US20100107686A1

US20100107686A1 - Method and apparatus for separating one or more c2+ hydrocarbons from a mixed phase hydrocarbon stream

Info

Publication number: US20100107686A1
Application number: US12/594,224
Authority: US
Inventors: Eduard Coenraad Bras; Diana Hooi Kheng Ooi
Original assignee: Individual
Current assignee: Shell USA Inc
Priority date: 2007-04-04
Filing date: 2008-04-02
Publication date: 2010-05-06
Also published as: EP2132508A2; AU2008235485B2; RU2493510C2; WO2008122556A3; RU2009140747A; AU2008235485A1; CA2682308A1; MX2009010129A; WO2008122556A2

Abstract

A method for separating one or more C₂+ hydrocarbons from a mixed phase hydrocarbon stream such as partly vapourised liquefied natural gas, the method at least comprising the steps of: (a) supplying a mixed phase hydrocarbon feed stream (10) to a first gas/liquid separator (12); (b) separating the hydrocarbon feed stream (10) in the first gas/liquid separator (12) into a first gaseous stream (20) from a first outlet (23) and at least one C₂+ liquid stream (30); (c) passing the first gaseous stream (20) through a compressor (14) to provide a compressed stream (60); and (d) cooling the compressed stream (60) in one or more heat exchangers (16) to provide an at least partly condensed hydrocarbon product stream (70); wherein a second gaseous stream (40) is added to a stream (20, 60, 70) downstream of the first outlet (23).

Description

The present invention relates to a method for separating one or more C₂+ hydrocarbons from a mixed phase hydrocarbon stream such as partly vapourised liquefied natural gas (LNG).
Liquid hydrocarbon streams such as LNG are well-known products, and they are commonly transported in a liquid form for vaporisation at a suitable location or terminal. One such terminal is an ‘import terminal’, which can vaporise the LNG for direct use, subsequent piping into a network, etc.
In their paper entitled “Processes for High C₂Recovery from LNG” for IPSI LLC, presented at the AlChE Spring Meeting in April 2006 (6th Tropical Conference on Natural Gas Utilisation, Orlando, Fla., Apr. 23-27, 2006), the authors stated that “re-gasified LNG being imported into the US must meet gas quality requirements before it can be accepted in the US pipeline grid. Towards this goal, many existing and prospective LNG terminal owners are considering C₂+ extraction”. Various arrangements are discussed in the Paper for improving the C₂+ recovery levels using a refluxed demethanizer, such as with residue compression and condensing; see for example its FIG. 7.
However, the IPSI Paper does not mention how a separate gaseous hydrocarbon stream can be accommodated into its processes. One additional gaseous hydrocarbon stream is boil-off-gas. Boil-off gas is generally always created in any storage or movement of a liquefied hydrocarbon stream such as LNG. Traditionally, boil-off gas from an LNG storage tank is simply compressed and recondensed. This has the problem of additional energy requirements, making it non-efficient.
There are other situations or locations, such as an LNG export terminal, where it may also be desired to have C₂+ extraction from a hydrocarbon stream or source, but wherein the problem of efficiently accommodating a separate gaseous hydrocarbon stream such as boil-off gas has not been considered.
The present invention provides a method for separating one or more C₂+ hydrocarbons from a mixed phase hydrocarbon stream such as partly vapourised liquefied natural gas, the method at least comprising the steps of:
(a) supplying a mixed phase hydrocarbon feed stream to a first gas/liquid separator;
(b) separating the hydrocarbon feed stream in the first gas/liquid separator into a first gaseous stream from a first outlet, and at least one C₂+ liquid stream;
(c) passing the first gaseous stream through a compressor to provide a compressed stream; and
(d) cooling the compressed stream in one or more heat exchangers to provide an at least partly condensed hydrocarbon product stream;
wherein a second gaseous stream is added to a stream downstream of the first outlet.
In a further aspect, the present invention provides apparatus for separating one or more C₂+ hydrocarbons from a mixed phase hydrocarbon stream such as liquefied natural gas, the apparatus at least comprising:
a first gas/liquid separator having an inlet for a mixed phase hydrocarbon feed stream, a first outlet for a first gaseous stream and a second outlet for at least one C₂+ hydrocarbon liquid stream;
a compressor to compress the first gaseous stream to provide a compressed stream;
one or more heat exchangers to cool the compressed stream to provide an at least partly condensed hydrocarbon product stream; and
a combiner to combine a second gaseous stream with a stream downstream of the first outlet of the gas/liquid separator.

