Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND APPARATUS FOR PRODUCING A LIQUEFIED
HYDROCARBON STREAM
The present invention relates to a method and
apparatus for producing a liquefied hydrocarbon product
stream.
Liquefied natural gas (LNG) forms an economically
important example of such a cryogenic hydrocarbon stream.
Natural gas is a useful fuel source, as well as a source
of various hydrocarbon compounds. It is often desirable
to liquefy natural gas in a liquefied natural gas plant
at or near the source of a natural gas stream for a
number of reasons. As an example, natural gas can be
stored and transported over long distances more readily
as a liquid than in gaseous form because it occupies a
smaller volume and does not need to be stored at high
pressure.
US application publication 2012/0167617 describes a
method wherein a treated liquefied hydrocarbon stream is
produced from natural gas, wherein lower boiling point
components, such as nitrogen, are separated from a multi-
phase hydrocarbon stream, to produce a liquefied natural
gas stream with a lower content of such lower boiling
point components. The method employs two subsequent
gas/liquid separators operating at different pressures.
The multi-phase hydrocarbon stream is fed into the first
gas/liquid separator at a first pressure. The bottom
stream of the first gas/liquid separator is passed to the
second gas/liquid separator, which provides vapour at a
second pressure that is lower than the first pressure.
The vapour is compressed in an overhead stream
compressor, and returned to the first gas/liquid
separator as a stripping vapour stream. A reflux
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condenser is envisaged in the first gas/liquid separator
to recondense some of the vapours at the top of the first
gas/liquid separator.
Still describing US 2012/0167617, the overhead stream
of the first gas/liquid separator is a vapour stream
comprising hydrocarbons and at least 30 mol% of nitrogen.
This stream is combusted in a low pressure fuel gas
consumer in the form of combustion device such as a
furnace, boiler, or duel fuel diesel engine. A high
pressure fuel stream, suitable for use as a fuel for a
gas turbine, is extracted from the hydrocarbon feed
stream prior to liquefaction. The high pressure fuel gas
stream has a low nitrogen content compared to the low
pressure fuel gas stream derived from the first separator
overhead stream.
A drawback of the method and apparatus as described
in US 2012/0167617 is that a lot of cooling duty may be
required in the reflux condenser to recondense vapours if
a high amount of stripping gas is formed in the second
gas/liquid separator. This may be the case if there is a
high amount of nitrogen in the multi-phase hydrocarbon
stream.
The present invention provides a method of providing
a liquefied hydrocarbon product stream, the method
comprising:
- providing a cryogenic hydrocarbon composition
comprising a nitrogen- and methane-containing
liquid phase;
- stream splitting the cryogenic hydrocarbon
composition into a first portion and a second portion,
the second portion having the same composition and
phase as the first portion;
- feeding a first nitrogen stripper feed stream, at a
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stripping pressure, into a nitrogen stripper column
comprising at least one internal stripping section
positioned within the nitrogen stripper column, said
first nitrogen stripper feed stream comprising at least
the first portion of the cryogenic hydrocarbon
composition;
- drawing a nitrogen-stripped liquid from a sump
space of the nitrogen stripper column below the
stripping section;
depressurizing the second portion of the cryogenic
hydrocarbon composition to a flash pressure that is
lower than the stripping pressure;
- feeding the depressurized second portion into an
end flash separator subsequently to said depressurizing
of said second portion to said flash pressure;
wherein from said stream splitting to said feeding of
the second portion the second portion bypasses the
nitrogen stripper column;
- producing at least a liquefied hydrocarbon product
stream and a process vapour from the nitrogen-stripped
liquid and the depressurized second portion,
comprising at least depressurizing the nitrogen-
stripped liquid to the flash pressure, wherein a flash
vapour is generated during said depressurizing of said
nitrogen-stripped liquid and the depressurised second
portion to said flash pressure, and phase separating
the nitrogen-stripped liquid and the depressurised
second portion, in an end flash separator, at a flash
separation pressure that is equal to or lower than the
flash pressure, into the liquefied hydrocarbon product
stream and the flash vapour, wherein the process
vapour comprises said flash vapour;
- compressing said process vapour to at least
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the stripping pressure, thereby obtaining a
compressed vapour;
- passing a stripping vapour stream into the
nitrogen stripper column at a level gravitationally
below said stripping section, said stripping vapour
stream comprising at least a stripping portion of said
compressed vapour;
- discharging a vapour fraction, comprising a
discharge fraction of an overhead vapour obtained from
an overhead part of the nitrogen stripping column, as
off gas, wherein the vapour fraction has a first
heating value;
- combusting the vapour fraction in a combustion device
other than a gas turbine;
removing a fuel gas vapour stream from the
compressed vapour, said fuel gas vapour stream
comprising a fuel gas portion of said compressed
vapour, which fuel gas vapour stream has a second
heating value that is higher than the first heating
value;
- passing the fuel gas vapour stream to a gas
turbine whereby the fuel gas vapour stream bypasses
the nitrogen stripper column once it has been removed
from the compressed vapour; and
combusting the fuel gas vapour stream in the gas
turbine.
In another aspect, the present invention
provides an apparatus for providing a liquefied
hydrocarbon product stream, the apparatus
comprising:
- a cryogenic feed line connected to a source of a
cryogenic hydrocarbon composition comprising
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- nitrogen and a methane-containing liquid
phase;
- an initial stream splitter at a downstream end of
the cryogenic feed line, arranged to split the
cryogenic hydrocarbon composition into a first portion
and a second portion having the same composition and
phase as the first portion;
- a first feed line for conveying the first portion
from the initial stream splitter to the nitrogen
stripper column;
- a second feed line for conveying the second portion
from the initial stream splitter to the end flash
separator, wherein the second feed line bypasses the
nitrogen stripper column;
a nitrogen stripper column in fluid communication
with the cryogenic feed line, said nitrogen stripper
column comprising at least one internal stripping
section positioned within the nitrogen stripper column;
- an overhead vapour discharge line communicating
with the nitrogen stripper column via an overhead
space within the nitrogen stripper column;
- a combustion device other than a gas turbine,
fluidly connected with the nitrogen stripper column via
at least the overhead vapour discharge line, and
arranged to receive a discharge fraction from an
overhead vapour carried in the overhead vapour discharge
line, and to combust the discharge fraction;
- a nitrogen-stripped liquid discharge line
communicating with a sump space within the nitrogen
stripper column gravitationally below the stripping
section;
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- an intermediate depressurizer in the nitrogen-
stripped liquid discharge line, fluidly connected to the
nitrogen stripper column, arranged to receive a nitrogen-
stripped liquid from the sump space of the nitrogen
stripper column and to depressurize the nitrogen-stripped
liquid, said intermediate depressurizer located on an
interface between a stripping pressure side comprising
the nitrogen stripper column and a flash pressure side;
- a liquid hydrocarbon product line arranged on the
flash pressure side to discharge a liquefied hydrocarbon
product stream produced from the nitrogen-stripped
liquid;
- a process vapour line arranged on the flash pressure
side to receive a process vapour produced from the
nitrogen-stripped liquid;
- an end flash separator arranged on the flash pressure
side of the interface and in fluid communication with the
nitrogen stripper column via the nitrogen-stripped liquid
discharge line; and arranged in discharging communication
with the liquid hydrocarbon product line and the in
discharging communication with the process vapour line;
- a process compressor arranged in the process vapour
line arranged to receive the process vapour from the end
flash separator, and to compress the process vapour to
provide a compressed vapour at a process compressor
discharge outlet of the process compressor, said process
compressor being on said interface between the stripping
pressure side and the flash pressure side;
- a stripping vapour line in fluid communication with
the nitrogen stripper column at a level gravitationally
below the stripping section and arranged to receive at
least a stripping portion of said compressed vapour from
the process compressor;
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- a fuel gas vapour line fluidly connected with the
process compressor discharge outlet via a fuel gas
splitter arranged in a path between the process
compressor discharge outlet and the stripping vapour
line, for removing a fuel gas vapour stream comprising a
fuel gas portion of the compressed vapour from the
compressed vapour;
- a gas turbine fluidly connected with the fuel gas
splitter via a fuel gas line that bypasses the nitrogen
stripper column, wherein said gas turbine is arranged to
receive and combust the fuel gas portion of the
compressed vapour.
The invention will be further illustrated
hereinafter, using examples and with reference to the
drawing in which;
Fig. 1 schematically represents a process flow scheme
representing a method and apparatus incorporating an
embodiment of the invention; and
Fig. 2 schematically represents a process flow scheme
representing a method and apparatus incorporating another
embodiment of the invention;
Fig. 3 schematically represents a process flow scheme
representing a method and apparatus incorporating still
another embodiment of the invention; and
Fig. 4 schematically represents a process flow scheme
representing a method and apparatus incorporating still
another embodiment of the invention.
In these figures, same reference numbers will be used
to refer to same or similar parts. Furthermore, a single
reference number will be used to identify a conduit or
line as well as the stream conveyed by that line.
The present description concerns producing a
liquefied hydrocarbon product stream. A first nitrogen
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stripper feed stream comprising at least a first portion
of a cryogenic hydrocarbon composition is fed into a
nitrogen stripper column at a stripping pressure. The
cryogenic hydrocarbon composition contains a nitrogen-
and methane-containing liquid phase. A nitrogen-stripped
liquid is drawn from a sump space of the nitrogen
stripper column, depressurized to a flash pressure that
is lower than the stripping pressure, and fed to an end
flash separator. A flash vapour is generated during said
depressurizing. A liquefied hydrocarbon product stream
is discharged from the end flash separator as well as a
process vapour comprising said flash vapour. The process
vapour is compressed to at least the stripping pressure,
and, split in a stripping vapour stream and a fuel gas
vapour stream.
The stripping vapour stream is fed into the nitrogen
stripper column, while the fuel gas vapour stream is
removed from the compressed vapour and passed to a gas
turbine whereby the fuel gas vapour stream bypasses the
nitrogen stripper column. This fuel gas vapour stream is
identified as high quality fuel gas stream. A low
quality fuel gas is obtained from the overhead vapour
discharged from the nitrogen stripper column, which low
quality fuel gas is combusted in a combustion device
other than a gas turbine. Low quality in this context
means having a heating value that is lower compared to
the heating value of the high quality fuel gas vapour
stream, which is combusted in the gas turbine.
It has been found that the compressed vapour, which
according to the prior art process is used as stripping
vapour for the nitrogen stripper column, can have a
suitable composition and/or heating value for use as fuel
gas vapour in a gas turbine. As there is a suitable use
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f or at least some of the compressed vapour, there is an
opportunity to reduce the amount of stripping vapour
being sent to the nitrogen stripper column. This is
advantageous, as it eventually results in less cooling
duty being required to recondense excess methane that is
not required in the lower value fuel gas which is
obtained from the overhead vapour from the nitrogen
stripper column.
