AU2008324194A1

AU2008324194A1 - Method and apparatus for cooling and liquefying a hydrocarbon stream

Info

Publication number: AU2008324194A1
Application number: AU2008324194A
Authority: AU
Inventors: Willem Dam; Thor Frette; Peter Marie Paulus; Johan Jan Barend Pek; David Bertil Runbalk
Original assignee: Shell Internationale Research Maatschappij BV
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2007-11-07
Filing date: 2008-11-05
Publication date: 2009-05-14
Anticipated expiration: 2028-11-05
Also published as: WO2009059985A2; AU2008324194B2; RU2503900C2; GB201005406D0; GB2466891B; GB2466891A; WO2009059985A3; RU2010122953A; KR20100093074A; KR101617177B1; US20100263406A1

Description

WO 2009/059985 PCT/EP2008/064973 METHOD AND APPARATUS FOR COOLING AND LIQUEFYING A HYDROCARBON STREAM The present invention relates to a floating vessel or an off-shore platform comprising an apparatus for cooling and liquefying a hydrocarbon stream, and to a method of cooling and liquefying a hydrocarbon stream performed on 5 a floating vessel or an off-shore platform. A common hydrocarbon stream to be cooled and/or liquefied comprises, or essentially consists of, natural gas. Several methods of liquefying a natural gas stream 10 thereby obtaining liquefied natural gas (LNG) are known. It is desirable to liquefy a natural gas stream for a number of reasons. As an example, natural gas can be stored and transported over long distances more readily as a liquid than in gaseous form because it occupies a 15 smaller volume and does not need to be stored at a high pressure. US 4,041,721 discloses a vessel having natural gas liquefaction capabilities. It is formed of a plurality of self-contained liquefaction assemblies each being 20 disposed in a separate liquefaction compartment. The liquefaction assemblies comprise compressor-driver assemblies wherein a gas turbine is in direct vicinity of the compressor. Thus, the gas turbine forms an ignition source close to a hydrocarbon inventory, such as e.g. the 25 refrigerant. The invention attempts to avoid, or at least reduce the number of, gas turbines in the vicinity of a significant hydrocarbon inventory.

WO 2009/059985 PCT/EP2008/064973 -2 The present invention provides a method of cooling and liquefying a hydrocarbon stream on a floating vessel or an off-shore platform, comprising at least the steps of: 5 (a) passing a hydrocarbon feed stream against two or more refrigerant streams to provide a cooled and liquefied hydrocarbon stream and two or more at least partly evaporated refrigerant streams; (b) compressing at least one of the at least partly 10 evaporated refrigerant streams through at least one or more first refrigerant compressors; (c) compressing at least the one other of the at least partly evaporated refrigerant streams through at least one or more second refrigerant compressors; 15 (d) driving one or more gas turbines to provide: (i) electrical power; and (ii) hot gas; (e) passing the hot gas of step (d) (ii) through one or more steam heat exchangers to provide steam power; 20 (f) using the electrical power to drive at least one of the second refrigerant compressors; and (g) using the steam power to drive one or more steam turbines to drive at least one of the first refrigerant compressors; 25 the method being carried out on a floating vessel or off shore platform comprising one or more storage tanks for liquefied hydrocarbons and/or components for the refrigerants, whereby the one or more gas turbines are driven in a turbine-assembly area being located on or 30 within the floating vessel or off-shore platform and remotely from the first and second refrigerant compressors and from the one or more storage tanks.

WO 2009/059985 PCT/EP2008/064973 -3 The present invention further provides a floating vessel or an off-shore platform comprising apparatus for cooling and liquefying a hydrocarbon stream on or within the floating vessel, the apparatus comprising: 5 two or more cooling stages through which a hydrocarbon feed stream passes against two or more refrigerant streams to provide a cooled and liquefied hydrocarbon stream and two or more at least partly evaporated refrigerant streams; 10 one or more first refrigerant compressors to compress at least one of the at least partly evaporated refrigerant streams; one or more second refrigerant compressors to compress at least one other of the at least partly 15 evaporated refrigerant streams; one or more gas turbines to provide: (i) electrical power to drive at least one of the second refrigerant compressors; and (ii) hot gas; 20 one or more steam heat exchangers to provide steam power from the hot gas; one or more steam turbines driven by the steam power to drive at least one of the first refrigerant compressors; 25 one or more storage tanks for liquefied hydrocarbons and/or components for the refrigerants, whereby the one or more gas turbines are located in a turbine-assembly area which is located remotely from the first and second refrigerant compressors and from the one 30 or more storage tanks. 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: WO 2009/059985 PCT/EP2008/064973 -4 Figure 1 is a first scheme of a hydrocarbon cooling process according to one embodiment of the present invention; Figure 2 is an enhanced scheme of a hydrocarbon 5 cooling process; Figure 3 is a more detailed scheme showing various embodiments of the present invention to fit with Figures 1 and 2; and Figure 4 is a diagrammatic floating vessel showing 10 another 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. 15 Figure 1 shows a general scheme 1 for a hydrocarbon cooling process, generally involving cooling a hydrocarbon stream such as natural gas. The methods and apparatuses disclosed herein involve a method and/or apparatus for driving two or more 20 refrigerant compressors in a hydrocarbon cooling process. In particular, the method comprises at least the steps of: - driving one or more gas turbines to provide: (i) electrical power; 25 (ii) hot gas; - passing the hot gas through one or more steam heat exchangers to provide steam power; - using the electrical power to drive at least one of the refrigerant compressors; and 30 - using the steam power to drive one or more steam turbines to drive at least one other refrigerant compressor of the refrigerant compressors.

