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WO2012092980A1 - Procédé d'élimination de gaz acide dans le gaz naturel - Google Patents

Procédé d'élimination de gaz acide dans le gaz naturel Download PDF

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Publication number
WO2012092980A1
WO2012092980A1 PCT/EP2011/050174 EP2011050174W WO2012092980A1 WO 2012092980 A1 WO2012092980 A1 WO 2012092980A1 EP 2011050174 W EP2011050174 W EP 2011050174W WO 2012092980 A1 WO2012092980 A1 WO 2012092980A1
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WIPO (PCT)
Prior art keywords
natural gas
stream
absorber
carbon dioxide
raw
Prior art date
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Ceased
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PCT/EP2011/050174
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English (en)
Inventor
Torbjørn FIVELAND
Knut Ingvar Aasen
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Equinor Energy AS
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Statoil Petroleum ASA
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Priority to PCT/EP2011/050174 priority Critical patent/WO2012092980A1/fr
Publication of WO2012092980A1 publication Critical patent/WO2012092980A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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    • 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
    • B01D45/00—Separating dispersed particles from gases or vapours by gravity, inertia, or centrifugal forces
    • B01D45/12—Separating dispersed particles from gases or vapours by gravity, inertia, or centrifugal forces by centrifugal forces
    • B01D45/14—Separating dispersed particles from gases or vapours by gravity, inertia, or centrifugal forces by centrifugal forces generated by rotating vanes, discs, drums or brushes
    • 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
    • B01D53/18—Absorbing units; Liquid distributors therefor
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • 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
    • B01D2258/00—Sources of waste gases
    • B01D2258/06—Polluted air
    • 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 the treatment of natural gas and other gas streams containing methane and at least one acid gas, such as carbon dioxide. More particularly, the invention relates to the use of gas separation membranes to remove at least excess carbon dioxide from the gas
  • Natural gas is an important fuel gas and is also used extensively as a basic raw material in the petrochemical and other chemical process industries.
  • the composition of natural gas varies widely from field to field.
  • a raw gas stream may contain as much as 95 percent methane, with only minor amounts of other hydrocarbons, nitrogen, carbon dioxide (CO 2 ), hydrogen sulphide (H 2 S) or water vapour.
  • streams with large proportions of one or more of these contaminants are common.
  • gas that is extracted as a result of miscible flood enhanced oil recovery may be very rich in carbon dioxide, as well as being saturated with C3+ hydrocarbons.
  • the separation of carbon dioxide from the raw gas stream is important in natural gas processing because carbon dioxide reduces the energy content of natural gas.
  • Some natural gas wells may contain high concentrations of carbon dioxide (as high as 70 percent), and most of this carbon dioxide must be removed before the natural gas is shipped and/or used.
  • Membrane units when compared with relatively large conventional treating processes such as amine absorption columns and associated regeneration columns, require a relatively small operational area, require small amounts of energy, and require only minor operational efforts. Also maintenance and inspection requirements are moderate.
  • cellulose acetate membranes which can provide a carbon dioxide/methane selectivity of about 10-20 in gas mixtures at pressure, have been the membranes of choice.
  • Other types of membrane that may be considered are polyethylene oxide based membranes, such as polyethylene oxide based membranes comprising block-copolymers (especially PEO 600/5000 T6T6T or a cross linked PEO), polyimide or polyaramide based membranes, cellulose acetate based membranes, zeolite based membranes, such as silica-alumina phosphate based membranes, especially, SAPO-34, micro-porous silica membranes or carbon molecular sieve membranes, or nano-molecular sieve-polymer mixed matrix membranes (MMMS).
  • polyethylene oxide based membranes such as polyethylene oxide based membranes comprising block-copolymers (especially PEO 600/5000 T6T6T or a cross linked PEO), polyimide or polyaramide based membranes, cellulose acetate based
  • membrane separation it would be desirable in many more cases to use membrane separation, because membrane systems are relatively simple, have few moving parts, can operate under moderate temperature and pressure conditions and, unlike amine scrubbing, do not require a regeneration cycle. Also, the wellhead gas pressure may be high enough to provide the total driving force for trans-membrane permeation.
  • cellulose acetate, polymeric and other types of membranes are not without problems.
  • many membranes are irreparably damaged by liquid hydrocarbons, and similar precautions must be taken to avoid the risk of condensation of C3+ hydrocarbons on the membranes at any time.
  • carbon dioxide readily sorbs into and interacts strongly with many polymers, and in the case of gas mixtures such as carbon dioxide/methane with other components, the carbon dioxide tends to have a swelling or plasticizing effect, thereby adversely changing the membrane permeation characteristics.
  • membrane materials such as polyimide
  • membranes have been, and are, used to remove carbon dioxide from natural gas, there are many situations where the composition of the gas, the size of the stream to be processed, the size of the membrane required, or the site geography renders a membrane-based process technically or economically unrealistic.
