Note: Descriptions are shown in the official language in which they were submitted.
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Method and system for liquefying
a natural gas feed stream
The present invention relates to a method and system
for liquefying a natural gas feed stream.
Methods of liquefying hydrocarbon-containing gas
streams are well known in the art. It is desirable to
liquefy a hydrocarbon-containing gas stream such as
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 pressures. Typically, before
being liquefied, the contaminated hydrocarbon-containing
gas stream is treated to remove one or more contaminants
(such as H20, CO2, HS and the like) which may freeze out
during the liquefaction process.
Processes of liquefaction are known from the prior
art in which one or more closed refrigerant cycles are
used to cool and liquefy the hydrocarbon-containing gas
stream. Examples are a C3-MR process or a DMR process. In
a C3-MR process a first cooling stage uses propane as
refrigerant and the second cooling stages uses a mixture
of two or more refrigerants, such as a mixture of
propane, ethane, methane and nitrogen. In a DMR process,
two refrigerant cycles are used, each comprising a mixed
refrigerant.
Alternative methods of liquefaction are known in
which no separate refrigerant cycle is used.
W02014/166925 describes a method of liquefying a
contaminated hydrocarbon-containing gas stream, the
method comprising at least the steps of:
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(1) providing a contaminated hydrocarbon-containing
gas stream;
(2) cooling the contaminated hydrocarbon-containing
gas stream in a first heat exchanger thereby obtaining a
cooled contaminated hydrocarbon-containing stream;
(3) cooling the cooled contaminated hydrocarbon-
containing stream in an expander thereby obtaining a
partially liquefied stream;
(4) separating the partially liquefied stream in a
separator thereby obtaining a gaseous stream and a liquid
stream;
(5) expanding the liquid stream obtained in step (4)
thereby obtaining a multiphase stream, the multiphase
stream containing at least a vapour phase, a liquid phase
and a solid phase;
(6) separating the multiphase stream in a separator
thereby obtaining a gaseous stream and a slurry stream
(comprising solid CO2 and liquid hydrocarbons);
(7) separating the slurry stream in a solid/liquid
separator thereby obtaining a liquid hydrocarbon stream
and a concentrated slurry stream;
(8) passing the gaseous stream obtained in step (4)
through the first heat exchanger thereby obtaining a
heated gaseous stream; and
(9) compressing the heated gaseous stream thereby
obtaining a compressed gas stream; and
(10) combining the compressed gas stream obtained in
step (9) with the contaminated hydrocarbon-containing gas
stream provided in step (1).
The method as described in W02014/166925 allows
liquefying a contaminated hydrocarbon-containing gas
stream with a relatively low equipment count, without the
need of a refrigerant cycle, thereby providing a simple
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and cost-effective method of liquefying a contaminated
hydrocarbon-containing gas stream, in particular a
methane-containing contaminated gas stream such as
natural gas. The contaminant may be CO2.
The method according to W02014/166925 uses a freeze
out process scheme to remove CO2. In step (5) as
described above, the process conditions in the liquid
stream obtained in step (4) are just outside the CO2
freeze out envelope (the process conditions are for
example 20 bar, -120 C, 1 mol% CO2) such that any further
temperature reduction will provoke freeze out of CO2. The
temperature reduction is achieved in step (5) by pressure
reduction over a Joule Thomson valve. The pressure
reduction evaporates part of the liquid methane, thus
cooling the remaining liquid.
Further methods of liquefaction are for instance
described in W015110779 and W012172281.
Other methods to remove CO2 are know from the prior
art, such as W015017357, W012068588 and W012162690 which
use different ways to remove CO2.
US3616652 describes a process for liquefying natural
gas comprising flashing the stream to a low pressure
level to form a low pressure liquid and a flash gas and
recirculating the flash gas in a circuit arranged to
assist in the cooling of the natural gas at the upper
pressure level by indirect heat exchange therewith.
It is an object to provide an alternative, more
efficient method and system to cool and liquefy a
hydrocarbon containing gas stream.