WO 2009/059985 PCT/EP2008/064973 -5 These steps can be carried out as part of a method of cooling and liquefying a hydrocarbon stream, either in an on-shore plant or off-shore on a floating vessel or platform. However, when carried out on a floating vessel 5 or off-shore platform comprising one or more storage tanks for liquefied hydrocarbons and/or components for the refrigerants, the method advantageously allows to drive the one or more gas turbines in a turbine-assembly area being located on or within the floating vessel or 10 off-shore platform and remotely from the first and second refrigerant compressors and from the one or more storage tanks. This makes the process remarkably saver, since the gas turbines may now located outside of the direct 15 vicinity of hydrocarbon inventory present in the compressors and storage tanks, such as LNG and refrigerants. An optional advantage of the present invention is that space required for the process can be saved. 20 Moreover, embodiments disclosed herein show an improved method and apparatus for cooling a hydrocarbon stream, such as natural gas, that have greater flexibility of its power requirements. It is remarked that US 6,691,531 B1 discloses a 25 natural gas liquefaction system, which uses single first and second gas turbines (labelled 700 and 702 in its Figure 1), to power first and second propane and ethylene compressors. The hot exhaust gases exiting gas turbines are conducted to an indirect heat exchanger (802) and a 30 water/steam stream flowing in conduit (804) is conducted to first and second steam turbines (704, 706) which power methane compressors. Although this system uses the hot exhaust gases exiting gas turbines, it still has two gas WO 2009/059985 PCT/EP2008/064973 -6 turbines directly adjacent to a number of propane and ethylene compressors, which has an inherent safety risk which the present invention seeks to avoid. Gas turbines are known in the art, and include 5 aeroderivative-type turbines. Such gas turbines typically include an air compression system and are fuelled with light hydrocarbon gases, usually one or more of methane, ethane, propane, etc. Steam heat exchangers, for providing steam power from 10 hot gas created by gas turbines, are also well known in the art. They can recover the heat energy in the hot gas, and include any type or form of steam creator, such as a waste heat recovery unit. The two or more refrigerant streams of step (a) of 15 the method of the present invention may be in separate refrigerant circuits, or may be separate fractions or parts of a single refrigerant circuit such as that shown in WO 96/33379 Al. The first and second refrigerant compressors may be 20 in separate refrigerant circuits, or may be in the same refrigerant circuit such as the single refrigerant circuit mentioned hereinabove. Where the first and second refrigerant compressors are in the same circuit, it may be that two or more of the at least partly evaporated 25 streams pass through one or more of the same refrigerant compressors. The present invention may comprise two or more cooling stages, each stage having one or more steps, parts etc. For example, each cooling stage may comprise 30 one to five heat exchangers, such as two or three heat exchangers. Each heat exchanger may have an associated refrigerant compressor. Optionally, each cooling stage comprises one or more refrigerant stream and one or more WO 2009/059985 PCT/EP2008/064973 -7 refrigerant compressor, optionally as part of the same or as part of separate refrigerant circuits. In one embodiment of the present invention, the hydrocarbon cooling process comprises two or three 5 cooling stages. A first cooling stage is preferably intended to reduce the temperature of a hydrocarbon feed stream to below 0 0 C, usually in the range -20 0 C to -70 0 C. Such a first cooling stage is sometimes also termed a 'pre-cooling' stage. 10 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 using a second refrigerant circulating in a second refrigerant circuit, although the refrigerant of the 15 second refrigerant stream may also pass through one or more heat exchanger of the first cooling stage, preferably all the heat exchangers of the first cooling stage. Such a second cooling stage is sometimes also termed a 'main cooling' stage. 20 Preferably, at least one of the refrigerant compressors of the second stage is a cryogenic refrigerant compressor, which more preferably is driven by the electrical power provided by the gas turbine(s). Preferably, at least one of the refrigerant 25 compressors of the first stage is a pre-cooling refrigerant compressor, which more preferably is driven by the steam turbine(s) (powered by the steam power provided from the hot gas from the gas turbine(s)). If there are two or more first refrigerant compressors, then 30 preferably all of the first refrigerant compressors are pre-cooling refrigerant compressors. Preferably, all the refrigerant compressors of the first stage are pre cooling refrigerant compressors.

