WO2015167404A1 - Système de purification de gaz naturel et son procédé d'utilisation - Google Patents

Système de purification de gaz naturel et son procédé d'utilisation Download PDF

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Publication number
WO2015167404A1
WO2015167404A1 PCT/TH2014/000022 TH2014000022W WO2015167404A1 WO 2015167404 A1 WO2015167404 A1 WO 2015167404A1 TH 2014000022 W TH2014000022 W TH 2014000022W WO 2015167404 A1 WO2015167404 A1 WO 2015167404A1
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WIPO (PCT)
Prior art keywords
liquid contact
contact system
hybrid gas
less
hollow fiber
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PCT/TH2014/000022
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English (en)
Inventor
Sakarin KHAISRI
Tassawuth POJANAVARAPHAN
Supakorn ATCHARIYAWUT
Kanokrot PHALAKORNKUL
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PTT PCL
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PTT PCL
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Priority to AU2014392793A priority Critical patent/AU2014392793A1/en
Priority to PCT/TH2014/000022 priority patent/WO2015167404A1/fr
Priority to SG11201607175UA priority patent/SG11201607175UA/en
Publication of WO2015167404A1 publication Critical patent/WO2015167404A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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Classifications

    • 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
    • B01D53/22—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 diffusion
    • B01D53/229—Integrated processes (Diffusion and at least one other process, e.g. adsorption, absorption)
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D63/00—Apparatus in general for separation processes using semi-permeable membranes
    • B01D63/02—Hollow fibre modules
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D71/00—Semi-permeable membranes for separation processes or apparatus characterised by the material; Manufacturing processes specially adapted therefor
    • B01D71/06—Organic material
    • B01D71/30—Polyalkenyl halides
    • B01D71/32—Polyalkenyl halides containing fluorine atoms
    • B01D71/36—Polytetrafluoroethylene
    • 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
    • B01D2257/30—Sulfur compounds
    • B01D2257/304—Hydrogen sulfide
    • 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
    • B01D2259/00—Type of treatment
    • B01D2259/45—Gas separation or purification devices adapted for specific applications
    • B01D2259/4566—Gas separation or purification devices adapted for specific applications for use in transportation means
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2315/00—Details relating to the membrane module operation
    • B01D2315/22—Membrane contactor
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2325/00—Details relating to properties of membranes
    • B01D2325/38—Hydrophobic membranes
    • 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
    • B01D53/14—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 absorption
    • B01D53/1456—Removing acid components
    • B01D53/1475—Removing carbon dioxide
    • 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 present disclosure relates to natural gas purification. More particularly, the present disclosure relates to a system and process for removing impurities from natural gas in a floating environment, such as on a ship or barge.
  • Petroleum reservoirs can be found onshore and/or offshore. There has been an interest in Floating Liquefied Natural Gas (FLNG) systems as a way to develop stranded gas reservoirs that are isolated and remote from land. These isolated and remote reservoirs generally are too small for permanent platform installation.
  • FLNG Floating Liquefied Natural Gas
  • An FLNG system can use a ship or barge to house necessary recovery, gas treatment, liquefaction and offloading equipment.
  • an FLNG system Compared to a land based Liquefied Natural Gas (LNG) plant, an FLNG system will typically have a greater need for a modular design to minimize the equipment footprint, equipment weight and equipment space requirement.
  • LNG Liquefied Natural Gas
  • membrane systems including dry membrane systems have typically been selected for reducing carbon dioxide content.
  • Membrane systems and processes are generally based on solution-diffusion technology. Carbon dioxide can diffuse from the natural gas feed stream from one side of the membrane to the other side of the membrane. However, some hydrocarbons such as methane, ethane, propane and butane can also diffuse from the natural gas feed stream according to the same principle as carbon dioxide. The majority of hydrocarbon loss comes from the loss of methane.
  • a single stage unit typically exhibits about 20% hydrocarbon loss.
  • about 10% to about 20% of the hydrocarbon loss is based on methane loss.
  • methane loss some operators of conventional membrane systems and processes install a second stage unit.
  • the conventional membrane systems and processes still exhibit a relatively large amount of methane loss.
