US20100000251A1 - Method and apparatus for liquefying a hydrocarbon stream - Google Patents

Method and apparatus for liquefying a hydrocarbon stream Download PDF

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Publication number
US20100000251A1
US20100000251A1 US12/373,107 US37310707A US2010000251A1 US 20100000251 A1 US20100000251 A1 US 20100000251A1 US 37310707 A US37310707 A US 37310707A US 2010000251 A1 US2010000251 A1 US 2010000251A1
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United States
Prior art keywords
location
hydrocarbon stream
treated
treated hydrocarbon
treating
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Abandoned
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US12/373,107
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English (en)
Inventor
Michiel Gijsbert Van Aken
Marcus Johannes Antonius Van Dongen
Peter Marie Paulus
Johan Jan Barend Pek
David Bertil Runbalk
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Shell USA Inc
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Individual
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Assigned to SHELL OIL COMPANY reassignment SHELL OIL COMPANY ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: VAN AKEN, MICHIEL GIJSBERT, PEK, JOHAN JAN BAREND, RUNBALK, DAVID BERTIL, PAULUS, PETER MARIE, VAN DONGEN, MARCUS JOHANNES ANTONIUS
Publication of US20100000251A1 publication Critical patent/US20100000251A1/en
Abandoned legal-status Critical Current

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Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F25J1/0243—Start-up or control of the process; Details of the apparatus used; Details of the refrigerant compression system used
    • F25J1/0257—Construction and layout of liquefaction equipments, e.g. valves, machines
    • F25J1/0275—Construction and layout of liquefaction equipments, e.g. valves, machines adapted for special use of the liquefaction unit, e.g. portable or transportable devices
    • F25J1/0277—Offshore use, e.g. during shipping
    • F25J1/0278—Unit being stationary, e.g. on floating barge or fixed platform
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/0002—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the fluid to be liquefied
    • F25J1/0022—Hydrocarbons, e.g. natural gas
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2220/00—Processes or apparatus involving steps for the removal of impurities
    • F25J2220/60—Separating impurities from natural gas, e.g. mercury, cyclic hydrocarbons
    • F25J2220/64—Separating heavy hydrocarbons, e.g. NGL, LPG, C4+ hydrocarbons or heavy condensates in general
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2220/00—Processes or apparatus involving steps for the removal of impurities
    • F25J2220/60—Separating impurities from natural gas, e.g. mercury, cyclic hydrocarbons
    • F25J2220/66—Separating acid gases, e.g. CO2, SO2, H2S or RSH
    • 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
    • F25J2290/00—Other details not covered by groups F25J2200/00 - F25J2280/00
    • F25J2290/12—Particular process parameters like pressure, temperature, ratios
    • 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
    • F25J2290/60—Details about pipelines, i.e. network, for feed or product distribution

