US20070157663A1 - Configurations and methods of integrated NGL recovery and LNG liquefaction - Google Patents
Configurations and methods of integrated NGL recovery and LNG liquefaction Download PDFInfo
- Publication number
- US20070157663A1 US20070157663A1 US11/479,320 US47932006A US2007157663A1 US 20070157663 A1 US20070157663 A1 US 20070157663A1 US 47932006 A US47932006 A US 47932006A US 2007157663 A1 US2007157663 A1 US 2007157663A1
- Authority
- US
- United States
- Prior art keywords
- stream
- absorber
- demethanizer
- product
- separator
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
- 238000011084 recovery Methods 0.000 title claims abstract description 58
- 238000000034 method Methods 0.000 title claims description 47
- 239000006096 absorbing agent Substances 0.000 claims abstract description 60
- 230000006835 compression Effects 0.000 claims abstract description 14
- 238000007906 compression Methods 0.000 claims abstract description 14
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims description 101
- 239000007789 gas Substances 0.000 claims description 100
- 239000003949 liquefied natural gas Substances 0.000 claims description 56
- 239000003345 natural gas Substances 0.000 claims description 38
- 238000010992 reflux Methods 0.000 claims description 24
- 238000010438 heat treatment Methods 0.000 claims description 5
- 230000007935 neutral effect Effects 0.000 claims description 3
- 238000005057 refrigeration Methods 0.000 abstract description 50
- 239000003507 refrigerant Substances 0.000 abstract description 37
- 238000001816 cooling Methods 0.000 abstract description 15
- 238000009833 condensation Methods 0.000 abstract description 2
- 230000005494 condensation Effects 0.000 abstract description 2
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical compound CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 description 36
- 239000001294 propane Substances 0.000 description 18
- 239000007788 liquid Substances 0.000 description 16
- OTMSDBZUPAUEDD-UHFFFAOYSA-N Ethane Chemical compound CC OTMSDBZUPAUEDD-UHFFFAOYSA-N 0.000 description 14
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 8
- 229930195733 hydrocarbon Natural products 0.000 description 8
- 238000004519 manufacturing process Methods 0.000 description 8
- 239000000203 mixture Substances 0.000 description 8
- 150000002430 hydrocarbons Chemical class 0.000 description 7
- 238000002156 mixing Methods 0.000 description 6
- 238000000926 separation method Methods 0.000 description 5
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 description 4
- 238000010521 absorption reaction Methods 0.000 description 4
- 238000005265 energy consumption Methods 0.000 description 4
- 229910052757 nitrogen Inorganic materials 0.000 description 4
- 230000008016 vaporization Effects 0.000 description 4
- UHOVQNZJYSORNB-UHFFFAOYSA-N Benzene Chemical compound C1=CC=CC=C1 UHOVQNZJYSORNB-UHFFFAOYSA-N 0.000 description 3
- VGGSQFUCUMXWEO-UHFFFAOYSA-N Ethene Chemical compound C=C VGGSQFUCUMXWEO-UHFFFAOYSA-N 0.000 description 3
- 239000005977 Ethylene Substances 0.000 description 3
- VLKZOEOYAKHREP-UHFFFAOYSA-N n-Hexane Chemical compound CCCCCC VLKZOEOYAKHREP-UHFFFAOYSA-N 0.000 description 3
- 239000004215 Carbon black (E152) Substances 0.000 description 2
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 2
- 230000015572 biosynthetic process Effects 0.000 description 2
- 229910002092 carbon dioxide Inorganic materials 0.000 description 2
- 239000002131 composite material Substances 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 239000000446 fuel Substances 0.000 description 2
- 239000002737 fuel gas Substances 0.000 description 2
- NNPPMTNAJDCUHE-UHFFFAOYSA-N isobutane Chemical compound CC(C)C NNPPMTNAJDCUHE-UHFFFAOYSA-N 0.000 description 2
- -1 methane hydrocarbons Chemical class 0.000 description 2
- 239000003921 oil Substances 0.000 description 2
- OFBQJSOFQDEBGM-UHFFFAOYSA-N Pentane Chemical class CCCCC OFBQJSOFQDEBGM-UHFFFAOYSA-N 0.000 description 1
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 1
- 150000004945 aromatic hydrocarbons Chemical class 0.000 description 1
- 238000009835 boiling Methods 0.000 description 1
- 239000001569 carbon dioxide Substances 0.000 description 1
- 239000000969 carrier Substances 0.000 description 1
- 239000003245 coal Substances 0.000 description 1
- 239000000356 contaminant Substances 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 230000003467 diminishing effect Effects 0.000 description 1
- 238000004821 distillation Methods 0.000 description 1
- 238000000605 extraction Methods 0.000 description 1
- 238000005194 fractionation Methods 0.000 description 1
- 238000007710 freezing Methods 0.000 description 1
- 230000008014 freezing Effects 0.000 description 1
- 239000003502 gasoline Substances 0.000 description 1
- 150000008282 halocarbons Chemical class 0.000 description 1
- 229910000037 hydrogen sulfide Inorganic materials 0.000 description 1
- 239000003077 lignite Substances 0.000 description 1
- 238000011068 loading method Methods 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- IJDNQMDRQITEOD-UHFFFAOYSA-N n-butane Chemical compound CCCC IJDNQMDRQITEOD-UHFFFAOYSA-N 0.000 description 1
- 238000005201 scrubbing Methods 0.000 description 1
- 229910052717 sulfur Inorganic materials 0.000 description 1
- 239000011593 sulfur Substances 0.000 description 1
- 238000011144 upstream manufacturing Methods 0.000 description 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 1
- 229910001868 water Inorganic materials 0.000 description 1
Images
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
- 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
-
- 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
- F25J1/0032—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production using the feed stream itself or separated fractions from it, i.e. "internal refrigeration"
- F25J1/0035—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production using the feed stream itself or separated fractions from it, i.e. "internal refrigeration" by gas expansion with extraction of work
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
- F25J1/003—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production
- F25J1/0032—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production using the feed stream itself or separated fractions from it, i.e. "internal refrigeration"
- F25J1/0045—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the kind of cold generation within the liquefaction unit for compensating heat leaks and liquid production using the feed stream itself or separated fractions from it, i.e. "internal refrigeration" by vaporising a liquid return stream
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
- F25J1/003—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
- F25J1/02—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
- F25J1/0207—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 at least a three level SCR refrigeration cascade
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
- F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
- F25J1/0211—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process using a multi-component refrigerant [MCR] fluid in a closed vapor compression cycle
- F25J1/0217—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process using a multi-component refrigerant [MCR] fluid in a closed vapor compression cycle as at least a three level refrigeration cascade with at least one MCR cycle
- F25J1/0218—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process using a multi-component refrigerant [MCR] fluid in a closed vapor compression cycle as at least a three level refrigeration cascade with at least one MCR cycle with one or more SCR cycles, e.g. with a C3 pre-cooling cycle
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
- F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
- F25J1/0228—Coupling of the liquefaction unit to other units or processes, so-called integrated processes
- F25J1/0229—Integration with a unit for using hydrocarbons, e.g. consuming hydrocarbons as feed stock
- F25J1/0231—Integration with a unit for using hydrocarbons, e.g. consuming hydrocarbons as feed stock for the working-up of the hydrocarbon feed, e.g. reinjection of heavier hydrocarbons into the liquefied 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
- F25J1/0228—Coupling of the liquefaction unit to other units or processes, so-called integrated processes
- F25J1/0235—Heat exchange integration
- F25J1/0237—Heat exchange integration integrating refrigeration provided for liquefaction and purification/treatment of the gas to be liquefied, e.g. heavy hydrocarbon removal from natural gas
- F25J1/0239—Purification or treatment step being integrated between two refrigeration cycles of a refrigeration cascade, i.e. first cycle providing feed gas cooling and second cycle providing overhead gas cooling
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
- F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
- F25J1/0243—Start-up or control of the process; Details of the apparatus used; Details of the refrigerant compression system used
- F25J1/0279—Compression of refrigerant or internal recycle fluid, e.g. kind of compressor, accumulator, suction drum etc.
- F25J1/0291—Refrigerant compression by combined gas compression and liquid pumping
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
- F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
- F25J1/0243—Start-up or control of the process; Details of the apparatus used; Details of the refrigerant compression system used
- F25J1/0279—Compression of refrigerant or internal recycle fluid, e.g. kind of compressor, accumulator, suction drum etc.
- F25J1/0292—Refrigerant compression by cold or cryogenic suction of the refrigerant gas
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- 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
- F25J2200/04—Processes or apparatus using separation by rectification in a dual 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
- F25J2200/00—Processes or apparatus using separation by rectification
- F25J2200/72—Refluxing the column with at least a part of the totally condensed overhead 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
- F25J2200/00—Processes or apparatus using separation by rectification
- F25J2200/78—Refluxing the column with a liquid stream originating from an upstream or downstream fractionator column
-
- 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
- F25J2205/02—Processes or apparatus using other separation and/or other processing means using simple phase separation in a vessel or drum
- F25J2205/04—Processes or apparatus using other separation and/or other processing means using simple phase separation in a vessel or drum in the feed line, i.e. upstream of the fractionation step
-
- 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
- F25J2215/00—Processes characterised by the type or other details of the product stream
- F25J2215/62—Ethane or ethylene
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2220/00—Processes or apparatus involving steps for the removal of impurities
- F25J2220/60—Separating impurities from natural gas, e.g. mercury, cyclic hydrocarbons
- F25J2220/62—Separating low boiling components, e.g. He, H2, N2, Air
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2230/00—Processes or apparatus involving steps for increasing the pressure of gaseous process streams
- F25J2230/08—Cold compressor, i.e. suction of the gas at cryogenic temperature and generally without afterstage-cooler
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2230/00—Processes or apparatus involving steps for increasing the pressure of gaseous process streams
- F25J2230/60—Processes or apparatus involving steps for increasing the pressure of gaseous process streams the fluid being hydrocarbons or a mixture of hydrocarbons
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2240/00—Processes or apparatus involving steps for expanding of process streams
- F25J2240/02—Expansion of a process fluid in a work-extracting turbine (i.e. isentropic expansion), e.g. 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
- F25J2245/00—Processes or apparatus involving steps for recycling of process streams
- F25J2245/02—Recycle of a stream in general, e.g. a by-pass stream
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2270/00—Refrigeration techniques used
- F25J2270/02—Internal refrigeration with liquid vaporising loop
-
- 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
- F25J2270/00—Refrigeration techniques used
- F25J2270/12—External refrigeration with liquid vaporising loop
-
- 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
- F25J2270/00—Refrigeration techniques used
- F25J2270/60—Closed external refrigeration cycle with single component refrigerant [SCR], e.g. C1-, C2- or C3-hydrocarbons
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2270/00—Refrigeration techniques used
- F25J2270/66—Closed external refrigeration cycle with multi component refrigerant [MCR], e.g. mixture of hydrocarbons
Definitions
- the field of the invention is natural gas liquids (NGL) recovery and liquefied natural gas (LNG) liquefaction, and particularly integrated plant configurations for such processes.
- NNL natural gas liquids
- LNG liquefied natural gas
- Natural gas is typically recovered from oil and gas production wells located onshore and offshore. Depending on the particular formation and reservoir, natural gas also contains relatively low quantities of non-methane hydrocarbons, including ethane, propane, i-butane, n-butane, pentanes, hexane and heavier components, as well as water, nitrogen, carbon dioxide, hydrogen sulfide, mercaptans, and other gases.
- non-methane hydrocarbons including ethane, propane, i-butane, n-butane, pentanes, hexane and heavier components, as well as water, nitrogen, carbon dioxide, hydrogen sulfide, mercaptans, and other gases.
- Natural gas from the wellheads is commonly treated to remove sulfur components, compressed, and transported to consumers in high pressure pipelines.
- natural gas is commonly transported by liquefying the natural gas and transporting the gas in liquid form (e.g., using LNG cargo carriers).
- liquefaction of natural gas is problematic as natural gas also contains aromatics (e.g., benzene) and heavy hydrocarbons, which solidify when chilled to the cryogenic temperatures. Consequently, most aromatic hydrocarbons must be removed to an extremely low level (typically less than 1 ppmv) to avoid freezing and plugging the cryogenic heat exchange equipment.
- lighter hydrocarbons such as C2, C3 and C4 must be removed when LNG is imported to the North America natural gas market, which typically requires a leaner natural gas.
- Typical North America pipeline gas contains mostly the clean burning methane gas with higher heating values between 1050 to 1070 Btu/SCF. Recovery of the non-methane components can be economically attractive as these hydrocarbons can be sold at a premium over natural gas.
- C2 is often used as feedstock for petrochemical manufacture
- C3 and C4 are marketed as LPG fuels
- the C5+ hydrocarbons can be further processed to be used for gasoline blending.
- a scrubbing column is used within the LNG liquefaction plant for the removal of the heavier components (C6+).
- C6+ lighter components
- a side stream from a spiral wound cryogenic exchanger is processed in a scrubber and fractionation unit, as shown in U.S. Pat. No. 6,308,531 to Roberts et al. While such process can advantageously be used to eliminate wax formation by removal of C6+ and heavier components, they are not suitable for the removal of C2+ components, especially at high levels (65% or higher C2 recovery) and consequently fail to produce the lean residue gas that can be liquefied for the North American natural gas market.
