CN113260811B - Gas treatment system equipped with a receiving terminal of a regasification unit and corresponding gas treatment method - Google Patents

Gas treatment system equipped with a receiving terminal of a regasification unit and corresponding gas treatment method Download PDF

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Publication number
CN113260811B
CN113260811B CN201980087368.7A CN201980087368A CN113260811B CN 113260811 B CN113260811 B CN 113260811B CN 201980087368 A CN201980087368 A CN 201980087368A CN 113260811 B CN113260811 B CN 113260811B
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gas
circuit
tank
circulating
line
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CN201980087368.7A
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CN113260811A (en
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B.奥恩
R.纳姆
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Gaztransport et Technigaz SA
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Gaztransport et Technigaz SA
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    • 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
    • F17C9/00—Methods or apparatus for discharging liquefied or solidified gases from vessels not under pressure
    • F17C9/02—Methods or apparatus for discharging liquefied or solidified gases from vessels not under pressure with change of state, e.g. vaporisation
    • 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
    • F25J1/0025—Boil-off gases "BOG" from storages
    • 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
    • F25J1/0032—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 the feed stream itself or separated fractions from it, i.e. "internal refrigeration"
    • F25J1/0045—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 the feed stream itself or separated fractions from it, i.e. "internal refrigeration" by vaporising a liquid return 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
    • 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
    • F25J1/0201—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 only internal refrigeration means, i.e. without external refrigeration
    • 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
    • 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
    • F17C2201/00—Vessel construction, in particular geometry, arrangement or size
    • F17C2201/05—Size
    • F17C2201/052—Size large (>1000 m3)
    • 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
    • F17C2221/00—Handled fluid, in particular type of fluid
    • F17C2221/03—Mixtures
    • F17C2221/032—Hydrocarbons
    • F17C2221/033—Methane, e.g. natural gas, CNG, LNG, GNL, GNC, PLNG
    • 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
    • F17C2223/00—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel
    • F17C2223/01—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel characterised by the phase
    • F17C2223/0146—Two-phase
    • F17C2223/0153—Liquefied gas, e.g. LPG, GPL
    • F17C2223/0161—Liquefied gas, e.g. LPG, GPL cryogenic, e.g. LNG, GNL, PLNG
    • 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
    • F17C2223/00—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel
    • F17C2223/03—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel characterised by the pressure level
    • F17C2223/033—Small pressure, e.g. for liquefied 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
    • F17C2223/00—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel
    • F17C2223/04—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel characterised by other properties of handled fluid before transfer
    • F17C2223/042—Localisation of the removal point
    • F17C2223/043—Localisation of the removal point in the 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
    • F17C2223/00—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel
    • F17C2223/04—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel characterised by other properties of handled fluid before transfer
    • F17C2223/042—Localisation of the removal point
    • F17C2223/046—Localisation of the removal point in the liquid
    • F17C2223/047—Localisation of the removal point in the liquid with a dip tube
    • 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
    • F17C2225/00—Handled fluid after transfer, i.e. state of fluid after transfer from the vessel
    • F17C2225/01—Handled fluid after transfer, i.e. state of fluid after transfer from the vessel characterised by the phase
    • F17C2225/0107—Single phase
    • F17C2225/0123—Single phase gaseous, e.g. CNG, GNC
    • 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
    • F17C2225/00—Handled fluid after transfer, i.e. state of fluid after transfer from the vessel
    • F17C2225/03—Handled fluid after transfer, i.e. state of fluid after transfer from the vessel characterised by the pressure level
    • F17C2225/035—High pressure, i.e. between 10 and 80 bars
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
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    • 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
    • F17C2225/00—Handled fluid after transfer, i.e. state of fluid after transfer from the vessel
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    • F17C2225/042—Localisation of the filling point
    • F17C2225/043—Localisation of the filling point in the gas
    • F17C2225/044—Localisation of the filling point in the gas at several points, e.g. with a device for recondensing gas
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    • 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
    • F17C2225/00—Handled fluid after transfer, i.e. state of fluid after transfer from the vessel
    • F17C2225/04—Handled fluid after transfer, i.e. state of fluid after transfer from the vessel characterised by other properties of handled fluid after transfer
    • F17C2225/042—Localisation of the filling point
    • F17C2225/046—Localisation of the filling point in the liquid
    • F17C2225/047—Localisation of the filling point in the liquid with a dip tube
    • 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
    • F17C2227/00—Transfer of fluids, i.e. method or means for transferring the fluid; Heat exchange with the fluid
    • F17C2227/01—Propulsion of the fluid
    • F17C2227/0128—Propulsion of the fluid with pumps or compressors
    • F17C2227/0135—Pumps
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    • F17C2227/00—Transfer of fluids, i.e. method or means for transferring the fluid; Heat exchange with the fluid
    • F17C2227/01—Propulsion of the fluid
    • F17C2227/0128—Propulsion of the fluid with pumps or compressors
    • F17C2227/0171—Arrangement
    • F17C2227/0178—Arrangement in the vessel
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    • F17C2227/00—Transfer of fluids, i.e. method or means for transferring the fluid; Heat exchange with the fluid
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    • F17C2227/0302—Heat exchange with the fluid by heating
    • F17C2227/0306—Heat exchange with the fluid by heating using the same fluid
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    • 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
    • F17C2227/00—Transfer of fluids, i.e. method or means for transferring the fluid; Heat exchange with the fluid
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    • F17C2227/0311—Air heating
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    • F17C2227/00—Transfer of fluids, i.e. method or means for transferring the fluid; Heat exchange with the fluid
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    • F17C2227/00—Transfer of fluids, i.e. method or means for transferring the fluid; Heat exchange with the fluid
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    • F17C2227/036—"Joule-Thompson" effect
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    • F17C2250/0626—Pressure
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
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    • F17C2250/0631—Temperature
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    • F17C2260/00—Purposes of gas storage and gas handling
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    • F17C2265/00—Effects achieved by gas storage or gas handling
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    • 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
    • F17C2265/00—Effects achieved by gas storage or gas handling
    • F17C2265/03—Treating the boil-off
    • F17C2265/032—Treating the boil-off by recovery
    • F17C2265/033—Treating the boil-off by recovery with cooling
    • F17C2265/034—Treating the boil-off by recovery with cooling with condensing the gas phase
    • 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
    • F17C2265/00—Effects achieved by gas storage or gas handling
    • F17C2265/03—Treating the boil-off
    • F17C2265/032—Treating the boil-off by recovery
    • F17C2265/036—Treating the boil-off by recovery with heating
    • 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
    • F17C2265/00—Effects achieved by gas storage or gas handling
    • F17C2265/03—Treating the boil-off
    • F17C2265/032—Treating the boil-off by recovery
    • F17C2265/037—Treating the boil-off by recovery with pressurising
    • 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
    • F17C2265/00—Effects achieved by gas storage or gas handling
    • F17C2265/03—Treating the boil-off
    • F17C2265/032—Treating the boil-off by recovery
    • F17C2265/038—Treating the boil-off by recovery with expanding
    • 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
    • F17C2265/00—Effects achieved by gas storage or gas handling
    • F17C2265/05—Regasification
    • 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
    • F17C2265/00—Effects achieved by gas storage or gas handling
    • F17C2265/06—Fluid distribution
    • F17C2265/066—Fluid distribution for feeding engines for propulsion
    • 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
    • F17C2265/00—Effects achieved by gas storage or gas handling
    • F17C2265/07—Generating electrical power as side effect
    • 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
    • F17C2270/00—Applications
    • F17C2270/01—Applications for fluid transport or storage
    • F17C2270/0102—Applications for fluid transport or storage on or in the water
    • F17C2270/0105—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
    • F17C2270/00—Applications
    • F17C2270/01—Applications for fluid transport or storage
    • F17C2270/0102—Applications for fluid transport or storage on or in the water
    • F17C2270/011—Barges
    • F17C2270/0113—Barges floating
    • 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
    • F17C2270/00—Applications
    • F17C2270/01—Applications for fluid transport or storage
    • F17C2270/0102—Applications for fluid transport or storage on or in the water
    • F17C2270/0118—Offshore
    • F17C2270/0123—Terminals
    • 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
    • F17C2270/00—Applications
    • F17C2270/01—Applications for fluid transport or storage
    • F17C2270/0134—Applications for fluid transport or storage placed above the ground
    • F17C2270/0136—Terminals
    • 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
    • F25J2205/00—Processes or apparatus using other separation and/or other processing means
    • F25J2205/90—Mixing of components
    • 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
    • F25J2230/24—Multiple compressors or compressor stages in parallel
    • 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
    • F25J2230/30—Compression of 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
    • F25J2235/00—Processes or apparatus involving steps for increasing the pressure or for conveying of liquid process streams
    • F25J2235/60—Processes or apparatus involving steps for increasing the pressure or for conveying of liquid process streams the fluid being (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
    • F25J2290/00—Other details not covered by groups F25J2200/00 - F25J2280/00
    • F25J2290/34—Details about subcooling of liquids

Landscapes

  • Engineering & Computer Science (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Ocean & Marine Engineering (AREA)
  • Combustion & Propulsion (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Filling Or Discharging Of Gas Storage Vessels (AREA)

Abstract

The invention relates to a gas processing system (1) for a gas receiving terminal, the system comprising: -at least one tank (2) for storing boil-off gas and liquefied gas, at least one compressor (21, 23), a first circuit (17) for supplying boil-off gas to the compressor (21), the first circuit (17) being connected to a line (18) connected to a boil-off gas outlet (20) from the tank (2), and-a regasification unit (4) comprising an inlet connected to a line (11) for supplying liquefied gas from the tank (2). According to the invention, a gas treatment system comprises: -a second circuit (22) comprising a gas inlet connected to a line (13) connected to a liquefied gas outlet of a tank (2) and a gas outlet connected to a compressor (21,23), said compressor (21,23) comprising an outlet connected to a regasification unit (4), and a third circuit (25) comprising a gas inlet connected to a line (26) connected to a liquefied gas outlet of said tank (2) and a liquefied gas outlet connected to a line (27) for re-injecting subcooled liquefied gas into the bottom of said tank to form a subcooled gas layer, said second circuit (22) being designed for subcooling a gas circulating in said third circuit (25) by heat exchange, said third circuit (25) being designed for heating at least the gas circulating in said second circuit (22) by heat exchange.