WO 2009/059985 PCT/EP2008/064973 -8 Thus, the passing of the hydrocarbon feed stream against two or more refrigerant streams in step (a), to provide a cooled and liquefied hydrocarbon stream and two or more at least partly evaporated refrigerant streams 5 preferably comprises a first cooling stage wherein the hydrocarbon feed stream is pre-cooled against one or more first refrigerant streams to provide a cooled hydrocarbon stream and one or more at least partly evaporated first refrigerant streams which are compressed using the first 10 refrigerant compressor(s) that are driven by the steam turbine(s), and a second cooling stage separate from the first cooling stage, wherein the temperature of the cooled hydrocarbon stream is reduced one or more second refrigerant streams, to provide a liquefied hydrocarbon 15 stream and one ore more at least partly evaporated second refrigerant streams which are compressed by the second refrigerant compressors which are driven by the electrical power. Even when not applied off-shore on a floating vessel 20 or platform, but e.g. in an on-shore plant, this use of electric driven compressors for the second cooling stage and steam driven compressors for the first cooling stage facilitates a more easy and efficient starting up of the process, as compared to a process wherein the second 25 compressors are driven by the steam and the first compressors as driven by the electrical power, because generally the first cooling stage needs to be started up before the second cooling stage and steam is more easily provided using auxiliary steam generating means (e.g. a 30 number of boilers) before the gas turbines have fully started up to produce the electrical power. In one embodiment of the present invention, one or more further providers of steam power or electrical power WO 2009/059985 PCT/EP2008/064973 -9 or both may be provided to provide further driving power to one or more refrigerant compressors, particularly for exceptional or peak demand, or where there is a reduction or shut down of one or more of the gas turbines or steam 5 turbines for maintenance or other purposes. Such additional further providers allow continuous operation of the hydrocarbon cooling process as far as possible. The present invention is particularly suitable where there is limitation of the space available for the 10 hydrocarbon cooling process, either as a stand-alone process, or as part of a larger process or plant such as including one or more pre-treatment processes, post liquefaction processes, and/or storage of a liquefied hydrocarbon stream including the requirement for one or 15 more storage tanks. Thus, the present invention is particularly suitable for location on a floating vessel, an off-shore platform, or a caisson. A floating vessel may be any movable or permanently-moored vessel, generally at least having a 20 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 25 facilities for floating vessels may limit such dimensions. Thus, in one embodiment of the present invention, the floating vessel or off-shore platform is less than 600m long, preferably less than 550m long such as under 500m, and has a beam of less than 100m, 30 typically 85m, so as to be able to be accommodated in existing ship-building and maintenance facilities. An off-shore platform may also be movable, but is generally more-permanently locatable than a floating WO 2009/059985 PCT/EP2008/064973 - 10 vessel. An off-shore platform may also float, and may also have any suitable dimensions. In another embodiment of the present invention, the method of cooling and/or hydrocarbon cooling process is, 5 or is part of, a liquefaction process, providing a liquefied hydrocarbon stream such as liquefied natural gas. Preferably, the liquefied hydrocarbon stream is stored in one or more storage tanks, which storage tanks maybe also located on or within any floating vessel or 10 off-shore platforms. Preferably, the or each gas turbine is located at least 50 m, preferably at least 100 m, from the first and second refrigerant compressors. By locating the gas turbine(s) used in the present invention at least 50m, 15 preferably at least 100m, from the refrigerant compressors, any undesired action or occasion relating to the gas turbine(s) is at least some distance from the refrigerant compressors, and any other relevant part of the process inventory, generally being any unit, 20 equipment, apparatus having a hydrocarbon content, such as an accumulator, vessel, store, etc. In particular, it is desired to maintain a distance between the gas turbine(s) and the refrigerant compressors where they are required to be located closer 25 to each other than is otherwise usual where there is no space limitation, such as on a floating vessel or off shore platform. The safety drivers in the lay-out of floating LNG plants is discussed in a paper of the same name presented in the 2003 AIChE Spring National Meeting: 30 LNG & Gas Transportation Sessions. The present invention preferably provides a nominal capacity (or name plate) of a liquefied hydrocarbon stream in the range of 1 to 10 millions (metric) tonnes WO 2009/059985 PCT/EP2008/064973 - 11 per annum (MTPA). The term "nominal capacity" is defined at the daily production capacity of a plant multiplied by the number of days per years the plant is intended to be in operation. For instance, some LNG plants are intended 5 to be operational for an average of 345 stream days per year. Preferably the nominal capacity of the hydrocarbon cooling process of the present invention is in the range of 3.5 to 7 MTPA. The hydrocarbon feed stream may be any suitable gas 10 stream to be cooled, preferably liquefied, but is usually a natural gas stream 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 15 process. Usually the natural gas stream is comprised substantially of methane. Preferably the hydrocarbon feed stream comprises at least 50 mol% methane, more preferably at least 80 mol% methane. 20 Depending on the source, the natural gas may contain varying amounts of hydrocarbons heavier than methane such as ethane, propane, butanes and pentanes, as well as some aromatic hydrocarbons. The composition varies depending upon the type and location of the gas. Hydrocarbons 25 heavier than methane generally need to be removed from natural gas for several reasons, such as having different freezing or liquefaction temperatures that may cause them to block parts of a methane liquefaction plant. C 2 -4 hydrocarbons can be used as a source of natural gas 30 liquids. The natural gas stream may also contain non hydrocarbons such as H 2 0, N 2 , CO 2 , Hg, H 2 S and other sulphur compounds.

WO 2009/059985 PCT/EP2008/064973 - 12 If desired, the hydrocarbon feed stream containing the natural gas may be pre-treated before use either as part of a hydrocarbon cooling process, or separately. This pre-treatment may comprise reduction and/or removal 5 of non-hydrocarbons such as C02 and H2S or other steps such as early cooling, pre-pressurizing. As these steps are well known to the person skilled in the art, their mechanisms are not further discussed here. Thus, the term "feed stream" also includes a 10 composition prior to any treatment, such treatment including cleaning, dehydration and/or scrubbing, as well as any composition having been partly, substantially or wholly treated for the reduction and/or removal of one or more compounds or substances, including but not limited 15 to sulphur, sulphur compounds, carbon dioxide, water, and

