WO1995011738A1 - Sour gas treatment process - Google Patents
Sour gas treatment process Download PDFInfo
- Publication number
- WO1995011738A1 WO1995011738A1 PCT/US1994/012099 US9412099W WO9511738A1 WO 1995011738 A1 WO1995011738 A1 WO 1995011738A1 US 9412099 W US9412099 W US 9412099W WO 9511738 A1 WO9511738 A1 WO 9511738A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- hydrogen sulfide
- carbon dioxide
- membrane
- methane
- die
- Prior art date
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- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 title claims abstract description 384
- 238000000034 method Methods 0.000 title claims abstract description 143
- 230000008569 process Effects 0.000 title claims abstract description 140
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims abstract description 650
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims abstract description 574
- 239000012528 membrane Substances 0.000 claims abstract description 521
- 229910000037 hydrogen sulfide Inorganic materials 0.000 claims abstract description 380
- 229910002092 carbon dioxide Inorganic materials 0.000 claims abstract description 346
- 239000001569 carbon dioxide Substances 0.000 claims abstract description 322
- 239000007789 gas Substances 0.000 claims abstract description 223
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Chemical compound O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 69
- 239000003345 natural gas Substances 0.000 claims abstract description 24
- 239000012466 permeate Substances 0.000 claims description 108
- 239000002131 composite material Substances 0.000 claims description 24
- 229920000642 polymer Polymers 0.000 claims description 12
- 239000004721 Polyphenylene oxide Substances 0.000 claims description 9
- 229920000570 polyether Polymers 0.000 claims description 9
- 229920001400 block copolymer Polymers 0.000 claims description 7
- 239000004952 Polyamide Substances 0.000 claims description 6
- 229920002647 polyamide Polymers 0.000 claims description 6
- 239000000203 mixture Substances 0.000 abstract description 78
- 238000000926 separation method Methods 0.000 abstract description 50
- 229960004424 carbon dioxide Drugs 0.000 description 290
- 230000004907 flux Effects 0.000 description 50
- 229920002301 cellulose acetate Polymers 0.000 description 31
- 238000004364 calculation method Methods 0.000 description 30
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- 230000035699 permeability Effects 0.000 description 16
- 241000196324 Embryophyta Species 0.000 description 15
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- 229910052717 sulfur Inorganic materials 0.000 description 11
- 238000012360 testing method Methods 0.000 description 11
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- 239000002033 PVDF binder Substances 0.000 description 9
- 229920002981 polyvinylidene fluoride Polymers 0.000 description 9
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 8
- 230000002349 favourable effect Effects 0.000 description 8
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- 238000012545 processing Methods 0.000 description 8
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- 241000208202 Linaceae Species 0.000 description 5
- 235000004431 Linum usitatissimum Nutrition 0.000 description 5
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 5
- 230000008901 benefit Effects 0.000 description 5
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- 108010010803 Gelatin Proteins 0.000 description 4
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 4
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- 238000005094 computer simulation Methods 0.000 description 4
- 229920000159 gelatin Polymers 0.000 description 4
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- 229920002379 silicone rubber Polymers 0.000 description 4
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- 239000002202 Polyethylene glycol Substances 0.000 description 3
- 239000004372 Polyvinyl alcohol Substances 0.000 description 3
- UCKMPCXJQFINFW-UHFFFAOYSA-N Sulphide Chemical compound [S-2] UCKMPCXJQFINFW-UHFFFAOYSA-N 0.000 description 3
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- -1 polytetra-fluoroethylene Polymers 0.000 description 3
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- YZCKVEUIGOORGS-OUBTZVSYSA-N Deuterium Chemical compound [2H] YZCKVEUIGOORGS-OUBTZVSYSA-N 0.000 description 2
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 2
- PEDCQBHIVMGVHV-UHFFFAOYSA-N Glycerine Chemical compound OCC(O)CO PEDCQBHIVMGVHV-UHFFFAOYSA-N 0.000 description 2
- 239000004677 Nylon Substances 0.000 description 2
- 229920002292 Nylon 6 Polymers 0.000 description 2
- 239000004695 Polyether sulfone Substances 0.000 description 2
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical compound CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 description 2
- RAHZWNYVWXNFOC-UHFFFAOYSA-N Sulphur dioxide Chemical compound O=S=O RAHZWNYVWXNFOC-UHFFFAOYSA-N 0.000 description 2
- 229920006099 Vestamid® Polymers 0.000 description 2
- XLOMVQKBTHCTTD-UHFFFAOYSA-N Zinc monoxide Chemical compound [Zn]=O XLOMVQKBTHCTTD-UHFFFAOYSA-N 0.000 description 2
- 238000013459 approach Methods 0.000 description 2
- 238000003889 chemical engineering Methods 0.000 description 2
- 238000006243 chemical reaction Methods 0.000 description 2
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- 229910052742 iron Inorganic materials 0.000 description 2
- 238000012423 maintenance Methods 0.000 description 2
- YQCIWBXEVYWRCW-UHFFFAOYSA-N methane;sulfane Chemical compound C.S YQCIWBXEVYWRCW-UHFFFAOYSA-N 0.000 description 2
- 238000002156 mixing Methods 0.000 description 2
- 239000002343 natural gas well Substances 0.000 description 2
- 229920001778 nylon Polymers 0.000 description 2
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- 229920001451 polypropylene glycol Polymers 0.000 description 2
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- 239000007787 solid Substances 0.000 description 2
- 239000002594 sorbent Substances 0.000 description 2
- PVXVWWANJIWJOO-UHFFFAOYSA-N 1-(1,3-benzodioxol-5-yl)-N-ethylpropan-2-amine Chemical compound CCNC(C)CC1=CC=C2OCOC2=C1 PVXVWWANJIWJOO-UHFFFAOYSA-N 0.000 description 1
- VZSRBBMJRBPUNF-UHFFFAOYSA-N 2-(2,3-dihydro-1H-inden-2-ylamino)-N-[3-oxo-3-(2,4,6,7-tetrahydrotriazolo[4,5-c]pyridin-5-yl)propyl]pyrimidine-5-carboxamide Chemical compound C1C(CC2=CC=CC=C12)NC1=NC=C(C=N1)C(=O)NCCC(N1CC2=C(CC1)NN=N2)=O VZSRBBMJRBPUNF-UHFFFAOYSA-N 0.000 description 1
- 102100032373 Coiled-coil domain-containing protein 85B Human genes 0.000 description 1
- RPNUMPOLZDHAAY-UHFFFAOYSA-N Diethylenetriamine Chemical compound NCCNCCN RPNUMPOLZDHAAY-UHFFFAOYSA-N 0.000 description 1
- 239000001856 Ethyl cellulose Substances 0.000 description 1
- ZZSNKZQZMQGXPY-UHFFFAOYSA-N Ethyl cellulose Chemical compound CCOCC1OC(OC)C(OCC)C(OCC)C1OC1C(O)C(O)C(OC)C(CO)O1 ZZSNKZQZMQGXPY-UHFFFAOYSA-N 0.000 description 1
- 229920000544 Gore-Tex Polymers 0.000 description 1
- 101000868814 Homo sapiens Coiled-coil domain-containing protein 85B Proteins 0.000 description 1
- QMMZSJPSPRTHGB-UHFFFAOYSA-N MDEA Natural products CC(C)CCCCC=CCC=CC(O)=O QMMZSJPSPRTHGB-UHFFFAOYSA-N 0.000 description 1
- SECXISVLQFMRJM-UHFFFAOYSA-N N-Methylpyrrolidone Chemical compound CN1CCCC1=O SECXISVLQFMRJM-UHFFFAOYSA-N 0.000 description 1
- 239000000020 Nitrocellulose Substances 0.000 description 1
- 239000005062 Polybutadiene Substances 0.000 description 1
- 239000004743 Polypropylene Substances 0.000 description 1
- ZXQYGBMAQZUVMI-QQDHXZELSA-N [cyano-(3-phenoxyphenyl)methyl] (1r,3r)-3-[(z)-2-chloro-3,3,3-trifluoroprop-1-enyl]-2,2-dimethylcyclopropane-1-carboxylate Chemical compound CC1(C)[C@@H](\C=C(/Cl)C(F)(F)F)[C@H]1C(=O)OC(C#N)C1=CC=CC(OC=2C=CC=CC=2)=C1 ZXQYGBMAQZUVMI-QQDHXZELSA-N 0.000 description 1
- 230000002411 adverse Effects 0.000 description 1
- 125000001931 aliphatic group Chemical group 0.000 description 1
- YVPYQUNUQOZFHG-UHFFFAOYSA-N amidotrizoic acid Chemical compound CC(=O)NC1=C(I)C(NC(C)=O)=C(I)C(C(O)=O)=C1I YVPYQUNUQOZFHG-UHFFFAOYSA-N 0.000 description 1
- 125000003118 aryl group Chemical group 0.000 description 1
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 1
- 230000005587 bubbling Effects 0.000 description 1
- 239000001273 butane Substances 0.000 description 1
- OWQNOTOYTSUHNE-UHFFFAOYSA-N carbon dioxide methane Chemical compound C.C(=O)=O.C OWQNOTOYTSUHNE-UHFFFAOYSA-N 0.000 description 1
- KDRIEERWEFJUSB-UHFFFAOYSA-N carbon dioxide;methane Chemical compound C.O=C=O KDRIEERWEFJUSB-UHFFFAOYSA-N 0.000 description 1
- 239000000969 carrier Substances 0.000 description 1
- 239000001913 cellulose Substances 0.000 description 1
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- 150000004985 diamines Chemical class 0.000 description 1
- LVTYICIALWPMFW-UHFFFAOYSA-N diisopropanolamine Chemical compound CC(O)CNCC(C)O LVTYICIALWPMFW-UHFFFAOYSA-N 0.000 description 1
- 150000002009 diols Chemical class 0.000 description 1
- 230000001614 effect on membrane Effects 0.000 description 1
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- 235000011187 glycerol Nutrition 0.000 description 1
- 239000001257 hydrogen Substances 0.000 description 1
- 150000002431 hydrogen Chemical class 0.000 description 1
- 229910052739 hydrogen Inorganic materials 0.000 description 1
- 230000002209 hydrophobic effect Effects 0.000 description 1
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 description 1
- ZXEKIIBDNHEJCQ-UHFFFAOYSA-N isobutanol Chemical compound CC(C)CO ZXEKIIBDNHEJCQ-UHFFFAOYSA-N 0.000 description 1
- 230000000670 limiting effect Effects 0.000 description 1
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- 229920000609 methyl cellulose Polymers 0.000 description 1
- 239000001923 methylcellulose Substances 0.000 description 1
- IJDNQMDRQITEOD-UHFFFAOYSA-N n-butane Chemical compound CCCC IJDNQMDRQITEOD-UHFFFAOYSA-N 0.000 description 1
- OFBQJSOFQDEBGM-UHFFFAOYSA-N n-pentane Natural products CCCCC OFBQJSOFQDEBGM-UHFFFAOYSA-N 0.000 description 1
- 229920001220 nitrocellulos Polymers 0.000 description 1
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- 229920002857 polybutadiene Polymers 0.000 description 1
- 229920000728 polyester Polymers 0.000 description 1
- 229920001601 polyetherimide Polymers 0.000 description 1
- 239000002861 polymer material Substances 0.000 description 1
- 229920005597 polymer membrane Polymers 0.000 description 1
- 229920001021 polysulfide Polymers 0.000 description 1
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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
- B01D53/225—Multiple stage diffusion
- B01D53/226—Multiple stage diffusion in serial connexion
-
- 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
-
- 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
- B01D53/228—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 characterised by specific membranes
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D69/00—Semi-permeable membranes for separation processes or apparatus characterised by their form, structure or properties; Manufacturing processes specially adapted therefor
- B01D69/02—Semi-permeable membranes for separation processes or apparatus characterised by their form, structure or properties; Manufacturing processes specially adapted therefor characterised by their properties
-
- 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
- B01D71/76—Macromolecular material not specifically provided for in a single one of groups B01D71/08 - B01D71/74
- B01D71/80—Block polymers
-
- 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
Definitions
- the invention relates to processes for removing acid gases from gas streams. More particularly, the invention relates to a membrane process for removing hydrogen sulfide and carbon dioxide from gas streams, such as natural gas.
- Natural gas provides more than one-fifth of all the primaiy energy used in the United States. Much raw gas is "subquality", that is, it exceeds the pipeline specifications in nitrogen, carbon dioxide and/or hydrogen sulfide content.
- the first is the removal of impurities, primarily water, hydrogen sulfide and carbon dioxide; the second is loss of methane during processing. Processes that remove hydrogen sulfide and carbon dioxide may also remove a portion of the methane. Losses of less than about 3% are normally acceptable; losses of 3-10% may be acceptable if offset by other advantages; losses above 10% are normally unacceptable.
- a third aspect is the fate of the impurities once removed. Carbon dioxide can be discharged or reinjected, but hydrogen sulfide, which is toxic even in low concentrations, must be treated. If the waste stream containing hydrogen sulfide can be concentrated sufficiently, it may be passed to a Claus plant for conversion to sulfur. Waste streams containing low concentrations must be disposed of in some other way, such as a redox process of the LO CAT or Stretford type, for example, or, less desirably, flaring.
- Choice of appropriate treatment is, therefore, not straightforward, and depends on the feed gas composition, the size and location of the plant and other variables.
- scavenging or sulfur recovery processes such as Sulfa-Scrub, Sulfa-Check, Chemsweet, Supertron 600, solid iron sponge or solid zinc oxide may be used for low-volume streams containing less than about 100 ppm hydrogen sulfide.
- Sulfa-Scrub Sulfa-Check
- Chemsweet Sulfa-Check
- Chemsweet Sulfa-Check
- Chemsweet Sulfa-Check
- Chemsweet Chemsweet
- Supertron 600 solid iron sponge or solid zinc oxide
- Many scavengers present substantial disposal problems, however. In an increasing number of states, the spent scavenger constitutes toxic waste.
- the combined effect of the sorption and diffusion phenomena determines the selectivity of the membrane.
- the balance between mobility, or diffusion, selectivity and sorption selectivity is different for glassy and rubbery polymers.
- the mobility term is usually dominant, permeability falls with increasing permeant size and small molecules permeate preferentially.
- the sorption term is usually dominant, permeability increases with increasing permeant size and larger molecules permeate preferentially.
- both carbon dioxide (3.3 A) and hydrogen sulfide (3.6 A) have smaller kinetic diameters than methane (3.8 A)
- both carbon dioxide and hydrogen sulfide are more condensable than methane
- both glassy and rubbery membranes are selective for the acid gas components over methane.
- most membrane development work in this area has focused on glassy materials, of which cellulose acetate is the most successful example.
- the report to DOE by Norman Li et al. gives carbon dioxide/methane selectivities in the range 9- 15 for one set of field trials (at 6,000-6,240 kPa (870-905 psi) feed pressure) and 12 for another set (at 1,483 kPa (200 psig) feed pressure) with a highly acid feed gas.
- the best carbon dioxide/methane selectivity is 160, for PAN at a temperature of 30°C and a feed pressure of 448 kPa (65 psia); the best hydrogen sulfide/methane selectivity is 200, for gelatin at the same conditions.
- the permeability is extremely low: for carbon dioxide through PAN, less than 5 x 10 "4 Barrer and for hydrogen sulfide through gelatin, less than 3 x 10" 3 Barrer.
- Patent 4,561,864 also to Klass and Landahl, incorporates in its text some of the data reported in the British patent discussed above.
- the '864 patent also includes a table of calculations for cellulose acetate membranes, showing the relationship between " Figure of Merit", a quantity used to express the purity and methane recovery in the residue stream, as a function of "Flow Rate Factor", a quantity that appears to be somewhat akin to stage-cut.
- separation factors where the separation factor is the sum of the carbon dioxide/methane selectivity and the hydrogen sulfide/methane selectivity
- the figures used in the calculations appear to range from the low end of the combined carbon dioxide and hydrogen sulfide selectivities from mixed gas data to the high end of the combined selectivities calculated from pure gas data.
- the already much-discussed DOE Final Report by N.N. Li et al. contains a section in which separation of polar gases from non-polar gases by means of a mixed-matrix, facilitated transport membrane is discussed.
- the membrane consists of a silicone rubber matrix carrying polyethylene glycol, which is used to facilitate transport of polar gases, such as hydrogen sulfide, over non-polar gases, such as methane.
- polar gases such as hydrogen sulfide
- non-polar gases such as methane
- the membrane was also shown to be physically unstable at feed pressure above about 1,290 kPa (170 psig), which, even if the carbon dioxide/methane selectivity were adequate, would render it unsuitable for handling raw natural gas streams.
- U.S. Patent 4,589,896, to M. Chen et al. exemplifies the type of process that must be adopted to remove carbon dioxide and hydrogen sulfide from methane and other hydrocarbons when working within the performance limitations of cellulose acetate membranes.
- the process is directed at natural gas streams with a high acid gas content, or at streams from enhanced oil recovery (EOR) operations, and consists of a multistage membrane separation, followed by fractionation of the acid gas components and multistage flashing to recover the hydrogen sulfide.
- EOR enhanced oil recovery
- the acid-gas-depleted residue stream is also subjected to further treatment to recover hydrocarbons.
- the raw gas to be treated typically contains as much as 80% or more carbon dioxide, with hydrogen sulfide at the relatively low, few thousands of ppm level.
- the ratio of the carbon dioxide content to the hydrogen sulfide content is high (about 400: 1), the raw gas stream must be passed through a minimum of four membrane stages, arranged in a three-step, two-stage configuration, to achieve good hydrogen sulfide removal.
- the goal is not to bring the raw gas stream to natural gas pipeline specification, but rather to recover relatively pure carbon dioxide, free from hydrogen sulfide, for further use in EOR.
- the target concentration of carbon dioxide in the treated hydrocarbon stream is less than 10%, which would, of course, not meet natural gas pipeline standards.
- the invention provides improved membranes and improved membrane processes for treating gas streams containing hydrogen sulfide, carbon dioxide, water vapor and methane, particularly natural gas streams.
- the processes rely on the availability of two membrane types: one, cellulose acetate, or a material with similar properties, characterized by a mixed gas carbon dioxide/methane selectivity of about 20 and a mixed gas hydrogen sulfide/methane selectivity of about 25; the other an improved membrane with a much higher mixed gas hydrogen sulfide/methane selectivity of at least about 30, 35 or 40 and a mixed gas carbon dioxide/methane selectivity of at least about 12.
- An important aspect of the invention is the availability of membranes with much higher hydrogen sulfide/methane selectivities than cellulose acetate. This provides d e flexibility to choose between the membrane with the higher carbon dioxide/methane selectivity, in treating streams containing little hydrogen sulfide relative to carbon dioxide; the membrane with the higher hydrogen sulfide/methane selectivity, in treating streams containing substantial amounts of hydrogen sulfide relative to carbon dioxide; and a mixed membrane configuration in treating streams in the intermediate category.
- the availability of the two membrane types enables treatment processes balanced in terms of the two membranes, so as to optimize any process attribute accordingly, to be designed.
- Based on the different permeation properties of the two membrane types we have discovered that it is possible, through computer modeling, to define gas composition zones in which a particular treatment process is favored. For example, if it is the primary goal to minimize methane loss in the membrane permeate, it may be better to carry out the treatment using only the more hydrogen-sulfide-selective membrane, only the more carbon- dioxide-selective membrane or a mixture of both, depending on the particular feed gas composition.
- the preferred configuration is to pass the gas stream first through modules containing the one membrane type, then to pass the residue stream from the first bank of modules through a second bank containing membranes of the other type. If the raw gas stream contains significant amounts of water, for example, it is preferable to use the more hydrogen- sulfide-selective membrane first These membranes are not usually damaged by water, and can handle gas streams having very high relative humidities, up to saturation. Furthermore, the membranes are very permeable to water vapor, and so can be used to dehydrate the gas stream before it passes to the second bank of modules.
- the most preferred material for the more carbon-dioxide-selective membrane is cellulose acetate cr its variants.
- the most preferred material for the more hydrogen-sulfide- selective membrane is a polyamide-polyether block copolymer having the general formula
- PA It It _I n O O
- PE is a polyether segment
- n is a positive integer.
- Such polymers are available commercially as Pebax® from Atochem Inc., Glen Rock, New Jersey or as Vestamid® from
- the processes of the invention make use of a one-stage membrane design, if a single membrane type is indicated, and a two-step membrane design, in which the residue from the first step becomes the feed for the second step, if a combination of membrane types is indicated.
- two-stage (or more complicated) membrane configurations in which the permeate from the first stage becomes the feed for the second, may be used. This will both increase the concentration of hydrogen sulfide in the second stage permeate and reduce the methane loss.
- the membrane process may also be combined with one or more non-membrane processes, to provide a treatment scheme that delivers pipeline quality methane, on the one hand, and that concentrates and disposes of the acid-gas-laden waste stream, in an environmentally acceptable manner, on the other.
- the processes of the invention exhibit a number of advantages compared with previously available acid gas treatment technology.
- provision of a membrane with much higher selectivity for hydrogen sulfide over methane makes it possible, for the first time, to apply membrane treatment efficiently to gas streams characterized by relatively high concentrations of hydrogen sulfide.
- the processes are much better at handling gas streams of high relative humidity.
- Thirdly it is sometimes possible to bring a natural gas stream into pipeline specifications for all three of carbon dioxide, hydrogen sulfide and water vapor with a single membrane treatment.
- much greater flexibility to adjust membrane operating and performance parameters is provided by the availability of two types of membranes.
- the process can be optimized for any chosen process attribute by calculating the appropriate membrane mix to use.
- Figure 1 is a diagram showing zones in which particular membranes should be used to separate hydrogen sulfide and carbon dioxide from methane.
- Figure 2 is a basic schematic drawing of a one-stage membrane separation process.
- Figure 3 is a graph showing the effect of water vapor on carbon dioxide flux through cellulose acetate membranes.
- Figure 4 is a graph showing the effects of hydrogen sulfide and water vapor on the performance of cellulose acetate membranes.
