WO2018118422A1 - Procédé de récupération de liquides de gaz naturel - Google Patents

Procédé de récupération de liquides de gaz naturel Download PDF

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Publication number
WO2018118422A1
WO2018118422A1 PCT/US2017/064803 US2017064803W WO2018118422A1 WO 2018118422 A1 WO2018118422 A1 WO 2018118422A1 US 2017064803 W US2017064803 W US 2017064803W WO 2018118422 A1 WO2018118422 A1 WO 2018118422A1
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WIPO (PCT)
Prior art keywords
stream
pressure
dng
natural gas
gas
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PCT/US2017/064803
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English (en)
Inventor
William B. Dolan
Alfonse Maglio
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Basf Corporation
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Publication of WO2018118422A1 publication Critical patent/WO2018118422A1/fr

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Classifications

    • 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
    • C10G5/02—Recovery of liquid hydrocarbon mixtures from gases, e.g. natural gas with solid adsorbents
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/02—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by adsorption, e.g. preparative gas chromatography
    • B01D53/04—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by adsorption, e.g. preparative gas chromatography with stationary adsorbents
    • B01D53/047—Pressure swing adsorption
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/26—Drying gases or vapours
    • B01D53/261—Drying gases or vapours by adsorption
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2256/00—Main component in the product gas stream after treatment
    • B01D2256/24—Hydrocarbons
    • B01D2256/245—Methane
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/50—Carbon oxides
    • B01D2257/504—Carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/80—Water
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00—Capture or disposal of greenhouse gases
    • Y02C20/40—Capture or disposal of greenhouse gases of CO2

Definitions

  • the invention relates to natural gas processing, including natural gas processing to recover C2+ or C3+ hydrocarbons.
  • natural gas is applied to gas produced from underground accumulations of widely varying composition.
  • the main constituent of natural gas is methane.
  • natural gas Apart from methane, natural gas generally includes other hydrocarbons, nitrogen, carbon dioxide, water and sometimes a small proportion of hydrogen sulfide.
  • Hydrocarbon constituents include ethane (C2), propane (C3), butane (C4), pentane (C5), hexane (C6), heptane (C7), etc.
  • Natural gas liquids comprise
  • Heavier constituents, C5+, are in the gaseous phase at elevated temperatures during production from the subsurface and in liquid phase when the gas mixture is cooled.
  • Removal of contaminants, in particular water, carbon dioxide and hydrocarbons, from natural gas streams is important to prevent problems that can occur during their processing.
  • Processing of natural gas includes use of low temperatures, requiring the removal of water and carbon dioxide to prevent formation of frozen solids.
  • TSA thermal swing adsorption
  • three adsorption beds are provided in natural gas purification processes, one of them in adsorption mode, one of them being regenerated by passing a slipstream of untreated natural gas stream at an elevated temperature over the bed so that adsorbed contaminants are removed, and one of them being cooled by the slipstream after the bed is regenerated.
  • the slipstream is first passed through the bed to be cooled, then heated and passed through the bed to be regenerated.
  • the slipstream takes up contaminants that are removed from the adsorbent bed in regeneration mode.
  • the contaminated slipstream is then passed through an air and water cooler, and condensed contaminants are separated off.
  • the flash gas is recycled to the natural gas stream to be treated, upstream of the adsorption bed in adsorption mode.
  • a problem in the use of thermal swing adsorption is that the bed must be regenerated and further has a limited lifetime due to repeated exposure to elevated temperatures. There is a need for improved methods and systems to remove contaminants from natural gas streams.
  • a method of recovering C2+ or C3+ hydrocarbons and/or producing sales gas from a natural gas feed gas (FG) comprising pressure swing adsorption; for instance in a turbo-expander plant.
  • the pressure swing adsorption is effective towards regenerating one or more adsorption beds (adsorbent beds).
  • a method of recovering C2+ or C3+ hydrocarbons and producing sales gas from a natural gas feed gas comprising routing the feed gas (FG) at a pressure P1 over an adsorbent bed to adsorb water to provide a dry natural gas (DNG) stream at pressure P1 ; routing the dry natural gas (DNG) stream through one or more processing elements to recover C2+ or C3+ liquid hydrocarbons and to provide a C2+ or C3+ hydrocarbon-depleted dry natural gas stream (HCDDNG); routing the hydrocarbon-depleted dry natural gas stream (HCDDNG) stream over an adsorbent bed to desorb water to provide a first wet natural gas stream (WNG1 ); and producing sales gas from the first wet natural gas stream (WNG1 ).
  • DNG dry natural gas
  • a plant for natural gas liquids recovery and/or sales gas production from a feed gas configured to route the feed gas at a pressure P1 over an adsorbent bed to adsorb water to provide a dry natural gas stream at pressure P1 ; to route the dry natural gas stream through one or more processing elements to provide a dry natural gas stream at a pressure P2 or P3; to route the dry natural gas stream at pressure P2 or P3 over an adsorbent bed to desorb water to provide a first wet natural gas stream (WNG1 ); and to recover C2+ or C3+ hydrocarbons from the dry natural gas stream; and/or to produce sales gas from the first wet natural gas stream; wherein P1 > P3 > P2.
  • a plant for natural gas liquids recovery and sales gas production from a feed gas (FG) configured to route the feed gas (FG) at a pressure P1 over an adsorbent bed to adsorb water to provide a dry natural gas stream (DNG) at pressure P1 ; to route the dry natural gas stream through one or more processing elements to recover C2+ or C3+ liquid hydrocarbons and to provide a C2+ or C3+ hydrocarbon-depleted dry natural gas stream (HCDDNG); to route the HCDDNG stream over an adsorbent bed to desorb water to provide a first wet natural gas (WNG1 ) stream and to produce sales gas from the WNG1 stream.
  • DNG dry natural gas stream
  • HCDDNG hydrocarbon-depleted dry natural gas stream
  • Alternative embodiments include thermal swing adsorption to regenerate adsorption beds.
  • Fig. 1 is a schematic of one embodiment comprising a turbo-expander plant equipped for regeneration of an adsorption bed via pressure swing adsorption.