Definitions

  • the present invention relates to a method of liquefying a hydrocarbon stream such as a natural gas stream.
  • LNG liquefied natural gas
  • the natural gas stream to be liquefied (mainly comprising methane) contains ethane, heavier hydrocarbons and possibly other components that are to be removed to a certain extent before the natural gas is liquefied.
  • the natural gas stream is treated.
  • One of the treatments may involve the removal of undesired components such as H 2 O, CO 2 and H 2 S and some of the ethane, propane and higher hydrocarbons such as butane and pentane.
  • WO 2006/009646 A2 a method is disclosed for liquefying natural gas.
  • FIG. 1 a conventional LNG liquefaction plant is shown, wherein the LNG liquefaction plant includes several examples of optional treatment steps such as feed purification steps (liquids removal, hydrogen sulphide removal, carbon dioxide removal, dehydration), product purification steps (helium removal, nitrogen removal) and non-methane product production steps (de-ethanizing, de-propanizing, sulphur recovery).
  • feed purification steps liquids removal, hydrogen sulphide removal, carbon dioxide removal, dehydration
  • product purification steps helium removal, nitrogen removal
  • non-methane product production steps de-ethanizing, de-propanizing, sulphur recovery
  • a problem of the known method is that, if at the place where the natural gas is treated and liquefied no easy access exist for ships or vessels intended for transporting the LNG to remote markets, the LNG has to be transported via a pipeline to a remote port first. This is highly undesirable in view of the high costs for cryogenic pipelines.
  • One or more of the above or other objects are achieved according to the present invention by providing a method of liquefying a hydrocarbon stream such as natural gas, the method at least comprising the steps of:
  • An advantage of the present invention is that the liquefied hydrocarbon product can be easily transported from the second location using a transportation vessel, as the second location is situated off-shore. Thus, no liquefied hydrocarbon product, in particular LNG, has to be transported over long distances via a pipeline.
  • Another advantage is that less equipment is needed in both locations; this enables liquefying a hydrocarbon stream even when limited plot space is available onshore and/or off-shore.
  • Yet another advantage is that, in particular if the method of the present invention is applied in very cold regions such as the Arctic, use can be made of the cold ambient whereby the treated hydrocarbon stream can be cooled to a certain extent before the actual liquefaction takes place. This may result in a reduced CAPEX (capital expenses) for the liquefaction equipment.
  • the first and second locations are not limited to include only a single process or treating unit but are rather intended to include a plant site containing one or more process units.
  • the first and second locations are at a distance of at least 2 km from each other, preferably at least 5 km, more preferably at least 10 km. The distance may be longer than 1000 km but is preferably less than 900 km.
  • the first location is usually situated near a site where the hydrocarbon stream to be treated and liquefied is produced, such as a natural gas or a petroleum reservoir.
  • treating units may include conventional treating units such as a slug catcher, a condensate stabilizer, acid gas removal (AGR) units, dehydration units, sulphur recovery units (SRU), mercury removal units, nitrogen rejection units (NRU), helium recovery units (HRU), hydrocarbon dewpoint units, etc.
  • fractionation or extraction units for recovery of e.g. C 3 /C 4 liquid petroleum gas (LPG) and C 5+ liquid (condensate) may be present on the first location.
  • LPG liquid petroleum gas
  • C 5+ liquid (condensate) may be present on the first location.
  • the second location is usually situated near an LNG export terminal from where the liquefied natural gas is shipped or otherwise transported to the desired markets.
  • On the second location at least a liquefaction plant is present to obtain a liquefied hydrocarbon product.
  • some of the treating units mentioned in respect of the first location may be present at the second location. However, preferably as few treating units as possible are located at the second location.
  • the amount of handling (and thereby the presence of workpeople) near the liquefaction plant can be minimized.
  • the plot space on the second location is minimised.
  • the hydrocarbon stream may be any suitable gas stream to be treated and liquefied, but is usually a natural gas stream produced at and obtained from natural gas or petroleum reservoirs.
  • the natural gas stream may also be obtained from another source, also including a synthetic source such as a Fischer-Tropsch process wherein methane is produced from synthesis gas.
  • the natural gas is comprised substantially of methane.
  • the feed stream comprises at least 60 mol % methane, more preferably at least 80 mol % methane.
  • the natural gas may contain varying amounts of hydrocarbons heavier than methane such as ethane, propane, butanes and pentanes as well as some aromatic hydrocarbons.
  • the natural gas may also contain non-hydrocarbons such as H 2 O, N 2 , CO 2 , H 2 S and other sulphur compounds, and the like.