The proposed method and apparatus can be
advantageously applied for instance if the cryogenic
hydrocarbon composition comprises in the range of from
1 mol% to 7 mol% nitrogen. However, most benefit is
enjoyed in cases wherein the raw liquefied stream
comprises more than 3 mol% of nitrogen, as in such cases
a relatively high flow rate of flash vapour is generated,
in order to maintain the liquefied hydrocarbon product
stream within specification with regard to maximum
content of lower boiling constituents, such as nitrogen
in commercially tradable liquefied natural gas.
The cryogenic hydrocarbon composition may be produced
by means of a liquefier wherein a hydrocarbon stream is
condensed and subcooled into a raw liquefied stream,
followed by a pressure reduction system wherein the
pressure of the raw liquefied stream is reduced to form
the cryogenic hydrocarbon composition. The liquefier may
comprise a refrigerant circuit for cycling a refrigerant
stream. The refrigerant circuit may comprise a
refrigerant compressor coupled to a refrigerant
compressor driver, and arranged to compress the
refrigerant stream; and a cryogenic heat exchanger
arranged to establish an indirect heat exchanging contact
between a hydrocarbon stream and the refrigerant stream
of the refrigerant circuit, whereby a raw liquefied
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stream is formed out of the hydrocarbon stream comprising
a subcooled hydrocarbon stream. The liquefier may
further comprise a pressure reduction system arranged
downstream of the cryogenic heat exchanger and in fluid
communication therewith, to receive the raw liquefied
stream and to reduce pressure of the raw liquefied
stream. A rundown line may fluidly connect the pressure
reduction system with the cryogenic heat exchanger to
establish fluid communication for the raw liquefied
stream to pass from the cryogenic heat exchanger to the
pressure reduction system, wherein the end-flash
separator is arranged downstream of the pressure
reduction system and in fluid communication therewith to
receive the cryogenic hydrocarbon composition from the
pressure reduction system. Suitably, the gas turbine
that is fluidly connected with the fuel gas splitter via
the fuel gas line is the refrigerant compressor driver of
the refrigerant circuit in the liquefier. The gas
turbine is preferably selected from the group consisting
of aeroderivative gas turbines.
Accordingly, the method may suitably comprise cycling
a refrigerant stream in the liquefier, comprising driving
a refrigerant compressor and compressing said refrigerant
stream in the refrigerant compressor. A hydrocarbon
stream may be condensed and subcooled, comprising
indirectly heat exchanging said hydrocarbon stream
against the refrigerant stream in the liquefier, thereby
forming a raw liquefied stream at a liquefaction pressure
of higher than 2 bara. The raw liquefied stream may be
passed through a pressure reduction step, thereby
obtaining the cryogenic hydrocarbon composition
comprising nitrogen and a methane-containing liquid
phase. Suitably, the refrigerant compressor is driven by
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the mentioned gas turbine to which the fully which the
fuel gas vapour stream is passed and in which the fuel
gas vapour stream is combusted.
In preferred embodiments, the cryogenic hydrocarbon
composition is split into the first portion that is fed
to the nitrogen stripper column as part of the first
nitrogen stripper feed stream, and a second portion. The
second portion may have the same composition and phase as
the first portion, and may be fed into the end flash
separator after reducing the pressure of the second
portion to the flash pressure. The second portion
preferably bypasses the nitrogen stripper column between
the stream splitting and the feeding of the second
portion into the end flash separator.
Herewith, the liquid loading of the nitrogen stripper
column is reduced compared to when the entire feed of
cryogenic hydrocarbon composition is fed into the
nitrogen stripper column, while at the same time
sufficient liquid can be maintained in the nitrogen
stripper column to facilitate effective stripping using
the stripping vapour stream. Consequently, the nitrogen
stripper column can be sized smaller than in the case of
US application publication 2012/0167617 in which the
first gas/liquid separator receives all of the multi-
phase hydrocarbon stream that is to be treated.
The split ratio of the cryogenic hydrocarbon
composition into the first and second portions may
suitably be adjusted whereby maintaining the flow rate of
the first portion on a predetermined target flow rate.
The split ratio may be defined as the flow rate of the
first portion relative to the total flow rata of the
first and second portions together.
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Suitably, the nitrogen stripper column further
comprises at least one internal rectifying section, which
is arranged gravitationally higher than the stripping
section within said nitrogen stripper column. A
partially condensed intermediate stream may be formed
from the overhead vapour obtained from the overhead part
of the nitrogen stripping column, whereby the overhead
vapour is partially condensed by heat exchanging the
overhead vapour against an auxiliary refrigerant stream
and thereby passing heat from the overhead vapour to the
auxiliary refrigerant stream at a cooling duty. The
partially condensed intermediate stream comprises a
condensed fraction and a vapour fraction. The overhead
part is suitably located above the rectifying section.
The condensed fraction may be separated from the vapour
fraction, at a separation pressure, and at least a reflux
portion of the condensed fraction may be allowed to enter
the rectifying section in the nitrogen stripper column
from a level above the rectifying section.
The auxiliary refrigerant stream is suitably formed
by a slip stream of the cycled refrigerant stream from
the liquefier if a liquefier is provided, or by a slip
stream of the liquefied hydrocarbon product stream. An
advantage of the latter option is that it can be applied
regardless of type of liquefier or other source of the
cryogenic hydrocarbon composition, and it can be
retrofitted to any pre-existing liquefier or source of
the cryogenic hydrocarbon composition. An advantage of
using a slip stream of the cycled refrigerant stream is
that a separate refrigerant circuit does not have to be
provided merely for providing the auxiliary refrigerant
stream. Suitably, the slip stream is formed of a part of
the cycled refrigerant stream against which the
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hydrocarbon stream is subcooled. This is generally the
refrigerant stream that within the liquefier is adapted
to extract heat from the hydrocarbon stream at the lowest
temperature range. This makes it the most suitable
cycled refrigerant stream that is available in the
liquefier for the purpose of partly condensing the
vaporous reject stream.
With the currently proposed solutions, the amount of
nitrogen remaining in the produced liquefied hydrocarbon
product stream can be kept below a specified maximum
nitrogen specification, while rejected vapours generated
from the cryogenic hydrocarbon composition in order to
achieve the low amount of nitrogen in the produced
liquefied hydrocarbon product stream can be used to
satisfy two different kinds of fuel gas supplies. The
liquefied hydrocarbon product stream can be stored and
transported at its cryogenic temperature and
approximately atmospheric pressure.
The vapour fraction, which is discharged and
combusted in the combustion device other than the gas
turbine, may contain a significant amount of nitrogen,
possibly from 50 mol% to 95 mol% of nitrogen. However,
this vapour fraction can still be used as low quality
fuel gas stream.
The fuel gas vapour stream that is removed from the
compressed vapour may contain less than 30 mol% of
nitrogen, so that it can be used to fuel a gas turbine.
The fuel gas vapour stream generally contains more than
5 mol%, preferably more than 10 mol% of nitrogen.
Herewith it is achieved that the separation efficiency of
the nitrogen stripper column does not have to be
extremely high whereby some nitrogen is allowed to remain
in the nitrogen-stripped liquid. Herewith the nitrogen
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stripper column can have fewer theoretical stages and use
less heating and cooling duty. Furthermore, allowing
some nitrogen (up to 30 mol%) to end up in the compressed
vapour allows for the optional second portion of the
cryogenic hydrocarbon composition (which contains a
relatively high amount of nitrogen) to bypass the
nitrogen stripper column and be fed directly into the
end-flash separator. Herewith the nitrogen stripper
column can be kept smaller as well.
If the nitrogen content in the compressed vapour is
still too high for the selected gas turbine, the fuel gas
vapour stream that is removed from the compressed vapour
may be blended with other fuel gas to bring the fuel on
specification. In such cases the invention provides the
benefit that the blending requirements are less demanding
than if the fuel gas had more than 30 mol% of nitrogen.
The fuel gas portion of the compressed vapour may
have to be subjected to further compression in order to
meet a pre-determined gas turbine fuel gas pressure
specification.
Preferably the vapour fraction is used as the low
quality fuel gas stream at a fuel gas pressure not higher
than the stripping pressure. Herewith, the need of a
dedicated low quality fuel gas compressor can be avoided.
Moreover, by selecting the stripping pressure at a
pressure exceeding the low quality fuel gas pressure, any
compression applied to the process vapour has an added
associated benefit, such as adding of enthalpy to the
process vapour which allows it to be used as stripping
vapour.
The proposed method and apparatus are specifically
suitable for application in combination with a liquefier
in the form of hydrocarbon liquefier, such as a natural
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gas liquefier, in order to remove nitrogen from the raw
liquefied product that is produced in the hydrocarbon
liquefier. It has been found that even when the raw
liquefied product - or the cryogenic hydrocarbon
composition - contains a fairly high amount of from
3 mol% (or from about 3 mol%) up to 7 mol% (or up to
about 7 mol%) of nitrogen, the resulting liquid
hydrocarbon product can meet a nitrogen content within a
specification of between from 0.5 to 1 mol% nitrogen. A
limited amount of the nitrogen from the raw liquefied
product - or the cryogenic hydrocarbon composition - ends
up in the high quality fuel gas which is combusted in the
gas turbine. The remainder of the nitrogen is discharged
as part of the vapour fraction in the off gas, together
with a non-zero amount of methane.
Figure 1 illustrates an apparatus comprising an
embodiment of the invention. A cryogenic hydrocarbon
composition comprising a nitrogen- and methane-containing
liquid phase is conveyed in a cryogenic feed line 8. The
source of the cryogenic hydrocarbon composition is not a
limitation of the invention in its broadest definition,
but for the sake of completeness one embodiment is
illustrated wherein the cryogenic hydrocarbon composition
is sourced from a liquefier 100.
Such a liquefier 100 would typically be provided
upstream of the cryogenic feed line 8. The liquefier 100
may be in fluid communication with the cryogenic feed
line 8 via a pressure reduction system 5, which
communicates with the liquefier 100 via a rundown line 1.
The pressure reduction system 5 is arranged downstream of
the cryogenic heat exchanger 180 and arranged to receive
and reduce the pressure of a raw liquefied stream from
the main cryogenic heat exchanger 180. In the embodiment
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as shown, the pressure reduction system 5 consists of a
dynamic unit, such as an expander turbine 6, and a static
unit, such as a Joule Thomson valve 7, but other variants
are possible including combinations of one or more static
units and/or one or more dynamic units. If an expander
turbine is used, it may optionally be drivingly connected
to a power generator.