  • Fig. 2 is a schematic of an embodiment comprising a turbo-expander plant equipped for regeneration of an adsorption bed via thermal swing adsorption.
  • Fig. 3 depicts an embodiment comprising a plant having a Joule Thompson valve equipped for regeneration of an adsorption bed via thermal swing adsorption.
  • Fig. 4 depicts an embodiment comprising a plant having a Joule Thompson valve equipped for regeneration of an adsorption bed via pressure swing adsorption.
  • Fig. 5 depicts an embodiment comprising a turbo-expander plant equipped for regeneration of an adsorption bed via thermal swing adsorption.
  • the present invention is aimed at the use of pressure swing adsorption to regenerate an adsorbent bed during processing of a natural gas feed gas.
  • the present processing may not require the use of thermal swing adsorption for adsorbent bed regeneration.
  • the feed gas (FG), or natural gas feed gas, that enters the plant may be within specifications for sales gas, that is, within specifications ("in-spec") regarding acceptable levels of water and/or carbon dioxide.
  • the feed gas may contain ⁇ 165 ppm water, for example from about 80 ppm, about 90 ppm, about 100 ppm or about 1 10 ppm to about 120 ppm, about 130 ppm, about 135 ppm, about 140 ppm about 150 ppm, about 160 ppm or about 165 ppm water, on a molar basis.
  • the feed gas may contain ⁇ 2.2 mol% (mole percent) carbon dioxide, for example from about 0.8, about 0.9, about 1 .0, about 1 .1 , about 1 .2, about 1 .3, about 1 .4 or about 1 .5 mol% to about 1 .6, about 1 .7, about 1 .8, about 1 .9, about 2.0, about 2.1 or about 2.2 mol% carbon dioxide.
  • the feed gas may be outside of the specifications regarding acceptable levels of water and/or carbon dioxide for sales gas, for example the feed gas may exceed the acceptable levels of water and/or carbon dioxide by up to about 10%, for example up to about 1 %, about 2%, about 3%, about 4%, about 5%, about 6%, about 7%, about 8% or about 9%.
  • the feed gas need not be within specifications for acceptable levels of water and/or carbon dioxide for sales gas.
  • the feed gas may be saturated with water at temperatures of from about 10°C to about 60 °C. That is, the feed gas may contain up to about 500 ppm or up to about 1000 ppm water on a molar basis.
  • the sales gas may contain the same acceptable levels of water and carbon dioxide. Accordingly, water and/or carbon dioxide content of the feed gas and the water and/or carbon dioxide content of the sales gas may be within about 1 , about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9 or about 10% by moles of each other. In other words, the feed natural gas entering the plant will contain about the same amounts of water and/or carbon dioxide as the natural gas product exiting the plant.
  • the feed gas entering the plant may contain from about 87, about 88, about 89 or about 90 mol% to about 91 , about 92, about 93, about 94, about 95 or about 96 mol% methane and from about 4, about 5, about 6 or about 7 mol% to about 8, about 9, about 10, about 1 1 or about 12 mol% C2+ hydrocarbons.
  • the feed gas enters the plant at a pressure P1 .
  • the feed gas is routed over an adsorbent bed at pressure P1 , for instance a pressure from about 650, about 700, about 750, about 800, about 850 or about 900 psia to about 950, about 1000, about 1050, about 1 100, about 1 150, about 1200, about 1300, about 1350, about 1400, about 1450, about 1500, about 1550, about 1600, about 1650, about 1700, about 1750, about 1800, about 1850, about 1900, about 1950 or about 2000 psia. Routing the feed gas over the adsorbent bed places the feed gas in contact with the adsorbent and serves to remove water and/or carbon dioxide from the feed gas.
  • the dry natural gas (DNG) stream will initially be at a pressure P1 .
  • the dry natural gas stream may contain ⁇ 5.0, ⁇ 4.5, ⁇ 4.0, ⁇ 3.5, ⁇ 3.0, ⁇ 2.5, ⁇ 2.0, ⁇ 1 .5, ⁇ 1 .0, ⁇ 0.5, ⁇ 0.4, ⁇ 0.3, ⁇ 0.2, ⁇ 0.10, ⁇ 0.08 or ⁇ 0.07 ppm water on a molar basis.
  • the dry natural gas stream may recover ⁇ 70%, ⁇ 60%, ⁇ 50%, ⁇ 40%, ⁇ 30%, ⁇ 20%, ⁇ 10%, ⁇ 5%, ⁇ 1 %, ⁇ 0.5%, ⁇ 0.3% or ⁇ 0.1 % carbon dioxide of the feed gas.
  • “recovers” means molar flow rate of C0 2 in the dry gas stream relative to the molar flow rate of C0 2 in the feed gas stream; or (molar flow rate of the dry gas stream) ⁇ (moles C0 2 in the dry gas stream) / (molar flow rate of the feed gas stream) / (moles C0 2 in the feed gas stream).
  • the dry natural gas stream will contain less than 2.5 moles of C0 2 relative to 100 moles of C2+ hydrocarbons. This is a typical specification of acceptable C0 2 content in a C2+ stream.
  • the C0 2 recovery level of the adsorption system is set to ensure the C0 2 specification in the C2+ can be met. This may be accomplished in conjunction with other approaches in the distillation column, such as those described by Hudson, et. al., "Reduced Treating Requirements for Cryogenic NGL Recovery Plants", presented at the 80 th Annual Convention of the Gas Processors Association, March 12, 2001 , San Antonio, Texas.
  • Processing elements include for instance one or more heat exchangers, compressors, expanders, turbo-expanders, Joule-Thompson valves, columns, condensers, separators, knockout pots, valves and the like.
  • the dry natural gas stream at P1 is routed through one or more processing elements to provide a dry natural gas stream at P2 or P3.
  • a dry natural gas stream at pressure P2 or P3 is routed over an adsorbent bed to desorb water and/or C0 2 to provide a wet natural gas stream at P2 or P3.
  • the dry natural gas stream at P1 is for instance routed through the expansion section of a turbo-expander to provide the dry natural gas stream at lower pressure P2.
