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WO1990000589A1 - A process for liquefying hydrocarbon gas - Google Patents

A process for liquefying hydrocarbon gas Download PDF

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Publication number
WO1990000589A1
WO1990000589A1 PCT/US1989/002916 US8902916W WO9000589A1 WO 1990000589 A1 WO1990000589 A1 WO 1990000589A1 US 8902916 W US8902916 W US 8902916W WO 9000589 A1 WO9000589 A1 WO 9000589A1
Authority
WO
WIPO (PCT)
Prior art keywords
gas
lhg
selected storage
conditioner
pressure
Prior art date
Application number
PCT/US1989/002916
Other languages
French (fr)
Inventor
Virgil Lee Brundige, Jr.
Original Assignee
Mobil Oil Corporation
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Mobil Oil Corporation filed Critical Mobil Oil Corporation
Publication of WO1990000589A1 publication Critical patent/WO1990000589A1/en
Priority to KR1019900700478A priority Critical patent/KR900701972A/en

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C1/00—Pressure vessels, e.g. gas cylinder, gas tank, replaceable cartridge
    • F17C1/005—Storage of gas or gaseous mixture at high pressure and at high density condition, e.g. in the single state phase
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/0002—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the fluid to be liquefied
    • F25J1/0022—Hydrocarbons, e.g. natural gas
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/003—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production
    • F25J1/0047—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production using an "external" refrigerant stream in a closed vapor compression cycle
    • F25J1/0052—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production using an "external" refrigerant stream in a closed vapor compression cycle by vaporising a liquid refrigerant stream
    • 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
    • F25J1/006—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the refrigerant fluid used
    • F25J1/008—Hydrocarbons
    • F25J1/0087—Propane; Propylene
    • 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
    • F25J1/0203—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process using a single-component refrigerant [SCR] fluid in a closed vapor compression cycle
    • F25J1/0204—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process using a single-component refrigerant [SCR] fluid in a closed vapor compression cycle as a single flow SCR cycle
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F25J1/0243—Start-up or control of the process; Details of the apparatus used; Details of the refrigerant compression system used
    • F25J1/0244—Operation; Control and regulation; Instrumentation
    • F25J1/0254—Operation; Control and regulation; Instrumentation controlling particular process parameter, e.g. pressure, temperature
    • 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
    • F25J1/0244—Operation; Control and regulation; Instrumentation
    • F25J1/0254—Operation; Control and regulation; Instrumentation controlling particular process parameter, e.g. pressure, temperature
    • F25J1/0255—Operation; Control and regulation; Instrumentation controlling particular process parameter, e.g. pressure, temperature controlling the composition of the feed or liquefied gas, e.g. to achieve a particular heating value of natural gas
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—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
    • F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/0204—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the feed stream
    • F25J3/0209—Natural gas or substitute natural gas
    • F25J3/0214—Liquefied 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
    • F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/0228—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream
    • F25J3/0233—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream separation of CnHm with 1 carbon atom or more
    • 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
    • F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/0228—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream
    • F25J3/0238—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream separation of CnHm with 2 carbon atoms or more
    • 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
    • F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/0228—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream
    • F25J3/0242—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream separation of CnHm with 3 carbon atoms or more
    • 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
    • F25J2200/00—Processes or apparatus using separation by rectification
    • F25J2200/02—Processes or apparatus using separation by rectification in a single pressure main column 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
    • F25J2200/00—Processes or apparatus using separation by rectification
    • F25J2200/70—Refluxing the column with a condensed part of the feed stream, i.e. fractionator top is stripped or self-rectified
    • 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
    • F25J2205/30—Processes or apparatus using other separation and/or other processing means using a washing, e.g. "scrubbing" or bubble column for purification purposes
    • 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
    • F25J2215/00—Processes characterised by the type or other details of the product stream
    • F25J2215/02—Mixing or blending of fluids to yield a certain product
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2290/00—Other details not covered by groups F25J2200/00 - F25J2280/00
    • F25J2290/62—Details of storing a fluid in a tank
    • 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
    • F25J2290/72—Processing device is used off-shore, e.g. on a platform or floating on a ship or barge

Definitions

  • the present invention relates to a process for liquefying hydrocarbon gas (e.g. , natural gas) to produce a liquefied heavy gas (LHG).
  • hydrocarbon gas e.g. , natural gas
  • LHG liquefied heavy gas
  • Vast reserves of hydrocarbon gas e.g., natural gas
  • hydrocarbon gas e.g., natural gas
  • the distances and terrain e.g., sea bottom
  • the gas from these areas must be processed at the remote site and then transported aboard specially-constructed, marine vessels to those market ports which have the proper facilities for off-loading the processed gas.
  • an LPG process only propane and possibly some butane are extracted from the natural gas feed stream and are cooled to a low temperature, e.g., from -70 to -40°C (-90 to -40°F) while maintaining the cooled components at a pressure of 110 Pa (16 psia) 5; in storage. Due to the higher temperature, an LPG process is cheaper to build and operate than an LNG process but the methane and ethane components of the natural gas are either sacrificed or must be handled separately, thereby making LPG less commercially attractive overall.
  • MLG medium condition liquefied gas
  • CNG compressed natural gas
  • MLG requires that any condensates in the natural gas feed stream be removed before liquefication and must be handled separately from the MLG.
  • specialized storage facilities are require ⁇ for transporting MLG which are substantially different from either LNG or LPG storage facilities with none of these storage facilities being interchangeable without substantial modification.
  • CNG merely involves compressing natural gas under extremely high pressures, e.g., 20700 kPa (3000 psi) at ambient temperatures. However, since the gas is not liquefied at these conditions, the volumetric efficiency of CNG does not make this process attractive for transporting large volumes of gas over long distances.
  • Still another process for transporting natural gas proposes to saturate the natural gas with a liquid organic additive whereby the gas-additive mixture will liquefy at a higher temperature than that of the gas alone; see U.S. Patent 4,010,622.
  • the additive is selected from hydrocarbons, alcohols, or esters having a chain length of C ⁇ to C-Q and which is liquid at ambient conditions. While this mixture does liquefy at higher temperatures thereby decreasing the refrigeration costs involved, the resulting liquefied ixture presents certain problems.
  • the solubility of methane decreases as the molecular weight of the additive increases so with heavier hydrocarbon additives, less methane can be liquefied.