In the example embodiment shown in Fig. 1, liquefier
100 comprises a refrigerant circuit 101 for cycling a
refrigerant. The refrigerant circuit 101 comprises a
refrigerant compressor 160 coupled to a refrigerant
compressor driver 190 in a mechanical driving engagement.
The refrigerant compressor 160 is arranged to compress a
spent refrigerant stream 150 and to discharge the
refrigerant, in a pressurized condition, into a
compressed refrigerant line 120. At least one reject
heat exchanger 124 is normally provided in the compressed
refrigerant line 120 of the refrigerant circuit 101. The
reject heat exchanger 124 is arranged to reject heat from
the pressurized refrigerant stream carried in the
compressed refrigerant line 120 to the ambient, either to
the air or to a body of water such as a lake, a river, or
the sea.
The liquefier 100 typically comprises a refrigerant
refrigerator arranged to refrigerate the pressurized
refrigerant from the compressed refrigerant line 120 from
which heat has been rejected in the reject heat exchanger
124. Herewith a refrigerated refrigerant stream is
obtained in a refrigerated refrigerant line 131.
The liquefier 100 further comprises a cryogenic heat
exchanger 180 connected to the refrigerant compressor 160
discharge outlet via the compressed refrigerant line 120.
In the embodiment of Figure 1, the cryogenic heat
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exchanger 180 also fulfils the function of the
refrigerant refrigerator discussed in the previous
paragraph, but this is not a requirement of the
invention. The cryogenic heat exchanger is generally
arranged to establish an indirect heat exchanging contact
between a hydrocarbon stream 110 and the refrigerant of
the refrigerant circuit 101.
A spent refrigerant line 150 connects the cryogenic
heat exchanger 180 with a main suction end of the
refrigerant compressor 160. The refrigerated refrigerant
line 131 is in fluid communication with the spent
refrigerant line 150, via a cold side of the cryogenic
heat exchanger 180. The hydrocarbon stream 110 flows
through a warm side of the cryogenic heat exchanger 180.
The cold side and the warm side are in heat exchanging
contact with each other. A main refrigerant control
valve 134 is configured in the refrigerated refrigerant
line 131.
The cryogenic heat exchanger 180 receives the
refrigerant stream in a depressurized condition from the
refrigerated refrigerant line 131 via the main
refrigerant control valve 134, and discharges into the
refrigerant compressor 160. Thus, the cryogenic heat
exchanger 180 forms part of the refrigerant circuit 101.
The cryogenic heat exchanger 180 may be provided in
any suitable form, including a printed circuit type, a
plate fin type, optionally in a cold box configuration,
or a tube-in-shell type heat exchanger such as a coil
wound heat exchanger or a spool wound heat exchanger.
A specific non-limiting example of the liquefier and
its refrigerant circuit based on a tube-in-shell type
heat exchanger and including the refrigerant compressor
and the cryogenic heat exchanger, is shown in Figures 2
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and 3. These figures will be described in detail later
below.
Back to the invention, the cryogenic feed line 8 is
in fluid communication with a nitrogen stripper column
20, via a first feed line 10 and a first inlet system 21.
The nitrogen stripper column 20 comprises an internal
stripping section 24 positioned within the nitrogen
stripper column 20. An overhead vapour discharge line 30
communicates with the nitrogen stripper column 20 via an
overhead space 26 within the nitrogen stripper column 20.
A nitrogen-stripped liquid discharge line 40 communicates
with the nitrogen stripper column 20 via a sump space 28
within the nitrogen stripper column 20 gravitationally
below the stripping section 24.
The nitrogen stripper column 20 of Fig. 1 comprises
vapour/liquid contact-enhancing means to enhance
component separation and nitrogen rejection. Depending
on the tolerable amount of nitrogen in the nitrogen
stripped liquid and the amount of nitrogen in the
cryogenic feed line 9, between 2 and 8 theoretical stages
may typically be needed in total. In one particular
embodiment, 4 theoretical stages may be required. Such
contact-enhancing means may be provided in the form of
trays and/or packing, in the form of either structured or
non-structured packing. At least part of the
vapour/liquid contact-enhancing means suitably forms part
of the internal stripping section 24.
An intermediate depressurizer 45 is arranged in the
nitrogen-stripped liquid discharge line 40, and thereby
fluidly connected to the nitrogen stripper column 20. The
intermediate depressurizer 45 may be functionally coupled
to a level controller LC, which cooperates with the sump
space 28 of the nitrogen stripper column 20.
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The intermediate depressurizer 45 is located on an
interface between a stripping pressure side comprising
the nitrogen stripper column 20, and a flash pressure
side. The flash pressure side comprises a liquid
hydrocarbon product line 90, arranged to discharge a
liquefied hydrocarbon product stream produced from the
nitrogen-stripped liquid 40. The flash pressure side also
comprises a process vapour line 60, arranged to receive a
process vapour produced from the nitrogen-stripped liquid
40.
If provided, the pressure reduction system 5 as
described above is typically located on the stripping
pressure side of the interface. In the embodiment as
shown, the flash pressure side furthermore comprises a
cryogenic storage tank 210 connected to the liquid
hydrocarbon product line 90 for storing the liquefied
hydrocarbon product stream, an optional boil-off gas
supply line 230, and an end flash separator 50.
Depending on the separation requirements, the end
flash separator 50 may be provided in the form of a
simple drum which separates vapour from liquid phases in
a single equilibrium stage (such as depicted in Fig. 1),
or a more sophisticated distillation column. Non-
limiting examples of possibilities are disclosed in US
Patents 5,421,165; 5,393,274; 6,014,869; 6,105,391; and
pre-grant publication US 2008/0066492.
The end flash separator 50 is configured in fluid
communication with the nitrogen stripper column 20 via
the intermediate depressurizer 45 and the nitrogen-
stripped liquid discharge line 40. The nitrogen-stripped
liquid discharge line 40 with the intermediate
depressurizer 45 are arranged to receive a nitrogen-
stripped liquid from the sump space of the nitrogen
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stripper column 20 and to discharge this liquid into the
end flash separator 50 in a depressurized condition. The
end flash separator 50 is in discharging communication
with the liquid hydrocarbon product line 90 on one side,
and in discharging communication with the process vapour
line 60 on the other side.
For instance, the end flash separator 50 may then be
connected to the cryogenic storage tank 210 via the
liquid hydrocarbon product line 90. A cryogenic pump 95
may be present in the liquid hydrocarbon product line 90
to assist the transport of the liquid hydrocarbon product
to the cryogenic storage tank 210.
The process vapour line 60, as shown in the
embodiment of Fig. 1, may be connected to the end flash
separator 50 via a flash vapour line 64 and flash vapour
flow control valve 65, as well as to the cryogenic
storage tank 210 via the optional boil-off gas supply
line 230. An advantage of the latter connection is that
it allows for handling of at least part of the boil-off
gas from the cryogenic storage tank 210 as part of the
process vapour.
Also configured on the interface between the
stripping pressure side and the flash pressure side, is a
process compressor 260. The process compressor 260 may
be driven by an electric motor or another suitable
driver. The process compressor 260 is arranged in the
process vapour line 60 to receive the process vapour and
to compress the process vapour. A compressed vapour
discharge line 70 is fluidly connected with a process
compressor discharge outlet 261 of the process compressor
260. Suitably, the process compressor 260 is provided
with anti-surge control and a recycle cooler which is
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used when the process compressor is on recycle and during
start-up (not shown in the drawing).
A stripping vapour line 71 is in fluid communication
with the nitrogen stripper column 20 via a second inlet
system 23 configured at a level gravitationally below the
stripping section 24 and preferably above the sump space
28. The stripping vapour line 71 is connected to the
compressed vapour discharge line 70 via an optional
bypass splitter 79. A stripping vapour valve 75 is
provided in the stripping vapour line 71.
Optionally, an external stripping vapour supply line
74 is provided in fluid communication with the second
inlet system 23 of the nitrogen stripper column 20. In
one embodiment, as shown in Fig. 1, the optional external
stripping vapour supply line 74 connects to the
compressed vapour discharge line 70. An external
stripping vapour flow control valve 73 is provided in the
optional external stripping vapour supply line 74. In
one embodiment, the optional external stripping vapour
supply line 74 is suitably connected to a hydrocarbon
vapour line in, or upstream of, the liquefier 100.
A combustion device 220 other than a gas turbine is
arranged fluidly connected to the nitrogen stripper
column 20 via at least the overhead vapour discharge line
30. This combustion device is arranged to receive a
discharge fraction from the overhead vapour carried in
the overhead vapour discharge line 30, and to combust the
discharge fraction as low quality fuel.
The combustion device 220 may comprise multiple
combustion units. It may include, for example, one or
more of a furnace, a boiler, an incinerator, a dual fuel
diesel engine, or cross-combinations thereof. A boiler
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and a duel fuel diesel engine may advantageously be
coupled to an electric power generator.
A fuel gas vapour line 240 is fluidly connected with
the process compressor discharge outlet 261 via a fuel
gas splitter 78 arranged in a path between the process
compressor discharge outlet 261 and the stripping vapour
line 71. The fuel gas vapour line 240 is intended for
removing a fuel gas vapour stream comprising a fuel gas
portion of the compressed vapour from the compressed
vapour in the compressed vapour discharge line 70. This
fuel gas vapour stream is identified as the high quality
fuel gas stream. A fuel flow control valve 245 may
optionally be arranged in the fuel gas vapour line 240.
A gas turbine 320 is fluidly connected with the fuel
gas splitter 78 via the fuel gas vapour line 240. This
gas turbine 320 is arranged to receive and combust the
fuel gas portion of the compressed vapour. The fuel gas
vapour line 240 bypasses the nitrogen stripper column 20.
Optionally, a fuel gas compressor 360 is arranged in the
fuel gas vapour line 240 between the fuel gas splitter 78
and the gas turbine 320.
Suitably, the gas turbine 320 in which the high
quality fuel gas vapour is ultimately combusted is the
refrigerant compressor driver 190 that is in driving
engagement with the refrigerant compressor 160. The gas
turbine 320 may drive the refrigerant compressor 160.
A vapour recycle line 87 is optionally configured to
receive at least a vaporous recycle portion of the vapour
from the overhead discharge line 30. The vapour recycle
line 87 bypasses the nitrogen stripper column 20, and
feeds back into at least one of the group consisting of:
the liquid hydrocarbon product line 90 and the process
vapour line 60. A vapour recycle flow control valve 88
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is preferably provided in the vapour recycle line 87. A
benefit of the proposed vapour recycle line 87 is that it
allows for selectively increasing of the nitrogen content
in the liquefied hydrocarbon product stream 90. The
vapour recycle line 87 suitably feeds into the end flash
separator 50.
