Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND APPARATUS FOR SEPARATING ONE OR MORE C2+
HYDROCARBONS FROM A MIXED PHASE HYDROCARBON STREAM
The present invention relates to a method for
separating one or more C2+ hydrocarbons from a mixed
phase hydrocarbon stream such as partly vapourised
liquefied natural gas (LNG).
Liquid hydrocarbon streams such as LNG are well-known
products, and they are commonly transported in a liquid
form for vaporisation at a suitable location or terminal.
One such terminal is an 'import terminal', which can
vaporise the LNG for direct use, subsequent piping into a
network, etc.
In their paper entitled "Processes for High C2
Recovery from LNG" for IPSI LLC, presented at the AlChE
Spring Meeting in April 2006 (6th Tropical Conference on
Natural Gas Utilisation, Orlando, Florida, April 23-27,
2006), the authors stated that "re-gasified LNG being
imported into the US must meet gas quality requirements
before it can be accepted in the US pipeline grid.
Towards this goal, many existing and prospective LNG
terminal owners are considering C2+ extraction". Various
arrangements are discussed in the Paper for improving the
C2+ recovery levels using a refluxed demethanizer, such
as with residue compression and condensing; see for
example its Figure 7.
However, the IPSI Paper does not mention how a
separate gaseous hydrocarbon stream can be accommodated
into its processes. One additional gaseous hydrocarbon
stream is boil-off-gas. Boil-off gas is generally always
created in any storage or movement of a liquefied
hydrocarbon stream such as LNG. Traditionally, boil-off
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gas from an LNG storage tank is simply compressed and
recondensed. This has the problem of additional energy
requirements, making it non-efficient.
There are other situations or locations, such as an
LNG export terminal, where it may also be desired to have
C2+ extraction from a hydrocarbon stream or source, but
wherein the problem of efficiently accommodating a
separate gaseous hydrocarbon stream such as boil-off gas
has not been considered.
The present invention provides a method for
separating one or more C2+ hydrocarbons from a mixed
phase hydrocarbon stream such as partly vapourised
liquefied natural gas, the method at least comprising the
steps of:
(a) supplying a mixed phase hydrocarbon feed stream to a
first gas/liquid separator;
(b) separating the hydrocarbon feed stream in the first
gas/liquid separator into a first gaseous stream from a
first outlet, and at least one C2+ liquid stream;
(c) passing the first gaseous stream through a compressor
to provide a compressed stream; and
(d) cooling the compressed stream in one or more heat
exchangers to provide an at least partly condensed
hydrocarbon product stream;
wherein a second gaseous stream is added to a stream
downstream of the first outlet.
In a further aspect, the present invention provides
apparatus for separating one or more C2+ hydrocarbons
from a mixed phase hydrocarbon stream such as liquefied
natural gas, the apparatus at least comprising:
a first gas/liquid separator having an inlet for a
mixed phase hydrocarbon feed stream, a first outlet for a
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first gaseous stream and a second outlet for at least one
C2+ hydrocarbon liquid stream;
a compressor to compress the first gaseous stream to
provide a compressed stream;
one or more heat exchangers to cool the compressed
stream to provide an at least partly condensed
hydrocarbon product stream; and
a combiner to combine a second gaseous stream with a
stream downstream of the first outlet of the gas/liquid
separator.
Embodiments of the present invention will now be
described by way of example only and with reference to
the accompanying non-limiting drawings in which:
Figure 1 is a schematic process scheme in accordance
with a first embodiment of the present invention; and
Figure 2 is a schematic process scheme in accordance
with a second embodiment of the present invention.
For the purpose of this description, a single
reference number will be assigned to a line as well as a
stream carried in that line. Same reference numbers refer
to similar components.
It is an object of the present invention to reduce
the capital and running costs in a method for separating
one or more C2+ hydrocarbons from a mixed phase
hydrocarbon stream to accommodate a further gaseous
hydrocarbon stream such as boil-off gas.