  • a first aspect of the present disclosure provides a process for treating a natural gas stream, that can comprise: directing the natural gas stream to an offshore platform, wherein the offshore platform comprises a hybrid gas-liquid contact system; directing the natural gas stream to the hybrid gas-liquid contact system, wherein the hybrid gas- liquid contact system comprises a membrane contactor and a solvent; removing acid gases (such as carbon dioxide (C0 2 ) and/or hydrogen sulfide (H 2 S)) from the natural gas stream to produce a purified natural gas stream and removed C0 2 ; wherein the membrane contactor comprises a hydrophobic membrane module.
  • acid gases such as carbon dioxide (C0 2 ) and/or hydrogen sulfide (H 2 S)
  • the hydrophobic membrane module can comprise a plurality of hollow fiber membranes (e.g., microporous membranes). In some embodiments, the hydrophobic membrane module can comprise a bundle of hollow fiber membranes. In some embodiments, the hydrophobic membrane module can comprise a plurality of hollow fiber membranes, wherein the plurality of hollow fiber membranes can comprise a bundle of hollow fiber membranes. In some embodiments, the hydrophobic membrane module can comprise a cylindrical shape. In some embodiments, one or more of the plurality of hollow fiber membranes can comprise polytetrafluoroethylene (PTFE). In some embodiments, each of the plurality of hollow fiber membranes can comprise PTFE.
  • PTFE polytetrafluoroethylene
  • each of the plurality of hollow fiber membranes can have an inner diameter of about 0.1 mm to about 2 mm. In some embodiments, each of the plurality of hollow fiber membranes can have a wall thickness of about 1% of the inner diameter to about 50% of the inner diameter. In some embodiments, the number and/or amount of hollow fiber membranes present in the hydrophobic membrane module is dependent on the packing density of the hydrophobic membrane module. The packing density is the ratio of an area corresponding to the plurality of hollow fiber membranes (e.g., the bundle of hollow fiber membranes) among a cross-sectional area of the hydrophobic membrane module to the cross-sectional area of the hydrophobic membrane module. In some embodiments, the hydrophobic membrane module comprises a packing density of about 0.3 cm 2 /cm 2 to about 0.7 cmVcm 2 .
  • each of the plurality of hollow fiber membranes can comprise a porosity of about 30% to about 70%.
  • the plurality of hollow fiber membranes can be bundled together and/or held in place in accordance with a predetermined spatial organization or pattern (e.g., an array) using a material such as a perfluoroalkoxy (PFA).
  • PFA perfluoroalkoxy
  • the plurality of hollow fiber membranes can be bundled together and/or held in place using a material such as perfluoroalkoxy (PFA) tubing.
  • PFA perfluoroalkoxy
  • the plurality of hollow fiber membranes can be bundled together and/or held in place using a material such as an epoxy.
  • the hydrophobic membrane module comprises a case and/or casing.
  • the casing can comprise a material such as an acrylic.
  • the casing can comprise a material such as a perfluoroalkoxy (PFA).
  • PFA perfluoroalkoxy
  • the solvent can comprise water, sea water, brackish water, an amine solvent or a combination of one or more thereof.
  • the solvent can comprise an amine solvent.
  • the purified natural gas stream can comprise C0 2 in an amount of less than about 50 ppmv. In some embodiments, the purified natural gas stream can comprise C0 2 in an amount of about 40 ppmv or less. In some embodiments, the purified natural gas stream can comprise C0 2 in an amount of about 30 ppmv or less. In some embodiments, the purified natural gas stream can comprise C0 2 in an amount of about 23 mole % or less.
  • the purified natural gas stream can comprise H 2 S in an amount of less than about 50 ppmv. In some embodiments, the purified natural gas stream can comprise H 2 S in an amount of 10 ppmv or less. In some embodiments, the purified natural gas stream can comprise H 2 S in an amount of 5 ppmv or less. In some embodiments, the purified natural gas stream can comprise H 2 S in an amount of about 0 ppmv. In some embodiments, the process can result in a loss of methane in an amount of about 7 mole % or less. In some embodiments, the process can result in a loss of methane in an amount of about 5 mole % or less.
  • the process can result in a loss of methane in an amount of about 3 mole % or less. In some embodiments, the process can result in a loss of methane in an amount of about 2 mole % or less. In some embodiments, the process can result in a loss of methane in an amount of about 1 mole % or less.
  • each of the plurality of PTFE hollow fiber membranes and/or the PTFE hollow fiber membrane module can maintain its stability in an amine solvent and/or withstand an amine solvent for at least 18 months. In some embodiments, each of the plurality of PTFE hollow fiber membranes and/or the PTFE hollow fiber membrane module can maintain its stability in an amine solvent and/or withstand an amine solvent for at least 24 months.
