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US20190376741A1 - Lng process for variable pipeline gas composition - Google Patents

Lng process for variable pipeline gas composition Download PDF

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Publication number
US20190376741A1
US20190376741A1 US15/954,771 US201815954771A US2019376741A1 US 20190376741 A1 US20190376741 A1 US 20190376741A1 US 201815954771 A US201815954771 A US 201815954771A US 2019376741 A1 US2019376741 A1 US 2019376741A1
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United States
Prior art keywords
heavies removal
natural gas
column
demethanizer
distillation column
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
Application number
US15/954,771
Inventor
Attilio J. Praderio
Qi Ma
Wesley R. Qualls
Will T. JAMES
Michael J. Calderon
Paul R. Davies
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
ConocoPhillips Co
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ConocoPhillips Co
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by ConocoPhillips Co filed Critical ConocoPhillips Co
Priority to AU2018254411A priority Critical patent/AU2018254411B2/en
Priority to PCT/US2018/027868 priority patent/WO2018195013A1/en
Priority to US15/954,771 priority patent/US20190376741A1/en
Priority to CA3060940A priority patent/CA3060940A1/en
Publication of US20190376741A1 publication Critical patent/US20190376741A1/en
Assigned to CONOCOPHILLIPS COMPANY reassignment CONOCOPHILLIPS COMPANY ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: PRADERIO, ATTILIO J., DAVIES, PAUL R., JAMES, Will T., MA, QI, QUALLS, WESLEY R., CALDERON, MICHAEL J.
Priority to US17/815,178 priority patent/US20220364005A1/en
Abandoned legal-status Critical Current

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    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F25J1/0243—Start-up or control of the process; Details of the apparatus used; Details of the refrigerant compression system used
    • F25J1/0244—Operation; Control and regulation; Instrumentation
    • F25J1/0254—Operation; Control and regulation; Instrumentation controlling particular process parameter, e.g. pressure, temperature
    • F25J1/0255—Operation; Control and regulation; Instrumentation controlling particular process parameter, e.g. pressure, temperature controlling the composition of the feed or liquefied gas, e.g. to achieve a particular heating value of natural gas
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G5/00—Recovery of liquid hydrocarbon mixtures from gases, e.g. natural gas
    • C10G5/06—Recovery of liquid hydrocarbon mixtures from gases, e.g. natural gas by cooling or compressing
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G70/00—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00
    • C10G70/04—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00 by physical processes
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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
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    • C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
    • C10L2290/543—Distillation, fractionation or rectification for separating fractions, components or impurities during preparation or upgrading of a fuel
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    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
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    • F25J2280/02—Control in general, load changes, different modes ("runs"), measurements
    • 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
    • F25J2280/00—Control of the process or apparatus
    • F25J2280/10—Control for or during start-up and cooling down of the installation
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J2290/00—Other details not covered by groups F25J2200/00 - F25J2280/00
    • F25J2290/60—Details about pipelines, i.e. network, for feed or product distribution

Definitions

  • the present invention relates generally to a method and apparatus for processing natural gas.
  • methods and apparatus provide stable processing of liquefied natural gas (LNG) across a highly variable and wide range of feed compositions.
  • LNG liquefied natural gas
  • Liquefied Natural Gas (LNG) liquefaction facilities accept feed gas (e.g., methane, ethane, propane, butane, carbon dioxide, nitrogen, etc.) which is converted into a liquefied form through various treatment processes (e.g., impurities removal, multi-stage cooling, etc.). These facilities are typically designed to accept feed gas compositions that fall within a specified range. Variability of the feed gas composition that exceeds a facility's capabilities can lead to frequent upsetting of the liquefaction process. This excessive variability may be particularly troublesome when liquefying pipeline feed gas.
  • feed gas e.g., methane, ethane, propane, butane, carbon dioxide, nitrogen, etc.
  • treatment processes e.g., impurities removal, multi-stage cooling, etc.
  • the present invention relates generally to a method and apparatus for processing natural gas.
  • methods and apparatus provide stable processing of liquefied natural gas (LNG) across a highly variable and wide range of feed compositions.
  • LNG liquefied natural gas
  • the invention more particularly relates to a system, method and apparatus for processing natural gas in an LNG facility.
  • a natural gas feed is introduced into a heavies removal unit, wherein the heavies removal system includes a heavies removal column and a distillation column, wherein the heavies removal column and the distillation column are fluidly connected.
  • One or more components of the natural gas feed is purged from the heavies removal column to a methane recycle stream via the purge/recovery line to obtain a specified concentration or concentration range of heavy components feeding into the distillation column.
  • the invention more particularly relates to a system, method and apparatus for processing natural gas feed during natural gas liquefaction.
  • the natural gas feed is introduced into a heavies removal unit, wherein the heavies removal system includes a heavies removal column and a demethanizer, wherein the heavies removal column and the demethanizer are fluidly connected.
  • the heavies removal column is downstream of the demethanizer.
  • the composition of the natural gas feed is determined before it is introduced into the demethanizer.
  • One or more heavy components of the natural gas feed is purged from the heavies removal column to a methane recycle stream via the purge/recovery line to reduce or increase concentration of heavy components feeding into the demethanizer.
  • FIGS. 1A-1B illustrate sample variability in feed gas composition from pipeline.
  • FIG. 1A shows methane mole % during a 3 week window.
  • FIG. 1B shows ethane mole % during the same 3 week window.
  • FIG. 2 illustrates a heavies removal unit in accordance with an embodiment of the present invention.
  • the Optimized Cascade Process is based on three multi-staged, cascading refrigerants circuits using pure refrigerants, brazed aluminum heat exchangers and insulated cold box modules. Pure refrigerants of propane (or propylene), ethylene, and methane are utilized.
  • the Optimized Cascade Process may use a heavies removal distillation column (heavies removal unit or HRU) to eliminate C6+ hydrocarbons (i.e. heavy components) from the natural gas prior to condensing the gas to LNG.
  • HRU heavies removal distillation column
  • C6+ hydrocarbons i.e. heavy components
  • gas has already been amine treated and dehydrated prior to heavies removal. Heavies removal is done to prevent freezing from occurring in the liquefaction heat exchangers and to moderate the heating value of the LNG. It also prevents LNG from going off spec due to increased levels of heavy components.
  • FIGS. 1A-1B illustrate an example of variability in methane and ethane composition of natural gas feed in an LNG liquefaction facility during a 3 week period.
  • a first column (demethanizer) within a Heavies Removal Unit may be used to reflux relatively heavy components originating from downstream column overheads.
  • a first column (demethanizer) within a Heavies Removal Unit may be used to reflux relatively heavy components originating from downstream column overheads.
  • lean methane reflux unit may be used.
  • the lean reflux unit is also less than ideal for used at all times (this unit is typically designed for startup) for all feed gas compositions.
  • Equipment for the lean methane reflux as well as the demethanizer are typically not sized for operation at full feed rates but rather at reduced rates until sufficient heavies are cycled up to create a heavies reflux during startup.
  • the present invention provides a method for purging undesirable components present in a gas feed stream to the methane recycle system where the components can be recovered as valuable product.
  • This purge can be accomplished using a purge/recovery line.
  • the rate of purging from the heavies removal system may be adjusted to absorb the compositional variations of the feed gas. Once the heavier components enter the methane recycle stream, the combined stream becomes easier to condense which conserves refrigeration horsepower.
  • the purge/recovery line makes the overall LNG plant stable and more efficient across a wide range of pipeline compositions with high compositional variability.
  • the present invention provides a method for purging undesirable problematic gas components that would otherwise cycle up to the recycle stream. Instead, the purged gas components can be recovered in the LNG stream without concern of freezing.
  • Flow through the purge/recovery line may be adjusted to fix the flow rate recycle to the high pressure demethanizer feed. Since approximately 50% of the liquid in the bottom portion of the high pressure demethanizer are recycled liquids, this greatly stabilizes the high pressure demethanizer operation.
  • the addition of this purge/recovery line also reduces the cycle up of components that otherwise must be fueled and/or flared. By controlling the rate through the purge/recovery line, a fixed set of operating setpoints for all columns are possible for over about 80% of the feed range without operating intervention or setpoint changes.
  • the invention provides very stable operation across a highly variable and wide range of feed compositions with minimal operator intervention.
  • the purged problematic components can be efficiently recovered as LNG.
  • the purged components from the heavies removal unit are routed to a methane recycle stream that is condensed with ethylene refrigeration in the optimized cascade process.
  • the introduction of heavier components within the methane recycle makes condensing with ethylene easier which in turn conserves ethylene turbine horsepower requirements.
  • Adjusting the rate of the purge/recovery line allows one to fix a major portion of the heavy components recycled to the high pressure demethanizer feed, thus greatly helping to stabilize the feed across a wide range of compositions.
  • the present invention purge/recover line acts as a compositional shock absorber for variable pipeline gas.
  • the invention eliminates the need to route cycled up pentanes and heavier components to fuel, which is less economical than recovering as product. The pentanes and heavier are also problematic in the fuel gas system.
  • the present invention allows a single set of operating conditions over 80% or more of the pipeline rates, compositional variations, allowing minimal operator intervention.
  • the present invention offers the ability to process a wider range of compositions and higher pipeline compositional variations than other current technology available with minimal operator intervention.
  • natural gas feed is introduced into the heavies removal unit 10 (perforated box) via inlet 20 .
  • the natural gas feed is then routed to the heavies removal column 30 within the heavies removal unit 10 where it is then separated into light and heavy components.
  • the light components are routed to a demethanizer 100 via a line 50 that connects a top portion of the heavies removal column 30 to a mid/top portion of the demethanizer 100 .
  • the heavy components are routed to the demethanizer 100 via a line 60 that connects a bottom portion of the heavies removal column to a mid/bottom portion of the demethanizer 100 .
  • a purge/recovery line 40 that removes heavies (C6+) to methane recycle stream is shown.
  • the demethanizer 100 is a distillation column.
  • the top portion 110 of the demethanizer 100 is for heavy reflux at full feed rates (but also works acceptably with lean reflux) and may include a condenser, reflux drum, pump, and the like.
  • the bottom portion of the demethanizer 120 is reboiling and may include a reboiler, steam condensate, and the like. As shown, lean reflux is needed for normal operation of the demethanizer 100 .
  • the heavies removal unit is relatively simple and easy to operate. It is able to handle a wide range of feed compositions with minimal operator interaction. The unit is also able to operate with minimal, if any, flaring.