The present methods and apparatus allow to have C2+
extraction from a hydrocarbon stream or source, wherein a
separate gaseous hydrocarbon stream such as boil-off gas
is efficiently accommodated.
It has been found that using the surprisingly simple
method and apparatus described herein, a second gaseous
stream can be accommodated into the method for separating
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one or more C2+ hydrocarbons from a mixed phase
hydrocarbon stream with minimal, if any, additional
running or capital costs.
A further advantage is provided by avoidance of
adding the second gaseous stream into the gas/liquid
separator, which would require a larger gas/liquid
separator due to the larger gaseous volume involved, and
so also lead to increasing capital and running costs.
A further advantage is provided by avoidance of
adding the second gaseous stream into apparatus for
cooling, preferably re-condensing, the first gaseous
stream from the gas/liquid separator, where the warmth of
the second gaseous stream would disadvantage the desire
for the coldest hydrocarbon product stream.
Advantageously, the second gaseous stream is
recovered as part of a useful product stream. Where the
second gaseous stream comprises one or more useful,
commercial or otherwise valuable hydrocarbons, these are
recovered by the present invention rather than being
burnt off or only used as a source of fuel. Thus the
method the present invention is also able to provide a
greater volume or amount of a product stream than prior
art processes.
The mixed phase hydrocarbon stream may be any
suitable at least partly vapourised hydrocarbon-
containing stream, such as a partly vapourised LNG
stream, from which it is intended to recover one or more
C2+ liquid streams. The mixed phase hydrocarbon stream
may be at least partly vaporised from a liquid source and
it may optionally contain also hydrocarbons that have at
least partly condensed from a gaseous source.
It is remarked that US Patent 6,023,942 discloses a
process for liquefying a gas stream rich in methane. If
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the natural gas stream contains heavy hydrocarbons, these
may be extracted by a fractionation process before
liquefying the gas. A problem associated with US patent
6,023,942 that is not addressed in said patent, is what
5 to do when the content of heavy hydrocarbons in an
already liquefied product is higher than desired, which
may for instance be the case if the fractionation process
upstream of the liquefaction is not sufficiently
selective to produce a liquefied stream with a level of
C2+ components below a desired maximum.
The present methods and apparatuses solve this
problem, without the need to modify any pre-liquefaction
facilities that may already be available in an existing
liquefaction line-up. The presently proposed solution may
be added-on to an existing facility at a liquefaction
site or an export site, or locally at an import site to
be able to modify the content of the liquefied product to
comply with local requirements.
As is the case for the mixed phase hydrocarbon
stream, the second gaseous stream may also be any
suitable hydrocarbon-containing stream. Optionally, the
second gaseous stream has the same components and
composition as the source of the mixed phase hydrocarbon
stream. One preferred second gaseous stream is boil-off
gas, for example gas evaporated from a liquefied
hydrocarbon store or source, such as one or more storage
tanks. The storage tanks could be static or moveable,
such as storage tanks on a sea-going transporter, or a
combination of same.
US 6, 658,892 B2 shows use of boil-off gas from two
LNG storage tanks in a storage area, which is combined
with an overhead reject gas from a common flash tank and
then fed into a common fuel gas compressor. However, the
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common flash tank in US 6, 658, 892 B2 is not intended to
provide at least one C2+ liquid stream, but to produce a
bottom LNG stream (line 124). Thus, the boil-off gas in
US 6, 658, 892 B2 is not combined with a C2+ depleted
gaseous stream downstream of a gas/liquid separator, but
is combined with the reject gas taken from a common flash
tank handling cooled feed gas produced from two
independent trains.
The one or more C2+ liquid streams provided in
step (b) of the present invention comprises at least one
stream comprising at least 40 mol% of at least one C2+
hydrocarbon, such hydrocarbons being one or more selected
from the group comprising: ethane, propane, butanes and
pentanes. Preferably, at least one of said streams
comprises >50 mol%, >60 mol%, >70 mol%, >80 mol% or
>90 mol% of at least one C2+ hydrocarbon.