Embodiments of the present invention will now be described by way of example only and with reference to the accompanying non-limiting drawings in which:

FIG. 1 is a schematic process scheme in accordance with a first embodiment of the present invention; and

FIG. 2 is a schematic process scheme in accordance with a second embodiment of the present invention.

For the purpose of this description, a single reference number will be assigned to a line as well as a stream carried in that line. Same reference numbers refer to similar components.
It is an object of the present invention to reduce the capital and running costs in a method for separating one or more C₂+ hydrocarbons from a mixed phase hydrocarbon stream to accommodate a further gaseous hydrocarbon stream such as boil-off gas.
The present methods and apparatus allow to have C₂+ extraction from a hydrocarbon stream or source, wherein a separate gaseous hydrocarbon stream such as boil-off gas is efficiently accommodated.
It has been found that using the surprisingly simple method and apparatus described herein, a second gaseous stream can be accommodated into the method for separating one or more C₂+ hydrocarbons from a mixed phase hydrocarbon stream with minimal, if any, additional running or capital costs.
A further advantage is provided by avoidance of adding the second gaseous stream into the gas/liquid separator, which would require a larger gas/liquid separator due to the larger gaseous volume involved, and so also lead to increasing capital and running costs.
A further advantage is provided by avoidance of adding the second gaseous stream into apparatus for cooling, preferably re-condensing, the first gaseous stream from the gas/liquid separator, where the warmth of the second gaseous stream would disadvantage the desire for the coldest hydrocarbon product stream.
Advantageously, the second gaseous stream is recovered as part of a useful product stream. Where the second gaseous stream comprises one or more useful, commercial or otherwise valuable hydrocarbons, these are recovered by the present invention rather than being burnt off or only used as a source of fuel. Thus the method the present invention is also able to provide a greater volume or amount of a product stream than prior art processes.
The mixed phase hydrocarbon stream may be any suitable at least partly vapourised hydrocarbon-containing stream, such as a partly vapourised LNG stream, from which it is intended to recover one or more C₂+ liquid streams. The mixed phase hydrocarbon stream may be at least partly vaporised from a liquid source and it may optionally contain also hydrocarbons that have at least partly condensed from a gaseous source.
It is remarked that U.S. Pat. No. 6,023,942 discloses a process for liquefying a gas stream rich in methane. If the natural gas stream contains heavy hydrocarbons, these may be extracted by a fractionation process before liquefying the gas. A problem associated with U.S. Pat. No. 6,023,942 that is not addressed in said patent, is what to do when the content of heavy hydrocarbons in an already liquefied product is higher than desired, which may for instance be the case if the fractionation process upstream of the liquefaction is not sufficiently selective to produce a liquefied stream with a level of C₂+ components below a desired maximum.
The present methods and apparatuses solve this problem, without the need to modify any pre-liquefaction facilities that may already be available in an existing liquefaction line-up. The presently proposed solution may be added-on to an existing facility at a liquefaction site or an export site, or locally at an import site to be able to modify the content of the liquefied product to comply with local requirements.
As is the case for the mixed phase hydrocarbon stream, the second gaseous stream may also be any suitable hydrocarbon-containing stream. Optionally, the second gaseous stream has the same components and composition as the source of the mixed phase hydrocarbon stream. One preferred second gaseous stream is boil-off gas, for example gas evaporated from a liquefied hydrocarbon store or source, such as one or more storage tanks. The storage tanks could be static or moveable, such as storage tanks on a sea-going transporter, or a combination of same.
