GB2466231A

GB2466231A - Cooling and storing hydrocarbon gas on a ship

Info

Publication number: GB2466231A
Application number: GB0822851A
Authority: GB
Inventors: Willie Milne Gray; Rene Spaarman
Original assignee: Shell Internationale Research Maatschappij BV
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2008-12-15
Filing date: 2008-12-15
Publication date: 2010-06-16
Anticipated expiration: 2028-12-15
Also published as: WO2010069910A3; GB0822851D0; WO2010069910A2; GB2466231B

Abstract

A system and associated method are presented in which hydrocarbon gas is cooled and stored upon a ship 1. There are various standard gas processing components, and steps, in the cooling process, cooling stages 50, 100, refrigerant streams 40, 45, compressors 200, 250, coolers 300, 350, expansion devices 400, 450, heat exchangers 500, 550, and a plurality of storage tanks 600. The tanks are membrane storage tanks 600 having a storage capacity of greater than 170, 000 m3, preferably greater than or equal to about 180,000 m3. The system may present a ship mounted cooling system as an alternative to a land based cooling system.

Description

METHOD FOR COOT.T! A HYDP.OCAREON STREAM AND A FLOATING

VESSEL THEREFOR

The present invention provides a vessel for cooling a hydrocarbon stream, such as the liquefaction of a natural gas stream, and a method therefor. Furthermore, a method of transferring a cooled hydrocarbon stream from such a vessel is also provided.

The Floating Liquefaction Storage Off-shore (FLSO) concept combines the natural gas liquefaction process, storage tanks, loading systems and other infrastructure into a single floating unit. Such a unit is advantageous because it provides an off-shore alternative to on-shore liquefaction plants. A FLSO vessel can be moored off the coast, or close to or at a gas field, in waters deep enough to allow off-loading of the LNG product onto a carrier vessel. It also represents a movable asset, which can be relocated to a new site when the gas field is nearing the end of its productive life, or when required by economic, environmental or political conditions.

In a first aspect, the present invention provides a floating vessel for the cooling of a hydrocarbon stream, such as natural gas, comprising at least: one or more cooling stages inwhich a hydrocarbon stream passes against one or more refrigerant streams in one or more refrigerant circuits to provide cooled hydrocarbon in one or:more cooled hydrocarbon streams and one or more at least partly evapoui'ated refrigerant streams; each refrigerant circuit comprising one or more compressors, one or more coolers, one or more expansion devices, arid one or more heat exchangers, said heat exchangers providing the one or more cooled hydrocarbon a plurality of storage tanks for the cooled hydrocarbon, said storage tanks comprising at least two membrane storage tanks and having a combined storage capacity of greater than 170, 000m3, preferably greater than or equal to about 180,000 m3.

In a second aspect, the present invention comprises a floating vessel according to the first aspect further comprising: an assembly for unloading cooled hydrocarbon which comprises: a balanced loading and unloading arm which is installed at a first site on the vessel (1) or platform and which includes a compass-style duct system, one end of which is mounted on a base and provided at the other end with a connection system for connecting the duct system (665, 670) to a coupling means that is installed at a second site; said compass-style duct system comprising a cooled hydrocarbon stream transfer,ine, said cooled hydrocarbon stream transfer line being in iuid communication with the one or more storage tanks at one eric and attached, to the connection system at the other nd; a first cable which is joined by one of itsends to means suitable for subjecting this cab1 to a constant tension; and a connection winch on which a connection cable is 3& wound for allowing the connection system to be brought into a position of connection to the coupling means, against the constant tension exerted on the first. cable joined to. the connection system.