  • the treating in step (b) at least comprises removal of CO 2 , preferably such that the treated hydrocarbon stream comprises less than 500 ppm CO 2 , more preferably less than 200 ppm CO 2 , even more preferably less than 50 ppm CO 2 . It is especially preferred that no CO 2 removal takes place at the second location.
  • the treating in step (b) at least comprises removal of H 2 O, preferably such that the treated hydrocarbon stream comprises less than 100 ppm H 2 O, more preferably less than 10 ppm H 2 O, even more preferably less than 1 ppm H 2 O.
  • the treating in step (b) comprises removal of mercury (Hg).
  • the treated hydrocarbon stream to be liquefied comprises at least 70 mole % of methane, more preferably at least 80 mole %.
  • the treated hydrocarbon stream to be liquefied comprises less than 5 mole % of C 5 + hydrocarbons, meaning pentanes and heavier hydrocarbons.
  • the treated hydrocarbon stream is compressed before transporting in step (c), preferably to a pressure above 50 bar, more preferably above 60 bar, still more preferably above 70 bar. It is especially preferred that the treated hydrocarbon stream is transported in a state being substantially above the critical point. In this way, the treated hydrocarbon stream can be transported in substantially a dense phase.
  • the treated hydrocarbon stream is cooled during transporting by heat exchanging against the ambient.
  • the treated hydrocarbon stream is cooled to a temperature ⁇ 10° C., preferably ⁇ 0° C., more preferably ⁇ 10° C. before it reaches the second location.
  • the cooling duty in the liquefaction plant at the second location can be significantly decreased.
  • the distance between the first and second location is such that the treated hydrocarbon stream is cooled as much as possible, preferably reaching ambient temperatures, if it is transported via a pipeline that is substantially not thermally insulated.
  • full advantage of cold ambient conditions may be used, in particular if the pipeline is in a cold area such as in Arctic regions. It is believed that this can be achieved when the distance between the first and second location is more than 2 km, preferably more than 5 km, still more preferably more than 10 km.
  • step (d) the treated hydrocarbon stream is liquefied.
  • the refrigerants may be produced in the second location or may be produced elsewhere and transported to the second location.
  • the refrigerants needed for liquefying the treated hydrocarbon stream are produced in a location that is geographically removed from the second location where liquefaction takes place.
  • the distance between the location where the refrigerants are produced and the second location is more than 2 km, more preferably more than 5 km.
  • a mixed refrigerant comprising at least two refrigerants is used and the refrigerants are transported to the second location via separate pipelines for each of the pure component refrigerants that make up the mixed refrigerant as used in the liquefaction process.
  • This solution offers the simplest line-up operation-wise for the supply and make-up of the required refrigerants.
  • a mixed refrigerant comprising at least two refrigerants is used and the different pure component refrigerants are delivered pre-mixed via a common pipeline.
  • the advantage of this embodiment is the elimination of the other pipelines that would otherwise be required to transport the different refrigerant components separately.
  • a mixed refrigerant comprising at least two refrigerants is used and the different pure refrigerant components are delivered to the second location via a single pipeline in successive plug-flows.
  • refrigerant is supplied to the second location via pipelines and the refrigerant supply pipelines are used as storage vessels to eliminate (or reduce) storage of the refrigerants at the second location. This further reduces the plot space needed at the second location.
  • the refrigerant is used to cool down the treated hydrocarbon stream to less than ⁇ 140° C., preferably less than ⁇ 150° C.
  • the cooling step is followed by expansion to atmospheric pressure.
  • the liquefied hydrocarbon product is obtained at atmospheric pressure.
  • the liquefied hydrocarbon product is usually transported and regasified.
  • the transportation of the liquefied hydrocarbon product such as LNG is usually performed by shipping.
  • Regasification is usually done at e.g. an LNG import terminal that may be onshore or offshore.
  • the liquefied hydrocarbon product may be further processed before transporting, if desired.
  • the present invention provides an apparatus for liquefying a hydrocarbon stream such as a natural gas stream, the apparatus at least comprising:
  • one of the treating units at the first location is adapted for removal of CO 2 . Further it is preferred that no CO 2 removal from the treated hydrocarbon stream takes place at the second location. Also it is preferred that one of the treating units at the first location is adapted for removal of H 2 O.
  • the apparatus according to the present invention further comprises a compressor for compressing the treated hydrocarbon stream at the first location, preferably to a pressure above 50 bar, preferably above 60 bar, more preferably above 70 bar.