- NGL recovery processes that are integrated to LNG liquefaction as disclosed by Roberts et al in Pat. No. 6,662,589, teach that a C2 enriched liquid can be used for C3 absorption in a high pressure absorption column. While such processes attempt to operate the absorption column at high feed gas pressure (e.g., 800 psig or higher) to reduce energy consumption, it should be noted that NGL separation suffers significantly due to decreasing relative volatilities of the NGL components, consequently producing NGL with excessive methane content. Moreover, such process schemes typically fail to achieve high C2 and C3 recovery (e.g., greater than 60%).
- Presently known LNG liquefaction processes generally include several steps in which natural gas is cooled and condensed, using either pure component refrigeration cycles or one or more mixed refrigerants cycles.
- the cascade-refrigeration cycle chills and liquefies the feed gas with several pure component refrigerants having successively lower boiling points, such as propane, ethylene, methane and nitrogen.
- the mixed refrigerant cycle uses a mixture of refrigerants and can therefore be configured to use a single compressor and heat exchanger, which simplifies the equipment configuration.
- the feed gas can also be cooled by a propane pre-cooling refrigeration cycle or by expansion of natural gas or nitrogen using either Joule-Thomson expansion valves or an expansion turbine.
- most known standalone LNG liquefaction processes using single or multiple refrigeration cycles have relatively low efficiencies when C2 or C3 recovery is incorporated upstream of the LNG liquefaction plant.
- the present invention is directed to configurations, plants, and methods for natural gas processing and liquefaction in which a cold separator overhead product is directly compressed in a compressor that is driven by a feed gas vapor expander, and wherein the compressed cold separator overhead product is then liquefied in a liquefaction unit.
- a cold separator overhead product is directly compressed in a compressor that is driven by a feed gas vapor expander, and wherein the compressed cold separator overhead product is then liquefied in a liquefaction unit.
- a gas processing plant includes a separator that is configured to receive a partially expanded vapor portion of a natural gas feed stream, wherein the separator is further configured to produce a cold overhead product stream.
- An expander in such plants is operationally coupled to drive a compressor, wherein the expander is configured to produce the partially expanded vapor portion and wherein the compressor is configured to produce a compressed cold overhead product stream from the cold overhead product stream, and wherein the separator and the compressor are fluidly coupled to each other such that the compressed cold overhead product stream has a pressure of at least 700 psig at a temperature of no warmer than ⁇ 50° F.
- the separator is configured to receive another expanded vapor portion of the natural gas feed stream at a separate location.
- the separator is configured to operate as a demethanizer, and a deethanizer may be coupled to the separator wherein the deethanizer is configured to produce a C3+ product and a C2 product, which may be at least partially combined with the cold overhead product stream (e.g., to adjust heating value).
- the separator is configured to operate as a refluxed absorber.
- the demethanizer is preferably configured to provide a reflux stream to the absorber, wherein the demethanizer is most typically configured to operate at a lower pressure than the absorber.
- a conduit may be provided that delivers a cooled absorber bottom product the absorber for C2 recovery and/or a conduit that provides a heated absorber bottom product the absorber for C2 rejection.
- a method of producing a liquefied natural gas may include a step of producing a cold overhead product stream in a separator and compressing the product stream in a compressor without prior substantial heating of the cold product stream, wherein the compressor is driven by an expander that expands a vapor portion of a natural gas feed, and wherein the expanded vapor portion is fed into the separator.
- the cold compressed product stream is then liquefied in a liquefaction unit.
- the separator may be operated as a demethanizer that further receives another portion of a natural gas feed, and that in such methods a deethanizer may be coupled to the separator, wherein the deethanizer receives a bottom product of the separator and optionally provides a C2 product to the cold overhead product stream.
- the separator is operated as a refluxed absorber.
- a demethanizer provides a reflux stream to the absorber and that the absorber provides a bottom product to the demethanizer, wherein the demethanizer is operated at a lower pressure than the absorber.
- the absorber bottom product may be heated for C2 rejection prior to entering the deethanizer and/or cooled for C2 recovery prior to entering the demethanizer most typically, a deethanizer is fluidly coupled to the demethanizer in such plant and receives a bottom product of the demethanizer for separation and recovery of C2 and C3+.
- the cold compressed product stream has a pressure of at least 700 psig and a temperature of no warmer than ⁇ 50° F.
- a method of producing LNG will include a step of separating in a separator a cold overhead product from a natural gas containing feed gas.
- the cold overhead product is compressed using expansion energy from the feed gas to form a cold compressed overhead product at a pressure and temperature suitable for liquefaction in a liquefaction unit, wherein the cold compressed overhead product is formed at neutral or negative net compression energy requirement.
- the step of separating is performed in an absorber or a demethanizer, and/or the cold compressed overhead product has a pressure of at least 700 psig and a temperature of no warmer than ⁇ 50° F.
- FIG. 1 is a schematic of an exemplary known plant configuration for recovery of NGL and LNG liquefaction.
- FIG. 2A is a schematic of on& exemplary plant configuration using a single column configuration for production of a cold compressed overhead product and separation of C2 and/or C3.
- FIG. 2B is a schematic of one exemplary plant configuration using a twin column configuration for production of a cold compressed overhead product and separation of C2 and/or C3.
- FIG. 3 is a more detailed schematic of an exemplary plant according to FIG. 2A with a cascade refrigeration cycle and two mixed refrigerant cycles for NGL recovery and LNG liquefaction.
- FIG. 4 is a more detailed schematic of an exemplary plant according to FIG. 2B with a cascade refrigeration cycle and two mixed refrigerant cycles for NGL recovery and LNG liquefaction.
- FIG. 5 is a more detailed schematic of an exemplary plant according to FIG. 2B with two cascade refrigeration cycles and one mixed refrigerant cycles for NGL recovery and LNG liquefaction.
- FIG. 6 is a more detailed schematic of an exemplary plant according to FIG. 2B with two cascade refrigeration cycles, and a mixed refrigerant/cascade cycle for NGL recovery and LNG liquefaction.
- FIG. 7 is a more detailed schematic of an exemplary plant according to FIG. 2B with three cascade refrigeration cycles for NGL recovery and LNG liquefaction.
- FIG. 8 is a graph depicting a composite heat curve of the LNG liquefaction process.
- FIG. 1 shows a standalone C2 NGL recovery process that is coupled with a standalone LNG liquefaction plant.
- a contaminant free and dried feed gas stream 1 typically supplied at about 1200 psig is cooled in feed gas exchanger 51 using refrigeration content of the column overhead vapor, side reboiler stream 22 , and external refrigerant 32 .
- Liquid is then removed from the chilled feed gas in separator 52 and sent to the NGL column 58 that acts as a demethanizer.
- the flashed vapor from separator 52 is split into two portions, with one portion being cooled in exchanger 54 to provide reflux to the column, and the other portion being expanded in turbo-expander 64 to provide a cooled feed stream that is sent to a lower section of the column for rectification.
- the above standalone gas subcooled process produces a residue gas at about ambient temperature and approximately 450 psig.
- Such relatively low pressure and high temperature is predominantly due to the use of the residue gas as refrigerant for feed gas cooling and subcooling of a vapor portion of the feed gas and the pressure drops in the heat exchangers. Consequently, substantial recompression in re-compressor 100 and additional cooling (cooler not shown) of the residue gas is typically required prior liquefaction in the plant, which significantly reduces process efficiency and economics.
- contemplated configurations presented herein preserve substantially all of the refrigeration content in the separator overhead product by directly feeding the residue gas (separator overhead product) into the compressor, without incurring the pressure drops in heat exchangers of prior arts.
- the compressor is driven by the vapor expansion of the feed gas and as the residue gas is significantly colder than in heretofore known configurations, substantially higher compressor discharge pressures at notably lower temperatures can be achieved.
- the separator is operated as an absorber, the compressor discharge pressure can be even higher. It should therefore be appreciated that in most contemplated configurations and methods, the residue gas pressure is higher than 700 psig (typically between 700 and 900 psig) at a temperature of lower than ⁇ 50° F. (typically ⁇ 50° F. to ⁇ 80° F.) can be achieved.
- FIG. 2A depicts one exemplary plant configuration in which the separator is operated as a demethanizer
- FIG. 2B depicts an exemplary plant configuration in which the separator is operated as a refluxed absorber, and in which a demethanizer and deethanizer then operate at a lower pressure to recover C2 and/or C3+ components.
- C2 content in the LNG may be adjusted to a predetermined or desired level by either combining separated C2 with the column overhead product as shown in dashed lines in FIG. 2A , or by temperature control of the absorber bottom product that is fed into the demethanizer (as shown in dashed lines for C2 rejection) depicted in FIG. 2B .
- contemplated integrated NGL recovery and liquefaction processes significantly reduce equipment cost and energy consumption of LNG liquefaction, while allowing fractionating the NGL into C2 and C3+ products.
- Such configurations and processes will produce an LNG predominantly comprising methane that can be used in and/or exported to North America with heating values complying with gas pipeline standards.
- contemplated plants can be operated to produce LNG with variable ethane and propane content for non-US markets.
- high propane recovery i.e., at least 95%) and high ethane recovery (up to 85%) from a feed gas with relatively high pressure (e.g., between about 800 psig to 1600 psig) can be realized by operating an absorber at a higher pressure than the demethanizer.
- a compressor is then used to recycle the demethanizer overhead to the absorber, while the absorber bottoms product is expanded to provide cooling to the demethanizer.
- the overhead vapor from the absorber is compressed using power (preferably exclusively) generated from the feed gas expander. Therefore, it should be appreciated that contemplated configurations and methods significantly reduce the energy consumption of the integrated liquefaction plant. Further configurations related to some aspects of the inventive subject matter are disclosed in our copending U.S. patent application with the Ser. No. 10/478705, which is incorporated by reference herein.
- the refrigeration processes for both NGL recovery and residue gas liquefaction can be configured to employ a combination of one or more vaporizing refrigeration cycles to provide chilling at least three temperature ranges: A first temperature range of 10° F. to ⁇ 35° F. for feed gas pre-cooling, a second temperature range of ⁇ 60° F. to ⁇ 160° F. for generation of demethanizer or absorber reflux, and a third temperature range of ⁇ 180° F. to ⁇ 270° F. for gas liquefaction.
- FIG. 3 depicts a more detailed schematic of an exemplary configuration in which the separator is operated as a demethanizer (see also FIG. 2A ).
- feed gas streams it is contemplated that numerous natural and man made feed gas streams are suitable for use in conjunction with the teachings presented herein, and especially preferred feed gas streams include natural gases, refinery gases, and synthetic gas streams from hydrocarbon materials such as naphtha, coal, oil, lignite, etc. Consequently, the pressure of contemplated feed gas streams may vary considerably.
- feed gas pressures for plant configurations according to the inventive subject matter will generally be in the range between 800 psig and 1600 psig, and that at least a portion of the feed gas is expanded in a turboexpander to provide cooling and/or power for the residue gas recompression.
- the overall mass balances illustrating gas composition and flow rate for the exemplary feed gas and products are shown in Table 1 below.
- feed gas stream 1 enters the plant at about 1200 psig and 120° F., and is cooled in exchanger 51 to typically 10° F. to ⁇ 30° F., forming stream 2 , using multiple cooling streams including liquid stream 5 from separator 52 , side reboiler stream 22 from demethanizer. 61 , flash vapor 70 from LNG storage tank 69 , and a propane refrigerant stream 32 .
- the propane refrigerant is typically generated in cascade propane refrigeration system 101 , vaporizing at least three different pressure levels to provide chilling for heated stream 33 .
- various exchangers e.g., plate and fin exchangers or spiral wound exchangers
- the chilled feed gas stream 2 is separated in separator 52 , forming a gaseous portion 3 and a liquid portion 4 .
- the liquid portion 4 is letdown in pressure in JT valve 53 forming stream 5 , and optionally heated to stream 6 with the heat content from the feed gas prior to entering the demethanizer 61 (reboiled by reboiler 63 ).
- the gaseous portion 3 from separator 52 is split into two portions. One portion (stream 7 ) is routed to the exchanger 54 to provide reflux to the absorber, and the other portion (stream 8 ) is expanded in turbo-expander 64 to produce a chilled vapor stream 10 , typically at ⁇ 80° F. to 100° F. and to generate power to drive the residue gas compressor 65 .
- the chilled vapor 10 is fed to the demethanizer 61 , which operates between 400 psig to 650 psig, most typically at 450 psig. It should be appreciated that the flow ratio of stream 8 to stream 3 can be adjusted to tailor to a desired C2 recovery level, and/or to meet desired C2 product rates.
- Demethanizer 61 is refluxed with top reflux stream 12 (formed from stream 9 via JT valve 55 ) from exchanger 54 .
- the reflux stream is preferably chilled in exchanger 54 to about ⁇ 125° F. to ⁇ 155° F. using mixed refrigerant stream 72 and 74 (via stream 73 and JT valve 91 ) that is generated from stream 72 by compressed mixed refrigerant of refrigeration unit 102 .
- the so heated refrigerant 75 is then returned to refrigeration unit 102 .
- the demethanizer 61 produces an overhead vapor stream 28 at about ⁇ 120° F. to ⁇ 140° F. and a bottoms stream 14 at about 20° F. to 80° F.
- the overhead vapor is compressed by the residue gas compressor 65 forming a discharge stream 29 , typically at about 700 psig to 900 psig and ⁇ 50° F. to ⁇ 80° F.
- compression of a cryogenic vapor is energy efficient and results in a high compression ratio across the compressor, which significantly reduces the refrigeration consumption for liquefaction (using the third temperature level).