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  • General Engineering & Computer Science (AREA)
  • Chemical & Material Sciences (AREA)
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Abstract

The invention relates to a system, method and apparatus for processing natural gas in an LNG facility. A natural gas feed is introduced into a heavies removal unit. The heavies removal system includes a heavies removal column and a distillation column. The heavies removal column and the distillation column are connected via a purge/recovery line. One or more components of the natural gas feed is purged from the heavies removal column to the distillation column via the purge/recovery line to obtain a specified concentration or concentration range of heavy components feeding into the distillation column.

Description

    CROSS-REFERENCE TO RELATED APPLICATIONS
  • This application is a non-provisional application which claims benefit under 35 USC § 119(e) to U.S. Provisional Application Ser. No. 62/487,170 filed Apr. 19, 2017, entitled “LNG PROCESS FOR VARIABLE PIPELINE GAS COMPOSITION” which is incorporated herein in its entirety.
    • FIELD OF THE INVENTION
  • The present invention relates generally to a method and apparatus for processing natural gas. In another aspect, methods and apparatus provide stable processing of liquefied natural gas (LNG) across a highly variable and wide range of feed compositions.
    • BACKGROUND OF THE INVENTION
  • Liquefied Natural Gas (LNG) liquefaction facilities accept feed gas (e.g., methane, ethane, propane, butane, carbon dioxide, nitrogen, etc.) which is converted into a liquefied form through various treatment processes (e.g., impurities removal, multi-stage cooling, etc.). These facilities are typically designed to accept feed gas compositions that fall within a specified range. Variability of the feed gas composition that exceeds a facility's capabilities can lead to frequent upsetting of the liquefaction process. This excessive variability may be particularly troublesome when liquefying pipeline feed gas.
    • BRIEF SUMMARY OF THE DISCLOSURE
  • The present invention relates generally to a method and apparatus for processing natural gas. In another aspect, methods and apparatus provide stable processing of liquefied natural gas (LNG) across a highly variable and wide range of feed compositions.
  • The invention more particularly relates to a system, method and apparatus for processing natural gas in an LNG facility. A natural gas feed is introduced into a heavies removal unit, wherein the heavies removal system includes a heavies removal column and a distillation column, wherein the heavies removal column and the distillation column are fluidly connected. One or more components of the natural gas feed is purged from the heavies removal column to a methane recycle stream via the purge/recovery line to obtain a specified concentration or concentration range of heavy components feeding into the distillation column.
  • The invention more particularly relates to a system, method and apparatus for processing natural gas feed during natural gas liquefaction. The natural gas feed is introduced into a heavies removal unit, wherein the heavies removal system includes a heavies removal column and a demethanizer, wherein the heavies removal column and the demethanizer are fluidly connected. The heavies removal column is downstream of the demethanizer. The composition of the natural gas feed is determined before it is introduced into the demethanizer. One or more heavy components of the natural gas feed is purged from the heavies removal column to a methane recycle stream via the purge/recovery line to reduce or increase concentration of heavy components feeding into the demethanizer.
    • BRIEF DESCRIPTION OF THE DRAWINGS
  • A more complete understanding of the present invention and benefits thereof may be acquired by referring to the follow description taken in conjunction with the accompanying drawings in which:
  • FIGS. 1A-1B illustrate sample variability in feed gas composition from pipeline. FIG. 1A shows methane mole % during a 3 week window. FIG. 1B shows ethane mole % during the same 3 week window.
  • FIG. 2 illustrates a heavies removal unit in accordance with an embodiment of the present invention.
    •  DETAILED DESCRIPTION
  • Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.
  • The following examples of certain embodiments of the invention are given. Each example is provided by way of explanation of the invention, one of many embodiments of the invention, and the following examples should not be read to limit, or define, the scope of the invention.
  • Recent LNG projects have introduced pipelines as the source of feed gas in an LNG Optimized Cascade Process (OCP). The Optimized Cascade Process is based on three multi-staged, cascading refrigerants circuits using pure refrigerants, brazed aluminum heat exchangers and insulated cold box modules. Pure refrigerants of propane (or propylene), ethylene, and methane are utilized.
  • The Optimized Cascade Process may use a heavies removal distillation column (heavies removal unit or HRU) to eliminate C6+ hydrocarbons (i.e. heavy components) from the natural gas prior to condensing the gas to LNG. In the usual case gas has already been amine treated and dehydrated prior to heavies removal. Heavies removal is done to prevent freezing from occurring in the liquefaction heat exchangers and to moderate the heating value of the LNG. It also prevents LNG from going off spec due to increased levels of heavy components.
  • One major technical problem with the LNG projects involving pipeline feed gas is that the gas feed encompasses a wider range of compositions than normally anticipated and/or designed to process. In other words, heavies removal units typically require hydrocarbon reflux meeting appropriate quality and quantity standards to achieve effective and efficient removal of heavy hydrocarbons. Lean natural gas sources lacking adequate amounts of C2-C4 hydrocarbons may not be suitable for refluxed heavies removal units because of the difficulty in generating sufficient quantities of reflux stream with satisfactory composition. Still, lean natural gases may contain significant amounts of C6+ hydrocarbons that can freeze and/or deposit in downstream cryogenic liquefaction equipment. FIGS. 1A-1B illustrate an example of variability in methane and ethane composition of natural gas feed in an LNG liquefaction facility during a 3 week period.