Figure 1 schematically shows a process scheme
(generally indicated with reference number 1) for
recovering C2+, that is ethane and heavier, hydrocarbons
from a mixed phase hydrocarbon feed stream 10.
The process shown in Figure 1 is equally able to
recover just a C2, C3 or C4, etc. stream, or C3+, C4+
streams, etc., from a hydrocarbon stream, either as
separate streams, or as one or more combined streams, or
a combination of same.
The mixed phase hydrocarbon feed stream 10 may be any
suitable hydrocarbon-containing stream from which it is
intended to recover one or more C2+ liquid streams. The
mixed phase hydrocarbon feed stream 10 is preferably at
least partly vapourised from a liquid source such as LNG,
and has a pressure above ambient, typically between 8 and
15 bar.
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Prior to the process scheme shown in Figure 1, the
mixed phase hydrocarbon feed stream 10 may have been
utilised in one or more other processes. One example is
use of some of the cold energy of a liquid hydrocarbon
stream, such that the mixed phase hydrocarbon feed stream
is consequently at least partly vapourised.
The mixed phase hydrocarbon stream 10 is preferably
provided by a liquid hydrocarbon stream such as a cold
stream obtained from a source of LNG, such as a liquid
10 product output stream of a liquefaction plant, or,
preferably, from one or more liquefied hydrocarbon
storage tanks such as one or more LNG storage tanks. Such
tanks may be static or moveable, such as on a sea-going
transporter. Thus the source of the LNG could be one or
more storage tanks on an LNG vessel or carrier, the LNG
being carried by a loading or unloading line at an LNG
import or export terminal. These liquefied hydrocarbon
storage tanks could be the same as the liquefied
hydrocarbon storage tanks that provide the boil-off gas
for the second gaseous stream, or they could be different
ones, or a combination of the same and different ones.
As is customary to the person skilled in the art, the
LNG stream may have various compositions. Usually the LNG
stream to be vaporized is comprised substantially of
methane. The LNG will generally contain varying amounts
of hydrocarbons heavier than methane such as ethane,
propane, butanes and pentanes.
Optionally, the mixed phase hydrocarbon feed stream
10 is comprised substantially of methane, that is at
least 80 mol%, preferably at least 90 mol%, 95 mol% or
even 99 mol%, methane.
The mixed phase hydrocarbon feed stream 10 is
supplied to the inlet 22 of a first gas/liquid separator
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12. The nature, design and capacity of the first
gas/liquid separator 12 can relate to the nature of the
incoming mixed phase hydrocarbon feed stream 10 and the
desired streams to be recovered. For example, where it is
desired to recover C2+ hydrocarbons from the mixed phase
hydrocarbon feed stream 10 at the bottom of the first
gas/liquid separator 12, the first gas/liquid separator
12 could be a de-methanizer, known in the art.
Alternatively, recovery of C3+ hydrocarbons as a bottom
product may use a de-ethanizer, also known in the art.
The gas/liquid separator 12 may be any suitable
vessel or arrangement for obtaining a gaseous stream and
a C2+ liquid stream, such as a scrubber, distillation
column, etc. The gas/liquid separator 12 may comprise
more than one separator, column, etc., and may be
designed for the separate separation of two or more
liquid streams, such as a C2 stream and a C3 stream, etc.
Such separators usually operate at above ambient
pressure, for example 6-12+ bar, depending on the type
and recovery of product(s) desired or expected, and
optionally with one or more reflux operations.
The recovery of C2+ hydrocarbons from a mixed phase
hydrocarbon feed stream 10 could be as part of one of a
number of processes using a hydrocarbon feed stream. One
process is for 'purification' of the hydrocarbon feed
stream to minimise heavier hydrocarbons therein, prior to
its subsequent use or further processing. Another process
is for adjusting the gas quality, for example for meeting
a particular heating value downstream. Another process is
for providing one or more C2+ streams, such as liquid
petroleum gas (LPG). A combination of one or more of
these processes or other objectives may also be desired.
