying the feed gas to
produce LNG and end-flash gas (EFG); compressing the EFG to
compressed EFG; using the compressed EFG as fuel gas; storing the
LNG in one or more LNG tanks; compressing LNG BOG from the one or
more LNG tanks to produce compressed LNG BOG; and either (1)
operating in a recycle mode by supplying at least a portion of the
compressed LNG BOG to the feed gas via a bidirectional line, or (2)
operating in a fuel mode by (a) supplying a portion of the feed gas
to the fuel gas via the bidirectional line and (b) supplying the
compressed LNG BOG to the fuel gas.
Inventors: |
Ryberg; Brett L.; (The
Woodlands, TX) ; Wright; Stephen; (Georgetown,
TX) ; Tadano; Kenichi; (Yokohama, JP) ;
Watanabe; Naoki; (Yokohama, JP) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
ExxonMobil Upstream Research Company |
Spring |
TX |
US |
|
|
Family ID: |
67544409 |
Appl. No.: |
16/519846 |
Filed: |
July 23, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62718742 |
Aug 14, 2018 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
F25J 2245/90 20130101;
F25J 1/0269 20130101; F25J 2210/90 20130101; F25J 2210/60 20130101;
F25J 2290/62 20130101; F25J 2230/08 20130101; F25J 1/0022 20130101;
F25J 1/0025 20130101; F25J 1/0279 20130101; F25J 1/023 20130101;
F25J 1/0245 20130101; F25J 2210/02 20130101; F28F 13/04
20130101 |
International
Class: |
F25J 1/00 20060101
F25J001/00; F25J 1/02 20060101 F25J001/02; F28F 13/04 20060101
F28F013/04 |
Claims
1. A natural gas liquefaction plant comprising: a feed gas line
fluidly connected to a liquefaction subsystem to supply feed gas to
the liquefaction subsystem; a liquefied natural gas (LNG) line
fluidly connecting the liquefaction subsystem to one or more LNG
tanks to supply LNG from the liquefaction subsystem to the one or
more LNG tanks; an end-flash gas (EFG) line fluidly connecting the
liquefaction subsystem to a fuel gas subsystem to supply EFG from
the liquefaction subsystem to a fuel gas subsystem; a LNG boil off
gas (BOG) header fluidly connecting the one or more LNG tanks to a
compressor to supply LNG BOG from the one or more LNG tanks to the
compressor; a compressed LNG BOG line fluidly connecting the
compressor to a fuel gas line and a bidirectional line; the fuel
gas line fluidly connecting the compressed LNG BOG line and the
bidirectional line to the fuel gas subsystem; the bidirectional
line fluidly connecting the feed gas line to the fuel gas line and
fluidly connecting the compressed LNG BOG line to the feed gas
line; wherein when in a recycle mode the compressed LNG BOG line
supplies compressed LNG BOG from the compressor to the
bidirectional line and the bidirectional line supplies the
compressed LNG BOG from the compressed LNG BOG line to the feed gas
line, and wherein when in a fuel mode the compressed LNG BOG line
supplies compressed LNG BOG from the compressor to the fuel gas
line and the bidirectional line supplies the natural gas from the
feed gas line to the fuel gas line.
2. The natural gas liquefaction plant of claim 1, wherein when in
the recycle mode the compressed LNG BOG line supplies compressed
LNG BOG from the compressor to the fuel gas line and the
bidirectional line.
3. The natural gas liquefaction plant of claim 1, wherein the feed
gas line, the compressed LNG BOG line, and the bidirectional line
are pressurized at about 55 bar gauge to about 70 bar gauge.
4. The natural gas liquefaction plant of claim 1, wherein the feed
gas line, the compressed LNG BOG line, and the bidirectional line
are pressurized at about 60 bar gauge to about 65 bar gauge.
