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WO2010069910A2 - Procédé de refroidissement d'un flux d'hydrocarbure et récipient flottant à cet usage - Google Patents

Procédé de refroidissement d'un flux d'hydrocarbure et récipient flottant à cet usage Download PDF

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Publication number
WO2010069910A2
WO2010069910A2 PCT/EP2009/067052 EP2009067052W WO2010069910A2 WO 2010069910 A2 WO2010069910 A2 WO 2010069910A2 EP 2009067052 W EP2009067052 W EP 2009067052W WO 2010069910 A2 WO2010069910 A2 WO 2010069910A2
Authority
WO
WIPO (PCT)
Prior art keywords
vessel
tanks
membrane
cooled
streams
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/EP2009/067052
Other languages
English (en)
Other versions
WO2010069910A3 (fr
Inventor
William Milne Gray
Rene Spaarman
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Shell Internationale Research Maatschappij BV
Original Assignee
Shell Internationale Research Maatschappij BV
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Shell Internationale Research Maatschappij BV filed Critical Shell Internationale Research Maatschappij BV
Priority to GB1109586.6A priority Critical patent/GB2478089B/en
Priority to CN2009801499974A priority patent/CN102388286A/zh
Publication of WO2010069910A2 publication Critical patent/WO2010069910A2/fr
Anticipated expiration legal-status Critical
Publication of WO2010069910A3 publication Critical patent/WO2010069910A3/fr
Ceased legal-status Critical Current