- Figure 5 is a basic schematic drawing of a typical two-stage membrane separation process.
- Figure 6 is a basic schematic drawing of a two-step membrane separation process.
- Figure 7 is a basic schematic drawing of a two-step/two-stage membrane separation process.
- Figure 8 is a basic schematic drawing of a two-stage membrane separation process with an auxiliary membrane unit forming a second-stage loop.
- Figure 9 is a diagram showing zones in which particular membranes should be used to separate hydrogen sulfide and carbon dioxide from methane, based on different hydrogen sulfide methane selectivities.
- Figure 10 is a diagram showing zones in which particular membranes should be used to separate hydrogen sulfide and carbon dioxide from methane, based on different carbon dioxide/methane selectivities.
- Figure 11 is a diagram showing zones in which particular membranes should be used to separate hydrogen sulfide and carbon dioxide from methane, for different feed gas pressures.
- intrinsic selectivity means the selectivity of the polymer material itself, calculated as the ratio of the permeabilities of two gases or vapors through a thick film of the material, as measured with pure gas or vapor samples.
- ideal selectivity means the selectivity of a membrane, calculated as the ratio of the permeabilities of two gases or vapors through the membrane, as measured with pure gas or vapor samples.
- mixed gas selectivity and actual selectivity mean the selectivity of a membrane, calculated as the ratio of the permeabilities of two gases or vapors through the membrane, as measured with a gas mixture containing at least the two gases or vapors in question.
- the invention has several aspects.
- the invention concerns processes for treating gas mixtures containing carbon dioxide in certain concentrations, hydrogen sulfide in certain concentrations and methane, to remove the carbon dioxide and hydrogen sulfide.
- the invention concerns optimizing such membrane separation processes in terms of a particular process attribute. This optimizing may be done to minimize the methane loss from the membrane process, to maximize me hydrogen sulfide concentration in the permeate stream, or to provide the best fit between the membrane process and a non-membrane process or processes acting together as a "hybrid" process, for example.
- the invention concerns membranes that maintain high hydrogen sulfide/methane selectivities when challenged with mixed gas streams under high pressures.
- the processes of the invention rely on the availability of two membrane types: one, cellulose acetate, or a material with similar properties, characterized by a mixed gas carbon dioxide/methane selectivity of about 20 and a mixed gas hydrogen sulfide/methane selectivity of about 25; the other a membrane with a much higher mixed gas hydrogen sulfide/methane selectivity of at least about 30, 35 or 40 and a mixed gas carbon dioxide/methane selectivity of at least about 12.
- the invention provides three forms of basic membrane treatment process: 1. Using only the more hydrogen-sulfide-selective membrane
- Loss of methane is usually one of the most important factors in natural gas processing.
- pipeline grade methane is the desired product, and substantial losses of product have a substantial adverse effect on the process economics.
- large quantities of methane in the acid gas stream make further handling and recovery of any useful products from this stream much more difficult.
- a successful natural gas treatment process should keep methane losses during processing to no more than about 10%, and preferably no more than about 5%.
- FIG. 1 shows a typical zone diagram, with feed gas carbon dioxide concentration on one axis and hydrogen sulfide concentration on the other.
- the diagram was prepared by running a series of membrane separation computer simulations for hypothetical three-component (methane, carbon dioxide, hydrogen sulfide) gas streams of particular flow rates and compositions. In all cases, the target was to bring the stream to a pipeline specification of 4 ppm hydrogen sulfide and 2% carbon dioxide.
- the membrane properties were assumed to be as follows:
- Hydrogen sulfide/methane selectivity 25 Methane flux: 7.5 x 10"* cm 3 (STP)/cm 2 -s-cmHg More H-S-selective membrane: Carbon dioxide/methane selectivity: 13 Hydrogen sulfide/methane selectivity: 50
- zone A no treatment is required, because the gas already contains less than 2% carbon dioxide and less than 4 ppm hydrogen sulfide.
- zone B methane loss is minimized if the more hydrogen-sulfide-selective membrane alone is used.
- zone C methane loss is minimized if the more carbon-dioxide-selective membrane alone is used.
- zone D methane loss is minimized by using a combination of the two membrane types.
- Zones 9 and 10 show the change in the B/D boundary for hydrogen sulfide/methane selectivities of 30, 40 and 50 and for carbon dioxide/methane selectivities of 10, 13 and 15.
- the zone diagram may be used directly to determine the best type of membrane to use for a specific separation by reading off the zone into which the feed composition fits.
- the feed gas to the membrane system contains less than about 3% carbon dioxide to less than about 10% carbon dioxide and more than about 10 ppm hydrogen sulfide to more than about 300 ppm hydrogen sulfide, with the lower end of the carbon dioxide range corresponding to the lower end of the hydrogen sulfide range ( ⁇ 3% carbon dioxide; >10 ppm hydrogen sulfide) and the upper end of the carbon dioxide range ⁇ -responding to the upper end of the hydrogen sulfide range ( ⁇ 10% carbon dioxide; >300 ppm hydrogen sulfide), then the most favorable process, in terms of minimizing methane loss, is carried out using the more hydrogen-sulfide-selective membrane only.
- the feed gas contains less than about 10% carbon dioxide to less than about 20% carbon dioxide and more than about 300 ppm hydrogen sulfide to more than about 600 ppm hydrogen sulfide, with the lower end of the carbon dioxide range corresponding to the lower end of the hydrogen sulfide range ( ⁇ 10% carbon dioxide; >300 ppm hydrogen sulfide) and the upper end of the carbon dioxide range corresponding to the upper end of die hydrogen sulfide range ( ⁇ 20% carbon dioxide; >600 ppm hydrogen sulfide), then the most favorable process, in terms of minimizing methane loss, is carried out using the more hydrogen-sulfide-selective membrane only.
- the feed gas contains less than about 20% carbon dioxide to less than about 40% carbon dioxide and more than about 600 ppm hydrogen sulfide to more than about 1% hydrogen sulfide, with the lower end of the carbon dioxide range corresponding to the lower end of the hydrogen sulfide range ( ⁇ 20% carbon dioxide; >600 ppm hydrogen sulfide) and the upper end of the carbon dioxide range corresponding to the upper end of the hydrogen sulfide range ( ⁇ 40% carbon dioxide; >1% hydrogen sulfide), then the most favorable process, in terms of minimizing methane loss, is carried out using the more hydrogen- sulfide-selective membrane only.
- the feed gas contains less than about 5 ppm hydrogen sulfide to less than about 50 ppm hydrogen sulfide and more than about 3% carbon dioxide to more than about 15% carbon dioxide, with the lower end of the carbon dioxide range corresponding to the lower end of the hydrogen sulfide range ( ⁇ 5 ppm hydrogen sulfide; >3% carbon dioxide) and the upper end of d e carbon dioxide range corresponding to the upper end of die hydrogen sulfide range ( ⁇ 50 ppm hydrogen sulfide; >15% carbon dioxide), then the most favorable process, in terms of minimizing methane loss, is carried out using the more carbon-dioxide-selective membrane only.
- the feed gas contains less than about 50 ppm hydrogen sulfide to less than about 250 ppm hydrogen sulfide and more than about 15% carbon dioxide to more than about 50% carbon dioxide, with the lower end of d e carbon dioxide range corresponding to the lower end of the hydrogen sulfide range ( ⁇ 50 ppm hydrogen sulfide; >15% carbon dioxide) and the upper end of the carbon dioxide range ⁇ MTesponding to the upper end of the hydrogen sulfide range ( ⁇ 250 ppm hydrogen sulfide; >50% carbon dioxide), then the most favorable process, in terms of minimizing methane loss, is carried out using die more carbon-dioxide-selective membrane only.
- the feed gas contains less than about 250 ppm hydrogen sulfide to less than about 500 ppm hydrogen sulfide and more than about 50% carbon dioxide to more than about 85% carbon dioxide, with die lower end of die carbon dioxide range corresponding to die lower end of the hydrogen sulfide range ( ⁇ 250 ppm hydrogen sulfide; >50% carbon dioxide) and die upper end of die carbon dioxide range corresponding to die upper end of die hydrogen sulfide range ( ⁇ 500 ppm hydrogen sulfide; >85% carbon dioxide), dien the most favorable process, in terms of --linimiz-ng methane loss, is carried out using the more carbon-dioxide-selective membrane only.
- die most favorable process in terms of minimizing methane loss, is carried out using a combination of the more hydrogen- sulfide-selective and die more carbon-dioxide-selective membranes.
- die carbon dioxide content of the stream is 10% and die hydrogen sulfide content is 1,000 ppm, die more hydrogen-sulfide-selective membrane only should be used.
- die carbon dioxide content of die stream is 10% and die hydrogen sulfide content is 20 ppm, the more carbon-dioxide-selective membrane only should be used.
- die carbon dioxide content of die stream is about 50-60% or more, die more hydrogen-sulfide- selective membrane should not be used alone, no matter how high the hydrogen sulfide content.
- Anodier way to express the teachings of die invention is simply to define single limits for the carbon dioxide and hydrogen sulfide concentrations that are best treated by different types of membrane.
- the carbon dioxide content of the stream is less than about 40% and die hydrogen sulfide content is more than about 6,000 ppm (1%), the more hydrogen-sulfide-selective membrane should be used.
- die carbon dioxide content of the stream is less than about 20% and die hydrogen sulfide content is more than about 500 ppm, the more hydrogen-sulfide-selective membrane should be used.
- the hydrogen sulfide content of the stream is less than about 25 ppm and die carbon dioxide content is more than about 10%, the more carbon-dioxide-selective membrane only should be used. 5. If the hydrogen sulfide content of the stream is less than about 100 ppm and die carbon dioxide content is more tiian about 15%, the more carbon-dioxide-selective membrane only should be used.
- carbon dioxide content of die stream is in the range about 5-20% carbon dioxide and die hydrogen sulfide content is in the range 10-1,000 ppm, a combination membrane system may be used.
- die carbon dioxide content of die stream is in the range about 10-25% carbon dioxide and die hydrogen sulfide content is in die range 50-5,000 ppm, a combination membrane system may be used.
- a combination membrane system may be used.
- a combination membrane system may be used. If a combination of die two membrane types is to be used, die simplest configuration is to pass die gas stream first through modules containing the one membrane type, then to pass the residue stream from the first bank of modules dirough a second bank containing membranes of the otiier type. The order in which the membrane types are encountered by die gas stream can be chosen according to die specifics of die application.
- die raw gas stream contains significant amounts of water and hydrogen sulfide, for example, it is preferable to use the more hydrogen-sulfide-selective membrane first, since cellulose acetate membranes have been shown to lose botii selectivity and permeability substantially if exposed to combinations of water vapor and hydrogen sulfide. They also do not witiistand relative humidities above about 30% very well.
- the polyamide-polyether block copolymer membranes tiiat are preferred as die more hydrogen-sulfide-selective membrane, on the odier hand, are not usually damaged by water or hydrogen sulfide, and can handle gas streams having high relative humidities, such as above 30% RH, above 90% RH and even saturation.
- the membranes are very permeable to water vapor, and so can be used to dehydrate the gas stream before it passes to the second bank of modules. If humidity and hydrogen sulfide content are not issues, and no other factors that affect only one of the membrane types are at work, then the total methane loss into the permeate streams and die total membrane area required to perform the separation should be essentially independent of die order in which the membranes are positioned.
- any membranes that can achieve the necessary carbon dioxide/methane selectivity and hydrogen sulfide/mediane selectivity, plus commercially useful transmembrane fluxes can be used.
- the membranes should be characterized by transmembrane methane fluxes of at least 1 x 10" 6 cm 3 (STP)/cm 'S'cmHg, most .preferably by transmembrane methane fluxes of at least 1 x 10- 5 cm 3 (STP)/cm 2 -s-cmHg.
- die preferred membranes are die cellulose acetate membranes that are already in use.
- Other candidates include different cellulose derivatives, such as ethylcellulose, methylcellulose, nitrocellulose and particularly other cellulose esters.
- membranes might be made from polysulfone, polyethersulfone, polyamides, polyimides, polyetherimides, polyacrylonitrile, polyvinylalcohol, other glassy materials or any other appropriate material.
- glassy materials have enough mechanical strength to be formed as integral asymmetric membranes, the production of which is well known in the art.
- the invention is not intended to be limited to any particular membrane material or membrane type, however, and encompasses any membrane, of any material, that is capable of meeting the target permeation properties, including, for example, homogeneous membranes, composite membranes, and membranes incorporating sorbents, carriers or plasticizers.
- the most preferred membranes have hydrophilic, polar elastomeric selective layers.
- the mobility selectivity of such materials although it favors hydrogen sulfide and carbon dioxide over metiiane, is modest compared to glassy materials.
- d e membrane is hydrophilic and polar, however, the sorption selectivity strongly favors hydrogen sulfide, carbon dioxide and water vapor over non-polar hydrophobic gases such as hydrogen, metiiane, propane, butane, etc.
- Preferred membrane materials exhibit water sorption greater than 5%, more preferably greater than 10%, when exposed to liquid water at room temperature.
- Particularly preferred are segmented or block copolymers mat form two-domain structures, one domain being a soft, rubbery, hydrophilic region, die otiier being harder and glassy or more glassy. Witiiout wishing to be bound by any particular ti eory of gas transport, we believe that die soft, rubbery domains provide a preferential pathway for the hydrogen sulfide and carbon dioxide components; die harder domains provide mechanical strength and prevent excessive swelling, and hence loss of selectivity, of die soft domains.
- Polyether blocks are preferred for forming the soft flexible domains; most preferably tiiese blocks incorporate polyethylene glycol, polytetramediylene glycol or polypropylene glycol, to increase die sorption of polar molecules by the membrane material.
- PA is a polyamide segment
- PE is a polyether segment
- n is a positive integer.
- Such polymers are available commercially as Pebax® from Atochem Inc., Glen Rock, New Jersey or as Vestamid® from
- the polyamide block gives strength and is believed to prevent the membrane swelling excessively in the presence of water vapor and/or carbon dioxide.
- polyether- and polyester-based polyurethanes include polyether- and polyester-based polyurethanes.
- Representative polymer formulations and recipes are given, for example, in U.S. Patent 5,096,592, in which the copolymers are made by first preparing a prepolymer by combining simple diols and aliphatic or aromatic dicarboxylic acids with an excess of diacid to prepare diacid-terminated blocks, then chain-extending these with appropriately selected polypropylene or polyethylene glycol segments.
- rubbery materials do not have enough mechanical strength to be formed as integral asymmetric membranes, but are instead incorporated into composite membranes, in which the rubbery selective layer is supported on a microporous substrate, often made from a glassy polymer.
- the preparation of composite membranes is also well known in the art. It is commonly thought that rubbery composite membranes do not widistand high-pressure operation well, and to date, such membranes have not been generally used in natural gas treatment, where feed gas pressures are often as high as 3,551 kPa (500 psig) or 7,000 kPa (1,000 psig).
- tiiat composite membranes with thin enough rubbery selective layers to provide a transmembrane methane flux of at least 1 x 10" 6 cm 3 (STP)/cm 2 -s-cmHg, can be used satisfactorily at high feed pressures and not only maintain their integrity but continue to exhibity high selectivity for hydrogen sulfide over metiiane.
- die processes of the invention make use of a one-stage membrane design if a single membrane type is indicated, and a two-step membrane design, in which the residue from die first step becomes the feed for die second step, if a combination of membrane types is indicated.
- a two-stage (or more complicated) membrane configuration in which the permeate from d e first stage becomes die feed for the second, may be used to further enrich the acid gas content of die permeate stream and to reduce methane losses.
- die residue stream from the second stage may be recirculated for further treatment in the first stage, or may be passed to die gas pipeline, for example.
- the residue stream may also be subjected to further membrane treatment.
- Both permeate and residue streams may be subjected to additional non-membrane treatment, such as in an amine plant, to bring it the residue stream to pipeline specification, for example.
- additional non-membrane treatment such as in an amine plant
- tiiat die membrane separation process will often form part of a hybrid treatment scheme that delivers pipeline quality metiiane, on die one hand, and that concentrates and disposes of die acid-gas-laden waste stream, in an environmentally acceptable manner, on the otiier.
- die target pipeline specification for the treated gas was assumed to be no more an about 2 vol% carbon dioxide and 4 ppm hydrogen sulfide, which is typical pipeline specification. However, depending on die destination of die gas and specific standards to which the gas is subject, it is believed that a carbon dioxide content below about 3 vol% and a hydrogen sulfide content below about 20 ppm will be acceptable in many situations.
- the processes of the invention exhibit a number of advantages compared witii previously available acid gas treatment technology.
- provision of a membrane witii much higher selectivity for hydrogen sulfide over metiiane makes it possible, for the first time, to apply membrane treatment efficiendy to gas streams c-r-aracterized by relatively high concentrations of hydrogen sulfide compared to carbon dioxide.
- This expands the range of utility of membrane separation substantially. Since membrane systems are light, simple and low-maintenance compared witii amine plants, the enhanced ability to use membranes as a treatment option facilitates the exploitation of gas fields off-shore or in remote locations.
- Examples 1-10 are comparative examples that illustrate the performance of various glassy and rubbery polymers exposed to acid gases under a variety of conditions.
- a three-layer composite membrane was prepared, using a microporous polyvinylidene fluoride (PVDF) support layer.
- the support was first coated witii a thin, high-flux, sealing layer, then witii a selective layer of polyimide (Matrimid Grade 5218, Ciba-Geigy, Hawthorne, NY).
- Membrane stamps were mounted in a test cell and die permeation properties of the membrane were tested witii pure carbon dioxide and with pure methane at a feed pressure of 448 kPa (50 psig). The results are listed in Table 1.
- a three-layer composite membrane was prepared, using a microporous polyvinylidene fluoride (PVDF) support layer.
- the support was first coated witii a thin, high-flux, sealing layer, then with a selective layer of polyimide (custom-made 6FDA-IPDA).
- Membrane stamps were mounted in a test cell and the permeation properties of die membrane were tested witii pure carbon dioxide and witii pure metiiane at a feed pressure of 448 kPa (50 psig). The results are listed in Table 1.
- Polyimide membranes of two grades (a) Three-layer composite membranes as in Example 1 (a) were tested witii a gas mixture consisting of 800 ppm hydrogen sulfide, 4 vol% carbon dioxide, die balance metiiane. The feed pressure was2,793 kPa ( 390 psig). The results are listed in Table 1. (b) Three-layer composite membranes as in Example 1(b) were tested witii a gas mixture consisting of 800 ppm hydrogen sulfide, 4 vol% carbon dioxide, die balance methane. Two feed pressures, 2,807 kPa (392 psig) and 4,890 kPa (694 psig), were used. The results are listed in Table 1. Example 3. Pure gas measurements. PTMSP membrane
- a composite membrane was prepared by coating a polytrimethyl-silylpropyne (PTMSP) layer onto a polyvinylidene fluoride (PVDF) support membrane.
- PVDF polyvinylidene fluoride
- Membrane stamps were mounted in a test cell and the permeation properties of the membrane were tested with pure carbon dioxide and witii pure methane at a feed pressure of 448 kPa (50 psig). The results are listed in Table 1.
- a composite membrane was prepared by coating a silicone rubber layer onto a microporous support membrane.
- Membrane stamps were mounted in a test cell and die permeation properties of the membrane were tested witii pure carbon dioxide and with pure methane at a feed pressure of 448 kPa (50 psig). The results are listed in Table 1.
- a composite membrane was prepared by coating a polybutadiene (Scientific Polymer Products, Ontario, NY) layer onto a PVDF support membrane.
- Membrane stamps were mounted in a test cell and die permeation properties of die membrane were tested witii pure carbon dioxide and witii pure methane at a feed pressure of 50 psig. The results are listed in Table 1.
- Example 8 Mixed gas measurements. Polvbutadiene membrane
- Li et al. examined d e effect of water vapor in a feed gas stream of carbon dioxide on transmembrane flux.
- Examples 11 and 12 show the performance of polyamide-polyetiier membranes exposed to pure gases. These examples are from earlier work at Membrane Technology and Research, as already reported in U.S. Patent 4,963, 165, since we were not able to make measurements with pure hydrogen sulfide.
- Example 1 Polvamide-polvether membranes. Pure gas data
- a multilayer composite membrane was prepared by coating a polysulfone support membrane first with a thin high-flux, sealing layer, then with a 1 wt% solution of Pebax grade 4011 in i-butanol.
- the membrane was tested witii pure gases at a temperature of 20°C and a feed pressure of 448 kPa (50 psig). The results are shown in Table 2.
- Examples 13-18 show the performance of polyamide-polyetiier membranes exposed to gas mixtures under a variety of conditions.
- a composite membrane was prepared by coating a layer of a polyamide-polyether copolymer (Pebax grade 4011) onto a polyvinylidene fluoride (PVDF) support membrane using die same general techniques as in Example 11.
- the membrane was tested witii a two-component gas mixture containing 4 vol% carbon dioxide, 96 vol% methane at three different feed pressures: 2,809 kPa (392 psig), 4,166 kPa (589 psig) and 6,724 kPa (960 psig).
- the permeate side of die membrane was at, or close to, atmospheric pressure and die membrane was at room temperature (23 °C).
- the permeation results are listed in Table 3.
- Example 15 The same type of membrane as in Example 13 was prepared and tested with a two-component gas mixture consisting of 970 ppm hydrogen sulfide, 99.9 vol% metiiane at three different feed pressures: 2,779 kPa (388 psig), 4,159 kPa (588 psig) and 6,793 kPa (970 psig). In all cases the permeate side of the membrane was at, or close to, atmospheric pressure and the membrane was at room temperature (23 °C). The permeation results are listed in Table 3.
- Example 15 The permeation results are listed in Table 3.
- Example 13 The same type of membrane as in Example 13 was prepared and tested with a three-component gas mixture consisting of 870 ppm hydrogen sulfide, 4.12 vol% carbon dioxide and 95.79 vol% metiiane at three different feed pressures: 2,776 kPa (386 psig), 4,166 kPa (589 psig) and 6,821 kPa (974 psig). In all cases die permeate side of the membrane was at, or close to, atmospheric pressure and die membrane was at room temperature (23 °C). The permeation results are listed in Table 3.
