U.S. patent application number 10/582903 was filed with the patent office on 2008-01-10 for compressor.
This patent application is currently assigned to THE BOC GROUP PLC. Invention is credited to Helmut Gerstendoerfer, Josef Pozivil.
Application Number | 20080008602 10/582903 |
Document ID | / |
Family ID | 31726310 |
Filed Date | 2008-01-10 |
United States Patent
Application |
20080008602 |
Kind Code |
A1 |
Pozivil; Josef ; et
al. |
January 10, 2008 |
Compressor
Abstract
A rotary liquefied natural gas boil-off compressor has a series
of compression stages. A gas passage passes through the series of
compression stages. The gas passage extends through and is in heat
exchange relationship with cooling means in the form of indirect
heat exchangers. Each of the heat exchangers is cooled by LNG
supplied from a pipeline. Flow control valves are provided for
controlling the flow of LNG to the heat exchangers respectively.
The valves are controlled in response to temperature sensors
respectively, so as to maintain the inlet temperature of each of
the compression stages at a chosen sub-ambient temperature or
between chosen sub-ambient temperature limits.
Inventors: |
Pozivil; Josef; (Allschwil,
CH) ; Gerstendoerfer; Helmut; (Ober-Erlinsbach,
CH) |
Correspondence
Address: |
THE BOC GROUP, INC.
575 MOUNTAIN AVENUE
MURRAY HILL
NJ
07974-2064
US
|
Assignee: |
THE BOC GROUP PLC
Windlesham, Surrey
GB
|
Family ID: |
31726310 |
Appl. No.: |
10/582903 |
Filed: |
January 13, 2005 |
PCT Filed: |
January 13, 2005 |
PCT NO: |
PCT/EP05/00279 |
371 Date: |
November 17, 2006 |
Current U.S.
Class: |
417/243 ;
417/244; 417/247; 417/250 |
Current CPC
Class: |
F17C 2223/047 20130101;
F17C 2227/0339 20130101; F17C 2250/0439 20130101; F17C 2250/0631
20130101; F17C 2265/015 20130101; Y02T 70/50 20130101; F17C
2265/033 20130101; F17C 9/00 20130101; F17C 2227/0185 20130101;
F17C 2227/0388 20130101; F17C 2203/0391 20130101; F17C 2223/0161
20130101; F17C 2265/022 20130101; F04D 29/5846 20130101; F17C
13/026 20130101; F17C 2227/0164 20130101; F17C 2270/0105 20130101;
F17C 2265/037 20130101; F17C 2223/043 20130101; F17C 2225/0123
20130101; F17C 2227/0316 20130101; F17C 2225/036 20130101; F17C
2260/035 20130101; F17C 2203/0617 20130101; F17C 2250/032 20130101;
F17C 2250/0408 20130101; B63J 2099/003 20130101; F17C 2227/0306
20130101; F04D 29/5833 20130101; F17C 2250/043 20130101; F17C
2265/066 20130101; F17C 2223/033 20130101; F17C 2227/0393 20130101;
Y02T 70/5263 20130101; F17C 2221/033 20130101; F28F 27/02 20130101;
F17C 2225/035 20130101; F17C 13/025 20130101 |
Class at
Publication: |
417/243 ;
417/244; 417/247; 417/250 |
International
Class: |
F04B 39/06 20060101
F04B039/06 |
Foreign Application Data
Date |
Code |
Application Number |
Jan 16, 2004 |
GB |
0400986.6 |
Claims
1. A rotary liquefied natural gas boil-off compressor having at
least two compression stages in series, a gas passage passing
through the series of compression stages, the gas passage extending
through and being in heat exchange relationship with at least one
cooling means between the or each pair of compression stages,
characterised in that the cooling means or at least one of the
cooling means is a cryogenic cooling means and in that there is
valve means for controlling flow of cryogenic coolant into the
cryogenic cooling means in response to the inlet temperature, or a
related parameter, of the next compression stage downstream of the
cryogenic cooling means so as, in use, to maintain said inlet
temperature at a chosen sub-ambient temperature or between chosen
sub-ambient temperature limits.