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Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F25J1/0243—Start-up or control of the process; Details of the apparatus used; Details of the refrigerant compression system used
    • F25J1/0279—Compression of refrigerant or internal recycle fluid, e.g. kind of compressor, accumulator, suction drum etc.
    • F25J1/0292—Refrigerant compression by cold or cryogenic suction of the refrigerant gas
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C1/00—Pressure vessels, e.g. gas cylinder, gas tank, replaceable cartridge
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
    • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
    • B63B25/00—Load-accommodating arrangements, e.g. stowing, trimming; Vessels characterised thereby
    • B63B25/02—Load-accommodating arrangements, e.g. stowing, trimming; Vessels characterised thereby for bulk goods
    • B63B25/08—Load-accommodating arrangements, e.g. stowing, trimming; Vessels characterised thereby for bulk goods fluid
    • B63B25/12—Load-accommodating arrangements, e.g. stowing, trimming; Vessels characterised thereby for bulk goods fluid closed
    • B63B25/16—Load-accommodating arrangements, e.g. stowing, trimming; Vessels characterised thereby for bulk goods fluid closed heat-insulated
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B63—SHIPS OR OTHER WATERBORNE VESSELS; RELATED EQUIPMENT
    • B63B—SHIPS OR OTHER WATERBORNE VESSELS; EQUIPMENT FOR SHIPPING 
    • B63B27/00—Arrangement of ship-based loading or unloading equipment for cargo or passengers
    • B63B27/24—Arrangement of ship-based loading or unloading equipment for cargo or passengers of pipe-lines
    • B63B27/25—Arrangement of ship-based loading or unloading equipment for cargo or passengers of pipe-lines for fluidised bulk material
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C1/00—Pressure vessels, e.g. gas cylinder, gas tank, replaceable cartridge
    • F17C1/002—Storage in barges or on ships
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C3/00—Vessels not under pressure
    • F17C3/02—Vessels not under pressure with provision for thermal insulation
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C3/00—Vessels not under pressure
    • F17C3/02—Vessels not under pressure with provision for thermal insulation
    • F17C3/025—Bulk storage in barges or on ships
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C7/00—Methods or apparatus for discharging liquefied, solidified, or compressed gases from pressure vessels, not covered by another subclass
    • F17C7/02—Discharging liquefied gases
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/0002—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the fluid to be liquefied
    • F25J1/0022—Hydrocarbons, e.g. natural gas
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/003—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production
    • F25J1/0047—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production using an "external" refrigerant stream in a closed vapor compression cycle
    • F25J1/0052—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production using an "external" refrigerant stream in a closed vapor compression cycle by vaporising a liquid refrigerant stream
    • F25J1/0055—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production using an "external" refrigerant stream in a closed vapor compression cycle by vaporising a liquid refrigerant stream originating from an incorporated cascade
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F25J1/0211—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process using a multi-component refrigerant [MCR] fluid in a closed vapor compression cycle
    • F25J1/0212—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process using a multi-component refrigerant [MCR] fluid in a closed vapor compression cycle as a single flow MCR cycle
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F25J1/0228—Coupling of the liquefaction unit to other units or processes, so-called integrated processes
    • F25J1/0229—Integration with a unit for using hydrocarbons, e.g. consuming hydrocarbons as feed stock
    • F25J1/023—Integration with a unit for using hydrocarbons, e.g. consuming hydrocarbons as feed stock for the combustion as fuels, i.e. integration with the fuel gas system
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F25J1/0243—Start-up or control of the process; Details of the apparatus used; Details of the refrigerant compression system used
    • F25J1/0257—Construction and layout of liquefaction equipments, e.g. valves, machines
    • F25J1/0275—Construction and layout of liquefaction equipments, e.g. valves, machines adapted for special use of the liquefaction unit, e.g. portable or transportable devices
    • F25J1/0277—Offshore use, e.g. during shipping
    • F25J1/0278—Unit being stationary, e.g. on floating barge or fixed platform
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F25J1/0243—Start-up or control of the process; Details of the apparatus used; Details of the refrigerant compression system used
    • F25J1/0279—Compression of refrigerant or internal recycle fluid, e.g. kind of compressor, accumulator, suction drum etc.
    • F25J1/0281—Compression of refrigerant or internal recycle fluid, e.g. kind of compressor, accumulator, suction drum etc. characterised by the type of prime driver, e.g. hot gas expander
    • F25J1/0283—Gas turbine as the prime mechanical driver
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F25J1/0243—Start-up or control of the process; Details of the apparatus used; Details of the refrigerant compression system used
    • F25J1/0279—Compression of refrigerant or internal recycle fluid, e.g. kind of compressor, accumulator, suction drum etc.
    • F25J1/0281—Compression of refrigerant or internal recycle fluid, e.g. kind of compressor, accumulator, suction drum etc. characterised by the type of prime driver, e.g. hot gas expander
    • F25J1/0284—Electrical motor as the prime mechanical driver
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2210/00—Processes characterised by the type or other details of the feed stream
    • F25J2210/04—Mixing or blending of fluids with the feed stream
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2220/00—Processes or apparatus involving steps for the removal of impurities
    • F25J2220/60—Separating impurities from natural gas, e.g. mercury, cyclic hydrocarbons
    • F25J2220/62—Separating low boiling components, e.g. He, H2, N2, Air
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2230/00—Processes or apparatus involving steps for increasing the pressure of gaseous process streams
    • F25J2230/08—Cold compressor, i.e. suction of the gas at cryogenic temperature and generally without afterstage-cooler
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2230/00—Processes or apparatus involving steps for increasing the pressure of gaseous process streams
    • F25J2230/32—Compression of the product stream
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2230/00—Processes or apparatus involving steps for increasing the pressure of gaseous process streams
    • F25J2230/60—Processes or apparatus involving steps for increasing the pressure of gaseous process streams the fluid being hydrocarbons or a mixture of hydrocarbons
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2245/00—Processes or apparatus involving steps for recycling of process streams
    • F25J2245/02—Recycle of a stream in general, e.g. a by-pass stream
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2245/00—Processes or apparatus involving steps for recycling of process streams
    • F25J2245/90—Processes or apparatus involving steps for recycling of process streams the recycled stream being boil-off gas from storage
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2290/00—Other details not covered by groups F25J2200/00 - F25J2280/00
    • F25J2290/62—Details of storing a fluid in a tank