One or more of the above or other objects are
achieved by a method of liquefying a natural gas feed
stream, the method comprising at least the steps of:
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(a) providing a process feed stream (11) by mixing
the natural gas feed stream (1) with a recycle stream
(105),
(b) compressing the process feed stream (11) and
cooling the process feed stream (11) against ambient in a
compressor stage (20), thereby obtaining a compressed
process stream (25) having a pressure (P25) of at least
120 bar and a first temperature (125) below 40 C,
(cl) obtaining a first split-off stream (32) from
the compressed process stream (25) and expanding the
first split-off stream (32) in a precool expander (33),
thereby obtaining an expanded first split-off stream
(34), having a second temperature below the first
temperature,
(c2) cooling a remainder of the compressed process
stream (31) in a first heat exchanger (40) against the
expanded first split-off stream (34), thereby obtaining a
precooled process stream (41) and a warmed first split-
off stream (42),
(dl) obtaining a second split-off stream (52) from
the precooled process stream (41) and expanding the
second split-off stream (52) in an expander (53), thereby
obtaining an expanded and cooled multiphase second split-
off stream (54), having a third temperature below the
second temperature,
(d2) splitting the expanded and cooled multiphase
second split-off stream (54) in a phase separator (55) to
obtain a vapour stream (56) and a liquid stream (57),
(d3) cooling a remainder of the precooled compressed
process stream (51) in a second heat exchanger (60)
against the vapour stream (56), thereby obtaining a
further cooled process stream (61) and a warmed vapour
stream (62),
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(e) expanding the further cooled process stream (61)
thereby obtaining a liquid natural gas stream (71),
(f) passing the warmed first split-off stream (42)
and the warmed vapour stream (62) to a recompression
stage (200), the recompression stage (200) generating the
recycle stream (105).
By compressing the process feed stream to a
relatively high pressure in (b), i.e. to a pressure of at
least 120 bar, the liquefaction efficiency is improved,
as the relatively high pressure translates into a
significant cooling (liquefaction) effect. The pressure
of the compressed process stream may be in the range of
120 - 200 bar or in the range of 130 - 190 bar,
preferably 145 - 175 bar, more preferably in the range of
155 - 165 bar.
Although the power consumed by the compressor stage
will be relatively high, this is compensated by a reduced
recycle stream and thus reduced recompression duties
needed for getting the pressure of the recycle stream to
match the pressure of the natural gas feed stream.
The first split-off stream (32), which functions as
a pre-cooling stream, also has a relatively high pressure
as a consequence of the relatively high compression in
step (b). Consequently, the first split-off stream 32 has
a relatively high specific heat capacity and therefore
provides efficient (pre-)cooling in the first heat
exchanger (40) and as a result the first split-off stream
(32) may have a relatively low mass flow.
Consequently, the hardware costs associated to the
recycle stream (compressors, pipes) will be relatively
low.
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Also, as no separate refrigerants and refrigerant
cycles are required, the amount of liquid handling is
significantly reduced, further reducing costs.
The absence of refrigerants, in particular the
absence of propane as refrigerant (component), further
contributes to the safety of the plant.
The pressure in step (b) is well above the critical
pressure (supercritical pressure), preferably at least 50
bars above the critical pressure, which results in a
relatively constant temperature profile in the first heat
exchanger (40, step c2) for the compressed process stream
(31), because of a relatively constant heat capacity at
supercritical conditions, as opposed to a pressure that
would be in the proximity of the critical point, where
heat capacity variations with temperature are large.
This enables a very small LMTD (logarithmic mean
temperature differences) reducing the local temperature
approaches and reducing external entropic generation
(thermodynamic inefficiency). Since the specific heat
capacity is relatively constant at supercritical
conditions, in particular at least 30 bars or at least 50
bars above the critical point, the temperature profiles
are substantially straight lines (in a temperature vs
heat (Q) diagram), reducing the temperature difference
between hot and cold streams and thus reducing
thermodynamic inefficiency.
A pressure close to the critical point would result
in a divergence between the two heat exchanging streams
at the cold of the heat exchanger, thereby resulting in
inefficiencies, meaning that the compressed process
stream (31) is less precooled (i.e. leaves the first
heat exchanger (40) at a higher temperature).