2. The compressor according to claim 1, characterised in that the
cryogenic cooling means comprises an indirect cooling means.
3. The compressor according to claim 1, characterised in that the
cryogenic cooling means comprises a direct cooling means.
4. The compressor according to claim 3, characterised in that the
direct cooling means comprises a chamber having an inlet for the
introduction of a cryogenic liquid.
5. The compressor according to claim 4, characterised in that the
outlet of the direct cooling communicates with a vessel adapted to
disengage particles of liquid from the natural gas, the vessel
having an outlet for natural gas communicating with said next
compression stage.
6. The compressor according to claim 1, characterised in that there
is a cryogenic cooling means intermediate each pair of successive
compression stages.
7. The compressor according to claim 1, characterised in that there
are at least three compression stages in sequence and in that there
is at least one direct cryogenic cooling means and at least one
indirect cryogenic cooling means.
8. The compressor according to claim 7, characterised in that an
inlet of a direct cooling means communicates with an outlet of an
indirect cooling means.
9. The compressor according to claim 1, characterised in that there
is a cryogenic cooling means downstream of the final compression
stage.
10. The compressor according to claim 1, characterised in that
there is a cryogenic cooling means upstream of the first
compression stage.
11. The compressor according to claim 1, characterised in that the
compressor has an intermediate inlet communicating with a forced
liquefied natural gas vaporiser.
12. A liquefied natural gas storage tank having an outlet for
boiled-off natural gas communicating with a compressor as claimed
in claim 1, the said cryogenic cooling means communicating with the
liquefied natural gas in the storage tank.
13. A method of operating a rotary liquefied natural gas boil-off
compressor having at least two compression stages in series and a
gas passage passing through the series of compression stages, the
method comprising cooling the compressed boiled-off natural gas by
means of a cryogenic coolant downstream of one of the compression
stages and upstream of another, monitoring the inlet temperature,
or a related parameter, of the compressed natural gas at the inlet
to the other compression stage, and adjusting the flow rate of
cryogenic coolant so as to maintain said inlet temperature at a
chosen sub-ambient temperature or between chosen sub-ambient
temperature limits.
14. The method according to claim 13, characterised in that the
inlet temperature of each compression stage is maintained at a
temperature in the range of minus 50 to minus 140.degree. C.
15. The method according to claim 14, characterised in that the
pressure ratio across each compression stage is in the range 2.15:1
to 3:1.
16. The method according to claim 15, characterised in that the
pressure ratio across each compression stage is in the range 2.5:1
to 3:1.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] National Stage application of International Application No.
PCT/EP2005/000279 filed Jan. 13, 2005, which claims priority to
British Application No. GB 0400986.6 filed Jan. 16, 2004.
BACKGROUND OF THE INVENTION
[0002] This invention relates to a rotary liquefied natural gas
boil-off compressor. The invention also relates to a method of
compressing boiled-off natural gas.
[0003] Liquefied natural gas is required to be stored in
thermally-insulated tanks. Notwithstanding the thermal insulation,
there is always a discernible inflow of heat from the surroundings
which causes the liquefied natural gas to boil at a modest rate.
The resulting boiled-off liquefied natural gas may be compressed
and reliquefied or may be used as a fuel. Use of the boiled-off
natural gas as a fuel usually requires its compression. For
example, it has been proposed to use the boil-off gas from a
shipboard liquefied natural gas storage tank to fuel a gas turbine
forming part of the ship's propulsion system. Such a gas turbine,
typically requires the boiled-off natural gas to be compressed to a
pressure in the order of 20 to 40 bar. In another example, the
natural gas is employed together with diesel fuel in an engine
employing both fuels. In this example, the natural gas may be
compressed to a pressure in the range of 5 to 7 bar.
[0004] Conventional boil-off compressors employ six compression
stages in series if a pressure as high as 40 bar needs to be
achieved. The compression of the gas in each stage generates heat.