Definitions

  • 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.
  • WO-2006/078104-A1 discloses an operating system of a liquefied natural gas (LNG) ship for performing sub- cooled liquefaction of boil-off gas.
  • the LNG ship is a tanker for the transport of LNG.
  • the ship comprises a number of storage tanks, which are supplied with LNG which is liquefied at a liquefaction plant.
  • the liquefaction plant may be another vessel, such as the above-mentioned FLSO, or an on-shore liquefaction plant.
  • the operating system of the LNG ship includes re- liquefaction means to re-liquefy boil-off gas of the LNG which is stored in the storage tanks.
  • the re-liquefaciton means are however unsuitable and have insufficient capacity to liquefy a feed stream of natural gas.
  • the storage tanks are relatively small.
  • 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 in which 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 evapourated refrigerant streams; each refrigerant circuit comprising one or more compressors, one or more coolers, one or more expansion devices, and one or more heat exchangers, said heat exchangers providing the one or more cooled hydrocarbon streams; and 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 170,000 m 3 , preferably greater than or equal to about 180,000 m 3 .
  • 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 line, said cooled hydrocarbon stream transfer line being in fluid communication with the one or more storage tanks at one end and attached to the connection system at the other end; a first cable which is joined by one of its ends to means suitable for subjecting this cable to a constant tension; and a connection winch on which a connection cable is 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.
  • the present invention provides a method of cooling a hydrocarbon stream, such as a natural gas stream, in floating vessel comprising at least the steps of:
  • each refrigerant circuit comprising one or more compressors, one or more coolers, one or more expansion devices, and one or more heat exchangers;
  • 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:
  • connection winch (b) raising the connection system above the coupling means installed on the carrier vessel; (c) unwinding the connection cable from the connection winch;
  • connection cable fixing the connection cable to a guidance section of the coupling means
  • connection winch (g) actuating the 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; and (i) passing at least a part of the cooled hydrocarbon in the one or more storage tanks to the cooled hydrocarbon stream receiving line of the carrier vessel.
  • the method of cooling the hydrocarbon stream is carried out on 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 dimensions. Thus, in one embodiment of the present invention, the floating vessel is less than 600 m long 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 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 LNG containment 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 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 process.
  • a natural gas stream is comprised substantially of methane.
  • the hydrocarbon feed stream comprises at least 50 mol% methane, more preferably at least 80 mol% methane.
  • 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 pentanes and aromatic hydrocarbons.
  • the composition varies depending upon the type and location of the gas.
  • the hydrocarbons heavier than methane 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 H2O, N2, CO2, 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, for instance a hydrocarbon pre-treatment facility.
  • a pre-treatment unit selected from the group comprising: acid gas removal, dehydration, and Natural Gas Liquid extraction.
  • Any such pre-treatment is carried out at a location different from the vessel 1, such as an on-shore location, for instance a hydrocarbon pre-treatment facility.
  • Such pre-treatment units are preferably at least 2 km, more preferably at least 10 km distant from the vessel.
  • hydrocarbon stream 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 compounds or substances, including but not limited to sulphur, sulphur compounds, carbon dioxide, water, Hg, and one or more C2+ hydrocarbons.
  • 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.
  • 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 comprise 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 be used 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 cooled, preferably partially liquefied, hydrocarbon stream, preferably at a temperature below 0 0 C.
  • 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 cooling stages can be provided, but are not discussed in this embodiment.
  • 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.
  • 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 0 C, usually in the range -20 0 C to
  • Such a first cooling stage is sometimes also termed a y 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 usually at 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 0 C.
  • 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 exchangers for use as the one or more first 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.
  • 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.
  • one or more fractions of the mixed refrigerant stream are passed through one or more heat exchangers, preferably two or more of the first and second heat exchangers described hereinabove, to provide one or more cooled mixed refrigerant streams.
  • the mixed refrigerant 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 .
  • the method of cooling, preferably liquefying, a hydrocarbon stream comprises one refrigerant circuit comprising one mixed refrigerant.
  • a mixed refrigerant or a mixed refrigerant stream as referred to herein comprises at least 5 mol% of two different components.
  • a common composition for a mixed refrigerant can be:
  • the total composition comprises 100 mol%.
  • 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 storage tanks.
  • the plurality of storage tanks should have a combined storage capacity of greater than about 170,000 m 3 , preferably greater than or equal to 180,000 m 3 . Combined storage capacities of 180,000 m 3 and 200,000 m 3 are particularly preferred.
  • Combined storage capacities of 180,000 m 3 and 200,000 m 3 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 m LNG. If the vessel disclosed herein manufactures 10,000 m 3 of cooled hydrocarbon for storage per day, then off-loading of 150,000 m 3 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 m 3 and by up to five days for a vessel with a combined storage capacity of 200,000 m 3 .