  • In a typical OCP setup, a first column (demethanizer) within a Heavies Removal Unit may be used to reflux relatively heavy components originating from downstream column overheads. When there is high variability of feed gas compositions, refluxing with heavier components from downstream column overheads is not possible for all feed compositions.
  • Alternatively, lean methane reflux unit may be used. However, the lean reflux unit is also less than ideal for used at all times (this unit is typically designed for startup) for all feed gas compositions. Equipment for the lean methane reflux as well as the demethanizer are typically not sized for operation at full feed rates but rather at reduced rates until sufficient heavies are cycled up to create a heavies reflux during startup.
  • With the inability to reflux with heavy components, a startup/offtest line recycling heavy components from the downstream two column overhead streams tends may be installed. In this setup, recycling the heavy components back to the feed line tends to cycle up propane and heavier components, which eventually must be either fueled or flared. Continual adjustments of operating setpoints are required to process the highly variable gas leading to frequent upsets.
  • The present invention provides a method for purging undesirable components present in a gas feed stream to the methane recycle system where the components can be recovered as valuable product. This purge can be accomplished using a purge/recovery line. The rate of purging from the heavies removal system may be adjusted to absorb the compositional variations of the feed gas. Once the heavier components enter the methane recycle stream, the combined stream becomes easier to condense which conserves refrigeration horsepower. Thus, the purge/recovery line makes the overall LNG plant stable and more efficient across a wide range of pipeline compositions with high compositional variability.
  • According to an embodiment, the present invention provides a method for purging undesirable problematic gas components that would otherwise cycle up to the recycle stream. Instead, the purged gas components can be recovered in the LNG stream without concern of freezing. Flow through the purge/recovery line may be adjusted to fix the flow rate recycle to the high pressure demethanizer feed. Since approximately 50% of the liquid in the bottom portion of the high pressure demethanizer are recycled liquids, this greatly stabilizes the high pressure demethanizer operation. The addition of this purge/recovery line also reduces the cycle up of components that otherwise must be fueled and/or flared. By controlling the rate through the purge/recovery line, a fixed set of operating setpoints for all columns are possible for over about 80% of the feed range without operating intervention or setpoint changes. Thus, the invention provides very stable operation across a highly variable and wide range of feed compositions with minimal operator intervention.
  • As alluded to earlier, one of the advantages of the present invention is that the purged problematic components can be efficiently recovered as LNG. In one embodiment, the purged components from the heavies removal unit are routed to a methane recycle stream that is condensed with ethylene refrigeration in the optimized cascade process. The introduction of heavier components within the methane recycle makes condensing with ethylene easier which in turn conserves ethylene turbine horsepower requirements. Adjusting the rate of the purge/recovery line allows one to fix a major portion of the heavy components recycled to the high pressure demethanizer feed, thus greatly helping to stabilize the feed across a wide range of compositions. Fixing the portion of overhead from the second column returned to the system and allowing remaining flow to continuously purge to a system where it can be efficiently recovered as valuable LNG product, provides a means to continuously adjust to variable pipeline compositions with minimal operator intervention. The present invention purge/recover line acts as a compositional shock absorber for variable pipeline gas. The invention eliminates the need to route cycled up pentanes and heavier components to fuel, which is less economical than recovering as product. The pentanes and heavier are also problematic in the fuel gas system. The present invention allows a single set of operating conditions over 80% or more of the pipeline rates, compositional variations, allowing minimal operator intervention. The present invention offers the ability to process a wider range of compositions and higher pipeline compositional variations than other current technology available with minimal operator intervention.
  • Referring to FIG. 2, natural gas feed is introduced into the heavies removal unit 10 (perforated box) via inlet 20. The natural gas feed is then routed to the heavies removal column 30 within the heavies removal unit 10 where it is then separated into light and heavy components. The light components are routed to a demethanizer 100 via a line 50 that connects a top portion of the heavies removal column 30 to a mid/top portion of the demethanizer 100. The heavy components are routed to the demethanizer 100 via a line 60 that connects a bottom portion of the heavies removal column to a mid/bottom portion of the demethanizer 100. A purge/recovery line 40 that removes heavies (C6+) to methane recycle stream is shown.
  • As shown in FIG. 2, the demethanizer 100 is a distillation column. The top portion 110 of the demethanizer 100 is for heavy reflux at full feed rates (but also works acceptably with lean reflux) and may include a condenser, reflux drum, pump, and the like. The bottom portion of the demethanizer 120 is reboiling and may include a reboiler, steam condensate, and the like. As shown, lean reflux is needed for normal operation of the demethanizer 100.
  • The heavies removal unit is relatively simple and easy to operate. It is able to handle a wide range of feed compositions with minimal operator interaction. The unit is also able to operate with minimal, if any, flaring.
  • In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as a additional embodiments of the present invention.
  • Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.