  • the invention resides in a process for liquefying hydrocarbon gas comprising: adding an organic conditioner which is normally gaseous at ambient conditions to said hydrocarbon gas to change the composition of said hydrocarbon gas and form an altered gas having a composition which will be in a liquid phase at a selected storage tmeperature and pressure; and cooling said altered gas to at least said selected storage temperature and maintaining said altered gas at said selected storage pressure to form a liquefied heavy gas.
  • the present invention provides a process for liquefying substantially any hydrocarbon gas, e.g., natural gas, wherein all of the components of the gas are liquefied into a single, liquefied heavy gas (LHG) .
  • the present process will liquefy natural gases produced from different sources which may have substantially different original compositions (e.g . , lean gas, rich gas, gas with substantial amounts of condensates and gases produced with crude oil ) .
  • LHGs liquefied from feed gases having different compositions are always in the liquid phase at the same common, selected storage temperature and pressure regardless of their original composition. This permits LHGs formed from natural gases of different original compositions to be stored and shipped in the same, standardized storage containers .
  • any marine vessel equipped with such storage containers can be used to transport LHG regardless of its origin or original composition. Further, there is no need to have separate storage available on board the vessel for condensates and/or other individual components of the natural gas since all of these are liquefied in the LHG.
  • the present invention relates to a process for liquefying natural gas wherein an "organic conditioner" is added to the natural gas feed stream after it has been dehydrated to change the composition of the natural gas and thereby form an altered gas which has a composition that will be in the liquid phase at a selected storage temperature and pressure.
  • the altered gas stream is then cooled to at least the selected storage temperature , e.g . , -40°C, while the gas is maintained at the selected storage pressure, e.g . , 8380 kPa (1200 psia) , to thereby form LHG.
  • the selected storage temperature is selected so that it is well above cryogenic temperatures requi red for LNG (e.g . , -160°C or -260°F) .
  • LHG' s higher temperature significantly reduces the compressor horsepower needed for the LHG system when compared to that for a LNG system ( i. e. , up to a 90% reduction in compressor horsepower) .
  • the selected storage pressure can be low enough (e.g. , 8380 kPa or 1200 psia) that LHG can be stored and transported in storage containers made from relatively inexpensive materials (e.g . , commercially available steel storage cylinders) with no expensive alloys being required as is the case with LNG storage.
  • the organic conditioner used to alter the original composition of the natural gas is a low molecular weight organic compound or mixture therof (e.g.
  • each natural gas to be liquefied will depend upon the original composition of the particular natural gas to be liquefied and can easily be determined once the particulars are known. That is, it is preferred to "tailor" each natural gas to be liquefied by matching the organic conditioner to a predominant light hydrocarbon fraction present in the original natural gas. For example, if a natural gas has a predominant amount of ethane, then ethane is the preferred organic conditioner. This allows the liquid conditioner to be easily recovered from the LHG at its destination by known means, e.g. , fractionation, whereby the conditioner can be "back-hauled” to a production area in the otherwise empty LHG ships for reuse in the liquification process.
  • LHG offers many advantages over other known gas liquefication processes, some of these being: a. Substantially less horsepower (up to 90% less than LNG) is required to liquefy LHG. b. LPG is included in LHG while butane is normally limited in LNG. c. Condensates are included in LHG while they must be separated and handled separately with LNG. d. The overall thermal efficiency from well head to burner tip is about 95% with LHG compared to about 70% with LNG. e. Significantly less pretreatment is required for LHG, e.g. , the feed natural gas for LHG need only to be pretreated to pipeline conditions (e.g .
  • Figure 1 is a phase diagram of three hydrocarbon gases of different composition before and after the same organic conditioner has been added to each in accordance with the present invention to establish a common bubble point (i. e. , selected storage point) for all of the gases;
  • Figure 2 is a phase diagram of a single hydrocarbon gas wherein three different organic conditioners have been added thereto in accordance with the present invention to produce three gases having a common bubble point temperature and pressure;
  • Figure 3 is a phase diagram of another single hydrocarbon gas wherein three different organic conditioners that could be made from said gas have been added to another portion of the same gas in accordance with the present invention to produce three gases having a common bubble point temperature and pressure.
  • Figure 4 is a schematic view of a system used to determine the amount of an organic conditioner to be added to a particular feed gas to form LHG in accordance with the present invention
  • Figure 5 is a schematic view of a LHG liquefication system
  • Figure 6 is a schematic view of a LHG storage and transportation system
  • Figure 7 is a schematic vi ew of a LHG off-loading system.
  • Figure 8 is a graph depicting the results of experiments dete rmining the solubility of methane in hydrocarbon liquids having different molecular weights .
  • the chemical composition of common hydrocarbon gases can vary substantially depending on the source from which the gas originates. That is, there are lean gases (i.e., substantially methane), rich gases (i.e., methane plus substantial amounts of heavier hydrocarbon components) , and many gases of varying compositions in between.
  • lean gases i.e., substantially methane
  • rich gases i.e., methane plus substantial amounts of heavier hydrocarbon components
  • the following represents the compositions of three actual produced gases, i.e., X, Y and Z:
  • the liquid-gas phase behavior of any gas will differ depending on its particular composition. That is, a rich gas will a ⁇ have a higher cri tical point (e.g . , temperature above which the gas cannot exist as a liquid) than that of a leaner gas.
  • cri tical point e.g . , temperature above which the gas cannot exist as a liquid
  • the composition of a particular gas its phase behavior, e.g . , critical point, can also be changed.
  • the critical temperature the bubble point line is changed to allow the storage pressure to be selected in a cost effective manner for the storage containers required.
  • the phase behavior of particular gas is changed by adding an organic conditioner thereto before it is liquefied.
  • composition of a feed gas is changed so that its cri tical point is changed to a point where the altered gas is always in the liquid phase at a selected temperature and pressure, collectively called "selected storage point" .
  • the selected storage point is selected so that different hydrocarbon gases whi ch are conditioned in accordance with the present invention will be li quid at the same, common selected storage point .
  • This allows gases of different composition from different areas to be conditioned so that all are in a liquid phase at the same temperature and pressure the reby facilitating transport and/or storage of the liquefied gases in standa rdi zed vessels.
  • Figure 1 is a phase diagram for the three hydrocarbon gases
  • Curve X represents the phase behavior of an actual produced , lean gas X having a "critical point" "C" of approximately -81°C (- 114°F) at 4758 kPa (690 psia) ;
  • Curve Y represents an actual produced gas-condensate Y having a critical point "C” of -7°C (-20°F) at 20000 kPa (2900 psia) ; and
  • Curve Z represents a rich gas Z having a critical point of -24°C (-12°F) at 10480 kPa (1520 psia) .