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The precooling pressure, i.e. the pressure of the
expanded first split-off stream (34) is an optimized
parameter. A lower pressure results in a colder expanded
first split-off stream (34) but requires more
recompression duty. The optimum precooling pressure may
therefore be determined by an iterative process. The
precooling pressure may further be adjusted during
operation to take into account changes in operation
conditions, such as a changing ambient temperature.
Hereinafter embodiments will be described with
reference to the following non-limiting drawings:
Fig. 1 schematically shows a process scheme according
to an embodiment,
Fig. 2 schematically shows a process scheme according
to an alternative embodiment.
Below, two embodiments will be described with
reference to Fig. 1 and Fig. 2 each showing a different
embodiment. Same reference numbers are used to refer to
similar items in the different figures.
First, a natural gas feed stream 1 is provided. The
natural gas feed stream 1 may also be referred to as a
hydrocarbon feed stream 1. The natural gas feed stream 1
mainly comprises methane. Although the natural gas feed
stream 1 is not particularly limited, it preferably is a
methane-rich gas stream, preferably comprising at least
50 mol% methane, more preferably at least 80 mol% and
more preferably at least 95 mol% methane.
The remainder of the natural gas feed stream 1 is
primarily formed of hydrocarbon molecules comprising two,
three or four carbon atoms (ethane, propane, butane).
The natural gas feed stream 1 may originate from a
gas treatment stage in which the contaminants and C5+
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mo 1 e cul e s are removed. As will be understood by the
skilled person, the exact line-up of the gas treatment
stage may depend on the gas composition upstream of the
gas treatment stage and the liquid natural gas
specifications.
Contaminants and hydrocarbon molecules comprising
five or more carbon atoms are preferably removed
upstream.
Preferably less than 1 mol% of the natural gas feed
stream 1 is formed by contaminants and hydrocarbon
molecules comprising five or more carbon atoms after
removal. Preferably, the natural gas feed stream 1
comprises less than 0.15 mol% hydrocarbon molecules
comprising five or more carbon atoms. The amount of
hydrocarbon molecules comprising five or more carbon
atoms may be in the range of 0.10 - 0.15 mol%.
Alternatively, the contaminants and hydrocarbon
molecules comprising five or more carbon atoms may be
removed in between the first and second heat exchangers
40, 60, instead of upstream removal.
The natural gas feed stream 1 preferably has a
pressure in the range of 50 - 80 bar, more preferably in
the range of 55 - 75 bar, e.g. 65 bar. The natural gas
feed stream 1 preferably has a temperature in the range
of 0 - 40 C, e.g. 17 C.
In a first step (a), a process feed stream 11 is
formed by mixing/combining the natural gas feed stream 1
with a recycle stream 105 by means of a combiner 2. The
recycle stream 105 will be described in more detail
below.
According to an embodiment, the mass flow rate of
the natural gas feed stream 1 (MF1) and the mass flow
rate of the recycle stream 105 (MF105) is in the range MF1
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: MFlos = [1:2 - 1:41, preferably substantially equal to
1:3.
In step (b), the process stream 11 is passed to a
compressor stage 20 to obtain a compressed process stream
25, having a pressure of at least 120 bars and a first
temperature below 40 C. As indicated above, the pressure
of the compressed process stream may be in the range of
120 - 200 bar or in the range of 130 - 190 bar,
preferably 145 - 175 bar, more preferably in the range of
155 - 165 bar.
According to an embodiment, shown in Fig. 2, the
compressor stage 20 comprises a single compressor 21 with
an associated intercooler 22 positioned downstream of the
compressor 21.
According to an embodiment, the compressor stage 20
comprises a multi-stage compressor with intercoolers. The
compressor stage 20 may comprise a multi-stage compressor
having any suitable number of compressors and
intercoolers to obtain the intended pressure and
20 temperature.
As shown in Fig. 1, the compressor stage 20 may
comprise a first compressor 21 to receive the process
stream 11, subsequently followed by a first intercooler
22, a second compressor 23 and a second intercooler 24.
The intercooler(s) preferably cool(s) the process
stream against ambient, such as against ambient air or
ambient water.
In step (c1), the compressed process stream 25 is
fed to a first splitter 30 to obtain a first split-off
stream 32. The first splitter 30 may be any suitable type
of splitter, including a simple T- or Y-junction.