In a third aspect, the present invention provides a method of cooling a hydrocarbon stream, such as a natural Q m 4r f1rinrr mr1-rcc F-11-i-1-

-----------------J

steps of: (a) providing one or more hydrocarbon streams and one or more refrigerant streams, wherein the one or more refrigerant streams are in one or more refrigerant circuits, each refrigerant circuit comprising one or more compressors, one or more coolers, one or more expansion devices, and one or more heat exchangers; (b) compressing at least a fraction of the one or more refrigerant streams in the one or more. compressors to provide one or more compressed refrigerant streams; (c) cooling the one or more compressed refrigerant streams in the one or more coolers to provide one or more cooled refrigerant streams; (d) expanding at least a fraction of the one or more cooled refrigerant streams in the one or more expansion devices to provide one or more expanded refrigerant streams; and (e) heat exchanging the one or more expanded refrigerant streams against the one or more hydrocarbon streams in the one or more heat exchangers to provide one or more at -least partly evapourated refrigerant streams and one or more cooled hydrocarbon streams; and (f) passing the one or more cooled hydrocarbon streams downstream to a plurality of storage tanks, said storage tanks comprising at least two membrane storage tanks and having a combined storage capacity of 170,000 m3 or mor, preferably greater than or equal to about 180,000 m3.

In a fourth aspect, the present invention provides a method of transferring a cooled hydrocarbon from a floating vessel according to the second aspect described above to a carrier vessel, comprising at least the steps of: (a) mooring the carrier v1 -in a side-by-side arrangement to the floating vessel; (b) raising the connection system above the coupling means installed on the carrier vessel; (c) unwinding the connection cable from the connection winch; (d) fixing the connection cable to a guidance section of the coupling means; (e) manoeuvring the loading and unloading arm into an intermediate position between the coupling means and the base; (f) placing the first cable under constant tension; (g) actuatiiigthe connection winch to reduce the length of the connection cable which is unwound from the winch thereby engaging the connection system of the assembly with the coupling means on the carrier vessel, while simultaneously maintaining the first cable at a constant tension; (h) connecting the cooled hydrocarbon stream transfer line to a cooled hydrocarbon stream receiving line on the coupling means on the receiving vessel;. sand (i) passing at leasta part of the tooled hythocrbQn. In: the-one or more storage tanksto the cooled hydroca�bon' stream receivin line:of the carrier vessel. : The method of cooling the hydrocarbon stream is carried outori a floating vessel. The floating vessel may be any movable or moored vessel, generally at least having a hull, and usually being in the form of a ship such as a tanker' Such floating vessels can be of any dimensions, but are usually elongate. Whilst the dimensions of a floating vessel are not limited at sea, building and maintenance facilities for floating vessels may limit such fli(fl Tthis; in (flP pmhndimnt rf the present invention, the floating vessel is less than 600 m long s such as 250-350 m, preferably about 300 m, and a beam of less than 100 m, such as 50 m, so as to be able to be accommodated in existing ship-building and maintenance facilities.

The vessel disclosed herein can be a new build or a io conversion from an existing vessel, such as a LNG carrier. In both embodiments, it is preferred to have a maximum separation between the high-pressure process equipment and the areas normally occupied by the crew. A new build is advantageous because it can be provided with -a deck arrangement having a LNGcontainmeflt system in---which it is easier to integrate process equipment, with the hull and accommodation structures being designed from the outset with the required features, such as blast strength, cryogenic protection and fire divisions.

The hydrocarbon stream may be any suitable gas stream to be cooled, preferably liquefied, but is usually a naural gas st.ram obtained from natural gas or petroleum reservoirs. As an alternative the natural gas stream may also be obtained from another -source, also including a synthetic source such as a Fischer-Tropsch process.

Usually a natür.1 gas stream is çorrprised --substantially of methane. Preferably the hydrocarbon feed stream comprises at least 50 molt methane, more preferably at least 80 mol methane.

Depending on the source, hydrocarbon sources such as natural gas may contain varying amounts of hydrocarbons heavier than methane such as in particular ethane, propane and the butanes, and-possibly lesser amounts of

_ -p

pentanes and aromatic hydrocarbons. The composition varies depending upon the type and location of the gas.

ri,F 4 rr 1 1 $-hQ h,1T' r 1h'r thri --_-_J, ---2_-_____**__'*_ are removed as far as efficiently possible prior to any significant cooling of the hydrocarbon stream for several reasons, such as having different freezing or liquefaction temperatures that may cause them to block parts of a methane liquefaction plant.

Hydrocarbon sources such as natural gas may also contain non-hydrocarbons such as H20, N2, C02, Hg, H2S and other sulphur compounds, and the like. If necessary, the hydrocarbon source such as natural gas may be pre-treated before cooling and liquefying. This pre-treatment may comprise reduction and/or removal of undesired components such' as CO2 and H2S. As these steps are well known to the person skilled in the art, their mechanisms are not further discussed here.