- Example 16 The same type of membrane as in Example 13 was prepared and tested with a three-component gas mixture consisting of 0.986 vol% hydrogen sulfide, 4.12 vol% carbon dioxide and 94.90 vol% methane at three different feed pressures: 2,786 kPa (389 psig), 4,145 kPa (586 psig) and 6,800 kPa (971 psig). In all cases the permeate side of die membrane was at, or close to, atmospheric pressure and die membrane was at room temperature (23 °C). The permeation results are listed in Table 3.
- Example 17 The permeation results are listed in Table 3.
- Example 18 The same type of membrane as in Example 13 was prepared and tested witii a three-component gas mixture consisting of 1.83 vol% hydrogen sulfide, 10.8 vol% carbon dioxide and 87.34 vol% methane at a feed pressure of 6,759 kPa (965 psig). The permeate side of die membrane was at, or close to, atmospheric pressure and d e membrane was at room temperature (23 °C). The permeation results are listed in Table 3.
- Example 18 The permeation results are listed in Table 3.
- Example 13 The same type of membrane as in Example 13 was prepared and tested witii a three-component gas mixture consisting of 950 ppm hydrogen sulfide, 8.14 vol% carbon dioxide and 91.77 vol% methane at three different feed pressures: 2,800 kPa (391 psig), 4,138 kPa (585 psig) and 6,793 kPa (970 psig).
- the increased flax may be due to swelling of the membrane by dissolved carbon dioxide.
- the pressure-normalized flaxes of hydrogen sulfide and carbon dioxide decrease witii increasing feed pressure, whereas those of methane increase.
- the decrease in the hydrogen sulfide and carbon dioxide fluxes may be due to competitive sorption, which results in a lower solubility coefficient (the ratio of concentration in die polymer to partial pressure) for each component.
- the polymer swells, resulting in a higher diffusivity for all components, including metiiane.
- the net result is an increase in the methane flux and a decrease in die fluxes of the acid gases (hydrogen sulfide and carbon dioxide).
- the hydrogen sulfide/methane selectivity for three-component mixtures varies from a low of
- Example 15 The experiments of Example 15 were repeated using feed gas streams saturated with water vapor by bubbling the feed gas through a water reservoir. The experiments were carried out at feed pressures of 2,772 kPa (387 psig), 4,159 kPa (588 psig) and 6,793 (970 psig). The permeate side of the membrane was at, or close to, atmospheric pressure and the membrane was at room temperature (23 °C). The permeation results are listed in Table 4.
- Examples 20-25 show typical computer calculations used to prepare a zone diagram. These calculations, and others of the same type, were used to prepare the zone diagram of Figure 1 , which shows feed gas carbon dioxide concentration on one axis and hydrogen sulfide concentration on the other.
- the diagram was prepared by running a series of membrane separation computer simulations for hypothetical three-component (methane, carbon dioxide, hydrogen sulfide) gas streams of particular flow rates and compositions at a feed pressure of 6,897 kPa (1,000 psia). In all cases, the target was to bring the stream to a pipeline specification of 4 ppm hydrogen sulfide and 2% carbon dioxide.
- the membrane properties were assumed to be as follows: More CO ? -selective membrane:
- Carbon dioxide/methane selectivity 20 Hydrogen sulfide/methane selectivity: 25 Methane flux: 7.5 x 10" 6 cm 3 (STP)/cm -s-cmHg
- the metiiane loss into the permeate stream that would occur if a one-stage membrane separation process were to be carried out was calculated, and was used to define zones of least methane loss.
- Example 20 A computer calculation was carried out for a feed stream of composition 200 ppm hydrogen sulfide, 15 vol% carbon dioxide, die remainder methane. Four simulations were performed: (i) using only the more hydrogen-sulfide-selective membrane (membrane A), (ii) using only the more carbon-dioxide- selective membrane (membrane B), (iii) using a combination of the more hydrogen-sulfide-selective membrane followed by die more carbon-dioxide-selective membrane (A +B), and (iv) using a combination of the more carbon-dioxide-selective membrane followed by the more hydrogen-sulfide-selective membrane (B + A). The results are listed in Table 5. TABLE 5
- Example 20 A computer calculation was performed as in Example 20, using a feed stream of composition 70 ppm hydrogen sulfide, 10 vol% carbon dioxide, the remainder metiiane. The results are listed in Table 6.
- Example 23 The calculations of Example 23 were repeated to show the effect of higher or lower selectivity on the zone boundaries. Representative calculations were performed assuming a hydrogen sulfide/methane selectivity of the more hydrogen-sulfide-selective membrane of 30, 40 or 50, and a carbon dioxide/methane selectivity of d e more hydrogen-sulfide-selective membrane of 10, 13 or 15. The results are plotted graphically in Figures 9 and 10. As can be seen, the Zone B/D boundary moves to die right as the ability of the membrane to separate carbon dioxide improves. Likewise, the boundary moves to the right as the selectivity for hydrogen sulfide over methane decreases. Although the area where the more hydrogen-sulfide-selective membranes should be used is larger at lower hydrogen sulfide/methane selectivity, the methane losses encountered in using the membrane will be greater.
- Example 23 The calculations of Example 23 were repeated assuming different values for the feed pressure. Representative calculations were performed assuming a feed pressure of 5,517, 6,897, or 8,276 kPa (800, 1,000 or 1,200 psia). The results are plotted graphically in Figure 11. As can be seen, the zone boundary is relatively insensitive to changes in the feed pressure. SET 4
- Examples 26-29 show representative processes using the more hydrogen-sulfide-selective membrane only.
- Methane flux 1 x 10- 6 cm 3 (STP)/cm 2 -s-cmHg
- compositions and flow rates of the permeate and residue streams were calculated and are given in Table 7.
- the membrane area used to perform such a separation was calculated to be about 70 m 2 .
- the stage cut was just under 10% and d e methane loss into die permeate was 7.5%.
- the process produces a residue stream tiiat simultaneously meets pipeline specification for carbon dioxide, hydrogen sulfide and water vapor.
- the low grade permeate gas could be sent to the foul gas line.
- Example 26 The simple design of Example 26 is only possible for certain cases where die raw stream to be treated contains an appropriate balance of hydrogen sulfide and carbon dioxide. In many cases, a more complicated, optimized design is needed to improve the methane recovery and meet pipeline specifications without overprocessing.
- a process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 1,000 ppm hydrogen sulfide, 0.1 vol% water vapor and the remainder metiiane, so as to keep methane loss in the permeate stream below 2%.
- the process uses a two-stage membrane separation system in which the permeate from the first bank of membrane modules becomes die feed for the second bank.
- a basic schematic of the process is shown in Figure 5, where numeral 10 indicates die first stage bank of membrane modules and numeral 18 indicates die second stage bank of membrane modules.
- the incoming gas stream 9 is at 6,897 kPa (1,000 psia) and is mixed witii the residue stream 20 from the second stage to form the feed gas stream 21 to the first membrane stage.
- the permeate stream 12 from the first stage is recompressed to 6,897 kPa (1,000 psia) in compressor 13.
- the compressed stream 14 passes to chiller 15, where water vapor is condensed and water is removed as liquid stream 16.
- the non-condensed stream 17 enters the second membrane stage 18, where further separation of hydrogen sulfide takes place.
- the residue stream from this stage is recirculated within the process. Both membrane stages were assumed to use more hydrogen-sulfide-selective membranes having the following characteristics:
- compositions and flow rates of the first and second stage permeate and residue streams were calculated and are given in Table 8.
- the membrane area used to perform such a separation was calculated to be about 280 m 2 total, 265 m 2 in the first stage and 15 m 2 in the second stage.
- the residue stream 11 from the first stage meets pipeline specifications.
- the permeate stream 19 from the second stage contains a high enough concentration of hydrogen sulfide to be passed to a Claus plant for sulfur recovery unit, or to a liquid redox process, such as LO-CAT, Sulferox, Hyperion or Stretford.
- the overall methane loss into the second stage permeate is very low, at just about 1%.
- a process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 1,000 ppm hydrogen sulfide, 4 vol% carbon dioxide and the remainder metiiane.
- the process uses a two-stage membrane separation system in which the permeate from the first bank of membrane modules becomes die feed for the second bank.
- the process schematic is as shown in Figure 5, except that no condenser 15 is used.
- Numeral 10 indicates die first stage bank of membrane modules and numeral 18 indicates die second stage bank of membrane modules.
- the incoming gas stream 9 is at 6,897 kPa (1,000 psia) and is mixed with the residue stream 20 from the second stage to form the feed gas stream 21 to the first membrane stage.
- the permeate stream 12 from the first stage is recompressed to 6,897 kPa (1,000 psia) in compressor 13, then passed without any condensation taking place as compressed stream 17 to the second membrane stage 18, where further separation of hydrogen sulfide takes place.
- the residue stream from this stage is recirculated within the process.
- Both membrane stages were assumed to use more hydrogen-sulfide-selective membranes having the following characteristics: Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/methane selectivity: 13
- Methane flux 7.5 x 10 ⁇ cm 3 (STP)/cm 2 -s-cmHg
- compositions of the first and second stage permeate and residue streams were calculated and are given in Table 9.
- the membrane area used to perform such a separation was calculated to be about 244 m 2 total, 232 m 2 in die first stage and 12 m 2 in the second stage.
- the residue stream 11 from the first stage meets pipeline specifications.
- the permeate stream 19 from the second stage contains a high enough concentration of hydrogen sulfide to be passed to a Claus plant for sulfur recovery unit, or to a liquid redox process, such as LO-CAT, Sulferox, Hyperion or Stretford.
- the overall methane loss into the second stage permeate is very low, at about 0.7%.
- Example 28 The calculations of Example 28 were repeated with a 28.3 NmVmin (1,000 scfm) gas stream containing 10,000 ppm hydrogen sulfide, 4 vol% carbon dioxide and the remainder methane. The results are given in Table 10. TABLE 10
- the membrane area used to perform such a separation was calculated to be about 353 m 2 total, 339 m 2 in the first stage and 14 m 2 in the second stage.
- the residue stream 11 from the first stage meets pipeline specifications.
- the permeate stream 19 from the second stage contains a very high hydrogen sulfide concentration. The methane loss is less than 1%.
- Examples 27-29 illustrate the benefits of two-stage processes in both reducing methane loss and raising the hydrogen sulfide concentration of the waste stream.
- the feed composition, both raw and after mixing witii recycle stream 20, is in zone B.
- Example 30
- a process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 1,000 ppm hydrogen sulfide, the remainder methane.
- the process uses a membrane separation system as shown in Figure 8.
- Numerals 38, 44 and 47 indicate the three banks of membrane modules: all contain the more hydrogen-sulfide-selective membrane.
- the incoming gas stream 36 is at 6,897 kPa (1,000 psia) and is mixed with the residue stream 49 from module(s) 47 to form the feed gas stream 37 to the first membrane stage.
- the permeate stream, 40, from the first stage is recompressed in compressor 42.
- Compressor 42 drives two membrane units, die second stage unit, 44, and an auxiliary module or set of modules, 47, that are connected on die permeate side either directly or indirectly to the inlet side of the compressor, so as to form a loop.
- permeate stream 48 may be merged with permeate stream 40 to form combined stream 41.
- the recompressed, combined stream, 43 passes as feed to membrane unit 44, and the residue stream, 46, from membrane unit 44 passes as feed to membrane unit 47.
- Permeate is withdrawn from the loop as stream 45 and the treated residue exits as stream 39.
- This system configuration is particularly useful in situations where the hydrogen sulfide content of the raw stream is relatively low, yet flaring is not an option and the stream has to be brought up to a viable concentration for sulfur recovery.
- a series of calculations was carried out by keeping the area of membrane unit 38 constant, but varying the relative areas of membrane units 44 and 47. The characteristics of the membrane were assumed to be as in Example 28. The results of the calculations are given in Table 11.
- the residue stream 39 from die first stage meets pipeline specifications.
- a high concentration of hydrogen sulfide in the waste permeate stream can be achieved with an appropriate choice of membrane areas.
- Examples 31-34 deal witii streams in which the feed composition is in zone D, so that a combination of membrane types is indicated.
- a process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 60 ppm hydrogen sulfide, 15 vol% carbon dioxide and die remainder metiiane, a composition that falls in Zone D of Figure 1, but close to the boundary between zones C and D.
- the process uses a membrane separation system as shown in Figure 7.
- Numerals 23, 26 and 32 indicate die three banks of membrane modules; 23 contains the more hydrogen-sulfide-selective membrane; 26 and 32 contain the more carbon-dioxide- selective membrane.
- the incoming gas stream 22 is at 6,897 kPa (1,000 psia) and is mixed with the residue stream 34 from the second stage to form the feed gas stream 35 to the first membrane stage.
- the residue stream, 24, from the first bank of modules passes as feed to die second bank of the first stage, 26. In this case, the permeate streams 25 and 28 from die two steps of the first stage are combined as stream
- the composition of stream 31 was in Zone C, so that the more carbon-dioxide-selective membrane was chosen for the second stage.
- the characteristics of the two types of membrane were assumed to be as follows:
- Metiiane flux 7.5 x 10 ⁇ cm 3 (STP)/cm -s ⁇ mHg
- compositions of the various streams were calculated and are given in Table 12.
- Example 32 A process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 200 ppm hydrogen sulfide, 15 vol% carbon dioxide and die remainder methane, a composition that falls in Zone D of Figure 1. The process uses a membrane separation system as shown in Figure 7.
- Numerals 23, 26 and 32 indicate the three banks of membrane modules; 23 and 32 contain the more hydrogen-sulfide-selective membrane; 26 contains the more carbon-dioxide-selective membrane.
- the incoming gas stream 22 is at 6,897 kPa (1,000 psia) and is mixed with the residue stream 34 from the second stage to form the feed gas stream 35 to the first membrane stage.
- the residue stream, 24, from the first bank of modules passes as feed to die second bank of the first stage, 26.
- the permeate streams 25 and 28 could be combined before or after recompression, and a condenser to remove water vapor could be included.
- the characteristics of die two types of membrane were assumed to be as follows: More hydrogen-sulfide-selective membrane:
- Methane flux 7.5 x 10 cm 3 (STP)/cm 2 -s-cmHg
- compositions of the various streams were calculated and are given in Table 13.
- the membrane areas required were as follows: 21 m 2 for membrane 23, 248 m 2 for membrane 26 and 17 m 2 for membrane 32.
- the residue stream 27 from the first stage meets pipeline specifications.
- the permeate stream 33 from the second stage contains about 1,500 ppm hydrogen sulfide and d e overall methane loss is about 0.4%.
- the feed stream to die second stage bank of modules, 32 contains 427 ppm hydrogen sulfide and 75 vol% carbon dioxide, a composition that falls in the more carbon-dioxide- selective membrane zone of the zone diagram.
- an optimized design provides better hydrogen sulfide recovery if the more hydrogen-sulfide-selective membrane is used.
- a process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 1,000 ppm hydrogen sulfide, 15 vol% carbon dioxide and die remainder methane, a composition that falls in Zone D of Figure 1, but close to the boundary of Zone B.
- the process uses a membrane separation system as shown in Figure 7.
- Numerals 23, 26 and 32 indicate die tiiree banks of membrane modules; 23 and 32 contain die more hydrogen-sulfide-selective membrane; 26 contains the more carbon-dioxide-selective membrane.
- the incoming gas stream 22 is at 6,897 kPa (1,000 psia) and is mixed witii the residue stream 34 from the second stage to form the feed gas stream 35 to the first membrane stage.
- the residue stream, 24, from the first bank of modules passes as feed to die second bank of the first stage, 26.
- die permeate streams 25 and 28 could be combined before or after recompression, and a condenser to remove water vapor could be included.
- the characteristics of the two types of membrane were assumed to be as follows:
- Methane flux 7.5 x 10- 6 cm 3 (STP)/cm 2 -s-cmHg
- compositions of the various streams were calculated and are given in Table 14.
- the membrane areas required were as follows: 119 m 2 for membrane 23, 188 m 2 for membrane 26 and 17 m 2 for membrane 32.
- the residue stream 27 from the first stage meets pipeline specifications.
- the permeate stream 33 from the second stage contains about 0.7 vol% hydrogen sulfide and the overall methane loss is about 0.4%.
- Example 34 As with Example 31, an optimized design uses the more hydrogen-sulfide-selective membrane for the second stage.
- a process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 100 ppm hydrogen sulfide, 4 vol% carbon dioxide and the remainder methane, a composition that falls in Zone B of Figure 1, but so close to the boundary of Zone D that the composition is just within Zone D after mixing with the recycle stream from the second membrane stage.
- the process uses a membrane separation system as shown in Figure 7.
- Numerals 23, 26 and 32 indicate the three banks of membrane modules; 23 and 32 contain the more hydrogen-sulfide-selective membrane; 26 contains the more carbon-dioxide-selective membrane.
- the incoming gas stream 22 is at 6,897 kPa (1,000 psia) and is mixed witii the residue stream 34 from the second stage to form die feed gas stream 35 to the first membrane stage.
- the residue stream, 24, from the first bank of modules passes as feed to the second bank of the first stage, 26.
- die permeate streams 25 and 28 could be combined before or after recompression, and a condenser to remove water vapor could be included.
- the characteristics of the two types of membrane were assumed to be as follows: More hydrogen-sulfide-selective membrane:
- Methane flux 7.5 x 10' 6 cm 3 (STP)/cm 2 -s-cmHg
- Methane flux 7.5 x 10" 6 cm 3 (STP)/cm 2 -sxmHg
- compositions of the various streams were calculated and are given in Table 15.
- the membrane areas required were as follows: 131 m 2 for membrane 23, 1 m 2 for membrane 26 and 9 m 2 for membrane 32.
- the residue stream 27 from the first stage meets pipeline specifications.
- the permeate stream 33 from the second stage contains about 0.4 vol% hydrogen sulfide and the overall methane loss is about 0.5%.
- Examples 35-38 compare the performances of different types of membrane process for various feed gas compositions. The processes are not optimized, but are simply intended to highlight the difference between the respective performances.
- a one-stage membrane process was designed to handle a gas stream containing 100 ppm hydrogen sulfide, die remainder metiiane, at a feed pressure of 6,897 kPa (1,000 psia).
- the process schematic is as shown in Figure 2, where numeral 1 indicates the bank of membrane modules, and the feed, residue and permeate streams are indicated by numerals 2, 3 and 4 respectively.
- the process was assumed to use one bank of more carbon-dioxide-selective membranes having die following characteristics:
- compositions and flow rates of die permeate and residue streams were calculated and are given in Table 16.
- the membrane area used to perform such a separation was calculated to be about 200 m 2 .
- the stage cut was 17% and the methane loss into the permeate was 17% also.
- Hydrogen sulfide/methane selectivity 50 Carbon dioxide/metiiane selectivity: 13 Methane flux: 7.5 x IQ "6 cm 3 (STP)/cm 2 -s-cmHg
- compositions and flow rates of the permeate and residue streams were calculated and are given in Table 17.
- the membrane area used to perform such a separation was calculated to be about 130 m 2 .
- the stage cut was 10.8% and the methane loss into the permeate was 10.8 % also.
- the loss of methane into the permeate through the more hydrogen-sulfide-selective membrane is about 2/3 of that through the more carbon-dioxide-selective membrane.
- the permeate stream from the more hydrogen-sulfide-selective membrane is about 2/3 the volume and 1.5 times more concentrated tiian the permeate stream from the more carbon-dioxide-selective membrane, making further treatment much easier.
- the process with the more hydrogen-sulfide-selective membrane also uses less membrane area.
- a one-stage membrane process was designed to handle a gas stream containing 100 ppm hydrogen sulfide, 4 vol% carbon dioxide and the remainder metiiane, at a feed pressure of 6,897 kPa
- Methane flux 7.5 x 10- 6 cm 3 (STP)/cm -s-cmHg
- the membrane area used to perform such a separation was calculated to be about 200 m 2 .
- the stage cut was 19% and the methane loss into the permeate was 16%.
- compositions and flow rates of the permeate and residue streams were calculated and are given in Table 19.
- the membrane area used to perform such a separation was calculated to be about 120 m 2 .
- the stage cut was 12% and the metiiane loss into the permeate was 10%.
- a one-stage membrane process was designed to handle a gas stream containing 100 ppm hydrogen sulfide, 30 vol% carbon dioxide and the remainder methane, at a feed pressure of 6,897 kPa
- Methane flux 7.5 x 10* cm 3 (STP)/cm 2 -s-cmHg
- compositions and flow rates of the permeate and residue streams were calculated and are given in Table 20.
- the membrane area used to perform such a separation was calculated to be about 150 m 2 .
- the stage cut was 40% and die methane loss into the permeate was over 16%.
- Methane flux 7.5 x 10* cm 3 (STP)/cm 2 -s-cmHg
- compositions and flow rates of the permeate and residue streams were calculated and are given in Table 21.
- a one-stage membrane process was designed to handle a gas stream containing 100 ppm hydrogen sulfide, 10 vol% carbon dioxide and the remainder metiiane, at a feed pressure of 6,897 kPa (1 ,000 psia).
- the target was to just meet pipeline specification of 2 v ⁇ l% for carbon dioxide, without controlling the hydrogen sulfide concentration in the residue stream.
- the process schematic is as shown in Figure 2, where numeral 1 indicates the bank of membrane modules, and the feed, residue and permeate streams are indicated by numerals 2, 3 and 4 respectively.
- the process was assumed to use one bank of more carbon-dioxide-selective membranes having the following characteristics:
- Methane flux 7.5 x 10* cm 3 (STP)/cm 2 -s-cmHg
- compositions and flow rates of die permeate and residue streams were calculated and are given in Table 22.
- the residue stream which still contains 14 ppm, does not meet pipeline specification for hydrogen sulfide.
- Methane flux 7.5 x 10* cm 3 (STP)/cm 2 -s-cmHg
- compositions and flow rates of the permeate and residue streams were calculated and are given in Table 23.