The first splitter 30 may also be a controllable
splitter to actively control and adjust the split-off
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port ion during operation. The controllable splitter may
comprise one or two controllable valves positioned
downstream of the junction to control the split ratio.
The split ratio is defined as the mass flow of the
split-off stream 32 (MF32) divided by the mass flow of
the compressed process stream 25 (MP25), MP32 : MF25.
Typically, the split ratio is in the range of 0.5 - 0.65.
The first split-off stream 32 is expanded and
thereby cooled in a precool expander 33. The expansion
typically has a pressure ratio in the range of 4 - 6,
e.g. 5, to provide sufficient cold to precool the
remainder of the compressed process stream 31. The
pressure ratio is defined as the pressure (P32) upstream
of the precool expander 33 divided by the pressure (P34)
downstream of the precool expander 33.
The expanded first split-off stream 34 may have a
pressure P34 in the range of 26 - 38 bar, preferably 29 -
35 bar, more preferably in the range of 31 - 33 bar. The
expanded first split-off stream 34 typically has a
temperature in the range of minus 60 - minus 80 C,
typically minus 70 C.
In step (c2), the remainder of the compressed
process stream 31 is fed to a warm-side of a first heat
exchanger 40 and the expanded first split-off stream 34
is fed to a cold-side of the first heat exchanger 40 to
allow the two streams to exchange heat, in particular to
allow the expanded first split-off stream 34 to precool
the remainder of the compressed process stream 31.
The first heat exchanger 40 may be any type of
suitable heat exchanger including a coil wound heat
exchanger or a plate (fin) heat exchanger. The first heat
exchanger 40 may comprise a plurality of serial and/or
parallel sub-heat exchangers (not shown).
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From the first heat exchanger 34 a precooled process
stream 41 is obtained on the cold-side and a warmed first
split-off stream 42 is obtained on the warm-side. The
warmed first split-off stream 42 is forwarded to the
recompression stage 200 to be comprised in the recycle
stream 105 as will be described in more detail below.
The warmed first split-off stream 42 may have a
temperature in the range of 0 C - 40 C, e.g. 15 C. The
precooled process stream 41 may have a temperature in the
range of minus 50 C - minus 70 C, e.g. minus 60 C.
The precooled process stream 41 is passed to a
second splitter 50 to obtain a second split-off stream
52.
The second splitter 50 may be any suitable type of
splitter, including a simple T- or Y-junction. The second
splitter 50 may also be a controllable splitter to
actively control and adjust a second split-off portion
during operation. The second controllable splitter 50 may
comprise one or two controllable valves positioned
downstream of the junction to control the second split
ratio.
The second split ratio is defined as the mass flow
of the second split-off stream 52 (MF52) divided by the
mass flow of the precooled process stream 41 (mF41), MF52
: MF41.
Typically, the second split ratio is in the range of
0.75 - 0.85.
In step (d1) the second split-off stream 52 is
passed to an expander 53, e.g. a dense phase expander, to
expand and thereby cool the second split-off stream 52 to
enter the two phase region thereby obtaining an expanded
and cooled multiphase second split-off stream 54. The
cooled multiphase second split-off stream 54 is typically
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expanded to a pressure in the range of 5 - 20 bar, e.g.
in the range 8 - 12 bar and to a third temperature in the
range of minus 110 C - minus 130 C.
The expander 53 may function as a dense phase
expander, i.e. an expander 53 which is suitable to
receive a pressurized supercritical flow at an inlet of
the expander 53 and arranged to discharge a multiphase
stream 54 via an outlet of the expander 53. The
multiphase stream 54 may be a two phase stream comprising
a vapour/gas phase and a liquid phase.
In step (d2), the expanded and cooled multiphase
second split-off stream 54 is flashed in a phase
separator 55 thereby obtaining a separate vapour stream
56 and a liquid stream 57. The mass ratio of the vapour
stream MF56 to the mass ratio of the expanded and cooled
multiphase second split-off stream 54 (MF54) is typically
in the range MF5.4: MF56 = 0.3 - 0.4.
The phase separator 55 may be any suitable vapour-
liquid separator, such as a flash drum or knock-out
vessel.