The floating vessel described herein does not contain a pre-treatment unit selected from the group comprising: acid gas removal, dehydration, and Natural Gas Liquid extraction. Any such pre-treatment, if necessary, is carried out at a location different from the vessel 1, such as an on-shore location, f or instance a hydrocarbon pre-treatment facility. Such pre-teattrrent units are preferably at least 2 km, more preferably at. least 10 km distant from the vessel.

Thus, the term "hydrocarbon stream" as used herein represents a composition after treatment, such treatment including acid gas removal, dehydration, and Natural Gas Liquid extraction, which does not occur on the vessel 1.

The hydrocarbon stream is thus a composition having been, as necessary, partly, substantially or wholly treated for. the reduction and/or removal of one or more

S -5, .

*. . a' * --. . S.- . ...

compounds or substances, including but not limited to sulphur, sulphur compounds, carbon dioxide, water, Hg, -..-,.. ,-s, ,-v. ,rsv (") *1 -The hydrocarbon stream is cooled in one or more cooling stages in which the hydrocarbon stream is passed against one or more refrigerant streams in one or more refrigerant circuits to provide cooled hydrocarbon in one or more cooled hydrocarbon streams and one or more at least partly evapourated refrigerant streams.

In a preferred embodiment, the hydrocarbon stream can be cooled against a mixed refrigerant in mixed refrigerant circuit. More preferably, the hydrocarbon stream can be cooled against two or more fractions of the mixed refrigerant. The mixed refrigerant circuit can cornpriâe one or more refrigerant compressors to compress---the mixed refrigerant. The refrigerant compressors can be driven by one or more drivers. The drivers may be electrical drivers or gas turbines. Electrical drivers may be supplied with power from at least one, preferably six Dual Fuel Diesel Electric (DFDE) generators, for example 6 x 16 MW DFDE generators. The gas turbines may be at least one, preferably two aero-type gas turbines which directly drive the compressors. In an alternative embodiment, gas turbines can be used. to drive electric power generators, which can then beused to power electrical drivers to drive the refrigerant compressors.

The hydrocarbon stream can be cooled in-one or more first heat exchangers, to provide a first cobled, preferably partially liquefied, hydrocarbon stream, preferably at a temperature below 0 0C.

Preferably, any such first heat exchangers could comprise a first cooling stage, and one or more second heat exchangers used in further cooling, preferably liquefying any fraction of the hydrocarbon stream could comprise one or more second cooling stages. Further coolinq stages can be providedf but are not dii ii this embodiment.

In this way, the method and vessel disclosed herein may involve two or more cooling stages, each stage having one or more steps, parts etc. For example, each cooling stage may comprise one to five heat exchangers. The or a fraction of a hydrocarbon stream and/or the mixed refrigerant may not pass through all, and/or all the same, the heat exchangers of a cooling stage.

In one embodiment, the hydrocarbon cooling, preferably liquefying, method comprises two or three cooling stages. A first cooling stage is preferably intended to reduce the temperature of a hydrocarbon stream to below 0 °C, usually in the range -20 °C to -70 °C to provide a first cooled hydrocarbon stream. Such a first cooling stage is sometimes also termed a pre-cooling' stage.

A second cooling stage is preferably separate from the first cooling stage. That is, the second cooling stage comprises one or more separate heat exchangers.

Such a. second cooling stage is sometimes also termed a main cooling' stage.

A second cooling stage is preferably intended to reduce the temperature of a first cooled hydrocarbon stream, which is usualiyat least a fraction of a hydrocarbon stream cooled by a first cooling stage 50, provide a second cooled hydrocarbon stream, which can be at a temperature below -100°C. Preferably the second cooled hydrocarbon stream is a liquefied hydrocarbon stream, such as a LNG stream. If the second cooled hydrocarbon stream is a LNG stream, it is preferred that

it is "on-specification" i.e. that the LNG has the

desired composition for a particular export market.

Heat exchanaers for ue a the one or more fii-t-or the one or more second heat exchangers are well known in the art. At least one of the second heat exchangers is preferably a spool-wound cryogenic heat exchanger known in the art. Optionally, a heat exchanger could comprise one or more cooling sections within its shell, and each cooling section could be considered as a cooling stage or as a separate heat exchanger' to the other cooling locations.