Accordingly the natural gas is cooled between each pair of
successive stages by indirect heat exchange with water. Such
machines typically require quite large motors and have a
substantial power consumption.
BRIEF SUMMARY OF THE INVENTION
[0005] It is an aim of the present invention to provide a liquefied
natural gas boil-off compressor which has a reduced size and power
consumption.
[0006] According to the present invention there is provided a
rotary liquefied natural gas boil-off compressor having at least
two compression stages in series, a gas passage passing through the
series of compression stages, the gas passage extending through and
being in heat exchange relationship with at least one cooling means
between the or each pair of compression stages, characterised in
that the cooling means or at least one of the cooling means is a
cryogenic cooling means and in that there is valve means for
controlling flow of cryogenic coolant into the cryogenic cooling
means in response to the inlet temperature, or a related parameter,
of the next compression stage downstream of the cryogenic cooling
means so as, in use, to maintain said inlet temperature at a chosen
sub-ambient temperature or between chosen sub-ambient temperature
limits.
[0007] The invention also provides a method of operating a rotary
liquefied natural gas boil-off compressor having at least two
compression stages in series and a gas passage passing through the
series of compression stages, the method comprising cooling the
compressed boiled-off natural gas by means of a cryogenic coolant
downstream of one of the compression stages and upstream of
another, monitoring the inlet temperature, or a related parameter,
of the compressed natural gas at the inlet to the other compression
stage, and adjusting the flow rate of cryogenic coolant so as to
maintain said inlet temperature at a chosen sub-ambient temperature
or between chosen sub-ambient temperature limits.
[0008] By use of a cryogenic coolant in accordance with the
invention, particularly between each pair of successive compression
stages, it is possible to increase the ratio of the outlet pressure
to the inlet pressure of each such stage, and thereby typically
reduce the number of compression stages required to achieve a
particular pressure. For example, it is possible by means of the
compressor and method according to the invention to raise the
pressure of boiled-off liquid natural gas from 1 bar to
approximately 40 bar using only four stages of compression, whereas
a comparable conventional compressor employing non-cryogenic
cooling, typically water cooling, requires six stages to reach such
a high pressure. As a result, the invention makes it possible in
these circumstances to achieve the same increase of pressure with a
smaller machine using fewer compression stages and a lower power
consumption.
[0009] The or each cryogenic cooling means may be either an
indirect cooling means, e.g. separate passes of a heat exchanger,
or a direct cooling means, e.g. the gas passage may extend through
a chamber into which a cryogenic liquid is introduced, for example,
in the form of a spray. It is preferred to have a cryogenic cooling
means intermediate each pair of compression stages. If there are
three or more compression stages it is preferred that at least one
of the cryogenic cooling means is an indirect cryogenic cooling
means and at least one other is a direct cooling means. In one
preferred arrangement a cryogenic liquid is only partially
vaporised in an indirect cryogenic cooling means and there is a
passage placing the inlet of a direct cryogenic cooling means in
communication with the outlet of the indirect cryogenic cooling
means.
[0010] There may also be a direct or indirect cryogenic cooling
means downstream of the final compression stage. If indirect, the
cryogenic cooling means may have an outlet communicating with an
inlet to a direct cryogenic cooling means upstream thereof.
[0011] The source of the cryogenic coolant is preferably the same
liquefied natural gas storage tank or array of storage tanks from
which the boil-off gas is evolved. Such tanks are conventionally
equipped with so-called stripping pumps which may be employed to
supply the cryogenic liquid to the cryogenic coolant means.
Alternatively, a dedicated cryogenic coolant supply pump may be
used.
[0012] There may be a cryogenic cooling means upstream of the first
compression stage. Such a cryogenic cooling means will not normally
be operated as the boiled-off natural gas is usually at a cryogenic
temperature, but may be required when the liquefied natural gas
storage tank is nearly empty, and the boil-off gas is therefore
typically received at an undesirably high temperature, a condition
that typically occurs after an ocean going LNG tanker has
discharged its load of LNG to a shore-based terminal. The upstream
cooling means may also be employed at start up when the piping is
warm.