In step (d3) the remainder of the precooled
compressed process stream 51 is fed to a warm-side of a
second heat exchanger 60 and the vapour stream 56 is fed
to a cold-side of the second heat exchanger 60 to allow
the two streams to exchange heat, in particular to allow
the vapour stream 56 to further cool the remainder of the
precooled compressed process stream 51. Thereby, a
further cooled process stream 61 and a warmed vapour
stream 62 are obtained.
The warmed vapour stream 62 may be forwarded to the
recompression stage 200 to be comprised in the recycle
stream 105 as will be described in more detail below.
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According to an embodiment, the warmed vapour stream
62 is first forwarded to the first heat exchanger 40 and
then forwarded to the recompression stage 200, as will be
described in more detail below.
The second heat exchanger 60 may be any type of
suitable heat exchanger including a coil wound heat
exchanger or a plate (fin) heat exchanger. The second
heat exchanger 60 may comprise a plurality of serial
and/or parallel sub-heat exchangers (not shown).
The warmed vapour stream 62 may have a temperature
T62 in the range of minus 65 C - minus 85 C and a
pressure P62 in the range of 5 - 20 bar.
The precooled process stream 51 may enter the second
heat exchanger 60 having a temperature T51 in the range
of minus 60 C - minus 80 C and the further cooled process
stream 61 may leave the second heat exchanger 60 having a
temperature T61 in the range of minus 110 C - minus 130 C
and a pressure which is still substantially equal to the
pressure of the compressed process stream 25, except for
a (undeliberate) pressure drop resulting from flowing
through the piping and first and second heat exchangers.
The further cooled process stream 61 may be in a
supercritical dense phase in which there is no
distinction between gas and liquid.
In step (e), the further cooled process stream 61 is
expanded in a liquid expander 70 thereby obtaining a
liquid natural gas stream 71 having a pressure in the
range of 8 - 15 bar, e.g. 10 bar, and a temperature equal
to the boiling temperature of the composition at that
pressure (e.g. approximately minus 125 C at 10 bar). The
liquid natural gas stream 71 may be passed to a flash
vessel 80 thereby obtaining liquid natural gas at a
pressure in the range of 1 - 3 bar, e.g. atmospheric
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pressure. Flash vessel 80 may be a storage vessel.
Alternatively, the liquid natural gas is passed from
flash vessel 80 to a subsequent storage vessel.
According to an embodiment the method further
comprises passing the liquid natural gas stream 71 to a
flash vessel 80 and obtaining a liquid natural gas
product stream 81 as bottom stream from the flash vessel
80. The liquid natural gas product stream 81 may be
passed to a LNG storage tank such as a LNG storage tank
on a LNG carrier vessel/ship or floating LNG facility.
According to an embodiment the method comprises
obtaining a flash gas stream 82 as top stream from the
flash vessel 80, passing the flash gas stream 82 to the
recompression stage 200, wherein the flash gas stream 82
is optionally at least partially passed through a third
heat exchanger 75, 75' to provide cooling to at least
part of the liquid stream 57 obtained in (d2).
By passing the flash gas stream through a third heat
exchanger 75, high quality cold is recovered while cold
compression of the flash gas stream in the recompression
stage, i.e. compression without the need of an
intercooler, is still possible.
According to an embodiment, as depicted in Fig. 1,
the method comprises
(el) splitting the liquid stream 57 obtained in (d2)
into a first liquid portion 71 and a second liquid
portion 74,
(e2) expanding the first liquid portion 71 in a
first pressure reduction device 72 to obtain a second
liquid natural gas stream 73, and
(e3) cooling the second liquid portion 74 by passing
the second liquid portion through the third heat
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exchanger 75 and a second pressure reduction device 78
to obtain a third liquid natural gas stream 76,
(e4) collecting the liquid natural gas stream
obtained in (e), the second liquid natural gas stream 73
obtained in (e2) and the third liquid natural gas stream
76 obtained in (e3) in the flash vessel 80.
The first pressure reduction device may be a (Joule-
Thomson) valve or an expander. The second pressure
reduction device may be a (Joule-Thomson) valve or an
expander. According to an embodiment, the first pressure
reduction device is an expander and the second pressure
reduction device is a Joule-Thomson valve.