In yet another embodiment of the present invention, one or more fractions of the mixed refrigerant stream are passed through one or more heat exchangers, preferably two or mote of the first *and second heat exchangers described hereinabove, to provide one or more cooled mixed refrigerant streams.

The mixed ref rigernt of the mixed refrigerant circuit may be formed from a mixture of two or more components selected from the group comprising: nitrogen, methane, ethane, ethylene, propane, propylene, butanes, pentanes, etc. The method disclosed herein may involve the use of one or more other refrigerants, in separate or overlapping refrigerant circuits or other cooling -circuits.

In one embodiment disclosed herein, the method of cooling, preferably liquefying, a hydrocarbon stream comprises one refrigetant circuit comprising one mixed refrigerant.

A mixed refrigerant or a mixed refrigerant stream as referred to herein comprises at least S molt of two different components. A common composition for a mixed refrigerant can be: -10 -Nitrogen 0-10 mol% Methane (Cl) 30-70 mo]c Ethane (C2) 30-70 mol% Propane (C3) 0-30 mol Butanes (C4) 0-15 mol% The total composition comprises 100 mol9&.

In another embodiment, the method is for liquefying natural gas to provide liquefied natural gas.

The cooled, preferably liquefied, hydrocarbon stream provided herein is stored in a plurality of storage tanks, which storage tanks are located on the floating vessel. The plurality of storage tanks comprises at least two membrane storagetanks.

In a preferred embodiment, the vessel has 4 to 6, more preferably 5 storage tanks.

It is further preferred that these storage tanks are arranged sequentially from the bow of the vessel. In a further embodiment, it is preferred that the one or more cooling stages are present in a topside module over the second storage tank arranged sequentially from the bow of the vessel. However,, the one or more cooling stages may be provided in a topside module above one of the other storage tanks.

The membrane storage tanks utilised herein comprise a cryogenic liner which is anchored to the structure of the vessel, and more specifically to the inner hull of a double hulled vessel. Current membrane standards require two barriers able to contain the liquid cargo and prevent the cryogenic liquid reaching the hull structure should a significant leak odcur through the first membrane.

Because hulls tend to be made of ordinary.steel, they -11 -would become brittle in contact with the cryogenic liquid such as LNG. Consequently all vessels with membrane containment systems havo tv:o mombranes, a primary membrane in contact with the cryogenic liquid and a secondary membrane which ensures that the LNG is kept separated from the inner hull.

The containment also presents insulating properties to maintain temperature acceptable for an inner steel hull and to minimise heat transfer to the cryogenic liquid to reduce its evapouration as Boil-off gas. In addition, the insulation should withstand the thermal cycles and resist the loads created by the cryogenic liquid static and dynamic pressure, and transfer it to the inner hull structure.

The triembrane storage tanks used herein can be provided with varying structures, with No 96 membrane storage systems and Mark III storage systems being preferred. A No 96 membrane storage system provides a cryogenic liner made of two identical metallic membranes and two independent insulation layers. The primary and secondary membranes are made of Invar, a 36% nickel-steel alloy, e.g. of 0.7 mm thickness. The primary membrane contains the cooled hydrocarbon, such as LNG. The secondary membrane provides a further protective layer in case of leakage. For instance, 500 mm wide Invar sheets can be continuously spread along the storage tank walls, joined by seam weldirag and evenly supported by the pimary and se&ondary insulation layers. . The primary,d secondary insulaioh layers compiise a load-bearing system made of prefabricated lywood boxes.

filled with expanded perlite. Such boxes may have a size of 1 m x 1.2 rn.. The thickness of the primary insulation layer can be varied from 170 mm to 250 mm depending upon -12 -the requirements of the vessel. The primary insulation layer can be secured by primary couplers, fixed to a seconry coupler assembly The. nriciry insl-ion layer can be laid over, and evenly supported by the inner hull through load-bearing resin ropes to a thickness of about 300 mm. Thus, the total insulation thickness can be in the region of 530 mm. The load-bearing resin ropes are anchored to the inner hull by means of secondary couplers.