  • dry gas stream at P1 may be routed to a heat exchanger which cools the gas stream.
  • the cooled, dry gas stream is then routed to a turbo-expander to expand it to provide a dry gas stream of a lower pressure P2.
  • Pressure P2 may be from about 150, about 200, about 250, about 300, about 350, about 400, about 450 or about 500 psia to about 550, about 600, about 650, about 700, about 750, about 800, about 850, about 900, about 950 or about 1000 psia.
  • Dry natural gas stream at P2 may be routed to a demethanizer distillation column.
  • the overhead gas product from the demethanizer may be routed back through a heat exchanger to cool an incoming gas stream.
  • the dry gas stream at P2 may be subsequently routed over an adsorbent bed.
  • the lower pressure serves to desorb and regenerate the adsorbent bed and put water and/or carbon dioxide back into the gas stream to provide a "wet natural gas stream".
  • a dry natural gas stream at P2 may for instance be routed over an adsorbent bed after being routed through a heat exchanger; for instance a dry gas stream at P2 may be routed over an adsorbent bed after being routed through a heat exchanger and through a turbo-expander.
  • the C2+ or C3+ hydrocarbons are recovered from the bottom of a demethanizer column.
  • the wet natural gas stream is routed through a turbo-expander and is compressed to a pressure P3 which is higher than P2.
  • the dry natural gas stream at P2 may be routed through a heat exchanger and turbo-expander to compress the gas to pressure P3.
  • the dry gas stream at pressure P3 is then routed over an adsorbent bed to desorb water and/or carbon dioxide and provide a wet gas stream.
  • Pressure P3 may for instance be from about 600, about 650, about 700, about 750, about 800, about 850 or about 900 psia to about 950, about 1000, about 1050, about 1 100, about 1 150, about 1200, about 1300, about 1350, about 1400, about 1450, about 1500, about 1550, about 1600, about 1650, about 1700, about 1750, about 1800, about 1850, about 1900 or about 1950 psia.
  • Pressure P1 is greater than pressure P2.
  • pressure P3 is greater than pressure P2.
  • P1 may be from about 500, about 550 or about 600 psia to about 650, about 700, about 750 or about 800 psia greater than P2.
  • P1 may be from about 100, about 150 or about 200 psia to about 250, about 300, about 350 or about 400 psia greater than P3.
  • P3 may be from about 250, about 300 or about 350 psia to about 400, about 450, about 500 or about 550 psia greater than P2.
  • the first wet gas stream (WNG1 ) or the dry natural gas stream may be further compressed if required to a pressure P4 to provide "in-spec" sales gas having acceptable levels of water and carbon dioxide.
  • the sales gas may be at a pressure P4 of from about 600, about 650, about 700, about 750, about 800, about 850 or about 900 psia to about 950, about 1000, about 1050, about 1 100, about 1 150, about 1200, about 1300, about 1350, about 1400, about 1450, about 1500, about 1550, about 1600, about 1650, about 1700, about 1750, about 1800, about 1850, about 1900, about 1950 or about 2000 psia.
  • the first wet gas stream (WNG1 ) advantageously contains water and/or carbon dioxide levels that are in-spec for sales gas.
  • the wet gas stream may be outside of the specifications regarding acceptable levels of water and/or carbon dioxide for sales gas, for example the wet gas may exceed the acceptable levels of water and/or carbon dioxide by up to about 10%, for example up to about 1 %, about 2%, about 3%, about 4%, about 5%, about 6%, about 7%, about 8% or about 9%.
  • a feed gas enters a turbo-expander NGL recovery plant 100 at an elevated pressure P1 and is routed over an adsorbent bed 101 to adsorb water and/or carbon dioxide to provide a dry natural gas stream at P1 .
  • the dry gas stream at P1 is then routed through a heat exchanger 102, is cooled and routed through an expansion section of a turbo-expander 103. This reduces the pressure to provide a dry cooled, dry natural gas stream at pressure P2.
  • the dry gas stream at P2 is routed to a demethanizer column 104, C2+ NGL is recovered from the bottom of the column and the overhead dry gas stream at pressure P2 is routed through the heat exchanger to cool incoming dry gas stream at P1 .
  • the dry gas stream at pressure P2 may be routed over an adsorbent bed (same or different bed) at this point to desorb and regenerate the bed and return water and carbon dioxide to the gas stream to provide a wet natural gas stream at P2.
  • Wet gas stream at P2 is then routed through the compression section of turbo-expander 103 and compressed to pressure P3, a pressure between P1 and P2.
  • Wet gas stream at P3 is further compressed via compressor 105 to produce sales gas.
  • the dry gas stream at P2 is routed through the compression section of turbo-expander 103 and compressed to intermediate pressure P3; this dry natural gas stream at P3 may be routed over an adsorbent bed to desorb and regenerate the bed and return water and carbon dioxide to the gas stream to provide the wet natural gas stream at P3.
  • the connectivity of routing the dry gas stream over an adsorbent bed to desorb and regenerate it is not explicitly shown in Fig. 1.
  • a natural gas feed gas stream enters a turbo- expander plant 100 at a pressure P1 of about 1000 psia and containing ⁇ 150 ppm water and ⁇ 2 mol% carbon dioxide.
  • the feed gas is routed over an adsorbent bed 101 to remove water and/or carbon dioxide to a suitable level for entering a turbo-expander 103; that is ⁇ 0.1 ppm water and ⁇ 0.1 mol% carbon dioxide.
  • This "dry natural gas stream" at P1 is cooled and expanded by being routed through a heat exchanger 102 and a turbo-expander 103, for instance to a pressure P2 of about 330 psia.
  • the dry, cooled and expanded gas stream is routed to a demethanizer 104. Heavier C2+ hydrocarbons are recovered from the bottom of the demethanizer 104 and the overhead dry gas stream is routed back through the heat exchanger 102 where it serves to cool incoming feed gas.