- Hydrogen sulfide/metiiane selectivity 50 Water vapor/methane selectivity: 1,000 Carbon dioxide/metiiane selectivity: 13
- Methane flux 7.5 x 10* cm 3 (STP)/cm 2 -s-cmHg
- Carbon dioxide/metiiane selectivity 20 Hydrogen sulfide/methane selectivity: 25 Hydrogen sulfide/methane selectivity: 200
- Methane flux 7.5 x 10* cm 3 (STP)/cm 2 -s-cmHg
- compositions and flow rates of the permeate and residue streams from each bank of modules were calculated and are given in Table 26. TABLE 26
- the combination process performs better than either of the single membrane processes in this composition range.
- the total membrane area used is about 135 m 2 .
- Residue stream 27 from the second stage meets pipeline specifications. If the permeate streams 25 and 28 from die two banks of membrane modules are pooled die permeate composition is 510 ppm hydrogen sulfide, 44 vol% carbon dioxide and 56 vol% methane. The methane loss in die pooled permeates is about 11.5%. This loss could be reduced if die process were optimized.
- Examples 39 and 40 show treatment processes in which the membrane process does not bring the gas stream to pipeline specification for all components.
- Example 39. Membrane plus scavenging process
- a process was designed to handle a gas stream containing 1 ,000 ppm hydrogen sulfide, 0.1 vol% water vapor, 4 vol% carbon dioxide and die remainder metiiane, at a feed pressure of 6,897 kPa (1,000 psia).
- the process includes a one-stage membrane separation step, followed by a scavenging step to bring the hydrogen sulfide concentration down further to 4 ppm.
- the scavenging step could be carried out using an iron sponge, for example.
- the process was assumed to use one bank of more hydrogen- sulfide-selective membranes having the following characteristics:
- Methane flux 1 x 10* cm 3 (STP)/cm 2 -s-cmHg
- STP cm 3
- the membrane area used was calculated to be about 70 m 2 .
- the stage cut was just under 10% and the methane loss into the permeate was 7.6%.
- the process produces a residue stream that meets pipeline specification for carbon dioxide and water vapor, but needs further polishing to remove hydrogen sulfide.
- Example 40 Process including amine plant for hvdropen sulfide removal
- a process was designed to handle a gas stream containing 0.5 vol % hydrogen sulfide, 20 vol% carbon dioxide and die remainder methane, at a feed pressure of 6,897 kPa ( 1 ,000 psia).
- the process uses a one-stage membrane separation step to carry out a first separation of carbon dioxide and hydrogen sulfide, followed by an amine plant to bring die stream to pipeline specification.
- the process was assumed to use one bank of more hydrogen-sulfide-selective membranes having the following characteristics:
- Methane flux 7.5 x 10* cm 3 (STP)/cm 2 -s-cmHg
- compositions and flow rates of the permeate and residue streams were calculated and are given in Table 28.
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Abstract
Improved membranes and improved membrane processes for treating gas streams containing hydrogen sulfide, carbon dioxide, water vapor and methane, particularly natural gas streams. The processes rely on the availability of two membrane types, one of which has a hydrogen sulfide/methane selectivity of at least about 40 when measured with multicomponent gas mixtures at high pressure. Based on the different permeation properties of the two membrane types, optimized separation processes can be designed.
Description
SOUR GAS TREATMENT PROCESS
FIELD OF THE INVENTION
The invention relates to processes for removing acid gases from gas streams. More particularly, the invention relates to a membrane process for removing hydrogen sulfide and carbon dioxide from gas streams, such as natural gas.
BACKGROUND OF THE INVENTION
Natural gas provides more than one-fifth of all the primaiy energy used in the United States. Much raw gas is "subquality", that is, it exceeds the pipeline specifications in nitrogen, carbon dioxide and/or hydrogen sulfide content.
The best treatment for natural gas right now is no treatment. Raw gas that is known to be high in nitrogen content, high in nitrogen plus carbon dioxide content, or high in hydrogen sulfide content is usually left in the ground, because it cannot be extracted and treated economically with present processing technology.
There are several aspects to the problem of treating natural gas to bring it to pipeline specifications. The first is the removal of impurities, primarily water, hydrogen sulfide and carbon dioxide; the second is loss of methane during processing. Processes that remove hydrogen sulfide and carbon dioxide may also remove a portion of the methane. Losses of less than about 3% are normally acceptable; losses of 3-10% may be acceptable if offset by other advantages; losses above 10% are normally unacceptable. A third aspect is the fate of the impurities once removed. Carbon dioxide can be discharged or reinjected, but hydrogen sulfide, which is toxic even in low concentrations, must be treated. If the waste stream containing hydrogen sulfide can be concentrated sufficiently, it may be passed to a Claus plant for conversion to sulfur. Waste streams containing low concentrations must be disposed of in some other way, such as a redox process of the LO CAT or Stretford type, for example, or, less desirably, flaring.
Choice of appropriate treatment is, therefore, not straightforward, and depends on the feed gas composition, the size and location of the plant and other variables.
When natural gas is treated, most plants handling large volumes of sour gas containing greater than about 200 ppm hydrogen sulfide use amine-based technology for acid gas removal. Amines commonly used include MEA, DEA, DIPA, DGA and MDEA. The plants can remove both carbon dioxide and hydrogen sulfide. When the amine solution is spent, the acid gases are flashed off and the
solution is regenerated. The mechanical equipment in an amine plant makes it susceptible to failure. The plant includes heaters, aerial coolers, pumps, etc. and requires frequent quality checks and maintenance, making operational reliability probably the weakest feature of the technology.
Amine plants do not sorb methane to any significant extent, so methane loss is not an issue in this case. However, the --ydrogen-sulfide-oontaining gas stream produced when the sorbent is regenerated must still be treated, subject to the same constraints as above.
As an alternative to amine sorption, or as a polishing step following any process, specialized scavenging or sulfur recovery processes, such as Sulfa-Scrub, Sulfa-Check, Chemsweet, Supertron 600, solid iron sponge or solid zinc oxide may be used for low-volume streams containing less than about 100 ppm hydrogen sulfide. Many scavengers present substantial disposal problems, however. In an increasing number of states, the spent scavenger constitutes toxic waste.
A considerable body of literature exists regarding membrane-based treatment of natural gas, mostly using cellulose acetate (CA) membranes to remove carbon dioxide. Although cellulose acetate membrane plants are designed to remove carbon dioxide, cellulose acetate membranes also have selectivity for hydrogen sulfide over methane, so they tend to coextract small amounts of hydrogen sulfide. Unless the raw gas stream contains very high concentrations of carbon dioxide, however, it is not possible to reduce a stream containing even modest amounts of hydrogen sulfide to pipeline specification (usually 4 ppm hydrogen sulfide) without vastly overprocessing as far as the carbon dioxide specification is concerned. If such overprocessing is performed, large amounts of methane are lost in the membrane permeate stream, and this is normally unacceptable.
Only a few of the many literature references relating to membrane-based carbon dioxide treatment specifically discuss removal of hydrogen sulfide in conjunction with the carbon dioxide. A paper by W.J. Schcll et al. ("Separation of CO2 from Mixtures by Membrane Permeation", presented at the Gas Conditioning Conference, University of Oklahoma, March 1983) says that "If the H2S level is low enough, the membrane system can also be used to meet pipeline specification for this component without any further treatment required." The paper shows a case where a cellulose acetate membrane system can be used to reach pipeline specification for carbon dioxide and hydrogen sulfide in two stages, starting with a feed content of 15% carbon dioxide and 250 ppm hydrogen sulfide, and points out that, for high concentrations of hydrogen sulfide, "a much larger number of elements are required to reduce the H2S levels to pipeline specification (1/4 grain) than for CO2 (3%)." The costs of membrane treatment are estimated to be more than 100% higher than conventional amine treatment in this case.
A report by N.N. Li et al. to the Department of Energy ("Membrane Separation Processes in the
Petrochemical Industry", Phase II Final Report, September 1987) examined the effect of impurities, including hydrogen sulfide, on the ability of cellulose acetate membranes to remove carbon dioxide from natural gas. The reporters found that the membrane performance was not affected significantly by hydrogen sulfide alone. However, dramatic loss of membrane permeability was observed if both hydrogen sulfide and water vapor were present in the feed. The authors concluded that "successful use of these CA- based membranes must avoid processing gas which simultaneously has high H2O and H2S concentrations". Another problem associated with cellulose acetate membranes is water, which is always present in raw natural gas streams to some extent, as vapor, entrained liquid, or both. The gas separation properties of cellulose acetate membranes are destroyed by contact with liquid water, so it is normally necessary to provide pretreatment to knock out any liquid water and to reduce the relative humidity low enough that there is no risk of condensation of water within the membrane modules on the permeate side. For example, the above-cited paper by W.J. Schell et al. ("Separation of CO2 from Mixtures by Membrane Permeation", presented at the Gas Condition-ng Conference, University of Oklahoma, March 1983) points out that "Even though membrane systems simultaneously dehydrate while removing C02, care must be taken to avoid contacting the membrane with liquid water. Feed gas streams saturated with water are normally preheated to at least 10° above the water dew point at the feed inlet pressure and the pressure tubes and inlet piping are insulated to prevent condensation."
The above-cited report by N. N. Li et al. ("Membrane Separation Processes in the Petrochemical Industry," Phase II Final Report, September 1987) presents data showing the effect of water vapor on membrane flux for cellulose acetate membranes, and concludes that "for relative humidities of 30% and higher, the flux decline is large, rapid, and irreversible". E.W. Funk et al. ("Effect of Impurities on Cellulose Acetate Membrane Performance", Recent Advances in Separation Techniques - III, AIChE Symposium Scries, 250, Vol 82, 1986) advocate that "Moisture levels up to 20% RH appear tolerable but higher levels can cause irreversible membrane compaction". U.S. Patent 4,130,403 to T.E. Cooley et al. (Removal of H2S and/or CO2 from a Light
Hydrocarbon Stream by Use of Gas Permeable Membrane, 1978, Col. 12, lines 36-39) states that "It has been discovered that in order to function effectively, the feed gas to the cellulose ester membrane should be substantially water free". A second paper by W.J. Schell et al. ("Spiral-Wound Permeators for Purification and Recovery", Chemical Engineering Progress, October 1982, pages 33-37) confiπns that "Liquid water is detrimental to the performance of the membrane, however, so that the feed gas is delivered to the membrane system at less than 90% relative humidity."
In other words, although cellulose acetate membranes will permeate water preferentially over
methane, and hence have the capability to dehydrate the gas stream, care must be taken to keep the amounts of water vapor being processed low, and, according to some teachings, as low as 20-30% relative humidity.
In light of these limitations, considerable effort has been expended over the last few years in the search for membrane materials that would be better able to handle streams containing carbon dioxide plus secondary contaminants, notably hydrogen sulfide and water.
For dense polymer membranes, the combined effect of the sorption and diffusion phenomena determines the selectivity of the membrane. The balance between mobility, or diffusion, selectivity and sorption selectivity is different for glassy and rubbery polymers. In glassy polymers, the mobility term is usually dominant, permeability falls with increasing permeant size and small molecules permeate preferentially. In rubbery polymers, the sorption term is usually dominant, permeability increases with increasing permeant size and larger molecules permeate preferentially. Since both carbon dioxide (3.3 A) and hydrogen sulfide (3.6 A) have smaller kinetic diameters than methane (3.8 A), and since both carbon dioxide and hydrogen sulfide are more condensable than methane, both glassy and rubbery membranes are selective for the acid gas components over methane. To date, however, most membrane development work in this area has focused on glassy materials, of which cellulose acetate is the most successful example.
In citing selectivity, it is important to be clear as to how the permeation data being used have been measured. It is common to measure the fluxes of different gases separately, then to calculate selectivity as the ratio of the pure gas permeabilities. This gives the "ideal" selectivity for that pair of gases. Pure gas measurements are more commonly reported than mixed gas experiments, because pure gas experiments are much easier to perform. Measuring the permeation data using gas mixtures, then calculating the selectivity as the ratio of the gas fluxes, gives the actual selectivity that can be achieved under real conditions. In gas mixtures that contain condensable components, it is frequently, although not always, the case that the mixed gas selectivity is lower, and at times considerably lower, than the ideal selectivity. The condensable component, which is readily sorbed into the polymer matrix, swells or, in the case of a glassy polymer, plasticizes the membrane, thereby reducing its discriminating capabilities.
A technique for predicting mixed gas performance under real conditions from pure gas measurements with any reliability has not yet been developed. In the case of gas mixtures such as carbon dioxide/methane with other components, the expectation is that the carbon dioxide at least will have a swelling or plasticizing effect, thereby changing the membrane permeation characteristics. This expectation is borne out by cellulose acetate membranes. For example, according to a paper by M.D.
Donahue et al. ("Permeation behavior of carbon dioxide-methane mixtures in cellulose acetate membranes", Journal of Membrane Science, 42, 197-214, 1989) when measured with pure gases, the carbon dioxide permeability of asymmetric cellulose acetate is 9.8 x 10"5 cm3/cm2's*kPa and the methane permeability is 2.0 x 10"6 cnrVcπvVkPa, giving an ideal selectivity of about 50. Yet the actual selectivity obtained with mixed gases is typically in the range 10-20, a factor of 3-5 times lower than the ideal selectivity. For example, the report to DOE by Norman Li et al., discussed above, gives carbon dioxide/methane selectivities in the range 9- 15 for one set of field trials (at 6,000-6,240 kPa (870-905 psi) feed pressure) and 12 for another set (at 1,483 kPa (200 psig) feed pressure) with a highly acid feed gas. The W.J. Schell et al. Chemical Engineering Progress paper, discussed above, gives carbon dioxide/methane selectivities of 21 (at 1,828-3,207 kPa (250-450 psig) feed pressure) and 23 (at 5,620 kPa (800 psig) feed pressure). Thus, even in mixed gas measurements, a wide spread of selectivities is obtained, the spread depending partly on operating conditions. In particular, the plasticizing or swelling effect of the carbon dioxide on the membrane tends to show pressure dependence, although it is sometimes hard to distinguish this from other effects, such as the contribution of secondary condensable components. The search for improved membranes for removing acid components from gas streams, although it has focused primarily on glassy membranes, encompasses several types of membranes and membrane materials. A paper by A. Deschamps et al. ("Development of Gaseous Permeation Membranes adapted to the Purification of Hydrocarbons", I.I.F - I.I.R - Commission A3, Paris, 1989) describes work with aromatic polyimides having an intrinsic material selectivity of 80 for carbon dioxide over methane and 200,000 for water vapor over methane. The paper defines the target selectivities that the researchers were aiming for as 50 for carbon dioxide methane and 200 for water vapor/methane. The paper, which is principally directed to dehydration, does not give carbon dioxide/methane selectivities, except to say that they were "generally low", even though the experiments were carried out with pure gas samples. In other words, despite the high intrinsic selectivity of 80, the lower target value of 50 could not be reached. British Patent number 1,478,083, to Klass and Landahl, presents a large body of permeation data obtained with methane/carbon dioxide hydrogen sulfide mixed gas streams and polyamide (nylon 6 and nylon 6/6), polyvinyl alcohol (PVA), polyacrylonitrile (PAN) and gelatin membranes. Some unexpectedly high selectivities are shown. For the nylon membranes, carbon dioxide/methane selectivities of up to 30, and hydrogen sulfide/methane selectivities up to 60, are reported. The best carbon dioxide/methane selectivity is 160, for PAN at a temperature of 30°C and a feed pressure of 448 kPa (65 psia); the best hydrogen sulfide/methane selectivity is 200, for gelatin at the same conditions. In both cases, however, the permeability is extremely low: for carbon dioxide through PAN, less than 5 x 10"4 Barrer and for
hydrogen sulfide through gelatin, less than 3 x 10"3 Barrer. These low permeabilities would make the transmembrane fluxes miserable for any practical purposes. It is also unknown whether the gelatin membrane, which was plasticized widi glycerin, would be stable much above the modest pressures under which it was tested. U.S. Patent 4,561,864, also to Klass and Landahl, incorporates in its text some of the data reported in the British patent discussed above. The '864 patent also includes a table of calculations for cellulose acetate membranes, showing the relationship between "Figure of Merit", a quantity used to express the purity and methane recovery in the residue stream, as a function of "Flow Rate Factor", a quantity that appears to be somewhat akin to stage-cut. In performing the calculations, separation factors (where the separation factor is the sum of the carbon dioxide/methane selectivity and the hydrogen sulfide/methane selectivity) of 20 to 120 are assumed. The figures used in the calculations appear to range from the low end of the combined carbon dioxide and hydrogen sulfide selectivities from mixed gas data to the high end of the combined selectivities calculated from pure gas data.
A paper by D.L. Ellig et al. ("Concentration of Methane from Mixtures with Carbon Dioxide by permeation through Polymeric Films", Journal of Membrane Science, 6, 259-263, 1980) summarizes permeation tests carried out with 12 different commercially available films and membranes, using a mixed gas feed containing 60% carbon dioxide, 40% methane, but no hydrogen sulfide or water vapor. The tests were carried out at 2,068 kPa (about 300 psi) feed pressure. The results show selectivities of about 9-27 for cellulose acetate, up to 40 for polyethersulfone and 20-30 for polysulfone. One of the membranes tested was nylon, which, in contradiction to the results reported by Klass and Landahl, showed essentially no selectivity at all for carbon dioxide over methane.
The already much-discussed DOE Final Report by N.N. Li et al. contains a section in which separation of polar gases from non-polar gases by means of a mixed-matrix, facilitated transport membrane is discussed. The membrane consists of a silicone rubber matrix carrying polyethylene glycol, which is used to facilitate transport of polar gases, such as hydrogen sulfide, over non-polar gases, such as methane. In tests on natural gas streams, the membranes exhibited hydrogen sulfide/methane selectivity of 25-30 and carbon dioxide/methane selectivity of 7-8, which latter number was considered too low for practical carbon dioxide separation. The membrane was also shown to be physically unstable at feed pressure above about 1,290 kPa (170 psig), which, even if the carbon dioxide/methane selectivity were adequate, would render it unsuitable for handling raw natural gas streams. U.S. Patents 4,608,060, to S. Kulprathipanja, and 4,606,740, to S. Kulprathipanja and S.S. Kulkarni, of Li's group at UOP, present additional data using the same type of glycol-laden membranes as discussed in the DOE report. In this
case, however, pure gas tests were performed and ideal hydrogen sulfide/methane selectivities as high as 115- 185 are quoted. It is interesting to note that these are 4-8 times higher than the later measured mixed gas numbers quoted in the DOE report. The same effect obtains for carbon dioxide, where the pure gas selectivities are in the range 21-32 and the mixed gas data give selectivities of 7-8. Similar in concept is U.S. Patent 4,737,166, to S.L. Matson et al., which discloses an immobilized liquid membrane typically containing n-methylpyrrolidone or another polar solvent in cellulose acetate or any other compatible polymer. The membranes and processes discussed in this patent are directed to selective hydrogen sulfide removal, in other words leaving both the methane and the carbon dioxide behind in the residue stream. As in the UOP patents, very high hydrogen sulfide/methane selectivities, in the range 90-350, are quoted. Only pure gas data are given, however, and the feed pressure is 793 kPa (100 psig). There is no discussion as to how the membranes might behave when exposed to multicomponent gas streams and/or high feed pressures. Based on the UOP teachings, the mixed gas, high-pressure results might be expected to be not so good.
U.S. Patent 4,781,733, to W.C. Babcock et al., describes results obtained with an interfacial composite membrane made by a potycondensation reaction between a diacid-chloride- terminated silicone rubber and a diamine. In pure gas experiments at 793 kPa (100 psig), the membrane exhibited hydrogen sulfide/methane selectivities up to 47 and carbon dioxide/methane selectivities up to 50. No mixed gas or high-pressure data are given.
U.S. Patent 4,493,716, to R.H. Swick, reports permeation results obtained with a composite membrane consisting of a polysulfide polymer on a Goretex (polytetra-fluoroethylene) support. Only pure gas, low-pressure test cell permeability data are given. Based on the reported permeabilities, which only give an upper limit for the methane permeability, the membrane appears to have a hydrogen sulfide/methane selectivity of at least 19-42 and a carbon dioxide/methane selectivity of at least 2-6. Some results show that the carbon dioxide permeability increased after exposure to hydrogen sulfide, which might suggest an overall decrease in selectivity if the membrane has become generally more permeable, although no methane data that could confirm or refute this are cited.
U.S. Patent 4,963,165, to I. Blume and I. Pinnau reports pure gas, low-pressure data for a composite membrane consisting of a polyamide-polyether block copolymer on a polyamide support. Hydrogen sulfide/methane selectivities in the range 140-190, and carbon dioxide/methane selectivities in the range 18-20, are quoted. Mixed gas data for a stream containing oxygen, nitrogen, carbon dioxide and sulfur dioxide are also quoted and discussed in the text, but it is not clear how these data would compare with those for methane- or hydrogen-sulfide-containing mixed gas streams.
Despite the many and varied research and development efforts that this body of literature represents, cellulose acetate membranes, with their attendant advantages and disadvantages, remain the only membrane type whose properties in handling acid gas streams under real gas-field operating conditions are reasonably well understood, and the only membrane type in commercial use for removing acid gas components from methane.
U.S. Patent 4,589,896, to M. Chen et al., exemplifies the type of process that must be adopted to remove carbon dioxide and hydrogen sulfide from methane and other hydrocarbons when working within the performance limitations of cellulose acetate membranes. The process is directed at natural gas streams with a high acid gas content, or at streams from enhanced oil recovery (EOR) operations, and consists of a multistage membrane separation, followed by fractionation of the acid gas components and multistage flashing to recover the hydrogen sulfide. The acid-gas-depleted residue stream is also subjected to further treatment to recover hydrocarbons. The raw gas to be treated typically contains as much as 80% or more carbon dioxide, with hydrogen sulfide at the relatively low, few thousands of ppm level. Despite the fact that the ratio of the carbon dioxide content to the hydrogen sulfide content is high (about 400: 1), the raw gas stream must be passed through a minimum of four membrane stages, arranged in a three-step, two-stage configuration, to achieve good hydrogen sulfide removal. The goal is not to bring the raw gas stream to natural gas pipeline specification, but rather to recover relatively pure carbon dioxide, free from hydrogen sulfide, for further use in EOR. The target concentration of carbon dioxide in the treated hydrocarbon stream is less than 10%, which would, of course, not meet natural gas pipeline standards. The methane left in the residue stream after higher hydrocarbon removal is simply used to strip carbon dioxide from hydrogen-sulfide-rich solvent in a later part of the separation process; no methane passes to a natural gas pipeline. Despite the multistep/multistage membrane arrangement, in a representative example, about 7% carbon dioxide is left in the hydrocarbon residue stream after processing, and about 12% hydrocarbon loss into the permeate takes place. In summary, it may be seen that there remains a need for improved membranes and improved processes for handling streams containing methane, acid gas components and water vapor.
SUMMARY OF THE INVENTION
The invention provides improved membranes and improved membrane processes for treating gas streams containing hydrogen sulfide, carbon dioxide, water vapor and methane, particularly natural gas streams. The processes rely on the availability of two membrane types: one, cellulose acetate, or a material with similar properties, characterized by a mixed gas carbon dioxide/methane selectivity of about 20 and
a mixed gas hydrogen sulfide/methane selectivity of about 25; the other an improved membrane with a much higher mixed gas hydrogen sulfide/methane selectivity of at least about 30, 35 or 40 and a mixed gas carbon dioxide/methane selectivity of at least about 12. These selectivities must be achievable with gas streams containing at least methane, carbon dioxide and hydrogen sulfide and at feed pressures of at least 3,551 kPa (500 psig), more preferably 5,620 kPa (800 psig), most preferably 7,000 kPa ( 1 ,000 psig).
An important aspect of the invention is the availability of membranes with much higher hydrogen sulfide/methane selectivities than cellulose acetate. This provides d e flexibility to choose between the membrane with the higher carbon dioxide/methane selectivity, in treating streams containing little hydrogen sulfide relative to carbon dioxide; the membrane with the higher hydrogen sulfide/methane selectivity, in treating streams containing substantial amounts of hydrogen sulfide relative to carbon dioxide; and a mixed membrane configuration in treating streams in the intermediate category.
The availability of the two membrane types enables treatment processes balanced in terms of the two membranes, so as to optimize any process attribute accordingly, to be designed. Based on the different permeation properties of the two membrane types, we have discovered that it is possible, through computer modeling, to define gas composition zones in which a particular treatment process is favored. For example, if it is the primary goal to minimize methane loss in the membrane permeate, it may be better to carry out the treatment using only the more hydrogen-sulfide-selective membrane, only the more carbon- dioxide-selective membrane or a mixture of both, depending on the particular feed gas composition. Similar determinations may be made if the amount of membrane area used is to be minimized, the costs and energy of recompression are to be kept below a target value, the hydrogen sulfide concentration in the permeate is to be maximized, the overall operating costs are to be reduced, or any other membrane process attribute is to be the key design factor.
If a combination of the two membrane types is to be used, the preferred configuration is to pass the gas stream first through modules containing the one membrane type, then to pass the residue stream from the first bank of modules through a second bank containing membranes of the other type. If the raw gas stream contains significant amounts of water, for example, it is preferable to use the more hydrogen- sulfide-selective membrane first These membranes are not usually damaged by water, and can handle gas streams having very high relative humidities, up to saturation. Furthermore, the membranes are very permeable to water vapor, and so can be used to dehydrate the gas stream before it passes to the second bank of modules.
Any membranes that can achieve the necessary carbon dioxide/methane and hydrogen sulfide/methane selectivities under mixed gas, high-pressure conditions, plus provide commercially useful
transmembrane fluxes, can be used. The most preferred material for the more carbon-dioxide-selective membrane is cellulose acetate cr its variants. The most preferred material for the more hydrogen-sulfide- selective membrane is a polyamide-polyether block copolymer having the general formula
HO - c — PA— C — O — PE — C ^τ- H
I— It It _I n O O where PA is a polyamide segment, PE is a polyether segment and n is a positive integer. Such polymers are available commercially as Pebax® from Atochem Inc., Glen Rock, New Jersey or as Vestamid® from
Nuodex Inc., Piscataway, New Jersey.
In their most basic embodiments, the processes of the invention make use of a one-stage membrane design, if a single membrane type is indicated, and a two-step membrane design, in which the residue from the first step becomes the feed for the second step, if a combination of membrane types is indicated. Optionally, two-stage (or more complicated) membrane configurations, in which the permeate from the first stage becomes the feed for the second, may be used. This will both increase the concentration of hydrogen sulfide in the second stage permeate and reduce the methane loss. The membrane process may also be combined with one or more non-membrane processes, to provide a treatment scheme that delivers pipeline quality methane, on the one hand, and that concentrates and disposes of the acid-gas-laden waste stream, in an environmentally acceptable manner, on the other.
The processes of the invention exhibit a number of advantages compared with previously available acid gas treatment technology. First, provision of a membrane with much higher selectivity for hydrogen sulfide over methane makes it possible, for the first time, to apply membrane treatment efficiently to gas streams characterized by relatively high concentrations of hydrogen sulfide. Secondly, the processes are much better at handling gas streams of high relative humidity. Thirdly, it is sometimes possible to bring a natural gas stream into pipeline specifications for all three of carbon dioxide, hydrogen sulfide and water vapor with a single membrane treatment. Fourthly, overprocessing of the gas stream by removing the carbon dioxide to a much greater extent than is actually necessary, simply to bring the hydrogen sulfide content down, can be avoided. Fifthly, much greater flexibility to adjust membrane operating and performance parameters is provided by the availability of two types of membranes. Sixthly, the process can be optimized for any chosen process attribute by calculating the appropriate membrane mix to use.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a diagram showing zones in which particular membranes should be used to separate hydrogen
sulfide and carbon dioxide from methane.
Figure 2 is a basic schematic drawing of a one-stage membrane separation process.
Figure 3 is a graph showing the effect of water vapor on carbon dioxide flux through cellulose acetate membranes. Figure 4 is a graph showing the effects of hydrogen sulfide and water vapor on the performance of cellulose acetate membranes.
Figure 5 is a basic schematic drawing of a typical two-stage membrane separation process.
Figure 6 is a basic schematic drawing of a two-step membrane separation process.
Figure 7 is a basic schematic drawing of a two-step/two-stage membrane separation process. Figure 8 is a basic schematic drawing of a two-stage membrane separation process with an auxiliary membrane unit forming a second-stage loop.
Figure 9 is a diagram showing zones in which particular membranes should be used to separate hydrogen sulfide and carbon dioxide from methane, based on different hydrogen sulfide methane selectivities.
Figure 10 is a diagram showing zones in which particular membranes should be used to separate hydrogen sulfide and carbon dioxide from methane, based on different carbon dioxide/methane selectivities.
Figure 11 is a diagram showing zones in which particular membranes should be used to separate hydrogen sulfide and carbon dioxide from methane, for different feed gas pressures.
DETAILED DESCRIPTION OF THE INVENTION The term intrinsic selectivity, as used herein, means the selectivity of the polymer material itself, calculated as the ratio of the permeabilities of two gases or vapors through a thick film of the material, as measured with pure gas or vapor samples.
The term ideal selectivity, as used herein, means the selectivity of a membrane, calculated as the ratio of the permeabilities of two gases or vapors through the membrane, as measured with pure gas or vapor samples.
The terms mixed gas selectivity and actual selectivity, as used herein, mean the selectivity of a membrane, calculated as the ratio of the permeabilities of two gases or vapors through the membrane, as measured with a gas mixture containing at least the two gases or vapors in question.
The invention has several aspects. In one aspect, the invention concerns processes for treating gas mixtures containing carbon dioxide in certain concentrations, hydrogen sulfide in certain concentrations and methane, to remove the carbon dioxide and hydrogen sulfide. In another aspect, the invention concerns optimizing such membrane separation processes in terms of a particular process
attribute. This optimizing may be done to minimize the methane loss from the membrane process, to maximize me hydrogen sulfide concentration in the permeate stream, or to provide the best fit between the membrane process and a non-membrane process or processes acting together as a "hybrid" process, for example. In yet another aspect, the invention concerns membranes that maintain high hydrogen sulfide/methane selectivities when challenged with mixed gas streams under high pressures.
The processes of the invention rely on the availability of two membrane types: one, cellulose acetate, or a material with similar properties, characterized by a mixed gas carbon dioxide/methane selectivity of about 20 and a mixed gas hydrogen sulfide/methane selectivity of about 25; the other a membrane with a much higher mixed gas hydrogen sulfide/methane selectivity of at least about 30, 35 or 40 and a mixed gas carbon dioxide/methane selectivity of at least about 12. These selectivities must be achievable with gas streams containing at least methane, carbon dioxide and hydrogen sulfide and at feed pressures of at least 3,551 kPa (500 psig), more preferably 5,621 kPa (800 psig), most preferably 7,000 kPa (1,000 psig).
The invention provides three forms of basic membrane treatment process: 1. Using only the more hydrogen-sulfide-selective membrane
2. Using only the more carbon-dioxide-selective membrane
3. Using a combination of both types of membrane.
Based on the different permeation properties of the two membrane types, we have discovered that it is possible, through computer modeling, to define gas composition zones most amenable to each one of these three types of basic processes. In performing the computer calculation, a specific process attribute is used as a basis for calculating the boundaries of the gas composition zones. It will be apparent to those of ordinary skill in the art that any one of many process attributes could serve as the basis for the calculation. Representative, non-limiting, examples include methane loss, membrane area, stage cut, energy consumption, annual operating costs, permeate composition, residue composition, best match with other processes in the treatment train, volume/composition of recycle streams, and so on.
Loss of methane is usually one of the most important factors in natural gas processing. On the one hand, pipeline grade methane is the desired product, and substantial losses of product have a substantial adverse effect on the process economics. On the other hand, large quantities of methane in the acid gas stream make further handling and recovery of any useful products from this stream much more difficult. As a general rule, a successful natural gas treatment process should keep methane losses during processing to no more than about 10%, and preferably no more than about 5%.
For simplicity, therefore, most of the discussion and examples have been directed to processes
designed to minimize methane losses, although it should be appreciated that the scope of the invention is intended to encompass any process design calculations done with the same goal, namely, defining zones applicable to the various processing options made possible by the two membrane types.
We believe the concept of these zones, how to calculate them and how to use them, is new, and will be useful in treating any gas stream that comprises methane, carbon dioxide and hydrogen sulfide.
Such streams arise from natural gas wells, from carbon dioxide miscible flooding for enhanced oil recovery
(EOR) and from landfills, for example. We believe that it will be particularly useful in the sweetening of natural gas containing acid gas components.
Referring now to Figure 1, this shows a typical zone diagram, with feed gas carbon dioxide concentration on one axis and hydrogen sulfide concentration on the other. The diagram was prepared by running a series of membrane separation computer simulations for hypothetical three-component (methane, carbon dioxide, hydrogen sulfide) gas streams of particular flow rates and compositions. In all cases, the target was to bring the stream to a pipeline specification of 4 ppm hydrogen sulfide and 2% carbon dioxide. The membrane properties were assumed to be as follows:
More COv-selective membrane: Carbon dioxide/methane selectivity: 20
Hydrogen sulfide/methane selectivity: 25 Methane flux: 7.5 x 10"* cm3(STP)/cm2-s-cmHg More H-S-selective membrane: Carbon dioxide/methane selectivity: 13 Hydrogen sulfide/methane selectivity: 50
Methane flux: 7.5 x 10"6 cm3(STP)/cm2-s-cmHg
In each case, the methane loss into the permeate stream that would occur if a one-stage membrane separation process were to be carried out was calculated, and was used to define zones of least methane loss. As can be seen, Figure 1 is divided into four zones. In zone A, no treatment is required, because the gas already contains less than 2% carbon dioxide and less than 4 ppm hydrogen sulfide. In zone B, methane loss is minimized if the more hydrogen-sulfide-selective membrane alone is used. In zone C, methane loss is minimized if the more carbon-dioxide-selective membrane alone is used. In zone D, methane loss is minimized by using a combination of the two membrane types. The zones are calculated based on the membrane selectivity and their exact position will change if the membrane selectivity changes. Figures 9 and 10 show the change in the B/D boundary for hydrogen sulfide/methane selectivities of 30, 40 and 50 and for carbon dioxide/methane selectivities of 10, 13 and 15.
The zone diagram may be used directly to determine the best type of membrane to use for a specific separation by reading off the zone into which the feed composition fits.
Another way to use the diagram is to define concentration bands that can serve as guidelines in selecting a membrane process. Again referring to Figures 1, 9 and 10, we have discovered that, as a guide, three carbon dioxide concentration bands may be defined, thus:
1. (a) If the feed gas to the membrane system contains less than about 3% carbon dioxide to less than about 10% carbon dioxide and more than about 10 ppm hydrogen sulfide to more than about 300 ppm hydrogen sulfide, with the lower end of the carbon dioxide range corresponding to the lower end of the hydrogen sulfide range (<3% carbon dioxide; >10 ppm hydrogen sulfide) and the upper end of the carbon dioxide range ∞-responding to the upper end of the hydrogen sulfide range (<10% carbon dioxide; >300 ppm hydrogen sulfide), then the most favorable process, in terms of minimizing methane loss, is carried out using the more hydrogen-sulfide-selective membrane only.
(b) If the feed gas contains less than about 10% carbon dioxide to less than about 20% carbon dioxide and more than about 300 ppm hydrogen sulfide to more than about 600 ppm hydrogen sulfide, with the lower end of the carbon dioxide range corresponding to the lower end of the hydrogen sulfide range (<10% carbon dioxide; >300 ppm hydrogen sulfide) and the upper end of the carbon dioxide range corresponding to the upper end of die hydrogen sulfide range (<20% carbon dioxide; >600 ppm hydrogen sulfide), then the most favorable process, in terms of minimizing methane loss, is carried out using the more hydrogen-sulfide-selective membrane only. (c) If the feed gas contains less than about 20% carbon dioxide to less than about 40% carbon dioxide and more than about 600 ppm hydrogen sulfide to more than about 1% hydrogen sulfide, with the lower end of the carbon dioxide range corresponding to the lower end of the hydrogen sulfide range (<20% carbon dioxide; >600 ppm hydrogen sulfide) and the upper end of the carbon dioxide range corresponding to the upper end of the hydrogen sulfide range (<40% carbon dioxide; >1% hydrogen sulfide), then the most favorable process, in terms of minimizing methane loss, is carried out using the more hydrogen- sulfide-selective membrane only.
Also, three hydrogen sulfide concentration bands may be defined, thus:
2. (a) If the feed gas contains less than about 5 ppm hydrogen sulfide to less than about 50 ppm hydrogen sulfide and more than about 3% carbon dioxide to more than about 15% carbon dioxide, with the lower end of the carbon dioxide range corresponding to the lower end of the hydrogen sulfide range (<5 ppm hydrogen sulfide; >3% carbon dioxide) and the upper end of d e carbon dioxide range corresponding to the upper end of die hydrogen sulfide range (<50 ppm hydrogen sulfide; >15% carbon
dioxide), then the most favorable process, in terms of minimizing methane loss, is carried out using the more carbon-dioxide-selective membrane only.
(b) If the feed gas contains less than about 50 ppm hydrogen sulfide to less than about 250 ppm hydrogen sulfide and more than about 15% carbon dioxide to more than about 50% carbon dioxide, with the lower end of d e carbon dioxide range corresponding to the lower end of the hydrogen sulfide range (<50 ppm hydrogen sulfide; >15% carbon dioxide) and the upper end of the carbon dioxide range αMTesponding to the upper end of the hydrogen sulfide range (<250 ppm hydrogen sulfide; >50% carbon dioxide), then the most favorable process, in terms of minimizing methane loss, is carried out using die more carbon-dioxide-selective membrane only. (c) If the feed gas contains less than about 250 ppm hydrogen sulfide to less than about 500 ppm hydrogen sulfide and more than about 50% carbon dioxide to more than about 85% carbon dioxide, with die lower end of die carbon dioxide range corresponding to die lower end of the hydrogen sulfide range (<250 ppm hydrogen sulfide; >50% carbon dioxide) and die upper end of die carbon dioxide range corresponding to die upper end of die hydrogen sulfide range (<500 ppm hydrogen sulfide; >85% carbon dioxide), dien the most favorable process, in terms of --linimiz-ng methane loss, is carried out using the more carbon-dioxide-selective membrane only.
Also: 3. For feed gas compositions outside die ranges specified in points 1 and 2 above, die most favorable process, in terms of minimizing methane loss, is carried out using a combination of the more hydrogen- sulfide-selective and die more carbon-dioxide-selective membranes.
For instance, using either die zone diagram itself or these concentration bands:
(i) If the carbon dioxide content of die stream is 4.5%, and the hydrogen sulfide content is 1,500 ppm, die more hydrogen-sulfide-selective membrane only should be used. (ii) If the carbon dioxide content of die stream is 4.5% and die hydrogen sulfide content is 7 ppm, die more carbon-dioxide selective membrane only should be used.
(iii) If die carbon dioxide content of the stream is 4.5% and die hydrogen sulfide content is 25 ppm, a combination membrane system should be used.
(iv) If die carbon dioxide content of the stream is 7% and die hydrogen sulfide content is 10,000 ppm, die more hydrogen-sulfide-selective membrane only should be used.
(v) If die carbon dioxide content of d e stream is 7% and the hydrogen sulfide content is 2 ppm (already wid in spec.), the more carbon-dioxide-selective membrane only should be used.
(vi) If the carbon dioxide content of the stream is 7% and die hydrogen sulfide content is 50 ppm, a combination membrane system should be used.
(vii) If die carbon dioxide content of the stream is 10% and die hydrogen sulfide content is 1,000 ppm, die more hydrogen-sulfide-selective membrane only should be used. (vϋi) If die carbon dioxide content of die stream is 10% and die hydrogen sulfide content is 20 ppm, the more carbon-dioxide-selective membrane only should be used.
(ix) If die carbon dioxide content of the stream is 10%, and d e hydrogen sulfide content is 100 ppm, a combination membrane system should be used.
(x) If the carbon dioxide content of the stream is 16% and die hydrogen sulfide content is 7,000 ppm, die more hydrogen-sulfide-selective membrane only should be used.
(xi) If the carbon dioxide content of die stream is 16% and die hydrogen sulfide content is 8 ppm, the more carbon-dioxide-selective membrane only should be used.
(xii) If the carbon dioxide content of die stream is 16%, and die hydrogen sulfide content is 250 ppm, a combination membrane system should be used. (xiii) If the carbon dioxide content of the stream is 25% and die hydrogen sulfide content is 10%, the more hydrogen-sulfide-selective membrane only should be used.
(xiv) If the carbon dioxide content of die stream is 25% and die hydrogen sulfide content is 50 ppm, the more carbon-dioxide-selective membrane only should be used.
(xv) If die carbon dioxide content of die stream is 25%, and the hydrogen sulfide content is 500 ppm, a combination membrane system should be used.
(xvi) If die carbon dioxide content of die stream is about 50-60% or more, die more hydrogen-sulfide- selective membrane should not be used alone, no matter how high the hydrogen sulfide content.
(xvii) If die carbon dioxide content of die stream is 40% and die hydrogen sulfide content is 120 ppm, die more carbon-dioxide selective membrane only should be used. (xviii) If the carbon dioxide content of die stream is 40%, and the hydrogen sulfide content is 2,000 ppm, a combination membrane system should be used.
(xix) If the hydrogen sulfide content of the stream is about 600 ppm or more, the more carbon-dioxide- selective membrane should not be used alone, no matter how high die carbon dioxide content.
(xx) If the carbon dioxide content of the stream is 70%, a combination membrane system should always be used if die hydrogen sulfide content is above about 500 ppm.
The discussion of die zone diagram and d e specific instances of what it teaches for twenty different gas compositions is deliberately fairly lengthy, so as to cover examples in the mid-ranges and
near the edges of die bands and zones.
Anodier way to express the teachings of die invention is simply to define single limits for the carbon dioxide and hydrogen sulfide concentrations that are best treated by different types of membrane.
This approach gives a less accurate result in any individual circumstance than the zone or band approaches, but gives a broad guide diat is useful irrespective of the particular process attribute that is of most concern. Specifically:
1. If the carbon dioxide content of the stream is less than about 40% and die hydrogen sulfide content is more than about 6,000 ppm (1%), the more hydrogen-sulfide-selective membrane should be used.
2. If die carbon dioxide content of the stream is less than about 20% and die hydrogen sulfide content is more than about 500 ppm, the more hydrogen-sulfide-selective membrane should be used.
3. If the carbon dioxide content of die stream is less man about 10% and the hydrogen sulfide content is more than about 10 ppm, the more hydrogen-sulfide-selective membrane should be used.
4. If the hydrogen sulfide content of the stream is less than about 25 ppm and die carbon dioxide content is more than about 10%, the more carbon-dioxide-selective membrane only should be used. 5. If the hydrogen sulfide content of the stream is less than about 100 ppm and die carbon dioxide content is more tiian about 15%, the more carbon-dioxide-selective membrane only should be used.
6. If the carbon dioxide content of die stream is in the range about 5-20% carbon dioxide and die hydrogen sulfide content is in the range 10-1,000 ppm, a combination membrane system may be used.
7. If die carbon dioxide content of die stream is in the range about 10-25% carbon dioxide and die hydrogen sulfide content is in die range 50-5,000 ppm, a combination membrane system may be used.
8. If the carbon dioxide content of the stream is greater than about 25% carbon dioxide and d e hydrogen sulfide content is greater than about 200 ppm, a combination membrane system may be used.