The first feed line 10 may connect the cryogenic feed
line 8 with the first inlet system 21 of the nitrogen
stripper column 20 via an optional initial stream
splitter 9 arranged between the cryogenic feed line 8 and
the first feed line 10.
An optional second feed line 11 is connected, at an
upstream side thereof, to the optional initial splitter
9. Via such initial stream splitter 9 and second feed
line 11, the cryogenic feed line 8 can be connected to
the end-flash separator 50 whereby bypassing the nitrogen
stripper column 20, in addition to the connection already
described above via first feed line 10 and the nitrogen-
stripped liquid discharge line 40 which does not bypass
the nitrogen stripper column 20.
The optional initial splitter 9 is configured to
divide the cryogenic hydrocarbon composition that flows
through the cryogenic feed line 8 into a first portion,
which is passed to the first feed line 10, and a second
portion, which is passed to the second feed line 11. A
benefit of the second feed line 11 and the initial
splitter 9 is that the nitrogen stripper column 20 can be
sized smaller than in the case that the cryogenic feed
line 8 and the first feed line 10 would be directly
connected without a splitter whereby all of the cryogenic
hydrocarbon composition is let into the nitrogen stripper
column 20 via the first inlet system 21.
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Preferably, the second feed line 11 does not pass
through any indirect heat exchanger functional to
indirectly exchange heat with any process stream.
In embodiments using the optional initial splitter 9,
a bypass stream flow control valve 15 may advantageously
be arranged in the second feed line 11. The bypass
stream flow control valve is functionally connected to a
flow controller PC provided in the first feed line 10.
The flow controller FC is configured to maintain the flow
rate of said first portion though the first feed line 10
on a predetermined target flow rate, by controlling a
split ratio of the cryogenic hydrocarbon composition
flowing through the cryogenic feed line 8 into the first
and second portions.
Optionally, the nitrogen stripper column 20 comprises
an internal rectifying section 22 in addition to the
internal stripping section 24. The internal rectifying
section 22 is positioned within the nitrogen stripper
column 20, gravitationally higher than the stripping
section 24. The first inlet system 21 is provided
gravitationally between the internal rectifying section
22 and the internal stripping section 24. The overhead
part 26 is formed by a space within the nitrogen stripper
column 20, gravitationally above the rectifying section
22.
The optional internal rectifying section 22 may
comprise vapour/liquid contact-enhancing means similar to
the internal stripping section 24, to further enhance
component separation and nitrogen rejection.
Typically, the nitrogen stripper column 20 cooperates
with a condenser to provide downward liquid flow through
the internal stripping section 24 and/or the optional
internal rectifying section 22. For example, in Figure 1
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the condenser is provided in the form of an overhead
condenser 35 external to the nitrogen stripper column 20,
whereas in Figure 2 it is provided in the form of an
integrated internal overhead condenser 235, which is
internally configured inside the overhead part 26 within
the nitrogen stripper column 20.
Such condenser may be advantageously utilized to re-
condense at least part of compressed process vapour from
the compressed vapour discharge line 70. For instance,
in the embodiment of Figure 1, the overhead condenser 35
is arranged in the overhead vapour discharge line 30.
Inside the overhead condenser 35 the overhead vapour can
pass in indirect heat exchange contact with an auxiliary
refrigerant stream 132, whereby heat passes from the
overhead vapour to the auxiliary refrigerant stream at a
cooling duty. An auxiliary refrigerant stream flow
control valve 135 is provided in the auxiliary
refrigerant line 132.
A cooling duty controller 34 may be provided to
control the cooling duty, being the rate at which heat
passes from the overhead vapour to the auxiliary
refrigerant stream. Suitably, the cooling duty
controller 34 is configured to control the cooling duty
in response to an indicator of heating value of the off
gas relative to a demand for heating power. In the
embodiment as shown, the cooling duty controller 34 is
embodied in the form of a pressure controller PC and the
auxiliary refrigerant stream flow control valve 135,
which are functionally coupled to each other.
Still referring to Figure 1, an overhead separator 33
is arranged on a downstream side of the overhead vapour
discharge line 30. The overhead vapour discharge line 30
discharges into the overhead separator 33. The overhead
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separator 33 is arranged to separate any, non-condensed,
vapour fraction from any condensed fraction of the
overhead vapour. A vapour fraction discharge line 80 is
arranged to discharge the vapour fraction.
Suitably, the combustion device 220 is arranged on a
downstream end of the vapour fraction discharge line 80,
to receive at least a fuel portion of the vapour fraction
in the vapour fraction discharge line 80. Suitably, the
configuration of the optional vapour recycle line 87
comprises an optional vapour fraction splitter 89, which
may be provided in the vapour fraction line 80, allowing
controlled fluid communication between the vapour
fraction line 80 and the vapour recycle line 87.
A cold recovery heat exchanger 85 may be provided in
the vapour fraction discharge line 80, to preserve the
cold vested in the vapour fraction 80 by heat exchanging
against a cold recovery stream 86 prior to feeding the
vapour fraction 80 to any combustion device.
In one embodiment, the cold recovery stream 86 may
comprise or consist of a side stream sourced from the
hydrocarbon feed stream in the hydrocarbon feed line 110
of the liquefier 100. The resulting cooled side stream
may for instance be combined with the cryogenic
hydrocarbon composition in the cryogenic feed line 8.
Thus, the cold recovery heat exchanging in the cold
recovery heat exchanger 85 supplements the production
rate of the cryogenic hydrocarbon composition. In
another embodiment, the cold recovery stream 86 may
comprise or consist of the overhead vapour in the
overhead vapour discharge line 30, preferably in the part
of the overhead vapour discharge line 30 where through
the overhead vapour is passed from the nitrogen stripper
column 20 to the overhead condenser 35. Herewith the
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duty required from the auxiliary refrigerant stream 132
in the overhead condenser 35 would be reduced.
A reflux system is arranged to allow at least a
reflux portion 36 of the condensed fraction into the
nitrogen stripper column 20 at a level above the
rectifying section 22. In the embodiment of Figure 1,
the reflux system comprises a condensed fraction
discharge line 37 fluidly connected to a lower part of
the overhead separator 33, an optional reflux pump 38
provided in the condensed fraction discharge line 37, and
an optional condensed fraction splitter 39. The optional
condensed fraction splitter 39 fluidly connects the
condensed fraction discharge line 37 with the nitrogen
stripper column 20, via a reflux portion line 36 and a
reflux inlet system 25, and with an optional liquid
recycle line 13. The optional liquid recycle line 13 is
in liquid communication with the liquid hydrocarbon
product line 90. Liquid communication means that the
liquid recycle line 13 is connected to any suitable
location from where at least a part of a liquid recycle
portion can flow into the liquid hydrocarbon product line
90 while staying in the liquid phase. Thus, the liquid
recycle line 13 may for instance be connected directly to
one or more selected from the group consisting of: the
nitrogen stripper column 20, the cryogenic feed line 8,
the first feed line 10, the second feed line 11, the
nitrogen-stripped liquid discharge line 40, the end flash
separator 50, and the liquid hydrocarbon product line 90.
A recycle valve 14 is configured in the optional liquid
recycle line 13. An optional reflux flow valve 32
functionally controlled by a reflux flow controller (not
shown) may preferably be provided in the reflux portion
line 36.
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The liquid recycle line 13 is in liquid communication
with the liquid hydrocarbon product line 90, preferably
via a recycle path that does not pass through the
rectifying section 22 if it is provided. This way the
liquid recycle line 13 helps to avoid feeding too much
liquid onto the rectifying section 22 and to avoid
passing the recycle liquid through the rectifying section
22. This is beneficial to avoid disturbing the
equilibrium in the nitrogen stripper column 20.
The optional bypass splitter 79 is in fluid
communication with the overhead vapour discharge line 30,
preferably on an upstream side of the overhead condenser
35 if the latter is provided. Hereto an optional vapour
bypass line 76 may be provided between the optional
bypass splitter 79 and the overhead vapour discharge line
30. A vapour bypass control valve 77 is preferably
provided in the vapour bypass line 76. A benefit of such
a vapour bypass line 76 is that at times when there is an
excess of process vapour, this can be processed together
with the off gas in the vapour fraction discharge line 80
without upsetting the material balance in the nitrogen
stripper column 20. The vapour bypass line 76 suitably
extends along a bypass path between the bypass splitter
79 the overhead vapour discharge line 30 on an upstream
side of the overhead condenser 35. The bypass path
extends between the bypass splitter 79 and the overhead
vapour discharge line 30 and/or the vapour fraction
discharge line 80. The bypass path does not pass through
the internal stripping section 24 in the nitrogen
stripper column 20. This way it can be avoided that the
non-stripping portion passes through the internal
stripping section 24, which helps to avoid disturbing the
equilibrium in the nitrogen stripper column 20.
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The apparatus described above may be used in a method
described as follows.
A cryogenic hydrocarbon composition 8 comprising a
nitrogen- and methane-containing liquid phase is provided
at an initial pressure and an initial temperature.
Providing of the cryogenic hydrocarbon composition 8 may
comprise passing a hydrocarbon stream 110 through the
liquefier 100. The hydrocarbon stream 110 may be
condensed and subcooled in the liquefier 100. The
condensing and subcooling of the hydrocarbon stream 110
preferably involves indirectly heat exchanging the
hydrocarbon stream 110 against the refrigerant in the
liquefier 100. The thus formed subcooled liquefied
hydrocarbons stream is referred to as the raw liquefied
stream. Thus the raw liquefied stream is formed out of
the hydrocarbon stream by condensing and subsequently
subcooling the hydrocarbon stream.
For example, in such a liquefier 100, the hydrocarbon
stream 110 comprising a hydrocarbon-containing feed
vapour may be heat exchanged, for example in the
cryogenic heat exchanger 180, against a main refrigerant
stream, thereby liquefying the feed vapour of the feed
stream to provide the raw liquefied stream within the
rundown line 1. The desired cryogenic hydrocarbon
composition 8 may then be obtained from the raw liquefied
stream 1. The raw liquefied stream may be discharged in
the rundown line 1 from the liquefier 100. The cryogenic
hydrocarbon composition 8 may be obtained from the raw
liquefied stream, for instance by passing the raw
liquefied stream through a pressure reduction step in
pressure reduction system 5. In this pressure reduction
step, the pressure may be reduced from the liquefaction
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pressure to the initial pressure of between 2 and 15 bar
absolute.