5. The natural gas liquefaction plant of claim 1, further
comprising one or more subsystems upstream of the liquefaction
subsystem, the subsystems selected from the group consisting of a
gas receiving subsystem, a condensate removal subsystem, an acid
gas removal subsystem, a dehydration subsystem, a mercury removal
subsystem, a precooling subsystem, a heavy-hydrocarbon removal
subsystem, and any combination thereof.
6. A method of operating a natural gas liquefaction plant
comprising: supplying a feed gas to a liquefaction subsystem;
liquefying the feed gas to produce liquefied natural gas (LNG) and
end-flash gas (EFG); compressing the EFG to compressed EFG; using
the compressed EFG as fuel gas; storing the LNG in one or more LNG
tanks; compressing LNG boil off gas (BOG) from the one or more LNG
tanks to produce compressed LNG BOG; and either (1) operating in a
recycle mode by supplying at least a portion of the compressed LNG
BOG to the feed gas via a bidirectional line, or (2) operating in a
fuel mode by (a) supplying a portion of the feed gas to the fuel
gas via the bidirectional line and (b) supplying the compressed LNG
BOG to the fuel gas.
7. The method of claim 6, wherein operating in recycle mode further
includes supplying at least a portion of the compressed LNG BOG to
the fuel gas.
8. The method of claim 6, wherein the feed gas and the compressed
LNG BOG are individually at a pressure of about 55 bar gauge to
about 70 bar gauge.
9. The method of claim 6, wherein the feed gas and the compressed
LNG BOG are individually at a pressure of about 60 bar gauge to
about 65 bar gauge.
10. The method of claim 6, further comprising: treating a natural
gas supply by one or more methods to produce the feed gas for
liquefaction, the one or more methods being selected from the group
consisting of: condensate removal, acid gas removal, dehydration,
mercury removal, precooling, heavy-hydrocarbon removal, and any
combination thereof.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This application claims the priority benefit of U.S.
Provisional Patent Application No. 62/718,742 filed Aug. 14, 2018,
entitled BOIL-OFF GAS RECYCLE SUBSYSTEM IN NATURAL GAS LIQUEFACTION
PLANTS.
FIELD
[0002] This disclosure relates generally to the subsystem for and
methods related to recycling liquefied natural gas (LNG) boil-off
gas (BOG) in natural gas liquefaction plants.
BACKGROUND
[0003] Because of its clean burning qualities and convenience,
natural gas has become widely used in recent years. However, large
volumes of natural gas (i.e., primarily methane) are located in
remote areas of the world. This gas has significant value if it can
be economically transported to market. Where gas reserves are
located in reasonable proximity to a market and the terrain between
the two locations permits, the gas is typically produced and then
transported to market through submerged and/or land-based
pipelines. However, when gas is produced in locations where laying
a pipeline is infeasible or economically prohibitive, other
techniques must be used for getting this gas to market.
[0004] A commonly used technique for non-pipeline transport of gas
involves liquefying the gas at or near the production site and then
transporting the liquefied natural gas to market in
specially-designed storage tanks aboard transport vessels. The
natural gas is cooled and condensed to a liquid state to produce
liquefied natural gas ("LNG") at substantially atmospheric pressure
and at temperatures of about -162.degree. C. (-260.degree. F.),
thereby significantly increasing the amount of gas that can be
stored in a storage tank, which can be on-site or aboard a
transport vessel.
[0005] During storage, heat from the surrounding environment, which
inherently leaks into the LNG storage tanks, causes some of the
stored LNG to vaporize resulting in LNG "boil-off gas" (BOG) within
the tanks. Additional storage tank LNG BOG is created by: (i)
energy input to the LNG by the rundown pumps that provide
sufficient pressure to effect LNG transfer from the flash tank to
the storage tank; (ii) heat leak through the insulation on the LNG
rundown line; (iii) heat leak through the insulation on the LNG
loading and recirculation line; and (iv) energy input to the stored
LNG by the recirculation pump(s). This LNG BOG is typically
recovered and compressed for use as fuel gas within the plant area.