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For example, it is known that 'rich' LNG generally
comprises about 5 mol% of C2+ hydrocarbons, which
percentage can be too high for use in certain territories
or locations. At least some of C2+ hydrocarbons
(especially ethane, propane and butane) are also termed
'natural gas liquids' (NGLs), and the production of NGLs
is also commercially attractive.
Thus, one particular involvement of the first
gas/liquid separator 12 in the process scheme of Figure 1
is to reduce the amount of C2+ hydrocarbons in a methane
feed stream, and to provide one or more C2+ product
streams, for example at an import terminal handling rich-
LNG.
In Figure 1, the first gas/liquid separator 12 shows
separation of the hydrocarbon feed stream 10 into a first
gaseous stream 20 through a first outlet 23, and a liquid
stream 30 through a second outlet 24. The liquid stream
30 may comprise one or more separate streams.
In the present invention, it is preferred that the
first gas/liquid separator 12 is able to recover
>80 mol%, >90 mol%, or even - 95 mol% of the heavier
(C2+, C3+, etc,) hydrocarbons, as the liquid stream or
streams 30 from the first gas/liquid separator 12.
The first gaseous stream 20 is combined with a second
gaseous stream 40 by a combiner 18. A combiner 18 may be
a distinct combination unit or vessel, or merely a
conjunction of streams or pipelines.
The second gaseous stream 40 preferably has the same
or similar pressure, temperature and other parameters as
the first gaseous stream 20 at the combiner 18. It is
also possible for the second gaseous stream 40 to have
different parameters and/or conditions.
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The combination of the first gaseous stream 20 and
second gaseous stream 40 provide a combined gaseous
stream 50, which passes into a compressor 14. The
combined gaseous stream 50 has the combination of
5 parameters of the first gaseous stream 20 and second
gaseous stream 40, and is preferably still gaseous and at
above ambient pressure.
The compressor 14 may comprise one or more
compressors in series or parallel or both, designed to
10 compress the combined gaseous stream 50 to a higher
pressure, and provide a compressed stream 60. Under some
operating conditions, for example high compression, a
portion of the combined gaseous stream 50 may become
liquid in the compressor 14. Thus, the compressed stream
60 may be a mixed phase stream.
The compressed stream 60 is then cooled. In Figure 1,
the cooling is provided by a first heat exchanger 16,
which may comprise one or more heat exchangers in series,
parallel or both. The first heat exchanger 16 cools the
compressed stream 60 to provide an at least partly
condensed hydrocarbon product stream 70. The cooling in
the heat exchanger 16 is provided by an incoming cold
stream 80, which passes out of the heat exchanger 15 as a
warmer stream 80a. The incoming cold stream 80 may be any
suitable cold stream being a dedicated refrigerant stream
or any other stream having suitable cold energy that can
be recovered. Optionally, it is a cold stream which is
available from another part or function of an embodiment
of the present invention.
The nature and arrangement of the first heat
exchanger 16 and of the cold stream 80 are designed to
provide the desired hydrocarbon product stream 70 (such
as recondensed or partly vaporised LNG) and/or the
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desired one or more liquid streams 30 and/or to adjust
the composition of the desired hydrocarbon product stream
70.
Optionally, a portion (not shown in Figure 1) of the
compressed stream 60 is used directly, for example fed or
piped directly to a gas network.
The second gaseous stream 40 could be added to one or
more of the group comprising: the first gaseous stream
20, the compressed stream 60, and the at least partly
condensed hydrocarbon product stream 70; downstream of
the first outlet 23 of the first gas/liquid separator 12.
Thus, in a first alternative embodiment, the second
gaseous stream 40 is combined with the compressed stream
60 after the compressor 14. This may be more suitable
where the parameters of the second gaseous stream 40,
especially its pressure, are closer to the parameters of
the compressed stream 60 than the first gaseous stream
20.
In a second alternative embodiment, the second
gaseous stream 40 may be combined with the at least
partly condensed hydrocarbon product stream 70.
This is especially where the parameters of the second
gaseous stream 40, in particular its temperature and
pressure, are closer (either inherently or by processing)
to those of the at least partly condensed hydrocarbon
product stream 70 than the first gaseous stream 40 or the
compressed stream 60.