- the compression of the overhead product requires no net energy as the compressor is coupled to the expander 64 .
- chilled residue gas can be delivered to the liquefaction unit without net compression energy expenditure at a higher pressure and lower temperature than other known NGL separation processes would allow for.
- the cold compressed residue gas 29 is then further chilled and condensed in exchanger 67 to about ⁇ 255° F. to ⁇ 265° F. using mixed refrigerant 79 operating at ⁇ 250° F. to ⁇ 270° F.
- Refrigerant 79 is produced by the mixed refrigeration system 103 , after the compressed stream 76 is chilled in exchangers 54 and 67 (to form stream 78 ), and JT'd via valve 92 . Heated stream 80 is then returned to the refrigeration system 103 .
- the liquefied residue gas 81 is further letdown in pressure to about 16.0 psig via JT valve 90 to form stream 82 , which is stored in LNG storage tank 69 .
- the LNG product is withdrawn as stream 30 , optionally combined with JT'd C2 product stream 15 and exported to the ship loading terminal, storage container, or other use.
- significant quantities of light gas may evolve, which can be used as refrigeration source in subsequent exchangers to form a fuel gas 71 that is typically compressed to fuel header pressure.
- a portion of the ethane product stream 15 can be directed from deethanizer 59 to the LNG storage tank, to be blended with the lean LNG to produce a heavier and richer LNG, which may be required to accommodate the various LNG markets.
- Deethanizer 59 receives the bottom product of the demethanizer and is reboiled by reboiler 34 to produce a C3+ bottom product that is withdrawn as liquid 23 for storage or further processing.
- Deethanizer overhead condenser 62 provides chilling for the C2 overhead product.
- One portion of the of the overhead product is provided as deethanizer reflux stream 18 from separator drum 68 to the column via pump 59 while another portion 19 is routed to storage or other use as stream 17 .
- the first column is configured to separately receive a first and a second portion of a feed gas vapor, wherein the first portion of the feed gas vapor is chilled by the first level refrigeration, and the second portion is chilled by the second level refrigeration that provides reflux to the demethanizer.
- a flow control unit typically automated and using a controller programmable according to a desired product composition and/or feed gas composition adjusts at least one of the first and second portions of the feed gas vapor to produce the desirable recovery levels of ethane, from 10% to 85% of the feed gas while maintaining a high C3 (98% or above) recovery.
- At least a portion of the demethanizer bottoms product is fed to the deethanizer that fractionates the demethanizer bottom product into an ethane overhead and a C3+ bottoms product.
- contemplated methods and configurations allow production of C2 at variable rates by blending at least a portion of overhead C2 liquid with the LNG. It should further be recognized that blending significantly simplifies NGL recovery plant operation and allows the same process conditions (temperatures and pressures) be maintained, regardless of the net C2 production rates.
- FIG. 4 depicts a more detailed schematic of an exemplary configuration in which the separator is configured as an absorber that operates a higher pressure than a downstream demethanizer and deethanizer (see also FIG. 2A ).
- the separator is configured as an absorber that operates a higher pressure than a downstream demethanizer and deethanizer (see also FIG. 2A ).
- the same considerations as discussed for configurations according to FIG. 3 above apply.
- the overall mass balances illustrating gas composition and flow rate for the exemplary feed gas and products are shown in Table 1 above.
- the absorber receives an expanded feed gas and a reflux stream that is produced from the overhead vapor from a demethanizer after the overhead vapor is compressed and cooled by the second level refrigeration.
- the demethanizer column is fluidly coupled to the absorber and receives a column feed stream and operates at a pressure that is at least 50 to 100 psi lower, more preferably 100 psi to 300 psi lower than the operating pressure of the absorber. Therefore, most typically, the feed gas has a pressure of between 900 psig and 1600 psig, is expanded in a turbo-expander, and is fed to an absorber.
- the bottom product of the absorber is expanded to a pressure in the range of 50 psi to 350 psi differential pressure (relative to the demethanizer) and thereby chilled by Joule-Thomson effect to ⁇ 90° F. to ⁇ 130° F. It is also contemplated that the cooled and expanded bottom product stream forms a rectification stream that is fed to the demethanizer for C2 recovery.
- the demethanizer is reboiled with heat content from the feed gas and an optional external heat source, controlling the methane content in the bottoms product at about 1.5 mol % (or as otherwise needed to meet desired product specifications).
- feed gas stream 1 enters the plant at about 1200 psig and 120° F., and is cooled in exchanger 51 to typically 10° F. to ⁇ 30° F., forming stream 2 , using multiple cooling streams including liquid stream 5 from separator 52 , side reboiler stream 22 from demethanizer 61 , flash vapor 70 from LNG storage tank 69 , and a propane refrigerant stream 32 of refrigeration system 101 .
- Propane refrigerant is generated from heated stream 33 with a cascade propane refrigeration system, vaporizing at least three different pressure levels.
- the chilled feed gas stream 2 is separated in separator 52 , forming a gaseous portion 3 and a liquid portion 4 .
- the liquid portion 4 is letdown in pressure in JT valve 53 forming stream 5 , and optionally heated to stream 6 with the heat content from the feed gas prior to entering the demethanizer 61 .
- the gaseous portion 3 from separator 52 is split into two portions. One portion (stream 7 ) is routed to the exchanger 54 to provide reflux to the absorber, and the other portion (stream 8 ) is expanded in turbo-expander 64 to produce a chilled vapor stream 10 , typically at ⁇ 80° F. to ⁇ 100° F. and to generate power to drive the residue gas compressor 65 .
- the chilled vapor 10 is fed to absorber 58 , which operates at a pressure well above 450 psig, typically at between 500 psig to 700 psig, and most typically at 600 psig.
- the flow ratio of vapor stream 8 to vapor stream 3 can be variably adjusted to achieve a specific C2 recovery level, and/or to meet desired C2 product rates.
- Table 2 below exemplarily illustrates the effect of flow ratio of vapor stream 8 to vapor stream 3 on C2 and C3 recovery. TABLE 2 FLOW RATIO C3 RECOVERY, C2 RECOVERY, (STREAM 8 TO STREAM 3) % % 0.7 98 85 0.8 98 62 0.9 99 31 1.0 99 25
- Absorber 58 is refluxed with two cold streams, wherein the first reflux (top reflux) is supplied by stream 27 (via 56 and 11 ) from the demethanizer 61 , wherein the second reflux is supplied by stream 12 (via 9 and 55 ) from exchanger 54 .
- the reflux streams are chilled to about ⁇ 125° F. to ⁇ 155° F. with mixed refrigerant stream 74 that is generated by the compressed mixed refrigerant from refrigeration unit 102 that is chilled in exchanger 54 and chilled by JT valve 91 .
- the absorber produces an overhead vapor stream 28 at about ⁇ 120° F. to ⁇ 140° F. and a bottoms stream 14 at about ⁇ 100° F. to ⁇ 110° F.
- the overhead vapor is compressed by the residue gas compressor 65 using the power produced from expander 64 forming a discharge stream 29 , typically at about 900 psig and ⁇ 70° F. to ⁇ 80° F. It should be especially appreciated that compression of a cryogenic vapor is thermodynamically more efficient resulting in a high compression ratio across the compressor, which reduces the refrigeration consumption for liquefaction.
- the residue gas is chilled and condensed in exchanger 67 to about ⁇ 255° F. to ⁇ 265° F. using mixed refrigerant 79 operating at ⁇ 180° F.
- LNG product is withdrawn as stream 30 and withdrawn to storage or transport.
- a significant quantity of light gas 70 is evolved which can be recovered as fuel gas after its refrigerant content is recovered.
- a portion of the ethane product stream 15 can be directed from deethanizer 59 to LNG storage or transport. In this ways, lean LNG can be converted to a heavier and richer LNG.
- Absorber bottoms product stream 14 is preferably expanded in JT valve (or other expansion device) 60 to a pressure that is about 50-350 psig less than absorber pressure and enters as cooled stream 20 the demethanizer at a temperature of between about ⁇ 90° F. to ⁇ 130° F.
- the demethanizer is reboiled using reboiler 63 and produces bottom product 25 , which is then fed to deethanizer 59 .
- Demethanizer overhead product 24 is then routed back to the absorber as reflux stream 11 . To that end, the overhead product 24 is re-compressed to form stream 26 (to a pressure above absorber pressure) by compressor 66 and chilled in exchanger 54 to form stream 27 , which is expanded to reflux stream 11 .
- the absorber bottoms product is JT expanded heated against feed gas stream 1 .
- the so heated stream is further heated in the demethanizer overhead condenser and then fed into the demethanizer as feed stream.
- Deethanizer 59 is configured as reboiled column using reboiler 34 to separate C2 from C3+ components, wherein the C3+ components are drawn from the column as stream 23 .
- the C2 overhead product is condensed in overhead condenser 62 and separated in drum 68 .
- One portion 18 of the C2 product is pumped back by pump 59 to the column as reflux while another portion 19 is withdrawn for LNG blending or storage/transport via stream 17 .
- the same considerations apply for like components as described in FIG. 3 above.
- an absorber in contemplated plants receives a liquid portion of the natural gas feed and a second vapor portion of the natural gas feed, wherein the second portion is reduced in pressure via a turbo expander.
- Preferred absorbers produce a bottom product that is expanded, chilled, and fed to the demethanizer for absorption of the C2 + components.
- Preferred demethanizer bottoms products are subsequently fractionated in a deethanizer into a C2 liquid overhead and a C3+ bottoms product.
- the absorber produces an overhead vapor product that is predominantly methane at cryogenic temperature ( ⁇ 100° F. or lower), which is further compressed using power generated by turbo-expansion of the feed gas.
- Such configurations produce a high pressure cryogenic vapor at ⁇ 75° F. to ⁇ 100° F. and 800 psig to 900 psig or higher pressure that is subsequently liquefied forming the LNG using the third temperature level refrigeration.
- FIG. 5 exemplarily illustrates a plant configuration in which the third temperature range refrigerant at ⁇ 180° F. to ⁇ 270° F. is supplied by a cascade methane refrigerant cycle 103 , operating with at least three pressure levels.
- a pure component refrigerant such as methane may also be appropriate.
- FIG. 6 illustrates another embodiment in which a propane pre-cooled cascade cycle 104 is added to the discharge of the mixed refrigeration system 102 .
- FIG. 7 illustrates yet another alternative embodiment in which a cascade propane refrigerant, a cascade ethylene refrigerant, and a methane refrigerant are employed for NGL recovery and LNG liquefaction.
- the absorber in contemplated plants and methods is configured to separately receive a first and a second portion of a feed gas vapor and a demethanizer overhead, wherein the first portion of the feed gas vapor and the demethanizer column overhead provide reflux to the absorber.
- a flow control unit adjusts at least one of the first and second portions of the feed gas vapor to produce the desirable recovery levels of ethane, from 10% to 85% of the feed gas, while maintaining a high C3 (98% or above) recovery. It is still further contemplated that at least a portion of the demethanizer bottoms product is fed to the deethanizer that fractionate the demethanizer bottom product into an ethane overhead and a C3+ bottoms product.
- preferred configuration can provide variable C2 production rates by blending at least a portion of the excess overhead C2 liquid with the LNG. It should be especially recognized that this blending step simplifies the NGL recovery plant operation and allows the same process conditions (temperatures and pressures) be maintained, regardless of the net C2 production rates.
- At least three temperature ranges are provided by one or more vaporizing refrigeration cycles: A first temperature range of 10° F. to ⁇ 35° F. refrigeration for the feed gas pre-cooling, a second temperature range of ⁇ 60° F. to ⁇ 160° F. for the first column reflux, and a third temperature range of ⁇ 180° F. to ⁇ 270° F. for gas liquefaction.
- the refrigerant in contemplated refrigeration circuits comprise one, two, or more hydrocarbon components and may further include nitrogen, halocarbons, and/or other refrigerants.
- Contemplated refrigeration cycles may also include combinations of refrigeration cycles, and especially combinations of a multi-component mixed refrigerant cycles, a single component cascade cycle, a gas expander cycle, and a propane pre-cooled refrigeration cycle.
- the first temperature range refrigeration at 10° F. to ⁇ 35° F. uses propane pre-cooled refrigeration or cascade refrigeration, and cools at least one portion of the feed gas and the refrigerant of the second temperature level.
- the second temperature level refrigeration at ⁇ 60° F. to ⁇ 160° F. may then use a mixed refrigerant cycle or cascade refrigeration using pure component such as ethylene to chill the absorber reflux, and the third temperature level refrigeration at ⁇ 180° F. to ⁇ 270° F.
- a mixed refrigerant cycle or cascade refrigeration using pure component such as methane may use a mixed refrigerant cycle or cascade refrigeration using pure component such as methane to liquefy the residual gas.
- Other preferred refrigeration cycles include letdown devices such as turbo-expanders and Joule-Thomson valves.
- letdown devices such as turbo-expanders and Joule-Thomson valves.
Landscapes
- Engineering & Computer Science (AREA)
- Physics & Mathematics (AREA)
- Mechanical Engineering (AREA)
- Thermal Sciences (AREA)
- General Engineering & Computer Science (AREA)
- Chemical & Material Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Chemical Kinetics & Catalysis (AREA)
- General Chemical & Material Sciences (AREA)
- Separation By Low-Temperature Treatments (AREA)
Abstract
Contemplated plants include a NGL recovery portion and a LNG liquefaction portion, wherein the NGL recovery portion provides a low-temperature and high-pressure overhead product directly to the LNG liquefaction portion. Feed gas cooling and condensation are most preferably performed using refrigeration cycles that employ refrigerants other than the demethanizer/absorber overhead product. Thus, cold demethanizer/absorber overhead product is compressed with the turbo-expansion and delivered to a liquefaction portion at significantly lower temperature and higher pressure without net compression energy expenditure.