However, natural gas liquefaction plants that use natural gas with
a moderate to high concentration of nitrogen also generate
end-flash gas (EFG), which can be used as fuel gas. Depending on
the plant fuel demand, there may not be the capacity to consume the
LNG BOG as fuel, and so an alternative means of use or disposal
will be required. While the LNG BOG could be flared, this is
generally not permitted as a normal operating mode.
[0006] U.S. Pat. No. 3,857,245 (Jones) discloses a process of
condensing a nitrogen-containing boil-off in which LNG is injected
into the nitrogen-containing boil-off vapor and the combined
mixture is then condensed. The injection of the LNG into the
nitrogen-containing boil-off increases the volume of vapor that
must be reliquefied.
[0007] U.S. Pat. No. 6,192,705 (Kimble) discloses a process of
passing boil-off through a heat exchanger followed by compressing
and cooling stages, and then recycling the boil-off back through
the heat exchanger. The compressed, cooled, and then heated
boil-off is subsequently expanded and passed to a gas-liquid
separator for removal of liquefied boil-off. The liquefied boil-off
is then combined with a second liquefied gas stream to produce a
desired product stream.
[0008] Other less complicated methods of using LNG BOG are
desired.
SUMMARY
[0009] This disclosure relates generally to the subsystem for and
methods related to recycling LNG BOG in natural gas liquefaction
plants. More specifically, the present disclosure utilized a
bi-directional line to allow LNG BOG to be directed for
liquefaction in a recycle mode or be directed for fuel gas in a
fuel mode. Such methods and subsystems may advantageously provide a
simple solution to using LNG BOG that brings value to the operator
with a simple, straightforward implementation design.
[0010] In a first embodiment, a natural gas liquefaction plant can
comprise: a feed gas line fluidly connected to a liquefaction
subsystem to supply feed gas to the liquefaction subsystem; a LNG
line fluidly connecting the liquefaction subsystem to one or more
LNG tanks to supply LNG from the liquefaction subsystem to the one
or more LNG tanks; a EFG line fluidly connecting the liquefaction
subsystem to a fuel gas subsystem to supply EFG from the
liquefaction subsystem to a fuel gas subsystem; a LNG BOG header
fluidly connecting the one or more LNG tanks to a compressor to
supply LNG BOG from the one or more LNG tanks to the compressor; a
compressed LNG BOG line fluidly connecting compressor to a fuel gas
line and a bidirectional line; the fuel gas line fluidly connecting
the compressed LNG BOG line and the bidirectional line to the fuel
gas subsystem; the bidirectional line fluidly connecting the feed
gas line to the fuel gas line and fluidly connecting the compressed
LNG BOG line to the feed gas line; wherein when in recycle mode the
compressed LNG BOG line supplies compressed LNG BOG from the
compressor to the bidirectional line and the bidirectional line
supplies the compressed LNG BOG from the compressed LNG BOG line to
the feed gas line, and wherein when in fuel mode the compressed LNG
BOG line supplies compressed LNG
[0011] BOG from the compressor to the fuel gas line and the
bidirectional line supplies the natural gas from the feed gas line
to the fuel gas line.
[0012] In a second embodiment, a method of operating a natural gas
liquefaction plant comprising: supplying a feed gas to a
liquefaction subsystem; liquefying the natural gas to produce LNG
and EFG; compressing the EFG to compressed EFG; using the
compressed EFG as fuel gas; storing the LNG in one or more LNG
tanks; compressing LNG BOG from the one or more LNG tanks to
produce compressed LNG BOG; either (1) operating in recycle mode by
supplying at least a portion of the compressed LNG BOG to the feed
gas via a bidirectional line or (2) operating in fuel mode by (a)
supplying a portion of the feed gas to the fuel gas via the
bidirectional line and (b) supplying the compressed LNG BOG to the
fuel gas.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] The following figures are included to illustrate certain
aspects of the embodiments, and should not be viewed as exclusive
embodiments. The subject matter disclosed is capable of
considerable modifications, alterations, combinations, and
equivalents in form and function, as will occur to those skilled in
the art and having the benefit of this disclosure.