  • the invention relates to a process for treatment of a raw natural gas and other gas streams containing methane and at least one acid gas, such as carbon dioxide, by removing said acid gas to produce a sweetened natural gas stream, the process comprising the steps of:
  • Suitable absorbent media comprise amine based absorbents such as primary, secondary and tertiary amines.
  • amine based absorbents such as primary, secondary and tertiary amines.
  • One well known example of applicable amines is mono ethanol amine (MEA).
  • MEA mono ethanol amine
  • the liquid diluent is selected among diluents that have a suitable boiling point, are stable and inert towards the absorbent in the suitable temperature and pressure interval.
  • An example of an applicable diluent is water.
  • Suitable amines for use with a diluents such as water are aqueous solutions of monoethanolamine (MEA), methylaminopropylamine (MAPA), piperazine, diethanolamine (DEA), triethanolamine (TEA), diethylethanolamine (DEEA), diisopropylamine (DIPA), aminoethoxyethanol (AEE), dimethylaminopropanol (DIMAP) and methyldiethanolamine (MDEA), methyldiisopropanolamine (MDIPA), 2-amino-1 -butanol (2-AB) or mixtures thereof.
  • MEA monoethanolamine
  • DEA methylaminopropylamine
  • DEA triethanolamine
  • DEEA diethylethanolamine
  • DIPA diisopropylamine
  • AEE aminoethoxyethanol
  • DIMAP dimethylaminopropanol
  • MDEA methyldiethanolamine
  • MDIPA 2-amino-1 -butanol
  • the raw natural gas feed stream can be contacted with a membrane to reduce the carbon dioxide content of the raw natural gas feed stream from at least 30 % C0 2 to a first level at or below 20 % C0 2 .
  • the reduction of C02 is dependent on the C02 content of the raw natural gas and/or the type and surface area of the membrane used.
  • the raw natural gas feed stream can be contacted with a membrane to reduce the carbon dioxide content of the raw natural gas feed stream from at least 30 % C0 2 to a first level between 7 and 12 % C0 2 .
  • the resulting natural gas product stream can be supplied to the further absorber to reduce the carbon dioxide content of the natural gas product stream from a first level of 20 % C0 2 or less, e.g from 7-12 % C0 2 , to a second level of 2,4 % C0 2 or less.
  • a typical gas pipeline specification for carbon dioxide which is usually less than 2,4 % C0 2 , preferably no more than 2 % C0 2 .
  • the reduction of the carbon dioxide content from the first level to the second level is achieved by supplying the lean absorption medium to an inner portion of at least one annular rotating absorber unit within the absorber, causing the lean absorption medium to flow radially outwards through the rotating absorption zone; and supplying the natural gas product stream to an outer portion of said annular rotating absorber unit, causing the natural gas product to flow radially inwards in order to create a radial cross-flow in the absorption zone.
  • the lean absorption medium is preferably supplied to a pair of identical and mirrored annular rotating absorber units rotating about a common axis within the absorber. The above process is particularly well suited for offshore applications, or in locations where space is an issue.
  • Suitable organic scrubbing agents for this purpose are toluene, N- methylpyrrolidone, dimethylformamide, isopropanolamine and especially dialkyi ethers of diethylene glycols and especially the dimethyl ethers of di- to heptaethylene glycols are suitable. Highly effective results are also obtained with dimethylisopropyl ethers of ethylene glycols.
  • alkyl will mean C1 to C18 straight or branched chain hydrocarbons and corresponding cycloalkyl compounds.
  • hydrogen sulfide-selective water-based solvents can also be used, for example aqueous solutions of aminoacid salts, although these scrubbing agents must be employed at temperatures above their respective freezing points and additional stages must be provided to dry the gas.
  • the elimination of the hydrogen sulfide content from the raw natural gas stream is achieved by supplying the organic scrubbing agent to an inner portion of at least one annular rotating absorber unit within the further absorber, causing the organic scrubbing agent to flow radially outwards through the rotating absorption zone; and supplying the raw natural gas stream to an outer portion of said annular rotating absorber unit, causing the raw natural gas stream to flow radially inwards in order to create a radial cross-flow in the absorption zone.
  • the organic scrubbing agent is preferably supplied to a pair of identical and mirrored annular rotating absorber units rotating about a common axis within the absorber.
  • Figure 1 shows a schematic, partially cross-sectioned absorber for use in a process according to the invention
  • Figure 2 shows a cross-section through a first alternative embodiment of an absorber for use in a process according to the invention
  • Figure 3 shows a schematic diagram of the flow of absorbent and natural gas through the absorbers of Fig. 1 and Fig.2;
  • Figure 4 shows a cross-section through a second alternative embodiment of an absorber for use in a process according to the invention;
  • Figure 5 shows a schematic diagram of the flow of absorbent and natural gas through the absorber of Fig.4;
  • Figure 6 shows a schematic diagram of a process according to a first embodiment of the invention.