C

2 + hydrocarbons. Preferably, a hydrocarbon feed stream to be used in the present invention undergoes at least the minimum pre treatment required to subsequently liquefy the 20 hydrocarbon stream. Such a requirement for liquefying natural gas is known in the art. Any pre-treatment may be performed near to or next to the method of the present invention, or remotely therefrom. Remotely therefrom includes on-shore/off-shore 25 separation, or two different off-shore locations. Each refrigerant stream used in the present invention may be formed from a single component such as propane or nitrogen, or may be a mixed refrigerant formed from a mixture of two or more components selected from a group 30 comprising: nitrogen, methane, ethane, ethylene, propane, propylene, butanes, pentanes, etc. Different stages, sections or steps of any part of a hydrocarbon cooling process may involve the same or WO 2009/059985 PCT/EP2008/064973 - 13 different types of refrigerant in a manner known to the person skilled in the art, and the present invention is not therefore limited thereby. In one embodiment of the present invention, at least 5 one of the first refrigerant and the second refrigerant is a mixed refrigerant. Preferably both the first and second refrigerants are mixed refrigerants, optionally comprising a different mixture ratio and/or composition. The term "refrigerant compressor" includes any unit, 10 device or apparatus able to increase the pressure of a refrigerant stream. This includes refrigerant compressors having a single compression process or step, or refrigerant compressors having multi-stage compressions or steps, more particularly multi-stage refrigerant 15 compressors within a single casing or shell. Evaporated refrigerant streams to be compressed can be provided to a refrigerant compressor at different pressures. Some stages or steps of a hydrocarbon cooling process may involve two or more refrigerant compressors in parallel 20 series or both. The present invention is not limited by the type or arrangement or layout of the refrigerant compressor or refrigerant compressors, particularly in any refrigerant circuit. It may also be desired to compress the hydrocarbon 25 feed stream either prior to any pre-treatment, or prior to any major cooling stage, or both. Compressors other than refrigerant compressors are commonly used as part of one or more of the pre-treatment processes or steps described above. 30 Thus, the present invention extends to use of the electrical power or the steam power or both powers derived from the one or more gas turbines to drive one or more further compressors, particularly where such other WO 2009/059985 PCT/EP2008/064973 - 14 compressors are part of a hydrocarbon cooling process. The hydrocarbon cooling process may extend to any treatment of a gas stream to be cooled prior to passing the hydrocarbon stream against at least one of the 5 refrigerant streams. This includes reduction and/or removal of non-hydrocarbons as hereinbefore described, in particular including an acid gas removal unit. It also includes the reduction and/or removal of hydrocarbons heavier than methane prior to any major cooling stage or 10 step. In addition, one or more compressors other than refrigerant compressors may also be used in one or more steps using the cooled hydrocarbon stream, such as for the compression of boil-off gas from a storage tank, 15 compression of any end-flash gas from an end-flash vessel, or any other post-cooling compression or re compression of gases such as methane, nitrogen, etc. Thus, one or more of such further compressors may compress any gas or combination of gases not limited to 20 methane-rich gases. Such gases include nitrogen, carbon dioxide, etc. In one embodiment of the present invention, steam power is used for one or more, preferably >50%, optionally all, of such further compressors. In a cooling 25 and/or liquefaction process or plant, such further compressors typically have a variety of compressor sizes and therefore a variety of power-requirements, and steam power has the advantage of being efficient independently of the size or power-requirement of a compressor. 30 Referring to the drawings, Figure 1 shows a hydrocarbon feed stream 10 passing through a first cooling stage 12 using a first refrigerant stream 35 WO 2009/059985 PCT/EP2008/064973 - 15 being cycled in a first refrigerant circuit 35, thereby obtaining a cooled hydrocarbon stream 20. In the scheme shown in Figure 1, the first refrigerant stream 35 may be any suitable component or 5 mixture of components, preferably including two or more of nitrogen, methane, ethane, ethylene, propane, propylene, butane, pentane, etc. The first cooling stage 12 may comprise one or more heat exchangers in parallel, series or both through which 10 the hydrocarbon feed stream 10 passes. Preferably, the first cooling stage 12 cools the feed stream 10, preferably to below 0 0 C, such as between -20 0 C and -70 0 C, more preferably either between -20 0 C and -45 0 C, or between -40 0 C and -70 0 C, generally 15 depending on the type of first cooling stage process. An at least partly, usually fully, evaporated first refrigerant stream 35a passes from the first cooling stage 12 through one or more first refrigerant compressors 34, one or more first ambient coolers 42a 20 such as water and/or air coolers, and one or more first expansion valves 44a in preparation for re-use. The cooled hydrocarbon stream 20 from the first cooling stage 12 is then sent to a second cooling stage 14 using a second refrigerant stream 37, preferably a 25 mixed refrigerant as hereinbefore described, circulating in a second refrigerant circuit 37. There can be various arrangements for the cooled hydrocarbon stream 20 and the second refrigerant circuit 37 in and through the second cooling stage 14. Such 30 arrangements are known in the art. These can involve one or more cooling steps, optionally at different pressure levels, and optionally within one vessel such as a main cryogenic heat exchanger.