[0014] FIG. 1 is an illustrative diagram of a portion in a natural
gas liquefaction plant.
[0015] FIG. 2 is an illustrative flow diagram of the subsystems of
an example natural gas liquefaction plant.
DETAILED DESCRIPTION
[0016] This disclosure relates generally to the subsystem for and
methods related to recycling liquefied natural gas (LNG) boil-off
gas (BOG) in natural gas liquefaction plants. More specifically,
the present disclosure utilized a bi-directional line to allow LNG
BOG to be directed for liquefaction in a recycle mode or be
directed for fuel gas in a fuel mode.
[0017] FIG. 1 is an illustrative diagram of a portion 100 of a
natural gas liquefaction plant. The portion 100 includes a feed gas
line 102 fluidly connected to a liquefaction subsystem 104 to
supply feed gas to the liquefaction subsystem 104. The feed gas is
natural gas having undergone the necessary treatments to be
suitable for liquefaction. The treatments depend on the composition
of the natural gas (e.g., sulfur, water, and mercury content) and
can include, but are not limited to, condensate removal, acid gas
removal, dehydration, mercury removal, heavy-hydrocarbon removal,
and combinations thereof.
[0018] As used herein, when describing a line that fluidly connects
two components, the line is used as a general term to encompass the
line or lines that fluidly connect the two components and the other
hardware like pumps, connectors, heat exchangers, and valves that
may be installed along the line.
[0019] Referring again to FIG. 1, the liquefaction subsystem 104
liquefies the natural gas to produce LNG at substantially ambient
pressure. As used herein, "substantially ambient pressure" refers
to ambient pressure.+-.5 bar gauge (barG). Liquefaction subsystems
are known in the art and can have several different configurations.
Typically, liquefaction subsystems include one or more heat
exchangers, an expansion valve or hydraulic turbine, one or more
pumps, and a separator. Examples of liquefaction subsystems
include, but are not limited to, those described in U.S. Pat. Nos.
5,916,260 and 6,658,892, U. S. Patent Application No. 2007/0193303
and PCT International Application No. WO2011/109117, each of which
is incorporated herein by reference.
[0020] Generally, the feed gas can be at about 55 barg (about 798
psi gauge (psig)) to about 70 barg (about 1,015 psig) as introduced
to the liquefaction subsystem 104. To reduce the pressure of feed
gas in the liquefaction subsystem 104, the feed gas is typically
passed from a cryogenic heat exchanger system across an expansion
valve or hydraulic turbine (i.e. "flashed") before it is passed
into a separator (i.e., the flash tank). As the pressure of the
cooled feed gas is reduced to produce LNG at substantially ambient
pressure, some of the gas flashes and becomes vapor known as
end-flash gas (EFG). LNG is removed from the flash tank and is
pumped from the liquefaction subsystem 104 on to an LNG storage
tank 108 via an LNG line 106 that fluidly couples the liquefaction
subsystem 104 and the LNG storage tank 108. The EFG is removed from
the flash tank in the liquefaction subsystem 104 and pumped to an
EFG compressor 112 via an EFG line 110 that fluidly couples the
liquefaction subsystem 104 and the EFG compressor 112.
[0021] The EFG compressor 112 compresses the EFG to produce
compressed EFG at a pressure of about 55 barg (about 798 psig) to
about 70 barg (about 1,015 psig). The compressed EFG is supplied to
a fuel gas subsystem 116 via compressed EFG line 114 that fluidly
couples the EFG compressor 112 and the fuel gas subsystem 116. The
fuel gas subsystem 116 provides fuel gas to various components of
the natural gas liquefaction plant.