  • each of the plurality of PTFE hollow fiber membranes and/or the PTFE hollow fiber membrane module can maintain its stability in high temperatures and/or withstand high temperatures of up to about 120 degrees Celsius. In some embodiments, each of the plurality of PTFE hollow fiber membranes and/or the PTFE hollow fiber membrane module can maintain its stability in high temperatures and/or withstand high temperatures of up to about 150 degrees Celsius.
  • each of the plurality of PTFE hollow fiber membranes and/or the PTFE hollow fiber membrane module can exhibit improved stability in an absorption system and desorption system.
  • the process can result in a reduced amine solvent equipment footprint in comparison with conventional amine systems by about 40% or more. In some embodiments, the process can result in a decrease in capital expenditures in comparison to conventional amine systems by about 42% or more.
  • the offshore platform can comprise a fixed offshore platform. In some embodiments, the fixed offshore platform can comprise a pipeline.
  • the offshore platform can comprise a floating offshore platform.
  • the floating offshore platform can comprise a floating liquefied natural gas (FLNG) system.
  • the FLNG system can comprise a ship or barge.
  • a second aspect of the present disclosure provides a hybrid gas-liquid contact system for an offshore platform, wherein the hybrid gas-liquid contact system comprises: a membrane contactor and a solvent; wherein the membrane contactor comprises a hydrophobic membrane module.
  • the hydrophobic membrane module can comprise a plurality of hollow fiber membranes.
  • the hydrophobic membrane module can comprise a bundle of hollow fiber membranes (e.g., microporous membranes).
  • the hydrophobic membrane module can comprise a cylindrical shape.
  • one or more of the plurality of hollow fiber membranes can comprise polytetrafluoroethylene (PTFE).
  • PTFE polytetrafluoroethylene
  • each of the plurality of the hollow fiber membranes can comprise PTFE.
  • the solvent can comprise water, sea water, brackish water, an amine solvent or a combination of one or more thereof. In some embodiments, the solvent can comprise an amine solvent.
  • the hybrid gas-liquid contact system can reduce a carbon dioxide (CO2) content in a natural gas stream to less than about 50 ppmv. In some embodiments, the hybrid gas-liquid contact system can reduce the C0 2 content in the natural gas stream to about 40 ppmv or less. In some embodiments, the hybrid gas- liquid contact system can reduce the C0 2 content in the natural gas stream to about 30 ppmv or less. In some embodiments, the hybrid gas-liquid contact system can reduce the C0 2 content in the natural gas stream to about 23 mole % or less. In some embodiments, the hybrid gas-liquid contact system can reduce a H 2 S content in a natural gas stream to less than about 50 ppmv.
  • CO2 carbon dioxide
  • the hybrid gas- liquid contact system can reduce the 3 ⁇ 4S content in the natural gas stream to about 10 ppmv or less. In some embodiments, the hybrid gas-liquid contact system can reduce the H 2 S content in the natural gas stream to about 5 ppmv or less. In some embodiments, the hybrid gas-liquid contact system can reduce the H 2 S content in the natural gas stream to about 0 ppmv. In some embodiments, the hybrid gas-liquid contact system can provides a loss of methane in an amount of about 7 mole % or less. In some embodiments, the hybrid gas-liquid contact system can provide a loss of methane in an amount of about 5 mole % or less.
  • the hybrid gas-liquid contact system can provide a loss of methane in an amount of about 3 mole % or less. In some embodiments, the hybrid gas-liquid contact system can provide a loss of methane in an amount of about 2 mole % or less. In some embodiments, the hybrid gas-liquid contact system can provide a loss of methane in an amount of about 1 mole % or less.
  • each of the plurality of PTFE hollow fiber membranes and/or the PTFE hollow fiber membrane module can maintain its stability in an amine solvent and/or withstand an amine solvent for at least 18 months. In some embodiments, each of the plurality of PTFE hollow fiber membranes and/or the PTFE hollow fiber membrane module can maintains its stability in an amine solvent and/or withstand an amine solvent for at least 24 months.