  • the vessel has 4 to 6, more preferably 5 storage tanks.
  • these storage tanks are arranged sequentially from the bow of the vessel.
  • 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.
  • 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 occur through the first membrane.
  • hulls tend to be made of ordinary steel, they would become brittle in contact with the cryogenic liquid such as LNG. Consequently all vessels with membrane containment systems have two membranes, 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 membrane 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 welding and evenly supported by the primary and secondary insulation layers.
  • the primary and secondary insulation layers comprise a load-bearing system made of prefabricated plywood boxes filled with expanded perlite. Such boxes may have a size of 1 m x 1.2 m.
  • the thickness of the primary insulation layer can be varied from 170 mm to 250 mm depending upon the requirements of the vessel.
  • the primary insulation layer can be secured by primary couplers, fixed to a secondary coupler assembly.
  • the secondary insulation 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 steel, such as 304 L with a thickness of 1.2 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 prefabricated panels in reinforced polyurethane foam including both the primary and secondary insulation layers and the secondary membrane to provide a load-bearing structure.
  • the insulation can be provided in panels of 3 m x 1 m.
  • the thickness of the insulation is adjustable from 250 mm to 350 mm, depending upon requirements, with a thickness of 270 mm being usual.
  • the panels can be bonded to the inner hull of the vessel 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, such as 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.
  • 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 internal 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 change in direction of the vessel.
  • the tank can therefore be loaded with any level of liquid.
  • the contents of the SPB tank can be 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 5 and 10% of the tank height and below, and high filling levels of 80% of the tank height and above.
  • the vessel can be provided with one or more, preferably two, lower-capacity (compared to the other storage tanks) membrane tanks as rundown tanks.
  • Rundown herein means that the liquefied natural gas after liquefaction is first supplied to the rundown tanks, and when the rundown tanks are filled to a predetermined level the content thereof is transferred to one of the other storage tanks.
  • the reduced size of such membrane rundown tanks will act to reduce the risk of damaging the tanks due to sloshing.
  • the vessel has a shape that is generally elongated along a longitudinal axis, it is preferred to provide the reduced size of the membrane rundown tanks in a direction perpendicular to the longitudinal axis.
  • the combined storage capacity in the totality of the reduced size tanks is preferably at least equal to N-M % of the storage capacity of one of the other storage tanks, whereby N, in terms of tolerable sloshing risk, is the minimum tolerable high level fill percentage, and the M is the maximum tolerable low level fill percentage.
  • N in terms of tolerable sloshing risk
  • M the maximum tolerable low level fill percentage
  • the storage combined storage capacity in the totality of the reduced size tanks is preferably at least equal to N %, enough to fill an empty full size storage tank to above its minimum tolerable high level, e.g. 80%. It will be understood by the person skilled in the art that such embodiments as described in the preceding paragraph can also be advantageously applied on vessels having a combined storage capacity of 170,000 m 3 or less. 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 means of a Joule-Thomson valve or by means of a cryogenic turbo-expander .
  • the liquefied hydrocarbon stream can be passed 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.
  • 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.
  • 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. .
  • DFDE Dual Fuel Diesel Electric
  • 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.
  • MTPA 1.0 million
  • MPTA metric tonnes per annum
  • nominal capacity is defined at the daily production capacity of the vessel multiplied by - li ⁇ the number of days per years the vessel is intended to be in operation. For instance, some LNG plants are intended to be operational for an average of 345 days per year.
  • 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 articulated arm disclosed in U.S. Patent No. 7,147,022, which is herein incorporated by reference.
  • the articulated arm is part of a connection system and is equipped with a hydraulic 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 relative to one another, allowing a good connection to be made between two vessels.
  • the vessel comprise at least two loading arms, more preferably four loading arms.
  • 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-style duct system comprises a cooled hydrocarbon stream transfer line.
  • the cooled 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.
  • 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 to be 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 .
  • 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
  • Figure 3 shows a schematic top view of a floating vessel showing a plurality of storage tanks according to an embodiment .
  • Figure 1 shows a general scheme for a hydrocarbon cooling, preferably liquefying method, in a floating vessel 1.
  • the hydrocarbon source which may contain natural gas, can be conventionally pre-treated to reduce and/or remove much of the heavier hydrocarbons therefrom. Such pre-treating is carried out at a location separate from the floating vessel 1.
  • NGL natural gas liquids'
  • the hydrocarbon stream 10 passes through one or more first heat exchangers 500 which can also define a first cooling stage 50.
  • the first cooling stage cools the hydrocarbon feed stream 10 to below 0 0 C, such as between -20 0 C and -70 0 C, preferably either between -20 0 C and -45 0 C, or between -40 0 C and -70 0 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 passage through the second heat exchanger 550, a cooled, preferably liquefied, hydrocarbon stream 30 is provided as a second cooled hydrocarbon stream.
  • Cooling in the one or more second 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 evapourated refrigerant stream 70 in a manner known in the art .