A Mark III membrane storage system comprises a primary metallic membrane placed on top of a prefabricated insulation panel. The prefabricated insulation panel includes a complete secondary membrane.

The primary membrane is made of corrugated stainless l5 steel, such as 304 L with athickness of l;2 mm.-The primary membrane contains the cryogenic liquid cargo and is directly supported by and fixed to the insulation panels. The corrugated primary membrane can be supplied in sheets of 3 m x 1 m and joined by TIG (Tungsten Inert Gas)/plasma welding. The secondary membrane provided within the insulation panels is composed of a composite laminate material, such as Triplex which can have a thickness of 0.6 mm. The laminate material comprises a thin sheet of aluminium disposed between to layers of glass cloth and resin. The secondary membrane is placed inside the prefabricated insulation panels between two layers of insulation.

The insulation comprises the prefabficated panels in reinforced polyurethane foam including both the primary and secondary insulation layers and the secondary membrane to provide a load-bearing structure. Similarly to the primary membrane, the insulation can be provided in panels of 3 m x 1 m. The thickness of the insulation -13 -is adjustable from 250 mm to 350 mm, depending upon requirements, with a thickness of 270 mm being usual. The cn h hndd tn l-h inner hull rf I-he vese1 by means of resin ropes which anchor the insulation and evenly spread the loads.

The plurality of storage tanks present in the vessel may also comprise one or more Self-supporting Prismatic-shape IMO type B (SPB) storage tanks. SPB tanks are composed of a stiffened plate structure of aluminium alloy, stainless steel, such as SUS 304, or 9% nickel steel covered with polyurethane foam insulation and supported by supports and chocks made of reinforced plywood. SPB tanks are subdivided by a centreline liquid tight bulkhead and a swash bulkhead to provide a plurality, suchas 4, internal volumes. Stainless steel tanks are advantageous from a construction perspective because it is easier to work with, and particularly weld.

In addition, stainless steel has good chemical stability.

In a preferred embodiment at least one, more preferably a single, SPB storage tank is present in the vessel. The SPB storage tank can be used as a cooled hydrocarbon rundown tank i.e. it can be used as the storage tank into which the cooled hydrocarbon produced by the cooling method on the vessel is initially passed after production. SPB storage tanks are advantageous as rundown tanks because they are inherently resistant to the motion of the cooled hydrocarbon contained therein, known as "sloshing", because their storage volume is subdivided by intena1 bulkheads.

The term "sloshing" refers to the motion of the liquid stored in the tanks caused by movement of the hull of the vessel such as roll, pitch and sway, either in response to wind and/or wave motion, or because of a -14 -change in direction of the vessel. The tank can therefore be loaded with any level of liquid. As the SPB tank rcachcccpaci ty, the contents of the SPB tank can he passed to one of the membrane storage tanks, which can be filled to a level at which sloshing is not a problem, such as low filling levels of between 5and 10% of the tank height and below,, and high filling levels of 80% of the tank height and above.

In a further embodiment, the vessel can be provided with one or more, preferably two, lower-capacity (compared to the other storage tanks) membrane tanks as rundown tanks. The reduced size of such membrane rundown tanks will act to reduce associated sloshing.

The plurality of storage tanks should have a combined storage capacity ofgreater than about 170, 000 m, preferably greater than or equal to 180, 000 m3. Combined storage capacities of 180, 000 m3 and 200, 000 in3 are particularly preferred.

Combined storage capacities of 180, 000 m3 and 200, 000 in3 are advantageous because storage flexibility allowing for delays in off-loading the cooled hydrocarbon product due to weather events. A typical LNG carrier can carry a cargo of 150, 000 m3 LNG. If the vessel disclosed herein manufactures 10, 000 in3 of cooled hydrocarbon for storage per day, then off-loading of 150, 000 m3 of cooled hydrocarbon can be delayed by up to three days due to bad weather for a vessel with a combined storage capacity of 180, 000 m3 and by up to five days for a vessel with a combined storage capacity of 200, 000 m3.

Further, the person skilled in the art will readily understand that after any liquefaction, the liquefied hydrocarbon stream may be further processed, if desired.

As an example, the obtained LNG may be'depressurized by -15 -means of a Joule-Thomson valve or by means of a cryogenic turbo-expander.