U.S. Pat. No. 6,658,892 B2 shows use of boil-off gas from two LNG storage tanks in a storage area, which is combined with an overhead reject gas from a common flash tank and then fed into a common fuel gas compressor. However, the common flash tank in U.S. Pat. No. 6,658,892 B2 is not intended to provide at least one C₂+ liquid stream, but to produce a bottom LNG stream (line 124). Thus, the boil-off gas in U.S. Pat. No. 6,658,892 B2 is not combined with a C₂+ depleted gaseous stream downstream of a gas/liquid separator, but is combined with the reject gas taken from a common flash tank handling cooled feed gas produced from two independent trains.
The one or more C₂+ liquid streams provided in step (b) of the present invention comprises at least one stream comprising at least 40 mol % of at least one C₂+ hydrocarbon, such hydrocarbons being one or more selected from the group comprising: ethane, propane, butanes and pentanes. Preferably, at least one of said streams comprises >50 mol %, >60 mol %, >70 mol %, >80 mol % or >90 mol % of at least one C₂+ hydrocarbon.
FIG. 1 schematically shows a process scheme (generally indicated with reference number 1) for recovering C₂+, that is ethane and heavier, hydrocarbons from a mixed phase hydrocarbon feed stream 10.
The process shown in FIG. 1 is equally able to recover just a C₂, C₃or C₄, etc. stream, or C₃+, C₄+ streams, etc., from a hydrocarbon stream, either as separate streams, or as one or more combined streams, or a combination of same.
The mixed phase hydrocarbon feed stream 10 may be any suitable hydrocarbon-containing stream from which it is intended to recover one or more C₂+ liquid streams. The mixed phase hydrocarbon feed stream 10 is preferably at least partly vapourised from a liquid source such as LNG, and has a pressure above ambient, typically between 8 and 15 bar.
Prior to the process scheme shown in FIG. 1, the mixed phase hydrocarbon feed stream 10 may have been utilised in one or more other processes. One example is use of some of the cold energy of a liquid hydrocarbon stream, such that the mixed phase hydrocarbon feed stream 10 is consequently at least partly vapourised.
The mixed phase hydrocarbon stream 10 is preferably provided by a liquid hydrocarbon stream such as a cold stream obtained from a source of LNG, such as a liquid product output stream of a liquefaction plant, or, preferably, from one or more liquefied hydrocarbon storage tanks such as one or more LNG storage tanks. Such tanks may be static or moveable, such as on a sea-going transporter. Thus the source of the LNG could be one or more storage tanks on an LNG vessel or carrier, the LNG being carried by a loading or unloading line at an LNG import or export terminal. These liquefied hydrocarbon storage tanks could be the same as the liquefied hydrocarbon storage tanks that provide the boil-off gas for the second gaseous stream, or they could be different ones, or a combination of the same and different ones.
As is customary to the person skilled in the art, the LNG stream may have various compositions. Usually the LNG stream to be vaporized is comprised substantially of methane. The LNG will generally contain varying amounts of hydrocarbons heavier than methane such as ethane, propane, butanes and pentanes.
Optionally, the mixed phase hydrocarbon feed stream 10 is comprised substantially of methane, that is at least 80 mol %, preferably at least 90 mol %, 95 mol % or even 99 mol %, methane.
The mixed phase hydrocarbon feed stream 10 is supplied to the inlet 22 of a first gas/liquid separator 12. The nature, design and capacity of the first gas/liquid separator 12 can relate to the nature of the incoming mixed phase hydrocarbon feed stream 10 and the desired streams to be recovered. For example, where it is desired to recover C₂+ hydrocarbons from the mixed phase hydrocarbon feed stream 10 at the bottom of the first gas/liquid separator 12, the first gas/liquid separator 12 could be a de-methanizer, known in the art. Alternatively, recovery of C₃+ hydrocarbons as a bottom product may use a de-ethanizer, also known in the art.
The gas/liquid separator 12 may be any suitable vessel or arrangement for obtaining a gaseous stream and a C₂+ liquid stream, such as a scrubber, distillation column, etc. The gas/liquid separator 12 may comprise more than one separator, column, etc., and may be designed for the separate separation of two or more liquid streams, such as a C₂stream and a C₃stream, etc. Such separators usually operate at above ambient pressure, for example 6-12+ bar, depending on the type and recovery of product(s) desired or expected, and optionally with one or more reflux operations.