[0013] In order to supplement the rate at which natural gas is
compressed, the compressor according to the invention may have an
intermediate inlet communicating with a forcing liquefied natural
gas vaporiser.
[0014] The forcing vaporiser and the cryogenic cooling means may if
desired share a common pump for the supply of the cryogenic
liquid.
[0015] The inlet temperature of each stage of the compressor is
preferably maintained at a temperature in the range of minus 50 to
minus 140.degree. C. By this means, it is possible to achieve a
pressure ratio across each stage in the range of 2.15:1 to 3:1, and
typically in the range 2.5:1 to 3:1. It is particularly desirable
to avoid the presence of any droplets of liquid in the natural gas
entering any stage of the compressor. Accordingly, if any direct
cryogenic cooling means is employed, the resulting cooled gas may
be passed through an apparatus for disengaging particles of liquid
therefrom.
[0016] Compressors and methods of their use according to the
invention will now be described by way of example with reference to
the accompanying drawings, in which:
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] FIGS. 1 to 5 of the accompanying drawings which are all
schematic flow diagrams, and
[0018] FIG. 6 shows a modification to any of the direct cooling
stages of the compressors shown in FIGS. 2, 4 and 5.
DETAILED DESCRIPTION OF THE INVENTION
[0019] Referring to FIG. 1 of the drawings, there is shown an LNG
storage tank 2. For the purposes of ease of illustration, various
pipes and valves associated with the tank 2, for example, its fill
pipe and its LNG discharge pipe, are not shown in FIG. 1 and the
other drawings. The configuration and operation of such LNG tanks
is however well known in the art. The tank 2 is typically located
on board an ocean-going tanker (not shown). The tank 2 is shown
containing a volume 4 of LNG. There is an ullage space 6 above the
surface of the volume 4 of LNG in the tank 2. The tank 2 is
vacuum-insulated or has another form of thermal insulation
associated therewith so as to keep down the rate of flow of heat
from the ambient environment into the liquid 4. Since LNG boils at
a cryogenic temperature, notwithstanding the thermal insulation of
the tank 2, there is continuous adsorption of heat by the LNG from
its surroundings and hence continuous evaporation of the LNG into
the ullage space 6. As a result there is a continuous flow of
vaporised gas out of the tank 2 into a passage 8. The passage 8
provides a flow of gas to a plural stage, centrifugal, natural gas
compressor 10. Apart from the arrangements for cooling the gas
downstream of each stage of the compressor 10, and an optional
arrangement for cooling the gas upstream of the first stage
thereof, it is essentially conventional but is made of materials
suitable for use at cryogenic temperatures. Unlike, say, a nitrogen
compressor, the natural gas compressor 10 is built to be explosion-
proof. Because many features of the natural gas compressor 10 are
conventional they are not illustrated in FIG. 1 of the drawings.
Thus, for example, the rotary devices within the individual
compression stages are not shown.
[0020] The centrifugal compressor 10 has, as shown, four
compression stages 12, 14, 16 and 18 in series. The rotary member
(not shown) of each of the compression stages 12, 14, 16 and 18 may
be mounted on the same drive shaft 20 and driven by an electric
motor 22. It is not, however, necessary for all the compression
stages to be mounted on the same shaft. If desired, some of the
stages may be mounted on a first shaft and others on a second shaft
with drive from one shaft to another being transmitted through a
gear box. Similarly, it is not necessary for an electric motor 22
to be used to drive the shaft 20. Other kinds of motor may be used
instead, or other forms of drive such as a steam turbine may be
used instead. If an electric motor 22 is employed, however, it is
preferably of a kind that has a single speed or it employs a
frequency converter to enable the speed of rotation to be varied
and thus the performance of the compressor to be optimised.
[0021] Compression of the natural gas in each of the stages 12, 14,
16 and 18 causes its temperature to rise. In general, the greater
the temperature rise the less thermodynamically efficient the
compression. The greater the inlet temperature at each compression
stage, the more power that is consumed in compressing the gas.