The liquefied hydrocarbon stream cn h p.ed through an end gas/liquid separator such as an end-flash vessel to provide an end-flash gas stream overhead and a liquid bottom stream, which can be stored in a plurality of storage tanks as the liquefied product such as LNG, as discussed above.

The end-flash gas can be compressed in an end compressor and provided as fuel gas to units consuming fuel gas on the vessel. For instance, the fuel gas can be used to power Dual Fuel Diesel Electric (DFDE) generators to produce electricity for the vessel or to power gas turbines, such as aero-type turbines.

The vessel and cooling method disclosed -herein can provide a nominal capacity (or name plate) of a liquefied hydrocarbon stream in the range of greater than 1.0 million (metric) tonnes per annum (MTPA), more preferably greater than or equal-to 1.3 MPTA, even more preferably about 2.0 MTPA. The term "nominal capacity" is defined at the daily production capacity of the-vessel multiplied by the number of days per years the vessel is intended to be in operation. For instance, some LNG plants are intended to be operationa3. for an average of 345 days per year.

Preferably the nominal capacity of the hydrocarbon cooling method disclosed herein is in the range of 1 < to �= 2 MTPA.

The cooled hydrocarbon can be unloaded from the floating vessel to a carrier vessel utilising an unloading assembly such as the articulatedarm disclosed in U.S. PatentNo. 1,147,022, which is herein * --incorported by rferènce. Th'e articulated arm is part of a coij.nection system and is equipped with a hydraulic -16 -coupling allowing transfer to be carried out between two vessels moored side-by-side. The connection system can operate between two sites which are moving relfHre to one another, allowing a good connection to be made between two vessels.

it is preferred that the vessel comprise at least two loading arms, more preferably four loading arms. For instance the vessel may comprises two loading arms dedicated to transfer of the cooled hydrocarbon, such as LNG, one dedicated to hydrocarbon vapour transfer, such as LNG vapour and one that can be used for either vapour or liquid.

The assembly for unloading cooled hydrocarbon comprises a balanced loading and unloading arm, a compass-style duct system, a first cable and a connection winch.

The balanced loading and unloading arm is installed at a first site on the vessel, such as in the upper deck area. The arm includes a compass-style duct system, one -end of which is mounted on a base and provided at the other end with a connection system for connecting the duct system to a coupling means.

The coupling means is installed..at a second site to receive the cooled hydrocarbon, such as on the deck of a cooled hydrocarbon carrier vessel. -The compass-styledut system comprises a cooled hydrocarbon stream transfer line. The' àooled hydrocarbon' stream transfer line is in fluid communication with the one: or more of the storage tanks at one end and attached to the connection system at'the other end.

A first cable is joined by one of its ends to a means suitable for subjecting this cable to a constant tension, such' as a constant tensioning device.

A connection winch comprising a connection capable is also provided. The connection cable can be in a wound or unwound state and allows the connection system t he brought into a position to connect to the coupling means.

This operation occurs under the constant tension exerted on the first cable joined to the connection system.

Figure 2 provides a more detailed discussion of the assembly for unloading the cooled hydrocarbon in operation.

io Embodiments of the present invention will now be described by way of example only, and with reference to the accompanying non-limiting drawings in which: Figure 1 is a diagrammatic scheme of a hydrocarbon cooling method showing an embodiment of the present invention; --Figure 2 is a diagrammatic scheme of method of transferring a cooled hydrocarbon from a floating vessel to a carrier vessel according to a further 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.

Referring to the drawings, Figure 1 shows a general scheme for a hydrocarbon cooling, preferably liquefying method, in a floating vessel 1. As discussed above, the hydrocarbon source, which may contain natural gas, can be conventionally pre-treated to reduce and/or remove: much of the heavier hydrocarbn thétefroP. Such pre-treating is carried out at a locaJon separate from the floating vessel 1. . A common form of such separation is termed natural gas liquids' (NGL) extraction, in which proportions of -18 - C2+ hydrocarbons are fractionated to provide a methane-enriched stream which is subsequently cooled, and one or more single or multi-component trn for the C2� components, such as NGL and LPG product streams.