9. If the carbon dioxide content of die stream is greater than about 40% carbon dioxide and die hydrogen sulfide content is greater than about 600 ppm, a combination membrane system may be used. If a combination of die two membrane types is to be used, die simplest configuration is to pass die gas stream first through modules containing the one membrane type, then to pass the residue stream from the first bank of modules dirough a second bank containing membranes of the otiier type. The order in which the membrane types are encountered by die gas stream can be chosen according to die specifics of die application. If die raw gas stream contains significant amounts of water and hydrogen sulfide, for example, it is preferable to use the more hydrogen-sulfide-selective membrane first, since cellulose acetate membranes have been shown to lose botii selectivity and permeability substantially if exposed to combinations of water vapor and hydrogen sulfide. They also do not witiistand relative humidities above
about 30% very well. The polyamide-polyether block copolymer membranes tiiat are preferred as die more hydrogen-sulfide-selective membrane, on the odier hand, are not usually damaged by water or hydrogen sulfide, and can handle gas streams having high relative humidities, such as above 30% RH, above 90% RH and even saturation. Furthermore, the membranes are very permeable to water vapor, and so can be used to dehydrate the gas stream before it passes to the second bank of modules. If humidity and hydrogen sulfide content are not issues, and no other factors that affect only one of the membrane types are at work, then the total methane loss into the permeate streams and die total membrane area required to perform the separation should be essentially independent of die order in which the membranes are positioned.
Any membranes that can achieve the necessary carbon dioxide/methane selectivity and hydrogen sulfide/mediane selectivity, plus commercially useful transmembrane fluxes, can be used. Preferably the membranes should be characterized by transmembrane methane fluxes of at least 1 x 10"6 cm3(STP)/cm 'S'cmHg, most .preferably by transmembrane methane fluxes of at least 1 x 10-5 cm3(STP)/cm2-s-cmHg.
For the more carbon-dioxide-selective membrane, die preferred membranes are die cellulose acetate membranes that are already in use. Other candidates include different cellulose derivatives, such as ethylcellulose, methylcellulose, nitrocellulose and particularly other cellulose esters. Otherwise, membranes might be made from polysulfone, polyethersulfone, polyamides, polyimides, polyetherimides, polyacrylonitrile, polyvinylalcohol, other glassy materials or any other appropriate material. Usually, glassy materials have enough mechanical strength to be formed as integral asymmetric membranes, the production of which is well known in the art. The invention is not intended to be limited to any particular membrane material or membrane type, however, and encompasses any membrane, of any material, that is capable of meeting the target permeation properties, including, for example, homogeneous membranes, composite membranes, and membranes incorporating sorbents, carriers or plasticizers.
For the more hydrogen-sulfide-selective membrane, the most preferred membranes have hydrophilic, polar elastomeric selective layers. The mobility selectivity of such materials, although it favors hydrogen sulfide and carbon dioxide over metiiane, is modest compared to glassy materials. Because d e membrane is hydrophilic and polar, however, the sorption selectivity strongly favors hydrogen sulfide, carbon dioxide and water vapor over non-polar hydrophobic gases such as hydrogen, metiiane, propane, butane, etc. Although the selectivity of such materials is affected by swelling in the presence of condensable components, we have discovered tiiat hydrogen sulfide/methane selectivities of at least 30 or 35, sometimes at least 40 and sometimes 50, 60 or above can be maintained, even with gas mixtures containing high acid gas concentrations, even at high relative humidity, and even at very high feed
pressures up to 3,551 kPa (500 psig), 5,621 kPa (800 psig), 7,000 kPa (1 ,000 psig) or above. These are unusual and very useful properties. These properties render die membranes unusually suitable for treating natural gas, which often contains multiple components, has high humidity and is at high pressure. Preferred membrane materials exhibit water sorption greater than 5%, more preferably greater than 10%, when exposed to liquid water at room temperature. Particularly preferred are segmented or block copolymers mat form two-domain structures, one domain being a soft, rubbery, hydrophilic region, die otiier being harder and glassy or more glassy. Witiiout wishing to be bound by any particular ti eory of gas transport, we believe that die soft, rubbery domains provide a preferential pathway for the hydrogen sulfide and carbon dioxide components; die harder domains provide mechanical strength and prevent excessive swelling, and hence loss of selectivity, of die soft domains. Polyether blocks are preferred for forming the soft flexible domains; most preferably tiiese blocks incorporate polyethylene glycol, polytetramediylene glycol or polypropylene glycol, to increase die sorption of polar molecules by the membrane material.
One specific example of the most preferred membrane materials that could be used for the more hydrogen-sulfide selective membrane is r-o-yamide-po-yether block copolymers having the general formula
HO -f— C — PA — C — O — PE — C -^ - H
I II II —I n
where PA is a polyamide segment, PE is a polyether segment and n is a positive integer. Such polymers are available commercially as Pebax® from Atochem Inc., Glen Rock, New Jersey or as Vestamid® from
Nuodex Inc., Piscataway, New Jersey. The polyamide block gives strength and is believed to prevent the membrane swelling excessively in the presence of water vapor and/or carbon dioxide.
Other specific examples include polyether- and polyester-based polyurethanes. Representative polymer formulations and recipes are given, for example, in U.S. Patent 5,096,592, in which the copolymers are made by first preparing a prepolymer by combining simple diols and aliphatic or aromatic dicarboxylic acids with an excess of diacid to prepare diacid-terminated blocks, then chain-extending these with appropriately selected polypropylene or polyethylene glycol segments.
Usually, rubbery materials do not have enough mechanical strength to be formed as integral asymmetric membranes, but are instead incorporated into composite membranes, in which the rubbery selective layer is supported on a microporous substrate, often made from a glassy polymer. The preparation of composite membranes is also well known in the art. It is commonly thought that rubbery composite membranes do not widistand high-pressure operation well, and to date, such membranes have
not been generally used in natural gas treatment, where feed gas pressures are often as high as 3,551 kPa (500 psig) or 7,000 kPa (1,000 psig). We have found, however, tiiat composite membranes, with thin enough rubbery selective layers to provide a transmembrane methane flux of at least 1 x 10"6 cm3(STP)/cm2-s-cmHg, can be used satisfactorily at high feed pressures and not only maintain their integrity but continue to exhibity high selectivity for hydrogen sulfide over metiiane.
In their most basic embodiments, die processes of the invention make use of a one-stage membrane design if a single membrane type is indicated, and a two-step membrane design, in which the residue from die first step becomes the feed for die second step, if a combination of membrane types is indicated. It will be apparent to those of ordinary skill in the art that more sophisticated embodiments are possible. For example, a two-stage (or more complicated) membrane configuration, in which the permeate from d e first stage becomes die feed for the second, may be used to further enrich the acid gas content of die permeate stream and to reduce methane losses. It is envisaged tiiat a two-stage membrane configuration, using like or unlike membrane types in the two stages will often be used. In such arrangements, die residue stream from the second stage may be recirculated for further treatment in the first stage, or may be passed to die gas pipeline, for example.
In one-stage configurations, the residue stream may also be subjected to further membrane treatment. Both permeate and residue streams may be subjected to additional non-membrane treatment, such as in an amine plant, to bring it the residue stream to pipeline specification, for example. Given die diversity of flow rates, compositions and locations of natural gas wells, it is envisioned tiiat die membrane separation process will often form part of a hybrid treatment scheme that delivers pipeline quality metiiane, on die one hand, and that concentrates and disposes of die acid-gas-laden waste stream, in an environmentally acceptable manner, on the otiier.
In the zone calculations, die target pipeline specification for the treated gas was assumed to be no more an about 2 vol% carbon dioxide and 4 ppm hydrogen sulfide, which is typical pipeline specification. However, depending on die destination of die gas and specific standards to which the gas is subject, it is believed that a carbon dioxide content below about 3 vol% and a hydrogen sulfide content below about 20 ppm will be acceptable in many situations.
The processes of the invention exhibit a number of advantages compared witii previously available acid gas treatment technology. First, provision of a membrane witii much higher selectivity for hydrogen sulfide over metiiane makes it possible, for the first time, to apply membrane treatment efficiendy to gas streams c-r-aracterized by relatively high concentrations of hydrogen sulfide compared to carbon dioxide. This expands the range of utility of membrane separation substantially. Since membrane
systems are light, simple and low-maintenance compared witii amine plants, the enhanced ability to use membranes as a treatment option facilitates the exploitation of gas fields off-shore or in remote locations. Secondly, the processes are much better at handling gas streams of high relative humidity, so tiiat less pretreatment of die raw gas stream is necessary. Thirdly, it is sometimes possible to bring a natural gas stream into pipeline specifications for all three of carbon dioxide, hydrogen sulfide and water vapor witii a single membrane treatment. This is a very improtant feature, which makes the processes of die invention clearly more attractive tiian using one process for dehydration, a second for carbon dioxide removal and a tiiird for hydrogen sulfide removal. Fourthly, overprocessing of the gas stream by removing the carbon dioxide to a much greater extent tiian is actually necessary, simply to bring the hydrogen sulfide content down, can be avoided. Fifthly, much greater flexibility to adjust membrane operating and performance parameters is provided by die availability of two types of membranes. Sixthly, die process can be optimized for any chosen process attribute by calculating the appropriate membrane mix to use.
The invention is now further illustrated by die following examples, which are intended to be illustrative of die invention, but are not intended to limit the scope or underlying principles of die invention in any way.
EXAMPLES
The examples are in seven sets. SET 1 Examples 1-10 are comparative examples that illustrate the performance of various glassy and rubbery polymers exposed to acid gases under a variety of conditions. Example 1. Pure gas measurements. Polyimide membranes of two grades
(a) A three-layer composite membrane was prepared, using a microporous polyvinylidene fluoride (PVDF) support layer. The support was first coated witii a thin, high-flux, sealing layer, then witii a selective layer of polyimide (Matrimid Grade 5218, Ciba-Geigy, Hawthorne, NY). Membrane stamps were mounted in a test cell and die permeation properties of the membrane were tested witii pure carbon dioxide and with pure methane at a feed pressure of 448 kPa (50 psig). The results are listed in Table 1.
(b) A three-layer composite membrane was prepared, using a microporous polyvinylidene fluoride (PVDF) support layer. The support was first coated witii a thin, high-flux, sealing layer, then with a selective layer of polyimide (custom-made 6FDA-IPDA). Membrane stamps were mounted in a test cell and the permeation properties of die membrane were tested witii pure carbon dioxide and witii pure metiiane at a feed pressure of 448 kPa (50 psig). The results are listed in Table 1.
Example 2. Mixed pas measurements. Polyimide membranes of two grades (a) Three-layer composite membranes as in Example 1 (a) were tested witii a gas mixture consisting of 800 ppm hydrogen sulfide, 4 vol% carbon dioxide, die balance metiiane. The feed pressure was2,793 kPa ( 390 psig). The results are listed in Table 1. (b) Three-layer composite membranes as in Example 1(b) were tested witii a gas mixture consisting of 800 ppm hydrogen sulfide, 4 vol% carbon dioxide, die balance methane. Two feed pressures, 2,807 kPa (392 psig) and 4,890 kPa (694 psig), were used. The results are listed in Table 1. Example 3. Pure gas measurements. PTMSP membrane
A composite membrane was prepared by coating a polytrimethyl-silylpropyne (PTMSP) layer onto a polyvinylidene fluoride (PVDF) support membrane. Membrane stamps were mounted in a test cell and the permeation properties of the membrane were tested with pure carbon dioxide and witii pure methane at a feed pressure of 448 kPa (50 psig). The results are listed in Table 1. Example 4. Mixed gas measurements. PTMSP membrane
Composite membranes as in Example 3 were tested with a gas mixture consisting of 800 ppm hydrogen sulfide, 4 vol% carbon dioxide, die balance metiiane. The feed pressure was 2,793 kPa (390 psig). The results are listed in Table 1. Example 5. Pure gas measurements. Si icone rubber membrane
A composite membrane was prepared by coating a silicone rubber layer onto a microporous support membrane. Membrane stamps were mounted in a test cell and die permeation properties of the membrane were tested witii pure carbon dioxide and with pure methane at a feed pressure of 448 kPa (50 psig). The results are listed in Table 1. Example 6. Mixed pas measurements. Silicone rubber membrane
Composite membranes as in Example 5 were tested with a gas mixture consisting of 650 ppm hydrogen sulfide, 4 vol% carbon dioxide, die balance metiiane. The feed pressure was 759 kPa (95 psig). The results are listed in Table 1.
Example 7. Pure gas measurements. Polvbutadiene membrane
A composite membrane was prepared by coating a polybutadiene (Scientific Polymer Products, Ontario, NY) layer onto a PVDF support membrane. Membrane stamps were mounted in a test cell and die permeation properties of die membrane were tested witii pure carbon dioxide and witii pure methane at a feed pressure of 50 psig. The results are listed in Table 1.
Example 8. Mixed gas measurements. Polvbutadiene membrane
Composite membranes as in Example 7 were tested with a gas mixture consisting of 800 ppm
hydrogen sulfide, 4 vol% carbon dioxide, die balance metiiane. The feed pressure was 2,821 kPa (394 psig). The results are listed in Table 1.
TABLE 1 Permeation Properties of Various Glassy and Rubbery Polymer Membranes
The highest selectivity for hydrogen sulfide over methane was only 10.5, which was achieved witii a polyimide membrane at about 2,862 kPa (400 psig) feed pressure.
Example 9. Behavior of Cellulose Acetate Membranes in the Presence of Water Vapor This comparative example is from the report by N.N. Li et al. to die Department of Energy
("Membrane Separation Processes in die Petrochemical Industry," Phase II Final Report, September 1987).
Li et al. examined d e effect of water vapor in a feed gas stream of carbon dioxide on transmembrane flux.
Figure 3, taken from the report summarizes their data. For relative humidity of 10% or less, tiiere is no appreciable effect on the carbon dioxide flux. For relative humidities in die range 18-23%, the flux decreased 30% compared to die dry gas flux, but recovered when die feed was switched back to dry gas.
For relative humidities of 30% and higher, the flux decline was found to be large, rapid and irreversible.
Example 10. Behavior of Cellulose Acetate Membranes in the Presence of Hydrogen Sulfide and Water
Vapor
This example is also taken from the Li et al. report. Figure 4 summarizes the data. Hydrogen sulfide has a negligible effect on membrane performance if the feed gas is dry. If both hydrogen sulfide and water vapor are present, however, the transmembrane flux is substantially reduced. Li et al. conclude that the processing of streams containing both high concentrations of hydrogen sulfide and water vapor must be avoided with cellulose acetate membranes.
SET 2
Examples 11 and 12 show the performance of polyamide-polyetiier membranes exposed to pure gases. These examples are from earlier work at Membrane Technology and Research, as already reported in U.S. Patent 4,963, 165, since we were not able to make measurements with pure hydrogen sulfide.
Example 1 1. Polvamide-polvether membranes. Pure gas data
A multilayer composite membrane was prepared by coating a polysulfone support membrane first with a thin high-flux, sealing layer, then with a 1 wt% solution of Pebax grade 4011 in i-butanol. The membrane was tested witii pure gases at a temperature of 20°C and a feed pressure of 448 kPa (50 psig). The results are shown in Table 2.
Example 12. Polyamide-polyetiier membranes. Pure gas data
A second membrane was prepared using the same materials and technique as in Example 11. The results of pure gas tests with this membrane are also shown in Table 2. There is good agreement between the sets of results from Examples 11 and 12. TABLE 2
Permeation Properties of Pebax 4011 Composite Membranes Tested with Pure Gases
Feed PrtHtsttre Nonrali-jed Flux 10* , Membr-meSe-ecdvity,
Ex. Pressure ' ' rcm*{STP)/(cm«s«c Hg)l cP ) .
,HjS C02 Cn* H2S/CH* CQ/C ,
11 448 (50 psig) 1,650 219 11.9 139 18
12 448 (50 psig) 1,750 185 9.19 190 20
Examples 13-18 show the performance of polyamide-polyetiier membranes exposed to gas mixtures under a variety of conditions. Example 13
A composite membrane was prepared by coating a layer of a polyamide-polyether copolymer
(Pebax grade 4011) onto a polyvinylidene fluoride (PVDF) support membrane using die same general techniques as in Example 11. The membrane was tested witii a two-component gas mixture containing 4 vol% carbon dioxide, 96 vol% methane at three different feed pressures: 2,809 kPa (392 psig), 4,166 kPa (589 psig) and 6,724 kPa (960 psig). In all cases the permeate side of die membrane was at, or close to, atmospheric pressure and die membrane was at room temperature (23 °C). The permeation results are listed in Table 3. Example 14
The same type of membrane as in Example 13 was prepared and tested with a two-component gas mixture consisting of 970 ppm hydrogen sulfide, 99.9 vol% metiiane at three different feed pressures: 2,779 kPa (388 psig), 4,159 kPa (588 psig) and 6,793 kPa (970 psig). In all cases the permeate side of the membrane was at, or close to, atmospheric pressure and the membrane was at room temperature (23 °C). The permeation results are listed in Table 3. Example 15
The same type of membrane as in Example 13 was prepared and tested with a three-component gas mixture consisting of 870 ppm hydrogen sulfide, 4.12 vol% carbon dioxide and 95.79 vol% metiiane at three different feed pressures: 2,776 kPa (386 psig), 4,166 kPa (589 psig) and 6,821 kPa (974 psig). In all cases die permeate side of the membrane was at, or close to, atmospheric pressure and die membrane was at room temperature (23 °C). The permeation results are listed in Table 3. Example 16 The same type of membrane as in Example 13 was prepared and tested with a three-component gas mixture consisting of 0.986 vol% hydrogen sulfide, 4.12 vol% carbon dioxide and 94.90 vol% methane at three different feed pressures: 2,786 kPa (389 psig), 4,145 kPa (586 psig) and 6,800 kPa (971 psig). In all cases the permeate side of die membrane was at, or close to, atmospheric pressure and die membrane was at room temperature (23 °C). The permeation results are listed in Table 3. Example 17
The same type of membrane as in Example 13 was prepared and tested witii a three-component gas mixture consisting of 1.83 vol% hydrogen sulfide, 10.8 vol% carbon dioxide and 87.34 vol% methane at a feed pressure of 6,759 kPa (965 psig). The permeate side of die membrane was at, or close to, atmospheric pressure and d e membrane was at room temperature (23 °C). The permeation results are listed in Table 3. Example 18
The same type of membrane as in Example 13 was prepared and tested witii a three-component
gas mixture consisting of 950 ppm hydrogen sulfide, 8.14 vol% carbon dioxide and 91.77 vol% methane at three different feed pressures: 2,800 kPa (391 psig), 4,138 kPa (585 psig) and 6,793 kPa (970 psig).
In all cases the permeate side of the membrane was at, or close to, atmospheric pressure and die membrane was at room temperature (23 °C). The permeation results are listed in Table 3.
TABLE 3
Permeation Properties of a Pebax® 4011 Composite Membrane with Various Feed Gas Compositions at Three Feed Pressures
Feed ircssureKoπn lize Fluxx Mf Membrane Selectivity
Ex, Pressure . (cro3(STPy(c " croHg)] # (kPa)
. *β CO, Cti4 HjS/CH4 eo/CH
2,809 (392 psig) _ 31 1.9 _ 17
13
4,166 (589 psig) . 30 1.9 _ 16
6,724 (960 psig) . 29 2.0 . 15
2,779 (388 psig) 91 . 1.8 51 •
14
4,159 (588 psig) 74 _ 1.8 41 .
6,793 (970 psig) 73 _ 1.8 41 .
2,766 (386 psig) 140 31 1.9 70 16
15
4,166 (589 psig) 115 30 2.0 56 15
6,821 (974 psig) 110 29 2.2 52 14
2,786 (389 psig) 113 32 2.0 55 16
16
4,145 (586 psig) 103 31 2.0 51 15
6,800 (971 psig) 97 29 2.0 48 14
17 6,759 (965 psig) 121 34 2.4 50 14
2,800 (391 psig) 93 26 1.6 58 16
18
4,138 (585 psig) 108 32 2.0 52 15
6,793 (970 psig) 93 28 1.9 48 14
The following observations can be made from die data of Examples 13-18: 1. The presence of carbon dioxide in the feed gas appears to increase the fluxes of both hydrogen sulfide and methane through the membrane. For example, a comparison of the results of Example 14, in which die feed mixture did not contain any carbon dioxide, witii those of Examples 15-18, shows that the
hydrogen sulfide flaxes are about 25% lower and the methane fluxes are about 15% lower in Example 14.
The increased flax may be due to swelling of the membrane by dissolved carbon dioxide.
2. In general, the pressure-normalized flaxes of hydrogen sulfide and carbon dioxide decrease witii increasing feed pressure, whereas those of methane increase. The decrease in the hydrogen sulfide and carbon dioxide fluxes may be due to competitive sorption, which results in a lower solubility coefficient (the ratio of concentration in die polymer to partial pressure) for each component. At the same time, the polymer swells, resulting in a higher diffusivity for all components, including metiiane. The net result is an increase in the methane flux and a decrease in die fluxes of the acid gases (hydrogen sulfide and carbon dioxide). 3. The hydrogen sulfide/methane selectivity for three-component mixtures varies from a low of
48 to a high of 70, although all of the measurements were made at fairly high feed pressures. The carbon dioxide/methane selectivity, also at high pressure, is about 14-16.
Example 19. Gas streams containinp water vapor
The experiments of Example 15 were repeated using feed gas streams saturated with water vapor by bubbling the feed gas through a water reservoir. The experiments were carried out at feed pressures of 2,772 kPa (387 psig), 4,159 kPa (588 psig) and 6,793 (970 psig). The permeate side of the membrane was at, or close to, atmospheric pressure and the membrane was at room temperature (23 °C). The permeation results are listed in Table 4.
TABLE 4 Permeation Properties of Pebax 4011 Composite Membranes Tested with Water-Saturated Gas Mixtures
Comparing these results with those of Table 3, it can be seen that the fluxes are considerably lower (about 40-45% lower) tiian those obtained in the absence of water vapor. Neither die hydrogen sulfide/methane nor the carbon dioxide/methane selectivities, however, change significantly. Furthermore, when the membranes were retested with a dry gas stream, the fluxes returned to the original values.