Description

Gas treatment system equipped with a receiving terminal of a regasification unit and corresponding gas treatment method
Technical Field
The present invention relates to a gas processing system equipped with a receiving terminal of a regasification unit. The receiving terminal may be a ship, such as a liquefied gas carrier, or installed on land to store liquefied gas.
Background
The prior art includes the documents FR-A1-3066248, FR-A2-3066249 and WO-A1-2018/206510.
It is known to transport several liquefied forms of gas on board a vessel, such as an LNG carrier, to facilitate their transport over long distances. Examples of liquefied gases are Liquefied Natural Gas (LNG) or Liquefied Petroleum Gas (LPG). The gases are cooled to very low temperatures, even cryogenic, e.g., -160 ℃ at atmospheric pressure for LNG, so they are liquid at near atmospheric pressure and are easily loaded onto dedicated vessels. Liquefied natural gas and liquefied petroleum gas are used in various industries as cleaner and more economical fuels for various facilities.
Liquefied natural gas can be used for the energy requirements of the operation of LNG carriers (propulsion of ships and/or power production of equipment onboard ships), particularly those that transport liquefied petroleum gas and/or liquefied natural gas to meet new environmental regulations. These on-board plants usually comprise a heat engine consuming gas from a vaporizer supplied by the liquefied gas cargo transported in the tanks of the LNG carrier. Once the liquefied gases are transported to the desired destination, they are typically stored in land-based or floating receiving terminals so that they can be sold and/or supplied to other equipment, such as public gas distribution networks.
Land-based or floating receiving terminals may be equipped with regas units. The latter is used to heat the liquefied gas to vaporize it for conversion back to gas (regasification or gasification) before being dispensed as fuel. Its temperature varied from-160 ℃ to 0 ℃ under high pressure. A floating receiving terminal is a vessel provided close to shore or in deep water, equipped with such a unit, and denoted floating storage and regasification unit by the acronym "FSRU".
Because of the large variation in demand for fuel gas, regasification is also randomly operated. This means that if the regas unit is stopped more frequently than it is in operation, gas vapour generated from the evaporation of the liquefied gas (referred to as "BOG" or "NBOG" (natural boil off gas) ") will continue to form in the upper part of the tank. This increase in boil-off gas results in an increase in pressure in the tank. To reduce the pressure, NBOG is extracted from the tank, burned in a combustion unit or discharged to ambient air, which means a loss of part of the cargo. Furthermore, it is well known that NBOG is also formed during loading of the tanks of the gas processing system (transfer of LNG from the LNG carrier to a floating or land-based receiving terminal). In practice, each tank contains a large amount of BOG from tank cooling (which must be sealed and insulated) and NBOG from the LNG heated in the tank. The vapor produced by the cooling is not re-condensed by the LNG loaded into the tank. To compensate for the formation of NBOG, the loading speed of the tank is reduced, which lengthens the loading time, which can double and exceed ten hours, thus resulting in the immobilization of the LNG carrier.
Disclosure of Invention
The present invention proposes to provide a simple, effective and economical solution that enables the management of the natural or forced vaporisation of the gas in the tank, in particular during the shut-down of the regasification unit and the production of fuel gas.
According to a first aspect, the present invention provides a gas processing system for a gas receiving terminal, the system comprising:
at least one tank for storing boil-off gas and liquefied gas,
-at least one compressor for compressing the refrigerant,
-a first circuit for supplying the compressor with boil-off gas, the first circuit being connected to a line connected to the outlet of the boil-off gas from the tank, and
a regasification unit comprising an inlet connected to a line for liquefied gas to be supplied from a tank,
it is characterized in that it comprises:
-a second circuit comprising a gas inlet connected to a line connected to the liquefied gas outlet of the tank and a gas outlet connected to a compressor comprising an outlet connected to a regasification unit, and
a third circuit comprising a gas inlet connected to a line connected to the liquefied gas outlet of the tank and a liquefied gas outlet connected to a line for reinjecting the subcooled liquefied gas into the bottom of the tank to form a layer of subcooled gas,
the second circuit is designed for supercooling the gas circulating in the third circuit by heat exchange, the third circuit being designed for heating at least the gas circulating in the second circuit by heat exchange.
The invention thus makes it possible to manage the production of natural boil-off gas and combustible gas in all cases without cargo loss. In particular, when the regasification unit is in operation and the amount of natural boil-off gas required to supply other equipment is low, the system makes it possible to transfer boil-off gas to the regasification unit for use in producing combustible gas. Also, when there is no need to produce fuel gas by the regas unit (production stops), the pressure within the tank is managed by venting boil-off gas, which will be recondensed by the LNG in the tank. Such a facility also enables faster filling of tanks at onshore or floating receiving terminals, as NBOG to be generated during filling can be easily recondensed by LNG stored in the tank.
The device according to the invention may comprise one or more of the following features taken separately from each other or in combination with each other:
the regas unit includes an outlet connected to the tank by a line,
the regasification unit includes a recondenser, which is connected on the one hand to the outlet of the compressor and on the other hand to the tank via a line, in order to return liquefied gas to the tank,
the regasification unit includes at least one pump and at least one heat exchanger, the pump being mounted between the recondenser and the heat exchanger,
the outlet of the second circuit is connected to a compression device arranged upstream of the compressor,
the gas treatment system comprising a fourth circuit comprising an inlet and an outlet, the inlet being connected to a line in which boil-off gas is circulated and the line being connected to the outlet of the compressor, the outlet of the fourth circuit being connected to a line connected to a regasification unit,
the second circuit is configured to cool gas circulating in the fourth circuit,
the system comprises a first heat exchanger comprising a first portion of the second circuit and a third circuit, the first heat exchanger being configured to allow, respectively, an supercooling of the gas circulating in the third circuit and at least one heating of the gas circulating in the first portion of the second circuit,
the system comprising a second heat exchanger comprising a second portion of the second circuit and the first circuit, the second heat exchanger being configured to allow evaporation of the gas circulating in the second portion of the second circuit and cooling of the gas circulating in the first circuit,
the first and second portions of the second conduit are connected by a first intermediate conduit,
the second heat exchanger further includes a first portion of a fourth circuit, a second portion of the second circuit configured to cool gas circulating in the first portion of the fourth circuit,
the system includes a third heat exchanger including a fifth circuit and a second portion of the fourth circuit, the third heat exchanger configured to heat the gas circulating in the fifth circuit and re-liquefy the boil-off gas circulating in the second portion of the fourth circuit,
the first and second portions of the fourth circuit are connected by a second intermediate conduit,
the fifth circuit comprising an inlet connected to a line connected to the tank in which the liquefied gas circulates and an outlet connected to the regasification unit, the fifth circuit being configured to reliquefy the boil-off gas circulating in the fourth circuit,
the system includes a single heat exchanger including at least a first circuit, a second circuit, and a third circuit,
the system comprises a pressure reduction device fitted on the line delivering liquefied gas for supplying the compressor,
the system includes a pressure reduction device fitted on a line that delivers liquefied gas to a regasification unit,
the system includes a heat exchanger that incorporates the function of a heat exchanger, the heat exchanger including a first exchange circuit and a second exchange circuit configured to perform:
subcooling of the gas extracted from the tank and circulating in the circuit and at least one heating of the gas extracted from the tank and circulating in the circuit, or
The vaporization of the gas extracted from the tank and circulating in the circuit and the reliquefaction of the vaporized gas circulating in the circuit,
the compression apparatus comprises two compressors mounted in series,
the compression ratio of each compressor mounted in series is about 2.
The invention also relates to a gas receiving terminal comprising a gas treatment system according to one of the aforementioned features.
Advantageously, but not limited to, the receiving terminal is a floating receiving terminal (e.g., a liquefied gas transport vessel (FSRU)) or a land-based receiving terminal.