WO 2009/059985 PCT/EP2008/064973 - 16 The second cooling stage 14 may reduce the temperature of the cooled hydrocarbon stream 20 to provide a liquefied hydrocarbon stream 30 such as LNG at a temperature of about or lower than -130 0 C. 5 In the simplified form shown in Figure 1, the second refrigerant circuit 37 passes the vapourised second refrigerant exit stream 37a through one or more second refrigerant compressors 36, one or more second ambient coolers 42b such as water and/or air coolers, and one or 10 more second expansion valves 44b in preparation for re use. Optionally, the second refrigerant stream 37 is at least partly cooled by passage through the first cooling stage 12 as shown in Figure 1. Figure 1 shows a method of driving the first and 15 second refrigerant compressors 34, 36. In Figure 1, there are one or more gas turbines 54 located separately from the hydrocarbon cooling process. The one or more gas turbines 54 provide electrical power via a first electrical generator 56 in a manner known in 20 the art. Moreover, hot gas from the one or more gas turbines 54 passes through a flue line 57 to pass through one or more steam heat exchangers 58 to recover the heat therefrom in a manner known in the art. Water is provided through a water line 59 into the steam heat exchanger 58 25 to provide a cold flue gas 61, and a steam stream 72, which has steam power to drive one or more steam turbines in a manner known in the art. In the scheme 1 shown in Figure 1, the electrical power from the first electrical generator 56 passes 30 through a power line 74 to power a first electric motor 76 driving the second refrigerant compressor 36. The steam power of the steam line 72 passes into a first steam turbine 82, which is used to directly drive WO 2009/059985 PCT/EP2008/064973 - 17 the first refrigerant compressor 34. To this end, the steam turbine 82 is mechanically coupled to the refrigerant compressor 34, for instance via shaft 85. An advantage of the present invention is that by 5 driving the first refrigerant compressor(s) using electrical power, and the second refrigerant compressor(s) by steam turbines using steam power from hot gas from the gas turbine(s), there is increased flexibility for the delivery of the power requirements 10 for the refrigerant compressors. Another advantage of the present invention is that by avoiding relying upon using all electrically powered equipment, there is some space-saving that allows a process or a plant using the present invention to be 15 arranged or designed more space-efficiently. Another advantage of the present invention is that it increases safety considerations and reduces risk factors in a process or plant using the present invention in a restricted space or location, such as off-shore. 20 The steam turbine 82 may be of any suitable type. It may for instance be a back pressure steam turbine which generally produces a low pressure steam stream which may be used to satisfy heat requirements elsewhere in or around the process at or around the plant. 25 However, alternatively, a condensing steam turbine may be employed. The heat requirements of the plant may be satisfied at least in part e.g. by employing hot oil instead of low-pressure steam. An advantage of using a condensing steam turbine is that the specific power 30 production in a condensing steam turbine is relatively high. It could typically be twice as high as in a back pressure steam turbine. Thus, less steam is needed to provide the same output of mechanical and/or electrical WO 2009/059985 PCT/EP2008/064973 - 18 power. This is in particular advantageous where desalinated water is scarce, such as for instance in an off-shore and/or floating process plant where steam is generated from sea water that has been processed by a 5 desalination facility. Thus, a condensing steam turbine allows for a smaller desalination facility, thereby saving space and capital expenditure. The need for water to produce steam may also be reduced by recycling at least part of the water produced 10 from the steam and/or the water expelled from the steam turbine 82 after having driven the steam turbine 82. Figure 2 shows an enhanced scheme 2 for a hydrocarbon cooling process, generally involving cooling a hydrocarbon stream such as natural gas. 15 As part of a hydrocarbon cooling process, and prior to any major cooling of the stream to be processed, an initial hydrocarbon stream containing natural gas may be pre-treated to separate out at least some heavier hydrocarbons and non-hydrocarbon impurities such as 20 carbon dioxide, water, mercury, sulfur and sulfur compounds, including but not limited to acid gases. For example, Figure 2 shows an initial hydrocarbon stream 5 such as provided by a pipeline from a well or well-head in a manner known in the art, firstly 25 undergoing an inlet separation in unit 6, optionally followed by compression through a feed compressor 13, then reduction and/or removal of impurities through an acid-gas removal unit (AGRU) 11, to provide a reduced impurity stream 90. Other streams from the AGRU 11, such 30 as CO 2 , could pass along line 115 to be compressed by a secondary compressor 32 to provide for example a compressed CO 2 stream 120.