  • each of the plurality of PTFE hollow fiber membranes and/or the PTFE hollow fiber membrane module can maintain its stability in high temperatures and/or withstand high temperatures of up to 120 degrees Celsius. In some embodiments, each of the plurality of PTFE hollow fiber membranes and/or the PTFE hollow fiber membrane module can maintain its stability in high temperatures and/or withstand high temperatures of up to about 150 degrees Celsius. In some embodiments, each of the plurality of PTFE hollow fiber membranes and/or the PTFE hollow fiber membrane module can exhibit improved stability in an absorption system and desorption system. In some embodiments, the hybrid gas-liquid contact system can provide a reduced amine solvent equipment footprint in comparison with conventional amine systems by about 40% or more.
  • the hybrid gas-liquid contact system can provide a decrease in capital expenditures in comparison to conventional amine systems by about 42% or more.
  • the offshore platform can comprise a fixed offshore platform.
  • the fixed offshore platform can comprise a pipeline.
  • the offshore platform can comprise a floating offshore platform.
  • the floating offshore platform can comprise a floating liquefied natural gas (FLNG) system.
  • the FLNG system can comprise a ship or barge.
  • FIGs. 1 A-IB illustrate a cross-section view of a hollow fiber/hollow fiber membrane of a hollow fiber membrane contactor in accordance with an embodiment of the present disclosure, wherein the hollow fiber/hollow fiber membrane of the hollow fiber membrane contactor can have two modes of operation.
  • FIG. 1A illustrates a first mode of operation wherein the solvent can flow on and/or along the inside/inner surface of the hollow fiber/hollow fiber membrane.
  • FIG. IB illustrates a second mode of operation wherein the solvent can flow on and/or along the outside/outer surface of the hollow fiber/hollow fiber membrane.
  • FIGs. 2A-2C illustrate mass transfer resistances in a series model comprising of a: FIG. 2A) non- wetted mode of operation example; FIG. 2B) fully wetted mode of operation example; and FIG. 2C) partially wetted mode of operation example.
  • the term "about” or “approximately”, in the context of concentrations of components, conditions, other measurement values, etc., means +/- 10% of the stated value or value range, +/- 5% of the stated value or value range, or +/- 4% of the stated value or value range, or +/- 3% of the stated value or value range, or +/- 2% of the stated value or value range, or +/- 1% of the stated value or value range, or +/- 0.5% of the stated value or value range, or +/- 0% of the stated value or value range.
  • range format is merely for convenience and brevity and should not be construed as an inflexible limitation on the scope of the disclosed ranges. Accordingly, the description of a range should be considered to have specifically disclosed all the possible sub-ranges as well as individual numerical values within that range. For example, description of a range such as from 1 to 6 should be considered to have specifically disclosed sub-ranges such as from 1 to 3, from 1 to 4, from 1 to 5, from 2 to 4, from 2 to 6, from 3 to 6 etc., as well as individual numbers within that range, for example, 1, 1.5, 2, 2.5, 3, 3.5, 4, 4.5, 5, 5.5 and 6. This applies regardless of the breadth of the range.
  • the present disclosure relates to a natural gas purification system and process for using thereof for Floating Liquefied Natural Gas (FLNG) system applications, wherein the natural gas purification system is based on membrane contactor technology and/or gas- liquid membrane contactor technology.
  • the membrane contactor and/or gas-liquid membrane contactor of the present disclosure combine the advantages and/or benefits of the membrane system and process, and an amine system and process.
  • the membrane contactor and/or gas-liquid membrane contactor of the present disclosure includes or uses a membrane or membrane structure, for instance, a hollow fiber membrane or membrane structure, instead of packing in a conventional amine based packed column/tower to increase the surface contact area.
  • a hollow fiber membrane or membrane structure in accordance with some embodiments of the present disclosure can be microporous, for instance, having pore sizes of less than or equal to approximately 1 ⁇ (e.g., pore sizes of approximately 1 ⁇ ). Microporosity can facilitate or result in higher flow rates and/or lower cost compared to nanoporous membranes.
  • the overall volumetric gas-phase mass transfer coefficient (KGa) for the membrane contactor and/or gas-liquid membrane contactor of the present disclosure can be up to four (4) times larger than the value obtained from a packed column. In some embodiments, the overall volumetric gas-phase mass transfer coefficient (KGa) for the membrane contactor and/or gas-liquid membrane contactor of the present disclosure can be up to five (5) times larger than the value obtained from a packed column. In some embodiments, the overall volumetric gas-phase mass transfer coefficient (KGa) for the membrane contactor and/or gas-liquid membrane contactor of the present disclosure can be up to seven (7) times larger than the value obtained from a packed column.
  • the membrane contactor and/or gas-liquid membrane contactor of the present disclosure can also overcome methane loss exhibited by conventional dry membrane systems and processes by reducing methane loss.
  • the reduction in methane loss can be achieved because the membrane contactor and/or gas-liquid membrane contactor process of the present disclosure utilizes an absorption process.
  • the absorption process of the membrane contactor and/or gas-liquid membrane contactor process of the present disclosure is completely different from the solution-diffusion theory.
  • the absorption process of the present disclosure can result in a loss of methane, but the amount lost is very small.
  • the methane loss of the absorption process of the present disclosure results from the physical solubility between the solvent and methane.
  • the membrane contactor and/or gas-liquid membrane contactor can provide for a reduction in methane loss from the natural gas feed stream in comparison to conventional dry membrane systems and processes.
  • a single stage unit typically exhibits about 10 mole % to about 20 mole % methane loss.
  • the membrane contactor and/or gas-liquid membrane contactor can provide for a reduced weight in comparison to a conventional amine based packed column/tower and a reduced equipment footprint in comparison to a conventional amine based packed column/tower.
  • this membrane contactor and/or gas-liquid membrane contactor can be used for FLNG applications.
  • the FLNG gas specification requires an ultra-low C0 2 concentration (e.g., compared to a conventional Liquefied Natural Gas (LNG) production procedure).
  • the C0 2 concentration requirement for FLNG applications is about 50 ppmv, which conventional dry membrane systems and processes typically cannot meet.
  • a conventional amine based packed column/tower is not suitable for FLNG applications because the height of the column/tower is relatively high and the size of equipment is relatively large thus requiring a large ship area which in turn would undesirably increase the capital expenditures and operational costs.
  • the membrane of the membrane contactor and/or gas-liquid membrane contactor acts as a selective barrier between gases (e.g., natural gas) and liquid (e.g., solvent).
  • gases e.g., natural gas
  • liquid e.g., solvent
  • the C0 2 from a natural gas feed stream diffuses in, into, or through the membrane pores and then is absorbed by the solvent.
  • the solvent can comprise water, sea water, brackish water, and/or an amine solvent.
  • the amine solvent can comprise monoethanolamine (MEA), diglycolamine (DGA), diethanolamine (DEA), diisopropanolamine (DIPA), triethanolamine (TEA), methyldiethanolamine (MDEA), activated-MDEA (aMDEA), 2-amino-2-methy-l-propanol (AMP) or a combination of two or more thereof.
  • MEA monoethanolamine
  • DGA diglycolamine
  • DEA diethanolamine
  • DIPA diisopropanolamine
  • TAA triethanolamine
  • MDEA methyldiethanolamine
  • aMDEA activated-MDEA
  • AMP 2-amino-2-methy-l-propanol
  • the amine based solvent can absorb more C0 2 than a water-based solvent because the amine based solvent system and process utilizes chemical absorption.
  • the amine solvent based system of the membrane contactor and/or gas-liquid membrane contactor can be a closed-loop system because the amine solvent can be regenerated.
  • acid gases such as C0 2 and H 2 S react with the amine the reaction is a reversible reaction.
  • the acid gases can be separated from the amine.
  • the amine solvent can be sent or directed to another unit known as a membrane desorber to heat the amine solvent.
  • the heated amine solvent can then desorb C0 2 from the amine solvent.
  • the treated amine solvent can then be sent back to the membrane contactor and/or gas-liquid membrane contactor of the present disclosure, which can also be referred to as a membrane absorber unit.
  • the mechanism for C0 2 absorption is physical absorption.
  • the physical absorption is based on the solubility of water and C0 2 .
  • the C0 2 rich water e.g., water saturated with C0 2
  • the solubility of C0 2 decreases when the pressure is reduced.
  • the flash unit can be used to reduce the pressure and the treated water can then be drained back to the sea. Draining the treated water back to sea provides for a reduced equipment footprint, reduced equipment size, and reduced equipment space requirement.
  • the size of tank(s) for storing water can be reduced.
  • the use of water, sea water and/or brackish water as the solvent and/or the draining of treated water back to sea can provide for a reduction in the ship size requirement and a reduction in the footprint of the whole membrane contactor and/or gas-liquid membrane contactor system and process of the present disclosure.
  • the hollow fiber membranes used in the membrane contactor and/or gas-liquid membrane contactor system and process can be hydrophobic membranes.