  • the pipeline is substantially not thermally insulated. This enables cooling of the treated hydrocarbon stream against the ambient during transport from the first to the second location. If the transport takes place in a cold environment such as the Arctic region, use of the cold ambient can be made.
  • FIG. 1 schematically a process scheme in accordance with the present invention.
  • FIG. 2 schematically a process scheme in accordance with another embodiment of the present invention.
  • FIG. 1 schematically shows a process scheme (generally indicated with reference No. 1 ) for the treating and liquefaction of a hydrocarbon stream such as natural gas.
  • the process scheme of FIG. 1 is divided over two separate locations, viz. a first location 2 and a second location 3 .
  • the first location 2 is usually situated near a site where the natural gas to be treated and liquefied is produced, such as a natural gas or a petroleum reservoir (not shown).
  • the first location is onshore.
  • On the first location 2 one or more treating units are located.
  • These treating units may include conventional treating units such as a slug catcher; a condensate stabilizer; acid gas removal (AGR) units for removal of CO 2 , H 2 S and other sour gases; dehydration units for the removal of H 2 O; sulphur recovery units (SRU); mercury removal units; nitrogen rejection units (NRU); helium recovery units (HRU); hydrocarbon dewpoint units; etc. Also fractionation or extraction units for recovery of e.g. C 3 /C 4 liquid petroleum gas (LPG) and C 5+ liquid (condensate) may be present at the first location 2 .
  • these treating units as such are well known to the person skilled in the art, they are not further discussed here.
  • the first location 2 contains a CO 2 removal unit 11 , a dehydration unit 12 , a mercury removal unit 13 , and a hydrocarbon dew-pointing facility 14 for removing selected heavier hydrocarbons from the natural gas.
  • a CO 2 removal unit 11 contains a CO 2 removal unit 11 , a dehydration unit 12 , a mercury removal unit 13 , and a hydrocarbon dew-pointing facility 14 for removing selected heavier hydrocarbons from the natural gas.
  • two coolers 15 , 16 as well as a compressor 17 are present.
  • the compressor 17 may be a train of two or more compressors.
  • the second location 3 is usually situated near an LNG export terminal from where the produced liquefied natural gas is shipped or otherwise transported to the desired markets.
  • the second location is on a distance from the first location of at least 2 km, and may be as high as 900 km.
  • On the second location 3 at least a liquefaction plant 21 is present to obtain LNG.
  • the second location 3 includes a liquefaction plant 21 (that may have various line-ups as is known in the art), and upstream of the liquefaction plant, a scrub column 18 in which C 3+ hydrocarbons are removed from the natural gas and sent to a fractionation unit 19 for further workup. Furthermore some coolers 22 , 23 and 24 are present
  • a feed stream 10 (as e.g. obtained from the natural gas or petroleum reservoir) is processed by the various treatment units at the first location 2 thereby obtaining a treated natural gas stream 20 .
  • the inlet pressure of the feed stream 10 will be between 50 and 100 bar and the temperature will usually between 0 and 60° C.
  • a treated hydrocarbon stream 20 is obtained.
  • the treated hydrocarbon stream 20 usually will have a temperature in the range of about 40-90° C., typically about 80° C.
  • Stream 20 is subsequently transported via pipeline 4 to the second location 3 .
  • the pipeline may be above or under the ground, or surrounded by sea water.
  • the pipeline 4 is substantially not thermally insulated from the ambient such that the treated stream 20 is cooled against the ambient.
  • the pipeline 4 may be substantially made from low temperature resistant carbon steel.
  • the treated stream 20 is cooled during transport in the pipeline 4 to a temperature ⁇ 10° C., preferably ⁇ 0° C., more preferably ⁇ 10° C. before it reaches the second location 3 .
  • the amount of cooling in the pipeline will depend on various factors such as the ambient temperature, the length of the pipeline 4 and the materials used in the pipeline 4 . It has been found that suitable results may be obtained if the pipeline 4 is at least 2 km long.
  • the treated stream 20 is further treated at the second location 3 to remove C 3+ hydrocarbons (which are sent to the fractionation unit 19 as stream 60 ).
  • the resulting leaner stream 40 is (after cooling in cooler 23 ) passed to the liquefaction plant 21 in which a LNG product 50 is produced.
  • the LNG 50 may be sent to an LNG export terminal for transportation to remote markets in which the LNG will be regasified again on or near a LNG import terminal (not shown).
  • the regasification of the LNG may take place onshore or offshore. Thereafter the regasified gas may be sent to a gas network and distributed to the end users.
  • the (one or more) product(s) obtained may be used as fuel or refrigerant. If desired, at least a part of the product 70 may be sent back to the first location 2 .
  • FIG. 2 shows an alternative embodiment of the present invention, in which also the scrub column 18 and fractionation unit 19 are placed at the first location 2 .
  • the treated stream 20 is already suitable for liquefaction before it is passed via the pipeline 4 to the second location 3 . Thus, no treatment needs to be performed at the second location 3 .