The invention also relates to a method of treating a gas with a gas treatment system having any of the above features, the method comprising the steps of:
a first part of the gas, which is vaporised, is extracted from a tank adapted to store both boil-off gas and liquefied gas, for transfer into the first circuit and compression,
extracting a liquefied second part of the gas from the tank to supply the regasification unit, an
Withdrawing a liquefied third portion of the gas from the tank to subcool the third portion of the gas by heat exchange with the second portion of the gas, and reheating the first portion of the gas at least once with the second portion of the gas,
-storing the subcooled third part of the gas in the bottom of the tank to constitute a cold reserve layer.
The method may include one or more of the following features or steps taken independently of each other or in combination with each other:
the third portion of gas is subcooled by reducing the pressure and at least partially vaporizing the second portion of gas.
A step of reliquefying the compressed first part of gas flowing through the third circuit by heat exchange with the first part of gas flowing through the first circuit and with the liquefied second part of gas,
a step of transferring a reliquefied first portion of the gas to a regasification unit,
a compressed first partial gas re-liquefaction step of re-liquefying the compressed first partial gas cooled by heat exchange with the liquefied fourth partial gas extracted from the tank,
the tank is connected to an energy production plant, which is intended to be supplied with boil-off gas, by a gas treatment system, and the subcooling of the third portion of gas is based on the boil-off gas requirements of the energy production plant or distribution network. The flow rates of the second portion of gas and the third portion of gas increase as the flow rate of the distribution network increases; likewise, as the flow rate of the distribution network decreases, the flow rates of the second portion of gas and the third portion of gas decrease.
The vaporized first portion of the gas flowing in excess to the compressor is transferred to the regasification unit through at least one heat exchanger,
transferring the reliquefied first portion of the gas and the liquefied fourth portion of the gas to a recondenser of the regasification unit; the gas leaving the recondenser is sent to a distribution network or a tank, as required by the distribution network. The flow rates of the first portion of gas and the fourth portion of gas increase as the flow rate of the distribution network increases; likewise, as the flow rate of the distribution network decreases, the flow rates of the first portion of gas and the fourth portion of gas decrease.
Transferring the reliquefied first portion of the gas and the liquefied fourth portion of the gas to a recondenser of the regasification unit; when the regasification unit is stopped, the gas leaving the recondenser is sent to the canister.
-a step of recondensing the compressed and cooled first portion of gas with gas extracted from the tank in a recondenser of the regasification unit; the gas leaving the recondenser is sent to a distribution network.
The gas re-condensed in the regasification unit is compressed to the pressure of the distribution network and evaporated before being sent to the distribution network.
Drawings
The invention will be better understood and other details, characteristics and advantages thereof will become more apparent from a reading of the following description, given by way of non-limiting example, with reference to the accompanying drawings. In the drawings:
FIG. 1 shows a first embodiment of a gas processing system that includes a storage and regasification unit according to the present invention and that may be equipped with a floating or land-based receiving terminal;
FIG. 2 shows a mode of operation of a gas treatment system according to a first embodiment of the invention, with an example of the temperature of the gas circulating in the system;
FIG. 3 illustrates another mode of operation of the system of the first embodiment of the gas treatment system according to the present invention;
FIG. 4 shows a further mode of operation of the gas treatment system according to the first embodiment of the invention;
FIG. 5 shows yet another mode of operation of the first embodiment of the gas treatment system according to the invention;
FIG. 6 is a second embodiment of a gas treatment system according to the invention;
FIG. 7 illustrates a mode of operation of a gas treatment system according to a second embodiment of the gas treatment system of the present invention;
FIG. 8 is another mode of operation of the second embodiment of the gas treatment system according to the invention;
FIG. 9 is another mode of operation of the second embodiment of the processing system according to the present invention;
FIG. 10 is yet another embodiment of a second embodiment of a gas treatment system according to the present invention;
FIG. 11 illustrates another embodiment of a gas treatment system that includes a storage and regasification unit in accordance with the present invention and that may be equipped with a floating or land-based receiving terminal;
FIG. 12a shows the mode of operation of a gas treatment system with two heat exchangers for the purpose of supplying a fuel gas distribution network;
FIG. 12b is a detail view of FIG. 12 in relation to a compression device of the gas treatment system;
FIG. 13 is another mode of operation of the gas treatment system having two heat exchangers for supplying the fuel gas distribution network; and
fig. 14 is an operational mode of the gas treatment system with two heat exchangers for the purpose of managing only the gas vapor in the tank.
Detailed Description
Fig. 1 shows a first embodiment of a gas treatment system according to the invention. The system can handle gas vapors generated from natural evaporation of liquefied gases and liquefied gases (in liquid form) stored in tanks.
In this example, the gas is natural gas comprising methane or a gas mixture comprising methane.
The gas processing system 1 is particularly, but not exclusively, suitable for supplying combustible gas from a floating receiving terminal, such as a liquefied gas transport vessel (coastal or deep water), or from a land-based receiving terminal.
The gas treatment system comprises a tank 2 for storing liquefied gas. Only one tank is shown in fig. 1, but the system may of course comprise other tanks. Therefore, the number of tanks 2 is not limited. For example, the number of cans is in the range of 1 to 6 according to the size of the receiving terminal. Each tank 2 may have a capacity of 1000 to 50000 cubic meters.
Hereinafter the word "can" should be interpreted as "the or each can"
The tank 2 may contain a gas in liquefied form (liquefied gas) at a predetermined pressure and temperature. These predetermined temperatures are very low temperatures, or even low temperatures of the order of-160 ℃ at atmospheric pressure. To this end, each tank comprises an outer shell for sealing the gas stored at its storage temperature from the outside environment.
One or more tanks 2 may be connected to an energy production plant 3. The energy generating device 3 is designed to meet the energy requirements (electricity, etc.) of the operation of the receiving terminal, in particular for propulsion and/or for the production of electricity for onboard equipment in the case of a ship (floating receiving terminal). Such a plant 3 typically comprises a heat engine, such as an engine on a ship, consuming gas from gas cargo transported in the tank(s) of the ship. The energy production plant 3 may also comprise a plant for supplying a regas-sification unit, which will be described later. The device may also provision a distribution network, which will also be described later.
Advantageously, the high-pressure compressor is arranged upstream of the energy production plant.
The tank 2 contains liquefied gas 2a and boil-off gas 2b, the boil-off gas 2b being in the form of a vapour, in particular natural boil-off, resulting from the boil-off of the liquefied gas in the tank. Liquefied gas is herein referred to by the acronym "LNG" for liquefied natural gas (liquefied natural gas). Boil off gas or gas vapour is denoted by the acronym "BOG" or "NBOG" as natural gas boil off gas, as opposed to forced boil off gas "FBOG". Naturally, the liquefied gas 2a is stored in the bottom of the tank, while the boil-off gas 2b is located above the liquefied gas in the tank, called the gas top, and schematically indicated by the letter N. NBOG in tank 2 is the movement of liquefied gas in the tank due to heat input from the external environment inside the tank, due to the movement of the sea, for example when loading liquefied gas into the tank, or even when cooling the tank to bring it to an equilibrium temperature.
In the embodiment shown in fig. 1, the gas treatment system comprises an LNG tank 2. The pumps are submerged in the LNG in the tank 2 and are preferably located at the bottom of the tank to ensure that they are supplied with LNG only. There are three pumps, 10a, 10b, 10c.
The system 1 includes a regas unit 4 for vaporizing and heating the LNG from its liquefied form to its gaseous form again. The regas unit 4 is connected to a fuel gas distribution network 300 and/or a power plant.
The regasification unit 4 comprises at least one recondenser, at least one pump 4a or compressor (see fig. 2, 6, 11) and at least one heat exchanger 4b (see fig. 2, 6, 11). In this example, the recondenser here is a bottle 5 which makes it possible to inject boil-off gas into the liquid, in order to operate to allow the boil-off gas to recondense into liquid form. In fact, reliquefied NBOG may not be completely liquefied.
The pump and the heat exchanger form a train. Depending on the size of the receiving terminal, the regas unit 4 may comprise one or more parallel columns. The heat exchanger uses a heat transfer fluid, such as ambient air, seawater, or an intermediate fluid, to transfer thermal energy from the heat transfer fluid to the LNG, thereby heating the LNG.
In this regas unit 4, the recondensed gas is compressed by a pump 4a to the pressure of the distribution network and then evaporated at the outlet of the recondensor 5 with a heat exchanger 4b before it is sent to the distribution network. The recondensed gas is pressurized, for example by a pump, to 10-200 bar, preferably 50-100 bar.
A pump 10a is connected to the lower end of the line 11. And the other end is connected to a regasification unit 4. In particular, this other end is connected to a first inlet of the phase bottle 5. The latter comprises an outlet connected to a duct 6, the duct 6 being coupled to an upstream line 7 and a downstream line 8. At least one valve and one pump are mounted on the pipe 6 at the outlet of the bottle 5. Pump 10a is configured to force the flow of LNG in line 11 from the bottom of tank 2 to regas unit 4, in particular to bottle 5. An upstream line 7 is connected to tank 2 to deliver LNG to the bottom of tank 2. In the present example, the upstream line 7 leads to a line 27 described later in the description. As for the downstream line 8, it allows the liquefied natural gas stream to pass to the other components of the regasification unit 4.