Description
- This application claims priority to our copending U.S. provisional patent application with the Ser. No. 60/697,467, which was filed 7 Jul. 2005.
- The field of the invention is natural gas liquids (NGL) recovery and liquefied natural gas (LNG) liquefaction, and particularly integrated plant configurations for such processes.
- While the crude oil supply in the world is diminishing, the supply of natural gas is still relatively abundant in many parts of the world. Natural gas is typically recovered from oil and gas production wells located onshore and offshore. Depending on the particular formation and reservoir, natural gas also contains relatively low quantities of non-methane hydrocarbons, including ethane, propane, i-butane, n-butane, pentanes, hexane and heavier components, as well as water, nitrogen, carbon dioxide, hydrogen sulfide, mercaptans, and other gases.
- Natural gas from the wellheads is commonly treated to remove sulfur components, compressed, and transported to consumers in high pressure pipelines. However, in remote locations lacking the necessary pipeline infrastructure, natural gas is commonly transported by liquefying the natural gas and transporting the gas in liquid form (e.g., using LNG cargo carriers). Unfortunately, liquefaction of natural gas is problematic as natural gas also contains aromatics (e.g., benzene) and heavy hydrocarbons, which solidify when chilled to the cryogenic temperatures. Consequently, most aromatic hydrocarbons must be removed to an extremely low level (typically less than 1 ppmv) to avoid freezing and plugging the cryogenic heat exchange equipment. Additionally, at least a portion of the lighter hydrocarbons such as C2, C3 and C4 must be removed when LNG is imported to the North America natural gas market, which typically requires a leaner natural gas. Typical North America pipeline gas contains mostly the clean burning methane gas with higher heating values between 1050 to 1070 Btu/SCF. Recovery of the non-methane components can be economically attractive as these hydrocarbons can be sold at a premium over natural gas. For example, C2 is often used as feedstock for petrochemical manufacture, C3 and C4 are marketed as LPG fuels, and the C5+ hydrocarbons can be further processed to be used for gasoline blending.
- There are numerous configurations and methods known in the art for the recovery of C2 and C3+ NGL from a natural gas feed. However, all past efforts have been focused on the removal of NGL hydrocarbons from natural gas using standalone NGL recovery plants, which operate independently from LNG liquefaction plants. These extraction processes generally produce a low to medium pressure residue gas which then requires compression and further chilling before liquefaction in a liquefaction plant. Typical examples for plants to recover C2 and C3+ components from natural gas include those employing expander processes described in U.S. Pat. No. 4,157,904 to Campbell et al., U.S. Pat. No. 4,251,249 to Gulsby, U.S. Pat. No. 4,617,039 to Buck, U.S. Pat. No. 4,690,702 to Paradowski et al., U.S. Pat. No. 5,275,005 to Campbell et al., U.S. Pat. No. 5,799,507 to Wilkinson et al., or U.S. Pat. No. 5,890,378 to Rambo et al.
- Other known high C2 recovery processes (e.g., U.S. Pat. Nos. 6,116,050), require to let down a portion of the high pressure residue gas to the NGL recovery column as a methane rich reflux using a Joule-Thomson (JT) valve. While these processes improve C2 recovery to at least some degree, the energy spent for residue gas recompression renders the process often uneconomical. To overcome some of these disadvantages, twin-column configurations may be implemented in which a high pressure absorber is fluidly coupled to a lower pressure distillation column to improve NGL recovery efficiency as described in commonly owned U.S. Pat. No. 6,837,070). However, as these NGL processes operate independently from the liquefaction plants, they will generally require additional compression and refrigeration prior to LNG liquefaction of the residue gas.
- In still other known configurations for NGL processing, a scrubbing column is used within the LNG liquefaction plant for the removal of the heavier components (C6+). For example, a side stream from a spiral wound cryogenic exchanger is processed in a scrubber and fractionation unit, as shown in U.S. Pat. No. 6,308,531 to Roberts et al. While such process can advantageously be used to eliminate wax formation by removal of C6+ and heavier components, they are not suitable for the removal of C2+ components, especially at high levels (65% or higher C2 recovery) and consequently fail to produce the lean residue gas that can be liquefied for the North American natural gas market. Still further known NGL recovery processes that are integrated to LNG liquefaction as disclosed by Roberts et al in Pat. No. 6,662,589, teach that a C2 enriched liquid can be used for C3 absorption in a high pressure absorption column. While such processes attempt to operate the absorption column at high feed gas pressure (e.g., 800 psig or higher) to reduce energy consumption, it should be noted that NGL separation suffers significantly due to decreasing relative volatilities of the NGL components, consequently producing NGL with excessive methane content. Moreover, such process schemes typically fail to achieve high C2 and C3 recovery (e.g., greater than 60%).
- Presently known LNG liquefaction processes generally include several steps in which natural gas is cooled and condensed, using either pure component refrigeration cycles or one or more mixed refrigerants cycles. The cascade-refrigeration cycle chills and liquefies the feed gas with several pure component refrigerants having successively lower boiling points, such as propane, ethylene, methane and nitrogen. The mixed refrigerant cycle uses a mixture of refrigerants and can therefore be configured to use a single compressor and heat exchanger, which simplifies the equipment configuration. Alternatively, the feed gas can also be cooled by a propane pre-cooling refrigeration cycle or by expansion of natural gas or nitrogen using either Joule-Thomson expansion valves or an expansion turbine. Unfortunately, most known standalone LNG liquefaction processes using single or multiple refrigeration cycles (either cascade refrigeration or mixed refrigerant cycle) have relatively low efficiencies when C2 or C3 recovery is incorporated upstream of the LNG liquefaction plant.
- Thus, while numerous plant configurations and methods for NGL recovery and LNG liquefaction are known in the art, all or almost all of them, suffer from various disadvantages. Thus, there is still a need for improved NGL recovery and LNG liquefaction, and especially plants in which NGL recovery and LNG liquefaction are integrated.
- The present invention is directed to configurations, plants, and methods for natural gas processing and liquefaction in which a cold separator overhead product is directly compressed in a compressor that is driven by a feed gas vapor expander, and wherein the compressed cold separator overhead product is then liquefied in a liquefaction unit. Most advantageously, such plants integrate NGL processing and LNG liquefaction in an efficient, cost effective, and technically simple manner.
- In one preferred aspect of the inventive subject matter, a gas processing plant includes a separator that is configured to receive a partially expanded vapor portion of a natural gas feed stream, wherein the separator is further configured to produce a cold overhead product stream. An expander in such plants is operationally coupled to drive a compressor, wherein the expander is configured to produce the partially expanded vapor portion and wherein the compressor is configured to produce a compressed cold overhead product stream from the cold overhead product stream, and wherein the separator and the compressor are fluidly coupled to each other such that the compressed cold overhead product stream has a pressure of at least 700 psig at a temperature of no warmer than −50° F.
- Most typically, the separator is configured to receive another expanded vapor portion of the natural gas feed stream at a separate location. In some embodiments, the separator is configured to operate as a demethanizer, and a deethanizer may be coupled to the separator wherein the deethanizer is configured to produce a C3+ product and a C2 product, which may be at least partially combined with the cold overhead product stream (e.g., to adjust heating value). In other embodiments, the separator is configured to operate as a refluxed absorber. In such configurations, the demethanizer is preferably configured to provide a reflux stream to the absorber, wherein the demethanizer is most typically configured to operate at a lower pressure than the absorber. Where desirable, a conduit may be provided that delivers a cooled absorber bottom product the absorber for C2 recovery and/or a conduit that provides a heated absorber bottom product the absorber for C2 rejection.
- Therefore, in another aspect of the inventive subject matter, a method of producing a liquefied natural gas may include a step of producing a cold overhead product stream in a separator and compressing the product stream in a compressor without prior substantial heating of the cold product stream, wherein the compressor is driven by an expander that expands a vapor portion of a natural gas feed, and wherein the expanded vapor portion is fed into the separator. In another step, the cold compressed product stream is then liquefied in a liquefaction unit.
- It should be recognized that the separator may be operated as a demethanizer that further receives another portion of a natural gas feed, and that in such methods a deethanizer may be coupled to the separator, wherein the deethanizer receives a bottom product of the separator and optionally provides a C2 product to the cold overhead product stream. In alternative aspects of the inventive subject matter, the separator is operated as a refluxed absorber. Here, it is generally preferred that a demethanizer provides a reflux stream to the absorber and that the absorber provides a bottom product to the demethanizer, wherein the demethanizer is operated at a lower pressure than the absorber. For flexible C2/C3+ recovery, it is contemplated that the absorber bottom product may be heated for C2 rejection prior to entering the deethanizer and/or cooled for C2 recovery prior to entering the demethanizer most typically, a deethanizer is fluidly coupled to the demethanizer in such plant and receives a bottom product of the demethanizer for separation and recovery of C2 and C3+. Regardless of the manner of operation of the separator, it is generally preferred that the cold compressed product stream has a pressure of at least 700 psig and a temperature of no warmer than −50° F.
- Viewed from a different perspective, a method of producing LNG will include a step of separating in a separator a cold overhead product from a natural gas containing feed gas. In another step, the cold overhead product is compressed using expansion energy from the feed gas to form a cold compressed overhead product at a pressure and temperature suitable for liquefaction in a liquefaction unit, wherein the cold compressed overhead product is formed at neutral or negative net compression energy requirement. Typically, the step of separating is performed in an absorber or a demethanizer, and/or the cold compressed overhead product has a pressure of at least 700 psig and a temperature of no warmer than −50° F.
- Various objects, features, aspects and advantages of the present invention will become more apparent from the following detailed description of preferred embodiments of the invention.
- Prior Art
FIG. 1 is a schematic of an exemplary known plant configuration for recovery of NGL and LNG liquefaction. -
FIG. 2A is a schematic of on& exemplary plant configuration using a single column configuration for production of a cold compressed overhead product and separation of C2 and/or C3. -
FIG. 2B is a schematic of one exemplary plant configuration using a twin column configuration for production of a cold compressed overhead product and separation of C2 and/or C3. -
FIG. 3 is a more detailed schematic of an exemplary plant according toFIG. 2A with a cascade refrigeration cycle and two mixed refrigerant cycles for NGL recovery and LNG liquefaction. -
FIG. 4 is a more detailed schematic of an exemplary plant according toFIG. 2B with a cascade refrigeration cycle and two mixed refrigerant cycles for NGL recovery and LNG liquefaction. -
FIG. 5 is a more detailed schematic of an exemplary plant according toFIG. 2B with two cascade refrigeration cycles and one mixed refrigerant cycles for NGL recovery and LNG liquefaction. -
FIG. 6 is a more detailed schematic of an exemplary plant according toFIG. 2B with two cascade refrigeration cycles, and a mixed refrigerant/cascade cycle for NGL recovery and LNG liquefaction. -
FIG. 7 is a more detailed schematic of an exemplary plant according toFIG. 2B with three cascade refrigeration cycles for NGL recovery and LNG liquefaction. -
FIG. 8 is a graph depicting a composite heat curve of the LNG liquefaction process. - The inventor discovered that natural gas processing and liquefaction can be integrated in various configurations, plants, and methods in which cold compression of lean natural gas in a compressor that is driven by a feed gas expander provides a cold high-pressure natural gas that can be directly liquefied in a liquefaction unit. Therefore, the net compression energy requirement for the lean natural gas is neutral or even negative, while feed gas cooling and condensation are achieved using distinct refrigeration cycles. Among other advantages, it should be appreciated that contemplated configurations and methods allow for an integrated NGL recovery and LNG liquefaction process in which 99% propane and up to 85% ethane can be recovered from a natural feed gas.
- Prior Art
FIG. 1 shows a standalone C2 NGL recovery process that is coupled with a standalone LNG liquefaction plant. Here, a contaminant free and driedfeed gas stream 1, typically supplied at about 1200 psig is cooled infeed gas exchanger 51 using refrigeration content of the column overhead vapor,side reboiler stream 22, andexternal refrigerant 32. Liquid is then removed from the chilled feed gas inseparator 52 and sent to theNGL column 58 that acts as a demethanizer. The flashed vapor fromseparator 52 is split into two portions, with one portion being cooled inexchanger 54 to provide reflux to the column, and the other portion being expanded in turbo-expander 64 to provide a cooled feed stream that is sent to a lower section of the column for rectification. It should be noted that the above standalone gas subcooled process produces a residue gas at about ambient temperature and approximately 450 psig. Such relatively low pressure and high temperature is predominantly due to the use of the residue gas as refrigerant for feed gas cooling and subcooling of a vapor portion of the feed gas and the pressure drops in the heat exchangers. Consequently, substantial recompression inre-compressor 100 and additional cooling (cooler not shown) of the residue gas is typically required prior liquefaction in the plant, which significantly reduces process efficiency and economics. - In contrast, contemplated configurations presented herein preserve substantially all of the refrigeration content in the separator overhead product by directly feeding the residue gas (separator overhead product) into the compressor, without incurring the pressure drops in heat exchangers of prior arts. As the compressor is driven by the vapor expansion of the feed gas and as the residue gas is significantly colder than in heretofore known configurations, substantially higher compressor discharge pressures at notably lower temperatures can be achieved. Moreover, where the separator is operated as an absorber, the compressor discharge pressure can be even higher. It should therefore be appreciated that in most contemplated configurations and methods, the residue gas pressure is higher than 700 psig (typically between 700 and 900 psig) at a temperature of lower than −50° F. (typically −50° F. to −80° F.) can be achieved.