  • Dry gas stream at P2 is then routed over an adsorbent bed 101 to desorb water and/or carbon dioxide to provide a "wet natural gas stream" at P2, which will advantageously contain about the same "in-spec" amounts of water and carbon dioxide as the incoming feed gas, for example ⁇ 150 ppm water and ⁇ 2 mol% carbon dioxide.
  • the wet gas stream is then routed through the compression section of a turbo-expander 103 where it is compressed to an intermediate pressure P3 of about 450 psia.
  • the wet gas stream at pressure P3 is
  • dry gas stream at P2 is routed from the heat exchanger 102 through the compression section of a turbo-expander 103 where it is compressed to an intermediate pressure P3 of about 450 psia.
  • the dry gas stream at pressure P3 is then routed over an adsorbent bed 101 to desorb water and/or carbon dioxide to prove a wet natural gas stream at pressure P3.
  • the wet gas stream at P3 is subsequently further compressed to about 1000 psia and is provided as consumable sales gas.
  • the adsorbent bed may also be desorbed at pressure P4.
  • P4 is greater than P3.
  • P4 may be less than or equal to, or less than P1 .
  • a present method comprises heating a DNG stream or a portion of a DNG stream at P2, P3 or P4 and passing the heated stream over an adsorbent bed at P2, P3 or P4 to desorb water and/or carbon dioxide.
  • the resulting heated wet stream is termed a second wet natural gas stream (WNG2).
  • the second wet natural gas stream is cooled and is routed through a processing unit such as a knock-out pot to remove water and to provide a third wet natural gas stream (WNG3).
  • the WNG3 stream may be recombined with any remaining portion of the DNG stream to provide the first wet natural gas stream WNG1 at P2, P3 or P4.
  • Fig. 2 illustrates an embodiment wherein a portion of a DNG stream at P2 is routed to a heating element 206 to provide a heated DNG stream.
  • the heated DNG stream at P2 is routed over the adsorbent bed at the point "desorb" (bed not pictured) to desorb the bed and to provide a second wet natural gas (WNG2) stream.
  • the WNG2 stream is cooled with cooling element 207 and is routed to a knock-out pot 208 to remove water and to provide a third wet natural gas stream (WNG3).
  • WNG3 stream is recombined with the remaining portion of the DNG stream to provide WNG1 at P2 prior to being routed to a compression section of a turbo- expander.
  • An entire portion of a DNG stream at P2 may be subjected to thermal swing adsorption as depicted in Fig. 2, or a portion of a DNG stream may be subjected to thermal swing adsorption, with a remaining portion being recombined with WNG3 to provide WNG1 .
  • the portion subjected to thermal swing may be from about 2 mol%, about 5, about 8, about 1 1 , about 15, about 20, about 25, about 30, about 35, about 40, about 45, about 50 or about 55 mol% to about 60 mol%, about 65, about 70, about 75, about 80, about 85, about 90, about 95, about 98, about 99 or 100 mol% of the total DNG stream, wherein the remaining portion is routed around the thermal swing apparatus and is rejoined with WNG3 to provide WNG1 .
  • the embodiment of Fig. 2 may alternatively be performed at P3 or at P4.
  • the term "mol%" means of the total percent of the stream, on a molar basis.
  • Joule-Thompson (JT) valve may be employed in a present process and plant configuration, for example a DNG stream at P1 may be routed to a heat exchanger, to a JT valve and then to a demethanizer.
  • a turbo-expander need not be present.
  • a JT valve may be employed in place of a turbo-expander prior to entering a C2+ or C3+ recovery column.
  • the HCDDNG stream may also be at any of P2, P3 or P4 and may be routed over an adsorbent bed to desorb the bed at any of these pressures and to provide WNG1 .
  • Fig. 3 depicts a plant equipped for thermal swing adsorption containing a Joule
  • Fig. 4 depicts a plant equipped for pressure swing adsorption containing a Joule
  • Fig. 5 illustrates an embodiment wherein a portion of a DNG stream at P3 is routed to a heating element 206 to provide a heated DNG stream.
  • the heated DNG stream at P3 is routed over the adsorbent bed at the point "desorb" (bed not pictured) to desorb the bed and to provide a second wet natural gas (WNG2) stream.
  • the WNG2 stream is cooled with cooling element 207 and is routed to a knock-out pot 208 to remove water and to provide a third wet natural gas stream (WNG3).
  • WNG3 stream is recombined with the remaining portion of the DNG stream to provide WNG1 at P3 prior to being routed to a compressor 105 to produce sales gas.
  • a JT valve and compressor may be interchanged with a turbo-expander and visa-versa.
  • a present method may comprise only thermal swing adsorption, only pressure swing adsorption or both thermal swing and pressure swing adsorption.
  • pressure swing adsorption processes and/or thermal swing adsorption processes desorption, or regeneration of the bed, may be performed at any of P2, P3 or P4.
  • heat exchanger 102 need not be present.
  • the dry natural gas stream at P2 at a low temperature from a column top may cool incoming feed gas by passing it over an adsorbent bed. Utilizing an adsorbent bed in this manner would make it a recuperative heat exchanger as well as a adsorption unit.
  • methods comprise heating a portion of a DNG stream at pressure P2, P3 or P4 to a temperature of from about 50 °C to about 350 °C to provide a heated, dry natural gas (HDNG) stream; routing the HDNG stream at pressure P2, P3 or P4 over the adsorbent bed to desorb water to provide a second wet natural gas (WNG2) stream; cooling the WNG2 stream to a temperature of from about ⁇ ⁇ 5°C to about 45 °C to provide a cooled WNG2 stream; and routing the cooled WNG2 stream through one or more processing elements such as a knock-out pot to remove water and to provide a third wet natural gas (WNG3) stream at P2, P3 or P4; and recombining WNG3 with a remaining portion of the DNG stream at P2, P3 or P4 to provide WNG1 at P2, P3 or P4.
  • HDNG heated, dry natural gas
  • such a thermal swing adsorption may be performed between elements 102 and 103 of Fig. 2 (as depicted), between elements 103 and 105 of Fig. 2 or after element 105 of Fig. 2; or between elements 102 and 304 of Fig. 3, between elements 304 and 105 of Fig. 3 or after element 105 of Fig. 3 (as depicted).