WO 2009/059985 PCT/EP2008/064973 - 19 The reduced-impurity stream 90 then undergoes NGL extraction through one or more separators, usually one or more NGL fractionators 26, to provide a methane-enriched feed stream 100. The methane-enriched stream 100 may also 5 undergo compression via another compressor 28 if it is desired or necessary to raise the pressure of the hydrocarbon feed stream 10 for the subsequent cooling process. Any residual methane that is recovered from the NGL stream(s) can pass along line 110 and may be 10 compressed by another secondary compressor 33, for re introduction into the main cooling process as part of the feed stream 10. The so-formed hydrocarbon feed stream 10 passes through a first cooling stage 12 using a first 15 refrigerant stream 35 being cycled in a first refrigerant circuit 35 as described hereinabove. Figure 2 shows an example of using two first refrigerant compressors 34a and 34b in the first refrigerant circuit 35. Other components of the first refrigerant circuit 35 are not 20 shown to simplify Figure 2. In one embodiment of the present invention, each heat exchanger of a multi-stage first cooling stage 12 involves a different first refrigerant pressure. The expanded refrigerant from each pressure stage could be 25 compressed in one or more first refrigerant compressors, for example, using different refrigerant compressors for different refrigerant entry pressures. The cooled hydrocarbon stream 20 from the first cooling stage 12 is then sent to a second cooling stage 30 14 using a second refrigerant stream 37, preferably a mixed refrigerant as hereinbefore described, circulating in a second refrigerant circuit 37 as described hereinabove. The second refrigerant circuit 37 passes the WO 2009/059985 PCT/EP2008/064973 - 20 vapourised second refrigerant exit stream 37a through, for example, two second refrigerant compressors 36a and 36b, and the second refrigerant stream 37 is at least partly cooled by the first cooling stage 12. 5 Additional cooling of the hydrocarbon feed stream, cooled and/or liquefied hydrocarbon stream and/or the refrigerant streams could be provided by one or more other refrigerants or refrigerant cycles in addition to cooling by the first and second cooling stages, 10 optionally being connected with another part of the method and/or apparatus for liquefying a hydrocarbon stream as described herein. For example, the liquefied stream 30 could then undergo a third cooling stage 16 (shown in dashed line), 15 preferably sub-cooling, to provide an optionally sub cooled stream 40. Sub-cooling can be provided by passing the liquefied stream 30 through one or more steps using one or more sub-cooling heat exchangers. The or each heat exchanger of the sub-cooling is preferably supplied with 20 cooling by a third refrigerant compressed by another refrigerant compressor 38. Further the person skilled in the art will readily understand that after liquefaction, the liquefied natural gas may be further processed, if desired. As an example, 25 the obtained LNG may be depressurized by means of a Joule-Thomson valve or by means of a cryogenic turbo expander. For example, the scheme 2 of Figure 1 shows the optionally subcooled stream 40 passing into a final 30 gas/liquid separator such as an end-flash vessel 18, to provide an enriched-methane liquid bottom stream 50 which can pass into a storage tank 22, and an overhead gas stream 60. Any boil-off gas 70 from the storage tank 22 WO 2009/059985 PCT/EP2008/064973 - 21 can also be added to the end-flash vessel 18. The overhead gas stream 60 can be compressed by a further compressor 24 to produce a stream 80 for use as a fuel stream, product stream, or elsewhere, in a manner known 5 in the art. The scheme 2 of Figure 2 shows the involvement not only of the first refrigerant compressors 34a and 34b, and the second refrigerant compressors 36a and 36b, but optionally other refrigerant compressors such as the sub 10 cooling refrigerant compressor 38, and optionally other non-refrigerant compressors such as those discussed hereinbefore and labelled 13, 24, 28, 32, 33. The present invention extends to the involvement of any other compressors which may be involved, related or 15 associated with a method of cooling a hydrocarbon stream, a hydrocarbon cooling process, or any related process including pre-treatment and post-liquefaction treatment, not discussed herein. Figure 3 shows more details for a method of driving 20 the refrigerant compressors 34, 36 of the schemes 1, 2 shown in Figures 1 and 2, as well as other embodiments of the present invention. In Figure 3, there are one or more gas turbines 54 located within a turbine-assembly area 52, which is 25 preferably separate from a hydrocarbon cooling process such as those shown in Figures 1 and 2. In the turbine assembly area 52, the one or more gas turbines 54 can be provided with air from an air inlet 53. The air is first compressed, mixed with a fuel such as methane or other 30 light hydrocarbon gases, and then fired. The one or more gas turbines 54 provide electrical power via a first electrical generator 56 in a manner known in the art. Moreover, hot gas from the one or more WO 2009/059985 PCT/EP2008/064973 - 22 gas turbines 54 passes through a flue line 57, (which may optionally be enriched with extra fuel gas by a fuel line 57a) to pass through a steam heat exchanger 58 in a manner known in the art. Water, usually at a high 5 pressure, is provided through a water line 59 into the steam heat exchanger 58 to provide a cold flue gas 61, and a steam stream 72 usually at a high pressure, which has steam power to drive one or more steam turbines in a manner known in the art. 10 In the arrangement shown in Figure 3, the electrical power from the electrical generator 56 passes through a power line 74 to power one or more electrical motors to drive at least one or more refrigerant compressors. For example, Figure 2 shows line 74 extending to a first 15 electric motor 76 driving a second refrigerant compressor 36, such as one or both of the second refrigerant compressors 36a, 36b shown in Figure 1. The electrical power in line 74 could also be used to drive one or more other electric motors 78, or other electrical equipment, 20 to power for example pumps, fans and other electrical services, particularly in a remote or an intended self sufficient location or environment, such as a floating vessel or off-shore platform. The steam power of the steam line 72 passes into at 25 least a first steam turbine 82 which is used to drive at least a first refrigerant compressor 34 such as the two first refrigerant compressors 34a, 34b shown in Figure 2. A fraction of the steam power of the steam line 72 could also be sent to one or more other steam turbines, 30 represented in Figure 3 as a second steam turbine 84, to drive one more other compressors such as one or more of those labelled 13, 24, 28, 32, 33, 38 in Figure 2. A fraction of the steam power of the steam line 72 could WO 2009/059985 PCT/EP2008/064973 - 23 also be sent to one or more further steam turbines, represented by a third steam turbine 86 in Figure 3, to drive, for example a second electrical generator 88 to provide further electrical power which can be fed by a 5 line 89 into the electrical power line 74. The second electrical generator 88 is an example of a further provider of electrical power in the present invention. Figure 3 also shows a separate boiler 62 which could 10 use fuel gas from a fuel line 64 to provide additional steam for additional steam power to be combined with the steam power in line 72. Thus, the present invention provides for the use of one or more further providers of steam power or 15 electrical power or both to assist the one or more gas turbines 54. The use of additional steam power from one or more separate boilers such as boiler 62 in Figure 3 also assists the start up of a hydrocarbon cooling process, 20 where help for pre-cooling, especially the first refrigerant compressors 34a, 34b, is required first. The present invention provides flexibility in the use of both electrical power and steam power in a hydrocarbon cooling process, and optionally other inclusive or 25 separate parts of processing of an initial hydrocarbon stream and/or a liquefied product stream. In this way, the size, design and inter-use of various gas turbines, steam turbines and electrical generators can be used in a most-efficient manner to provide the requirements of the 30 hydrocarbon cooling process and additional processes, steps or stages. The invention in not limited by which source of power drives which refrigerant compressor or compressors.