  • the higher the hydrophobicity of the hollow fiber membrane the better the long-term performance of the hollow fiber membrane.
  • the higher the hydrophobicity of the hollow fiber membrane the greater the stability of the hollow fiber membrane.
  • the definition of hydrophobic is that the contact angle between a water droplet and surface is higher than 90°.
  • the hollow fiber membranes can comprise polytetrafluoroethylene (PTFE).
  • PTFE polytetrafluoroethylene
  • the PTFE hollow fiber membranes exhibit hydrophobic characteristics and hydrophobic polymer properties.
  • FIGS. 1A-1B illustrate a cross-section view of a PTFE hollow fiber/PTFE hollow fiber membrane of a PTFE hollow fiber membrane contactor in accordance with an embodiment of the present disclosure.
  • a PTFE hollow fiber membrane or membrane structure in accordance with an embodiment of the present disclosure can have an interlamellar structure, in a manner readily understood by one having ordinary skill in the art.
  • the PTFE hollow fiber / PTFE hollow fiber membrane of the PTFE hollow fiber membrane contactor can be configured or designed to have pore sizes that enable the passage of C0 2 and H 2 S therethrough (and into the absorbent / solvent), but which block, essentially block, or very substantially block the passage of hydrocarbons (HC) therethrough.
  • the PTFE hollow fiber/PTFE hollow fiber membrane of the PTFE hollow fiber membrane contactor can have two modes of operation with respect to the flow of an absorbent or solvent (e.g., received or introduced from an absorbent / solvent feed system or apparatus) relative to the flow of natural gas (e.g., received, obtained, or introduced from a natural gas source or reservoir, and directed or introduced to an FLNG platform and into the PTFE hollow fiber membrane contactor).
  • FIG. 1A illustrates a first mode of operation wherein the solvent can flow on and/or along the inside/inner surface of the PTFE hollow fiber membrane.
  • IB illustrates a second mode of operation wherein the solvent can flow on and/or along the outside/outer surface of the PTFE hollow fiber membrane.
  • the inside/inner surface and outside/outer surface of the PTFE hollow fiber membrane are both hydrophobic, a solvent can flow inside and/or outside the PTFE hollow fiber membrane. That is, a given PTFE hollow fiber membrane or PTFE hollow fiber membrane structure or module in accordance with an embodiment of the present disclosure can be employed in a system configured for solvent flow on the inside of the PTFE hollow fiber membrane, or solvent flow on the outside of the PTTE hollow fiber membrane, depending upon embodiment details.
  • hydrophilic hollow fiber membranes such as a poly(ether ether ketone) (PEEK) membrane typically require the outside/outer surface of the PEEK membrane to be coated with a material to modify the outside/outer surface of the PEEK membrane such that the outside/outer surface comprises hydrophobic properties.
  • PEEK poly(ether ether ketone)
  • a solvent can only flow on and/or along the outside/outer surface of the PEEK hollow fiber membrane. The solvent must contact the hydrophobic side of the membrane to prevent membrane wetting. Membrane wetting results in water and/or solvent filled membrane pores, which in turn leads to a reduced mass transfer coefficient as can be seen in FIG. 2A-2C.
  • FIGS. 2A-2C illustrate mass transfer resistances in a series model comprising of a: FIG. 2A) non-wetted mode of operation example; FIG. 2B) fully wetted mode of operation example; and FIG. 2C) partially wetted mode of operation example.
  • FIG. 2A illustrates a non-wetted mode of operation. In the non-wetted mode of operation only the gas phase is in the membrane pores. The non-wetted mode of operation can be the most effective mode of operation for the hydrophobic hollow fiber membrane contactor of the present disclosure. The gas diffusivity in the gas phase is much larger that the gas diffusivity in the liquid phase. This leads to a high mass transfer rate in the non-wetted mode.
  • FIG. 2B illustrates a fully wetted mode of operation. In the fully wetted mode the liquid phase fills all the membrane pores.
  • FIG. 2C illustrates a partially wetted mode of operation. In the partially wetted mode the liquid phase partially fills the membrane pores.
  • the fully wetted mode of operation and the partially wetted mode of operation lead to a reduction in the mass transfer rate compared to the non-wetted mode of operation.
  • the hollow fiber membrane contactor and/or gas-liquid hollow fiber membrane contactor of the present disclosure can comprise a hollow fiber membrane module.
  • the hollow fiber membrane module can comprise a plurality of hollow fiber membranes.