  • adsorbent beds there may be two or more adsorbent beds. For instance, one bed will be in "adsorption mode” and one will be in "desorption mode”. There may be three adsorbent beds, for instance with at least one in adsorption mode, at least one in desorption mode and one in a de-pressurization or re-pressurization mode at any point or step during processing.
  • mode means an element is performing the defined step during operation.
  • the natural gas feed gas that enters the plant will generally be within specifications for sales gas regarding acceptable levels of water and carbon dioxide.
  • Fig. 1 and Fig. 2 represent possible features of a turbo-expander plant. There may be additional features, for instance, one or more further features or elements selected from heat exchangers, compressors, reboilers, separators, condensers, reflux drums, temperature controllers and the like. Also, the location of an arrow does not necessarily represent the desired location of entry of a gas stream into a particular element.
  • turbo-expander plants there are numerous configurations of turbo-expander plants, for example some may employ external refrigeration.
  • gas exiting a liquids recovery column may be employed for regeneration of an adsorbent bed at different points throughout the process.
  • present methods are capable of recovering at least 90% C2 and at least 90% C3 fractions of incoming feed gas. For instance, present methods may provide for at least 92%, at least 93%, at least 94% or at least 95% C2 recovery and may provide for at least 92%, at least 94%, at least 96% or at least 98% C3 recovery.
  • Suitable adsorbents are solids having a microscopic structure.
  • the internal surface of such adsorbents is for example from about 100, 300 or about 500 m 2 /g to about 1500, 1700 or about 2000 m 2 /g.
  • the nature of the internal surface of the adsorbent in an adsorbent bed is such that water, carbon dioxide and possibly heavier hydrocarbons are adsorbed.
  • the internal surface of the adsorbent is polar.
  • Suitable adsorbent materials include materials based on silica, silica gel, alumina, silica-alumina, molecular sieves or zeolites. Adsorbents are taught for example in U.S. Pat. Nos.
  • size selective adsorbents may also be considered, for example 3A, 4A, CTS-1 type molecular sieves and the like are suitable.
  • a feed gas is a gas that enters a natural gas processing plant; the plant suitable to produce sales gas and/or to recover natural gas liquids.
  • the dry natural gas stream at pressure P1 has lower water and/or carbon dioxide content than the feed gas and has been treated with an adsorbent bed.
  • the dry natural gas stream will upon further processing be at pressure P2 and/or pressure P3.
  • the dry gas stream at P2 or P3 will have about the same low water and/or carbon dioxide levels as the dry gas stream at P1 .
  • the dry gas stream at P1 may be routed through a heat exchanger and the expansion section of a turbo-expander.
  • the dry gas stream at P2 may be routed through a demethanizer and back through a heat exchanger.
  • the dry gas stream at P2 may also be routed through the compression section of a turbo-expander.
  • the wet natural gas stream may be at pressure P2 and/or pressure P3.
  • the wet gas stream contains higher levels of water and/or carbon dioxide than the dry gas stream, which levels may advantageously be within specifications for sales gas.
  • the wet natural gas stream is formed when the dry natural gas stream is routed over the adsorption bed at pressure P2 or pressure P3, which serves to desorb and regenerate the bed.
  • the dry natural gas stream has been treated with an adsorbent bed and contains a decreased amount of water and/or carbon dioxide.
  • the wet natural gas stream contains desorbed water and/or carbon dioxide from an adsorbent bed.
  • Pressures P1 , P2 and P3 at various stages in processing may be in a range; that is, each one need not be identical at various points within the plant during processing.
  • pressure P1 at the feed gas, at entry to a heat exchanger, at exit of a heat exchanger and at entry to a turbo-expander may be within a range and need not be identical.
  • the temperature of the feed gas is for instance from about I CO, about 20 °C, about 30 °C or about 40 °C to about 50 °C, about 60 °C, about 70 °C, about 80 °C, about 90 °C or about 100°C.
  • the temperature of the dry natural gas stream exiting after cooling with a heat exchanger is for instance from about 0 °C, about 10 °C, about 20 °C or about 30 °C to about 40 °C or about 50 °C. Temperatures of the natural gas streams at other points in processing are those typical in NGL recovery plants.
  • adsorb water means to adsorb water onto a bed.
  • desorb water means to desorb water from the bed.
  • numeric value may be modified by ⁇ 5%, ⁇ 4%, ⁇ 3%, ⁇ 2%, ⁇ 1 %, ⁇ 0.5%, ⁇ 0.4%, ⁇ 0.3%, ⁇ 0.2%, ⁇ 0.1 % or ⁇ 0.05%. All numeric values are modified by the term “about” whether or not explicitly indicated. Numeric values modified by the term “about” include the identified value; that is “about 5.0” includes 5.0. Measureable levels of atoms, elements or molecules may depend on the method of detection. In part, the term “about” is intended to provide for this.
  • Some method embodiments of the invention include the following.
  • a method of recovering C2+ or C3+ hydrocarbons and producing sales gas from a natural gas feed gas comprising routing the feed gas (FG) at a pressure P1 over an adsorbent bed to adsorb water to provide a dry natural gas (DNG) stream at pressure P1 ; routing the dry natural gas (DNG) stream through one or more processing elements to recover C2+ or C3+ liquid hydrocarbons and to provide a C2+ or C3+ hydrocarbon-depleted dry natural gas stream (HCDDNG); routing the hydrocarbon-depleted dry natural gas stream (HCDDNG) stream over an adsorbent bed to desorb water to provide a first wet natural gas stream (WNG1 ); and producing sales gas from the first wet natural gas stream (WNG1 ).
  • a method of recovering C2+ or C3+ hydrocarbons and/or producing sales gas from a natural gas feed gas comprising routing the feed gas (FG) at a pressure P1 over an adsorbent bed to adsorb water to provide a dry natural gas (DNG) stream at pressure P1 ; routing the dry natural gas (DNG) stream through one or more processing elements to provide a dry natural gas stream (DNG) at a pressure P2, P3 or P4; routing the dry natural gas stream (DNG) at pressure P2, P3 or P4 over an adsorbent bed to desorb water to provide a first wet natural gas (WNG1 ) stream; and recovering C2+ or C3+ hydrocarbons from the dry natural gas stream and/or producing sales gas from the first wet natural gas (WNG1 ) stream; wherein P1 > P3 > P2, the sales gas is at pressure P4 and wherein P4 > P3.