  • Figure 7 shows a schematic diagram of a process according to a second embodiment of the invention.
  • Figure 6 shows a schematic diagram of a process according to a first embodiment of the invention.
  • a raw gas stream 610 which may be any natural gas, or hydrocarbon-containing gas, from which it is desired to remove carbon dioxide is directed into a production plant for carrying out the process.
  • the gas may be from a natural gas well, may be associated gas produced in conjunction with oil, either spontaneously or as a result of carbon dioxide injection, may be gas gathered from a landfill, or may arise from any other source.
  • the raw gas stream 610 may be as-extracted from the ground or may have been subjected to pretreatment of any kind, including, but not limited to, filtration to remove particulates, entrained water or hydrocarbon liquids, separation by any means, including, but not limited to absorption, adsorption, condensation and other membrane or non-membrane separation, to remove gaseous contaminants, such as nitrogen or water vapor.
  • the raw gas stream 610 is typically at above atmospheric pressure, such as at a few hundred psia (a few thousand kPa), and may or may not be at sufficiently high pressure for the desired process performance for the membrane.
  • the content of carbon dioxide in raw gas stream 610 may be any amount, ranging from, for example, 20-30 percent or more.
  • Natural gas pipeline specification for carbon dioxide is usually no more than 2-2,4 percent. If the process is directed at treating carbon-dioxide-containing gas from a natural gas well, therefore, the raw gas stream 610 will contain at least 2 percent carbon dioxide. The process is particularly well suited to treat gas containing at least about 20 percent carbon dioxide or more.
  • the raw gas stream 610 also contains C3+ hydrocarbons and water vapor, and these also may be present in any quantities. Therefore, the partial pressures of both the hydrocarbons and the water in the feed may be close to the saturation vapor pressures of those components at the temperature of the raw gas stream 610.
  • the aggregate partial pressure of all C3+ hydrocarbons in the gas might be as much as 30 psia, 50 psia, 75 psia, 100 psia or more.
  • the partial pressure of hydrocarbons, particularly C3+ hydrocarbons may be 20 percent, 50 percent, 80 percent or more of saturation, for example.
  • the typical water content is up to about 1 ,200 ppm. Water can be removed in a separate dehydration process prior to the carbon dioxide removal.
  • the other most significant component of the stream is methane, frequently, but not necessarily, the major component, and the stream may typically contain a number of other components, such as ethane, hydrogen sulfide and/or inert gases such as helium and argon in minor or trace amounts.
  • the current invention is mainly directed to the removal of carbon dioxide.
  • the first embodiment relates to a process for treatment of a raw natural gas and other gas streams containing methane and carbon dioxide, by removing said carbon dioxide to produce a sweetened natural gas stream, the process comprising the initial steps of contacting the raw natural gas feed stream with a separation membrane to obtain a natural gas product stream rich in methane and having a carbon dioxide content reduced to a first level relative to the raw natural gas stream;
  • the raw gas stream 610 is typically at elevated pressure. If it is at insufficiently high pressure to operate the process satisfactorily, the raw gas stream 610 may optionally be compressed, as shown in Figure 6.
  • the raw gas stream 610 then passes into an optional compression step 61 1 .
  • the compressor used in compression step 61 1 may be of any convenient type, such as centrifugal, screw or reciprocating, based on considerations of outlet pressure needed, gas flow rate and composition, and like issues familiar to those of skill in the art. Screw compressors are relatively inexpensive and are widely used to reach pressures up to about 300 or 400 psia; for higher pressures, piston compressors are more commonly used. Typically, but not necessarily, the compression step raises the pressure of the gas stream between 3 and 10 times. This may be done in a single-stage or multiple-stage compressor, as is well known in the art.
  • compression step 61 1 raises the pressure of the feed stream 612 to between about 500 psia and 1 ,500 psia, depending on the type of membrane used. It is possible to use fuel gas generated by the process to power a gas engine to drive the compressor. This provides a cost advantage that is an attractive feature of the process.
  • the cooling step is carried out by any suitable means, for instance by air cooling. If a lower temperature than can be attained by air cooling is desired, the step may be carried out using cooling water, refrigerants and/or heat exchange against other plant streams, for example. Such techniques are well known in the art.
  • An optional phase separation step (not shown) can be used upstream of the membrane separation step 615 if the raw gas stream 610 is a two-phase mixture containing entrained hydrocarbon liquids as mist or droplets, or if a compression step 61 1 and/or cooling step 613 have been used.
  • the optional phase separation step can produce a single liquid phase and gas phase, as will be the case if a simple knock-out drum or two-phase separator is used.
  • a three-phase separator may be used to produce discrete liquid water and natural gas liquid (NGL) streams.
  • the gas phase of the natural gas stream is withdrawn from the phase separation step, if used, and passed to the membrane separation step 615.
  • This step 615 is carried out using a membrane separation unit equipped with a membrane that is selective in favor of carbon dioxide over methane and other hydrocarbons.
  • the membrane material used in this step is preferably a glassy polymer with good carbon dioxide/methane selectivity under conditions of high carbon dioxide partial pressure.
  • Representative membrane materials that can be used for this step include cellulose acetate, other cellulose derivatives, polyimide, and fluorinated dioxoles and dioxolanes.
  • cellulose acetate membranes are still the most widely used membranes in industrial carbon dioxide separation units. They typically provide a carbon dioxide/methane selectivity of about 10 under real operating conditions. Such membranes are available commercially from Kvaerner Process Systems of Houston, Texas, or as Separex Membrane Systems from UOP of Des Plaines, III. As the raw gas has already been treated in cooling/phase separation steps the gas stream supplied to the membrane unit may be sufficiently dry, light and sweet that cellulose acetate membranes may be used.
  • Alternative candidate membranes of this type include those made from different cellulose derivatives, such as ethyl cellulose, methyl cellulose, nitrocellulose, and particularly other cellulose esters.
  • polyimides that exhibit resistance to plasticization or swelling when exposed to high partial pressures of carbon dioxide and C3+ hydrocarbons, in conjunction with good carbon dioxide/methane selectivity and carbon dioxide permeability.
  • certain polyimides based on 6FDA may be used.
  • the polyimide 6FDA-MPDA has a carbon dioxide/methane selectivity of about 50 as measured in C3+ hydrocarbon-free gas mixtures, and may provide a selectivity of about 10 or above under real operating conditions.
  • Polyimide membranes are available commercially from Ube Industries, of Ube City, Japan, or from Medal L P, of Newport, Del., a division of Air Liquide.
  • the most preferred membranes for use in said step are made from glassy polymers characterized by having repeating units of a fluorinated, non- aromatic cyclic structure, the ring having at least five members, and further characterized by a fractional free volume no greater than about 0.3.
  • Preferred polymers in this group are formed from fluorinated monomers of (i) dioxoles that polymerize by opening of the double bond, or (ii) dioxolanes, similar five- member rings but without the double bond in the main ring, or (iii) aliphatic structures having an alkyl ether group, polymerizable into cyclic ether repeat units with five or six members in the ring.
  • the polymers may take the form of homopolymers or copolymers. Such materials are discussed at length in e.g. US 6572680, entitled “Carbon Dioxide Gas Separation Using Organic-Vapor- Resistant Membranes", and in US 6361583.
  • membranes suitable for use in the invention are characterized by a fractional free volume no greater than about 0.3, a glass transition temperature, Tg, of at least about 100[deg.] C, and a fluorine:carbon ratio of at least 1 :1 , but need not necessarily include a cyclic structure.
  • Tg glass transition temperature
  • fluorine:carbon ratio of at least 1 :1
  • Such materials are discussed at length in US 6572680, entitled “Carbon Dioxide Gas Separation Using Organic-Vapor-Resistant Membranes”, and in US 6361582.
  • the most preferred membranes can provide a typical selectivity of 10, 15 or more under real operating conditions. Such selectivity is remarkable, in that it can be achieved even in the presence of significant concentrations of C3+ hydrocarbons and/or carbon dioxide, and at high feed pressure.
  • the membranes used for the membrane separation step may again take any convenient form known in the art.
  • the membranes are asymmetric membranes, having a thin skin that is responsible for the separation properties and an underlying integral micro porous support layer, or composite membranes.
  • the membrane separation unit used in the membrane separation step 615 divides the gas stream into a carbon-dioxide-enriched permeate stream 614 and a carbon-dioxide-depleted, methane-rich residue stream 616.
  • the residue stream is in this text also referred to as a natural gas product stream 616.
  • the natural gas product stream 616 has a carbon dioxide content reduced to a first level relative to the raw natural gas stream 610. If the principal goal of the process is to upgrade raw natural gas to pipeline specification, the natural gas product stream 616 may be the primary product of the process. Preferably, this stream contains no more than about 20 percent carbon dioxide and more preferably no more than 7-12 percent carbon dioxide. To meet pipeline specification, it is most preferable that this stream contains no more than about 2 percent carbon dioxide. This requires a further process step, which will be described in detail below.
  • the natural gas product stream 616 may still contain too much carbon dioxide to pass directly to the pipeline.
  • the natural gas product stream 616 is passed to an amine absorption step 617 for further reducing the carbon dioxide content to a second level relative to the raw natural gas stream 610.
  • the amine absorption step 617 involves supplying the natural gas product stream and a lean absorption medium comprising a liquid diluent and at least one amine to an absorber unit (see Figures 1 -5).
  • the natural gas product stream is passed into cross-flow contact with the lean absorption medium within a rotating absorption zone in the absorber, wherein carbon dioxide is removed from the natural gas product stream by the lean absorption medium when passing through the rotating absorption zone, in order to obtain a sweetened natural gas product 620 having a carbon dioxide content reduced to a second level relative to the raw natural gas stream.
  • a lean amine stream 618 is supplied to the absorber from an amine regeneration unit (not shown).
  • a rich amine stream 619 containing absorbed carbon dioxide is removed from the absorber and is supplied to said amine regeneration unit.
  • the sweetened natural gas product 620 contains no more than about 2-2,4 percent carbon dioxide in order to meet pipeline specification standards.
  • FIG. 1 shows a schematic, partially cross-sectioned absorber for use in a process according to the invention.
  • the absorber in Figure 1 comprises a vessel 101 in the form of a cylindrical outer stator shell containing a first and a second annular absorber packing 102a, 102b rotatable about a longitudinal axis X within the vessel 101 , which absorber packings have a predetermined axial extension with an inner radius r and an outer radius R (see Fig.3).
  • the absorber further comprises an absorbent inlet 103, arranged for supplying lean absorbent to the absorber packing, and absorbent outlets 104a, 104b, arranged for removing rich absorbent on the vessel radially outside the outer perimeter 1 1 1 of the absorber packings at the lower section of the vessel 101 .
  • Lean absorbent is supplied to the vessel 101 from a conduit (not shown) connected to a rotary joint 105 attached to an inlet shaft 106 in the form of a hollow idle shaft comprising a central pipe for transport of lean absorbent through the inlet shaft 106 to a number of radial channels 107a, 107b for transport of lean absorbent to a number of longitudinal distribution tubes 108a, 108b, which distribution tubes adjacent the inner perimeter 1 12 of the absorber packings 102a, 102b is provided with nozzles (not shown) for even distribution of lean absorbent tangentially and axially on the inner perimeter of the absorber packings.
  • the absorber also comprises natural gas inlets 109a, 109b for pressurized natural gas, arranged radially outside an outer perimeter of the absorber packing, and natural gas outlets 1 10, arranged on the vessel radially outside the outer perimeter of the absorber packing.
  • the natural gas outlets 1 10 are arranged axially separated from the natural gas inlets 109a, 109b, and aligned with a radially open section 1 13 separating the absorber packings 102a, 102b.
  • the arrangement in Figure 1 has four natural gas outlets 1 10 arranged in a radial plane through the vessel, which outlets are located equidistant around the circumference of the vessel.
  • the radially open section 1 13 is separated from the natural gas inlets 109a, 109b and the facing end surfaces of the absorber packings 102a, 102b by first and second radial walls 1 14a, 1 14b.
  • Each radial wall 1 14a, 1 14b extends from the inner perimeter of the annular absorber packing to a gas tight labyrinth seal 1 15a, 1 15b at the inner wall of the vessel.
  • a third radial wall 1 14c is located between the first and second radial walls 1 14a, 1 14b and extends from the inlet shaft 106 to the outer perimeter of the absorber packings 102a, 102b.
  • the third radial wall 1 14c is provided to guide the flow of sweet natural gas from the inner perimeter of the absorber packings towards the natural gas outlets 1 10.
  • the opposing end surfaces of the absorber packings 102a, 102b are sealed by a pair of rotor end plates 1 16a, 1 16b to form a an absorber packing assembly or rotor assembly.
  • the rotor end plates 1 16a, 1 16b are each supported inside the vessel by a rotor shaft journalled at each end of the vessel.
  • the rotor assembly is held together by means of multiple axial tension rods 1 17 (one shown) which extend through all the radial walls in the assembly outside the outer perimeter of each absorber packing and are bolted to the rotor end plates and the radial walls 1 14a, 1 14b adjacent the open section 1 13.
  • the vessel 101 comprises a cylindrical outer stator shell having a pair of end domes, wherein each dome is provided with a gas tight seal 1 18a, 1 18b around the respective rotor shaft.
  • the entire absorber assembly located between these rotor shafts is rotated as a unit by a driving torque T applied to a driven rotor shaft 1 19 located on the opposite side of the vessel relative to the absorbent inlet 103.
  • the absorber packing assembly comprises two absorber packings which are symmetrical on either side of a central plane at right angles to the rotational axis of the absorber packing.
  • the central plane is, in this case, taken through a position half way between the facing ends of two absorber packings located end-to-end or with an axial separation along a common axis of rotation.
  • an example of a suitable size for the absorber arrangement is a pair of absorber packings each having an inner diameter of 1 m, an outer diameter of 2,5 m and a length of 2,2 m.
  • a suitable metal foam having a surface area of 2500 m2/m3, theses dimensions give surface area of 223 m3 and a volume of 18 m3 of metal foam.
  • Four natural gas inlets with a diameter of 200-250 mm will give a gas velocity of up to 20 m/s.
  • a lean absorbent inlet with a diameter of 169 mm at the idle rotor shaft will give an absorber velocity of 10 m/s.