After any pre-treatment and pre-fractionation, processes, steps or stages, are carried out remotely to provide the initial hydrocarbon stream 10 to the vessel.

The operation of the vessel 1 will now be discussed in greater detail. The hydrocarbon stream 10 passes through one or more first heat exchangers 500 which can also define a first cooling stage 50. Preferably, the first cooling stage cools the hydrocarbon feed stream 10 to below 0 °C, such as between -20 °C and -70 °C, preferably either between -20°C and -45°C, or between - 40 °C and -70 °C, "to provide a hydrocarbon stream 20, -which can be a first cooled hydrocarbon stream.

Cooling in the one or more first heat exchangers 500 is provided by a mixed refrigerant to provide an at least partly evapourated refrigerant stream 60 as a first at least partly evapourated refrigerant stream.

The first cooled hydrocarbon stream 20, which may be partially liquefied, is passed to one or more second heat exchangers 550, preferably a main cryogenic heat exchanger. After passag& through the second heat exchanger 550, acoo1ed; preferably liquefied, hydrocarbon tream 30 is provided as a second cooled hydrocarbon stream.

Cooling in the one or moresecbnd heat exchangers 550 is provided by a second refrigerant stream 40'compriSing at least a fraction of the mixed refrigerant of the mixed refrigerant circuit "150. The second refrigerant stream 40 is evaporated through the one or more second heat exchangers 550 to provide a second at least partially -19 -evapourated refrigerant stream 70 in a manner known in the art.

Second cooled hydrocarbon stream 30 is theri passed through an expansion device, such as a valve 800 to provide an expanded partially liquefied hydrocarbon stream 810 which is passed to an end gas/liquid separator 850, which can be an end-flash vessel. The end gas/liquid separator 850 provides an end-flash gas stream 860 overhead and a liquid bottom stream 870. The liquid bottom stream 870 can be passed into a plurality of membrane storage tanks 600a-e.

In a preferred embodiment, the liquid bottom stream 870 is passed to an SPB storage tank to store the liquid hydrocarbon. When the SPB storage tank is nearing capacity, the1iquid hydrocarbon can be transferred to one or more membrane storage tanks. The membrane storage tanks can be filled to less than 10% capacity or greater than 80% capacity to avoid sloshing.

Cooled hydrocarbon stream transfer line 610 is connected at a first end to each of the storage tanks GOOa-e and at a second end to an assembly 650 for unloading cooled hydrocarbon. This assembly 650 will be discussed in greater detail in Figure 2.

End-flash gas stream 860 can be optionally combined with the boil-off gas stream 620 from the storage tanks 600a-e, to provide a combined compressor feed stream 880 prior to passing it to one or more end compressors 900, which are driven by end drivers D3. End compressors 900 provide compressed gas stream 910: A portion of the compressed gas stream 910 can be removed as recycle hydrocarbon stream 920, cooled by recycle cooler 950 to provide a liquefied recycle stream 960 and returned to the storage tanks 600a-600e.

A further portion of the compressed gas stream 910 can be removed as fuel gas stream 930 and passed to a fuel gas stream consumer. such as an on-board 1Prtric generator to generate electrical power. If one or more of the first, second and end drivers Dl, D2 and D3 are electric drivers, then they can be powered by the electricity generated from the fuel gas. Alternatively, if one or more of the first, second and end drivers Dl, D2 and D3 are gas turbines, then they can be powered by the fuel gas.

Turning to mixed refrigerant circuit 150, the second at least partly evapourated refrigerant stream 70 exiting the second heat exchanger 550 is compressed by a second compressor 250 driven by a second driver D2 to provide a second compressed refrigerant stream 210.

The second compressed refrigerant stream 210 can be cooled by a second cooler 300 to provide a second cooled compressed stream 310, and then combined with first at least partly evapourated refrigerant stream 60 from the first heat exchanger 500 to provide a combined compressor stream 240 for first compressor 250. First compressor 250 can be driven by a first electric driver Dl to provide first compressed refrigerant stream 260. First compressed refrigerant stream 260 can be passed through first cooler 350 to provide first cooled refrigerant stream 360.