The recovery of C₂+ hydrocarbons from a mixed phase hydrocarbon feed stream 10 could be as part of one of a number of processes using a hydrocarbon feed stream. One process is for ‘purification’ of the hydrocarbon feed stream to minimise heavier hydrocarbons therein, prior to its subsequent use or further processing. Another process is for adjusting the gas quality, for example for meeting a particular heating value downstream. Another process is for providing one or more C₂+ streams, such as liquid petroleum gas (LPG). A combination of one or more of these processes or other objectives may also be desired.
For example, it is known that ‘rich’ LNG generally comprises about 5 mol % of C₂+ hydrocarbons, which percentage can be too high for use in certain territories or locations. At least some of C₂+ hydrocarbons (especially ethane, propane and butane) are also termed ‘natural gas liquids’ (NGLs), and the production of NGLs is also commercially attractive.
Thus, one particular involvement of the first gas/liquid separator 12 in the process scheme of FIG. 1 is to reduce the amount of C₂+ hydrocarbons in a methane feed stream, and to provide one or more C₂+ product streams, for example at an import terminal handling rich-LNG.
In FIG. 1, the first gas/liquid separator 12 shows separation of the hydrocarbon feed stream 10 into a first gaseous stream 20 through a first outlet 23, and a liquid stream 30 through a second outlet 24. The liquid stream 30 may comprise one or more separate streams.
In the present invention, it is preferred that the first gas/liquid separator 12 is able to recover >80 mol %, >90 mol %, or even ≧95 mol % of the heavier (C₂+, C₃+, etc,) hydrocarbons, as the liquid stream or streams 30 from the first gas/liquid separator 12.
The first gaseous stream 20 is combined with a second gaseous stream 40 by a combiner 18. A combiner 18 may be a distinct combination unit or vessel, or merely a conjunction of streams or pipelines.
The second gaseous stream 40 preferably has the same or similar pressure, temperature and other parameters as the first gaseous stream 20 at the combiner 18. It is also possible for the second gaseous stream 40 to have different parameters and/or conditions.
The combination of the first gaseous stream 20 and second gaseous stream 40 provide a combined gaseous stream 50, which passes into a compressor 14. The combined gaseous stream 50 has the combination of parameters of the first gaseous stream 20 and second gaseous stream 40, and is preferably still gaseous and at above ambient pressure.
The compressor 14 may comprise one or more compressors in series or parallel or both, designed to compress the combined gaseous stream 50 to a higher pressure, and provide a compressed stream 60. Under some operating conditions, for example high compression, a portion of the combined gaseous stream 50 may become liquid in the compressor 14. Thus, the compressed stream 60 may be a mixed phase stream.
The compressed stream 60 is then cooled. In FIG. 1, the cooling is provided by a first heat exchanger 16, which may comprise one or more heat exchangers in series, parallel or both. The first heat exchanger 16 cools the compressed stream 60 to provide an at least partly condensed hydrocarbon product stream 70. The cooling in the heat exchanger 16 is provided by an incoming cold stream 80, which passes out of the heat exchanger 15 as a warmer stream 80 a. The incoming cold stream 80 may be any suitable cold stream being a dedicated refrigerant stream or any other stream having suitable cold energy that can be recovered. Optionally, it is a cold stream which is available from another part or function of an embodiment of the present invention.
The nature and arrangement of the first heat exchanger 16 and of the cold stream 80 are designed to provide the desired hydrocarbon product stream 70 (such as recondensed or partly vaporised LNG) and/or the desired one or more liquid streams 30 and/or to adjust the composition of the desired hydrocarbon product stream 70.
Optionally, a portion (not shown in FIG. 1) of the compressed stream 60 is used directly, for example fed or piped directly to a gas network.
The second gaseous stream 40 could be added to one or more of the group comprising: the first gaseous stream 20, the compressed stream 60, and the at least partly condensed hydrocarbon product stream 70; downstream of the first outlet 23 of the first gas/liquid separator 12.