SET 3
Examples 20-25 show typical computer calculations used to prepare a zone diagram. These calculations, and others of the same type, were used to prepare the zone diagram of Figure 1 , which shows feed gas carbon dioxide concentration on one axis and hydrogen sulfide concentration on the other. The diagram was prepared by running a series of membrane separation computer simulations for hypothetical three-component (methane, carbon dioxide, hydrogen sulfide) gas streams of particular flow rates and compositions at a feed pressure of 6,897 kPa (1,000 psia). In all cases, the target was to bring the stream to a pipeline specification of 4 ppm hydrogen sulfide and 2% carbon dioxide. The membrane properties were assumed to be as follows: More CO?-selective membrane:
Carbon dioxide/methane selectivity: 20 Hydrogen sulfide/methane selectivity: 25 Methane flux: 7.5 x 10"6 cm3(STP)/cm -s-cmHg
More H-S-selective membrane:
Carbon dioxide/methane selectivity: 13
Hydrogen sulfide/methane selectivity: 50
Methane flux: 7.5 x 10"6 cm3(STP)/cm2-s-cmHg
In each case, the metiiane loss into the permeate stream that would occur if a one-stage membrane separation process were to be carried out was calculated, and was used to define zones of least methane loss.
Example 20. A computer calculation was carried out for a feed stream of composition 200 ppm hydrogen sulfide, 15 vol% carbon dioxide, die remainder methane. Four simulations were performed: (i) using only the more hydrogen-sulfide-selective membrane (membrane A), (ii) using only the more carbon-dioxide- selective membrane (membrane B), (iii) using a combination of the more hydrogen-sulfide-selective membrane followed by die more carbon-dioxide-selective membrane (A +B), and (iv) using a combination of the more carbon-dioxide-selective membrane followed by the more hydrogen-sulfide-selective membrane (B + A). The results are listed in Table 5.
TABLE 5
Membrane type Membrane area Methane loss Residue H2S Residue CO2 (m2) (%) cone, (ppm) cone. (vol%)
A 203 18.1 <0.1 2.0
B 204 18.6 4 0.6
A + B 160 14.3 4 2.0
B + A 160 14.3 4 2.0
The methane losses in all cases are high, because the process design was kept to a simple one- stage design for comparison purposes. The goal of this calculation was not to design a fully optimized process, but to determine which of the possible membrane types would be preferred. It is apparent from the table that a combination of d e two membrane types would be indicated for treating a stream of this composition. Example 21.
A computer calculation was performed as in Example 20, using a feed stream of composition 70 ppm hydrogen sulfide, 10 vol% carbon dioxide, the remainder metiiane. The results are listed in Table 6.
TABLE 6
Membrane type Membrane area Methane loss Residue H2S Residue CO2 (m2) cone, (ppm) cone. (vol%)
A 171 14.7 <0.1 2.0
B 161 14.0 4 1.0
A + B 130 11.5 4 2.0
B + A 130 11.5 4 2.0
Example 22.
By repeating sets of calculations as shown in Examples 21 and 22, the boundary line between zones C and D, based on die stated assumptions as to membrane performance and operating conditions, was determined to be as follows:
CO, content of feed gas H,S content of feed pas
(vol%) (ppm)
2 4 3 6
5 12
10 29
20 70
30 120
Example 23.
Calculations similar to those described in Example 22 were carried out to determine the position of the boundary line between zones D and B. The position of the boundary was determined to be as follows:
CO, content of feed Ras H,S content of feed gas (vol%) (ppm)
2 4
3 15
5 75
10 700
20 13,000
30 120,000
Example 24.
The calculations of Example 23 were repeated to show the effect of higher or lower selectivity on the zone boundaries. Representative calculations were performed assuming a hydrogen sulfide/methane selectivity of the more hydrogen-sulfide-selective membrane of 30, 40 or 50, and a carbon dioxide/methane selectivity of d e more hydrogen-sulfide-selective membrane of 10, 13 or 15. The results are plotted graphically in Figures 9 and 10. As can be seen, the Zone B/D boundary moves to die right as the ability of the membrane to separate carbon dioxide improves. Likewise, the boundary moves to the right as the selectivity for hydrogen sulfide over methane decreases. Although the area where the more hydrogen-sulfide-selective membranes should be used is larger at lower hydrogen sulfide/methane selectivity, the methane losses encountered in using the membrane will be greater.
Example 25.
The calculations of Example 23 were repeated assuming different values for the feed pressure. Representative calculations were performed assuming a feed pressure of 5,517, 6,897, or 8,276 kPa
(800, 1,000 or 1,200 psia). The results are plotted graphically in Figure 11. As can be seen, the zone boundary is relatively insensitive to changes in the feed pressure. SET 4
Examples 26-29 show representative processes using the more hydrogen-sulfide-selective membrane only. Example 26
A very simple one-stage membrane process was designed to handle a gas stream containing
100 ppm hydrogen sulfide, 0.1 vol% water vapor, 4 vol% carbon dioxide and die remainder methane, at a feed pressure of 6,897 kPa (1,000 psia). A basic schematic of the process is shown in Figure 2, where numeral 1 indicates die bank of membrane modules, and die feed, residue and permeate streams are indicated by numerals 2, 3 and 4 respectively. The process was assumed to use one bank of more hydrogen-sulfide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 80 Water vapor/methane selectivity: 1,000
Carbon dioxide/methane selectivity: 12
Methane flux: 1 x 10-6 cm3(STP)/cm2-s-cmHg
The compositions and flow rates of the permeate and residue streams were calculated and are given in Table 7.
TABLE 7
STREAM FEED RESIDUE PERMEATE
Flow rate (NmV in) 28.3 (1,000 scfm) 25.6 (903 scfm) 2.7 (97 scfm)
CH4 conc. (vol%) 95.9 98.1 75.6
C02 conc. (vol%) 4.0 1.9 23.2
H2S conc. (ppm) 100 4 995
Water vapor cone. (vol%) 0.1 2 ppm 1.0
The membrane area used to perform such a separation was calculated to be about 70 m2. The stage cut was just under 10% and d e methane loss into die permeate was 7.5%. The process produces a residue stream tiiat simultaneously meets pipeline specification for carbon dioxide, hydrogen sulfide and water vapor. The low grade permeate gas could be sent to the foul gas line. Example 27
The simple design of Example 26 is only possible for certain cases where die raw stream to be
treated contains an appropriate balance of hydrogen sulfide and carbon dioxide. In many cases, a more complicated, optimized design is needed to improve the methane recovery and meet pipeline specifications without overprocessing.
A process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 1,000 ppm hydrogen sulfide, 0.1 vol% water vapor and the remainder metiiane, so as to keep methane loss in the permeate stream below 2%. The process uses a two-stage membrane separation system in which the permeate from the first bank of membrane modules becomes die feed for the second bank. A basic schematic of the process is shown in Figure 5, where numeral 10 indicates die first stage bank of membrane modules and numeral 18 indicates die second stage bank of membrane modules. The incoming gas stream 9 is at 6,897 kPa (1,000 psia) and is mixed witii the residue stream 20 from the second stage to form the feed gas stream 21 to the first membrane stage. The permeate stream 12 from the first stage is recompressed to 6,897 kPa (1,000 psia) in compressor 13. The compressed stream 14 passes to chiller 15, where water vapor is condensed and water is removed as liquid stream 16. The non-condensed stream 17 enters the second membrane stage 18, where further separation of hydrogen sulfide takes place. The residue stream from this stage is recirculated within the process. Both membrane stages were assumed to use more hydrogen-sulfide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 50 Water vapor/methane selectivity: 1 ,000
Methane flux: 7.5 x 10"* cm3(STP)/cm -s-cmHg
The compositions and flow rates of the first and second stage permeate and residue streams were calculated and are given in Table 8.
TABLE 8
STREAM FEED RESIDUE PERMEATE
FIRST STAGE
Flow rate (NmVmin) 34.0 (1,200 scfm) 27.9 (985 scf ) 6.1 (215 scfm)
CH4 conc. (vol%) 99.82 99.99 98.99
Water vapor cone. (vol%) 0.08 0.0 0.45
H2S conc. (vol%) 0.10 4 ppm 0.55
SECOND STAGE
Flow rate (Nm3/min) 26.1 (215 scfm) 5.7 (202 scfm) 0.4 (13 scfm)
CH4 conc. (vol%) 99.42 99.89 92.12
Water vapor cone, (ppm) 330 21 5,015
H2S conc. (vol%) 0.55 0.1 7.4
The membrane area used to perform such a separation was calculated to be about 280 m2 total, 265 m2 in the first stage and 15 m2 in the second stage. The residue stream 11 from the first stage meets pipeline specifications. The permeate stream 19 from the second stage contains a high enough concentration of hydrogen sulfide to be passed to a Claus plant for sulfur recovery unit, or to a liquid redox process, such as LO-CAT, Sulferox, Hyperion or Stretford. The overall methane loss into the second stage permeate is very low, at just about 1%. Example 28
A process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 1,000 ppm hydrogen sulfide, 4 vol% carbon dioxide and the remainder metiiane. The process uses a two-stage membrane separation system in which the permeate from the first bank of membrane modules becomes die feed for the second bank. The process schematic is as shown in Figure 5, except that no condenser 15 is used. Numeral 10 indicates die first stage bank of membrane modules and numeral 18 indicates die second stage bank of membrane modules. The incoming gas stream 9 is at 6,897 kPa (1,000 psia) and is mixed with the residue stream 20 from the second stage to form the feed gas stream 21 to the first membrane stage. In this case, the permeate stream 12 from the first stage is recompressed to 6,897 kPa (1,000 psia) in compressor 13, then passed without any condensation taking place as compressed stream 17 to the second membrane stage 18, where further separation of hydrogen sulfide takes place. The residue stream from this stage is recirculated within the process. Both membrane stages were assumed to use more hydrogen-sulfide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10^ cm3(STP)/cm2-s-cmHg
The compositions of the first and second stage permeate and residue streams were calculated and are given in Table 9.
TABLE 9
STREAM FEED RESIDUE PERMEATE
FIRST STAGE
Flow rate (NmVmin) 34.5 (1,220 scfm) 27.3 (964 scfm) 7.2 (256 scfm)
CH4 conc. (vol%) 93.0 98.86 71.8
C02 cone. (vol%) 6.9 1.14 28.3
H2S cone, (ppm) 1,000 4 4,733
SECOND STAGE
Flow rate (NmVmin) 7.2 (256 scfm) 6.2 (220 scfm) 1.0 (36 scfm)
CH4 conc. (vol%) 71.8 80.0 19.6
C02 conc. (vol%) 28.3 19.9 77.7
H-S conc. (vol%) 0.47 0.1 2.7
The membrane area used to perform such a separation was calculated to be about 244 m2 total, 232 m2 in die first stage and 12 m2 in the second stage. The residue stream 11 from the first stage meets pipeline specifications. The permeate stream 19 from the second stage contains a high enough concentration of hydrogen sulfide to be passed to a Claus plant for sulfur recovery unit, or to a liquid redox process, such as LO-CAT, Sulferox, Hyperion or Stretford. The overall methane loss into the second stage permeate is very low, at about 0.7%. Example 29
The calculations of Example 28 were repeated with a 28.3 NmVmin (1,000 scfm) gas stream containing 10,000 ppm hydrogen sulfide, 4 vol% carbon dioxide and the remainder methane. The results are given in Table 10.
TABLE 10
STREAM FEED RESIDUE PERMEATE
FIRST STAGE
Flow rate (NmVmin) 37.7 (1,330 scfm) 26.9 (950 scfm) 10.8 (380 scfm)
CH4 conc. (vol%) 91.0 99.4 70.0
C02 conc. (vol%) 8.0 0.6 26.5
H2S conc. (ppm) 10,000 4 3.5 voI%
SECOND STAGE
Flow rate (NmVmin) 10.8 (380 scfm) 9.4 (330 scfm) 1.4 (50 scfm)
CH4 conc. (vol%) 70.0 78.6 16.2
CO, cone. (vol%) 26.5 20.4 64.6
H2S conc. (vol%) 3.5 1.0 19.2
The membrane area used to perform such a separation was calculated to be about 353 m2 total, 339 m2 in the first stage and 14 m2 in the second stage. The residue stream 11 from the first stage meets pipeline specifications. The permeate stream 19 from the second stage contains a very high hydrogen sulfide concentration. The methane loss is less than 1%.
Examples 27-29 illustrate the benefits of two-stage processes in both reducing methane loss and raising the hydrogen sulfide concentration of the waste stream. In Examples 27-29, the feed composition, both raw and after mixing witii recycle stream 20, is in zone B. Example 30
A process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 1,000 ppm hydrogen sulfide, the remainder methane. The process uses a membrane separation system as shown in Figure 8. Numerals 38, 44 and 47 indicate the three banks of membrane modules: all contain the more hydrogen-sulfide-selective membrane. The incoming gas stream 36 is at 6,897 kPa (1,000 psia) and is mixed with the residue stream 49 from module(s) 47 to form the feed gas stream 37 to the first membrane stage. The permeate stream, 40, from the first stage is recompressed in compressor 42. Compressor 42 drives two membrane units, die second stage unit, 44, and an auxiliary module or set of modules, 47, that are connected on die permeate side either directly or indirectly to the inlet side of the compressor, so as to form a loop. Thus, permeate stream 48 may be merged with permeate stream 40 to form combined stream 41. The recompressed, combined stream, 43, passes as feed to membrane unit 44, and the residue stream, 46, from membrane unit 44 passes as feed to membrane unit 47. Permeate is withdrawn from the
loop as stream 45 and the treated residue exits as stream 39. This system configuration is particularly useful in situations where the hydrogen sulfide content of the raw stream is relatively low, yet flaring is not an option and the stream has to be brought up to a viable concentration for sulfur recovery. A series of calculations was carried out by keeping the area of membrane unit 38 constant, but varying the relative areas of membrane units 44 and 47. The characteristics of the membrane were assumed to be as in Example 28. The results of the calculations are given in Table 11.
TABLE 11
Membrane Area (m2) Permeate cone. (vol%)
Unit 38 Unit 44 Unit 47 Total
242 0 18 260 2.65
242 10 11 263 4.26
242 15 8 265 5.77
242 20 6 268 8.92
242 35 2 279 19.7
242 50 0.4 292.4 55.0
The residue stream 39 from die first stage meets pipeline specifications. A high concentration of hydrogen sulfide in the waste permeate stream can be achieved with an appropriate choice of membrane areas.
This type of design could also be used in situations where combinations of the two membrane types are indicated. SET 5
Examples 31-34 deal witii streams in which the feed composition is in zone D, so that a combination of membrane types is indicated. Example 31
A process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 60 ppm hydrogen sulfide, 15 vol% carbon dioxide and die remainder metiiane, a composition that falls in Zone D of Figure 1, but close to the boundary between zones C and D. The process uses a membrane separation system as shown in Figure 7. Numerals 23, 26 and 32 indicate die three banks of membrane modules; 23 contains the more hydrogen-sulfide-selective membrane; 26 and 32 contain the more carbon-dioxide- selective membrane. The incoming gas stream 22 is at 6,897 kPa (1,000 psia) and is mixed with the residue stream 34 from the second stage to form the feed gas stream 35 to the first membrane stage. The residue stream, 24, from the first bank of modules passes as feed to die second bank of the first stage, 26.
In this case, the permeate streams 25 and 28 from die two steps of the first stage are combined as stream
29 to be recompressed in compressor 30, men passed as compressed stream 31 to die second membrane stage 32. It will be apparent to those of ordinary skill in the art that two separate compressors could be used and the stream combined after compression. Also, in cases where the stream to be treated contains water vapor, the system could include a condenser as in Figure 5 to condense permeating water vapor.
The composition of stream 31 was in Zone C, so that the more carbon-dioxide-selective membrane was chosen for the second stage. The characteristics of the two types of membrane were assumed to be as follows:
More hydrogen-sulfide-selective membrane:
Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/methane selectivity: 13
Metiiane flux: 7.5 x 10^ cm3(STP)/cm -sτmHg
More carbon-dioxide-selective membrane:
Hydrogen sulfide methane selectivity: 25 Carbon dioxide/methane selectivity: 20
Methane flax: 7.5 x 10-6 cm3(STP)/cm2-s-cmHg
The compositions of the various streams were calculated and are given in Table 12.
TABLE 12
Stream tt CH4 conc. (vol%) H2S conc. (ppm) C02 cone. (vol%)
22 85.0 60 15.0
35 84.0 60 16.0
24 90.2 10 9.8
27 98.0 1 2.0
25 36.1 456 63.9
28 52.3 51 47.7
31 45.5 223 54.5
33 7.5 407 92.5
34 78.6 60 21.4
The membrane areas required were as follows: 66 m2 for membrane 23, 120 m2 for membrane 26 and 22
m2 for membrane 32. The residue stream 27 from the first stage meets pipeline specifications. The permeate stream 33 from the second stage contains about 400 ppm hydrogen sulfide and die overall methane loss is about 1%. Example 32 A process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 200 ppm hydrogen sulfide, 15 vol% carbon dioxide and die remainder methane, a composition that falls in Zone D of Figure 1. The process uses a membrane separation system as shown in Figure 7. Numerals 23, 26 and 32 indicate the three banks of membrane modules; 23 and 32 contain the more hydrogen-sulfide-selective membrane; 26 contains the more carbon-dioxide-selective membrane. The incoming gas stream 22 is at 6,897 kPa (1,000 psia) and is mixed with the residue stream 34 from the second stage to form the feed gas stream 35 to the first membrane stage. The residue stream, 24, from the first bank of modules passes as feed to die second bank of the first stage, 26. As in Example 31, the permeate streams 25 and 28 could be combined before or after recompression, and a condenser to remove water vapor could be included. The characteristics of die two types of membrane were assumed to be as follows: More hydrogen-sulfide-selective membrane:
Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/metiiane selectivity: 13
Methane flux: 7.5 x 1 Or6 cm3(STP)/cm2-s-cmHg
More carbon-dioxide-selective membrane:
Hydrogen sulfide/methane selectivity: 25 Carbon dioxide/metiiane selectivity: 20
Methane flux: 7.5 x 10 cm3(STP)/cm2-s-cmHg
The compositions of the various streams were calculated and are given in Table 13.
TABLE 13
Stream # CH4 conc. (vol%) H2S conc. (ppm) C02 cone. (vol%)
22 85.0 200 15.0
35 64.0 200 36.0
24 68.0 130 32.0
27 98.0 4 2.0
25 13.2 1,443 86.7
28 26.7 294 73.3
31 25.2 427 74.8
33 3.0 1,447 97.0
34 29.9 200 70.1
The membrane areas required were as follows: 21 m2 for membrane 23, 248 m2 for membrane 26 and 17 m2 for membrane 32. The residue stream 27 from the first stage meets pipeline specifications. The permeate stream 33 from the second stage contains about 1,500 ppm hydrogen sulfide and d e overall methane loss is about 0.4%. The feed stream to die second stage bank of modules, 32, contains 427 ppm hydrogen sulfide and 75 vol% carbon dioxide, a composition that falls in the more carbon-dioxide- selective membrane zone of the zone diagram. However, since it is not required to meet pipeline specification for the residue stream from the second stage, an optimized design provides better hydrogen sulfide recovery if the more hydrogen-sulfide-selective membrane is used. Example 33
A process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 1,000 ppm hydrogen sulfide, 15 vol% carbon dioxide and die remainder methane, a composition that falls in Zone D of Figure 1, but close to the boundary of Zone B. The process uses a membrane separation system as shown in Figure 7. Numerals 23, 26 and 32 indicate die tiiree banks of membrane modules; 23 and 32 contain die more hydrogen-sulfide-selective membrane; 26 contains the more carbon-dioxide-selective membrane. The incoming gas stream 22 is at 6,897 kPa (1,000 psia) and is mixed witii the residue stream 34 from the second stage to form the feed gas stream 35 to the first membrane stage. The residue stream, 24, from the first bank of modules passes as feed to die second bank of the first stage, 26. As in Examples 31 and 32, die permeate streams 25 and 28 could be combined before or after recompression, and a condenser to remove water vapor could be included. The characteristics of the two types of membrane
were assumed to be as follows:
More hydrogen-sulfide-selective membrane:
Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/methane selectivity: 13
Metiiane flux: 7.5 x IQ"6 cm3(STP)/cm2-s-cmHg
More carbon-dioxide-selective membrane:
Hydrogen sulfide/metiiane selectivity: 25 Carbon dioxide/methane selectivity: 20
Methane flux: 7.5 x 10-6 cm3(STP)/cm2-s-cmHg
The compositions of the various streams were calculated and are given in Table 14.
TABLE 14
Stream # CH4 conc. (vol%) H2S conc. (ppm) C02 cone. (vol%)
22 84.9 1,000 15.0
35 63.9 1,000 36.0
24 79.7 70 20.3
27 98.0 4 2.0
25 17.0 3,770 82.7
28 37.4 221 62.6
31 26.6 2,084 73.2
33 3.1 7,390 96.2
34 31.5 1,000 68.4
The membrane areas required were as follows: 119 m2 for membrane 23, 188 m2 for membrane 26 and 17 m2 for membrane 32. The residue stream 27 from the first stage meets pipeline specifications. The permeate stream 33 from the second stage contains about 0.7 vol% hydrogen sulfide and the overall methane loss is about 0.4%.