  • the plurality of hollow fiber membranes can comprise a bundle of hollow fiber membranes.
  • the hollow fiber membrane module can be provided and/or prepared on a commercial scale.
  • the plurality of hollow fiber membranes and/or the hollow fiber membrane module can comprise a specific surface area of about 1 cm 2 /cm 3 to about 100 cm /cm .
  • the plurality of hollow fiber membranes and/or the hollow fiber membrane module can comprise a specific surface area of greater than 100 cm 2 /cm 3 .
  • the bundle of hollow fiber membranes can comprise a specific surface area of about 1 cm 2 /cm 3 to about 100 cm /cm .
  • the bundle of hollow fiber membranes can comprise a specific surface area of greater than 100 cm .
  • each of the plurality of hollow fiber membranes can have an inner diameter of about 0.1 mm to about 2 mm. In some embodiments, each of the plurality of hollow fiber membranes can have a wall thickness of about 1% of the inner diameter to about 50% of the inner diameter.
  • the number and/or amount of hollow fiber membranes present in the hydrophobic membrane module is dependent on the packing density of the hydrophobic membrane module.
  • the packing density is the ratio of an area corresponding to the plurality of hollow fiber membranes (e.g., the bundle of hollow fiber membranes) among a cross-sectional area of the hydrophobic membrane module to the cross-sectional area of the hydrophobic membrane module.
  • the hydrophobic membrane module comprises a packing density of about 0.3 cm 2 /cm 2 to about 0.7 cm 2 /cm 2 .
  • each of the plurality of hollow fiber membranes can comprise a porosity of about 30% to about 70%.
  • the plurality of hollow fiber membranes corresponding to a module can be bundled together and/or held in place using a material such as a perfluoroalkoxy (PFA).
  • PFA perfluoroalkoxy
  • the plurality of hollow fiber membranes can be bundled together and/or held in place using a material such as perfluoroalkoxy (PFA) tubing.
  • PFA perfluoroalkoxy
  • the plurality of hollow fiber membranes can be bundled together and/or held in place using a material such as an epoxy. Other materials are also suitable for bundling or holding the hollow fiber membranes in place.
  • the hydrophobic membrane module comprises a case and/or casing.
  • the casing can comprise a material such as an acrylic.
  • the casing can comprise a material such as a perfluoroalkoxy (PFA). Other materials are also contemplated.
  • aspects of the present disclosure relate to the capture or removal of C0 2 and/or H 2 S from natural gas.
  • a liquid/solvent will absorb C0 2 and/or H 2 S.
  • the liquid/solvent used for absorbing C0 2 and/or H 2 S from a natural gas feed stream can comprise water, sea water, brackish water, an amine aqueous based solution or a combination of one or more thereof.
  • the amine aqueous based solution can comprise the amine in an amount of about 1 weight percent to up to about 40 weight percent.
  • each country has a specification for the concentration of C0 2 allowed in a gas pipeline or allowed for specific applications.
  • the C0 2 content and/or concentration must be less than 50 ppmv.
  • a PEEK membrane is originally a hydrophilic membrane that must be treated or modified to have hydrophobic properties. More particularly, a PEEK membrane is treated and/or modified using a grafting process to provide hydrophobic properties. In the grafting process, the surface of the PEEK membrane is grafted with a specific material to make the PEEK membrane hydrophobic. Unfortunately, the grafting process can result in uncertainty with respect to whether the PEEK membrane surface has been effectively modified. For example, during the grafting process, a surface modification reaction may not occur at some locations or areas of the PEEK membrane's surface. Such un-modified PEEK membrane surface locations or areas remain hydrophilic, resulting in membrane wetting in the membrane contactor, thereby significantly decreasing overall mass transfer.
  • the material(s) used to coat the PEEK membrane and impart hydrophobic properties to the PEEK membrane can be susceptible to deformation and cannot be guaranteed to withstand or reliably withstand the high pressure, high temperature, high flow rate of liquid, and/or long term exposure to an amine solvent, associated with membrane contactors and/or gas-liquid contactors, especially for FLNG applications.
  • the grafting process is an additional process that the PEEK membrane is required to undergo before it can be used in the membrane contactor.
  • the grafting process can involve additional materials, additional equipment, additional time, and/or extra costs.
  • the PTFE hollow fiber membranes in accordance with embodiments of the present disclosure do not require an additional treatment process and/or additional modification process, as the PTFE hollow fiber membranes inherently exhibit hydrophobic properties.