  • Second cooled hydrocarbon stream 30 is then 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.
  • the liquid bottom stream 870 is passed to an SPB storage tank to store the liquid hydrocarbon.
  • the liquid 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.
  • the liquid bottom stream 870 may be passed to one or more of a number of smaller membrane tanks 630a, 630b amongst one or more larger membrane storage tanks 600b-600e. Such an arrangement will be further illustrated with reference to Figure 3 below.
  • Cooled hydrocarbon stream transfer line 610 is connected at a first end to each of the storage tanks 600a-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 electric generator to generate electrical power.
  • 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.
  • 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.
  • 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 and 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 into 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 .
  • FIG. 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
  • 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 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 tensioning device 690.
  • 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 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.
  • connection system 680 is then raised above a coupling means 750 installed on the carrier vessel 2.
  • 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.
  • 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 the carrier vessel 2. This can be achieved using a messenger line, if necessary.
  • the loading and unloading arm 655 can then be manoeuvred into an intermediate position between the coupling means 750 and the base 675 of the arm. This represents an intermediate position 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 constant tension 690, such as a constant tensioning device.
  • connection winch 696 can then be 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 hydrocarbon stream receiving line 780 of the carrier vessel 2, from where it can be sent to storage tanks 795a-795e.
  • FIG. 3 is a schematic top view of a floating vessel 1 for the cooling of a hydrocarbon stream with an alternative arrangement based on all membrane tank storage.
  • the vessel 1 has a generally elongate shape, the direction of elongation defining a longitudinal axis A.
  • full size storage tanks here depicted as membrane tanks 600b to 60Oe provided side-by-side along the longitudinal axis A
  • two or more reduced size membrane tanks 630a, 630b have been provided.
  • the reduced size membrane tanks are to be used for rundown purposes as described above.
  • the reduced size tanks 630a, 630b may be provided in a side-by-side arrangement on either side of the longitudinal axis A of the vessel.
  • Such a longitudinally split arrangement provides smaller tanks with reduced width, which when used as rundown tanks is particularly effective at reducing the risk of damage due to sloshing.
  • the two or more reduced sized membrane tanks are to be used for rundown purposes as described above.
  • Such a longitudinally split arrangement provides smaller tanks
  • the rundown tanks 630a, 630b may occupy about the same space as one of the other storage tanks 600b to 60Oe, but that is not always a requirement. They may be occupying more or less space if so desired. For instance, they could be made larger in the longitudinal direction to provide more storage capacity without increasing the width of the tanks.
  • the rundown tanks 630a, 630b could be arranged perpendicular to the axis A, to minimize sloshing in the direction of the axis A. More than two of such smaller tanks may be provided, either side by side or in other arrangements. For instance, to minimize sloshing in all horizontal directions, four or more rundown tanks could be arranged on the same area as a single full size storage tank 600b.
  • the rundown tanks could be substantially square in plan view .
  • the full size storage tanks 600b-600e substantially span the width of the vessel 1.
  • the width of the vessel is for instance in the order of 35-45 m.
  • the rundown tanks 630a, 630b span for instance half of the width of the vessel or less.
  • the length of the rundown tanks may be half the length of the full size storage tanks or less.
  • the height of the rundown tanks may be substantially equal to the height of the full size storage tanks.
  • Membrane storage tanks may span substantially the entire width or breadth of the vessel 1.
  • the top side of the tanks can be flat, providing a convenient flat deck- space on top of the tanks.
  • membrane tanks allow to fully use the available space within the hull of the vessel. This in contrast to spherical tanks.
  • membrane tanks are more cost efficient in comparison to SPB tanks. The enforcement structures inside the SPB tanks to cope with sloshing render SPB tanks relatively expensive.
  • the vessel of the invention may be provided with thrusters to stabilize the vessel during transfer of liquefied hydrocarbons from the rundown tanks to one of the other storage tanks. Stabilizing the vessel during transfer prevents sloshing of the liquefied hydrocarbons in the storage tank, and thus prevents damaging the storage tank.
  • the thrusters enable the transfer of hydrocarbons even during adverse weather conditions and rough sea conditions.
  • the thrusters may include one or more bow or tunnel thrusters. The latter are arranged near the stern 2 of the vessel 1.
  • the thrusters for instance include an impeller arranged in the tunnel that extends through the stern. Each thruster can create thrust in either direction perpendicular to the axis A.
  • the present invention enables to use relatively cheap membrane storage tanks, in combination with one, two or more smaller membrane rundown tanks.
  • any one of the storage tanks 600a to 60Oe could be replaced by two or more smaller membrane tanks such as 630a and 630b in Figure 3.
  • the embodiment of Figure 3 shows the smaller tanks to be located as the first tanks when seen from the bow 2. This has been found advantageous from a structural design point of view, as only one discontinuity needs to be accommodated, between the smaller tanks 630a and 630b — Z O Qo — on one hand and the first membrane storage tank 600b on the other hand. The same advantage is achieved when the smaller tanks are located as the last tanks when seen from the bow 2. Also, the mechanical loading at the bow end is typically lower than in the middle.