Figure 2 schematically shows a process scheme
(generally indicated with reference number 2) for a
second embodiment of the present invention.
In particular, Figure 2 shows a storage tank 32 such
as an LNG storage tank at an LNG import terminal. Such
storage tanks 32 are known in the art, and are generally
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designed to store liquefied hydrocarbons such as LNG for
a period of time prior to transport and/or use of the
LNG.
The storage tank 32 shown in Figure 2 has a first
outlet 25 for a liquid hydrocarbon stream 8. The storage
tank 32 has a second outlet 26 for the passage of 'boil-
off gas' 40a. Due to the unavoidable inflow of heat into
storage tanks of liquid hydrocarbons, which are generally
kept at -100 C or below, such as -160 C for LNG, the
creation of boil-off gas is inevitable.
Conventionally, boil-off gas is compressed, and
recondensed. However, this requires at least one or more
additional recondensers, which also involve additional
running costs.
It is an object of the present invention to provide
an alternative use of boil-off gas which does not require
additional capital and/or running costs, or reduces same.
In Figure 2, the liquid hydrocarbon stream 8 passes
through a heat exchanger 16a, which may be the same or
different from the first heat exchanger 16 shown in
Figure 1. In the process scheme 2 shown in Figure 2,
involving the first heat exchanger 16 also means that the
liquid hydrocarbon stream 8 is equivalent to the incoming
cold stream 80 shown in Figure 1, and at least some of
its cold energy is used to cool a second stream
(discussed hereinbelow) also passing through the heat
exchanger 16a.
The heat exchanger 16a may be one or more heat
exchangers in series, parallel or both, and its
arrangement and configuration will be known to those
skilled in the art. Preferably, the heat exchanger 16a
comprises a preheater and/or a condenser as hereinafter
described.
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Through use of at least some of the cold energy of
the liquid hydrocarbon stream 8, the heat exchanger 16a
provides a mixed phase hydrocarbon feed stream 10 (which
may be equivalent to the warmer stream 80a shown in
Figure 1), which passes into the first gas/liquid
separator 12 through the inlet 22. The arrangement and
configuration of the first gas/liquid separator 12 is
described above, and generally provides one or more C2+
liquid streams 30 through one or more outlets such as
second outlet 24 as shown, and a first gaseous stream 20
through a first outlet 23.
The nature of the liquid stream(s) 30 is discussed
above. Figure 2 shows further use of a liquid stream 30,
which passes into a heat exchanger such as a reboiler 44
to provide a reflux stream 30a for re-entry into the
first gas/liquid separator 12 via an inlet 26, and a
liquid product stream 30b. The liquid product stream 30b
may comprise one or more NGL streams for separate
commercial use.
The first gaseous stream 20 in Figure 2 is supplied
into a second gas/liquid separator 36. The second
gas/liquid separator 36 may be any unit or vessel able to
allow any liquid to separate out as a liquid stream 90a,
and to provide a third gaseous stream 90 therefrom. As an
example, the second gas/liquid separator 36 can be a
'knock-out drum' known in the art.
The second gas/liquid separator 36 is a convenient
receiver of a second gaseous stream 40, especially a
boil-off gas stream 40a from the storage tank 32 as shown
in Figure 2. A gas/liquid separator usually has a number
of fittings or ports, easily able to be adapted to
provide one or more additional inlets of gas thereinto.
As such, the present invention is also particularly
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convenient for the introduction of a second gaseous
stream 40 into an existing gas/liquid separator such as a
knock-out drum, including retro-fitting of a second
gaseous stream passage and inlet into an existing plant,
design or facility. In this way, the second gas/liquid
separator 36 is acting as the combiner 18 of the two
gaseous streams as shown in Figure 1.
Boil-off gas is by its nature usually normally
gaseous, and usually has a temperature below 0 C, such as
between -20 C and -90 C. Usually, but optionally, there
is a boil-off gas compressor 34 to compress the boil-off
gas stream 40a to a greater than ambient pressure, such
as between 6-15 bar. Where the storage tank 32 is storing
LNG, boil-off gas is usually >70 mol% methane.