  • a selected storage point "S" i. e. , a common temperature and pressure at which each of gases X, Y, and Z will be in the liquid phase
  • S a selected storage point
  • An organic conditioner i . e. , commercial grade propane
  • LHG liquef ied heavy gases
  • the solubility of methane in the LHG is of prime importance to the overall efficiency of LHG transportation since the main objective is to maximize the amount of feed gas that will be liquefied into a LHG while minimizing the liquefication operation.
  • the "organic conditioner" used in the present invention is selected from the lightest hydrocarbons (other than methane) normally found in the natural gas (i. e. , principally ethane and propane with limited quantities of butane and heavier components such as condensates and pentane-plus) . These light hydrocarbons are normally gaseous at ambient conditions.
  • Figure 8 illustrates graphically the results of experiments to test the solubility of methane at 2760 kPa (400 psia) and at 6200 kPa (900 psia) in ethane, propane, butane, and heptane, respectively.
  • Heavier hydrocarbons i. e. , pentanes and heavier
  • they while providing some lowering of the storage pressure of the LHG should be limited in the present organic conditioner in that they not only decrease the solubility of methane in the LHG but they also become insoluble and form solids in particular LHGs under certain conditions of concentration, pressure, and temperatures.
  • the "organic conditioner” changes the original composition of a feed gas to an altered gas which will be in the liquid phase at a selected storage point S.
  • the conditioner is preferably derived directly from the normally gaseous components of produced natural gases , themselves . That is, a portion of the natural gas production in an area can be processed to recover an organic conditioner (e.g. , ethane, propane, butane and C0 2 ) therefrom which, in turn, is then used to form LHG from another portion of the same production.
  • an organic conditioner e.g. , ethane, propane, butane and C0 2
  • the conditioner can originate from other sources, e.g . , back-hauled from other sites to the remote site.
  • the organic condi tioner can be selected from different gaseous light hydrocarbons or mixtu res the reof .
  • Figure 2 shows the effect of adding three different , light hydrocarbon or CO2 organic conditioners to separate samples of the same feed gas, (gas Z of Figure 1 ) to form three gases having different compositions (Z 3 , Z 4 , Z5) , all of which will be in the liquid phase at a predetermined , common selected storage point S (i. e. , -40°C, 1165 psia [8033 kPa] in Figure 2) .
  • Z are commercial grade propane, C0 2 , and commercial grade butane, respectively.
  • These conditioners are added in amounts of 9000, 3600, and 2800 barrels (1440 , 576 and 448 -m 3 respectively) per one hundred million standard cubic feet ( 2.8 x 10 ) of feed gas, respectively, to produce the different gases, Z-r , Z , t Zr, all of which have the same, common storage point S at which each gas is in a liquid phase.
  • Figure 3 plots the phase diagram of further diffe rent gases , Y-, (also plotted in Figure 1) , Y 2 and Y, , formed by adding three different organic condi tioners to feed gas Y wherein the conditioners themselves are deri ved from the feed gas Y. That is , a portion of feed gas Y is processed to extract a component (s) thereof which, in turn, is then added to another portion of feed gas Y to form LHG.
  • the respective conditioners for gases Y, , Y 2 , Y, in Figure 3 are butane; a 40-60 mixture of isobutane/normal butane; and natural gas liquids (a mixture of 44.4 Mol % ethane; 39.4 Mol % propane 6.7 Mol % isobutane; and 9.5 Mol % normal butane) .
  • a particular conditioner for any gi ven feed gas For example, how the LHG is to be processed at its market destination should be considered in selecting the organic conditioner for a particular feed gas. That is, if the LHG is to undergo fractionation at its destination, the LHG should be made up so that a minimum of organic conditioner will remain in the methane gas upon separation to prevent any substantial loss of the conditioner. To do this, the LHG should be "tailored" by matching the organic conditioner to the dominant hydrocarbon component naturally found in the particular feed gas being liquefied. For example, gas X (see TABLE 1) has very little pr ⁇ ane therein.
  • propane as the conditioner for gas X would result in an unavoidable loss of propane during fractionation of the LHG conditioned with propane.
  • ethane would be the preferred organic conditioner for gas X.
  • gas Z has nearly equal quantities of ethane and propane, thus either ethane, propane, or mixtures thereof would be a preferred conditioner.
  • Gas Y has approximately 2.5 times as much ethane as propane and both are insufficient quantities whereby the conditioner should contain more ethane than propane.
  • the liquid conditioner can be easily recovered from the LHG and then back-hauled in the LHG transport ships to the production area for reuse in liquefying additional LHG.
  • the selected storage point S for LHG formed in accordance with the present invention is selected such that the storage temperature, preferably -100°C to -7°C, (-150°F to 20 °F) , is well above cryogenic temperatures and the pressure, preferably 3450 to 9650 kPa (300 to 1400 psia), is low enough so that the LHG can easily be stored and transported using only conventional materials such as commercially-available steel cylinders.
  • This allows a marine vessel which is equipped with standardized storage facilities that are capable of maintaining LHG at the common selected storage point S during transit to be used for transporting LHG regardless of the original composition or source of the LHG.
  • a storage pressure and temperature is selected for the LHG, certain other constraints may be placed on the organic conditioner.
  • the conditioner For normal storage of the conditioner, its composition should be such that it has a vapor pressure above atmospheri c pressure at the storage temperature in order for the conditioner to be back-hauled efficiently to the production area in the same ships that are used to haul the LHG from the production area.
  • FIG. 3 illustrates a simple apparatus 10 that can be used to physically make the same determination.
  • Feed gas e.g . , produced natural gas Z
  • organic conditioner e.g. , pr ⁇ ane
  • the mixture is passed through heat exchanger 13 where it is cooled to the selected storage temperature (e.g. , -40°C) .
  • the cooled mixture is then passed into separator 14 whe rein the pressure is maintained at the selected storage pressure, e.g.
  • FIG. 5 illustrates a system for forming LHG from a feed gas at a producing site.
  • the feed gas ordinary produced natural gas or compressed casing head gas from oil wells
  • the selected storage pressure e. g. , 1200 psia (8270 kPa) through feed line 20.