Claims (12)

1. A method for processing natural gas in an LNG facility comprising:
introducing a natural gas feed to a heavies removal unit, wherein the heavies removal system includes a heavies removal column and a distillation column, wherein the heavies removal column and the distillation column are fluidly connected; and
purging one or more components of the natural gas feed from the heavies removal column to a methane recycle stream via the purge/recovery line to obtain a specified concentration or concentration range of heavy components feeding into the distillation column.
2. The method of claim 1, wherein the distillation column is a high pressure demethanizer.
3. The method of claim 1, further comprising:
adjusting rate of the purging based in order to adjust flow rate to the distillation column.
4. The method of claim 1, wherein the LNG facility is configured for a cascade liquefaction process.
5. The method of claim 1, wherein the heavies removal column is downstream of the distillation column.
6. The method of claim 1, wherein the purging removes hydrocarbons having 6 or more carbons.
7. A method for processing natural gas feed during natural gas liquefaction comprising:
introducing the natural gas feed into a heavies removal unit, wherein the heavies removal system includes a heavies removal column and a demethanizer, wherein the heavies removal column and the demethanizer are fluidly connected and wherein the heavies removal column is downstream of the demethanizer;
determining composition of the natural gas feed before it is introduced into the demethanizer; and
purging one or more heavy components of the natural gas feed from the heavies removal column to a methane recycle stream via the purge/recovery line to reduce or increase concentration of heavy components feeding into the demethanizer.
8. The method of claim 7, further comprising:
adjusting rate of the purging in order to adjust flow rate to the distillation column.
9. The method of claim 7, wherein the natural gas liquefaction is a cascade liquefaction process.
10. The method of claim 7, wherein at least three pure refrigerants are used in the cascade liquefaction process.
11. The method of claim 10, wherein the pure refrigerants include methane, ethane, ethylene, propane, or propylene.
12. The method of claim 7, wherein the heavy components comprise carbon molecules having 6 or more carbon atoms.
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