As the pressure is similar to that of the first
gaseous stream 20 supplied by the first gas/liquid
separator 12, minimal energy is required for the
combination of the first gaseous stream 20 and a second
gaseous stream 40 being the (optionally compressed) boil-
off gas stream 40a, in the second gas/liquid separator
36. This directly utilises the boil-off gas from the
storage vessel 32 as a gaseous stream without requiring
additional capital and running costs, in particular the
need for other or additional recondensor(s) for the boil-
off gas.
Furthermore, the introduction of the second gas
stream 40 into the second gas/liquid separator 36 avoids
the need for a larger first gas/liquid separator 12 to
accommodate inflow of the second gaseous stream 40. It
also makes the process of Figure 2 independent of the
supply of the second gaseous stream 40, where this may be
intermittent and/or variable (for example during loading
and unloading of LNG), as well as making the process
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independent of the temperature of the mixed phase
hydrocarbon feed stream 10.
From the second gas/liquid separator 36, the third
gaseous stream 90 is passed into a compressor 14. As
5 described above, the compressor 14 may be one or more
compressors, and provides a compressed stream 60.
The compressed stream 60 passes into the heat
exchanger 16a (described above), to be cooled by the
liquid hydrocarbon stream 8 also passing into the heat
10 exchanger 16a.
It is preferred for the compressed hydrocarbon stream
60 to be cooled as much as possible by the liquid
hydrocarbon stream 8, so as to provide an at least partly
condensed hydrocarbon product stream 70 having the
15 largest or greatest amount of cold energy. This is so as
to maximise use of the cold energy in the at least partly
condensed hydrocarbon product stream 70. For example, the
hydrocarbon product stream 70 may be used in one or more
further processes, which partly or fully vaporises the
hydrocarbon product stream 70 and recovers its cold
energy for integration with one or more other processes
such as in a gas separation plant, power plant, etc.
It can be seen that the introduction of the
relatively warm second gaseous stream 40 into either the
colder liquid hydrocarbon stream 8 or the condensing heat
exchanger 16a would affect maximisation of the condensing
of the compressed hydrocarbon stream 60 by the liquid
hydrocarbon stream 8, and it is therefore less desired to
carry out such alternative arrangements.
In Figure 2, the at least partly condensed
hydrocarbon product stream 70 can pass through a splitter
38. The splitter 38 may be a simple division of one or
more streams or pipelines, or may be a distinct unit or
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vessel such as an accumulator having two or more outlets.
The splitter 38 can provide two streams: a first (usually
majority) at least partly (preferably fully) liquid
stream 100 for subsequent use (such as pumping through a
pump 46 and subsequent vaporisation in a vaporiser 48 to
supply the hydrocarbon as a vapour product stream 110 to
a network); and a second, usually minority, at least
partly liquid stream 100a. After passing through a
pressure reduction valve 42, the second stream 100a is an
expanded stream 100b which can be passed through an inlet
27 into the first gas/liquid separator 12 as a reflux
stream. Some gas/liquid separators are more efficient
where two or more incoming streams having different
temperatures are supplied at different inlets, in a
manner known in the art.
The second at least partly liquid stream 100a is
preferably less than 20 mol%, more preferably less than
10 mol%, of the at least partly condensed hydrocarbon
product stream 70.
Table 1 gives an overview of estimated pressures and
temperatures of the streams at various parts of an
example process of Figure 2.
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Table 1
Line Pressure (bar) Temperature ( C) Phase
composition*
8 9.5 -157 L
9.0 -114 V/L
100b 8.5 -125 V/L
8.5 -121 V
30b 8.6 -25 L
40 9.5 -24 V
60 13.5 -96 V
100 13.0 -122 or lower L
* V = vapour, L = Liquid
The person skilled in the art will readily understand
that many modifications may be made without departing
from the scope of the invention.