First cooled refrigerant stream 360 can pass through a first refrigerant gas/liquid separator 375 to provide an overhead gaseous stream 385 nd a liquid bottom stream 380. The overhead gaseous stream 375 is passed through first heat exchanger 500 and cooled to provide second.

refrigerant stream 410. The liquid bottom stream 380 may be cooled by its passage through the first heat exchanger 500 (not shown) to provide a first fraction cooled refrigerant stream 380, which can be expanded through an expansion device, such as valve 450 to produce first fraction 45 of mixed refrigerant and passed intn first heat exchanger 500 where it is at least partially evaporated to provide first at least partially evapourated refrigerant stream 60 in a manner known in the art.

In a further embodiment, exemplified in Figure 2, a schematic representation of a method of transferring a cooled hydrocarbon from a floating vessel 1 to a carrier vessel 2, such as a LNG carrier is provided.

An assembly for unloading cooled hydrocarbon can be provided on the floating vessel 1. The assembly comprises a balanced loading and unloading arm 655, a compass-style duct system 665, 670; a first cable 685 and a connection winch 696.

The balanced loading and unloading arm 655 is installed at a first site 660 on the floating vessel 1, such as in the upper deck area. The arm 655 includes a compass-style duct system 665, 670, one end of which is mounted on a base 675 and provided at the other end with a connection system 680 for connecting the duct system to a coupling means 750. -The coupling means 750 is installed at a second site 760 to receive the cooled hydrocarbon, such as on the deck of a cooled.hydrocarbofl carrier vessel 2.

The compass-style duct system 665, 670 comprises a cooled hydrocarbon stream transfer line 610. The cooled hydrocarbon stream transfer line 610.is.in fluid communication with the one or more of the storage tanks on the floating vessel 1 at one end and attached to the connection system 680 at the other end. a

-22 -A first cable 685 is joined by one of its ends to a means suitable for subjecting this cable to a constant tension, such as a constant teninning device 690.

A connection winch 696 comprising a connection cable 695 is also provided. The connection cable 695 can be in a wound or unwound state and allows the connection system 680 to be brought into a position to connect to the coupling means 750. This operation occurs under the constant tension exerted on the first cable joined to the io connection system.

A carrier vessel 2, such as a LNG carrier, is moored in a side-by-side arrangement to the floating vessel 1 in order to transfer the cooled hydrocarbon.

The connection system 680 is then raised above a coupling means 750 installed on the carrier vessel 2.

This can be carried out by an operator utilising a remote control panel. A reduced pressure can be applied to the means for subjecting the first cable to a constant tension 690, such as a constant tensioning device, to avoid any slackening of the first cable 685 at this point in the off-loading process.

The connection cable 695 can then be unwound from connection winch 696 and brought to the end of a guidance sectiOn 770.of the coupling means 750 on a second site 760 On th carrier vessel 2. This can be achieved using a messenger line,, if necessary.

The loading án unloading arm'655 can then' be manoeuvred intà an.interthediate position between the coupling means 750 a.nd the base 675 of the arm. This represents an intermediate posi-tion between the stored and connected states of the arm 655.

The first cable 685 can then be placed under constant tension via the means for subjecting the first cable to a -23 -constant tension 690, such as a constant tensioning device.

The connection winch 696 can then h actuated to reduce the length of the connection cable 695 which is unwound from the winch thereby engaging the connection system 680 of the assembly 650 with the coupling means 750 on the carrier vessel 2. At the same time, the first cable 685 is maintained at a constant tension.

The cooled hydrocarbon stream transfer line 610 can then be connected to a cooled hydrocarbon stream receiving line 780 on the coupling means 750 on the receiving vessel 2. The connection can be carried out by a hydraulic coupling 697 on arm 655, which can connect to a flange 690 on a manifold connected to the cooled hydrocarbon stream receiving line 780. A hydraulic limiting valve can be used to automatically stop the connection winch 696.

The tension applied to the first cable 685 can be reduced to the minimum necessary to keep the cable taught before the unloading operation is started.

At least a part of the cooled hydrocarbon in the one or more storage tanks can then be passed to the cooled hydrocarbor. stream receiving line 780 of the carrier vessel 2, from where it can be sent to storage tanks 795a-795e.

The person skilled in the.art will readily understand that many modifications may be made withOut, departing from the scope of the invention as defined by the appended claims.