Advantageously, but not limitatively, the pressure at the inlet of the regasification unit 4 is between 2 and 10 bar, while the pressure at the outlet of the regasification unit is between 60 and 110 bar.
The pump 10b is here connected to the lower end of a line 12. The pump 10c is in turn connected to one end, here also the lower end, of a line 13.
In a variant, there may be more of each type of pump, for example to provide redundancy for the pumps 10a, 10b, 10c, or to use existing pumps, for example spray pumps already present on the ship (in which case some of the pump functions may be provided by the spray pumps, each pump being present in a separate tank). As a variant, it is also possible to use fuel gas pumps already present on board the ship (in which case some of the functions may be performed by the fuel gas pump(s), each present in one or more separate tanks).
The pump flow rate is 10m 3 H and 550m 3 The ratio of the water to the water is between/h. Advantageously, but not exclusively, the pump 10c is of 5 to 15m 3 Flow rates in the/h range. Pump 10b at 50 to 60m 3 Flow rates in the range of/h. Finally, pump 10c is operated at 400 to 600m 3 Flow rates in the/h range. Of course, the flow rate of the pump 10c depends on the size and capacity of the regas unit 4 and the receiving terminal.
The pipeline 12 includes an upper end connected to a boom 14 for spraying droplets of liquefied natural gas. The spray boom 14 is located in the upper part of the tank 2, above the level N. Thus, the boom 14 is configured to spray droplets of LNG into NBOG. This makes it possible to force the NBOG to re-condense in the tank 2.
The pump 10b is configured to force the circulation of LNG in the line 12 from the bottom of the tank 2 to the boom 14 and to ensure that the LNG is sprayed in the form of droplets. In practice, there may be a gas overhead in the main tank, while NBOG may circulate in the pipeline.
Pump 10c is configured to force the LNG in line 13 to pass from the bottom of storage tank 14 to heat exchanger 15. Line 13 includes a pressure reduction device 16 to reduce the pressure of the LNG circulating in line 13 before reaching exchanger 15. The pressure reducing device 16 includes, for example, a joule-thomson effect valve.
Thus, passage of LNG in line 13 and through pressure letdown device 16 results in partial vaporization of the LNG prior to supply to exchanger 15.
In the example shown in fig. 1, there is a single heat exchanger 15. The heat exchanger 15 comprises at least three heat exchange circuits. Advantageously, but in non-limiting manner, the heat exchanger 15 is a tube, plate or coil exchanger.
In particular, the heat exchanger 15 comprises a first circuit 17, the first circuit 17 having an inlet connected to a line 18 for supplying the first circuit 17 with NBOG from the tank. To this end, the line 18 comprises one end coupled to an outlet 20 of the tank. An outlet 20 is located in the upper part of the tank 2 and opens into the top of the gas (above level N). NBOG is discharged from tank 2 through this line 18 in order to feed device 3.
The first circuit 17 comprises an outlet connected to the inlet of at least one compressor 21. In this embodiment, the outlet of the first circuit 17 is connected to two compressors 21. These compressors 21 are arranged in parallel, since redundancy of this type of compressor is required at the receiving terminal, in particular the floating terminal, here the ship. The outlet of the compressor(s) 21 is connected to the apparatus 3, taking into account its fuel gas supply. Each compressor 21 is configured to compress the gas to an operating pressure suitable for its use in the apparatus 3.
The heat exchanger 15 comprises a second circuit 22 having an inlet connected to line 13 for supplying the second circuit 22 with the gas in two-phase leaving the pressure reducing device 16. The second circuit 22 comprises an outlet connected to a compression device 23. These compression means 23 are arranged between the heat exchanger 15 and the compressor(s) 21. The pressure reducing device 16 may reduce the pressure of the gas entering the circuit 22 to 120 to 800 bar (absolute), preferably 300 to 800 bar (absolute). The gas entering the compressor is at the correct pressure for its operation.
Also, the compression device 23 allows boil-off gas that is over-circulated in the system to be returned to the tank. Typically, the compression ratio of these compression devices is 2 bar.
The compression device 23 here comprises at least one compressor. In particular, the inlet of the compressor is connected to the outlet of the second circuit 22 and the outlet of the compressor is connected to the inlet of at least one compressor 21.
Advantageously, the compressor 23 can also compress the vaporized LNG to the pressure required by the plant 3.
Typically, there may be two compressors 23 mounted in parallel on the receiving terminal. These compressors make it possible to provide approximately 6000m of a two-phase gas mixture at the outlet of the circuit 22 3 Flow rate per hour. These compressors are connected at the inlet to the boil-off gas outlet of the tank and at the outlet to the boil-off gas collector. The compressors mounted in parallel are shown in dashed lines in fig. 12 b. These ensure good loading and reheating of the tank.
The heat exchanger 15 further comprises a third circuit 25, the third circuit 25 comprising an inlet connected to the first path of the three-way valve 19 by a line 26. The second path of the three-way valve 19 is connected to the boom 14. Finally, the third path of the three-way valve is connected to the line 12. The third circuit 25 comprises an outlet connected to a line 27, the line 27 advantageously projecting into the bottom of the tank 2.
The heat exchanger 15 also comprises a fourth circuit 28. The fourth circuit includes an inlet connected to the outlet of the compressor(s) 21. The fourth circuit 28 also comprises an outlet connected to the regas unit 4. Line 29 makes it possible to connect on the one hand the inlet of the fourth circuit 28 and on the other hand the outlet of the compressor 21. As regards the outlet of the fourth circuit 28, it is connected in particular to the end of the line 30 connected to the regasification unit 4. The other end of the line 30 is in particular connected to a second inlet arranged in the upper part of the bottle 5. The compressed NBOG circulates in a fourth circuit 28.
A pressure reduction device 31 is installed on line 30 and is configured to reduce the pressure of the gas (here, the reliquefied LNG) before the gas is re-injected into the cylinder. The pressure of the reliquefied LNG entering the bottle is between 3 and 10 bar absolute. The pressure reducing means 31 comprise, for example, a joule-thompson effect valve, which makes it possible to reduce the gas temperature by adiabatic expansion.
Joule-thomson relaxation or decompression is a steady and slow laminar relaxation achieved by passing a gas stream through a buffer (usually a wad or silk cloth) in an insulated duct, the pressure on the left and right sides of which differs. For real gases, joule-thomson expansion is usually accompanied by a temperature change: this is the joule-thomson effect.
As shown in fig. 1, the heat exchanger 15 includes a fifth circuit 33. This fifth circuit 33 comprises an inlet connected to a line 34 connected to the tank 2 and an outlet connected to the regas unit 4. In particular, line 34 leads to line 26, line 26 being connected to pump 10b. Alternatively, line 34 is connected directly to a pump placed at the bottom of the tank. The outlet of the fifth circuit 33 is connected to a line 35, the line 35 being connected to the regasification unit 4, in particular a bottle. More precisely, the line 31 opens in the line 31 to supply the bottle.
The second circuit 22 is a cold circuit. In fact, the fluid circulating in this circuit 22, and in this case the depressurized LNG, is intended to be heated by circulation in this circuit so as to be at least partially vaporized. The fluid is intended to be heated and therefore to be cold. Thus, the circuit 22 is considered a cooling circuit.
The circuit 25 is a thermal circuit and thus a cooling circuit. The fluid circulating in the circuit 25, and in this case the LNG coming from the tank 2, is intended to be cooled, or even subcooled, by circulating in this circuit.
Circuits 22 and 25 are configured to effect heat exchange therebetween. It will be appreciated that the depressurization upstream of the circuit 22 makes it possible to lower the vaporization temperature, which makes it possible to produce a two-phase gas mixture by heat exchange with the LNG withdrawn from the tank and circulating in the circuit 25. Partial vaporization requires heat supplied by the LNG circulating in circuit 25; it is therefore a refrigeration source for cooling the LNG circulating in the circuit 25. In other words, the LNG in circuit 25 is cooled or even subcooled as a result of the depressurization and at least partial vaporization of the gas in circuit 22 (using depressurization device 16).
The circuit 28 is a thermal circuit and therefore a heating circuit in which the fluid circulates, in which case the compressed gas leaving the compressor 21 is intended to be cooled by circulating in this circuit. Expansion downstream of loop 28 makes it possible to reduce the temperature of the reliquefied LNG before re-injection into tank 2.
The circuit 17 is a cold circuit and therefore a cooling circuit, in which the fluid circulating, i.e. the NBOG taken from the tank, is intended to be heated by circulation in the circuit.
The circuits 17 and 28 are configured such that they also exchange heat between them. The NBOG makes it possible to cool the compressed NBOG circulating in the circuit 28.
The circuits 22 and 28 are configured such that they also exchange heat therebetween. The gas in the two-phase state may cool the compressed NBOG circulating in the circuit 22, or the NBOG may heat the gas in the two-phase state to complete partial vaporization.
The circuit 33 is also cold and therefore serves to cool the fluid circulating therein (LNG from the tank), this circuit 33 being intended to be heated while remaining in the liquid state.
Circuits 33 and 28 are configured to also effect heat exchange therebetween. The LNG circulating in loop 33 is a cold source to produce reliquefaction of the chilled LNG circulating in loop 28.