  • the PTFE hollow fiber membranes in accordance with embodiments of the present disclosure thus do not exhibit the aforementioned drawbacks associated with PEEK membranes.
  • the conventional dry membrane systems and processes typically result in a loss of methane from the natural gas feed stream in an amount of up to about 20 mole %.
  • the use of the membrane contactor and/or gas-liquid contactor results in loss of methane from an natural gas feed stream in an amount of about 7 mole % or less, about 6 mole % or less, about 5 mole % or less, about 4 mole % or less, about 3 mole % or less, about 2 mole % or less, about 1 mole % or less, or about 0 mole %.
  • the membrane contactor and/or gas-liquid contactor of the present disclosure utilizes an absorption process and is based on the absorption theory. As such, the membrane contactor and/or gas-liquid contactor of the present disclosure is different from conventional dry membrane systems and processes. Any methane loss exhibited in the membrane contactor process and gas-liquid contactor process of the present disclosure results from the methane that is absorbed in the liquid/solvent (e.g., water, sea water, brackish water and/or amine solvent).
  • the liquid/solvent e.g., water, sea water, brackish water and/or amine solvent
  • the natural gas purification system and process of the present disclosure can be used for removing impurities from natural gas received by or being treated on an offshore platform.
  • the offshore platform can be a fixed offshore platform or a floating platform.
  • the natural gas purification system and process of the present disclosure can be used for removing impurities from natural gas in a floating environment, for instance, on a ship or barge (e.g., a floating platform analogous, similar, or generally similar to the Royal Dutch Shell Prelude platform or another type of floating platform).
  • a floating platform analogous, similar, or generally similar to the Royal Dutch Shell Prelude platform or another type of floating platform.

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  • Chemical & Material Sciences (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Engineering & Computer Science (AREA)
  • Analytical Chemistry (AREA)
  • General Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Separation Using Semi-Permeable Membranes (AREA)
  • Gas Separation By Absorption (AREA)

Abstract

La présente invention concerne la purification du gaz naturel. La présente invention concerne plus particulièrement un système et un procédé d'élimination des impuretés d'un flux de gaz naturel dans un environnement flottant, par exemple sur un bateau ou une barge, qui porte un contacteur à membrane comprenant au moins un module de membrane hydrophobe ayant une pluralité de membranes à fibres creuses de PTFE (par exemple, comprenant ou constituées de membranes de PTFE microporeuses).
PCT/TH2014/000022 2014-04-28 2014-04-28 Système de purification de gaz naturel et son procédé d'utilisation Ceased WO2015167404A1 (fr)

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AU2014392793A AU2014392793A1 (en) 2014-04-28 2014-04-28 A natural gas purification system and a process of using thereof
PCT/TH2014/000022 WO2015167404A1 (fr) 2014-04-28 2014-04-28 Système de purification de gaz naturel et son procédé d'utilisation
SG11201607175UA SG11201607175UA (en) 2014-04-28 2014-04-28 A natural gas purification system and a process of using thereof

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US10343107B2 (en) 2013-05-09 2019-07-09 Exxonmobil Upstream Research Company Separating carbon dioxide and hydrogen sulfide from a natural gas stream using co-current contacting systems
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US10343107B2 (en) 2013-05-09 2019-07-09 Exxonmobil Upstream Research Company Separating carbon dioxide and hydrogen sulfide from a natural gas stream using co-current contacting systems
US10300429B2 (en) 2015-01-09 2019-05-28 Exxonmobil Upstream Research Company Separating impurities from a fluid stream using multiple co-current contactors
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US10391442B2 (en) 2015-03-13 2019-08-27 Exxonmobil Upstream Research Company Coalescer for co-current contractors
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US11000795B2 (en) 2017-06-15 2021-05-11 Exxonmobil Upstream Research Company Fractionation system using compact co-current contacting systems
US11260342B2 (en) 2017-06-15 2022-03-01 Exxonmobil Upstream Research Company Fractionation system using bundled compact co-current contacting systems
US10876052B2 (en) 2017-06-20 2020-12-29 Exxonmobil Upstream Research Company Compact contacting systems and methods for scavenging sulfur-containing compounds
US11000797B2 (en) 2017-08-21 2021-05-11 Exxonmobil Upstream Research Company Integration of cold solvent and acid gas removal

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