  • the feed gas passes through filter- separator 21 to remove ent rained solids and the like and through a glycol dehydration unit 22 to produce a dry gas of about -50°F (-46°C) water dew point .
  • any entrained liquids e.g.
  • condensates can be removed by standard separation techniques but with the present invention, it is preferred to leave the condensates in the gas so there will be no need to handle these separately.
  • acid-forming gases e.g. , C0 2 , H 2 S, etc.
  • C0 2 , H 2 S, etc. may be removed by known techniques if they are present in such quantities to present corrosion problems during storage. Otherwise, it is not necessary to remove these components .
  • the dehydrated gas stream is next passed through a refrigeration unit 23 (shown as a three-stage system) to reduce the temperature of the pressurized feed gas to the selected storage temperature (e.g. , -40°C) .
  • a refrigeration unit 23 shown as a three-stage system
  • an inexpensive refrigerant e.g. , propane
  • propane can be used in unit 23 and may be the same material which is used as the organic conditioner.
  • the organic conditioner e.g . , propane, flows through line 24 and is mixed with the feed gas within the refrige ration uni t 23 to form LHG whi ch, in turn, can be temporarily stored in tankage
  • the organic conditioner and/or the refrigerant can be stored aboard vessel 26, if applicable, and the refrigerant compressors 27 can be operated by power (e. g. , steam) from vessel 26 and can be cooled by circulating seawater (not shown) .
  • power e. g. , steam
  • FIG. 6 shows further details of forming and loading LHG into storage containers 30 aboard marine vessel 26.
  • Feed gas is passed under pressure, e. g . , 1200 psia (8270 kPa) from feed line 31 through refrigeration unit 23a to cool the gas stream to the selected storage temperature, e. g . , -40°C.
  • the pressurized, cooled gas is then passed through line 32 to fill all of the containers 30 with feed gas at the selected storage temperature and pressure.
  • organic conditioner e.g. , pr ⁇ ane
  • the LHG is passed into the bottom of each cylinder 30 through line 35 to displace the feed gas out of the top of cylinders and back through refrigeration unit 23a via line 36. This is continued until all of cylinders 30 are filled with LHG.
  • Figu re 7 discloses a system for off-loading LHG once vessel 26 reaches a market port. LHG is in the liquid phase and should be displaced with a gas or other working fizid in order to maintain the pressure of the LHG at the selected storage pressure or the temperature will drop substantially, e.g. , from -40°C to as low as -62°C.
  • the LHG is displaced by a product gas, e. g . , natural gas, which is compressed to the selected storage pressu re.
  • the product gas flows into tops of containers 30 ( Figure 5) the reby forcing the LHG out of the bottom thereof .
  • the LHG flows from vessel 26 ( Figure 6) through line 40 via expansion valve 41 to a standard fractionator 42 (e.g. , de-ethanizer column with reboiler 43) .
  • Expansion of the LHG through valve 41 decreases the temperature of the LHG, e.g. , from -40°C to -68°C while reducing the pressure, e.g . , from 1200 psia (8270 kPa) to 450 psia (3100 kPa) which are typical operating conditions of the fractionator 42.
  • the product gas exits the top of fractionator 42 and flows through line 44 to a pipeline or other use.
  • the heavier hydrocarbon products (ethane plus) from the LHG flow from the bottom of fractionator 42 and through line 45 for use or further processing .
  • a portion of the products in line 45 can be diverted through line 46 and heat exchanged at 47 with the produc gas in line 44 to cool and condense the products which are then returned to vessel 26 to be "back-hauled" for use as organic conditioner in future LHG processes, especially in those instances where there is insufficient organic conditioner available at the production site.

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Abstract

In a process for liquefying a natural gas an organic conditioner, e.g., a gaseous hydrocarbon, which is gaseous at ambient conditions is added to the natural gas to shift the bubble point of the natural gas to a selected storage temperature and pressure at which the gas will be in the liquid phase.

Description

A IftOCESS FOR LIQUEFYING HYDROCARBON GAS
The present invention relates to a process for liquefying hydrocarbon gas (e.g. , natural gas) to produce a liquefied heavy gas (LHG).
Vast reserves of hydrocarbon gas, e.g., natural gas, are known to exist in remote areas of the world. Due to the remoteness of some of these areas, getting the gas to market, once it is produced, presents a formidable problem in the development of these reserves. If the distances and terrain (e.g., sea bottom) are such that pipelines cannot be used to move the gas to market, the gas from these areas must be processed at the remote site and then transported aboard specially-constructed, marine vessels to those market ports which have the proper facilities for off-loading the processed gas.
There are several known processes for treating natural gas at or near a production site to prepare the gas for shipment. These processes typically require separation of the natural gas into its various components (e.g., methane, heavier hydrocarbon gases and condensates) and then liquefying only certain of these components for storage and/or shipment. For example, one sophisticated process involves first separating methane from the gas and then partially oxidizing the methane to form a synthesis gas which, in turn, is catalytically converted to a liquid product, e.g., methanol. Currently this process appears to be of limited application in that it is relatively expensive, has poor conversion efficiency, and produces a product, e.g., methanol, which cannot easily or economically be reconverted into a gaseous product upon reaching its market destination.
Other more commonly used processes for transporting remote gas are those which separate the feed gas into its components and then liquefy only certain of these components by cooling them under pressure to produce, e.g., liquefied natural gas (LNG) and liquefied petroleum gas (LPG). While these processes are different, both have similar drawbacks. That is, both processes liquefy only a portion of a natural gas feed stream and many valuable remaining components of the gas have to be handled separately at significant expense or have to be otherwise disposed of at the remote area.
For example, in a typical LNG process, substantially all those hydrocarbons components in the natural gas which are heavier than propane (some butane may remain), all "condensates" (e.g., 0- pentanes and heavier) in the gas, and all of the solid-forming components (e.g., CO2 and H,S) in the gas must be removed before the remaining components (e.g., methane, ethane, and propane) are cooled to cryogenic temperatures, e.g., -160°C (-260°F). The equipment and compressor horsepower required to achieve these *55 temperatures are considerable thereby making any LNG system expensive to build and operate at the producing or remote site. Further, specialized storage facilities are required aboard specially-constructed marine vessels for transporting LNG. Still further, equally expensive off-loading and revaporization acilities 0~ are required for handling the LNG at the market port.