Fig. 2 shows a first mode of operation of the gas treatment system which makes it possible to regasify LNG stored in the tank 2 to supply the distribution network 300 without loss of cargo, while processing NBOG. The device 3 is supplied with NBOG, which is not much, that is to say low, required. This is the nominal operating condition of the gas treatment system. In particular, in the process, the gas processing system 1 makes it possible to generate cold which can be used subsequently, and also to convert the gas from LNG and BOG to fuel (regasification). The pressure in the tank is not very high because there is a large amount of cold reserve available. For this purpose LNG is taken from the tank 2 and supplied to the regas unit 4 via a conduit 11.
Initially, LNG from tank 2 is therefore sent by pump 10c to pressure reduction device 16 and then circulated in circuit 22 (cold) of exchanger 15. At the same time, LNG from tank 2 is delivered by pump 10b to loop 25 (hot) of exchanger 15. Thus, the heat exchange between these circuits 22, 25 results in:
heating the depressurized and partially vaporized LNG (two-phase gas state) in order to continue its vaporization, which is done in compressor 23, and
subcooled LNG which is re-injected into tank 2, in particular at the bottom, through line 27.
LNG is extracted from tank 2 at a temperature of about-160 c. Preferably, the pressure of the gas in two-phase state at the inlet of the heat exchanger 15 is between 120 and 800 mbar, more preferably between 300 and 800 mbar, and the temperature is between-182 ℃ and-151 ℃. The temperature of the gas in gaseous form upon leaving the heat exchanger is between-50 ℃ and-15 ℃. Preferably, the temperature of the at least partially vaporized gas is greater than or equal to 35 ℃. Such an outlet temperature makes it possible to use a compressor 23 which is less expensive than a cryogenic compressor. It should be noted that the cryogenic compressor can be operated at temperatures significantly below-50 ℃ or even-160 ℃. Furthermore, this temperature level ensures that all the liquefied gas is completely evaporated and therefore gaseous at the outlet of the circuit 22 and therefore gaseous at the inlet of the compressor 23.
The LNG entering the loop 25 has a temperature of about-160 c. The LNG outlet temperature after heat exchange in line 25 is about-168 c.
Secondly, NBOG from tank 2 flows in circuit 17 and is then compressed in compressor(s) 21. At the same time, LNG from tank 2 is still delivered by pump 10c to loop 22 of exchanger 15 (cold). Compressed BOG from the compressor 21 is also circulated in the loop 28 before undergoing reliquefaction and expansion. In the present invention, the term "reliquefaction" refers to the condensation of the gas vapor, bringing it back to the liquid state. The heat exchange between these circuits 22, 28, 17 results in:
heating the BOG to be compressed in the compressor 21,
heating the depressurized and partially vaporized LNG in order to continue its vaporization, which is done in compressor 23, and
cooling the compressed BOG, which is then re-expanded and re-liquefied before being injected into the bottle via line 30.
The temperature of the NBOG at the inlet of the loop 17 is about-120 ℃. Advantageously, the temperature of NBOG at the outlet of circuit 17, after heat exchange with the gas in the two-phase state (in circuit 22), is about 25 ℃. The temperature of the NBOG at the inlet of the circuit 28 after undergoing a temperature increase by compression is about 43 ℃. The gas temperature at the outlet of the circuit 28 is between-110 ℃ and-90 ℃. The gas circulating in the circuit 28 exchanges heat with the gas in the two-phase state circulating in the circuit 22 to reach a temperature of about-150 ℃
The pressure inside the bottle 5 is between 1 and 5 bar. Preferably, the pressure is about 3 bar.
Thirdly, LNG from tank 2 is delivered by pump 10b to circulate in loop 33 of heat exchanger 15. The NBOG from tank 2 still flows in circuit 17 and is then compressed in compressor(s) 21. Compressed BOG from the compressor 21 is also circulated in the loop 28 before undergoing reliquefaction and expansion. Therefore, the heat exchange between these circuits 33, 17, 28 results in:
cooling the compressed BOG, which is then expanded and reliquefied before injection into the bottle 5 via line 30.
The LNG is heated and will be transferred to the regas unit 4, in particular the upper part of the tank 5.
The LNG entering the loop 33 has a temperature of about-160 c. After heat exchange in loop 33, the LNG outlet temperature is about-145 ℃. At the inlet to the loop 28, the temperature of the compressed BOG is about 43 ℃. After the compressed BOG has exchanged heat with the gas in the circuit 33, the temperature of the re-liquefied gas at the outlet of the circuit 28 is about-150 deg.c
In this operating mode, the reliquefied NBOG (circulating in circuit 28) and the slightly heated LNG (circuit 33) are transferred to the bottles 5 to supply the distribution network 300. The flow rate of the distribution network controls the flow rate of the partially vaporized (22) and subcooled (loop 25) gas. The greater the network consumption, the more the gas flow rate in circuits 22 and 25 increases and vice versa. The flow rate of network 300 also controls the flow rate of the slightly heated (loop 33) and vaporized (loop 17) gases. The part NBOG circulating in the circuit 17 is sent to the plant 3 for power generation. We understand that NBOG passes through heat exchanger 15 twice (NBOG and reliquefied NBOG). The NBOG is continuously reheated (or preheated), compressed, cooled and (at least partially) reliquefied before reaching the regasification unit, in particular the bottle 5. The system also makes it possible to purposefully generate more excess cold in order to benefit from a higher recondensing capacity and to reuse the cold. The configuration of the system also makes it possible to recover the cold without the flow rates circulating in the various circuits being too high.
In a second mode of operation, shown in fig. 3, the gas processing system 1 makes it possible to regasify LNG extracted from the tanks to supply the distribution network 300 and BOG located in the tanks. Part of the NBOG supplies the device 3 for receiving the needs of the terminal. The requirements of the device 3 are low. In this mode of operation, the pressure in the tank can be controlled through the outlet 20 using NBOG. There is no subcooling of the LNG for storage and subsequent use because the pressure in the tank is not very high due to the use of NBOG to produce fuel gas via the regasification unit. Only circuits 17, 28 and 33 are supplied with gas. In this case, NBOG extracted from the tank is sent in circuit 17 to compressor 21, where it is compressed in compressor 21. The compressed NBOG is returned through the circuit 28 to the heat exchanger 15 where it is cooled by heat exchange with the NBOG circulating in the circuit 17. The cooled NBOG flowing through loop 28 is also reliquefied by heat exchange with LNG flowing through loop 33. The reliquefied NBOG reaches a temperature of about-150 ℃ at the outlet of the loop 28. The reliquefied NBOG is then expanded in a pressure reduction device 31 and then sent to a regasification unit. Upon exiting the expansion device, the reliquefied NBOG had a temperature of about-149 ℃.
LNG circulating in the circuit 33 is extracted from the tank 2 by the pump 10b. The LNG is reheated by heat exchange with the cooled NBOG circulating in the loop 28 and then injected into the regasification unit. The temperature of the LNG at the inlet of the loop 33 is about-160 c and the temperature of the LNG at the outlet is about-145 c. Meanwhile, LNG is extracted from the LNG tank to the regasification unit 4 using the pump 10a, thereby converting it into fuel gas.
Reliquefied NBOG (loop 28) and slightly heated LNG (loop 33) are transferred to the bottles 5, the bottles 5 transferring the recondensed gas to the distribution network 300, the demand of the distribution network 300 being more or less large. The recondensed gas is pressurized by pump 4a and then vaporized as described above. The consumption of the distribution network 300 fluctuates. In particular, when the consumption of the distribution network increases, that is to say when the flow rate increases, the flow rate of the gas circulating in the circuits 28 and 33 also increases.
As LNG is sucked out of the tank 2, it is sprayed through one channel of the three-way valve 19 to the top of the gas of the tank 2, thereby forcing the NBOG in the tank to re-condense.
In a third mode of operation, shown in fig. 4, the purpose of the gas treatment system is to control the pressure in the tank, in particular to maintain the pressure in the tank without converting the gas into fuel. Part of the NBOG supplies the device 3 for the needs of the receiving terminal. The requirements of the device 3 are low. The regas unit 4 is stopped. The demand of the distribution network 300 is zero. In this mode of operation, the NBOG is reliquefied and a liquefied gas is produced for later use. The NBOG is taken out of the tank and fed to a compressor 21, where it is compressed in the compressor 21. The NBOG is directed at the outlet of the compressor 21 to the heat exchanger 15 in the circuit 28. The compressed NBOG circulating in circuit 28 undergoes cooling by heat exchange with the NBOG circulating in circuit 17, as in the second mode of operation. This compressed NBOG is also reliquefied by heat exchange with LNG from tank 2 circulating in loop 33. The LNG circulating in the circuit 33 is reheated by heat exchange with the compressed and cooled NBOG and then sent to the regasification unit 4, in particular only to the bottles 5. The reliquefied NBOG (loop 28) and the slightly heated LNG (loop 33) are transferred into the bottle 5. LNG leaving bottle 5 is returned to tank 2 via line 7.