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  • Engineering & Computer Science (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Combustion & Propulsion (AREA)
  • Ocean & Marine Engineering (AREA)
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Abstract

La présente invention concerne un récipient flottant (1) et un procédé de refroidissement d'un flux d'hydrocarbure (10), tel qu'un gaz naturel, utilisant un tel récipient. Ledit récipient comprend au moins un ou plusieurs étages de refroidissement (50, 100) dans lesquels un flux d'hydrocarbure (10, 20) passe contre un ou plusieurs flux réfrigérants (40, 45) dans un ou plusieurs circuits réfrigérants (150), afin de fournir l'hydrocarbure refroidi dans un ou plusieurs flux d'hydrocarbure refroidi (20, 30) et un ou plusieurs flux réfrigérants au moins partiellement évaporés (60, 70). Chaque circuit réfrigérant (150) comprend un ou plusieurs compresseurs (200, 250), un ou plusieurs refroidisseurs (300, 350), un ou plusieurs dispositifs d'expansion (400, 450), et un ou plusieurs échangeurs de chaleur (500, 550), lesdits échangeurs de chaleur procurant le ou les flux d'hydrocarbure refroidi (20, 30). Ledit récipient comprend en outre une pluralité de réservoirs de stockage (600) pour l'hydrocarbure refroidi, lesdits réservoirs de stockage comprenant au moins deux réservoirs de stockage membranaires et possédant une capacité de stockage combinée de plus de 170 000 m3, de préférence supérieure ou égale à environ 180 000 m3.
PCT/EP2009/067052 2008-12-15 2009-12-14 Procédé de refroidissement d'un flux d'hydrocarbure et récipient flottant à cet usage Ceased WO2010069910A2 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
GB1109586.6A GB2478089B (en) 2008-12-15 2009-12-14 Method for cooling a hydrocarbon stream and a floating vessel therefor
CN2009801499974A CN102388286A (zh) 2008-12-15 2009-12-14 用于冷却烃流的方法及其浮动船

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
GB0822851A GB2466231B (en) 2008-12-15 2008-12-15 Method for cooling a hydrocarbon stream and a floating vessel therefor
GB0822851.2 2008-12-15
EP09162665.5 2009-06-15
EP09162665 2009-06-15

Publications (2)

Publication Number Publication Date
WO2010069910A2 true WO2010069910A2 (fr) 2010-06-24
WO2010069910A3 WO2010069910A3 (fr) 2013-11-14