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  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Mechanical Engineering (AREA)
  • Thermal Sciences (AREA)
  • General Engineering & Computer Science (AREA)
  • Ocean & Marine Engineering (AREA)
  • Chemical & Material Sciences (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Separation By Low-Temperature Treatments (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
US12/373,107 2006-07-13 2007-07-09 Method and apparatus for liquefying a hydrocarbon stream Abandoned US20100000251A1 (en)

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
EP06117142.7 2006-07-13
EP06117142 2006-07-13
PCT/EP2007/056929 WO2008006788A2 (fr) 2006-07-13 2007-07-09 Procédé et appareil permettant de liquéfier un courant d'hydrocarbure

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US20100000251A1 true US20100000251A1 (en) 2010-01-07

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US12/373,107 Abandoned US20100000251A1 (en) 2006-07-13 2007-07-09 Method and apparatus for liquefying a hydrocarbon stream
US12/373,099 Abandoned US20090205365A1 (en) 2006-07-13 2007-07-11 Method and apparatus for liquefying a natural gas stream

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US (2) US20100000251A1 (fr)
EP (2) EP2047194A2 (fr)
JP (2) JP2009542881A (fr)
KR (2) KR20090028829A (fr)
CN (1) CN101490490A (fr)
AU (2) AU2007274367B2 (fr)
BR (1) BRPI0713628A2 (fr)
NO (1) NO20090697L (fr)
RU (1) RU2009145096A (fr)
WO (2) WO2008006788A2 (fr)

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WO2012030476A2 (fr) * 2010-08-30 2012-03-08 Chevron U.S.A. Inc. Procédé, système et installation de production et de stockage pour traitement gpl et gnl en mer de gaz associés
EP2439255A1 (fr) * 2010-10-05 2012-04-11 Shell Internationale Research Maatschappij B.V. Procédé et système pour la production d'un flux gazeux sans contaminants
EP2749830A1 (fr) 2012-12-27 2014-07-02 Shell Internationale Research Maatschappij B.V. Procédé pour la fabrication de l'éthane conditionné et appareil prévu à cet effet

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US8454727B2 (en) 2010-05-28 2013-06-04 Uop Llc Treatment of natural gas feeds
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WO2013171856A1 (fr) * 2012-05-16 2013-11-21 石油資源開発株式会社 Procédé de traitement et dispositif de traitement pour gaz naturel
SG11201507299TA (en) 2013-04-12 2015-10-29 Excelerate Liquefaction Solutions Llc Systems and methods for floating dockside liquefaction of natural gas
US20150033792A1 (en) * 2013-07-31 2015-02-05 General Electric Company System and integrated process for liquid natural gas production
KR102372754B1 (ko) * 2015-05-15 2022-03-10 대우조선해양 주식회사 천연가스의 이산화탄소 제거 방법
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JP2009542881A (ja) 2009-12-03
KR20090028651A (ko) 2009-03-18
AU2007274367A1 (en) 2008-01-17
JP2009542882A (ja) 2009-12-03
NO20090697L (no) 2009-02-12
WO2008006788A3 (fr) 2008-10-30
WO2008006842A2 (fr) 2008-01-17
BRPI0713628A2 (pt) 2012-10-23
EP2047194A2 (fr) 2009-04-15
RU2009145096A (ru) 2011-06-10
EP2041506A2 (fr) 2009-04-01
CN101490490A (zh) 2009-07-22
AU2007274367B2 (en) 2010-07-29
US20090205365A1 (en) 2009-08-20
WO2008006788A2 (fr) 2008-01-17
KR20090028829A (ko) 2009-03-19
AU2007274331A1 (en) 2008-01-17

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