  • a method according to the first embodiment comprising routing the dry natural gas (DNG) stream through a heat exchanger to provide a cooled, DNG stream at pressure P1 .
  • DNG dry natural gas
  • Further method embodiments include a method according to the first or second embodiments comprising routing the DNG stream through a turbo-expander to provide an expanded DNG stream at pressure P2.
  • embodiments comprising recovering C2+ hydrocarbons.
  • a method according to any of the preceding embodiments comprising recovering C3+ hydrocarbons.
  • a method according to any of the preceding embodiments comprising producing sales gas.
  • a method according to any of the preceding embodiments comprising routing the DNG stream through a demethanizer.
  • a method according to any of the preceding embodiments comprising routing the DNG stream at pressure P2 through a demethanizer.
  • a method according to any of the preceding embodiments comprising compressing the WNG1 with a turbo-expander from pressure P2 to a pressure P3.
  • a method according to any of the preceding embodiments comprising compressing the DNG stream with a turbo-expander from pressure P2 to a pressure P3.
  • the FG contains ⁇ 165 ppm water, for example from about 80 ppm, about 90 ppm, about 100 ppm or about 1 10 ppm to about 120 ppm, about 130 ppm, about 135 ppm, about 140 ppm about 150 ppm, about 160 ppm or about 165 ppm water, on a molar basis.
  • the FG contains ⁇ 2.2 mol% (mole percent) carbon dioxide, for example from about 0.8, about 0.9, about 1 .0, about 1 .1 , about 1 .2, about 1 .3, about 1 .4 or about 1 .5 mol% to about 1 .6, about 1 .7, about 1 .8, about 1 .9, about 2.0, about 2.1 or about 2.2 mol% carbon dioxide.
  • the sales gas contains from about 80 ppm, about 90 ppm, about 100 ppm or about 1 10 ppm to about 120 ppm, about 130 ppm, about 135 ppm, about 140 ppm about 150 ppm, about 160 ppm or about 165 ppm water, on a molar basis.
  • the sales gas contains from about 0.8, about 0.9, about 1 .0, about 1 .1 , about 1 .2, about 1 .3, about 1 .4 or about 1 .5 mol% to about 1 .6, about 1 .7, about 1 .8, about 1 .9, about 2.0, about 2.1 or about 2.2 mol% carbon dioxide.
  • the FG contains from about 87, about 88, about 89 or about 90 mol% to about 91 , about 92, about 93, about 94, about 95 or about 96 mol% methane and from about 4, about 5, about 6 or about 7 mol% to about 8, about 9, about 10, about 1 1 or about 12 mol% C2+ hydrocarbons.
  • the DNG stream contains ⁇ 5.0, ⁇ 4.5, ⁇ 4.0, ⁇ 3.5, ⁇ 3.0, ⁇ 2.5, ⁇ 2.0, ⁇ 1 .5, ⁇ 1 .0, ⁇ 0.5, ⁇ 0.4, ⁇ 0.3, ⁇ 0.2, ⁇ 0.10, ⁇ 0.08 or ⁇ 0.07 ppm water, on a molar basis.
  • a method comprising routing the FG over the adsorbent bed at a pressure P1 of from about 650, about 700, about 750, about 800, about 850 or about 900 psia to about 950, about 1000, about 1050, about 1 100, about 1 150, about 1200, about 1300, about 1350, about 1400, about 1450, about 1500, about 1550, about 1600, about 1650, about 1700, about 1750, about 1800, about 1850, about 1900, about 1950 or about 2000 psia.
  • a method comprising routing the DNG stream over the adsorbent bed at a pressure P2 of from about 150, about 200, about 250, about 300, about 350, about 400, about 450 or about 500 psia to about 550, about 600, about 650, about 700, about 750, about 800, about 850, about 900, about 950 or about 1000 psia.
  • a method comprising routing the DNG stream over the adsorbent bed at a pressure P3 of from about 600, about 650, about 700, about 750, about 800, about 850 or about 900 psia to about 950, about 1000, about 1050, about 1 100, about 1 150, about 1200, about 1300, about 1350, about 1400, about 1450, about 1500, about 1550, about 1600, about 1650, about 1700, about 1750, about 1800, about 1850, about 1900 or about 1950 psia.
  • a method according to any of the preceding embodiments comprising the use of two or more adsorbent beds; for example 3 adsorbent beds.
  • a method according to any of the preceding embodiments comprising the use of two or more adsorbent beds where at least one is in an adsorption mode and at least one is in a desorption mode.
  • a method according to any of the first through 33 embodiments comprising heating a portion of the DNG stream at pressure P2, P3 or P4 to a temperature of from about 50 °C, about 75 °C, about 100 ⁇ ⁇ , about 125 ⁇ ⁇ , about 150°C, about 175°C, about 200 °C or about 225 °C to about 250 ⁇ ⁇ , about 275 ⁇ ⁇ , about 300 ⁇ ⁇ about 325 °C or about 350 °C to provide a heated, dry natural gas (HDNG) stream; routing the HDNG stream at pressure P2, P3 or P4 over the adsorbent bed to desorb water to provide a second wet natural gas (WNG2) stream; cooling the WNG2 stream to a temperature of from about 15°C, about 20 °C, about 25 °C or about 30 °C to about 35°
  • HDNG heated, dry natural gas
  • a method according to embodiment 35 comprising heating from about 2 mol%, about 5, about 10 or about 15 to about 20, about 25 or about 30 mol% of the DNG stream to provide the WNG3 stream and combining WNG3 with from about 70 mol%, about 75 or about 80 mol% to about 85 mol%, about 90, about 95 or about 98 mol% of the DNG at pressure P2, P3 or P4 to provide WNG1 at P2, P3 or P4.