In an LPG process, only propane and possibly some butane are extracted from the natural gas feed stream and are cooled to a low temperature, e.g., from -70 to -40°C (-90 to -40°F) while maintaining the cooled components at a pressure of 110 Pa (16 psia) 5; in storage. Due to the higher temperature, an LPG process is cheaper to build and operate than an LNG process but the methane and ethane components of the natural gas are either sacrificed or must be handled separately, thereby making LPG less commercially attractive overall. Further, since LPG must be maintained at -40 to 0 -18°C (-40 to 0°F) while cyrogenic I-NG must be maintained at -160°C (-260°F), the storage facilities used for transporting LPG are substantially different from those required for transporting LNG so that the two processes are not readily interchangeble. As mentioned above, in both LNG and LPG processes, any condensates in the natural gas feed stream have to be separated and handled separately from either LNG or LPG, thereby requiring separate storage facilities for transport which obviously adds to their overall cost.
Other processes for transporting natural gas include those known as "medium condition liquefied gas" (MLG) and "compressed natural gas" (CNG) both of which are purported to provide an overall saving when compared to the LNG process, see "A New Process for the Transportation of Natural Gas", R. J. Broeker, Session No. 5, Paper 30, PROCEEDINGS OF FIRST INTERNATIONAL CONFERENCE on LNG, Chicago, Illinois, April 7-12, 1968. MLG differs from LNG in that low cryogenic temperatures are not required (i.e., -115°C versus -160°C) but the pressure is higher (i.e, 1480 kPa versus atmospheric). However, as with LNG and LPG, MLG requires that any condensates in the natural gas feed stream be removed before liquefication and must be handled separately from the MLG. Further, specialized storage facilities are require^ for transporting MLG which are substantially different from either LNG or LPG storage facilities with none of these storage facilities being interchangeable without substantial modification.
CNG merely involves compressing natural gas under extremely high pressures, e.g., 20700 kPa (3000 psi) at ambient temperatures. However, since the gas is not liquefied at these conditions, the volumetric efficiency of CNG does not make this process attractive for transporting large volumes of gas over long distances.
Still another process for transporting natural gas proposes to saturate the natural gas with a liquid organic additive whereby the gas-additive mixture will liquefy at a higher temperature than that of the gas alone; see U.S. Patent 4,010,622. The additive is selected from hydrocarbons, alcohols, or esters having a chain length of Cς to C-Q and which is liquid at ambient conditions. While this mixture does liquefy at higher temperatures thereby decreasing the refrigeration costs involved, the resulting liquefied ixture presents certain problems. First, the solubility of methane decreases as the molecular weight of the additive increases so with heavier hydrocarbon additives, less methane can be liquefied. Further, when the liquefied gas product is delivered to market, the added heavier hydrocarbons hinder the vaporization or regasification of the product. Volumes of air have to be mixed with the liquefied mixture as it is vaporized to provide the ultimate fuel product which present safety hazards in the handling of gas-air mixtures.
In view of the above, it can readily be seen that a need exists for a process by which basically the entire composition of a natural gas, regardless of its origin or original composition, can be readily processed and liquefied at a remote site without requiring the removal and separate handling of various components of the gas. Further, it is highly desirable that the gas, once liquefied, can be transported in a vessel having standardized storage facilities whereby any marine vessel having such.storage facilities can doc at any port and take on a single liquid gas product which has been produced from a gas feed stream regardless of the original source or composition of the feed stream. Still further, it is desirable that the liquefied gas can be easily regasified once it has reached its destination.
Accordingly, the invention resides in a process for liquefying hydrocarbon gas comprising: adding an organic conditioner which is normally gaseous at ambient conditions to said hydrocarbon gas to change the composition of said hydrocarbon gas and form an altered gas having a composition which will be in a liquid phase at a selected storage tmeperature and pressure; and cooling said altered gas to at least said selected storage temperature and maintaining said altered gas at said selected storage pressure to form a liquefied heavy gas.
The present invention provides a process for liquefying substantially any hydrocarbon gas, e.g., natural gas, wherein all of the components of the gas are liquefied into a single, liquefied heavy gas (LHG) . The present process will liquefy natural gases produced from different sources which may have substantially different original compositions (e.g . , lean gas, rich gas, gas with substantial amounts of condensates and gases produced with crude oil ) . Further, LHGs liquefied from feed gases having different compositions are always in the liquid phase at the same common, selected storage temperature and pressure regardless of their original composition. This permits LHGs formed from natural gases of different original compositions to be stored and shipped in the same, standardized storage containers . Accordingly, any marine vessel equipped with such storage containers can be used to transport LHG regardless of its origin or original composition. Further, there is no need to have separate storage available on board the vessel for condensates and/or other individual components of the natural gas since all of these are liquefied in the LHG.
More specifically, the present invention relates to a process for liquefying natural gas wherein an "organic conditioner" is added to the natural gas feed stream after it has been dehydrated to change the composition of the natural gas and thereby form an altered gas which has a composition that will be in the liquid phase at a selected storage temperature and pressure. The altered gas stream is then cooled to at least the selected storage temperature , e.g . , -40°C, while the gas is maintained at the selected storage pressure, e.g . , 8380 kPa (1200 psia) , to thereby form LHG. The selected storage temperature is selected so that it is well above cryogenic temperatures requi red for LNG (e.g . , -160°C or -260°F) . LHG' s higher temperature significantly reduces the compressor horsepower needed for the LHG system when compared to that for a LNG system ( i. e. , up to a 90% reduction in compressor horsepower) . Further, the selected storage pressure can be low enough (e.g. , 8380 kPa or 1200 psia) that LHG can be stored and transported in storage containers made from relatively inexpensive materials (e.g . , commercially available steel storage cylinders) with no expensive alloys being required as is the case with LNG storage. The organic conditioner used to alter the original composition of the natural gas is a low molecular weight organic compound or mixture therof (e.g. , ethane, propane, butane and COj which is a gas at ambient conditions and which when added to the natural gas will shift the bubble point of the altered gas to the selected storage temperature and pressure. The actual organic conditioner and the amount thereof will depend upon the original composition of the particular natural gas to be liquefied and can easily be determined once the particulars are known. That is, it is preferred to "tailor" each natural gas to be liquefied by matching the organic conditioner to a predominant light hydrocarbon fraction present in the original natural gas. For example, if a natural gas has a predominant amount of ethane, then ethane is the preferred organic conditioner. This allows the liquid conditioner to be easily recovered from the LHG at its destination by known means, e.g. , fractionation, whereby the conditioner can be "back-hauled" to a production area in the otherwise empty LHG ships for reuse in the liquification process.