In a fourth mode of operation, shown in fig. 5, the gas treatment system can only process NBOG and the regasification unit is completely stopped. In this case, the amount of NBOG produced in the tank 2 is sufficient to meet the needs of the plant 3. To control the pressure in the tank 1, the NBOG is taken out of the tank and fed to the compressor 21 to reach the pressure required by the plant 3. In this operating example, the NBOG is taken from tank 2 and sent to compressor 21 through heat exchanger 15, in particular circuit 17. It will be appreciated that the BOG does not exchange any heat and that its temperature at the inlet and outlet of the heat exchanger 15 is the same, i.e. about-120 ℃.
Fig. 6 to 10 show a second embodiment of a gas treatment system 1 according to the invention. Elements already described above are denoted by the same reference numerals. The system 1 comprises several heat exchangers which allow heat exchange between LNG boil-off gas (NBOG) and/or liquid LNG. The system thus differs from the first embodiment in the number of heat exchangers. In particular, in the embodiment shown in fig. 6, the system 1 comprises at least three heat exchangers. In fig. 6, a single canister is also shown. Of course, the system may include other tanks. The system 1 further comprises pumps 10a, 10b and 10c mounted in the tank 2. In particular, each pump 10a, 10b, 10c is submerged in the LNG and is preferably located at the bottom of the tank to ensure that the tank is supplied with LNG only.
First heat exchanger 40 includes circuits 22a and 25. Advantageously, but not in a limiting way, the first heat exchanger is a Vacuum Evaporator (VE). The latter mainly generates heat (heat). Note that LNG taken from tank 2 via two pumps 10b, 10c is cooled in loop 25 and reheated in loop 22 a. The circuit 22a is the first part of the circuit 22 of the heat exchanger 15 described above and exchanges heat with the circuit 25. In particular, LNG taken from tank 2 and circulated in circuit 25 is subcooled and returned to the bottom of tank 2, thereby forming a cold reserve layer. The circuit 25 is connected on the one hand to a line 26 and on the other hand to a line 27 coupled to the tank.
The LNG circulating in loop 22a is reheated to the desired temperature and to a two-phase state. Before being reheated, the LNG is depressurized by a pressure-reducing device 16 installed upstream of the circuit 22a so that its pressure is at the pressure required by the compression device 23. The inlet of circuit 22a is connected to line 13 carrying pressure relief device 16. The depressurization and vaporization at least partially allows subcooling of the LNG circulating in the loop 25. The depressurized and reheated LNG is sent to the compressor 23. However, the depressurized and reheated LNG is intended to pass through the second heat exchanger 41.
The second heat exchanger 41 makes it possible to generate cold. The heat exchanger 41 comprises a circuit 17, a circuit 22b and a circuit 28a. Circuit 22b is a second portion of circuit 22 that exchanges heat with circuit 17. Loop 22b ensures heating of the gas two-phase mixture and total vaporization of the remaining liquid in the LNG. Circuit 28a is the first portion of circuit 28 that exchanges heat with circuits 22 and 33. In particular, the circuit 28a provides cooling of the NBOG. As regards the circuit 17, it can heat the NBOG taken from the tank. The inlet of circuit 28a is connected to the outlet of circuit 17. Likewise, the inlet of circuit 28a is connected to the outlet of circuit 22b. The inlet of circuit 17 is connected to outlet 20 by line 18 and the outlet of circuit 17 is connected to at least one compressor 21. The inlet of the circuit 28a is connected to the outlet of at least one compressor 21. Intermediate conduit 42 makes it possible to connect circuits 22a and 22b. The cooled and reliquefied NBOG is transferred to a regasification unit. The provision of this heat exchanger 41 in the system makes it possible to avoid the extraction of large amounts of LNG, thus enabling the handling of NBOG and the reduction of the pressure in the tank. More precisely, the heat exchange carried out between circuit 17 and circuit 28 makes it possible not to extract large quantities of LNG and to process NBOG.
To this end, the system 1 comprises a third heat exchanger 43 for generating cold. Advantageously, but not in a limiting way, the first heat exchanger is a Recondenser (RCD). The third heat exchanger 43 comprises a circuit 28b and a circuit 33. Circuit 28b is the second portion of circuit 28 that exchanges heat with circuits 22 and 33. The circuit 28b makes it possible to cool and reliquefy the NBOG previously cooled in the circuit 28a. The input of circuit 28a is connected to the outlet of circuit 28a by an intermediate conduit 44. The LNG taken out of the tank and circulating in the circuit 33 is reheated by heat exchange with the cooled and reliquefied NBOG circulating in the circuit 28b and then injected into the regasification unit. The inlet of the circuit 33 is connected to the line 26 and the outlet is connected to the conduit 30.
Advantageously, but in non-limiting manner, the heat exchangers 40, 41, 43 are separate from the tank. In other words, the subcooling, reliquefaction and/or at least partial evaporation takes place outside the tank 2.
Advantageously, but in non-limiting manner, the heat exchangers 40, 41, 43 are tube, plate or coil exchangers.
The gas treatment system operates in substantially the same manner as the above-described embodiments.
Fig. 7 shows a mode of operation similar to fig. 2. In this example of operation, the system makes it possible to generate cold while converting the gas into fuel by means of a regasification unit to supply the distribution network 300. Part of the NBOG supplies the device 3 for receiving the needs of the terminal. The requirements of the device 3 are low. We can see that the temperature of NBOG at the inlet of the circuit 17 is about-120 c and the temperature at the outlet is about 15 c. The reheated NBOG passes through compressor 21 and enters circuit 28a at a temperature of about 43 ℃. At the outlet of loop 28a, the BOG is cooled and has a temperature of about-105 ℃. This same compressed and cooled NBOG is sent to circuit 28b where it is liquefied again in circuit 28 b. The temperature at the outlet of loop 28b is about-150 c.
The LNG withdrawn from the tank is depressurized and has a temperature of about-169 c at the inlet of loop 22 a. The depressurized and reheated LNG has a temperature of about-162 c at the outlet of loop 22 a. The LNG is transferred in a two-phase state to heat exchanger 41 in loop 22b.
The depressurization and vaporization at least partially allows subcooling of the LNG circulating in the loop 25. The LNG temperature is about-160 c at the inlet of the loop 25 and about-168 c at the outlet of the loop 25. At the outlet of the loop 22b, the LNG, in the form of a two-phase gas mixture, is vaporized to reach a temperature of about 15 ℃. As mentioned before, this also makes it possible to use a cheaper compressor.
The LNG withdrawn from the tank is sent to a circuit 33, in which circuit 33 the LNG is reheated by heat exchange with the cooled LNG circulating in the circuit 28b, and in which the cooled LNG is subcooled.
In this mode of operation, the NBOG passes through heat exchanger 41 twice and through heat exchanger 43 once. In other words, in this embodiment, the NBOG passes through two heat exchangers 41, which are continuously reheated (or preheated), compressed, cooled and reliquefied before reaching the regasification unit. Also, the reliquefied NBOG (28a, 28b) and the slightly heated LNG loop 33) are transferred to the bottles 5 to supply the distribution network.
Fig. 8 shows a mode of operation similar to the first embodiment shown in fig. 3, in which the system 1 uses BOG and LNG withdrawn from the tanks to feed the regas unit. The pressure in the tank can be controlled through the outlet 20 using BOG. In this mode of operation, part of the NBOG provisioning device 3 is used to receive the requirements of the terminal. The requirements of the device 3 are low. There is no subcooling of the LNG for later use (the system does not store any refrigeration). Only circuits 17, 28a,28b and 33 are supplied with gas. It will be appreciated that the system uses second and third heat exchangers 41, 43. In contrast to the situation of fig. 7, the compressed and cooled NBOG at the outlet of the circuit 28a is about-100 ℃. In practice, the compressed NBOG is only in heat exchange relationship with the NBOG circulating in circuit 17 at an inlet temperature of about-120 ℃. The compressed and cooled NBOG is liquefied again in circuit 28b by heat exchange with LNG taken from the tank and circulated in circuit 33. At the outlet of loop 28b, the reliquefied NBOG is at a temperature of about-150 ℃. After being expanded in the pressure reduction device 31, the reliquefied NBOG has a temperature of about-149 ℃.
LNG withdrawn from the tank at a temperature of about-160 c is passed through a loop 33 where it is reheated by heat exchange with the NBOG in loop 33. The heated (but not vaporized) LNG has a temperature of about-149 c at the outlet of the loop 33.
LNG removed from the tank is also sprayed into the top of the gas to force the NBOG to re-condense. LNG is also withdrawn from tank 2 using pump 10a to be supplied to regasification unit 4 via line 11.
The reliquefied NBOG ( loop 28a,28 b) and the slightly heated LNG (loop 33) are transferred to the bottles 5, the bottles 5 transferring the recondensed gas to the distribution network 300, the demand of the distribution network 300 being more or less large. The consumption of the distribution network 300 fluctuates. In particular, when the consumption of the distribution network increases, that is to say when the flow rate increases, the flow rate of the gas circulating in the circuits 28 and 33 also increases.