  • a method according to embodiments 35 or 36 comprising routing cooled WNG2 through a knock-out pot to remove water.
  • Some plant embodiments of the invention include the following.
  • DNG dry natural gas stream
  • HCDDNG hydrocarbon-depleted dry natural gas stream
  • a plant for natural gas liquids recovery and/or sales gas production from a feed gas (FG) configured to route the feed gas (FG) at a pressure P1 over an adsorbent bed to adsorb water to provide a dry natural gas stream (DNG) at pressure P1 ; to route the dry natural gas stream through one or more processing elements to provide a dry natural gas stream (DNG) at a pressure P2 or P3; to route the DNG stream at pressure P2 or P3 over an adsorbent bed to desorb water to provide a first wet natural gas (WNG1 ) stream and to recover C2+ or C3+ hydrocarbons from the DNG stream and/or to produce sales gas from the WNG1 stream; wherein P1 > P3 > P2, the sales gas is at pressure P4 and wherein P4 > P3.
  • a fourth plant embodiment disclosed is a plant according to the first or second embodiments where the one or more processing elements comprise a turbo-expander or a Joule Thompson valve.
  • a plant according to any of the preceding embodiments configured to recover C2+ hydrocarbons.
  • a plant according to any of the preceding embodiments configured to recover C3+ hydrocarbons.
  • a plant according to any of the preceding embodiments configured to produce sales gas.
  • a plant according to any of the preceding embodiments configured to route the DNG stream through a demethanizer to recover C2+ and/or C3+ hydrocarbons.
  • a plant according to any of the preceding embodiments configured to route the DNG stream at pressure P2 through a demethanizer to recover C2+ and/or C3+ hydrocarbons.
  • a plant according to any of the preceding embodiments configured to route the DNG stream at pressure P2 through the heat exchanger to cool the DNG stream at pressure P1 .
  • a plant according to any of the preceding embodiments configured to route the DNG stream at pressure P2 over the adsorbent bed to provide the WNG1 stream.
  • a plant according to any of the preceding embodiments configured to route the DNG stream at pressure P2 over the adsorbent bed to provide the WNG1 stream after routing the DNG stream through a heat exchanger.
  • a plant according to any of the preceding embodiments configured to route the DNG stream at pressure P3 over the adsorbent bed to provide the WNG1 stream.
  • a plant according to any of the preceding embodiments configured to route the DNG stream at pressure P3 over the adsorbent bed to provide the WNG1 stream after routing DNG stream through a heat exchanger and a turbo-expander.
  • a plant according to any of the preceding embodiments configured to compress the WNG1 stream with a turbo-expander from pressure P2 to a pressure P3.
  • a plant according to any of the preceding embodiments configured to compress the DNG stream with a turbo- expander from pressure P2 to pressure P3.
  • a plant according to any of the preceding embodiments configured to route the feed gas (FG) at a pressure P1 over the adsorbent bed to adsorb water and carbon dioxide to provide the DNG stream at pressure P1 .
  • FG feed gas
  • a plant configured to route the DNG stream over the adsorbent bed at pressure P2 or P3 to desorb carbon dioxide and water to provide the WNG1 stream.
  • a plant according to any of the preceding embodiments where the feed gas contains ⁇ 165 ppm water for example from about 80 ppm, about 90 ppm, about 100 ppm or about 1 10 ppm to about 120 ppm, about 130 ppm, about 135 ppm, about 140 ppm about 150 ppm, about 160 ppm or about 165 ppm water, on a molar basis.
  • a plant according to any of the preceding embodiments configured to route the feed gas over the adsorbent bed at a pressure P1 of from about 700, about 750, about 800, about 850 or about 900 psia to about 950, about 1000, about 1050, about 1 100, about 1 150 or about 1200 psia.
  • a plant according to any of the preceding embodiments configured to route the DNG stream over the adsorbent bed at a pressure P3 of from about 400, about 450, about 500 or about 550 psia to about 600, about 650 or about 700 psia.
  • a plant according to any of the preceding embodiments configured to compress the WNG1 or the DNG stream to provide the sales gas at a pressure of from about 800, about 850, about 900, about 950, about 1000 or about 1050 psia to about 1 100, 1 150 or about 1200 psia.
  • a plant according to any of the preceding embodiments comprising two or more adsorbent beds; for example 3 adsorbent beds.
  • a plant according to any of the preceding embodiments comprising two or more adsorbent beds and configured to have at least one in an adsorption mode and at least one in a desorption mode.
  • a plant configured to heat a portion of the DNG stream at pressure P2, P3 or P4 to a temperature of from about 50 °C, about 75 °C, about 100°C, about 125°C, about 150°C, about 175 ⁇ ⁇ , about 200 °C or about 225 °C to about 250 °C, about 275 ⁇ ⁇ , about 300 ⁇ ⁇ about 325 ⁇ ⁇ or about 350 °C to provide a heated, dry natural gas (HDNG) stream; to route the HDNG stream at pressure P2, P3 or P4 over the adsorbent bed to desorb water to provide a second wet natural gas (WNG2) stream; to cool the WNG2 stream to a temperature of from about 15°C, about 20 °C, about 25°C or about 30 °C to about 35°C, about 40 °C or about 45 °C to provide a cooled WNG2 stream; and to route the cooled WNG2 stream through one or more processing elements to
  • a plant according to embodiment 35 configured to heat from about 2 mol%, about 5, about 10 or about 15 to about 20, about 25 or about 30 mol% of the DNG stream and to provide the WNG3 stream and to combine WNG3 with a remaining portion of the DNG stream, for example from about 70 mol%, about 75 or about 80 mol% to about 85 mol%, about 90, about 95 or about 98 mol% of the DNG at pressure P2, P3 or P4 to provide WNG1 at P2, P3 or P4.
  • a plant according to embodiment 35 configured to heat from about 2 mol%, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90 or about 100 mol% of the DNG stream and to provide the WNG3 stream and to combine WNG3 with a remaining portion of the DNG stream, for example with from 0 mol%, about 10 mol%, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90 or about 98 mol% of the DNG stream at P2, P3 or P4 to provide WNG1 at P2, P3 or P4.