The cryogenic hydrocarbon composition 8 may be
obtained from natural gas or petroleum reservoirs or coal
beds. As an alternative the cryogenic hydrocarbon
composition 8 may also be obtained from another source,
including as an example a synthetic source such as a
Fischer-Tropsch process. Preferably the cryogenic
hydrocarbon composition 8 comprises at least 50 mol%
methane, more preferably at least 80 mol% methane. A
preferred initial temperature of lower than -130 C may
be achieved by passing a hydrocarbon stream 110 through a
liquefaction system 100. An embodiment of passing the
hydrocarbon stream 110 through the liquefaction system
100 will be described in more detail below.
A first nitrogen stripper feed stream 10, obtained
from the cryogenic hydrocarbon composition 8, is then fed
into the nitrogen stripper column 20 at a stripping
pressure, via the first inlet system 21. The first
nitrogen stripper feed stream 10 comprises at least a
first portion of the cryogenic hydrocarbon composition 8.
In preferred embodiments the cryogenic hydrocarbon
composition 8 undergoes stream splitting into said first
portion and a second portion, but such embodiments will
be discussed in more detail herein below.
The stripping pressure is usually equal to or lower
than the initial pressure. The stripping pressure in
preferred embodiments is selected in a range of between 2
and 15 bar absolute. Preferably, the stripping pressure
is at least 4 bara, because with a somewhat higher
stripping pressure the stripping vapour in stripping
vapour line 71 can benefit from some additional enthalpy
(in the form of heat of compression) that is added to the
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process stream 60 in the process compressor 260.
Preferably, the stripping pressure is at most 8 bara in
order to facilitate the separation efficiency in the
nitrogen stripper column 20. Moreover, if the stripping
pressure is within a range of between 4 and 8 bara, the
off gas in the vapour fraction discharge line 80 can
readily be used as so-called low pressure fuel stream
without a need to further compress.
An overhead vapour stream 30 is obtained from the
overhead part 26 of the nitrogen stripping column 20. A
vapour fraction 80 obtained from the overhead vapour
stream 30, and comprising a discharge fraction of the
overhead vapour 30, is discharged as off gas. Suitably,
at least a fuel portion of the vapour fraction 80 is
passed to the combustion device 220 where it is
combusted. Preferably, the fuel portion is passed into
the combustion device 220 at a fuel gas pressure that is
not higher than the stripping pressure. The vapour
fraction 80 from which the fuel portion is extracted has
a first heating value.
A nitrogen-stripped liquid 40 is drawn from the sump
space 28 of the nitrogen stripper column 20. The
temperature of the nitrogen-stripped liquid 40 is
typically higher than that of the first nitrogen stripper
feed stream 10. Typically, it is envisaged that the
temperature of the nitrogen-stripped liquid 40 is higher
than that of the first nitrogen stripper feed stream 10
and between -140 C and -80 C, preferably
between -140 C and -120 C.
The nitrogen-stripped liquid 40 is then
depressurized, preferably employing the intermediate
depressurizer 45, to a flash pressure that is lower than
the stripping pressure. At least part of a liquefied
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hydrocarbon product stream 90 and a process vapour stream
60 are formed from the nitrogen-stripped liquid 40 as a
result of the depressurization in the intermediate
depressurizer 45.
The intermediate depressurizer 45 may be controlled
by the level controller LC, set to increase the flow rate
through the intermediate depressurizer 45 if the level of
liquid accumulated in the sump space 28 of the nitrogen
stripper column 20 increases above a target level. As a
result of the depressurization, the temperature may for
instance be lowered to below -160 C. The liquefied
hydrocarbon product stream 90 that is produced hereby can
typically be kept at an atmospheric pressure in an open
insulated cryogenic storage tank.
A flash vapour is also generated during the
depressurizing of the nitrogen-stripped liquid stream 40.
The flash vapour is phase separated from the nitrogen-
stripped liquid stream 40 in the end flash separator 50
at a flash separation pressure that is equal to or lower
than the flash pressure. The process vapour stream 60
comprises the flash vapour thus separated.
The process vapour 60 is then compressed to at least
the stripping pressure, thereby obtaining a compressed
vapour stream 70. A stripping vapour stream 71 is
obtained from the compressed vapour stream 70, and passed
into the nitrogen stripper column 20 via the second inlet
system 23. The stripping vapour stream 71 comprises at
least a stripping portion of the compressed vapour 70.
This stripping vapour can percolate upward through the
stripping section 23 in contacting counter current with
liquids percolating downward through the stripping
section 23.
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If the external stripping vapour supply line 74 is
provided in fluid communication with the second inlet
system 23, an external stripping vapour may selectively
be fed into the nitrogen stripper column 20 via the
second inlet system 23. Herewith major disruption of the
nitrogen stripper column 20 may be avoided, for instance,
in case the process compressor 260 is not functioning to
provide the compressed vapour stream 70 in sufficient
amounts.
The stripping vapour stream 71 is obtained from the
compressed vapour stream 70 from which a fuel gas vapour
stream 240 has been removed. Thus the stripping vapour
stream 71 does not contain a fuel gas portion of the
compressed vapour 70 that is removed from the compressed
vapour 70 as fuel gas vapour stream 240. This fuel gas
vapour stream 240 has a second heating value that is
higher than the first heating value. The thus obtained
fuel gas vapour stream 240 is passed to a gas turbine
320, whereby the fuel gas vapour stream 240 bypasses the
nitrogen stripper column 20 once it has been removed from
the compressed vapour 70. The fuel gas vapour stream 240
is combusted in the gas turbine 320.
The first and second heating values define the amount
of heat that can be released by combustion of a mole of
the fuel gas. This can be either the so-called "high"
heating value as the "low" heating value as long as the
same conditions are used for comparing the two heating
values. Preferably the "low" heating value is used to
compare the two heating values, as this is the closest to
the combustion conditions used in the invention. The
heating value may be determined using ASTM D3588-98 or
DIN 51857 standards applied regardless of the composition
of the vapour fraction 80 and/or the compressed vapour
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70. As a result of cryogenic distillation in the
nitrogen stripper column 20, the first heating value
(belonging to the vapour fraction 80) is lower than the
second heating value (belonging to the compressed vapour
70).
Optionally, the fuel gas vapour stream 240 is further
compressed, for instance in the optional fuel gas
compressor 360, to a second fuel gas pressure that is
higher than the pressure of the compressed vapour stream
70.
As described above, an optional initial stream
splitter 9 may be arranged between the cryogenic feed
line 8 and the first feed line 10. In such embodiments,
when the cryogenic hydrocarbon composition 8 arrives at
the initial stream splitter 9 the cryogenic hydrocarbon
composition 8 is split in the initial stream splitter 9
into the first portion in the form of the first nitrogen
stripper feed stream in the first feed line 10, and the
second portion in the form of a bypass feed stream in the
second feed line 11. The second portion has the same
composition and phase as the first portion. The stream
splitting of the cryogenic hydrocarbon composition 8 into
the first and second portions is such that the second
portion 11 has the same composition and phase as the
first portion 10.
The second portion of the cryogenic hydrocarbon
composition 8, in the form of the bypass feed stream 11,
is passed to and into the end flash separator 50. Before
feeding the second portion into the end flash separator
50, the second portion is subjected to depressurizing to
the flash pressure. From the stream splitting in the
initial stream splitter 9 to the feeding into the end
flash separator 50, the second portion bypasses the
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nitrogen stripper column 20. The second portion
originating from the initial stream splitter 9 is
preferably not subject to any functional indirect heat
exchange in any single pass from the initial stream
splitter 9 to said subsequent feeding. In this context
the term "functional indirect heat exchange" is intended
to exclude inherent "non-functional" heat exchange and/or
de-minimis heat exchange between the second portion in
second feed line 11 and the ambient surrounding the
second feed line 11.
The split ratio, defined as the flow rate of the
second portion relative to the flow rate of the cryogenic
hydrocarbon composition in the cryogenic hydrocarbon
composition line 8, may be controlled using the bypass
stream flow control valve 15. This bypass stream flow
control valve 15 may be controlled by the flow controller
FC to maintain a predetermined target flow rate of the
first nitrogen stripper feed stream 10 into the nitrogen
stripper column 20. The flow controller FC will increase
the open fraction of the bypass stream flow control valve
15 if there is a surplus flow rate that exceeds the
target flow rate, and decrease the open fraction if there
is a flow rate deficit compared to the target flow rate.
As a general guideline, the size of the nitrogen
stripper and a design split ratio are determined based on
the expected design amount of nitrogen in the feed. If,
for instance due to some variation in the feed, a higher
content of nitrogen than the design amount, the operation
may continue using a lower value for the split ratio than
the design split ratio. A higher value would be
preferred for lower content of nitrogen in the condensed
hydrocarbon composition.
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Depending on the source, the hydrocarbon stream 110
may contain varying amounts of components other than
methane and nitrogen, including one or more non-
hydrocarbon components other than water, such as 002, Hg,
H2S and other sulphur compounds; and one or more
hydrocarbons heavier than methane such as in particular
ethane, propane and butanes, and, possibly lesser amounts
of pentanes and aromatic hydrocarbons. Hydrocarbons with
a molecular mass of at least that of propane may herein
be referred to as 03+ hydrocarbons, and hydrocarbons with
a molecular mass of at least that of ethane may herein be
referred to as C2+ hydrocarbons.
If desired, the hydrocarbon stream 110 may have been
pre-treated to reduce and/or remove one or more of
undesired components such as CO2 and H2S, or have
undergone other steps such as pre-pressurizing or the
like. Such steps are well known to the person skilled in
the art, and their mechanisms are not further discussed
here. The composition of the hydrocarbon stream 110 thus
varies depending upon the type and location of the gas
and the applied pre-treatment(s).
A refrigerant may be cycled in the refrigerant
circuit 101 of the liquefier 100. Cycling comprises
driving the refrigerant compressor 160, and compressing
the refrigerant stream in the refrigerant compressor 160.
Particularly, spent refrigerant 150 is compressed in the
refrigerant compressor 160, to form a compressed
refrigerant 120 out of the spent refrigerant 150. Heat
is removed from the compressed refrigerant discharged
from the refrigerant compressor 160, via the one or more
heat exchangers that are provided in the compressed
refrigerant line 120 including the least one reject heat
exchanger 124. This results in an at least partially
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condensed compressed refrigerant. The at least partially
condensed compressed refrigerant is then refrigerated by
passing it through a heat exchange, for example the
cryogenic heat exchanger 180, whereby indirectly heat
exchanging the at least partially condensed compressed
refrigerant against the main refrigerant stream. As a
result, the refrigerant is subcooled and discharged into
the refrigerated refrigerant line 131. It may be passed
to the cold side of the cryogenic heat exchanger 180
where it is allowed to evaporate by picking up heat from
the hydrocarbon stream 110 and/or the at least partially
condensed compressed refrigerant stream. The spent
refrigerant stream 150 is formed by the evaporated
refrigerant being discharged from the cold side of the
cryogenic heat exchanger 180.