The mode of operation of fig. 9 is similar to the first embodiment shown in fig. 4, wherein the system manages NBOG to avoid an increase in pressure in the tank. Part of the NBOG supplies the device 3 for the needs of the receiving terminal. The requirements of the device 3 are low. The regas unit 4 is stopped. The demand of the distribution network 300 is zero. This mode of operation differs from that of fig. 8 in that there is no flow of LNG in line 11 to the regas unit. Instead, LNG is transferred from the regas unit 4 from the outlet of the bottle 5 to the tank 2. The LNG leaving the bottle 5 has a temperature of about-160 c.
The mode of operation of fig. 10 is similar to the first mode of operation shown in fig. 5. The gas treatment system employs NBOG only to control the pressure in the tank and supply NBOG to the plant 3. The NBOG passes through the second heat exchanger by circulating in the circuit 17. The NBOG is compressed by the compressor 21 before the supply device 3.
Fig. 11-14 illustrate one embodiment of a gas treatment system. Elements already described above are denoted by the same reference numerals. The system 1 comprises several heat exchangers which allow heat exchange between LNG boil-off gas (NBOG) and/or liquid LNG. In this embodiment, the heat exchangers 40 and 43 described in the foregoing embodiments are combined in a single heat exchanger 400.
Fig. 11 illustrates the general concept of this system. In particular, the combined heat exchanger 400 acts as a vacuum evaporator and recondenser. This combination makes it possible to dispense with a further heat exchanger and allows economic gains. The exchanger 400 comprises a circuit 220 in which the LNG circulates, which is extracted from the bottom of the tank 2 and reheated by heat exchange to reach a two-phase condition. The inlet of the loop 220 is connected to line 13 and line 13 is connected to the bottom of the tank. In particular, line 13 is connected to line 12, line 12 being coupled to a pump 10b submerged at the bottom of tank 2. A pressure reducing device 16 is installed on the line 13. The outlet of the circuit 220 is connected to an intermediate pipe 42 connected to a heat exchanger 41. The heat exchanger 400 also comprises a circuit 250 in which the LNG withdrawn from the bottom of the tank circulates. The inlet of the loop 250 is connected to a line 34 for extracting LNG from the bottom of the tank and the outlet of the loop is connected to lines 27, 35 for feeding LNG to the bottom of the regas unit 4 or tank 2.
Heat exchanger 41 includes circuit 17, circuit 22b, and circuit 28a. Loop 22b ensures heating of the gas in two-phase and complete vaporization of the remaining liquid in the LNG, and loop 28a ensures cooling of the NBOG. As regards the circuit 17, it can heat the NBOG taken from the tank. To this end, the inlet of circuit 17 is connected to outlet 20 by line 18, and the outlet of circuit 17 is connected to at least one of compressors 21. The inlet of the circuit 22b is connected to one end of the intermediate pipe. The outlet of the circuit 22b is connected to a compression device 23. Which is connected to the inlet of the compressor(s) 21.
The inlet of circuit 28a is connected to the outlet of circuit 17. Likewise, the inlet of circuit 28a is connected to the outlet of circuit 22b. More precisely, the inlet of the circuit 28a is connected to the outlet of at least one of the compressors 21. The compressor 23 is arranged upstream of the compressor 21 in the fluid flowing direction in the circuit 22b. The outlet of circuit 28a is connected to a heat exchanger 400. In particular, the outlet of the circuit 28a is connected to one end of an intermediate duct 44.
As shown in fig. 11, the other end of the intermediate conduit 44 is also connected to a circuit 220. Likewise, the outlet of the circuit 220 is connected to a line connected to the regasification unit 4, in particular to the bottle 5. The pressure reducing device 31 is mounted on the pipe 31.
In this embodiment, the outlet of circuit 28a is connected to the inlet of circuit 220 downstream of heat exchanger 400 (depending on the direction of flow of the fluid in circuit 250. One end of intermediate conduit 44 is connected to the heat exchanger on the 0 outlet side of circuit 25. Likewise, line 30 is connected to the outlet of circuit 220 upstream of the heat exchanger, on the inlet side of circuit 250.
In an alternative embodiment of the gas treatment system, the compression device 23 comprises two compressors mounted in series (see fig. 12a and 12 b). This configuration makes it possible to reduce the pressure of the tank to between 0.2 and 0.8 bar, and preferably between 0.3 and 0.5 bar. This also facilitates vaporization after the loop ( loop 22,22 b) where LNG is partially vaporized. The compression ratio of each compressor is about 2. In this way it is possible to achieve a compression ratio of 4 bar.
These compressors in series operate at flow rates of 10,000 to 40,000 cubic meters per hour. Preferably, but not limited to, the flow rate is between 30,000 and 35,000 cubic meters per hour
Fig. 12a shows the mode of operation of the gas processing system in which the LNG is subcooled and vaporized. This mode of operation makes it possible to regasify LNG stored in the tank 2 in order to supply LNG to the distribution network 300, while processing NBOG without losing cargo. The NBOG requirements of the partial NBOG provision device 3 for the receiving terminal are relatively low.
LNG taken from tank 2 via pump 10b passes through a heat exchanger; the latter is subcooled in circuit 250 and reheated in circuit 220. Heating of the LNG is facilitated by depressurization upstream of the loop 220. The depressurization and at least partial vaporization of the LNG in the loop 220, as we have seen in the previous example, allows for the subcooling of the LNG circulating in the loop 250. The subcooled LNG is returned to the bottom of tank 2 to form a cold reserve layer. The reheated LNG in two-phase state at the outlet of the loop 220 is transferred to the exchanger 41 where it is vaporized in the loop 22b. The subcooled LNG is transferred to the bottom of the tank.
In order to treat NBOG in the tank, a portion thereof is extracted from the tank and sent to a heat exchanger 41 in circuit 17, where in heat exchanger 41 the latter is reheated by heat exchange with LNG circulating in circuit 22b. The reheated NBOG is compressed by a compressor and then returned to the heat exchanger where it is cooled by heat exchange with the LNG vaporized in loop 22b. The cooled NBOG was transferred to bottle 5. In this case, NBOG does not pass through heat exchanger 400, but circulates in a conduit 440, conduit 440 being connected on the one hand to the outlet of circuit 28a and on the other hand to the upper part of bottle 5.
LNG is also withdrawn from the tank to supply the bottles 5 of the regas unit 4. LNG and NBOG passing through the bottles 5 are sent to a distribution network 300.
Fig. 13 shows a mode of operation of a gas treatment system similar to that of fig. 3 or 8. The system 1 uses BOG and LNG withdrawn from the tanks to supply the regas unit. The pressure in the tank can be controlled through the outlet 20 using BOG. NBOG makes it possible to supply a device 3, which device 3 has a relatively low energy requirement. In this mode of operation, the LNG is not subcooled for later use (the system does not store any refrigeration). Only circuits 17, 28a, 220 and 250 are supplied with gas.
The NBOG at the tank outlet passes through a heat exchanger 41 in the circuit 17 so that the latter is compressed by the compressor(s) 21. The compressed NBOG is again passed through a heat exchanger in circuit 28a. The NBOG circulating in circuit 17 is reheated before passing through the compressor(s). The compressed NBOG is only in heat exchange with the reheated NBOG flowing in circuit 17 to undergo cooling.
The compressed and cooled NBOG is passed to heat exchanger 40 in loop 220 to be reliquefied by heat exchange with LNG withdrawn from the tank and circulated in loop 250. At the outlet of the circuit 220, the reliquefied NBOG is expanded in the pressure-reducing device 31 and then transferred into the bottle 5.
LNG withdrawn from tank 2 passes through loop 250 where it is reheated by heat exchange with NBOG (compression and cooling). The heated (but not vaporized) LNG is then transferred to a bottle (flash) 5. LNG removed from tank 2 is also sprayed into the top of the gas to force the NBOG in the tank to re-condense.
LNG is also withdrawn from tank 2 using pump 10a to be supplied to regas unit 4 via line 11 to be converted into combustible gas.
Reliquefied NBOG (circuits 28a, 250) and slightly heated LNG (circuit 250) are transferred to the bottles 5, the bottles 5 transferring the recondensed gas to the distribution network 300, the demand of the distribution network 300 being more or less large. In particular, when the consumption of the distribution network increases, that is to say when the flow rate increases, the flow rate of the gas circulating in the circuits 28 and 33 also increases.
Fig. 14 illustrates another mode of operation of the gas treatment system, which is similar to the mode of operation of fig. 4 or 9. In particular, this mode of operation makes it possible to control the pressure in the tank, in particular to maintain the pressure in the tank without converting the gas into fuel. NBOG supply 3 (which has a relatively low demand to ensure power generation from the receiving terminal), and regasification unit 4 is stopped. The demand of the distribution network 300 is zero. In this mode of operation, the tank is considered to already have subcooled LNG. The NBOG is reliquefied and liquefied gas (slightly heated) is produced for later use.
The NBOG is taken out of the tank and passes for the first time through a heat exchanger 41 in circuit 17 before being compressed by compressor 21. The NBOG is directed to the outlet of the compressor 21 for a second time to the heat exchanger 41 in the circuit 28a. The compressed NBOG circulating in circuit 28a undergoes cooling by heat exchange with the NBOG circulating in circuit 17.