Thus, in a first alternative embodiment, the second gaseous stream 40 is combined with the compressed stream 60 after the compressor 14. This may be more suitable where the parameters of the second gaseous stream 40, especially its pressure, are closer to the parameters of the compressed stream 60 than the first gaseous stream 20.
In a second alternative embodiment, the second gaseous stream 40 may be combined with the at least partly condensed hydrocarbon product stream 70.
This is especially where the parameters of the second gaseous stream 40, in particular its temperature and pressure, are closer (either inherently or by processing) to those of the at least partly condensed hydrocarbon product stream 70 than the first gaseous stream 40 or the compressed stream 60.
FIG. 2 schematically shows a process scheme (generally indicated with reference number 2) for a second embodiment of the present invention.
In particular, FIG. 2 shows a storage tank 32 such as an LNG storage tank at an LNG import terminal. Such storage tanks 32 are known in the art, and are generally designed to store liquefied hydrocarbons such as LNG for a period of time prior to transport and/or use of the LNG.
The storage tank 32 shown in FIG. 2 has a first outlet 25 for a liquid hydrocarbon stream 8. The storage tank 32 has a second outlet 26 for the passage of ‘boil-off gas’ 40 a. Due to the unavoidable inflow of heat into storage tanks of liquid hydrocarbons, which are generally kept at −100° C. or below, such as −160° C. for LNG, the creation of boil-off gas is inevitable.
Conventionally, boil-off gas is compressed, and recondensed. However, this requires at least one or more additional recondensers, which also involve additional running costs.
It is an object of the present invention to provide an alternative use of boil-off gas which does not require additional capital and/or running costs, or reduces same.
In FIG. 2, the liquid hydrocarbon stream 8 passes through a heat exchanger 16 a, which may be the same or different from the first heat exchanger 16 shown in FIG. 1. In the process scheme 2 shown in FIG. 2, involving the first heat exchanger 16 also means that the liquid hydrocarbon stream 8 is equivalent to the incoming cold stream 80 shown in FIG. 1, and at least some of its cold energy is used to cool a second stream (discussed hereinbelow) also passing through the heat exchanger 16 a.
The heat exchanger 16 a may be one or more heat exchangers in series, parallel or both, and its arrangement and configuration will be known to those skilled in the art. Preferably, the heat exchanger 16 a comprises a preheater and/or a condenser as hereinafter described.
Through use of at least some of the cold energy of the liquid hydrocarbon stream 8, the heat exchanger 16 a provides a mixed phase hydrocarbon feed stream 10 (which may be equivalent to the warmer stream 80 a shown in FIG. 1), which passes into the first gas/liquid separator 12 through the inlet 22. The arrangement and configuration of the first gas/liquid separator 12 is described above, and generally provides one or more C₂+ liquid streams 30 through one or more outlets such as second outlet 24 as shown, and a first gaseous stream 20 through a first outlet 23.
The nature of the liquid stream(s) 30 is discussed above. FIG. 2 shows further use of a liquid stream 30, which passes into a heat exchanger such as a reboiler 44 to provide a reflux stream 30 a for re-entry into the first gas/liquid separator 12 via an inlet 26, and a liquid product stream 30 b. The liquid product stream 30 b may comprise one or more NGL streams for separate commercial use.
The first gaseous stream 20 in FIG. 2 is supplied into a second gas/liquid separator 36. The second gas/liquid separator 36 may be any unit or vessel able to allow any liquid to separate out as a liquid stream 90 a, and to provide a third gaseous stream 90 therefrom. As an example, the second gas/liquid separator 36 can be a ‘knock-out drum’ known in the art.
The second gas/liquid separator 36 is a convenient receiver of a second gaseous stream 40, especially a boil-off gas stream 40 a from the storage tank 32 as shown in FIG. 2. A gas/liquid separator usually has a number of fittings or ports, easily able to be adapted to provide one or more additional inlets of gas thereinto. As such, the present invention is also particularly convenient for the introduction of a second gaseous stream 40 into an existing gas/liquid separator such as a knock-out drum, including retro-fitting of a second gaseous stream passage and inlet into an existing plant, design or facility. In this way, the second gas/liquid separator 36 is acting as the combiner 18 of the two gaseous streams as shown in FIG. 1.