This embodiment provides the advantage that the
splitting in (el) makes it possible to control the flow
rate of the second liquid portion through the third heat
exchanger and thereby allows for a better matching of the
heating curves in the third heat exchanger 75, yielding a
lower logarithmic mean temperature difference (LMTD) and
hence lower exergy losses in the third heat exchanger 75.
This provides a more energy efficient method.
The splitting in (el) may be a predetermined split,
e.g. may provide for a predetermined flow rate of the
second liquid portion through the third heat exchanger.
Alternatively, the splitting may be a controllable split
provided by a controllable splitter, which provides for
an adjustable split, which can be controlled actively
during operation.
The second liquid natural gas stream 73 and the
third liquid natural gas stream 76 are typically at the
same pressure, being close to atmospheric (in the range 1
- 1.25 bar) and at a temperature close to or at -161.5 C
(in the range minus 160 - minus 162 C), although small
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difference in pressure/temperature may exist due to
differences in composition.
In step (e3) the second liquid portion 74 is cooled
in the third heat exchanger 75 against at least part of
the flash gas stream 82, thereby obtaining a warmed flash
gas stream 77, which is passed to the recompression stage
200.
The third liquid natural gas stream 76, which is a
sub-cooled liquid, can effectively be reduced in
pressure, preferably (close) to storage conditions with
the second pressure reduction device, e.g. Joule-Thomson
valve 78, minimizing the flashing of vapour.
According to an embodiment, as depicted in Fig. 2,
the method comprises
(el') passing the liquid stream 57 obtained in (d2)
through the third heat exchanger 75' and an expander 78'
to obtain a further liquid natural gas stream 76',
(e2') collecting the liquid natural gas stream
obtained in (e) and the further liquid natural gas stream
76' obtained in (el') in the flash vessel 80.
Expander 78' may more generally be a pressure
reduction device, such as a (Joule-Thomson) valve.
Further liquid natural gas stream 76' may have a
pressure in the range of 1 - 1.25 bar, e.g. 1.05 bar, and
a temperature in the range minus 160 - minus 162 C, e.g.
minus 160.6 C.
The warmed flash gas stream 77 may be at atmospheric
pressure, e.g. 1 bar, and at a temperature in the range
of minus 120 - minus 130 C, e.g. minus 125 C.
The pressure in the flash vessel 80 is substantially
equal to atmospheric pressure and the collected liquid
natural gas is at its boiling point.
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According to an embodiment, the warmed vapour stream
62 obtained from the second heat exchanger 60 in (d3) is
passed through the first heat exchanger 40 to provide
cooling to the remainder of the compressed process stream
31 thereby obtaining a further warmed vapour stream 43
before being passed to the recompression stage 200.
In step (f) the warmed first split-off stream 43 and
the warmed vapour stream 62 originating from the expanded
and cooled multiphase second split-off stream 54 are
combined to be comprised in the recycle stream 105 in the
recompression stage 200.
According to an embodiment, (f) comprises separately
passing the warmed first split-off stream 42 and one of
the warmed vapour stream 62 and the further warmed vapour
stream 43 to the recompression stage 200 to obtain the
recycle stream 105.
The recompression stage 200 may be a multi-stage re-
compressor stage. The first split-off stream 42 and one
of the warmed vapour stream 62 and the further warmed
vapour stream 43 are preferably fed to different
(pressure) stages of the recompression stage 200.
In case the warmed vapour stream 43 is passed
through the first heat exchanger 40, it is the further
warmed vapour stream 43 that is passed to the
recompression stage 200 to be comprised in the recycle
stream 105. In the description below reference will be
made to the further warmed vapour stream 43, but it will
be understood that this may be the warmed vapour stream
62 in case the warmed vapour stream 62 is not passed
through the first heat exchanger 40.
According to an embodiment, (f) further comprises
passing the flash gas stream (82) or the warmed flash gas
stream 77 to the recompression stage 200.
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The flash gas stream 82 or warmed flash gas stream
77 is passed to the recompression stage separately from
the warmed first split-off stream 42, the warmed vapour
stream 62 and the further warmed vapour stream 43. The
flash gas stream 82 or warmed flash gas stream 77, the
warmed first split-off stream 42, the warmed vapour
stream 62 or the further warmed vapour stream 43 are
preferably fed to different (pressure) stages of the
recompression stage 200.