Suitably, the gas turbine 320 in which the fuel gas
vapour stream 240 is ultimately combusted is the
refrigerant compressor driver 190 that is in driving
engagement with the refrigerant compressor 160. The gas
turbine 320 may drive the refrigerant compressor 160.
Obtaining of the stripping vapour stream 71 from the
compressed vapour stream 70 may further involve splitting
the compressed vapour stream 70 into the stripping vapour
stream 71 and a vapour bypass portion that does not
comprise the stripping portion and that can be
selectively injected into the overhead vapour line 30
whereby bypassing at least the stripping section 22 of
the nitrogen stripper column 20 or possibly bypassing the
entire the nitrogen stripper column 20. The selective
injection may be controlled using the vapour bypass
control valve 77. Suitably, the vapour bypass control
valve 77 is controlled by a pressure controller on the
compressed vapour line 70, which is set to increase the
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open fraction of the vapour bypass control valve 77 in
response to an increasing pressure in the compressed
vapour line 70. It is envisaged that the flow rate of
the vapour bypass portion that is allowed to flow through
the vapour bypass line 76 into the overhead vapour stream
30 is particularly high during so-called loading mode at
which time usually the amount of boil-off gas is much
higher than in is usually the case during so-called
holding mode. The vapour bypass control valve 77 may be
fully closed during normal operation in holding mode.
In preferred embodiments, a partially condensed
intermediate stream is formed from the overhead vapour
30. This involves indirectly heat exchanging the
overhead vapour 30 against the auxiliary refrigerant
stream in 132 the auxiliary refrigerant line 132, whereby
heat is passed from the overhead vapour 30 to the
auxiliary refrigerant stream 132 at a selected cooling
duty. The resulting partially condensed intermediate
stream comprises a condensed fraction and a vapour
fraction. If the nitrogen stripper column 20 is equipped
with the optional internal rectifying section 22 as
described above, the overhead vapour stream 30 is
preferably obtained from an overhead part of the nitrogen
stripping column 20 above the rectifying section 22.
The condensed fraction is separated from the vapour
fraction in the overhead separator 33, at a separation
pressure that may be lower than the stripping pressure,
and preferably lies in a range of between 2 and 15 bar
absolute. The vapour fraction is discharged via the
vapour fraction discharge line 80. The condensed
fraction is discharged from the overhead separator 33
into the reflux system, for instance via the condensed
fraction discharge line 37.
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At least a reflux portion 36 of the condensed
fraction is allowed into the nitrogen stripper column 20,
starting at a level above the rectifying section 22. In
the case of the embodiment of Figure 1, the condensed
fraction may pass through the optional reflux pump 38
(and/or it may flow under the influence of gravity). The
reflux portion is then obtained from the condensed
fraction and charged into the nitrogen stripper column 20
via reflux inlet system 25 and reflux portion line 36.
In the case of the embodiment of Figures 2 and 3, the
condensed fraction is separated inside the overhead part
of the nitrogen stripper column 20 and therefore already
available above the rectifying section to percolate
downward through the rectifying section 22, in contact
with vapours rising upward through the rectifying section
22.
The reflux portion may contain all of the condensed
fraction, but optionally, the condensed fraction is split
in the optionally provided condensed fraction splitter 39
into a liquid recycle portion which is charged via liquid
recycle line 13 into, for instance, the first feed stream
10, and the reflux portion which is charged into the
nitrogen stripper column 20 via reflux inlet system 25
and reflux portion line 36. The capability of splitting
the condensed fraction into the reflux portion 36 and the
liquid recycle portion 13 is beneficial to divert any
excess condensed fraction around the rectifying section
22 such as not to upset the operation of the rectifying
section 22. The recycle valve 14 may suitably be
controlled using a flow controller provided in the
condensed fraction discharge line 37 and/or a level
controller provided on the overhead separator 33.
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The partially condensing may also involve direct
and/or indirect heat exchanging with other streams in
other consecutively arranged overhead heat exchangers.
For instance, the cold recovery heat exchanger 85 may be
such an overhead heat exchanger whereby the partially
condensing of the overhead stream further comprises
indirect heat exchanging against the vapour fraction 80.
The optional vapour recycle line 87 may be
selectively employed, suitably by selectively opening the
vapour recycle control valve 88, to increase the amount
of nitrogen that remains in the liquefied hydrocarbon
product stream 90. This may be done by drawing a
vaporous recycle portion from the vapour fraction,
depressurising the vaporous recycle portion to the flash
pressure and subsequently injecting the vaporous recycle
portion into at least one of: the nitrogen-stripped
liquid 40; the liquefied hydrocarbon product stream 90;
and the process vapour 60. Suitably, the vaporous
recycle portion is injected into the end flash separator
50 such as is illustrated in Figure 1. The remaining
part of the vapour fraction 80 that is not passed into
the vapour recycle line 87 may form the fuel portion that
may be conveyed to the combustion device 220.
The overhead condenser 35 thus allows for re-
condensation of vaporous methane that has previously
formed part of cryogenic hydrocarbon composition 8, to
the extent that it is in excess of a target amount of
methane in the discharged vapour fraction 80, by adding
any such vaporous methane containing stream to the
(compressed) process vapour stream. Once forming part of
the process vapour 60 or compressed process vapour 70,
the vaporous methane can find its way to the heat
exchanging with the auxiliary refrigerant 132 by which it
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is selectively condensed out of the overhead vapour 30
from the nitrogen stripper column 20, while allowing the
majority of the nitrogen to be discharged with the off
gas. Herewith it becomes possible to remove sufficient
nitrogen from the cryogenic hydrocarbon composition 8 to
produce a liquefied hydrocarbon product stream 90 within
a desired maximum specification of nitrogen content,
while as the same time not producing more heating
capacity in the off gas than needed.
Vaporous methane that has previously formed part of
cryogenic hydrocarbon composition 8 includes the flash
vapour in the flash vapour line 64 from the end flash
separator 50. In addition, it may also may include boil-
off gas 230, which typically results from adding of heat
to the liquefied hydrocarbon product stream 90 whereby a
part of the liquefied hydrocarbon product stream 90
evaporates to form the boil-off gas. In order to
facilitate transferring of the boil-off gas to the
process vapour stream 60, an optional boil-off gas supply
line 230 may be employed to connect a vapour space in the
cryogenic storage tank 210 with the process vapour line
60. In order to facilitate transferring the flash vapour
64 to the process vapour stream 60, and to further
denitrogenate the liquefied hydrocarbon product stream
90, preferably, the nitrogen-stripped liquid after its
depressurization is fed into the optional end flash
separator where it is phase separated at a flash
separation pressure into the liquefied hydrocarbon
product stream 90 and the flash vapour 64.
The proposed solution may facilitate the handling of
these vapours. It combines the removal of nitrogen from
the cryogenic hydrocarbon composition 8 with re-
condensation of excess vaporous methane. This forms an
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elegant solution in situations where little plant fuel is
demanded, such as could be the case in a plant driven by
gas turbines of the aero derivative type, which are
relatively fuel efficient compared to industrial frame
type gas turbines.
The auxiliary refrigerant 132 stream may suitably be
formed by a slip stream of the cycled refrigerant stream
from the liquefier 100, more preferably by a slip stream
of the light refrigerant fraction, as illustrated in
Figure 2, or by a slip stream of the liquefied
hydrocarbon product stream 90. This latter case is
illustrated in Figures 3 and 4. These options may also
be applied in the embodiment of Figure 1, and will be
illustrated in more detail below.
It is also possible to employ a separate
refrigeration cycle for the purpose of partially
condensing the overhead vapour stream 30. Such separate
refrigeration cycle may for instance employ a cycled
refrigerant fluid containing a large relative amount of
nitrogen and/or argon, such as at least 80 mol% of
nitrogen and/or argon. However, employing a slip stream
from the refrigerant stream that is already being cycled
in the liquefier, or a slip stream of the hydrocarbon
product stream 90 has as advantage that the amount of
additional equipment to be installed is minimal. For
instance, no additional auxiliary refrigerant compressor
and auxiliary refrigerant condenser would be needed.
An advantage of employing a slip stream of the
hydrocarbon product stream 90 for this purpose is that it
can relatively easily be implemented on an already
existing plant without the need to interrupt or modify
the pre-existing liquefier 100. Moreover, it is the
coldest stream readily available in the plant, without
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the need for providing a dedicated refrigeration cycle,
and there is plenty of it.
The liquefier 100 has so far been depicted very
schematically. It can represent any suitable hydrocarbon
liquefaction system and/or process, in particular any
natural gas liquefaction process producing liquefied
natural gas, and the invention is not limited by the
specific choice of liquefaction system. Examples of
suitable liquefaction systems employ single refrigerant
cycle processes (usually single mixed refrigerant - SMR -
processes, such as PRICO described in the paper "LNG
Production on floating platforms" by K R Johnsen and P
Christiansen, presented at Gastech 1998 (Dubai), but also
possible is a single component refrigerant such as for
instance the BHP-cLNG process also described in the
afore-mentioned paper by Johnsen and Christiansen);
double refrigerant cycle processes (for instance the much
applied Propane-Mixed-Refrigerant process, often
abbreviated C3MR, such as described in for instance US
Patent 4,404,008, or for instance double mixed
refrigerant - DMR - processes of which an example is
described in US Patent 6,658,891, or for instance two-
cycle processes wherein each refrigerant cycle contains a
single component refrigerant); and processes based on
three or more compressor trains for three or more
refrigeration cycles of which an example is described in
US Patent 7,114,351.
Other examples of suitable liquefaction systems are
described in: US Patents 5,832,745 (Shell SMR);
6,295,833; 5,657,643 (both are variants of Black and
Veatch SMR); 6,370,910 (Shell DMR). Another suitable
example of DMR is the so-called Axens LIQUEFIN process,
such as described in for instance the paper entitled
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"LIQUEFIN: AN INNOVATIVE PROCESS TO REDUCE LNG COSTS" by
P-Y Martin et a/, presented at the 2211d World Gas
Conference in Tokyo, Japan (2003). Other suitable three-
cycle processes include for example US Patents 6,962,060;
5,669,234 (commercially known as optimized cascade
process); 7,127,914; 6,253,574 (commercially known as
mixed fluid cascade process); 6,308,531; US application
publications Nos. 2011/0185717 and 2008/0141711;
DE3521060A1; Mark J. Roberts et al "Large capacity single
train AP-X(TM) Hybrid LNG Process", Gastech 2002, Doha,
Qatar (13-16 October 2002). These suggestions are
provided to demonstrate wide applicability of the
invention, and are not intended to be an exclusive and/or
exhaustive list of possibilities. Not all examples
listed above employ (aero derivative) gas turbines as
primary refrigerant compressor drivers. It will be clear
that any drivers other than gas turbines can be replaced
for a gas turbine to enjoy the certain preferred benefits
of the present invention.