-
FIG. 2A depicts one exemplary plant configuration in which the separator is operated as a demethanizer, whileFIG. 2B depict s an exemplary plant configuration in which the separator is operated as a refluxed absorber, and in which a demethanizer and deethanizer then operate at a lower pressure to recover C2 and/or C3+ components. As can be seen from both figures, C2 content in the LNG may be adjusted to a predetermined or desired level by either combining separated C2 with the column overhead product as shown in dashed lines inFIG. 2A , or by temperature control of the absorber bottom product that is fed into the demethanizer (as shown in dashed lines for C2 rejection) depicted inFIG. 2B . - It should be recognized that contemplated integrated NGL recovery and liquefaction processes significantly reduce equipment cost and energy consumption of LNG liquefaction, while allowing fractionating the NGL into C2 and C3+ products. Such configurations and processes will produce an LNG predominantly comprising methane that can be used in and/or exported to North America with heating values complying with gas pipeline standards. Moreover, it should be noted that contemplated plants can be operated to produce LNG with variable ethane and propane content for non-US markets.
- Using such configurations and methods, high propane recovery (i.e., at least 95%) and high ethane recovery (up to 85%) from a feed gas with relatively high pressure (e.g., between about 800 psig to 1600 psig) can be realized by operating an absorber at a higher pressure than the demethanizer. A compressor is then used to recycle the demethanizer overhead to the absorber, while the absorber bottoms product is expanded to provide cooling to the demethanizer. The overhead vapor from the absorber is compressed using power (preferably exclusively) generated from the feed gas expander. Therefore, it should be appreciated that contemplated configurations and methods significantly reduce the energy consumption of the integrated liquefaction plant. Further configurations related to some aspects of the inventive subject matter are disclosed in our copending U.S. patent application with the Ser. No. 10/478705, which is incorporated by reference herein.
- While not limiting to the inventive subject matter, it is typically preferred that the refrigeration processes for both NGL recovery and residue gas liquefaction can be configured to employ a combination of one or more vaporizing refrigeration cycles to provide chilling at least three temperature ranges: A first temperature range of 10° F. to −35° F. for feed gas pre-cooling, a second temperature range of −60° F. to −160° F. for generation of demethanizer or absorber reflux, and a third temperature range of −180° F. to −270° F. for gas liquefaction.
-
FIG. 3 depicts a more detailed schematic of an exemplary configuration in which the separator is operated as a demethanizer (see alsoFIG. 2A ). With respect to the feed gas streams it is contemplated that numerous natural and man made feed gas streams are suitable for use in conjunction with the teachings presented herein, and especially preferred feed gas streams include natural gases, refinery gases, and synthetic gas streams from hydrocarbon materials such as naphtha, coal, oil, lignite, etc. Consequently, the pressure of contemplated feed gas streams may vary considerably. However, it is generally preferred that appropriate feed gas pressures for plant configurations according to the inventive subject matter will generally be in the range between 800 psig and 1600 psig, and that at least a portion of the feed gas is expanded in a turboexpander to provide cooling and/or power for the residue gas recompression. The overall mass balances illustrating gas composition and flow rate for the exemplary feed gas and products are shown in Table 1 below.TABLE 1 C2 C3+ LNG MOL % FEED PRODUCT PRODUCT PRODUCT CO2 0.042 0.000 0.000 0.000 N2 4.569 0.000 0.000 5.005 C1 86.161 1.470 0.000 94.282 C2 5.046 97.528 0.454 0.700 C3 1.854 1.001 43.430 0.012 iC4 0.395 0.000 9.531 0.000 nC4 0.590 0.000 14.256 0.000 iC5 0.248 0.000 5.982 0.000 Nc5 0.205 0.000 4.947 0.000 C6 0.224 0.000 5.417 0.000 C7 0.662 0.000 15.985 0.000 MMscfd 1,227 55 51 1,120 BPD —/— 34,895 40,174 445,070 Metric Tons/yr 10.3 0.7 1.4 8.2 - Here, feed
gas stream 1 enters the plant at about 1200 psig and 120° F., and is cooled inexchanger 51 to typically 10° F. to −30° F., formingstream 2, using multiple cooling streams includingliquid stream 5 fromseparator 52,side reboiler stream 22 from demethanizer. 61,flash vapor 70 fromLNG storage tank 69, and apropane refrigerant stream 32. The propane refrigerant is typically generated in cascadepropane refrigeration system 101, vaporizing at least three different pressure levels to provide chilling forheated stream 33. It should be noted that various exchangers (e.g., plate and fin exchangers or spiral wound exchangers) can be used to achieve a close temperature approach that provides high thermodynamic efficiency as demonstrated in the integrated composite curves ofFIG. 8 . - The chilled
feed gas stream 2 is separated inseparator 52, forming agaseous portion 3 and aliquid portion 4. Theliquid portion 4 is letdown in pressure inJT valve 53 formingstream 5, and optionally heated to stream 6 with the heat content from the feed gas prior to entering the demethanizer 61 (reboiled by reboiler 63). Thegaseous portion 3 fromseparator 52 is split into two portions. One portion (stream 7) is routed to theexchanger 54 to provide reflux to the absorber, and the other portion (stream 8) is expanded in turbo-expander 64 to produce achilled vapor stream 10, typically at −80° F. to 100° F. and to generate power to drive theresidue gas compressor 65. Thechilled vapor 10 is fed to thedemethanizer 61, which operates between 400 psig to 650 psig, most typically at 450 psig. It should be appreciated that the flow ratio ofstream 8 to stream 3 can be adjusted to tailor to a desired C2 recovery level, and/or to meet desired C2 product rates.Demethanizer 61 is refluxed with top reflux stream 12 (formed fromstream 9 via JT valve 55) fromexchanger 54. The reflux stream is preferably chilled inexchanger 54 to about −125° F. to −155° F. using mixedrefrigerant stream 72 and 74 (viastream 73 and JT valve 91) that is generated fromstream 72 by compressed mixed refrigerant ofrefrigeration unit 102. The so heated refrigerant 75 is then returned torefrigeration unit 102. - The
demethanizer 61 produces anoverhead vapor stream 28 at about −120° F. to −140° F. and abottoms stream 14 at about 20° F. to 80° F. The overhead vapor is compressed by theresidue gas compressor 65 forming adischarge stream 29, typically at about 700 psig to 900 psig and −50° F. to −80° F. It should be particularly appreciated that compression of a cryogenic vapor is energy efficient and results in a high compression ratio across the compressor, which significantly reduces the refrigeration consumption for liquefaction (using the third temperature level). Moreover, it should be noted that the compression of the overhead product requires no net energy as the compressor is coupled to theexpander 64. Thus, by using a relatively high feed gas pressure (e.g., about 1000 psig) and compression of cold separator overhead product, chilled residue gas can be delivered to the liquefaction unit without net compression energy expenditure at a higher pressure and lower temperature than other known NGL separation processes would allow for. The coldcompressed residue gas 29 is then further chilled and condensed inexchanger 67 to about −255° F. to −265° F. using mixed refrigerant 79 operating at −250° F. to −270°F. Refrigerant 79 is produced by themixed refrigeration system 103, after the compressedstream 76 is chilled inexchangers 54 and 67 (to form stream 78), and JT'd viavalve 92.Heated stream 80 is then returned to therefrigeration system 103. - The liquefied
residue gas 81 is further letdown in pressure to about 16.0 psig viaJT valve 90 to formstream 82, which is stored inLNG storage tank 69. The LNG product is withdrawn asstream 30, optionally combined with JT'dC2 product stream 15 and exported to the ship loading terminal, storage container, or other use. In some cases, and depending on the natural gas composition and temperature from the liquefier exchanger, significant quantities of light gas may evolve, which can be used as refrigeration source in subsequent exchangers to form afuel gas 71 that is typically compressed to fuel header pressure. - As pointed out above, a portion of the
ethane product stream 15 can be directed fromdeethanizer 59 to the LNG storage tank, to be blended with the lean LNG to produce a heavier and richer LNG, which may be required to accommodate the various LNG markets.Deethanizer 59 receives the bottom product of the demethanizer and is reboiled byreboiler 34 to produce a C3+ bottom product that is withdrawn asliquid 23 for storage or further processing. Deethanizeroverhead condenser 62 provides chilling for the C2 overhead product. One portion of the of the overhead product is provided asdeethanizer reflux stream 18 fromseparator drum 68 to the column viapump 59 while anotherportion 19 is routed to storage or other use asstream 17. - Most preferably, the first column (demethanizer) is configured to separately receive a first and a second portion of a feed gas vapor, wherein the first portion of the feed gas vapor is chilled by the first level refrigeration, and the second portion is chilled by the second level refrigeration that provides reflux to the demethanizer. In such configurations, it should be noted that a flow control unit (typically automated and using a controller programmable according to a desired product composition and/or feed gas composition) adjusts at least one of the first and second portions of the feed gas vapor to produce the desirable recovery levels of ethane, from 10% to 85% of the feed gas while maintaining a high C3 (98% or above) recovery.
- It is further contemplated that at least a portion of the demethanizer bottoms product is fed to the deethanizer that fractionates the demethanizer bottom product into an ethane overhead and a C3+ bottoms product. Thus, it should be recognized that contemplated methods and configurations allow production of C2 at variable rates by blending at least a portion of overhead C2 liquid with the LNG. It should further be recognized that blending significantly simplifies NGL recovery plant operation and allows the same process conditions (temperatures and pressures) be maintained, regardless of the net C2 production rates.
-
FIG. 4 depicts a more detailed schematic of an exemplary configuration in which the separator is configured as an absorber that operates a higher pressure than a downstream demethanizer and deethanizer (see alsoFIG. 2A ). With respect to the feed gas streams the same considerations as discussed for configurations according toFIG. 3 above apply. The overall mass balances illustrating gas composition and flow rate for the exemplary feed gas and products are shown in Table 1 above. - In general, the absorber receives an expanded feed gas and a reflux stream that is produced from the overhead vapor from a demethanizer after the overhead vapor is compressed and cooled by the second level refrigeration. In such configurations, the demethanizer column is fluidly coupled to the absorber and receives a column feed stream and operates at a pressure that is at least 50 to 100 psi lower, more preferably 100 psi to 300 psi lower than the operating pressure of the absorber. Therefore, most typically, the feed gas has a pressure of between 900 psig and 1600 psig, is expanded in a turbo-expander, and is fed to an absorber. The bottom product of the absorber is expanded to a pressure in the range of 50 psi to 350 psi differential pressure (relative to the demethanizer) and thereby chilled by Joule-Thomson effect to −90° F. to −130° F. It is also contemplated that the cooled and expanded bottom product stream forms a rectification stream that is fed to the demethanizer for C2 recovery. The demethanizer is reboiled with heat content from the feed gas and an optional external heat source, controlling the methane content in the bottoms product at about 1.5 mol % (or as otherwise needed to meet desired product specifications).