[0022] As described above, LNG in the LNG storage tank 108
vaporizes to LNG BOG over time due at least in part to heat from
the surrounding environment warming the LNG. The LNG BOG is
captured in an LNG BOG header 118 that fluidly couples the LNG
storage tank 108 to an LNG BOG compressor 120. The LNG BOG
compressor 120 compresses the LNG BOG to produce compressed LNG BOG
at a pressure of about 55 barg (about 798 psig) to about 70 barg
(about 1,015 psig). A compressed LNG BOG line 122 fluidly couples
the LNG BOG compressor 120 to a fuel gas line 124 and a
bidirectional line 126.
[0023] Compressed LNG BOG is supplied to the fuel gas line 124 in
an amount needed to supply or augment the supply of fuel gas needed
to run the natural gas liquefaction plant. This can be all of the
compressed LNG BOG, some of the compressed LNG BOG, or none of the
compressed LNG BOG. When there is excess compressed LNG BOG not
needed for fuel gas, the excess compressed LNG BOG is conveyed to
the feed gas line 102 via the bidirectional line 126 in the flow
direction of arrow A. The excess compressed LNG BOG is entrained
with the feed gas for liquefaction. This configuration in flow
direction A is referred to herein as being in "recycle mode."
[0024] Alternatively, when all of the LNG BOG is insufficient to
supply or augment the supply of fuel gas needed to run the natural
gas liquefaction plant, at least a portion of the feed gas from
feed gas line 102 can be conveyed to the fuel gas line 124 via the
bidirectional line 126 in the flow direction of arrow B. This
configuration in flow direction A is referred to herein as being in
"fuel mode."
[0025] Accordingly, methods of the present disclosure can include
supplying a feed gas to a liquefaction subsystem; liquefying the
feed gas, which may be a natural gas, to produce LNG and EFG;
compressing the EFG to compressed EFG; using the compressed EFG as
fuel gas; storing the LNG in one or more LNG tanks; compressing LNG
BOG from the one or more LNG tanks to produce compressed LNG BOG;
and either (1) operating in a recycle mode by supplying at least a
portion of the compressed LNG BOG to the feed gas via a
bidirectional line, or (2) operating in a fuel mode by (a)
supplying a portion of the feed gas to the fuel gas via the
bidirectional line and (b) supplying the compressed LNG BOG to the
fuel gas. In some instances, operating in recycle mode can further
include supplying at least a portion of the compressed LNG BOG to
the fuel gas.
[0026] Fuel demand at a natural gas liquefaction plant varies
depending on the processes running. For example, typically several
liquefaction subsystems 104 are operating in parallel. When some
are off-line for maintenance or because supply or demand is low,
the compressed EFG may be sufficient to supply the fuel gas needs
of the plant. In such instances a portion of or none of the
compressed LNG BOG may be needed to augment the supply of
compressed EFG. In such instances, the portion 100 may operate in
recycle mode.
[0027] In another example, the natural gas liquefaction plant may
be operating several liquefaction subsystems 104 in parallel such
that the combined amount of the compressed EFG and the compressed
LNG BOG are insufficient to provide the amount fuel gas needed to
operate the plant. In such instances, the portion 100 may operate
in fuel mode.
[0028] In yet another example, the natural gas supply may have a
low concentration of nitrogen, which results in lower amounts of
EFG. Consequently, the portion 100 may operate in fuel mode more
often than if the natural gas supply had a moderate to high
concentration of nitrogen.
[0029] In the portion 100, the feed gas, the compressed LNG BOG,
and the compressed EFG can each individually be at a pressure of
about 55 barg (about 798 psig) to about 75 barg (about 1,088 psig),
or about 58 barg (about 841 psig) to about 72 barg (about 1,044
psig), or about 60 barg (about 870 psig) to about 70 barg (about
1,015 psig), or about 62 barg (about 899 psig) to about 68 barg
(about 986 psig).
[0030] FIG. 2 is an illustrative flow diagram of the subsystems 230
of an example natural gas liquefaction plant. In alternate
embodiments, some of the subsystems 230 can be eliminated or
bypassed, the subsystems 230 can be reordered, and/or additional
subsystems 230 can be included.