Further, as the temperature of the gas rises so its density falls.
The more dense the gas, the smaller the compression stage needed to
achieve a given increase in pressure. This corresponds to the
enthalpy change at lower or higher temperature.
[0022] In accordance with the invention, a first cryogenic
interstage heat exchanger 26 is located intermediate the first
compression stage 12 and the second compression stage 14; a second
cryogenic interstage heat exchanger 28 is located intermediate the
second compression stage 14 and the third compression stage 16, and
a third cryogenic interstage heat exchanger 30 is located
intermediate the third compression stage 16 and the final
compression stage 18. The heat exchangers 26, 28 and 30 are
employed to effect cryogenic interstage cooling of the natural gas
as it flows through the series of compression stages 12, 14, 16 and
18 in sequence. A further cryogenic heat exchanger 32 is located
downstream of the final compression stage 18 and a yet further
cryogenic heat exchanger 24 is located upstream of the first
compression stage 12 in the sequence. Accordingly, the passage 8
extends in sequence through the upstream cryogenic heat exchanger
24, the first compression stage 12, the first cryogenic interstage
heat exchanger 26, the second compression stage 14, the second
cryogenic interstage heat exchanger 28, the third compression stage
16, the third cryogenic interstage heat exchanger 30, the final
compression stage 18 and the downstream cryogenic heat exchanger
32.
[0023] Cooling of the boiled-off natural gas evolved from the
volume of liquid 4 in the tank 2 is effected in each of the
interstage heat exchangers 26, 28 and 30. The cooling is cryogenic
so as to reduce the temperature of the gas entering the next
compression stage in the sequence to a temperature in the range
minus 50 to minus 140.degree. C. The upstream heat exchanger 24 may
also be used to cool the gas to a similar temperature upstream of
the first compression stage 12, although, typically, the gas is
already at this temperature so the heat exchanger 24 will during
normal operation be by-passed or not operated. However, normal
practice when discharging LNG from the tank 2 is to leave a small
proportion of the liquid therein so as to maintain the tank 2 on
the return journey. In consequence, during the return journey, the
temperature of the boil-off gas tends to be much higher than when
the tank 2 is full and it is then desirable to operate the upstream
heat exchanger 24. Similarly, the downstream heat exchanger may be
operated to cool the gas leaving the final stage 18 of the
compressor 10 to a temperature in the range minus 50 to minus
140.degree. C. if the gas is required at such a cryogenic
temperature. If it is required at ambient temperature, however, the
cryogenic heat exchanger 32 may be omitted.
[0024] As shown in FIG. 1, all the cryogenic heat exchangers 24,
26, 28, 30 and 32 are indirect heat exchangers. As will be
discussed below, some or all may alternatively be direct heat
exchangers, that is to say heat exchangers in which the coolant
fluid is mixed with the fluid to be cooled. It should also be noted
that it is possible in accordance with the invention to operate
only one of the interstage heat exchangers 26, 28 and 30
cryogenically, but such a mode of operation is not preferred. It is
also possible in accordance with the invention to provide a single
indirect heat exchanger unit that provides cryogenic cooling of the
boiled off natural gas intermediate two or more pairs of
compression stages. For example, the heat exchangers 26, 28 and 30
may be combined in a single unit. Further, if desired, the heat
exchangers 24 and 32 may be included in that unit.