WO 2009/059985 PCT/EP2008/064973 - 24 Other compressors such as those shown in Figure 2 can be easily powered by balancing the requirements of the usually larger refrigerant compressors with the power output of the one or more gas turbines 54. Usually, it is 5 preferable to use as much as or all of the steam power that is provided from the heat from the one or more gas turbines 54, so as to maximise energy therefrom which would otherwise be wasted. In this way, the present invention is particularly 10 suitable where such flexibility is required in a space limited plant or process, such as that on a floating vessel or off-shore platform. For example, a floating LNG vessel has limited space for a hydrocarbon cooling process, and even more limited space where there is 15 additional processing such as impurity and/or heavy hydrocarbon production and removal stages. It is known in the art that very careful design is required in space limited situations, and the present invention further provides increasing safety by remote location of the one 20 or more gas turbines, with increased flexibility of the use of the power available from the one or more gas turbines. Figure 4 shows an example of a floating vessel 7, on which there is a liquefaction plant 2a, comprising at 25 least a first cooling stage 12 and a second cooling stage 14 as hereinbefore described. One or more gas turbines are located in a turbine-assembly area 52, which is located remotely from the liquefaction process, preferably at least 50 meters or preferably at least 100 30 meters distant. The hydrocarbon feed stream 10 is cooled by the first and second cooling stages 12, 14 to provide (directly or after further processing) a liquefied hydrocarbon stream 50 which passes into a storage tank WO 2009/059985 PCT/EP2008/064973 - 25 22. Other tanks 23 for storage of other components such as propane may also be provided on the floating vessel 7, either as storage of product streams such as LPG, or for storage of components required in a liquefaction process, 5 for example components for the refrigerants in the liquefaction process. It is further desired to have distance between the turbine-assembly area 52 and such one or more storage tanks 22, 23. The arrangement shown in Figure 4 illustrates a 10 further advantage of the present invention. The present invention is able to increase safety requirements and reduce risk factors by separating, preferably as far as possible within the design constraints, power generation for a hydrocarbon cooling process, generally being one or 15 more gas turbines, and the major uses of power, generally being the refrigerant compressors, which are generally located near to or next to their required use, more especially units or hydrocarbons such as propane known to have a higher risk factor than other units or 20 hydrocarbons. This is especially where there is space constraint or limitation such as on an off-shore platform or a floating vessel. US 7,114,351 B2 shows a system for liquefying natural gas using all electrically powered equipment. It states 25 that the system and method are effective to produce sufficient electrical power for operation of the liquefaction process. However, the use of electrical power for all operations of a liquefaction process requires significant 30 numbers of associated transformers, switch gear and other electrical units and apparatus, all of which require significant space. Thus, the system and method of US 7,114,351 are not suitable for space-limited processes WO 2009/059985 PCT/EP2008/064973 - 26 and operations. Moreover, the system of US 7,114,351 is limited to the use of electrically powered equipment only, and is not flexible by the use of other powered equipment. 5 Table 1 gives a relative comparison data of three parameters for three different systems for powering a hydrocarbon cooling process such as that shown in Figure 1 herewith. The data in Table 1 is based on driving the same number, type and arrangement of 10 refrigerant compressors for cooling the same Heating Value for the hydrocarbon feed gas, and for the production of the same amount of LNG by each system. The values are relative to using a "100%" value for the Hybrid system. 15 The "Electric" system is based on using all electrically powered equipment for cooling the feed gas, such as that shown in US 7, 114, 351 B2. The "All steam" system is based on using all steam-powered equipment. The "Hybrid" system is based the present invention involving 20 both electrical power and steam power to drive different refrigerant compressors. Table 1 Electric Fuel Gas % Carbon Equipment Dioxide % Space % Hybrid 100 100 100 Electric 130 91 91 All Steam 60 133 133 Column 1 of Table 1 provides a relative comparison of the space required to locate all the electrical equipment required for the three systems. As expected, the Electric WO 2009/059985 PCT/EP2008/064973 - 27 system requires the greatest space, whilst the All Steam system requires the least, as generators, transformers, etc., are not required. Column 2 provides a relative comparison of the amount 5 of Fuel Gas required to drive the gas turbine(s) to effect the three systems. If it can be seen that the fuel gas required for the Electric system is the lowest, whilst the Fuel Gas required to provide the same amount of LNG using the All Steam system is a third greater than 10 the Hybrid system of the present invention. The third column of Table 1 confirms the amount of carbon dioxide produced by each system in relation to the same amount of LNG produced. Thus, the Electric system produces the least amount of carbon dioxide, whilst the 15 All Steam system produces the most. The data in Table 1 illustrates that the present invention provides a suitable balance between the space requirement, the fuel gas requirement and carbon dioxide produced. These factors can be used to consider the 20 balance between the CAPEX and/or OPEX for a hydrocarbon cooling process, in particular a natural gas liquefaction plant, and the efficiency of such a process and/or plant, especially in or on a space-restricted location. The person skilled in the art will understand that 25 the present invention can be carried out in many various ways without departing from the scope of the appended claims.