  • 1250 kW is required for transport of the lean absorbent alone.
  • the power consumption for the gas will be lower because momentum is exchanged from the lean absorbent.
  • Figure 2 shows a cross-section through a first alternative embodiment of an absorber for use in a process according to the invention.
  • the absorber in Figure 2 differs from that of Figure 1 in that it comprises an absorber provided with means for recuperating energy from the gas flow through the absorber.
  • the recuperating means is placed within the open section 1 13 between the absorber packings 102a, 102b, as shown in Figure 1 , and comprises a radial discharge fan 201 with curved radial vanes, as shown in Figure 2.
  • the radially open section 1 13 is separated from the natural gas inlets (not shown) and the facing end surfaces of the absorber packings 102a, 102b by first and second radial walls 1 14a, 1 14b.
  • a third radial wall 1 14c is located between the first and second radial walls 1 14a, 1 14b and extends from the inlet shaft 106 to the outer perimeter of the absorber packings 102a, 102b.
  • the third radial wall 1 14c is provided to guide the flow of sweet natural gas from the inner perimeter of the absorber packings towards the natural gas outlets (not shown).
  • the radial discharge fan 201 comprises a first and a second set of radial vanes 202a, 202b, wherein the first set of radial vanes 202a is attached between the first radial wall 1 14a and the third radial wall 1 14c. Similarly, the second set of radial vanes 202b is attached between the second radial wall 1 14b and the third radial wall 1 14c.
  • the radial vanes have several functions, such as acting as a mechanical, torque transmitting connection between the two absorber sections, assisting in transport of sweet gas from centre to periphery while recovering some of the momentum to rotational power, and assisting in separating rich absorbent droplets from the sweet natural gas.
  • the latter function requires droplet traps to be integrated in the design, as described for the embodiment according to Figure 1 above.
  • the energy recovery is achieved by guiding sweet natural gas through the radial vanes 202a, 202b in the radially open section 1 13, whereby some of the momentum from the pressurized sweet natural gas flowing towards the outlet is transferred to the vanes of the discharge fan 201 .
  • the recovered momentum causes a driving torque applied to the rotor shaft and assists in rotating the absorber assembly.
  • Figure 3 shows a schematic illustration of the flow patterns of fluids in the rotated absorber assembly in the rotational symmetric radial-axial plane of the units shown in Figures 1 and 2.
  • Absorbent medium is supplied from an inlet a- ⁇ through a central rotor shaft and is distributed on the inner perimeter a 2 of the absorber packing.
  • the lean absorbent is distributed and transported a 3 to the outer perimeter a 4 by the high centrifugal forces (high G) in the rotating absorber assembly.
  • the rich absorbent is then removed via an outlet a 5 for processing and re-use.
  • the sour gas is supplied from inlets A at the outer periphery of the absorber packing and is forced towards the centre of the assembly in the opposite direction A 2 allowing efficient cross flow for mass transfer of C0 2 to the lean absorbent.
  • the sweet gas is guided along the inner perimeter A 3 and then outwards A 4 through an open section from the axial centre of the assembly. This open section can have vanes allowing recovery of kinetic energy from the gas as well as droplet traps to remove absorbent droplets carried over in the gas. Finally, the sweet gas is removed form the assembly through an outlet A 5 .
  • Figure 4 shows a cross-section through a second alternative embodiment of an absorber for use in a process according to the invention.
  • the absorber in Figure 4 differs from that of Figure 2 in that it comprises an absorber provided with means for recuperating energy from the gas flow through the absorber placed within a first and a second open section 413a, 413b at either end of an absorber packing 400.
  • Each open section 413a, 413b comprises a radial discharge fan 401 a, 401 b with curved radial vanes, similar to the arrangement shown in Figure 2.
  • the radially open sections 413a, 413b are separated from the natural gas inlets (not shown) and the opposite end surfaces of the absorber packing 400 by first and second radial walls 414a, 414b.
  • a third radial wall 414c is located in a position equidistant from the first and second radial walls 414a, 414b and extends from the inlet shaft 406 to the inner perimeter 412 of the absorber packing 400.
  • the third radial wall 414c is provided to guide the flow of sweet natural gas from the inner perimeter of the absorber packing towards the natural gas outlets 410a, 410b. This arrangement also ensures that the flow of natural gas is distributed so that each radial discharge fan 401 a, 401 b will receive approximately the same gas flow.
  • the radial discharge fans 401 a, 401 b comprise a first and a second set of radial vanes 402a, 402b, wherein the first set of radial vanes 402a is attached between the first radial wall 416a and a first rotor end plate 412a. Similarly, the second set of radial vanes 402b is attached between the second radial wall 414b and a second rotor end plate 416b, in order to form a an absorber packing assembly or rotor assembly.