Consequently, the pressure levels of the different
streams passed to the recompression stage 200) are
decoupled.
By passing the warmed first split-off stream 42
separately from the warmed vapour stream 62 and the
further warmed vapour stream 43, pollution of the warmed
first split-off stream 42 with nitrogen is prevented,
allowing a more efficient fuel bleed.
The recompression stage 200 may comprise a number of
recompression stages positioned in series, each
recompression stage comprising one or more compressors
90, 93, 102.
The number of recompression stages may be equal to
the number of streams being passed to the recompression
stage 200, e.g. three according to the embodiment
depicted in Fig. 1.
One or more recompression stages may comprise one or
more associated intercoolers. The recompression stage 200
may then be referred to as an intercooled multi-stage re-
compressor stage.
According to the embodiment depicted in Fig. 1, the
recompression stage 200 is a three-stage recompressor
stage 200 comprising three recompression stages
positioned in series, i.e. a pre-recompression stage, an
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intermediate recompression stage and a final
recompression stage.
As depicted in Fig. 1, the pre-recompression stage
may comprise a first compressor 90 comprising two serial
sub-compressors, arranged to receive the warmed flash gas
stream 77 and compress the warmed flash gas stream 77
thereby obtaining a first recompressed stream 91 having a
temperature 191 in the range of 15 C - 20 C. The pressure
P91 of the first recompressed stream is substantially
equal to the pressure P43 of the warmed vapour stream 43,
e.g. in the range of 8 - 12 bar, e.g. 10 bar.
As the inlet stream of the first compressor 90 is
relatively cold (flash gas stream 82 typically having a
temperature of -162 C and warmed flash gas stream 77
typically having a temperature of approximately minus
120 C - minus 130 C) compression power requirements are
relatively low and no intercooler may be needed.
The pre-compressed stream 91 and the further warmed
vapour stream 43 (or warmed vapour stream 62) are
combined and are fed to the intermediate recompression
stage as combined stream 92.
The intermediate recompression stage comprises an
intermediate compressor 93 and associated intermediate
intercooler 97 positioned downstream of the intermediate
compressor 93. The intermediate recompression stage is
arranged to receive the combined stream 92 and further
recompress and cool the combined stream 92 to obtain
intermediate compressed stream 98 typically having an
intermediate pressure P98 in the range of 25 - 35 bar,
e.g. 32 bar. The stream 96 leaving intermediate
compressor 93 typically has a temperature of above 100 C
and is cooled by intercooler 97 typically to a
temperature 198 in the range of 15 C - 25 C.
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Intermediate compressed stream 98 and warmed first
split-off stream 42 are combined and are fed to the final
recompression stage as further combined stream 101.
The final recompression stage comprises a final
compressor 102 and associated intercooler 104 positioned
downstream of the final compressor 102. The final
recompression stage is arranged to receive the further
combined stream 101 and further recompress and cool the
further combined stream 101 to obtain recycle stream 105.
The recycle stream 105 typically has a pressure Plos
substantially equal to the pressure of the natural gas
feed stream 1, typically in the range of 50 - 80 bar,
more preferably in the range of 55 - 75 bar, e.g. 65 bar.
According to an embodiment, the method further
comprises
(g) obtaining a fuel stream 95 from an intermediate
position of the recompression stage 200, preferably
upstream of the position at which the warmed first split-
off stream 42 is fed to the recompression stage 200.
Preferably, the fuel stream 95 is obtained at an
intermediate position at which the nitrogen concentration
is relatively high. As the flash gas stream 77, 82 and
the vapour stream 56 contain a relatively high amount of
nitrogen compared to the first split-off stream 32, 42,
the fuel stream 95 is preferably obtained upstream from
the position at which the warmed first split-off stream
42 enters the multi-stage re-compressor unit 200.
The fuel stream 95 is preferably obtained as a side
stream of stream 96 leaving intermediate compressor 93.
The fuel stream 95 is obtained at an intermediate
position in between the intermediate compressor 93 and
associated intermediate intercooler 97.