LHG offers many advantages over other known gas liquefication processes, some of these being: a. Substantially less horsepower (up to 90% less than LNG) is required to liquefy LHG. b. LPG is included in LHG while butane is normally limited in LNG. c. Condensates are included in LHG while they must be separated and handled separately with LNG. d. The overall thermal efficiency from well head to burner tip is about 95% with LHG compared to about 70% with LNG. e. Significantly less pretreatment is required for LHG, e.g. , the feed natural gas for LHG need only to be pretreated to pipeline conditions (e.g . , dehydrated and acid-foimiπg gases removed if present in large quantities) while the gas feed for LNG has to be treated to further remove condensates, solid-forming compounds (e. g . , (X- ) . The only advantage that LNG would appear to have over LHG is that due to the much lower temperature of ING as compared to that of LHG, LNG will have a greater density than LHG and , accordingly, less storage is needed with LNG to transport the same volume of natural gas. However , any costs resulting in the increased storage requirements for LHG transportation are more than offset by the savings in the liquefication and handling costs of LHG when compared to those involved in LNG.
The invention will be more particularly described with reference to the accompanying drawings in which like numerals identify like parts and in which:
Figure 1 is a phase diagram of three hydrocarbon gases of different composition before and after the same organic conditioner has been added to each in accordance with the present invention to establish a common bubble point ( i. e. , selected storage point) for all of the gases;
Figure 2 is a phase diagram of a single hydrocarbon gas wherein three different organic conditioners have been added thereto in accordance with the present invention to produce three gases having a common bubble point temperature and pressure;
Figure 3 is a phase diagram of another single hydrocarbon gas wherein three different organic conditioners that could be made from said gas have been added to another portion of the same gas in accordance with the present invention to produce three gases having a common bubble point temperature and pressure.
Figure 4 is a schematic view of a system used to determine the amount of an organic conditioner to be added to a particular feed gas to form LHG in accordance with the present invention;
Figure 5 is a schematic view of a LHG liquefication system; Figure 6 is a schematic view of a LHG storage and transportation system;
Figure 7 is a schematic vi ew of a LHG off-loading system; and
Figure 8 is a graph depicting the results of experiments dete rmining the solubility of methane in hydrocarbon liquids having different molecular weights . The chemical composition of common hydrocarbon gases, e.g., natural gas, can vary substantially depending on the source from which the gas originates. That is, there are lean gases (i.e., substantially methane), rich gases (i.e., methane plus substantial amounts of heavier hydrocarbon components) , and many gases of varying compositions in between. For example, the following represents the compositions of three actual produced gases, i.e., X, Y and Z:
0 TABLE I
GAS Type
5
N2
°°2 O3 0 C2H6
C3H8
2C4H10 nC4H10 2C5H12 nC5H12
2-5* C6+
Figure imgf000010_0001
The liquid-gas phase behavior of any gas will differ depending on its particular composition. That is, a rich gas will aσ have a higher cri tical point (e.g . , temperature above which the gas cannot exist as a liquid) than that of a leaner gas. By changing the composition of a particular gas, its phase behavior, e.g . , critical point, can also be changed. By changing the critical temperature, the bubble point line is changed to allow the storage pressure to be selected in a cost effective manner for the storage containers required. In accordance with the present invention, the phase behavior of particular gas is changed by adding an organic conditioner thereto before it is liquefied. That is, the composition of a feed gas is changed so that its cri tical point is changed to a point where the altered gas is always in the liquid phase at a selected temperature and pressure, collectively called "selected storage point" . The selected storage point is selected so that different hydrocarbon gases whi ch are conditioned in accordance with the present invention will be li quid at the same, common selected storage point . This allows gases of different composition from different areas to be conditioned so that all are in a liquid phase at the same temperature and pressure the reby facilitating transport and/or storage of the liquefied gases in standa rdi zed vessels. Figure 1 is a phase diagram for the three hydrocarbon gases
X, Y and Z before and after they have been processed in accordance with the present invention. Curve X represents the phase behavior of an actual produced , lean gas X having a "critical point" "C" of approximately -81°C (- 114°F) at 4758 kPa (690 psia) ; Curve Y represents an actual produced gas-condensate Y having a critical point "C" of -7°C (-20°F) at 20000 kPa (2900 psia) ; and Curve Z represents a rich gas Z having a critical point of -24°C (-12°F) at 10480 kPa (1520 psia) .
In accordance with the present invention, a selected storage point "S" ( i. e. , a common temperature and pressure at which each of gases X, Y, and Z will be in the liquid phase) is selected ; this being -40°C, 8033 kPa (-40 °F, 1165 psia) in Figure 1. An organic conditioner (i . e. , commercial grade propane) is added and mixed with each of the gases X, Y, Z in amounts calculated to produce liquef ied heavy gases (LHG) X Y Z, having compositions such that each will be in the liquid phase at the selected storage point S. The cri tical point C of each gas is also changed substantially, i. e. , -16°C (4 °F) at 9653 kPa ( 1400 psia) for gas X1 ; -21°C (-6°F) at 10653 kPa (1545 psia) for gas Yj and -8°C (18°F) at 1066 kPa (1605 psia) for gas Zχ, all of which are above the selected storage point S. This means that each of the gases will remain in the liquid even at temperatures above the selected storage point S , (i. e, up to their respective critical points "C" as seen in Figure 1) . This is highly beneficial in storing and transporting a particular LHG in that the actual storage temperature can rise above the selected storage temperature without the LHG vaporizing.
The solubility of methane in the LHG is of prime importance to the overall efficiency of LHG transportation since the main objective is to maximize the amount of feed gas that will be liquefied into a LHG while minimizing the liquefication operation. Since the solubility of methane in normal hydrocarbons decreases as the molecular weight, of the hydrocarbons increases, the "organic conditioner" used in the present invention is selected from the lightest hydrocarbons (other than methane) normally found in the natural gas (i. e. , principally ethane and propane with limited quantities of butane and heavier components such as condensates and pentane-plus) . These light hydrocarbons are normally gaseous at ambient conditions. Figure 8 illustrates graphically the results of experiments to test the solubility of methane at 2760 kPa (400 psia) and at 6200 kPa (900 psia) in ethane, propane, butane, and heptane, respectively. Heavier hydrocarbons (i. e. , pentanes and heavier) while providing some lowering of the storage pressure of the LHG should be limited in the present organic conditioner in that they not only decrease the solubility of methane in the LHG but they also become insoluble and form solids in particular LHGs under certain conditions of concentration, pressure, and temperatures.
The "organic conditioner" changes the original composition of a feed gas to an altered gas which will be in the liquid phase at a selected storage point S. The conditioner is preferably derived directly from the normally gaseous components of produced natural gases , themselves . That is, a portion of the natural gas production in an area can be processed to recover an organic conditioner (e.g. , ethane, propane, butane and C02) therefrom which, in turn, is then used to form LHG from another portion of the same production. However, the conditioner can originate from other sources, e.g . , back-hauled from other sites to the remote site. As mentioned above, the organic condi tioner can be selected from different gaseous light hydrocarbons or mixtu res the reof . By way of illust ration , Figure 2 shows the effect of adding three different , light hydrocarbon or CO2 organic conditioners to separate samples of the same feed gas, (gas Z of Figure 1 ) to form three gases having different compositions (Z3, Z4, Z5) , all of which will be in the liquid phase at a predetermined , common selected storage point S (i. e. , -40°C, 1165 psia [8033 kPa] in Figure 2) . The organic conditioners added to Z to form altered gases Z, , Z . , Z are commercial grade propane, C02 , and commercial grade butane, respectively. These conditioners are added in amounts of 9000, 3600, and 2800 barrels (1440 , 576 and 448 -m3 respectively) per one hundred million standard cubic feet ( 2.8 x 10 ) of feed gas, respectively, to produce the different gases, Z-r , Z , t Zr, all of which have the same, common storage point S at which each gas is in a liquid phase.
Figure 3 plots the phase diagram of further diffe rent gases , Y-, (also plotted in Figure 1) , Y2 and Y, , formed by adding three different organic condi tioners to feed gas Y wherein the conditioners themselves are deri ved from the feed gas Y. That is , a portion of feed gas Y is processed to extract a component (s) thereof which, in turn, is then added to another portion of feed gas Y to form LHG. The respective conditioners for gases Y, , Y2 , Y, in Figure 3 are butane; a 40-60 mixture of isobutane/normal butane; and natural gas liquids (a mixture of 44.4 Mol % ethane; 39.4 Mol % propane 6.7 Mol % isobutane; and 9.5 Mol % normal butane) .
Other factors also enter into the selection of a particular conditioner for any gi ven feed gas. For example, how the LHG is to be processed at its market destination should be considered in selecting the organic conditioner for a particular feed gas. That is, if the LHG is to undergo fractionation at its destination, the LHG should be made up so that a minimum of organic conditioner will remain in the methane gas upon separation to prevent any substantial loss of the conditioner. To do this, the LHG should be "tailored" by matching the organic conditioner to the dominant hydrocarbon component naturally found in the particular feed gas being liquefied. For example, gas X (see TABLE 1) has very little prφane therein. Therefore, the use of propane as the conditioner for gas X would result in an unavoidable loss of propane during fractionation of the LHG conditioned with propane. According ly, ethane would be the preferred organic conditioner for gas X. As seen from TABLE I, gas Z has nearly equal quantities of ethane and propane, thus either ethane, propane, or mixtures thereof would be a preferred conditioner. Gas Y has approximately 2.5 times as much ethane as propane and both are insufficient quantities whereby the conditioner should contain more ethane than propane.
By tailoring the LHG for efficient separation at its destination, e. g. , by fractionation, the liquid conditioner can be easily recovered from the LHG and then back-hauled in the LHG transport ships to the production area for reuse in liquefying additional LHG.
As mentioned above, the selected storage point S for LHG formed in accordance with the present invention is selected such that the storage temperature, preferably -100°C to -7°C, (-150°F to 20 °F) , is well above cryogenic temperatures and the pressure, preferably 3450 to 9650 kPa (300 to 1400 psia), is low enough so that the LHG can easily be stored and transported using only conventional materials such as commercially-available steel cylinders. This allows a marine vessel which is equipped with standardized storage facilities that are capable of maintaining LHG at the common selected storage point S during transit to be used for transporting LHG regardless of the original composition or source of the LHG. When a storage pressure and temperature is selected for the LHG, certain other constraints may be placed on the organic conditioner. For normal storage of the conditioner, its composition should be such that it has a vapor pressure above atmospheri c pressure at the storage temperature in order for the conditioner to be back-hauled efficiently to the production area in the same ships that are used to haul the LHG from the production area.
The amounts of a particular organic condi tioner needed to change the composition of a feed gas having a known composition to an altered gas whi ch will be in the liquid phase at a selected storage point can be readily determined from known phase relationships. Figure 3 illustrates a simple apparatus 10 that can be used to physically make the same determination. Feed gas (e.g . , produced natural gas Z) from line 11 is mixed with organic conditioner (e.g. , prφane) from line 12 and the mixture is passed through heat exchanger 13 where it is cooled to the selected storage temperature (e.g. , -40°C) . The cooled mixture is then passed into separator 14 whe rein the pressure is maintained at the selected storage pressure, e.g. , 1200 psia (8270 kPa) . The amount of conditioner added to the flowstream of gas Z is increased until the mixture in separator 14 is completely in the liquid phase and no vapor is escaping through the gas outlet 15 of separator 14. This is an easy way to determine how much of a particular organic conditioner needs to be added to a particular gas to produce LHG at a selected temperature and pressure. Of course, in some instances, vapor may be removed from separator 14 in a continuous manner to produce a liquid phase, LHG, wherein the removed vφor may be used for fuel or to othe rwise enhance the liquefaction cycle.
The following table compares the calculated amounts of conditioner added to the gases X, Y, Z shown in Figures 1-3 and the densities and the storage volumes of the resulting LHG. -14-
LHG* LHG STORAGE VOL, CONDITIO
GAS CONDITIONER DENSITY OF FEED GAS FEED GAS lb/ft3(kg/m3) nrVlOOMMSCF Bbls/IOO (m3/10°m3) (m3/106m
20.6 (333.7) 10, 200 (3600) 15 ,900 ( 8 24.5 (411.5) 9,000 (3180) 12 ,700 (7
22.4 (362.9) 8 , 200 (2900) 3 , 800 (2 26.0 (421.2) 8 ,300 (2930) 9,000 (5
22.5 (364.5) 8 ,600 (3040) 3,600 (2 22.4 (362.9) 8, 200 (2900) 2, 800 (1
28.6 (463.3) 9,480 (3350) 17 ,500 (9
Figure imgf000016_0001
23.8 (385.6) 9, 160 (3240) 14, 100 (7
*Bubble point = -40°C, 1165 psia (8033 kPa)
Figure 5 illustrates a system for forming LHG from a feed gas at a producing site. The feed gas (ordinary produced natural gas or compressed casing head gas from oil wells) is fed at the selected storage pressure, e. g. , 1200 psia (8270 kPa) through feed line 20. As will be understood in the gas processing art, the feed gas passes through filter- separator 21 to remove ent rained solids and the like and through a glycol dehydration unit 22 to produce a dry gas of about -50°F (-46°C) water dew point . Of course, any entrained liquids (e.g. , condensates) can be removed by standard separation techniques but with the present invention, it is preferred to leave the condensates in the gas so there will be no need to handle these separately. Also, acid-forming gases, e.g. , C02 , H2S, etc. , may be removed by known techniques if they are present in such quantities to present corrosion problems during storage. Otherwise, it is not necessary to remove these components .
The dehydrated gas stream is next passed through a refrigeration unit 23 (shown as a three-stage system) to reduce the temperature of the pressurized feed gas to the selected storage temperature (e.g. , -40°C) . Since cyrogenic temperatures are not required, an inexpensive refrigerant , e.g. , propane, can be used in unit 23 and may be the same material which is used as the organic conditioner. The organic conditioner, e.g . , propane, flows through line 24 and is mixed with the feed gas within the refrige ration uni t 23 to form LHG whi ch, in turn, can be temporarily stored in tankage
25 or loaded di rectly into the storage facili ties of ma rine vessel
26 for transportation to market. The organic conditioner and/or the refrigerant can be stored aboard vessel 26, if applicable, and the refrigerant compressors 27 can be operated by power (e. g. , steam) from vessel 26 and can be cooled by circulating seawater (not shown) .
Figure 6 shows further details of forming and loading LHG into storage containers 30 aboard marine vessel 26. Feed gas is passed under pressure, e. g . , 1200 psia (8270 kPa) from feed line 31 through refrigeration unit 23a to cool the gas stream to the selected storage temperature, e. g . , -40°C. The pressurized, cooled gas is then passed through line 32 to fill all of the containers 30 with feed gas at the selected storage temperature and pressure. Next, organic conditioner, e.g. , prφane, is pumped from source 33 into thέ feed gas through line 34 to mix the rewith as it passes through refrigeration unit 23a to form LHG. The LHG is passed into the bottom of each cylinder 30 through line 35 to displace the feed gas out of the top of cylinders and back through refrigeration unit 23a via line 36. This is continued until all of cylinders 30 are filled with LHG.
Once the cylinders 30 are full, the feed gas is stopped and LHG is ci rculated through the enti re system to make sure that containers 30 , insulation, etc. , are all at temperature equilibrium to eliminate any possibility of dissimilar temperatu res if the LHG refrigeration unit 23a is not a permanent part of the marine vessel. Figu re 7 discloses a system for off-loading LHG once vessel 26 reaches a market port. LHG is in the liquid phase and should be displaced with a gas or other working f luid in order to maintain the pressure of the LHG at the selected storage pressure or the temperature will drop substantially, e.g. , from -40°C to as low as -62°C. As illust rated, the LHG is displaced by a product gas, e. g . , natural gas, which is compressed to the selected storage pressu re. The product gas flows into tops of containers 30 (Figure 5) the reby forcing the LHG out of the bottom thereof . The LHG flows from vessel 26 (Figure 6) through line 40 via expansion valve 41 to a standard fractionator 42 (e.g. , de-ethanizer column with reboiler 43) . Expansion of the LHG through valve 41 decreases the temperature of the LHG, e.g. , from -40°C to -68°C while reducing the pressure, e.g . , from 1200 psia (8270 kPa) to 450 psia (3100 kPa) which are typical operating conditions of the fractionator 42.
The product gas (e.g . , methane) exits the top of fractionator 42 and flows through line 44 to a pipeline or other use. The heavier hydrocarbon products (ethane plus) from the LHG flow from the bottom of fractionator 42 and through line 45 for use or further processing . A portion of the products in line 45 can be diverted through line 46 and heat exchanged at 47 with the produc gas in line 44 to cool and condense the products which are then returned to vessel 26 to be "back-hauled" for use as organic conditioner in future LHG processes, especially in those instances where there is insufficient organic conditioner available at the production site.

Claims

CLAIMS:
1. A process for liquefying hydrocarbon gas comprising : adding an organic conditioner which is normally gaseous at ambient conditions to said hydrocarbon gas to change the composition of said hydrocarbon gas and form an altered gas having a composition whi ch will be in a liquid phase at a selected storage tmeperature and pressure; and cooling said altered gas to at least said selected storage temperature and maintaining said alte red gas at said selected storage pressure to form a liquefied heavy gas.
2. The process of claim 1 wherein said selected storage temperature is between -100°C and -7°C (- 150 and 20°F ) and' said selected storage pressure is between 3450 and 9650 kPa ( 300 and 1400 psia) .
3. The process of claim 1 whe rein the organic conditioner comprises ethane, prφane, butane, C02, or a mixture thereof .
4. The process of claim 1 wherein said hydrocarbon gas is dehydrated before said organic conditioner is added thereto.
PCT/US1989/002916 1988-07-11 1989-06-30 A process for liquefying hydrocarbon gas WO1990000589A1 (en)

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US6460721B2 (en) 1999-03-23 2002-10-08 Exxonmobil Upstream Research Company Systems and methods for producing and storing pressurized liquefied natural gas
US6539747B2 (en) 2001-01-31 2003-04-01 Exxonmobil Upstream Research Company Process of manufacturing pressurized liquid natural gas containing heavy hydrocarbons
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EP1040305A4 (en) * 1997-12-19 2005-05-18 Exxonmobil Upstream Res Co PROCESS PARTS, TANKS AND TUBES SUITABLE FOR STORAGE AND PROMOTION OF DEEP TEMPERATURE MEDIA
EP1021675A4 (en) * 1997-06-20 2005-08-17 Exxonmobil Upstream Res Co SYSTEM FOR THE DISTRIBUTION OF LIQUEFUL NATURAL GAS WITH THE HELP OF A LAND VEHICLE
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