[0025] The source of the cryogenic fluid for cooling the heat
exchangers 24, 26, 28, 30 and 32 is the storage tank 2 itself. A
submerged pump 34 within the tank 2 pumps liquefied natural gas
(LNG) to a main pipeline 36. The main pipeline 36 communicates with
cooling passages in the heat exchangers 24, 26, 28, 30 and 32 by
distributor pipes 38, 40, 42, 44 and 46, respectively. Cooling is
effected in each of these heat exchangers by partial or total
vaporisation of the LNG in indirect heat exchange with the boil-off
gas being compressed. Flow of the LNG into each of the interstage
heat exchangers 26, 28 and 30 is controlled so as to maintain the
temperature of the boil-off gas at the inlet to the next
compression stage in the sequence at a chosen value or between
chosen bounds. The first interstage heat exchanger 26 has in the
distribution pipe 40 associated therewith a flow control valve 50
operatively associated through a valve controller 70 with a
temperature sensor 60 positioned in the passage 8 at a region
intermediate the exit for compressed boil-off gas from the heat
exchanger 26 and the inlet to the second compression stage 14. It
can be readily appreciated by those well versed in the art of flow
control valves that the valve 50 may be so arranged as to maintain
the temperature sensed by the sensor 60 at a chosen value, say
minus 130.degree. C., or between chosen limits, say, minus
125.degree. C. and minus 135.degree. C. Essentially identical flow
control equipment is provided for the two other interstage heat
exchangers 28 and 30 and for the upstream heat exchanger 24 and the
downstream heat exchanger 32. Control of the LNG flow to the heat
exchanger 28 is provided by a flow control valve 52 in the
distribution pipe 42. A temperature sensor 62 is positioned in the
passage 8 intermediate the outlet of the heat exchanger 28 and the
inlet to the next compression stage 16. A valve controller 72 is
adapted to adjust the valve 52 so as to hold the sensed temperature
at a chosen value or between chosen temperatures; an essentially
identical arrangement of flow control valve 54, temperature sensor
64 and valve controller 74 is provided for the third interstage
heat exchanger 30; an essentially identical arrangement of flow
control valve 56, temperature sensor 66 and valve controller 76 for
the downstream heat exchanger 32, and an essentially identical
arrangement of flow control valve 48, temperature sensor 58 and
flow controller 68 for the upstream heat exchanger 24.
[0026] Should the demand for LNG fluctuate, excess LNG may be
returned to the tank via a return pipeline 78 which branches off
from the main pipeline 36. Preferably, there is a flow control
valve 79 in the pipeline 78 which is operatively associated via a
valve controller 82 with a pressure sensor 80 in the main pipeline
36 at a region of it upstream of all the distributor pipes 38, 40,
42, 44 and 46 so as to maintain the LNG supply at constant
pressure. If desired, the rate of pumping LNG from the tank 2 to
the pipeline 36 may always be in excess of that required for the
purposes of the heat exchangers 24, 26, 28, 30 and 32 so that there
is always LNG returned to the tank 2 via the pipeline 78. Such
return can be arranged to ameliorate or control the effects of
stratification of the LNG in the tank 2.
[0027] In operation of the apparatus shown in FIG. 1, LNG coolant
passing through the heat exchangers 24, 26, 28, 30 and 32 flows in
totally or partially vaporised form to a main return pipeline 84
via pipes 86, 88, 90, 92 and 94 associated with the heat exchangers
24, 26, 28, 30 and 32 respectively. The pipeline 84 as shown
returns the cold natural gas from these heat exchangers to the
ullage space of the tank 6. Alternatively, the pipeline 84 may
terminate in a region of the passage 8 upstream of the heat
exchanger 24 or even downstream of the heat exchanger 32 if the
pressure of the LNG supply is high enough.
[0028] The compressed boiled-off natural gas can, as stated above,
be arranged to leave the heat exchanger 32 at a temperature in the
range of minus 60 to minus 140.degree. C. If the gas is to be
reliquefied, then a lower temperature is favoured. If the gas is,
however, to be used as fuel for running an engine that provides
propulsion for the ocean-going vessel, then a higher temperature is
acceptable and indeed, if desired, the final heat exchanger 32 may
be omitted or have a conventional water-cooled heat exchanger
substituted for it.
[0029] The pressure ratio across each of the compression stages 12,
14, 16 and 18 may be selected according to the required final
outlet pressure. For a gas turbine requiring a natural gas feed of
40 bar and a feed boil-off gas stream at a pressure of 1 bar, each
compression stage may have a pressure ratio of 2.6:1. If, however,
the gas turbine requires natural gas at a pressure of only 20 bar,
the pressure ratio across each compression stage may be 2.1:1. One
particular advantage of the invention is that it is difficult to
achieve pressure ratios as high as 2.6:1 with natural gas when
conventional cooling is used. If desired, the pressure ratio across
each compression stage may be tailored by appropriately setting the
inlet temperature to that stage.