[0031] In the illustrated subsystems 230, a natural gas supply 232
is provided to a gas receiving subsystem 234 and transported to a
condensate removal subsystem 236. The condensate removal subsystem
236 extracts unstabilized condensate 238, which is transported to a
condensate stabilization subsystem 240. The product from the
condensate removal subsystem 236 is then treated through an acid
gas removal subsystem 242, a dehydration subsystem 244, a mercury
removal subsystem 246, and a precooling subsystem 248 before
removal of heavy hydrocarbons 252 in the heavy-hydrocarbon removal
subsystem 250. The heavy hydrocarbons 252 can be fractionated in a
fractionation subsystem 254 into stabilized condensate 256, natural
gas liquids 258 (NGL) (e.g., ethane, propane, butanes, and heavier
hydrocarbons), and methane 260. The stabilized condensate 256 can
be transported to a condensate storage subsystem 262, which is
where the stabilized condensate 264 from the condensate
stabilization subsystem 240 is also stored. The NGL 258 can be
transported to a NGL storage subsystem 266. The methane 260 can be
transported to a refrigeration subsystem 268 the cooled methane can
be combined with the feed gas 270 product of the heavy-hydrocarbon
removal subsystem 250.
[0032] Then, as described in FIG. 1, the feed gas 270 is provided
to the liquefaction subsystem 272. The EFG 274 is compressed and
transported to a fuel gas subsystem 276. The LNG 278 produced in
the liquefaction subsystem 272 can be stored in an LNG storage
subsystem 280. The LNG BOG 282 from the LNG storage subsystem 280
can be compressed.
[0033] Then, in recycle mode, at least a portion of the LNG BOG 282
can be transported via a bidirectional line 284 to be entrained
with feed gas 270. Alternatively, in fuel mode, the LNG BOG 282 can
be transported to the fuel gas subsystem 276 along with a portion
of the feed gas 270 via the bidirectional line 284 according to
flow arrows B.
[0034] Finally, as needed, the LNG in the LNG storage subsystem 280
can be transferred to transportation vessels 286 (e.g., tanker
trucks, tanker railcars, and ships).
[0035] Methods of the present disclosure can include treating a
natural gas supply by one or more methods to produce the feed gas
for liquefaction, the one or more methods being selected from the
group consisting of: condensate removal, acid gas removal,
dehydration, mercury removal, precooling, heavy-hydrocarbon
removal, and combinations thereof.
[0036] Unless otherwise indicated, all numbers expressing
quantities of ingredients, properties such as molecular weight,
reaction conditions, and so forth used in the present specification
and associated claims are to be understood as being modified in all
instances by the term "about." Accordingly, unless indicated to the
contrary, the numerical parameters set forth in the following
specification and attached claims are approximations that may vary
depending upon the desired properties sought to be obtained by the
embodiments of the present invention. At the very least, and not as
an attempt to limit the application of the doctrine of equivalents
to the scope of the claim, each numerical parameter should at least
be construed in light of the number of reported significant digits
and by applying ordinary rounding techniques.
[0037] One or more illustrative embodiments incorporating the
invention embodiments disclosed herein are presented herein. Not
all features of a physical implementation are described or shown in
this application for the sake of clarity. It is understood that in
the development of a physical embodiment incorporating the
embodiments of the present invention, numerous
implementation-specific decisions must be made to achieve the
developer's goals, such as compliance with system-related,
business-related, government-related and other constraints, which
vary by implementation and from time to time. While a developer's
efforts might be time-consuming, such efforts would be,
nevertheless, a routine undertaking for those of ordinary skill in
the art and having benefit of this disclosure.
[0038] While compositions and methods are described herein in terms
of "comprising" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps.
[0039] 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, combined,
or modified and all such variations are considered within the scope
and spirit of the present invention. The invention illustratively
disclosed herein suitably may be practiced in the absence of any
element that is not specifically disclosed herein and/or any
optional element disclosed herein. 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.
* * * * *