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EP2808294A1 (fr) 2013-05-31 2014-12-03 Shell Internationale Research Maatschappij B.V. Ensemble de chargement et coupleur de déconnexion d'urgence permettant d'acheminer un gaz sous pression entre une unité de traitement de gaz flottante et une autre structure
EP2808293A1 (fr) 2013-05-31 2014-12-03 Shell Internationale Research Maatschappij B.V. Ensemble de chargement destiné à transporter un gaz sous pression et unité de traitement de gaz flottante
US9919774B2 (en) 2010-05-20 2018-03-20 Excelerate Energy Limited Partnership Systems and methods for treatment of LNG cargo tanks
US10919756B2 (en) 2013-10-18 2021-02-16 Shell Oil Company Loading assembly for conveying a pressurized gas stream and a switching system for use in a loading assembly
US11959700B2 (en) 2018-06-01 2024-04-16 Steelhead Lng (Aslng) Ltd. Liquefaction apparatus, methods, and systems
JP2024525845A (ja) * 2021-08-09 2024-07-12 ハンファ オーシャン カンパニー リミテッド 船舶の蒸発ガスの再液化システム及び蒸発ガスの再液化方法並びに船舶用再液化装置のオフガス処理システム及びオフガス処理方法

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DE102010062044A1 (de) * 2010-11-26 2012-05-31 Siemens Aktiengesellschaft Flüssigerdgasanlage und Verfahren zum Betrieb

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DE3200958A1 (de) * 1982-01-14 1983-07-21 Linde Ag, 6200 Wiesbaden Verfahren zur gewinnung von erdgas aus maritimen lagerstaetten
FR2813872B1 (fr) * 2000-09-14 2003-01-31 Fmc Europe Ensemble a bras articule de chargement et de dechargement de produits, en particulier de produits fluides
US6889522B2 (en) * 2002-06-06 2005-05-10 Abb Lummus Global, Randall Gas Technologies LNG floating production, storage, and offloading scheme
WO2006052392A2 (fr) * 2004-11-05 2006-05-18 Exxonmobil Upstream Research Company Moyen de transport pour le gaz naturel liquefie et procede de transport d'hydrocarbures
CN101057101A (zh) * 2004-11-08 2007-10-17 国际壳牌研究有限公司 液化天然气的浮动储存再气化单元
US20060156758A1 (en) * 2005-01-18 2006-07-20 Hyung-Su An Operating system of liquefied natural gas ship for sub-cooling and liquefying boil-off gas
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Cited By (11)

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US9919774B2 (en) 2010-05-20 2018-03-20 Excelerate Energy Limited Partnership Systems and methods for treatment of LNG cargo tanks
EP2808294A1 (fr) 2013-05-31 2014-12-03 Shell Internationale Research Maatschappij B.V. Ensemble de chargement et coupleur de déconnexion d'urgence permettant d'acheminer un gaz sous pression entre une unité de traitement de gaz flottante et une autre structure
EP2808293A1 (fr) 2013-05-31 2014-12-03 Shell Internationale Research Maatschappij B.V. Ensemble de chargement destiné à transporter un gaz sous pression et unité de traitement de gaz flottante
US10919756B2 (en) 2013-10-18 2021-02-16 Shell Oil Company Loading assembly for conveying a pressurized gas stream and a switching system for use in a loading assembly
US11959700B2 (en) 2018-06-01 2024-04-16 Steelhead Lng (Aslng) Ltd. Liquefaction apparatus, methods, and systems
US12111103B2 (en) 2018-06-01 2024-10-08 Steelhead Lng (Aslng) Ltd. Methods of manufacturing apparatus and systems for liquefaction of natural gas
US12158301B2 (en) 2018-06-01 2024-12-03 Steelhead Lng (Aslng) Ltd. Apparatus and systems for liquefaction of natural gas
US12158302B2 (en) 2018-06-01 2024-12-03 Steelhead Lng (Aslng) Ltd. Apparatus and systems for liquefaction of natural gas
US12163735B2 (en) 2018-06-01 2024-12-10 Steelhead Lng (Aslng) Ltd. Systems for liquefaction of natural gas
JP2024525845A (ja) * 2021-08-09 2024-07-12 ハンファ オーシャン カンパニー リミテッド 船舶の蒸発ガスの再液化システム及び蒸発ガスの再液化方法並びに船舶用再液化装置のオフガス処理システム及びオフガス処理方法
JP7675923B2 (ja) 2021-08-09 2025-05-13 ハンファ オーシャン カンパニー リミテッド 船舶の蒸発ガスの再液化システム及び蒸発ガスの再液化方法並びに船舶用再液化装置のオフガス処理システム及びオフガス処理方法

Also Published As

Publication number Publication date
GB0822851D0 (en) 2009-01-21
GB2466231A (en) 2010-06-16
GB2466231B (en) 2012-12-12
WO2010069910A3 (fr) 2013-11-14

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