[0030] Some of the possible alternative embodiments of the
compressor according to the invention are shown in FIGS. 2 to 5 of
the accompanying drawings. Like parts shown in FIGS. 1 to 5 of the
drawings are indicated by the same reference numerals.
[0031] Referring first to FIG. 2, the compressor and associated
equipment shown therein, and their operation, are essentially the
same as for the corresponding compressor and equipment shown in
FIG. 1 with the exception that the indirect heat exchangers 24, 26,
28, 30 and 32 of FIG. 1 are replaced by direct heat exchangers 202,
204, 206, 208 and 210 respectively. In each of the direct heat
exchangers 202, 204, 206, 208 and 210 the LNG is sprayed directly
into the stream of boil-off gas from the storage tank 2 and
therefore augments that stream. As a result, there is no vaporised
natural gas to recirculate to the storage tank 2. Accordingly, the
pipes 86, 88, 90, 92 and 94 and the return pipeline 84 are omitted
from the equipment shown in FIG. 2.
[0032] In a typical example of the operation of the apparatus shown
in FIG. 2, the outlet pressures of the compression stages 12, 14,
16 and 18 are 2.6, 6.3, 15.4 and 40 bar, respectively.
[0033] Whereas the boiled-off natural gas entering the pipeline 8
is depleted of heavier hydrocarbon impurities such as ethane,
propane and butane, the LNG supplied by the pump 34 will normally
contain these impurities. As a result, mixing of the boiled off
natural gas with the LNG in the direct heat exchangers 202, 204,
206, 208 and 210 will tend to raise the dewpoint of the boiled-off
natural gas. It is thus desirable to ensure that the temperature
control is exerted so as to prevent particles of liquid being
carried from a mixing chamber into a compression stage. If desired,
the compressor shown in FIG. 2 can be provided with a device for
disengaging liquid particles from the boiled off natural gas
intermediate any chosen direct heat exchanger and the compression
stage immediately downstream thereof. For example, referring now to
FIG. 6 of the drawings there is included between a mixing chamber
600 and the compression stage 602 associated therewith a phase
separation vessel 604 having a demister pad 608 or the like
inserted therein above an inlet 606. The natural gas passes through
the pad 608 and has any particles of liquid disengaged therefrom.
The phase separation vessel 604 has an outlet 612 at its bottom for
disengaged liquid. A flow control valve 614 is located in the
outlet 612 and may be arranged to open whenever the level of the
liquid in the vessel 604 reaches that of a level sensor 616. A
valve controller 618 may be programmed so as to transmit the
necessary signals to the valve 614. The LNG may be returned to the
storage tank 2.
[0034] An arrangement such as that described above with reference
to FIG. 6 may be employed upstream of one or more of the
compression stages shown in FIG. 2 of the drawings.
[0035] Another alternative to the equipment shown in FIG. 1 is
illustrated in FIG. 3. The equipment shown in FIG. 3 is for use
when the normal boil-off rate from the LNG stored in the tank 2 is
too small to create enough energy for the ship's propulsion. For
example, the boil-off may be burnt in a gas turbine or injected
into a dual fuel diesel engine. Typically, approximately 50% to 60%
of the propulsion power can be covered by the natural boil-off gas.
The rest of the propulsion power is raised by oil or diesel fuel.
The equipment shown in FIG. 3 can be used when a greater proportion
or all of the energy for propulsion of the ship is to be generated
by combustion of the gas. The equipment shown in FIG. 3 provides
forced boiling in addition to the natural boiling of the LNG with
the forced vapour being used for cryogenic cooling between at least
one pair of stages of the compressor.