The NBOG is then transferred to heat exchanger 400 where it is reliquefied by heat exchange with LNG circulating in circuit 250 from tank 2. The LNG circulating in the circuit 250 is reheated by heat exchange with the compressed and cooled NBOG and then sent to the regasification unit 4, in particular only to the bottles 5. NBOG circulating in loop 220 and LNG circulating in loop 250 circulate in opposite directions in the heat exchanger, which facilitates heat exchange.
The reliquefied NBOG ( circuits 17 and 28 a) and the slightly heated LNG (circuit 250) are transferred to the bottle 5. The reliquefied NBOG is relaxed before reaching the separation bottle. LNG leaving the bottle 5 is returned to the bottom of the tank 2 via line 7.

Claims (25)

1. A gas processing system (1) for a gas receiving terminal, the gas processing system comprising:
at least one tank (2) for storing boil-off gas and liquefied gas,
at least one compressor (21, 23),
a first circuit (17) for supplying boil-off gas to the compressor (21), the first circuit (17) being connected to a line (18) connected to a boil-off gas outlet (20) from the tank (2), and
a second circuit (22, 220) comprising a gas inlet connected to a line (13) connected to the liquefied gas outlet of the tank (2) and a gas outlet connected to the compressor (21,23), the line (13) being equipped with a pressure reduction device (16),
a third circuit (25,250) comprising a gas inlet connected to a line (26) connected to the liquefied gas outlet of the tank (2) and a liquefied gas outlet connected to a line (27) for re-injecting subcooled liquefied gas into the bottom of the tank to form a subcooled gas layer, and
a fourth circuit (28, 28 a) comprising an inlet connected to a line (29) through which boil-off gas flows, and this line (29) is connected to the outlet of the compressor (21),
the second circuit (22) being designed to supercool the gas circulating in the third circuit (25) by heat exchange, the third circuit (25) being designed to heat at least the gas circulating in the second circuit (22) by heat exchange,
characterized in that the gas treatment system comprises a regasification unit (4), the regasification unit (4) comprising a port connected to a line (11), which line (11) is intended to be supplied with liquefied gas from the tank (2), the regasification unit being connected to a fuel gas distribution network (300) and/or a power plant, and the compressor (21, 23) comprising an outlet connected to the regasification unit (4), and the fourth circuit comprising an outlet connected to a line (30.
2. The gas processing system (1) according to claim 1,
the regasification unit (4) comprises a recondenser connected on the one hand to the outlet of the compressor (21,23) and on the other hand to the tank (2) by line (7) for returning liquefied gas to the tank.
3. The gas processing system (1) according to claim 2,
the regasification unit (4) comprises at least one pump (4 a) and at least one heat exchanger (4 b), the pump (4 b) being mounted between the recondenser (5) and the heat exchanger (4 b).
4. The gas treatment system (1) according to any one of the preceding claims,
the outlet of the second circuit (22) is connected to a compression device (23) arranged upstream of the compressor (21).
5. The gas processing system (1) according to claim 4,
the second circuit (22) is configured to cool a gas circulating in the fourth circuit (28).
6. The gas processing system (1) according to any one of claims 1 to 3,
the gas treatment system comprises a first heat exchanger (40) comprising a first portion (22 a) of the second circuit (22) and a third circuit (25), the first heat exchanger (40) being configured to allow, respectively, an over-cooling of the gas circulating in the third circuit (25) and at least one heating of the gas circulating in the first portion (22 a) of the second circuit (22).
7. The gas processing system (1) according to any one of claims 1 to 3,
the gas treatment system comprises a second heat exchanger (41) comprising a second portion (22 b) of the second circuit (22) and the first circuit (17), the second heat exchanger being configured to allow evaporation of the gas circulating in the second portion of the second circuit (22) and cooling of the gas circulating in the first circuit (17).
8. The gas processing system (1) according to claim 7,
the second heat exchanger (41) also comprises a first portion (28 a) of the fourth circuit (28), the second portion (22 b) of the second circuit (22) being configured to cool the gas circulating in the first portion (28 a) of the fourth circuit (28).
9. The gas processing system (1) according to any one of claims 1 to 3,
the gas treatment system comprises a third heat exchanger (43) comprising a fifth circuit (33) and a second portion (28 b) of the fourth circuit (28), the third heat exchanger being configured to heat the gas circulating in the fifth circuit (33) and to re-liquefy the boil-off gas circulating in the second portion (28 b) of the fourth circuit.
10. The gas processing system (1) according to claim 9,
the fifth circuit (33) comprises an inlet connected to a line (34) connected to the tank (2), in which line (34) liquefied gas flows, and an outlet connected to the regasification unit (4), the fifth circuit (33) being configured to reliquefy the boil-off gas flowing in the fourth circuit (28).
11. The gas processing system (1) according to any one of claims 1 to 3,
the gas treatment system comprises a single heat exchanger (15) comprising at least a first, a second and a third circuit (17, 22, 25).
12. The gas processing system (1) according to any one of claims 1 to 3,
the gas treatment system comprises a pressure reduction device (16, 31) fitted on a line (30) delivering liquefied gas to the regasification unit (4).
13. The gas processing system of claim 7,
the gas treatment system comprises a heat exchanger (400) incorporating the functions of a heat exchanger (40, 43), the heat exchanger comprising a first exchange circuit (220) and a second exchange circuit (250), the first and second exchange circuits being configured to perform:
supercooling of the gas extracted from the tank and circulating in the second exchange circuit (250) and at least one heating of the gas extracted from the tank and circulating in the first exchange circuit (220), or
Heating of the gas extracted from the tank and circulating in the second exchange circuit (250) and re-liquefaction of the boil-off gas circulating in the first exchange circuit (220).
14. The gas treatment system of claim 4,
the compression device (23) comprises two compressors mounted in series.
15. A gas receiving terminal comprising a gas treatment system according to any one of the preceding claims.
16. A method of treating a gas with a gas treatment system according to any one of claims 1 to 14, the method characterized by comprising the steps of:
a first part of the boil-off gas is extracted from a tank (2) adapted to store boil-off gas and liquefied gas for transfer into the first circuit (17) and compression,
extracting a liquefied second part of gas from the tank (2) to supply the regasification unit (4), and
withdrawing a liquefied third portion of gas from the tank (2) for subcooling the third portion of gas by heat exchange with the second portion of gas and reheating the first portion of gas at least once with the second portion of gas,
-storing a third sub-cooled portion of the gas in the bottom of the tank to form a cold reserve layer.
17. The method of claim 16,
the third portion of gas is subcooled by at least partial evaporation and depressurization of the second portion of gas.
18. The method of any one of claims 16 to 17,
the method also comprises a step of cooling the compressed first portion of gas circulating in the third circuit (28, 28 a) by heat exchange with the first portion of gas circulating in said first circuit (17), and a step of transferring the reliquefied first portion of gas to the regasification unit (4).
19. The method of claim 18,
the method further comprises the step of re-liquefying the compressed first portion of gas cooled by heat exchange with the liquefied fourth portion of gas extracted from the tank (2).
20. The method of claim 16 or 17,
the tank (2) is connected to an energy production plant (3) for being supplied with boil-off gas through the gas treatment system, and the subcooling of the third portion of gas is based on the boil-off gas requirements of the energy production plant or distribution network.
21. The method of claim 16 or 17,
the vaporized first portion of gas flowing in excess to the compressor (21) is transferred to the regasification unit (4) through at least one heat exchanger (15, 40, 41.
22. The method of claim 19,
the reliquefied first portion of gas and the liquefied fourth portion of gas are transferred to a recondenser of the regasification unit (4), and the gas leaving the recondenser is sent to the distribution network (300) or to the canister (2) as required by the distribution network (300).
23. The method of claim 19,
the reliquefied first portion of gas and the liquefied fourth portion of gas are transferred to a recondenser of the regasification unit (4), and when the regasification unit (4) is stopped, the gas leaving the recondenser is sent to the drum (2).
24. The method of claim 16,
the method further comprises the step of recondensing the compressed and cooled first portion of the gas with the gas extracted from the tank (2) in a recondensor of the regasification unit (4), the gas leaving the recondensor being sent to a distribution network (300).
25. The method of claim 20,
the gas re-condensed in the regas unit (4) is compressed to the pressure of the distribution network and evaporated before being sent to the distribution network (300).
CN201980087368.7A 2018-11-30 2019-11-29 Gas treatment system equipped with a receiving terminal of a regasification unit and corresponding gas treatment method Active CN113260811B (en)

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FR1872120A FR3089282B1 (en) 2018-11-30 2018-11-30 GAS TREATMENT SYSTEM OF A RECEPTION TERMINAL EQUIPPED WITH A REGASIFICATION UNIT AND CORRESPONDING GAS TREATMENT METHOD
PCT/EP2019/083140 WO2020109580A1 (en) 2018-11-30 2019-11-29 Gas treatment system of a receiving terminal equipped with a regasification unit and corresponding gas treatment method

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KR102600264B1 (en) * 2021-12-09 2023-11-13 한국항공우주연구원 Heat exchange system and heat exchange method using same

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FR3089282A1 (en) 2020-06-05

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