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This results in an effective fuel stream having a
relatively high amount of nitrogen and reduces the amount
of nitrogen being recycled.
According to an example, the method in use with
function as follows. The process feed stream 11 is
obtained by mixing the natural gas feed stream 1, taken
after dew pointing to meet the C5+ specification
(<0.1%mol) with recycle stream 105 in a ratio of
approximately 1:3. A (booster) compressor stage 20,
comprising two stages with intercooling rises the
pressure from 65 bar to 160 bar. The process feed stream
11 is cooled down by the intercooler(s) to approximately
17 C using water as a cooling media. The thereby obtained
compressed process stream 25 is split in two fractions,
the first split-off stream 32 (0.57 mass fraction) and a
remainder of the compressed process stream (0.43 mass
fraction).
The first split-off stream is expanded in the precool
expander 33, being a 30 MW expander, with a pressure
ration of approximately 5. Thereby the expanded first
split-off stream 34 is obtained to provide cold for the
remainder of the compressed process stream. These streams
exchange heat in the first heat exchanger 40. The hot
outlet reaches -75 C and the cold outlet is directed to
the recompression stage 200.
The precooled process stream 41 is subsequently split
into a second split-off stream 52 (0.8 mass fraction),
which is expanded to 10 bar in expander 53, thereby
cooling itself to approximately minus 123 C, entering the
two phase region thereby obtaining the expanded and
cooled multiphase second split-off stream 54.
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The expanded and cooled multiphase second split-off
stream 54 is flashed in a high pressure separator 55 to
obtain the vapour stream 56 (0.34 mole fraction).
After the high pressure separator 55, the vapor
stream 56 is employed to further cool the remainder of
the precooled compressed process stream 51 in the second
heat exchanger 60 to approximately -123 C. Subsequently,
the vapor stream 56 (now being warmed vapour stream 62)
provides cold in the first heat exchanger 40.
The thereby obtained further cooled process stream
61, being a high pressure low temperature stream, is
expanded in a liquid expander 70 to storage conditions.
The liquid stream 57 obtained from the separator 55
is split into two. The first liquid portion or main
stream 71 (0.89 mass fraction) is expanded through a
first pressure reduction device, for instance liquid
expander 72, whereas the second liquid portion 74 or
minor fraction (0.19 mass fraction) is subcooled against
the flash gas stream 82 in third heat exchanger 75 and
subsequently let down in pressure with a second pressure
reduction device, such as a J-T valve 78 before being
passed to the flash vessel 80.
The flash gas stream 82, after having cooled at least
part of the liquid stream 57 in the third heat exchanger
75, is forwarded to the recompression stage 200. The
warmed flash gas stream 77 is directed to cold
recompression. By use of cold compression (2 stages), low
duty requirements are achieved and there is no need for
intercoolers. The outlet temperature of the first
compressor 90 has risen to 17 C. The outlet stream of
the first compressor 90 is mixed with the 10 bar
further warmed vapour stream 43 coming out of the first
heat exchanger 40 which combined stream 92 is compressed
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by intermediate compressor 93 to an intermediate pressure
of 32 bar. Next, the stream 96 leaving intermediate
compressor 93 is mixed with the warmed first split-off
stream 42 and successively compressed to feed pressure
level of 65 bar to form the recycle stream 105.
Simulations have shown that process schemes as
described with reference to Fig.'s 1 and 2 need a
relatively small recycle stream 105 which greatly
improves efficiency, which more than balances the cost of
higher boosting pressures needed by the compressor stage
200.
The simulations have shown that the embodiment
described with reference to Fig. 1 allows for a specific
power consumption of 9.816 kW/tpd (235.6 kWh/ton). This
corresponds to a LNG production of 3.4 mpta using a 100MW
gas turbine as mechanical drive, assuming 95%
availability.
The person skilled in the art will readily understand
that many modifications may be made without departing
from the scope of the invention. For instance, it will be
understood that the compressor stage 20 as shown in Fig.
1 may be used in the embodiment of Fig. 2 and vice versa.
Where the word step or steps is used in this text, it
will be understood that this is not done to imply a
specific order (in time). The steps may be applied in any
suitable order, including simultaneously.