Boil-off gas is by its nature usually normally gaseous, and usually has a temperature below 0° C., such as between −20° C. and −90° C. Usually, but optionally, there is a boil-off gas compressor 34 to compress the boil-off gas stream 40 a to a greater than ambient pressure, such as between 6-15 bar. Where the storage tank 32 is storing LNG, boil-off gas is usually >70 mol % methane.
As the pressure is similar to that of the first gaseous stream 20 supplied by the first gas/liquid separator 12, minimal energy is required for the combination of the first gaseous stream 20 and a second gaseous stream 40 being the (optionally compressed) boil-off gas stream 40 a, in the second gas/liquid separator 36. This directly utilises the boil-off gas from the storage vessel 32 as a gaseous stream without requiring additional capital and running costs, in particular the need for other or additional recondensor(s) for the boil-off gas.
Furthermore, the introduction of the second gas stream 40 into the second gas/liquid separator 36 avoids the need for a larger first gas/liquid separator 12 to accommodate inflow of the second gaseous stream 40. It also makes the process of FIG. 2 independent of the supply of the second gaseous stream 40, where this may be intermittent and/or variable (for example during loading and unloading of LNG), as well as making the process independent of the temperature of the mixed phase hydrocarbon feed stream 10.
From the second gas/liquid separator 36, the third gaseous stream 90 is passed into a compressor 14. As described above, the compressor 14 may be one or more compressors, and provides a compressed stream 60.
The compressed stream 60 passes into the heat exchanger 16 a (described above), to be cooled by the liquid hydrocarbon stream 8 also passing into the heat exchanger 16 a.
It is preferred for the compressed hydrocarbon stream 60 to be cooled as much as possible by the liquid hydrocarbon stream 8, so as to provide an at least partly condensed hydrocarbon product stream 70 having the largest or greatest amount of cold energy. This is so as to maximise use of the cold energy in the at least partly condensed hydrocarbon product stream 70. For example, the hydrocarbon product stream 70 may be used in one or more further processes, which partly or fully vaporises the hydrocarbon product stream 70 and recovers its cold energy for integration with one or more other processes such as in a gas separation plant, power plant, etc.
It can be seen that the introduction of the relatively warm second gaseous stream 40 into either the colder liquid hydrocarbon stream 8 or the condensing heat exchanger 16 a would affect maximisation of the condensing of the compressed hydrocarbon stream 60 by the liquid hydrocarbon stream 8, and it is therefore less desired to carry out such alternative arrangements.
In FIG. 2, the at least partly condensed hydrocarbon product stream 70 can pass through a splitter 38. The splitter 38 may be a simple division of one or more streams or pipelines, or may be a distinct unit or vessel such as an accumulator having two or more outlets. The splitter 38 can provide two streams: a first (usually majority) at least partly (preferably fully) liquid stream 100 for subsequent use (such as pumping through a pump 46 and subsequent vaporisation in a vaporiser 48 to supply the hydrocarbon as a vapour product stream 110 to a network); and a second, usually minority, at least partly liquid stream 100 a. After passing through a pressure reduction valve 42, the second stream 100 a is an expanded stream 100 b which can be passed through an inlet 27 into the first gas/liquid separator 12 as a reflux stream. Some gas/liquid separators are more efficient where two or more incoming streams having different temperatures are supplied at different inlets, in a manner known in the art.
The second at least partly liquid stream 100 a is preferably less than 20 mol %, more preferably less than 10 mol %, of the at least partly condensed hydrocarbon product stream 70.
Table 1 gives an overview of estimated pressures and temperatures of the streams at various parts of an example process of FIG. 2.

TABLE 1

			Phase
Line	Pressure (bar)	Temperature (° C.)	composition*

8	9.5	−157	L
10	9.0	−114	V/L
100b	8.5	−125	V/L
20	8.5	−121	V
30b	8.6	−25	L
40	9.5	−24	V
60	13.5	−96	V
100	13.0	−122 or lower	L

*V = vapour, L = Liquid

The person skilled in the art will readily understand that many modifications may be made without departing from the scope of the invention.

Claims

1. A method for separating one or more C₂+ hydrocarbons from a mixed phase hydrocarbon stream, the method at least comprising the steps of:

(a) supplying a mixed phase hydrocarbon feed stream in the form of a partly vapourised hydrocarbon feed stream, to a first gas/liquid separator;

(b) separating the hydrocarbon feed stream in the first gas/liquid separator into a first gaseous stream from a first outlet, and at least one C₂+ liquid stream;

(c) passing the first gaseous stream through a compressor to provide a compressed stream; and

(d) cooling the compressed stream in one or more heat exchangers to provide an at least partly condensed hydrocarbon product stream;

(e) adding a second gaseous stream to a stream downstream of the first outlet, wherein the second gaseous stream comprises boil-off gas drawn from one or more liquid hydrocarbon storage tanks.

2. A method as claimed in claim 1, wherein the second gaseous stream comprises compressed boil-off gas.

3. A method as claimed in claim 1, wherein the second gaseous stream has a temperature of −25° C. or below, and comprises at least 70 mol % methane.

4. A method as claimed in claim 1, wherein the mixed phase hydrocarbon feed stream is provided from one or more liquid hydrocarbon storage tanks.

5. A method as claimed in claim 1, wherein the second gaseous stream is drawn from the one or more liquid hydrocarbon storage tanks in gaseous form.

6. A method as claimed in claim 1, wherein both the second gaseous stream and the mixed phase hydrocarbon feed stream are provided from the same liquid hydrocarbon storage tank(s).

7. A method as claimed in claim 1, wherein the second gaseous stream is added to one or more of the group comprising: the first gaseous stream, the compressed stream, and the at least partly condensed hydrocarbon product stream downstream of the first outlet.

8. A method as claimed in claim 1, wherein the second gaseous stream is combined with the first gaseous stream prior to step (c).

9. A method as claimed in claim 1, wherein the first gaseous stream is passed into a second gas/liquid separator to provide a separated gaseous stream prior to step (c).

10. A method as claimed in claim 9, wherein the second gaseous stream is also passed into the second gas/liquid separator.

11. A method as claimed in claim 1, wherein at least one of the one or more liquid hydrocarbon storage tanks is located in a sea-going transporter.

12. A method as claimed in claim 1, wherein the compressed stream is cooled in step (d) against a liquid hydrocarbon source stream to provide the mixed phase hydrocarbon feed stream and the at least partly condensed hydrocarbon product stream.

13. A method as claimed in claim 1, wherein the at least partly condensed hydrocarbon product stream is subsequently vapourised in a vaporiser.

14. A method as claimed in claim 1, further comprising the step of:

(F) dividing the at least partly condensed hydrocarbon product stream into a first at least partly liquid stream and a second at least partly liquid stream.

15. A method as claimed in claim 14, wherein the first at least partly liquid stream is subsequently vaporised in a vaporiser.

16. Apparatus for separating one or more C₂+ hydrocarbons from a mixed phase hydrocarbon stream, the apparatus at least comprising:

a first gas/liquid separator having an inlet for a mixed phase hydrocarbon feed stream in the form of a partly vapourised hydrocarbon stream, a first outlet for a first gaseous stream and a second outlet for at least one C₂+ hydrocarbon liquid stream;

a compressor to compress the first gaseous stream to provide a compressed stream;

one or more heat exchangers to cool the compressed stream to provide an at least partly condensed hydrocarbon product stream;

a line connected to one or more hydrocarbon storage tanks to provide a second gaseous stream comprising boil-off gas drawn from the one or more hydrocarbon storage tanks;

a combiner to combine the second gaseous stream with a stream downstream of the first outlet of the gas/liquid separator.

17. Apparatus as claimed in claim 16, wherein the combiner combines the second gaseous stream with one or more of the group comprising: the first gaseous stream, the compressed stream, and the at least partly condensed hydrocarbon product stream; downstream of the outlet of the gas/liquid separator.

18. Apparatus as claimed in claim 16, wherein the combiner comprises a second gas/liquid separator to receive the first gaseous stream and the second gaseous stream prior to the compressor.

19. Apparatus as claimed in claim 16, wherein the line bypasses the first gas/liquid separator.

20. Apparatus as claimed in claim 16, wherein the inlet of the first gas/liquid separator is in fluid communication with one or more liquid hydrocarbon storage tanks to provide the mixed phase hydrocarbon feed stream.