Claims

1. A method of cooling and liquefying a hydrocarbon stream on a floating vessel or an off-shore platform, comprising at least the steps of: (a) passing a hydrocarbon feed stream against two or more 5 refrigerant streams to provide a cooled liquefied hydrocarbon stream and two or more at least partly evaporated refrigerant streams; (b) compressing at least one of the at least partly evaporated refrigerant streams through at least one or 10 more first refrigerant compressors; (c) compressing at least the one other of the at least partly evaporated refrigerant streams through at least one or more second refrigerant compressors; (d) driving one or more gas turbines to provide: 15 (i) electrical power; and (ii) hot gas; (e) passing the hot gas of step (d) (ii) through one or more steam heat exchangers to provide steam power; (f) using the electrical power to drive at least one of 20 the second refrigerant compressors; and (g) using the steam power to drive one or more steam turbines to drive at least one of the first refrigerant compressors; the method being carried out on a floating vessel or off 25 shore platform comprising one or more storage tanks for liquefied hydrocarbons and/or components for the refrigerants, whereby the one or more gas turbines are driven in a turbine-assembly area being located on or within the floating vessel or off-shore platform and WO 2009/059985 PCT/EP2008/064973 - 29 remotely from the first and second refrigerant compressors and from the one or more storage tanks.

2. Method as claimed in Claim 1, wherein at least one of the second refrigerant compressors is a cryogenic 5 refrigerant compressor.

3. Method as claimed in one or more of the preceding claims, wherein at least one of the first refrigerant compressors is a pre-cooling refrigerant compressor.

4. Method as claimed in one or more of the preceding 10 claims, wherein the method further comprises one or more further treatment steps of either the hydrocarbon feed stream prior to step (a) or of the cooled hydrocarbon stream of step (a), or both, such further treatment steps involving one or more further compressors, and wherein 15 the electrical power or the steam power or both the electrical power and the steam power drive at least one of the further compressors.

5. Method as claimed in claim 4, wherein at least one of the further compressors is for compressing one or more 20 streams other than the at least partly evaporated refrigerant streams of step (b) and step (c).

6. Method as claimed in one or more of the preceding claims, further comprising one or more further providers of steam power or electrical power. 25

7. Method as claimed in one or more of the preceding claims, wherein remotely means at least 50 meters, or preferably at least 100 meters, distant.

8. Method as claimed in one or more of the preceding claims, wherein the liquefied hydrocarbon stream has 30 nominal capacity in the range 1 to 10 MTPA, preferably in the range 3.5 to 7 MTPA.

9. Method as claimed in one or more of the preceding claims, involving at least a first cooling stage and a WO 2009/059985 PCT/EP2008/064973 - 30 second cooling stage, and wherein the refrigerant streams for the first and second cooling stages are mixed refrigerants.

10. Method as claimed in one or more of the preceding 5 claims, wherein at least one of the one or more steam turbines is a condensing steam turbine.

11. Method as claimed in one or more of the preceding claims, wherein the floating vessel or off-shore platform is less than 600m long and less than 100m wide. 10

12. Method as claimed in one or more of the preceding claims, wherein step (a) comprises a first cooling stage wherein the hydrocarbon feed stream is pre-cooled against one or more first refrigerant streams to provide a cooled hydrocarbon stream and one or more at least partly 15 evaporated first refrigerant streams which are compressed in step (b) and a second cooling stage separate from the first cooling stage, wherein the temperature of the cooled hydrocarbon stream is reduced one or more second refrigerant streams, to provide a liquefied hydrocarbon 20 stream and one ore more at least partly evaporated second refrigerant streams which are compressed in step (c).

13. Method as claimed in one or more of the preceding claims, wherein the hydrocarbon stream comprises, or essentially consists of, natural gas. 25

14. A floating vessel or an off-shore platform comprising apparatus for cooling and liquefying a hydrocarbon stream on or within the floating vessel, the apparatus comprising: two or more cooling stages through which a 30 hydrocarbon feed stream passes against two or more refrigerant streams to provide a cooled and liquefied hydrocarbon stream and two or more at least partly evaporated refrigerant streams; WO 2009/059985 PCT/EP2008/064973 - 31 one or more first refrigerant compressors to compress at least one of the at least partly evaporated refrigerant streams; one or more second refrigerant compressors to 5 compress at least one other of the at least partly evaporated refrigerant streams; one or more gas turbines to provide: (i) electrical power to drive at least one of the second refrigerant compressors; and 10 (ii) hot gas; one or more steam heat exchangers to provide steam power from the hot gas; one or more steam turbines driven by the steam power to drive at least one of the first refrigerant 15 compressors one or more storage tanks for liquefied hydrocarbons and/or components for the refrigerants, whereby the one or more gas turbines are located in a turbine-assembly area which is located remotely from the 20 first and second refrigerant compressors and from the one or more storage tanks.

15. Floating vessel or off-shore platform as claimed in claim 14, wherein remotely means at least 50 meters, preferably at least 100 meters, distant.