[0036] The equipment shown in FIG. 3 adds to that shown in FIG. 1 a
forcing vaporiser 302 which has an inlet for LNG communicating with
the pipeline 36 upstream of its union with the distributor pipe 38
and which also has an outlet communicating with a region of the gas
passage 8 intermediate the outlet of the first compression stage 12
and the compressed natural gas inlet to the first interstage heat
exchanger 26. The forcing vaporiser 302 is used to augment the flow
of compressed natural gas from the outlet of the first compression
stage 12. The forcing vaporiser 302 includes a shell-and-tube heat
exchanger 304 in which liquefied natural gas from the storage tank
2 is vaporised by indirect heat exchange with steam or a hot
mixture of water and glycol, and a mixing chamber 306 in which the
thus vaporised natural gas is mixed with a flow of LNG which
by-passes the shell-and-tube heat exchanger 304. In order to supply
the by-pass flow of LNG there is a by-pass passage 308 having a
flow control valve 310 disposed therein. The flow control valve 310
is operatively associated with a valve controller 312 which
receives signals from a temperature sensor 314 in a pipeline 316
extending from the outlet of the chamber 306 to the region of the
gas passage 8 intermediate the compression stage 12 and the first
interstage heat exchanger 26. The arrangement is such that the
amount of by-pass LNG can be adjusted so as to maintain the
temperature of the flow to the gas passage at a chosen temperature
or between chosen temperature limits. The flow of LNG into the
shell-and-tube heat exchanger 304 is controlled by a flow control
valve 318 which is operatively associated with a valve controller
320 responsive to demand signals for extra gas from a pressure
sensor 322 in the pipeline 316 or downstream of the heat exchanger
32. The arrangement is such that the flow of vaporised natural gas
from the forcing vaporiser 302 is at essentially the same pressure
as the outlet pressure of the first compression stage 12.
[0037] Referring now to FIG. 4, there is shown a modification to
the equipment illustrated in FIG. 3, in which a combination of
indirect and direct heat exchangers is used. Thus, the indirect
heat exchangers 24, 26 and 28 shown in FIG. 3 are replaced by
direct heat exchangers 402, 404 and 406, respectively. Further, the
pipes 38, 40, 42, 86, 88 and 90 are replaced by partially vaporised
natural gas recycle pipes 408, 410 and 412 and the valves 48, 50
and 52, respectively are located in these pipes. A further
difference from the apparatus shown in FIG. 3 is that the forcing
vaporiser 302 now communicates with a region of the gas passage 8
intermediate the outlet of the second compression stage 14 and the
inlet to the direct interstage heat exchanger 406.
[0038] The operation of the equipment shown in FIG. 4 is similar to
that shown in FIG. 3. In the heat exchangers 30 and 32 the LNG
supplied to the heat exchangers 30 and 32 is only partially
vaporised therein and the resultant mixture of cold vapour and
liquid is recirculated to the direct heat exchangers 402, 404 and
406. It is found that this arrangement is particularly effective in
keeping down the power consumption of the compressor 10.
[0039] Referring now to FIG. 5, the apparatus shown therein is
essentially the same as that shown in FIG. 2 but in addition
employs a forcing vaporiser 302 essentially the same as that shown
in FIG. 3 except that it communicates with the gas passage 8 at a
region thereof downstream of the outlet of the final compression
stage 18 but upstream of the direct heat exchanger 210. In the
embodiment shown in FIG. 5, the forcing vaporiser 302 is operated
so as to provide a flow of natural gas to the gas passage 8 at a
pressure essentially the same as the outlet pressure of the final
stage 18 of the compressor 10.
[0040] It can thus be appreciated that the compressor shown in FIG.
3 employs a relatively low pressure forcing vaporiser, whereas that
shown in FIG. 5 employs a relatively high pressure forcing
vaporiser, and that shown in FIG. 4 employs a forcing vaporiser
operating at a pressure between the operating pressure of the other
two compressors.
[0041] The compressors shown in FIG. 4 and FIG. 5 may be modified
by having a phase separation vessel placed upstream of any stage
thereof which receives directly cooled natural gas, the phase
separation vessel being essentially the same as the vessel 604
shown in FIG. 6 and being fitted with a demister.
* * * * *