  • the rotor assembly is held together by means of multiple axial tension rods 417 (schematically indicated in Fig.4) which extend through all the radial walls in the assembly outside the outer perimeter 41 1 of the absorber packing and are bolted to the rotor end plates.
  • the absorber packing assembly comprises a single absorber packing which is symmetrical on either side of a central plane at right angles to the rotational axis of the absorber packing.
  • the central plane is, in this case, taken through a position located at the mid-point of the single absorber packing along the axis of rotation.
  • the radial vanes have several functions, such as acting as a mechanical, torque transmitting connection between the two absorber sections, assisting in transport of sweet gas from centre to periphery while recovering some of the momentum to rotational power, and assisting in separating rich absorbent droplets from the sweet natural gas.
  • the latter function requires droplet traps to be integrated in the design, as described for the embodiment according to Figure 1 above.
  • the radial walls 414a, 414b extends from the inner perimeter of the annular absorber packing to a gas tight labyrinth seal 415a, 415b at the inner wall of the vessel.
  • the energy recovery is achieved by guiding sweet natural gas through the radial vanes 402a, 402b in the radially open section 413a, 413b, whereby some of the momentum from the pressurized sweet natural gas flowing towards the outlet is transferred to the vanes of the discharge fans 401 a, 401 b.
  • the recovered momentum causes a driving torque applied to the rotor shaft 1 19 and assists in rotating the absorber assembly.
  • FIG 5 shows a schematic illustration of the flow patterns of fluids in the rotated absorber assembly in the rotational symmetric radial-axial plane of the unit shown in Figure 4.
  • Absorbent medium is supplied from an inlet through a central rotor shaft and is distributed on the inner perimeter a 2 of the absorber packing.
  • the lean absorbent is distributed and transported a 3 to the outer perimeter a 4 by the high centrifugal forces (high G) in the rotating absorber assembly.
  • the rich absorbent is then removed via an outlet a 5 for processing and re-use.
  • the sour gas is supplied from inlets A at the outer periphery of the absorber packing and is forced towards the centre of the assembly in the opposite direction A 2 allowing efficient cross flow for mass transfer of C0 2 to the lean absorbent.
  • the sweet gas is guided along the inner perimeter A 3 and then outwards A' 4 from the axial centre of the assembly through open sections at each end of the assembly.
  • the open sections can have vanes allowing recovery of kinetic energy from the gas as well as droplet traps to remove absorbent droplets carried over in the gas. Finally, the sweet gas is removed form the assembly through outlets A' 5 at each end of the assembly.
  • Figure 7 shows a schematic diagram of a process according to a second embodiment of the invention.
  • the second embodiment is substantially the same as the embodiment described in connection with Figure 6, with the difference that a further absorption step 702 for eliminating hydrogen sulphide has been introduced prior to the steps 61 1 , 613, 615, 617 shown in Figure 6.
  • the process according to the second embodiment comprises the further step of supplying a raw natural gas stream 701 comprising , for instance, up to 5 percent hydrogen sulphide and an organic scrubbing agent 704 specific to hydrogen sulphide to a further absorber prior to a separation membrane step 715.
  • a raw natural gas stream 701 comprising , for instance, up to 5 percent hydrogen sulphide and an organic scrubbing agent 704 specific to hydrogen sulphide to a further absorber prior to a separation membrane step 715.
  • Suitable organic scrubbing agents for this purpose have already been discussed in the text of the description.
  • the raw natural gas stream 701 is passed into cross-flow contact with the lean organic scrubbing agent 704 within a rotating absorption zone in the further absorber, wherein the hydrogen sulphide is removed from the raw natural gas stream by the organic scrubbing agent when passing through the rotating absorption zone, in order to obtain a raw natural gas stream 710 free from hydrogen sulphide.
  • the hydrogen sulphide removal process involves supplying the organic scrubbing agent to an inner portion of at least one annular rotating absorber unit within the further absorber, causing the organic scrubbing agent to flow radially outwards through the rotating absorption zone; and supplying the raw natural gas stream to an outer portion of said annular rotating absorber unit, causing the raw natural gas stream to flow radially inwards in order to create a radial cross-flow in the absorption zone.
  • the organic scrubbing agent is supplied to a pair of identical and mirrored annular rotating absorber units rotating about a common axis within the absorber.
  • the absorber units described in connection with Figures 1 -5 above are suitable for this purpose.
  • the raw natural gas stream 710 free from hydrogen sulphide is then directed into a production plant for carrying out the process for removal of carbon dioxide.
  • the raw gas stream 710 is typically at elevated pressure. If it is at insufficiently high pressure to operate the process satisfactorily, the raw gas stream 710 may optionally be compressed, as shown in Figure 7.
  • the raw gas stream 710 then passes into an optional compression step 71 1 .