An example, wherein in the liquefaction system 100 is
based on, for instance C3MR or Shell DMR, is briefly
illustrated in Figures 2 and 3. In both cases the
cryogenic heat exchanger 180 in the liquefaction system
100 is selected to be a coil wound heat exchanger,
comprising a warm side comprising all the tubes,
including lower and upper hydrocarbon product tube
bundles (181 and 182, respectively), lower and upper LMR
tube bundles (183 and 184, respectively) and an HMR tube
bundle 185. The cold side is formed by the shell side
186 of the cryogenic heat exchanger 180.
The lower and upper hydrocarbon product tube bundles
181 and 182 fluidly connect the hydrocarbon stream line
110 with the rundown line 1. At least one refrigerated
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hydrocarbon pre-cooling heat exchanger 115 may be
provided in the hydrocarbon stream line 110, upstream of
the cryogenic heat exchanger 180.
The refrigerant provided in the refrigerant circuit
101 will be referred to as "main refrigerant" to
distinguish it from other refrigerants that may used in
the liquefaction system 100 such as a pre-cooling
refrigerant 127 which may provide cooling duty to the
refrigerated hydrocarbon pre-cooling heat exchanger 115.
The main refrigerant in the present embodiment is a mixed
refrigerant.
The refrigerant circuit 101 comprises a spent
refrigerant line 150, connecting the cryogenic heat
exchanger 180 (in this case a shell side 186 of the
cryogenic heat exchanger 180) with a main suction end of
the refrigerant compressor 160, and a compressed
refrigerant line 120 connecting the refrigerant
compressor 160 discharge outlet with an MR separator 128.
One or more heat exchangers are provided in the
compressed refrigerant line 120, including in the present
example at least one reject heat exchanger 124. The MR
separator 128 is in fluid connection with the lower LMR
tube bundle 183 via a light refrigerant fraction line
121, and with the HMR tube bundle via a heavy refrigerant
fraction line 122.
The at least one refrigerated hydrocarbon pre-cooling
heat exchanger 115 and the at least one refrigerated main
refrigerant pre-cooling heat exchanger 125 are
refrigerated by the pre-cooling refrigerant (via lines
127 and 126, respectively). The same pre-cooling
refrigerant may be shared from the same pre-cooling
refrigerant cycle. Moreover, the at least one
refrigerated hydrocarbon pre-cooling heat exchanger 115
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and the at least one refrigerated main refrigerant pre-
cooling heat exchanger 125 may be combined into one pre-
cooling heat exchanger unit (not shown). Reference is
made to US Pat. 6,370,910 as a non-limiting example.
The optional external stripping vapour supply line 74
(if provided) may suitably be connected to the
hydrocarbon feed line 110, either at a point upstream of
the at least one refrigerated hydrocarbon pre-cooling
heat exchanger 115, downstream of the at least one
refrigerated hydrocarbon pre-cooling heat exchanger 115,
or (for instance possible if two or more refrigerated
hydrocarbon pre-cooling heat exchangers are provided)
between two consecutive refrigerated hydrocarbon pre-
cooling heat exchangers, to be sourced with a part of the
hydrocarbon feed stream from the hydrocarbon feed line
110.
At a transition point between the upper (182, 184)
and lower (181, 183) tube bundles, the HMR tube bundle
185 is in fluid connection with an HMR line 141. The HMR
line 141 is in fluid communication with the shell side
186 of the cryogenic heat exchanger 180 via a first HMR
return line 143, in which an HMR control valve 144 is
configured. Via the said shell side 186, and in heat
exchanging arrangement with each of one of the lower
hydrocarbon product tube bundle 181 and the lower LMR
tube bundle 183 and the HMR tube bundle 185, first HRM
return line 143 is fluidly connected to the spent
refrigerant line 150.
Above the upper tube bundles 182 and 184, near the
top of the cryogenic heat exchanger 180, the LMR tube
bundle 184 is in fluid connection with the refrigerated
refrigerant line 131. A main refrigerant return line 133
establishes fluid communication between the refrigerated
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refrigerant line 131 and the shell side 186 of the
cryogenic heat exchanger 180. A main refrigerant control
valve 134 is configured in the main refrigerant return
line 133. The main refrigerant return line 133 is in
fluid communication with the spent refrigerant line 150,
via said shell side 186 and in heat exchanging
arrangement with each of one of the upper and lower
hydrocarbon product tube bundles 182 and 181,
respectively, and each one of the LMR tube bundles 183
and 184, and the HMR tube bundle 185.
The line-up around the nitrogen stripper column 20
and the end flash separator 50 as shown in Figures 2 and
3 corresponds to the line-up shown in Figure 1. The
explanations above made with reference to Figure 1 also
apply to Figures 2 and 3. Optional lines including the
optional liquid recycle line 13, the optional external
stripping vapour supply line 74, the optional vapour
bypass line 76 and the optional vapour recycle line 87
may be provided but have not been reproduced in Figures 2
and 3, for purpose of clarity.
One difference to be noted, however, comparing the
embodiments of Figures 2 and 3 with that of Figure 1, is
that the overhead condenser 35, the overhead separator 33
and the reflux system of Figure 1 have in Figures 2 and 3
been embodied in the form of an integrated internal
overhead condenser 235. Such integrated internal
overhead condenser 235 is known in the art. If desired,
the optional liquid recycle line 13 can be provided in
the case of Figures 2 and 3 as well, for instance by
providing the optional condensed fraction splitter 39 in
the form of a partial liquid draw off tray (not shown)
gravitationally between the integrated internal overhead
condenser 235 and the rectifying section 22. Internal or
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external overhead condensers and reflux systems can be
used interchangeably.
Figure 2 illustrates one possible source of the
auxiliary refrigerant which has briefly been mentioned
above, and that is the slip stream of the cycled
refrigerant stream from the liquefier 100. There are
many variations possible to obtain and return such a slip
stream. As example, in Figure 2 the refrigerated
refrigerant line 131 is split into the auxiliary
refrigerant feed line 132 and the main refrigerant return
line 133. The auxiliary refrigerant return line 138, on
an upstream end thereof, fluidly connects with the
auxiliary refrigerant feed line 132 via the condenser
(which in Figure 2 is embodied in the form of the
integrated internal overhead condenser 235 but it could
also be the external overhead condenser 35). In the
embodiment of Figure 2, the auxiliary refrigerant return
line 138, on a downstream end thereof, ultimately
connects with the spent refrigerant line 150 via the
first HMR return line 143.
The refrigerant is cycled in the refrigerant circuit
101, whereby spent refrigerant 150 is compressed in the
refrigerant compressor 160 to form a compressed
refrigerant 120 out of the spent refrigerant 150. Heat
is removed from the compressed refrigerant discharged
from the refrigerant compressor 160, via the one or more
heat exchangers that are provided in the compressed
refrigerant line 120 including the least one reject heat
exchanger 124. This results in a partially condensed
compressed refrigerant, which is phase separated in the
MR separator 128 into a light refrigerant fraction 121
consisting of the vaporous constituents of the partially
condensed compressed refrigerant, and a heavy refrigerant
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fraction 122 consisting of the liquid constituents of the
partially condensed compressed refrigerant.
The light refrigerant fraction 121 is passed via
successively the lower LMR bundle 183 and the upper LMR
bundle 184 through the cryogenic heat exchanger 180,
while the heavy refrigerant fraction 122 is passed via
the HMR bundle 185 through the cryogenic heat exchanger
180 to the transition point. While passing through these
respective tube bundles, the respective light- and heavy
refrigerant fractions are cooled against the light and
heavy refrigerant fractions that are evaporating in the
shell side 186 again producing spent refrigerant 150
which completes the cycle. Simultaneously, the
hydrocarbon stream 110 passes through the cryogenic heat
exchanger 180 via successively the lower hydrocarbon
bundle 181 and the upper hydrocarbon bundle 182 and is
being liquefied evaporating heavy refrigerant fraction
and sub-cooled against the evaporating light refrigerant
fraction.
In a preferred embodiment, the auxiliary refrigerant
stream is formed by a slip stream of the main refrigerant
stream, more specifically by a slip stream of the light
refrigerant fraction. This latter case is illustrated in
Figure 2. Such a slip stream may conveniently be passed
back into the main refrigerant circuit via the shell side
186 of the cryogenic heat exchanger 180, where it may
still assist in withdrawing heat from the stream in the
upper and/or lower tube bundles.
In one example, a contemplated composition of the
auxiliary refrigerant contains between 25 mol% and
mol% of nitrogen; between 30 mol% and 60 mol% of
methane and up to 30 mol% of C2 (ethane and/or ethylene),
whereby the auxiliary refrigerant contains at least 95%
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of these constituents and/or the total of nitrogen and
methane is at least 65 mo196. A composition within these
ranges is may be readily available from the main
refrigerant circuit if a mixed refrigerant is employed
for sub-cooling of the liquefied hydrocarbon stream.
Employing a slip stream from the main refrigerant
stream has as advantage that the amount of additional
equipment to be installed is minimal. For instance, no
additional auxiliary refrigerant compressor and auxiliary
refrigerant condenser would be needed, which would be the
case if a separate independent auxiliary refrigerant
cycle would be proposed.
Figures 3 and 4 illustrate another possible source of
the auxiliary refrigerant, which has briefly been
mentioned above, and that is the slip stream of the
liquefied hydrocarbon product stream 90. There are many
variations possible to obtain and return such a slip
stream. As example, in Figures 3 and 4 the liquefied
hydrocarbon product line 90 is split into the auxiliary
refrigerant feed line 132 and a main product line 91.
The auxiliary refrigerant return line 138, on an upstream
end thereof, fluidly connects with the auxiliary
refrigerant feed line 132 via the condenser (which in
Figure 3 is embodied in the form of the integrated
internal overhead condenser 235 but it could also be the
external overhead condenser 35 such as illustrated in
Figure 4). In the embodiment of Figures 3 and 4, the
auxiliary refrigerant return line 138, on a downstream
end thereof, ultimately connects with the end-flash
separator 50. The end-flash separator 50 is this way
suitably used to handle any components from the auxiliary
refrigerant stream that may have evaporated upon heat
exchanging in the condenser. A separate cryogenic pump
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96 may optionally be provided in the auxiliary
refrigerant feed line 132.
Material and heat balance calculations have been
performed using Pro2 simulation software, to demonstrate
the feasibility of the proposed methods and apparatuses.