- More particularly, and as depicted in
FIG. 4 , feedgas stream 1 enters the plant at about 1200 psig and 120° F., and is cooled inexchanger 51 to typically 10° F. to −30° F., formingstream 2, using multiple cooling streams includingliquid stream 5 fromseparator 52,side reboiler stream 22 fromdemethanizer 61,flash vapor 70 fromLNG storage tank 69, and apropane refrigerant stream 32 ofrefrigeration system 101. Propane refrigerant is generated fromheated stream 33 with a cascade propane refrigeration system, vaporizing at least three different pressure levels. - The chilled
feed gas stream 2 is separated inseparator 52, forming agaseous portion 3 and aliquid portion 4. Theliquid portion 4 is letdown in pressure inJT valve 53 formingstream 5, and optionally heated to stream 6 with the heat content from the feed gas prior to entering thedemethanizer 61. Thegaseous portion 3 fromseparator 52 is split into two portions. One portion (stream 7) is routed to theexchanger 54 to provide reflux to the absorber, and the other portion (stream 8) is expanded in turbo-expander 64 to produce achilled vapor stream 10, typically at −80° F. to −100° F. and to generate power to drive theresidue gas compressor 65. Thechilled vapor 10 is fed toabsorber 58, which operates at a pressure well above 450 psig, typically at between 500 psig to 700 psig, and most typically at 600 psig. The flow ratio ofvapor stream 8 tovapor stream 3 can be variably adjusted to achieve a specific C2 recovery level, and/or to meet desired C2 product rates. Table 2 below exemplarily illustrates the effect of flow ratio ofvapor stream 8 tovapor stream 3 on C2 and C3 recovery.TABLE 2 FLOW RATIO C3 RECOVERY, C2 RECOVERY, ( STREAM 8 TO STREAM 3)% % 0.7 98 85 0.8 98 62 0.9 99 31 1.0 99 25 -
Absorber 58 is refluxed with two cold streams, wherein the first reflux (top reflux) is supplied by stream 27 (via 56 and 11) from thedemethanizer 61, wherein the second reflux is supplied by stream 12 (via 9 and 55) fromexchanger 54. The reflux streams are chilled to about −125° F. to −155° F. with mixedrefrigerant stream 74 that is generated by the compressed mixed refrigerant fromrefrigeration unit 102 that is chilled inexchanger 54 and chilled byJT valve 91. - The absorber produces an
overhead vapor stream 28 at about −120° F. to −140° F. and abottoms stream 14 at about −100° F. to −110° F. The overhead vapor is compressed by theresidue gas compressor 65 using the power produced fromexpander 64 forming adischarge stream 29, typically at about 900 psig and −70° F. to −80° F. It should be especially appreciated that compression of a cryogenic vapor is thermodynamically more efficient resulting in a high compression ratio across the compressor, which reduces the refrigeration consumption for liquefaction. The residue gas is chilled and condensed inexchanger 67 to about −255° F. to −265° F. using mixed refrigerant 79 operating at −180° F. to −270° F. that is produced by themixed refrigeration system 103, after the compressedstream 76 is chilled inexchangers valve 92. The liquefied residue gas is further letdown in pressure to stream 82 at about 16.0 psig viaJT valve 90, and the flashed liquid is stored inLNG storage tank 69. LNG product is withdrawn asstream 30 and withdrawn to storage or transport. In some cases, depending on the natural gas composition and the temperature from the liquefier exchanger, a significant quantity oflight gas 70 is evolved which can be recovered as fuel gas after its refrigerant content is recovered. Where desired, a portion of theethane product stream 15 can be directed fromdeethanizer 59 to LNG storage or transport. In this ways, lean LNG can be converted to a heavier and richer LNG. - Absorber
bottoms product stream 14 is preferably expanded in JT valve (or other expansion device) 60 to a pressure that is about 50-350 psig less than absorber pressure and enters as cooledstream 20 the demethanizer at a temperature of between about −90° F. to −130° F. The demethanizer is reboiled usingreboiler 63 and producesbottom product 25, which is then fed todeethanizer 59. Demethanizeroverhead product 24 is then routed back to the absorber asreflux stream 11. To that end, theoverhead product 24 is re-compressed to form stream 26 (to a pressure above absorber pressure) bycompressor 66 and chilled inexchanger 54 to formstream 27, which is expanded to refluxstream 11. Alternatively (not shown inFIG. 4 , seeFIG. 2B ), and especially where C2 is rejected, the absorber bottoms product is JT expanded heated againstfeed gas stream 1. The so heated stream is further heated in the demethanizer overhead condenser and then fed into the demethanizer as feed stream. -
Deethanizer 59 is configured as reboiledcolumn using reboiler 34 to separate C2 from C3+ components, wherein the C3+ components are drawn from the column asstream 23. The C2 overhead product is condensed inoverhead condenser 62 and separated indrum 68. Oneportion 18 of the C2 product is pumped back bypump 59 to the column as reflux while anotherportion 19 is withdrawn for LNG blending or storage/transport viastream 17. With respect to the remaining components and process conditions, the same considerations apply for like components as described inFIG. 3 above. - Therefore, and viewed from a different perspective, an absorber in contemplated plants receives a liquid portion of the natural gas feed and a second vapor portion of the natural gas feed, wherein the second portion is reduced in pressure via a turbo expander. Preferred absorbers produce a bottom product that is expanded, chilled, and fed to the demethanizer for absorption of the C2 + components. Preferred demethanizer bottoms products are subsequently fractionated in a deethanizer into a C2 liquid overhead and a C3+ bottoms product. In a still further contemplated aspect, the absorber produces an overhead vapor product that is predominantly methane at cryogenic temperature (−100° F. or lower), which is further compressed using power generated by turbo-expansion of the feed gas. Such configurations produce a high pressure cryogenic vapor at −75° F. to −100° F. and 800 psig to 900 psig or higher pressure that is subsequently liquefied forming the LNG using the third temperature level refrigeration.
- While configurations according to
FIG. 4 are generally preferred, it should be noted that numerous alternative cooling methods and configurations for the first, second, and/or third cooling stages are also deemed suitable herein. For example,FIG. 5 exemplarily illustrates a plant configuration in which the third temperature range refrigerant at −180° F. to −270° F. is supplied by a cascademethane refrigerant cycle 103, operating with at least three pressure levels. Alternatively, and depending on the residue gas composition and pressure, a pure component refrigerant such as methane may also be appropriate.FIG. 6 illustrates another embodiment in which a propane pre-cooledcascade cycle 104 is added to the discharge of themixed refrigeration system 102. Such alternative refrigeration system is especially suitable when a very high ethane recovery is required or when the feed gas contains a very high ethane and propane content.FIG. 7 illustrates yet another alternative embodiment in which a cascade propane refrigerant, a cascade ethylene refrigerant, and a methane refrigerant are employed for NGL recovery and LNG liquefaction. - Thus, the absorber in contemplated plants and methods is configured to separately receive a first and a second portion of a feed gas vapor and a demethanizer overhead, wherein the first portion of the feed gas vapor and the demethanizer column overhead provide reflux to the absorber. In such configurations, a flow control unit adjusts at least one of the first and second portions of the feed gas vapor to produce the desirable recovery levels of ethane, from 10% to 85% of the feed gas, while maintaining a high C3 (98% or above) recovery. It is still further contemplated that at least a portion of the demethanizer bottoms product is fed to the deethanizer that fractionate the demethanizer bottom product into an ethane overhead and a C3+ bottoms product. Thus, preferred configuration can provide variable C2 production rates by blending at least a portion of the excess overhead C2 liquid with the LNG. It should be especially recognized that this blending step simplifies the NGL recovery plant operation and allows the same process conditions (temperatures and pressures) be maintained, regardless of the net C2 production rates.
- In preferred plants, at least three temperature ranges are provided by one or more vaporizing refrigeration cycles: A first temperature range of 10° F. to −35° F. refrigeration for the feed gas pre-cooling, a second temperature range of −60° F. to −160° F. for the first column reflux, and a third temperature range of −180° F. to −270° F. for gas liquefaction. It is generally preferred that the refrigerant in contemplated refrigeration circuits comprise one, two, or more hydrocarbon components and may further include nitrogen, halocarbons, and/or other refrigerants. Contemplated refrigeration cycles may also include combinations of refrigeration cycles, and especially combinations of a multi-component mixed refrigerant cycles, a single component cascade cycle, a gas expander cycle, and a propane pre-cooled refrigeration cycle. For example, it is contemplated that the first temperature range refrigeration at 10° F. to −35° F. uses propane pre-cooled refrigeration or cascade refrigeration, and cools at least one portion of the feed gas and the refrigerant of the second temperature level. The second temperature level refrigeration at −60° F. to −160° F. may then use a mixed refrigerant cycle or cascade refrigeration using pure component such as ethylene to chill the absorber reflux, and the third temperature level refrigeration at −180° F. to −270° F. may use a mixed refrigerant cycle or cascade refrigeration using pure component such as methane to liquefy the residual gas. Other preferred refrigeration cycles include letdown devices such as turbo-expanders and Joule-Thomson valves. With respect to the temperature levels, (combination of) refrigeration cycles, and cooling media, it should be noted that they may be adjusted as needed to achieve the lowest energy consumption in the cooling and liquefaction processes.
- With respect to remaining components and process conditions in
FIGS. 5-7 , the same considerations apply for like components as described inFIG. 3 above. It should be further appreciated that all components of contemplated configurations (e.g., exchangers, pumps, valves, compressors, expanders, refluxed absorbers, demethanizers, deethanizers, etc.) are commercially available and suitable for use in conjunction with the teachings presented herein. It is further generally contemplated that configurations according to the inventive subject matter may find wide applicability in gas plant applications where high propane and ethane recovery are desirable, and feed gas is available at pressure greater than 800 psig. Moreover, such configurations produce a high pressure cryogenic methane rich vapor that will advantageously reduce equipment and operating costs when integrated to a LNG liquefaction plant. Table 3 below illustrates the temperatures and pressures of the residue gas from the NGL recovery plant and the energy savings of contemplated integrated plants versus heretofore known standalone plants on the basis of 70 mol % ethane recovery. The energy savings of contemplated plant configurations are about 10% as compared to known plants, which may be used to produce an equivalent amount of additional LNG.TABLE 3 Standalone NGL Integrated NGL Recovery/LNG Recovery/LNG Plants Plants Residue Gas Temperature, ° F. 120 −80 to −60 Residue Gas Pressure, psig 550 790 to 900 Total Power Consumption of NGL 360 320 Recovery and Liquefaction, MW - Thus, specific embodiments and applications for integrated NGL recovery and LNG liquefaction have been disclosed. It should be apparent, however, to those skilled in the art that many more modifications besides those already described are possible without departing from the inventive concepts herein. The inventive subject matter, therefore, is not to be restricted except in the spirit of the appended claims. Moreover, in interpreting both the specification and the claims, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms “comprises” and “comprising” should be interpreted as referring to elements, components, or steps in a non-exclusive manner, indicating that the referenced elements, components, or steps may be present, or utilized, or combined with other elements, components, or steps that are not expressly referenced. Furthermore, where a definition or use of a term in a reference, which is incorporated by reference herein is inconsistent or contrary to the definition of that term provided herein, the definition of that term provided herein applies and the definition of that term in the reference does not apply.
Claims (20)
1. A gas processing plant, comprising:
a separator that is configured to receive a partially expanded vapor portion of a natural gas feed stream, and that is further configured to produce a cold overhead product stream;
an expander operationally coupled to drive a compressor, wherein the expander is configured to produce the partially expanded vapor portion and wherein the compressor is configured to produce a compressed cold overhead product stream from the cold overhead product stream; and
wherein the separator and the compressor are fluidly coupled to each other such that the compressed cold overhead product stream has a pressure of at least 700 psig at a temperature of no warmer than −50° F.
2. The plant of claim 1 wherein the separator is configured to receive another expanded vapor portion of the natural gas feed stream at a separate location.
3. The plant of claim 1 wherein the separator is configured to operate as a demethanizer.
4. The plant of claim 3 further comprising a deethanizer that is configured to produce a C3+ product and a C2 product.
5. The plant of claim 4 further comprising a conduit that provides at least part of the C2 product to the cold overhead product stream.
6. The plant of claim 1 wherein the separator is configured to operate as a refluxed absorber.
7. The plant of claim 6 wherein the demethanizer is configured to provide a reflux stream to the absorber.
8. The plant of claim 6 wherein the demethanizer is configured to operate at a lower pressure than the absorber.
9. The plant of claim 6 further comprising at least one of a conduit that provides a cooled absorber bottom product the absorber for C2 recovery and a conduit that provides a heated absorber bottom product the absorber for C2 rejection.
10. A method of producing a liquefied natural gas, comprising:
producing a cold overhead product stream in a separator and compressing the product stream in a compressor without prior substantial heating of the cold product stream;
wherein the compressor is driven by an expander that expands a vapor portion of a natural gas feed, and wherein the expanded vapor portion is fed into the separator; and
liquefying the cold compressed product stream in a liquefaction unit.
11. The method of claim 10 wherein the separator is operated as a demethanizer that further receives another portion of a natural gas feed.
12. The method of claim 10 further comprising a deethanizer that receives a bottom product of the separator and that optionally provides a C2 product to the cold overhead product stream.
13. The method of claim 10 wherein the separator is operated as a refluxed absorber.
14. The method of claim 11 wherein a demethanizer provides a reflux stream to the absorber, wherein the absorber provides a bottom product to the demethanizer, and wherein the demethanizer is operated at a lower pressure than the absorber.
15. The method of claim 14 wherein the absorber bottom product is heated for C2 rejection prior to entering the demethanizer or cooled for C2 recovery prior to entering the demethanizer.
16. The method of claim 14 wherein a deethanizer receives a bottom product of the demethanizer for C2 and C3+ recovery.
17. The method of claim 10 wherein the cold compressed product stream has a pressure of at least 700 psig and a temperature of no warmer than −50° F.
18. A method of producing LNG comprising:
separating in a separator a cold overhead product from a natural gas containing feed gas;
compressing the cold overhead product using expansion energy from the feed gas to form a cold compressed overhead product at a pressure and temperature suitable for liquefaction in a liquefaction unit;
wherein the cold compressed overhead product is formed at neutral or negative net compression energy requirement.
19. The method of claim 17 wherein the step of separating is performed in an absorber or a demethanizer.
20. The method of claim 17 wherein the cold compressed overhead product has a pressure of at least 700 psig and a temperature of no warmer than −50° F.