As with Example 31, an optimized design uses the more hydrogen-sulfide-selective membrane for the second stage. Example 34
A process was designed to handle a 28.3 NmVmin (1,000 scfm) gas stream containing 100 ppm hydrogen sulfide, 4 vol% carbon dioxide and the remainder methane, a composition that falls in Zone B
of Figure 1, but so close to the boundary of Zone D that the composition is just within Zone D after mixing with the recycle stream from the second membrane stage. The process uses a membrane separation system as shown in Figure 7. Numerals 23, 26 and 32 indicate the three banks of membrane modules; 23 and 32 contain the more hydrogen-sulfide-selective membrane; 26 contains the more carbon-dioxide-selective membrane. The incoming gas stream 22 is at 6,897 kPa (1,000 psia) and is mixed witii the residue stream 34 from the second stage to form die feed gas stream 35 to the first membrane stage. The residue stream, 24, from the first bank of modules passes as feed to the second bank of the first stage, 26. As in Examples 31-33, die permeate streams 25 and 28 could be combined before or after recompression, and a condenser to remove water vapor could be included. The characteristics of the two types of membrane were assumed to be as follows: More hydrogen-sulfide-selective membrane:
Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10'6 cm3(STP)/cm2-s-cmHg
More carbon-dioxide-selective membrane:
Hydrogen sulfide/methane selectivity: 25 Carbon dioxide/metiiane selectivity: 20
Methane flux: 7.5 x 10"6 cm3(STP)/cm2-sxmHg
The compositions of the various streams were calculated and are given in Table 15.
TABLE 15
Stream # CH4 conc. (vol%) H2S conc. (ppm) C02 cone. (vol%)
22 96.0 100 4.0
35 94.0 100 6.0
24 98.0 4 2.0
27 98.1 4 1.9
25 70.3 741 29.7
28 75.7 57 24.3
31 70.3 737 29.7
33 20.0 3,680 79.6
34 81.2 99 18.8 ___
The membrane areas required were as follows: 131 m2 for membrane 23, 1 m2 for membrane 26 and 9 m2 for membrane 32. The residue stream 27 from the first stage meets pipeline specifications. The permeate stream 33 from the second stage contains about 0.4 vol% hydrogen sulfide and the overall methane loss is about 0.5%.
SET 6
Examples 35-38 compare the performances of different types of membrane process for various feed gas compositions. The processes are not optimized, but are simply intended to highlight the difference between the respective performances. Example 35. No carbon dioxide: moderate amounts of hydrogen sulfide
A one-stage membrane process was designed to handle a gas stream containing 100 ppm hydrogen sulfide, die remainder metiiane, at a feed pressure of 6,897 kPa (1,000 psia). The process schematic is as shown in Figure 2, where numeral 1 indicates the bank of membrane modules, and the feed, residue and permeate streams are indicated by numerals 2, 3 and 4 respectively. The process was assumed to use one bank of more carbon-dioxide-selective membranes having die following characteristics:
Hydrogen sulfide/methane selectivity: 25 Carbon dioxide/methane selectivity: 20
Methane flax: 7.5 x 10* cm3(STP)/cm2-s-cmHg
The compositions and flow rates of die permeate and residue streams were calculated and are given in Table 16.
TABLE 16
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 (1,000 scfm) 23.6 (833 scfm) 4.7 (167 scfm)
CH4 conc. (vol%) 99.99 99.99 99.94
H2S cone, (ppm) 100 4 580
The membrane area used to perform such a separation was calculated to be about 200 m2. The stage cut was 17% and the methane loss into the permeate was 17% also.
The process design calculation was repeated using more hydrogen-sulfide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/metiiane selectivity: 13
Methane flux: 7.5 x IQ"6 cm3(STP)/cm2-s-cmHg
The compositions and flow rates of the permeate and residue streams were calculated and are given in Table 17.
TABLE 17
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 (1,000 scfm) 25.3 (892 scfm) 3.0 (108 scfm)
CH4 conc. (vol%) 99.99 99.99 99.91
H2S conc. (ppm) 100 4 890
The membrane area used to perform such a separation was calculated to be about 130 m2. The stage cut was 10.8% and the methane loss into the permeate was 10.8 % also.
Comparing the two calculations, the loss of methane into the permeate through the more hydrogen-sulfide-selective membrane is about 2/3 of that through the more carbon-dioxide-selective membrane. The permeate stream from the more hydrogen-sulfide-selective membrane is about 2/3 the volume and 1.5 times more concentrated tiian the permeate stream from the more carbon-dioxide-selective membrane, making further treatment much easier. The process with the more hydrogen-sulfide-selective membrane also uses less membrane area. Example 36. Small amounts of carbon dioxide: moderate amounts of hydrogen sulfide
A one-stage membrane process was designed to handle a gas stream containing 100 ppm hydrogen sulfide, 4 vol% carbon dioxide and the remainder metiiane, at a feed pressure of 6,897 kPa
(1,000 psia). The process schematic is as shown in Figure 2, where numeral 1 indicates the bank of membrane modules, and the feed, residue and permeate streams are indicated by numerals 2, 3 and 4 respectively. The process was assumed to use one bank of more carbon-dioxide-selective membranes having the following characteristics:
Hydrogen sulfide/metiiane selectivity: 25 Carbon dioxide/methane selectivity: 20
Methane flux: 7.5 x 10-6 cm3(STP)/cm -s-cmHg
The compositions and flow rates of the permeate and residue streams were calculated and are given in Table 18.
TABLE 18
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 (1,000 scfm) 22.8 (807 scfm) 5.5 (193 scfm)
CH4 conc. (vol%) 95.99 99.72 80.38
C02 conc. (vol%) 4.0 0.27 19.5
H2S conc. (ppm) 100 4 502
The membrane area used to perform such a separation was calculated to be about 200 m2. The stage cut was 19% and the methane loss into the permeate was 16%.
The process design calculation was repeated using more hydrogen-sulfide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10* cm3(STP)/cm -s-cmHg
The compositions and flow rates of the permeate and residue streams were calculated and are given in Table 19.
TABLE 19
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 (1,000 scfm) 24.8 (876 scfm) 3.5 (124 scfm)
CH4 conc. (vol%) 95.99 98.62 77.34
C02 conc. (vol%) 4.0 1.38 22.58
H2S cone, (ppm) 100 4 780
The membrane area used to perform such a separation was calculated to be about 120 m2. The stage cut was 12% and the metiiane loss into the permeate was 10%.
Comparing the two calculations, the methane losses, permeate concentration, permeate volume and membrane area are once again better with the more hydrogen-sulfide-selective membrane. It should also be noted that the more carbon-dioxide-selective membrane, in order to bring the residue stream hydrogen sulfide concentration to 4 ppm, reduces the carbon dioxide concentration to the low level of 0.27 vol%, which means that the gas stream has been significantly over-processed. Example 37. Large amounts of carbon dioxide: moderate amounts of hvdropen sulfide
A one-stage membrane process was designed to handle a gas stream containing 100 ppm
hydrogen sulfide, 30 vol% carbon dioxide and the remainder methane, at a feed pressure of 6,897 kPa
(1,000 psia). The process schematic is as shown in Figure 2, where numeral 1 indicates the bank of membrane modules, and die feed, residue and permeate streams are indicated by numerals 2, 3 and 4 respectively. The process was assumed to use one bank of more carbon-dioxide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 25 Carbon dioxide/metiiane selectivity: 20
Methane flux: 7.5 x 10* cm3(STP)/cm2-s-cmHg
The compositions and flow rates of the permeate and residue streams were calculated and are given in Table 20.
TA BLE 20
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 (1,000 scfm) 16.9 ( 598 scfm) 11.4 (402 scfm)
CH4 conc. (vol%) 69.99 97.99 28.34
CO- cone. (vol%) 30.0 2.0 71.64
H,S cone, (ppm) 100 3 244
The membrane area used to perform such a separation was calculated to be about 150 m2. The stage cut was 40% and die methane loss into the permeate was over 16%.
The process design calculation was repeated using more hydrogen-sulfide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/metiiane selectivity: 13
Methane flux: 7.5 x 10* cm3(STP)/cm2-s-cmHg
The compositions and flow rates of the permeate and residue streams were calculated and are given in Table 21.
TABLE 21
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 (1,000 scfm) 15.3 (541 scfm) 13.0 (459 scfm)
CH4 conc. (vol%) 69.99 98.0 37.0
C02 conc. (vol%) 30.0 2.0 62.97
H,S conc. (ppm) 100 4 218
The membrane area used to perform such a separation was calculated to be about 240 m2. The stage cut was 46% and the methane loss into the permeate was 24%.
Comparing the two calculations, the methane losses are high in both cases, because the process was not optimized In practise, a two-stage system should be used to reduce die metiiane loss and improve the permeate hydrogen sulfide concentration. It is clear, however, that the methane loss, permeate concentration, permeate volume and membrane area are all more favorable if the more carbon-dioxide- selective membrane is used. Example 38. Moderate amounts of carbon dioxide: moderate amounts of hydrogen sulfide
A one-stage membrane process was designed to handle a gas stream containing 100 ppm hydrogen sulfide, 10 vol% carbon dioxide and the remainder metiiane, at a feed pressure of 6,897 kPa (1 ,000 psia). The target was to just meet pipeline specification of 2 vόl% for carbon dioxide, without controlling the hydrogen sulfide concentration in the residue stream. The process schematic is as shown in Figure 2, where numeral 1 indicates the bank of membrane modules, and the feed, residue and permeate streams are indicated by numerals 2, 3 and 4 respectively. The process was assumed to use one bank of more carbon-dioxide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 25 Carbon dioxide/metiiane selectivity: 20
Methane flux: 7.5 x 10* cm3(STP)/cm2-s-cmHg
The compositions and flow rates of die permeate and residue streams were calculated and are given in Table 22.
TABLE 22
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 (1,000 scfm) 23.4 (828 scfm) 4.9 (172 scfm)
CH4 conc. (vol%) 89.99 97.99 51.41
C02 conc. (vol%) 10.0 2.0 48.54
H2S cone, (ppm) 100 14 516
As can be seen from the table, the residue stream, which still contains 14 ppm, does not meet pipeline specification for hydrogen sulfide.
The process design calculation was repeated using more hydrogen-sulfide-selective membranes
having the following characteristics:
Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/metiiane selectivity: 13
Methane flux: 7.5 x 10* cm3(STP)/cm2-s-cmHg
The compositions and flow rates of the permeate and residue streams were calculated and are given in Table 23.
TABLE 23
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 (1,000 scfm) 22.2 (783 scfm) 6.1 (217 scfm)
CH4 conc. (vol%) 89.99 97.99 61.05
C02 conc. (vol%) 10.0 2.0 38.91
HjS conc. (ppm) 100 <1 46
In this case, although the residue stream meets the 2 vol% carbon dioxide specification, the hydrogen sulfide content of the stream has been reduced to just below 1 ppm. This overprocessing results in a high methane loss of 15%.
The two calculations were repeated, using the hydrogen sulfide specification of 4 ppm as the target, but without controlling the carbon dioxide concentration in the residue stream. The results for the more more carbon-dioxide-selective membrane are given in Table 24, and for the more hydrogen-sulfide- selective membrane are given in Table 25.
TABLE 24
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 (1,000 scfm) 21.6 (764 scfm) 6.7 (236 scfm)
CH4 conc. (vol%) 89.99 99.28 59.90
C02 conc. (vol%) 10.0 0.72 48.05
H,S cone, (ppm) 100 4 411
As can be seen from the table, the residue stream, although it meets the 4 ppm hydogen sulfide specification, contains only 0.7 vol% carbon dioxide. This substantial overprocessing results in a high methane loss of 16%.
TABLE 25
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 ( 1,000 scfm) 24.1 (850 scfm) 4.2 (150 scfm)
CH4 conc. (vol%) 89.99 96.20 54.84
C02 conc. (vol%) 10.0 3.8 45.1
H2S conc. (ppm) 100 4 643
In tiiis case, the residue stream, which still contains nearly 4 vol% carbon dioxide, does not meet die pipeline specification for carbon dioxide.
The calculations were repeated, using a combination process design as in Figure 6, where numeral 23 indicates a more hydrogen-sulfide-selective bank of membrane modules and numeral 26 indicates a more carbon-dioxide-selective bank of membrane modules. The incoming gas stream 22 is at 6,897 kPa (1,000 psia). The residue stream 24 from the first bank of modules forms the feed to die second bank.
The more hydrogen-sulfide-selective membrane was assumed to have die following characteristics:
Hydrogen sulfide/metiiane selectivity: 50 Water vapor/methane selectivity: 1,000 Carbon dioxide/metiiane selectivity: 13
Methane flux: 7.5 x 10* cm3(STP)/cm2-s-cmHg
The more carbon-dioxide-selective membrane was assumed to have die following characteristics:
Carbon dioxide/metiiane selectivity: 20 Hydrogen sulfide/methane selectivity: 25 Water vapor/methane selectivity: 200
Methane flux: 7.5 x 10* cm3(STP)/cm2-s-cmHg
The compositions and flow rates of the permeate and residue streams from each bank of modules were calculated and are given in Table 26.
TABLE 26
STREAM FEED RESIDUE PERMEATE
FIRST MODULE BANK (more hydrogen-sulfide-selective membrane)
Flow rate (NmVmin) 28.3 (1,000 scfm) 25.5 (900 scfm) 2.8 (99.7 scfm)
CH4 conc. (vol%) 89.99 94.38 50.35
CO- cone. (vol%) 10.0 5.62 49.57
H2S conc. (ppm) 100 14 876
SECOND MODULE BANK (more carbon-dioxide-selective membrane)
Flow rate (NmVmin) 25.5 (900 scfm) 23.0 (812 scfm) 2.5 (88.4 scfm)
CH4 conc. (vol%) 94.38 97.98 61.35
CO, cone. (vol%) 5.62 2.01 38.65
H2S conc. (ppm) 14 4 106
The combination process performs better than either of the single membrane processes in this composition range. The total membrane area used is about 135 m2. Residue stream 27 from the second stage meets pipeline specifications. If the permeate streams 25 and 28 from die two banks of membrane modules are pooled die permeate composition is 510 ppm hydrogen sulfide, 44 vol% carbon dioxide and 56 vol% methane. The methane loss in die pooled permeates is about 11.5%. This loss could be reduced if die process were optimized. SET 7
Examples 39 and 40 show treatment processes in which the membrane process does not bring the gas stream to pipeline specification for all components. Example 39. Membrane plus scavenging process
A process was designed to handle a gas stream containing 1 ,000 ppm hydrogen sulfide, 0.1 vol% water vapor, 4 vol% carbon dioxide and die remainder metiiane, at a feed pressure of 6,897 kPa (1,000 psia). The process includes a one-stage membrane separation step, followed by a scavenging step to bring the hydrogen sulfide concentration down further to 4 ppm. The scavenging step could be carried out using an iron sponge, for example. The process was assumed to use one bank of more hydrogen- sulfide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 80
Water vapor/methane selectivity: 1,000
Carbon dioxide/methane selectivity: 12
Methane flux: 1 x 10* cm3(STP)/cm2-s-cmHg
The compositions and flow rates of die permeate and residue streams were calculated and are given in Table 27.
TABLE 27
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 2.8 (100 scfm) 2.5 (90.3 scfm) 0.3 (9.7 scfm)
CH4 conc. (vol%) 95.8 98 74.9
C02 conc. (vol%) 4.0 1.9 23.1
H,S conc. (ppm) 1,000 40 990
Water vapor cone. (vol%) 0.1 2 ppm 1.0
The membrane area used was calculated to be about 70 m2. The stage cut was just under 10% and the methane loss into the permeate was 7.6%. The process produces a residue stream that meets pipeline specification for carbon dioxide and water vapor, but needs further polishing to remove hydrogen sulfide.
Example 40. Process including amine plant for hvdropen sulfide removal
A process was designed to handle a gas stream containing 0.5 vol % hydrogen sulfide, 20 vol% carbon dioxide and die remainder methane, at a feed pressure of 6,897 kPa ( 1 ,000 psia). The process uses a one-stage membrane separation step to carry out a first separation of carbon dioxide and hydrogen sulfide, followed by an amine plant to bring die stream to pipeline specification. The process was assumed to use one bank of more hydrogen-sulfide-selective membranes having the following characteristics:
Hydrogen sulfide/methane selectivity: 50 Carbon dioxide/methane selectivity: 13
Methane flux: 7.5 x 10* cm3(STP)/cm2-s-cmHg
The compositions and flow rates of the permeate and residue streams were calculated and are given in Table 28.
TABLE 28
STREAM FEED RESIDUE PERMEATE
Flow rate (NmVmin) 28.3 (1,000 scfm) 23.8 (840 scfm) 4.5 (160 scfm)
CH4 conc. (vol%) 79.5 88.8 30
CO- cone. (vol%) 20 11.1 67
H2S conc. (vol%) 0.5 0.05 2.9
The membrane area used was calculated to be about 70 m2. The stage cut was just under 16% and the methane loss into die permeate was 6%. The process produces a residue stream from which 90% of the hydrogen sulfide and about 50% of the carbon dioxide has been removed. This residue stream passes to the amine plant for additional treatment to bring it within specification for carbon dioxide and hydrogen sulfide.
Claims
1. A membrane process for treating a gas stream comprising hydrogen sulfide, carbon dioxide and methane, said process comprising the following steps:
(a) providing a feed stream containing carbon dioxide in a concentration less than about 3% to less than about 10% and hydrogen sulfide in a concentration more than about 10 ppm to more than about 300 ppm, with the lower end of die carbon dioxide range corresponding to the lower end of the hydrogen sulfide range (<3% carbon dioxide; >10 ppm hydrogen sulfide) and the upper end of the carbon dioxide range corresponding to the upper end of the hydrogen sulfide range (<10% carbon dioxide; >300 ppm hydrogen sulfide);
(b) passing said feed stream through a membrane unit containing a membrane characterized by a selectivity for hydrogen sulfide over methane of at least 35 and a selectivity for carbon dioxide over methane of at least 12, said selectivity being measured with a mixed gas stream containing at least hydrogen sulfide, carbon dioxide and metiiane and at a feed pressure of at least 500 psig;
(c) withdrawing from said membrane unit a residue stream containing carbon dioxide in a concentration no greater than about 3 vol% and hydrogen sulfide in a concentration no greater than about 20 ppm.
2. A membrane process for treating a gas stream comprising hydrogen sulfide, carbon dioxide and methane, said process comprising die following steps:
(a) providing a feed stream containing carbon dioxide in a concentration less than about 10% to less than about 20% and hydrogen sulfide in a concentration more than about 300 ppm to more than about 600 ppm, with the lower end of the carbon dioxide range corresponding to the lower end of die hydrogen sulfide range (<10% carbon dioxide; >300 ppm hydrogen sulfide) and the upper end of the carbon dioxide range corresponding to the upper end of die hydrogen sulfide range (<20% carbon dioxide; >600 ppm hydrogen sulfide);
(b) passing said feed stream through a membrane unit containing a membrane characterized by a selectivity for hydrogen sulfide over methane of at least 35 and a selectivity for carbon dioxide over methane of at least 12, said selectivity being measured with a mixed gas stream containing at least hydrogen sulfide, carbon dioxide and metiiane and at a feed pressure of at least 500 psig;
(c) withdrawing from said membrane unit a residue stream containing carbon dioxide in a concentration no greater than about 3 vol% and hydrogen sulfide in a concentration no greater than about 20 ppm.
3. A membrane process for treating a gas stream comprising hydrogen sulfide, carbon dioxide and methane, said process comprising the following steps:
(a) providing a feed stream containing carbon dioxide in a concentration less than about 20% to less than about 40% and hydrogen sulfide in a concentration more tiian about 600 ppm to more than about 1%, with die lower end of the carbon dioxide range corresponding to the lower end of the hydrogen sulfide range (<20% carbon dioxide; >600 ppm hydrogen sulfide) and the upper end of die carbon dioxide range corresponding to the upper end of die hydrogen sulfide range (<40% carbon dioxide; >1% hydrogen sulfide);
(b) passing said feed stream through a membrane unit containing a membrane characterized by a selectivity for hydrogen sulfide over metiiane of at least 35 and a selectivity for carbon dioxide over methane of at least 12, said selectivity being measured witii a mixed gas stream containing at least hydrogen sulfide, carbon dioxide and metiiane and at a feed pressure of at least 500 psig;
(c) withdrawing from said membrane unit a residue stream containing carbon dioxide in a concentration no greater than about 3 vol% and hydrogen sulfide in a concentration no greater than about 20 ppm.
4. The process of claim 1 , 2, or 3, wherein said selectivity for hydrogen sulfide over metiiane is at least 50.
5. The process of claim 1, 2, or 3, wherein said feed pressure at which said selectivity can be obtained is at least 1,000 psig.
6. The process of claim 1, 2, or 3, wherein said residue stream contains carbon dioxide in a concentration no greater than about 2 vol%.
7. The process of claim 1, 2, or 3, wherein said residue stream contains hydrogen sulfide in a concentration no greater than about 4 ppm.
8. The process of claim 1, 2, or 3, wherein said membrane comprises a composite membrane having a selective layer comprising a polymer that is rubbery under the operating conditions of the process.
9. The process of claim 1, 2, or 3, wherein said membrane comprises a block copolymer containing a polyether block.
10. The process of claim 1, 2, or 3, wherein said membrane comprises a polyamide-polyetiier block copolymer having the general formula
HO -P- C — PA — C — O — PE — C -^- H
I — II II _l n
wherein PA is a polyamide group, PE is a polyether group and n is a positive integer.
11. The process of claim 1, 2, or 3, wherein said feed stream comprises natural gas.
12. The process of claim 1, 2, or 3, further comprising:
(d) withdrawing from said membrane unit a permeate stream enriched in carbon dioxide and hydrogen sulfide and having a methane content such that methane loss from said feed stream is no more than about 5%.
13. The process of claim 12, wherein said metiiane loss is no more than about 2%.
14. The process of claim 1, 2, or 3, wherein said feed stream contains carbon dioxide, hydrogen sulfide and water vapor, all in concentrations above pipeline specification, and wherein said residue stream meets pipeline specifications for carbon dioxide, hydrogen sulfide and water vapor.
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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US143,496 | 1980-04-24 | ||
US08/143,496 US5407467A (en) | 1993-10-25 | 1993-10-25 | Sour gas treatment process |
Publications (1)
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WO1995011738A1 true WO1995011738A1 (en) | 1995-05-04 |
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ID=22504341
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PCT/US1994/012099 WO1995011738A1 (en) | 1993-10-25 | 1994-10-21 | Sour gas treatment process |
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US (1) | US5407467A (en) |
CA (1) | CA2174347A1 (en) |
WO (1) | WO1995011738A1 (en) |
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