Table 1 shows results for an embodiment based on
Figure 4, assuming cold recovery stream 86 consists of a
side stream of natural gas sourced from the hydrocarbon
feed stream in the hydrocarbon feed line 110 of the
liquefier 100. It has the same composition as the raw
liquefied stream 1. The first nitrogen stripper feed
stream in the first feed line 10 consists of the cold
recovery stream 86 and the part from the cryogenic
hydrocarbon composition 8 coming from the initial stream
splitter 9. It is further assumed that vapour bypass
control valve 77, vapour recycle control valve 88,
recycle valve 14, and external stripping vapour flow
control valve 73 are closed and in no-flow condition.
The composition of the liquefied hydrocarbon
inventory as stored in the cryogenic storage tank 210 is
0.80 mol.% nitrogen; 98.78 mol.% methane and 0.43 mol.%
C2+, whereby C2+ indicates all hydrocarbons having a mass
corresponding to that of ethane, and upward. The
liquefied hydrocarbon stream being passed through the
main product line 91 to the cryogenic storage tank 210
has slightly more nitrogen than the liquefied hydrocarbon
inventory as stored in the cryogenic storage tank 210.
As calculated in the present example, a low quality
fuel gas is discharged from the cold recovery heat
exchanger 85 at a pressure of 5.5 bara and a temperature
of 12 C. The fuel gas vapour stream 240, which can
ultimately serve as high quality fuel gas, is drawn from
o
Table 1
Stream Nr. 1 8 10 30 37 64 70 80 86 90 132
138 230 240
Pressure
74.8 7.31 7.31 6.20 6.00 1.05 6.50 6.00 89.0 1.05
2.50 2.00 1.00 6.50
(bara)
Temperature
-158 -159 -159 -145 -153 -163 -65 -154 -140 -164
-164 -153 -159 -65 0
( C)
(r,
Flow rate
199 199 72.1 12.4 3.86 28.2 31.4 8.53 2.57 182 17.6 17.6 3.20 13.9
(kg/s)
0
Nitrogen
I5
3.93 3.93 3.93 48.6 14.3 20.7 20.4 70.0 3.93 0.98
0.98 0.98 17.3 20.4
(mol.%)
Methane
95.7 95.7 95.7 51.4 85.7 79.3 79.6 30.0 95.7 98.6
98.6 98.6 82.7 79.6
(mol.%)
02+
0.39 0.39 0.39 0.00 0.00 0.00 0.00 0.00 0.39 0.42
0.42 0.42 0.00 0.00
(mol.%)
JI
JI
ni
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the compressed stream 70 at a pressure of 6.5 bara and a
temperature of -65 C. Some cold is there to be
recovered, but the amount to be recovered may not be
worth the additional equipment and operational
complexity.
It follows from the calculation above that about 10 %
of the liquefied hydrocarbon product stream 90 would be
needed as the auxiliary refrigerant stream 132 to cool
the condenser with sufficient cooling duty. Generally,
between 3 and 24 % of the liquefied hydrocarbon product
stream 90 may be needed as the auxiliary refrigerant
stream 132.
Regardless of which embodiment is being used, the
heating value of the vapour fraction 80 being discharged
is suitably regulated by adjusting the cooling duty in
the overhead condenser 35 (which is optionally embodied
in the form of the integrated internal overhead condenser
235). This may be done by the cooling duty controller
34. By adjusting the cooling duty at which heat is passed
from the overhead vapour to the auxiliary refrigerant
stream, the relative amount of methane in the off gas can
be regulated. As a result, the heating value of the
discharged vapour fraction can be regulated to match with
a specific demand of heating power. This renders the off
gas suitable for use as fuel gas stream, even in
circumstances where the demand for heating value is
variable.
In the context of the present description, cooling
duty reflects the rate at which heat is exchanged in the
condenser, which can be expressed in units of power (e.g.
Watt or MWatt). The cooling duty is related to the flow
rate of the auxiliary refrigerant being subjected to the
heat exchanging against the overhead vapour.
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When the vapour fraction 80 is passed to and consumed
by the combustion device 220 as fuel, the heating value
may be regulated to match with an actual demand of
heating power by the combustion device 220.
The heating value being regulated may be selected in
accordance with the appropriate circumstances of the
intended use of the off gas as fuel gas. For many
applications, the heating value being regulated may be
proportional to the low heating value (LHV; sometimes
referred to as net calorific value) as defined herein
above. The concept of LHV broadly speaking assumes the
latent heat of vaporization of water in the reaction
products is not recovered.
However, for the purpose of regulating the heating
value in the context of the present disclosure, the
actual heating value of the vapour fraction being
discharged does not need to be determined on an absolute
basis. Generally it is sufficient to regulate the
heating value relative to an actual demand for heating
power, with the aim to minimize any shortage and excess
of heating power being delivered.
Preferably, the cooling duty is automatically
adjusted in response to a signal that is causally related
to the heating value being regulated. In embodiments
wherein the vapour fraction is passed to one or more
selective consumers of methane, such as for instance the
combustion device 220 shown in the figures, the
controlling can be done in response to the demanded
heating power, whereby the partial flow rate of methane
is controlled to achieve a heating value that matches the
demand. Suitably, the auxiliary refrigerant stream flow
control valve 135 may be controlled by the pressure
controller PC to maintain a predetermined target flow
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rate of auxiliary refrigerant stream 132 through the
overhead condenser 35. The actual pressure in the vapour
fraction discharge line 80 is causally related to the
heating value that is being regulated. The pressure
controller PC will be set to decrease the open fraction
of the auxiliary refrigerant stream flow control valve
135 when the pressure drops below a pre-determined target
level, which is indicative of a higher consumption rate
of methane than supply rate in the vapour fraction 80.
Conversely, the pressure controller PC will be set to
increase the open fraction of the auxiliary refrigerant
stream flow control valve 135 when the pressure exceeds
the pre-determined target level.
In some embodiments, the target amount of nitrogen
dissolved in the liquefied hydrocarbon product stream 90
is between 0.5 and 1 mol%, preferably as close to 1.0
mol% as possible yet not exceeding 1.1 mol%. The vapour
recycle flow control valve 88 regulates the amount of the
vapour fraction stream 80 that is fed back into, for
instance, the end flash separator 50 while bypassing the
nitrogen stripper column 20. Herewith the amount of
nitrogen in the liquefied hydrocarbon product stream 90
can be influenced. To further assist in meeting the
target nitrogen content, the vapour recycle flow control
valve 88 may be controlled in response to a signal from a
quality measurement instrument QMI that is optionally
provided in the liquid hydrocarbon product line 90.
In any of the examples and embodiments described
above, the raw liquefied stream and/or the cryogenic
hydrocarbon composition may comprise in the range of from
1 mol% to 7 mol% nitrogen and more than 81 mol% of
methane. Preferably, the raw liquefied stream and/or
the cryogenic hydrocarbon composition may comprise in the
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range of from 3 mol% to 7 mol% nitrogen and more than
85 mol% of methane. The temperature of the raw liquefied
stream in the rundown line 1 may be anywhere
between -165 C and -120 C. Preferably, the initial
pressure of the cryogenic hydrocarbon composition is
between 2 and 15 bar absolute (bara), and preferably the
initial temperature is lower than -130 C.
The hydrocarbon stream 110 and/or the cryogenic
hydrocarbon composition 8 in any of the examples
disclosed herein may be obtained from natural gas or
petroleum reservoirs or coal beds. As an alternative
hydrocarbon stream 110 and/or the cryogenic hydrocarbon
composition 8 may also be obtained from another source,
including as an example a synthetic source such as a
Fischer-Tropsch process. Preferably the hydrocarbon
stream 110 and/or the cryogenic hydrocarbon composition
comprises at least 50 mol% methane, more preferably at
least 80 mol% methane. The resulting liquid hydrocarbon
product conveyed in the liquid hydrocarbon product line
90 and/or stored in the cryogenic storage tank 210 is
preferably liquefied natural gas (LNG).
Compressors forming part of the hydrocarbon
liquefaction process in the liquefier 100, particularly
any refrigerant compressor including refrigerant
compressor 160, may be driven by any type of suitable
compressor driver 190, including any selected from the
group consisting of gas turbine; steam turbine; and
electric motor; and inter combinations thereof. This
generally applies also to refrigerant compressor driver
190.
The gas turbine may be selected from the group of so-
called industrial gas turbines, or the group of so-called
aero derivative gas turbines. The group of aero
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derivative gas turbines includes: Rolls Royce Trent 60,
RB211, or 6761, and General Electric LMS100TM, 1M6000,
1M5000 and LM2500, and variants of any of these (e.g.
LM2500+).
Typically, the second fuel gas pressure is selected
in a range between 15 and 75 bara, more preferably in a
range of between 45 and 75 bara. The usual prescribed
fuel gas pressure for most conventional types of
industrial gas turbines is between around 15 and around
25 bara, on average. However, the latest generation of
industrial gas turbine requires relatively high pressure
fuel gas, such as in the range of from 35 to 45 bara.
The range of between 45 and 75 bara is recommended to
meet fuel gas pressure requirements of typical aero
derivative gas turbines.
In any of the examples above, the vapour fraction 80
is envisaged to contain in the range of from 50 mol% to
95 mol% of nitrogen, preferably in the range of from 60
mol% to 95 mol% of nitrogen or in the range of from 50
mol% to 90 mol% of nitrogen, preferably in the range of
from 60 mol% to 90 mol% of nitrogen, most preferably from
60 mol% to 80 mol% of nitrogen. To achieve a content of
nitrogen of between 60 mol% and 80 mol%, such as about 70
mol%, sufficient methane must be recondensed from the
compressed vapour stream 70. This may for instance be
done using a pressure of the compressed vapour stream 70
of between 4 and 8 bara, and achieving a temperature of
the partially condensed intermediate stream of in the
range of from -150 C to -135 C.
The flash pressure may suitably be in a range of
between 1 and 2 bar absolute. Preferably, the flash
pressure lies in a range of between from 1.0 and 1.4
bara. With a somewhat higher differential between the
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flash pressure and the stripping pressure, the stripping
vapour in stripping vapour line 71 can benefit from some
additional heat of compression that is added to the
process stream 60 in the process compressor 260.
The flash separation pressure suitably also lies in
the range of from 1 to 2 bar absolute, and it is
preferably equal to or lower than the flash pressure.
Preferably, the flash separation pressure is in the range
of between 1 and 1.2 bara. In one embodiment the flash
separation pressure is envisaged to be about 1.05 bara.
The person skilled in the art will understand that
the present invention can be carried out in many various
ways without departing from the scope of the appended
claims.