  • a plant according to embodiments 35 or 36 configured to route cooled WNG2 through a knock-out pot to remove water.
  • a plant according to embodiments 35 to 37 configured to route a dry natural gas DNG stream at pressure P2, P3 or P4 over the adsorbent bed at a temperature of from about 15°C, about 20 °C, about 25 °C or about 30 °C to about 35 °C, about 40 °C or about 45 °C to cool the adsorbent bed after routing the HDNG stream over the bed.
  • a turbo-expander plant containing elements described in Fig. 1 is employed.
  • the plant contains 3 adsorbent beds and employs a 9 step process.
  • natural gas feed gas is routed into the plant at a pressure of about 1000 psia.
  • the feed gas is "in spec", containing ⁇ 150 ppm water and 2 mol% or less C0 2 .
  • the feed gas also contains 88-95 mol% C and 5-10 mol% C2+ hydrocarbons.
  • the feed gas is passed over an adsorbent bed which adsorbs water to provide a dry natural gas stream at 1000 psia (P1 ).
  • the dry gas stream contains ⁇ 0.1 ppm water.
  • the dry gas stream is routed through a heat exchanger.
  • the adsorbent bed is de- pressurized either co-currently or counter-currently from the feed pressure to bring the bed down to a pressure of about 330 psia (P2).
  • the gas stream exiting the bed from this step will bypass the heat exchanger and demethanizer and be directed to the turbo-expander for recompression to the pipeline.
  • the gas stream exiting the bed from this step will bypass the heat exchanger and demethanizer and be directed to the turbo-expander for recompression to the pipeline.
  • the gas stream exiting the bed from this step will bypass the heat exchanger and demethanizer and be directed to the turbo-expander for recompression to the pipeline.
  • the gas stream exiting the bed from this step will bypass the heat exchanger and demethanizer and be directed to the turbo-expander for recompression to the pipeline.
  • the gas stream exiting the bed from this step will bypass the heat exchanger and demethanizer and be directed to the turbo-expander for recompression
  • LS 28482-619 stream exiting the bed can be directed to the demethanizer, at the expense of some lost in cooling of the gas entering the demethanizer; or, as in the counter-current case, the gas could be directed to the turbo-expander for re-compression.
  • the bed After de-pressurization, the bed is moved to a desorption step by purging counter- currently (to the feed) with the dry gas stream at P2 as it exits the heat exchanger. Finally, the bed is re-pressurized with a gas stream leaving the bed in the adsorption step at P1 to complete the cycle.
  • adsorption occurs at about 1000 psia, de-pressurization from about 1000 to about 330 psia, desorption at about 330 psia and re-pressurization from about 330 to about 1000 psia.
  • the 3 beds in operation over the 9 process steps are shown in the table below.
  • an adsorbent bed When an adsorbent bed is removing water from the gas stream it is in an adsorption mode "A"; when the bed is being de-pressurized it is in a co-current or counter-current depressurization mode "C"; when the bed is releasing water to form a wet gas stream it is in a desorption mode "D"; and when the bed is being re-pressurized it is in a re-pressurization mode

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Abstract

La présente invention concerne un procédé de récupération d'hydrocarbures en C2+ ou en C3+ et/ou de production de gaz de vente à partir d'un gaz d'alimentation de gaz naturel, le procédé comprenant le passage du gaz d'alimentation à une pression P1 sur un lit adsorbant pour adsorber l'eau afin d'obtenir un courant de gaz naturel sec à la pression P1; le passage du courant de gaz naturel sec à travers un ou plusieurs éléments de traitement pour obtenir un courant de gaz naturel sec à une pression P2 ou P3; le passage du courant de gaz naturel sec à une pression P2 ou P3 sur un lit adsorbant pour désorber l'eau afin d'obtenir un premier courant de gaz naturel humide; et la récupération des hydrocarbures en C2+ ou en C3+ à partir du courant de gaz naturel sec et/ou la production d'un gaz de vente à partir du premier courant de gaz naturel humide; P1 > P3 > P2, le gaz de vente étant à une pression P4 et P4 > P3. Le procédé permet de régénérer les lits d'adsorption par adsorption modulée en pression dans une installation de traitement de gaz naturel. L'invention concerne également un procédé comprenant une adsorption modulée en température, qui est utilisé avec une configuration d'installation de traitement de gaz naturel similaire.
PCT/US2017/064803 2016-12-23 2017-12-06 Procédé de récupération de liquides de gaz naturel WO2018118422A1 (fr)

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Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4235613A (en) * 1979-05-29 1980-11-25 Atlantic Richfield Company Preparation of sales gas
US5089034A (en) * 1990-11-13 1992-02-18 Uop Process for purifying natural gas
US20070006732A1 (en) * 2005-07-06 2007-01-11 Mitariten Michael J Integrated heavy hydrocarbon removal, amine treating and dehydration
US20100263532A1 (en) * 2007-09-24 2010-10-21 Ifp Dry natural gas liquefaction method
US8282709B2 (en) * 2010-06-29 2012-10-09 The Governors Of The University Of Alberta Removal of ethane from natural gas at high pressure
US20170056811A1 (en) * 2015-09-02 2017-03-02 Ananda K. Nagavarapu Apparatus and System For Swing Adsorption Processes Related Thereto

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4235613A (en) * 1979-05-29 1980-11-25 Atlantic Richfield Company Preparation of sales gas
US5089034A (en) * 1990-11-13 1992-02-18 Uop Process for purifying natural gas
US20070006732A1 (en) * 2005-07-06 2007-01-11 Mitariten Michael J Integrated heavy hydrocarbon removal, amine treating and dehydration
US20100263532A1 (en) * 2007-09-24 2010-10-21 Ifp Dry natural gas liquefaction method
US8282709B2 (en) * 2010-06-29 2012-10-09 The Governors Of The University Of Alberta Removal of ethane from natural gas at high pressure
US20170056811A1 (en) * 2015-09-02 2017-03-02 Ananda K. Nagavarapu Apparatus and System For Swing Adsorption Processes Related Thereto

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