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US11/479,320 US20070157663A1 (en) | 2005-07-07 | 2006-06-29 | Configurations and methods of integrated NGL recovery and LNG liquefaction |
US13/672,602 US20130061633A1 (en) | 2005-07-07 | 2012-11-08 | Configurations and methods of integrated ngl recovery and lng liquefaction |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US69746705P | 2005-07-07 | 2005-07-07 | |
US11/479,320 US20070157663A1 (en) | 2005-07-07 | 2006-06-29 | Configurations and methods of integrated NGL recovery and LNG liquefaction |
Related Child Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US13/672,602 Division US20130061633A1 (en) | 2005-07-07 | 2012-11-08 | Configurations and methods of integrated ngl recovery and lng liquefaction |
Publications (1)
Publication Number | Publication Date |
---|---|
US20070157663A1 true US20070157663A1 (en) | 2007-07-12 |
Family
ID=37637722
Family Applications (2)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US11/479,320 Abandoned US20070157663A1 (en) | 2005-07-07 | 2006-06-29 | Configurations and methods of integrated NGL recovery and LNG liquefaction |
US13/672,602 Abandoned US20130061633A1 (en) | 2005-07-07 | 2012-11-08 | Configurations and methods of integrated ngl recovery and lng liquefaction |
Family Applications After (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US13/672,602 Abandoned US20130061633A1 (en) | 2005-07-07 | 2012-11-08 | Configurations and methods of integrated ngl recovery and lng liquefaction |
Country Status (7)
Country | Link |
---|---|
US (2) | US20070157663A1 (en) |
EP (1) | EP1904801A2 (en) |
AU (1) | AU2006269436B2 (en) |
CA (1) | CA2614404C (en) |
EA (1) | EA011599B1 (en) |
MX (1) | MX2007015604A (en) |
WO (1) | WO2007008525A2 (en) |
Cited By (35)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20070012072A1 (en) * | 2005-07-12 | 2007-01-18 | Wesley Qualls | Lng facility with integrated ngl extraction technology for enhanced ngl recovery and product flexibility |
US20070056318A1 (en) * | 2005-09-12 | 2007-03-15 | Ransbarger Weldon L | Enhanced heavies removal/LPG recovery process for LNG facilities |
US20080098770A1 (en) * | 2006-10-31 | 2008-05-01 | Conocophillips Company | Intermediate pressure lng refluxed ngl recovery process |
US20090090049A1 (en) * | 2007-10-09 | 2009-04-09 | Chevron U.S.A. Inc. | Process for producing liqefied natural gas from high co2 natural gas |
US20090126401A1 (en) * | 2007-11-15 | 2009-05-21 | Conocophillips Company | Dual-refluxed heavies removal column in an lng facility |
WO2009103715A2 (en) * | 2008-02-20 | 2009-08-27 | Shell Internationale Research Maatschappij B.V. | Method and apparatus for cooling and separating a hydrocarbon stream |
US20090255294A1 (en) * | 2008-04-09 | 2009-10-15 | Chee Seng Teo | Method and apparatus for liquefying a hydrocarbon stream |
US20100050688A1 (en) * | 2008-09-03 | 2010-03-04 | Ameringer Greg E | NGL Extraction from Liquefied Natural Gas |
US20100126214A1 (en) * | 2008-11-25 | 2010-05-27 | Henri Paradowski | Process for the production of a subcooled liquefied natural gas stream from a natural gas feed stream, and associated installation |
US20110011127A1 (en) * | 2009-07-16 | 2011-01-20 | Conocophillips Company | Process for Controlling Liquefied Natural Gas Heating Value |
US20110048067A1 (en) * | 2007-10-26 | 2011-03-03 | Ifp | Natural gas liquefaction method with high-pressure fractionation |
US20110174017A1 (en) * | 2008-10-07 | 2011-07-21 | Donald Victory | Helium Recovery From Natural Gas Integrated With NGL Recovery |
US20120137726A1 (en) * | 2010-12-01 | 2012-06-07 | Black & Veatch Corporation | NGL Recovery from Natural Gas Using a Mixed Refrigerant |
US20130213087A1 (en) * | 2012-02-22 | 2013-08-22 | Black & Veatch Corporation | Ngl recovery from natural gas using a mixed refrigerant |
US8635885B2 (en) | 2010-10-15 | 2014-01-28 | Fluor Technologies Corporation | Configurations and methods of heating value control in LNG liquefaction plant |
WO2014106178A1 (en) | 2012-12-28 | 2014-07-03 | Linde Process Plants, Inc. | Integrated process for ngl (natural gas liquids recovery) and lng (liquefaction of natural gas) |
US20150233634A1 (en) * | 2013-06-18 | 2015-08-20 | Pioneer Energy Inc. | Systems and methods for producing cng and ngls from raw natural gas, flare gas, stranded gas, and/or associated gas |
US20150246859A1 (en) * | 2014-02-28 | 2015-09-03 | Fluor Technologies Corporation | Configurations and Methods for Nitrogen Rejection, LNG and NGL Production from High Nitrogen Feed Gases |
US20150308738A1 (en) * | 2014-04-24 | 2015-10-29 | Air Products And Chemicals, Inc. | Integrated Nitrogen Removal in the Production of Liquefied Natural Gas Using Refrigerated Heat Pump |
US9243842B2 (en) | 2008-02-15 | 2016-01-26 | Black & Veatch Corporation | Combined synthesis gas separation and LNG production method and system |
EP2872842A4 (en) * | 2012-07-12 | 2016-07-06 | Linde Engineering North America Inc | Methods for separating hydrocarbon gases |
US9574822B2 (en) | 2014-03-17 | 2017-02-21 | Black & Veatch Corporation | Liquefied natural gas facility employing an optimized mixed refrigerant system |
US9726426B2 (en) | 2012-07-11 | 2017-08-08 | Butts Properties, Ltd. | System and method for removing excess nitrogen from gas subcooled expander operations |
US20180058753A1 (en) * | 2016-09-01 | 2018-03-01 | Fluor Technologies Corporation | Methods and configurations for lng liquefaction |
WO2018048478A1 (en) * | 2016-09-06 | 2018-03-15 | Lummus Technology Inc. | Pretreatment of natural gas prior to liquefaction |
US20180208855A1 (en) * | 2015-07-23 | 2018-07-26 | L'Air Liquide, Société Anonyme pour I'Etude et I'Exploitation des Procédés Georges Claude | Method for purifying a gas rich in hydrocarbons |
US10113127B2 (en) | 2010-04-16 | 2018-10-30 | Black & Veatch Holding Company | Process for separating nitrogen from a natural gas stream with nitrogen stripping in the production of liquefied natural gas |
WO2019050940A1 (en) * | 2017-09-06 | 2019-03-14 | Linde Engineering North America, Inc. | Methods for providing refrigeration in natural gas liquids recovery plants |
US10520250B2 (en) | 2017-02-15 | 2019-12-31 | Butts Properties, Ltd. | System and method for separating natural gas liquid and nitrogen from natural gas streams |
US10563913B2 (en) | 2013-11-15 | 2020-02-18 | Black & Veatch Holding Company | Systems and methods for hydrocarbon refrigeration with a mixed refrigerant cycle |
US10767922B2 (en) | 2014-04-24 | 2020-09-08 | Air Products And Chemicals, Inc. | Integrated nitrogen removal in the production of liquefied natural gas using intermediate feed gas separation |
US11015865B2 (en) | 2018-08-27 | 2021-05-25 | Bcck Holding Company | System and method for natural gas liquid production with flexible ethane recovery or rejection |
US11112175B2 (en) | 2017-10-20 | 2021-09-07 | Fluor Technologies Corporation | Phase implementation of natural gas liquid recovery plants |
US11365933B2 (en) | 2016-05-18 | 2022-06-21 | Fluor Technologies Corporation | Systems and methods for LNG production with propane and ethane recovery |
US11725879B2 (en) | 2016-09-09 | 2023-08-15 | Fluor Technologies Corporation | Methods and configuration for retrofitting NGL plant for high ethane recovery |
Families Citing this family (13)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
KR20090088372A (en) * | 2006-10-24 | 2009-08-19 | 쉘 인터내셔날 리써취 마트샤피지 비.브이. | Method and apparatus for treating a hydrocarbon stream |
US8505333B2 (en) | 2007-12-10 | 2013-08-13 | Conocophilips Company | Optimized heavies removal system in an LNG facility |
US10451344B2 (en) | 2010-12-23 | 2019-10-22 | Fluor Technologies Corporation | Ethane recovery and ethane rejection methods and configurations |
US20160153454A1 (en) * | 2014-12-01 | 2016-06-02 | Eric Kuegeler | Anti-freeze distribution system |
CN104864682B (en) * | 2015-05-29 | 2018-01-16 | 新奥科技发展有限公司 | A kind of natural gas pipe network pressure energy recoverying and utilizing method and system |
DE102015009254A1 (en) * | 2015-07-16 | 2017-01-19 | Linde Aktiengesellschaft | Process for separating ethane from a hydrocarbon-rich gas fraction |
CA3003614A1 (en) * | 2015-11-06 | 2017-05-11 | Fluor Technologies Corporation | Systems and methods for lng refrigeration and liquefaction |
US10006701B2 (en) | 2016-01-05 | 2018-06-26 | Fluor Technologies Corporation | Ethane recovery or ethane rejection operation |
US11499775B2 (en) | 2020-06-30 | 2022-11-15 | Air Products And Chemicals, Inc. | Liquefaction system |
DE102020004821A1 (en) * | 2020-08-07 | 2022-02-10 | Linde Gmbh | Process and plant for the production of a liquefied natural gas product |
CN112961711B (en) * | 2021-02-08 | 2021-11-26 | 赛鼎工程有限公司 | System and method for preparing LNG (liquefied Natural gas) and coproducing methanol, liquid ammonia and hydrogen through coke oven gas purification |
WO2022203600A1 (en) * | 2021-03-22 | 2022-09-29 | Singapore Lng Corporation Pte Ltd | Methods, apparatus and system for utilising cold energy recovered from a liquefied natural gas feed in a natural gas liquid extraction process |
US11884621B2 (en) | 2021-03-25 | 2024-01-30 | Enerflex Us Holdings Inc. | System, apparatus, and method for hydrocarbon processing |
Citations (7)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US4608069A (en) * | 1984-03-12 | 1986-08-26 | Linde Aktiengesellschaft | Separation of higher boiling impurities from liquefied gases |
US6016665A (en) * | 1997-06-20 | 2000-01-25 | Exxon Production Research Company | Cascade refrigeration process for liquefaction of natural gas |
US6023942A (en) * | 1997-06-20 | 2000-02-15 | Exxon Production Research Company | Process for liquefaction of natural gas |
US6401486B1 (en) * | 2000-05-18 | 2002-06-11 | Rong-Jwyn Lee | Enhanced NGL recovery utilizing refrigeration and reflux from LNG plants |
US6551380B1 (en) * | 1998-11-10 | 2003-04-22 | Fluor Corporation | Recovery of CO2 and H2 from PSA offgas in an H2 plant |
US20040187520A1 (en) * | 2001-06-08 | 2004-09-30 | Wilkinson John D. | Natural gas liquefaction |
US20040206112A1 (en) * | 2002-05-08 | 2004-10-21 | John Mak | Configuration and process for ngli recovery using a subcooled absorption reflux process |
Family Cites Families (7)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US4445916A (en) * | 1982-08-30 | 1984-05-01 | Newton Charles L | Process for liquefying methane |
DE19716415C1 (en) * | 1997-04-18 | 1998-10-22 | Linde Ag | Process for liquefying a hydrocarbon-rich stream |
US6742357B1 (en) * | 2003-03-18 | 2004-06-01 | Air Products And Chemicals, Inc. | Integrated multiple-loop refrigeration process for gas liquefaction |
US6925837B2 (en) * | 2003-10-28 | 2005-08-09 | Conocophillips Company | Enhanced operation of LNG facility equipped with refluxed heavies removal column |
JP4599362B2 (en) * | 2003-10-30 | 2010-12-15 | フルオー・テクノロジーズ・コーポレイシヨン | Universal NGL process and method |
US7204100B2 (en) * | 2004-05-04 | 2007-04-17 | Ortloff Engineers, Ltd. | Natural gas liquefaction |
US20080271480A1 (en) * | 2005-04-20 | 2008-11-06 | Fluor Technologies Corporation | Intergrated Ngl Recovery and Lng Liquefaction |
-
2006
- 2006-06-29 US US11/479,320 patent/US20070157663A1/en not_active Abandoned
- 2006-07-05 WO PCT/US2006/026176 patent/WO2007008525A2/en active Search and Examination
- 2006-07-05 CA CA2614404A patent/CA2614404C/en not_active Expired - Fee Related
- 2006-07-05 EP EP06786357A patent/EP1904801A2/en not_active Withdrawn
- 2006-07-05 AU AU2006269436A patent/AU2006269436B2/en not_active Ceased
- 2006-07-05 EA EA200800267A patent/EA011599B1/en not_active IP Right Cessation
- 2006-07-05 MX MX2007015604A patent/MX2007015604A/en active IP Right Grant
-
2012
- 2012-11-08 US US13/672,602 patent/US20130061633A1/en not_active Abandoned
Patent Citations (7)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US4608069A (en) * | 1984-03-12 | 1986-08-26 | Linde Aktiengesellschaft | Separation of higher boiling impurities from liquefied gases |
US6016665A (en) * | 1997-06-20 | 2000-01-25 | Exxon Production Research Company | Cascade refrigeration process for liquefaction of natural gas |
US6023942A (en) * | 1997-06-20 | 2000-02-15 | Exxon Production Research Company | Process for liquefaction of natural gas |
US6551380B1 (en) * | 1998-11-10 | 2003-04-22 | Fluor Corporation | Recovery of CO2 and H2 from PSA offgas in an H2 plant |
US6401486B1 (en) * | 2000-05-18 | 2002-06-11 | Rong-Jwyn Lee | Enhanced NGL recovery utilizing refrigeration and reflux from LNG plants |