  • An optional phase separation step (not shown) can be used upstream of the membrane separation step 715 if the raw gas stream 710 is a two-phase mixture containing entrained hydrocarbon liquids as mist or droplets, or if a compression step 71 1 and/or cooling step 713 have been used. This step 715 is carried out using a membrane separation unit equipped with a membrane that is selective in favour of carbon dioxide over methane and other hydrocarbons.
  • the membrane separation unit used in the membrane separation step 715 divides the gas stream into a carbon-dioxide-enriched permeate stream 714 and a carbon-dioxide-depleted, methane-rich residue stream 716.
  • the residue stream is in this text also referred to as a natural gas product stream 716.
  • the natural gas product stream 716 has a carbon dioxide content reduced to a first level relative to the raw natural gas stream 710. If the principal goal of the process is to upgrade raw natural gas to pipeline specification, the natural gas product stream 716 may be the primary product of the process. Preferably, this stream contains no more than about 20 percent carbon dioxide and more preferably no more than 7-12 percent carbon dioxide. To meet pipeline specification, it is most preferable that this stream contains no more than about 2 percent carbon dioxide. This requires a further process step, which has been described in detail above.
  • the natural gas product stream 716 is passed to an amine absorption step 717 for further reducing the carbon dioxide content to a second level relative to the raw natural gas stream 710.
  • the amine absorption step 717 involves supplying the natural gas product stream and a lean absorption medium comprising a liquid diluent and at least one amine to an absorber unit (see Figures 1 -5).
  • the natural gas product stream is passed into cross-flow contact with the lean absorption medium within a rotating absorption zone in the absorber, wherein carbon dioxide is removed from the natural gas product stream by the lean absorption medium when passing through the rotating absorption zone, in order to obtain a sweetened natural gas product 720 having a carbon dioxide content reduced to a second level relative to the raw natural gas stream.
  • a lean amine stream 718 is supplied to the absorber from an amine regeneration unit (not shown).
  • a rich amine stream 719 containing absorbed carbon dioxide is removed from the absorber and is supplied to said amine regeneration unit.
  • the sweetened natural gas product 720 contains no more than about 2-2,4 percent carbon dioxide in order to meet pipeline specification standards.

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

Abstract

La présente invention concerne le traitement du gaz naturel et d'autres flux gazeux contenant du méthane et au moins un gaz acide comme le dioxyde de carbone. Plus particulièrement, la présente invention implique la mise en contact du flux d'alimentation en gaz naturel brut avec une membrane de séparation pour obtenir un flux de produit de gaz naturel riche en méthane et de teneur en dioxyde de carbone réduite jusqu'à un premier niveau par rapport au flux de gaz naturel brut. Ensuite, le flux de produit de gaz naturel passe à travers une zone d'absorption rotative pour obtenir un produit de gaz naturel adouci de teneur en dioxyde de carbone réduite jusqu'à un second niveau par rapport au flux de gaz naturel brut.
PCT/EP2011/050174 2011-01-07 2011-01-07 Procédé d'élimination de gaz acide dans le gaz naturel Ceased WO2012092980A1 (fr)

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Cited By (5)

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US9216377B1 (en) 2015-02-24 2015-12-22 Chevron U.S.A. Inc. Method and system for removing impurities from gas streams using rotating packed beds
US10632417B2 (en) 2018-01-23 2020-04-28 Uop Llc High hydrocarbon recovery membrane plus solvent based system
CN114377562A (zh) * 2022-01-17 2022-04-22 天津众泰材料科技有限公司 一种用于co2/ch4气体分离的混合基质膜及其制备方法
CN114405237A (zh) * 2022-03-02 2022-04-29 深圳市安驰环保科技有限公司 一种联合吸收的二氧化碳捕集与压缩处理系统及工艺
EP4263046A4 (fr) * 2020-12-17 2025-05-07 Granitefuel Engineering Inc. Procédé de régénération de milieu d'adsorption faisant appel à du dioxyde de carbone

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Publication number Priority date Publication date Assignee Title
US9216377B1 (en) 2015-02-24 2015-12-22 Chevron U.S.A. Inc. Method and system for removing impurities from gas streams using rotating packed beds
US10632417B2 (en) 2018-01-23 2020-04-28 Uop Llc High hydrocarbon recovery membrane plus solvent based system
EP4263046A4 (fr) * 2020-12-17 2025-05-07 Granitefuel Engineering Inc. Procédé de régénération de milieu d'adsorption faisant appel à du dioxyde de carbone
CN114377562A (zh) * 2022-01-17 2022-04-22 天津众泰材料科技有限公司 一种用于co2/ch4气体分离的混合基质膜及其制备方法
CN114405237A (zh) * 2022-03-02 2022-04-29 深圳市安驰环保科技有限公司 一种联合吸收的二氧化碳捕集与压缩处理系统及工艺
CN114405237B (zh) * 2022-03-02 2022-12-23 深圳市安驰环保科技有限公司 一种联合吸收的二氧化碳捕集与压缩处理系统及工艺

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