US20040187520A1 (en) * | 2001-06-08 | 2004-09-30 | Wilkinson John D. | Natural gas liquefaction |
US20040206112A1 (en) * | 2002-05-08 | 2004-10-21 | John Mak | Configuration and process for ngli recovery using a subcooled absorption reflux process |
Cited By (66)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20070012072A1 (en) * | 2005-07-12 | 2007-01-18 | Wesley Qualls | Lng facility with integrated ngl extraction technology for enhanced ngl recovery and product flexibility |
US20070056318A1 (en) * | 2005-09-12 | 2007-03-15 | Ransbarger Weldon L | Enhanced heavies removal/LPG recovery process for LNG facilities |
US20080098770A1 (en) * | 2006-10-31 | 2008-05-01 | Conocophillips Company | Intermediate pressure lng refluxed ngl recovery process |
US20090090049A1 (en) * | 2007-10-09 | 2009-04-09 | Chevron U.S.A. Inc. | Process for producing liqefied natural gas from high co2 natural gas |
US9222724B2 (en) * | 2007-10-26 | 2015-12-29 | IFP Energies Nouvelles | Natural gas liquefaction method with high-pressure fractionation |
US20110048067A1 (en) * | 2007-10-26 | 2011-03-03 | Ifp | Natural gas liquefaction method with high-pressure fractionation |
US20090126401A1 (en) * | 2007-11-15 | 2009-05-21 | Conocophillips Company | Dual-refluxed heavies removal column in an lng facility |
US9377239B2 (en) * | 2007-11-15 | 2016-06-28 | Conocophillips Company | Dual-refluxed heavies removal column in an LNG facility |
US9243842B2 (en) | 2008-02-15 | 2016-01-26 | Black & Veatch Corporation | Combined synthesis gas separation and LNG production method and system |
WO2009103715A2 (en) * | 2008-02-20 | 2009-08-27 | Shell Internationale Research Maatschappij B.V. | Method and apparatus for cooling and separating a hydrocarbon stream |
WO2009103715A3 (en) * | 2008-02-20 | 2014-10-02 | Shell Internationale Research Maatschappij B.V. | Method and apparatus for cooling and separating a hydrocarbon stream |
AU2009235461B2 (en) * | 2008-04-09 | 2012-04-26 | Shell Internationale Research Maatschappij B.V. | Method and apparatus for liquefying a hydrocarbon stream |
CN102762944A (en) * | 2008-04-09 | 2012-10-31 | 国际壳牌研究有限公司 | Method and apparatus for liquefying a hydrocarbon stream |
WO2009124925A3 (en) * | 2008-04-09 | 2012-11-22 | Shell Internationale Research Maatschappij B.V. | Method and apparatus for liquefying a hydrocarbon stream |
US8534094B2 (en) * | 2008-04-09 | 2013-09-17 | Shell Oil Company | Method and apparatus for liquefying a hydrocarbon stream |
US9310127B2 (en) | 2008-04-09 | 2016-04-12 | Shell Oil Company | Method and apparatus for liquefying a hydrocarbon stream |
US20090255294A1 (en) * | 2008-04-09 | 2009-10-15 | Chee Seng Teo | Method and apparatus for liquefying a hydrocarbon stream |
US20100050688A1 (en) * | 2008-09-03 | 2010-03-04 | Ameringer Greg E | NGL Extraction from Liquefied Natural Gas |
US20110174017A1 (en) * | 2008-10-07 | 2011-07-21 | Donald Victory | Helium Recovery From Natural Gas Integrated With NGL Recovery |
US20100126214A1 (en) * | 2008-11-25 | 2010-05-27 | Henri Paradowski | Process for the production of a subcooled liquefied natural gas stream from a natural gas feed stream, and associated installation |
US9506690B2 (en) * | 2008-11-25 | 2016-11-29 | Technip France | Process for the production of a subcooled liquefied natural gas stream from a natural gas feed stream, and associated installation |
US20110011127A1 (en) * | 2009-07-16 | 2011-01-20 | Conocophillips Company | Process for Controlling Liquefied Natural Gas Heating Value |
US10082331B2 (en) | 2009-07-16 | 2018-09-25 | Conocophillips Company | Process for controlling liquefied natural gas heating value |
US10113127B2 (en) | 2010-04-16 | 2018-10-30 | Black & Veatch Holding Company | Process for separating nitrogen from a natural gas stream with nitrogen stripping in the production of liquefied natural gas |
US8635885B2 (en) | 2010-10-15 | 2014-01-28 | Fluor Technologies Corporation | Configurations and methods of heating value control in LNG liquefaction plant |
US20120137726A1 (en) * | 2010-12-01 | 2012-06-07 | Black & Veatch Corporation | NGL Recovery from Natural Gas Using a Mixed Refrigerant |
US9777960B2 (en) * | 2010-12-01 | 2017-10-03 | Black & Veatch Holding Company | NGL recovery from natural gas using a mixed refrigerant |
US20130213087A1 (en) * | 2012-02-22 | 2013-08-22 | Black & Veatch Corporation | Ngl recovery from natural gas using a mixed refrigerant |
US10139157B2 (en) * | 2012-02-22 | 2018-11-27 | Black & Veatch Holding Company | NGL recovery from natural gas using a mixed refrigerant |
US10708741B2 (en) | 2012-07-11 | 2020-07-07 | Butts Properties, Ltd. | System and method for reducing nitrogen content of GSP/expander product streams for pipeline transport |
US10048001B2 (en) | 2012-07-11 | 2018-08-14 | Butts Properties, Ltd. | System and method for reducing nitrogen content of GSP/expander product streams for pipeline transport |
US9726426B2 (en) | 2012-07-11 | 2017-08-08 | Butts Properties, Ltd. | System and method for removing excess nitrogen from gas subcooled expander operations |
EP2872842A4 (en) * | 2012-07-12 | 2016-07-06 | Linde Engineering North America Inc | Methods for separating hydrocarbon gases |
WO2014106178A1 (en) | 2012-12-28 | 2014-07-03 | Linde Process Plants, Inc. | Integrated process for ngl (natural gas liquids recovery) and lng (liquefaction of natural gas) |
US9803917B2 (en) | 2012-12-28 | 2017-10-31 | Linde Engineering North America, Inc. | Integrated process for NGL (natural gas liquids recovery) and LNG (liquefaction of natural gas) |
US20170336138A1 (en) * | 2012-12-28 | 2017-11-23 | Linde Engineering North America Inc. | Integrated process for ngl (natural gas liquids recovery) and lng (liquefaction of natural gas) |
US20150233634A1 (en) * | 2013-06-18 | 2015-08-20 | Pioneer Energy Inc. | Systems and methods for producing cng and ngls from raw natural gas, flare gas, stranded gas, and/or associated gas |
US10563913B2 (en) | 2013-11-15 | 2020-02-18 | Black & Veatch Holding Company | Systems and methods for hydrocarbon refrigeration with a mixed refrigerant cycle |
US20170023293A1 (en) * | 2014-02-28 | 2017-01-26 | Fluor Technologies Corporation | Configurations and methods for nitrogen rejection, lng and ngl production from high nitrogen feed gases |
US9920986B2 (en) * | 2014-02-28 | 2018-03-20 | Fluor Technologies Corporation | Configurations and methods for nitrogen rejection, LNG and NGL production from high nitrogen feed gases |
US20150246859A1 (en) * | 2014-02-28 | 2015-09-03 | Fluor Technologies Corporation | Configurations and Methods for Nitrogen Rejection, LNG and NGL Production from High Nitrogen Feed Gases |
US9487458B2 (en) * | 2014-02-28 | 2016-11-08 | Fluor Corporation | Configurations and methods for nitrogen rejection, LNG and NGL production from high nitrogen feed gases |
US9574822B2 (en) | 2014-03-17 | 2017-02-21 | Black & Veatch Corporation | Liquefied natural gas facility employing an optimized mixed refrigerant system |
US20150308738A1 (en) * | 2014-04-24 | 2015-10-29 | Air Products And Chemicals, Inc. | Integrated Nitrogen Removal in the Production of Liquefied Natural Gas Using Refrigerated Heat Pump |
US9945604B2 (en) * | 2014-04-24 | 2018-04-17 | Air Products And Chemicals, Inc. | Integrated nitrogen removal in the production of liquefied natural gas using refrigerated heat pump |
US10767922B2 (en) | 2014-04-24 | 2020-09-08 | Air Products And Chemicals, Inc. | Integrated nitrogen removal in the production of liquefied natural gas using intermediate feed gas separation |
US11060037B2 (en) * | 2015-07-23 | 2021-07-13 | L'Air Liquide, Société Anonyme pour l'Etude et l'Exploitation des Procédés Georges Claude | Method for purifying a gas rich in hydrocarbons |
US20180208855A1 (en) * | 2015-07-23 | 2018-07-26 | L'Air Liquide, Société Anonyme pour I'Etude et I'Exploitation des Procédés Georges Claude | Method for purifying a gas rich in hydrocarbons |
US11365933B2 (en) | 2016-05-18 | 2022-06-21 | Fluor Technologies Corporation | Systems and methods for LNG production with propane and ethane recovery |
US10605522B2 (en) * | 2016-09-01 | 2020-03-31 | Fluor Technologies Corporation | Methods and configurations for LNG liquefaction |
US20180058753A1 (en) * | 2016-09-01 | 2018-03-01 | Fluor Technologies Corporation | Methods and configurations for lng liquefaction |
KR102243894B1 (en) | 2016-09-06 | 2021-04-22 | 러머스 테크놀러지 인코포레이티드 | Pretreatment of natural gas before liquefaction |
AU2017324000B2 (en) * | 2016-09-06 | 2021-07-15 | Lummus Technology Inc. | Pretreatment of natural gas prior to liquefaction |
US11402155B2 (en) | 2016-09-06 | 2022-08-02 | Lummus Technology Inc. | Pretreatment of natural gas prior to liquefaction |
WO2018048478A1 (en) * | 2016-09-06 | 2018-03-15 | Lummus Technology Inc. | Pretreatment of natural gas prior to liquefaction |
KR20190046946A (en) * | 2016-09-06 | 2019-05-07 | 러머스 테크놀러지 인코포레이티드 | Pre-liquefaction pretreatment of natural gas |
JP2019529853A (en) * | 2016-09-06 | 2019-10-17 | ルマス テクノロジー インコーポレイテッド | Pretreatment of natural gas prior to liquefaction |
EP3510128A4 (en) * | 2016-09-06 | 2020-05-27 | Lummus Technology Inc. | Pretreatment of natural gas prior to liquefaction |
US11725879B2 (en) | 2016-09-09 | 2023-08-15 | Fluor Technologies Corporation | Methods and configuration for retrofitting NGL plant for high ethane recovery |
US10520250B2 (en) | 2017-02-15 | 2019-12-31 | Butts Properties, Ltd. | System and method for separating natural gas liquid and nitrogen from natural gas streams |
US11125497B2 (en) | 2017-02-15 | 2021-09-21 | Bcck Holding Company | System and method for separating natural gas liquid and nitrogen from natural gas streams |
RU2763101C2 (en) * | 2017-09-06 | 2021-12-27 | Линде Инжиниринг Норт Америка, Инк. | Methods for cold supply in installations for extraction of gas condensate liquids |
US11268757B2 (en) | 2017-09-06 | 2022-03-08 | Linde Engineering North America, Inc. | Methods for providing refrigeration in natural gas liquids recovery plants |
WO2019050940A1 (en) * | 2017-09-06 | 2019-03-14 | Linde Engineering North America, Inc. | Methods for providing refrigeration in natural gas liquids recovery plants |
US11112175B2 (en) | 2017-10-20 | 2021-09-07 | Fluor Technologies Corporation | Phase implementation of natural gas liquid recovery plants |
US11015865B2 (en) | 2018-08-27 | 2021-05-25 | Bcck Holding Company | System and method for natural gas liquid production with flexible ethane recovery or rejection |
Also Published As
Publication number | Publication date |
---|---|
WO2007008525A2 (en) | 2007-01-18 |
CA2614404C (en) | 2011-05-24 |
WO2007008525B1 (en) | 2007-12-13 |
EP1904801A2 (en) | 2008-04-02 |
MX2007015604A (en) | 2008-02-19 |
WO2007008525A3 (en) | 2007-11-08 |
EA200800267A1 (en) | 2008-06-30 |
AU2006269436B2 (en) | 2009-11-12 |
US20130061633A1 (en) | 2013-03-14 |
AU2006269436A1 (en) | 2007-01-18 |
CA2614404A1 (en) | 2007-01-18 |
EA011599B1 (en) | 2009-04-28 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
CA2614404C (en) | Configurations and methods of integrated ngl recovery and lng liquefaction | |
CA2619021C (en) | Integrated ngl recovery and lng liquefaction | |
US6945075B2 (en) | Natural gas liquefaction | |
US7204100B2 (en) | Natural gas liquefaction | |
US9803917B2 (en) | Integrated process for NGL (natural gas liquids recovery) and LNG (liquefaction of natural gas) | |
AU2006262789B2 (en) | Hydrocarbon gas processing | |
AU2008251750B2 (en) | Hydrocarbon gas processing | |
AU735706B2 (en) | Process for liquefying a natural gas stream containing at least one freezable component | |
CA2513677C (en) | Multiple reflux stream hydrocarbon recovery process | |
US8635885B2 (en) | Configurations and methods of heating value control in LNG liquefaction plant | |
US6672104B2 (en) | Reliquefaction of boil-off from liquefied natural gas | |
US11365933B2 (en) | Systems and methods for LNG production with propane and ethane recovery | |
JP5683277B2 (en) | Method and apparatus for cooling hydrocarbon streams | |
US20090293538A1 (en) | Natural gas liquefaction | |
US20100175424A1 (en) | Methods and apparatus for liquefaction of natural gas and products therefrom | |
WO1998059205A2 (en) | Improved process for liquefaction of natural gas | |
MX2011000840A (en) | Liquefied natural gas production. | |
EA010538B1 (en) | Natural gas liquefaction | |
CA2755079C (en) | Configurations and methods of heating value control in lng liquefaction plant |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |