WO1986002628A1 - Procede d'elimination du sulfure d'hydrogene contenu dans des gaz - Google Patents

Procede d'elimination du sulfure d'hydrogene contenu dans des gaz Download PDF

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Publication number
WO1986002628A1
WO1986002628A1 PCT/US1985/002179 US8502179W WO8602628A1 WO 1986002628 A1 WO1986002628 A1 WO 1986002628A1 US 8502179 W US8502179 W US 8502179W WO 8602628 A1 WO8602628 A1 WO 8602628A1
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Prior art keywords
hydrogen sulfide
solvent
sulfur dioxide
gas
solution
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PCT/US1985/002179
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English (en)
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Scott Lynn
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The Regents Of The University Of California
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Publication of WO1986002628A1 publication Critical patent/WO1986002628A1/fr

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    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/46—Removing components of defined structure
    • B01D53/48—Sulfur compounds
    • B01D53/52—Hydrogen sulfide
    • B01D53/523—Mixtures of hydrogen sulfide and sulfur oxides
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1456—Removing acid components
    • B01D53/1468—Removing hydrogen sulfide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1456—Removing acid components
    • B01D53/1481—Removing sulfur dioxide or sulfur trioxide
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B17/00—Sulfur; Compounds thereof
    • C01B17/02—Preparation of sulfur; Purification
    • C01B17/04—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides
    • C01B17/05—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by wet processes

Definitions

  • This invention relates to the removal of hydrogen sulfide from gases.
  • One method of removing hydrogen sulfide from a gas is by absorbing it physically in an organic solvent and then reacting it with a solution of sulfur dioxide in the same solvent in accordance with the following equation:
  • the sulfur dioxide may be derived from an outside source, or it may be produced by burning some of the hydrogen sulfide in accordance with the following reaction
  • a second, related, method of removing hydrogen sulfide from such a gas is by absorbing it chemically in an organic solvent that contains dissolved sulfur dioxide. Reaction (1) then occurs as the hydrogen sulfide is absorbed and may accelerate the absorption process.
  • Still -a third related method of removing hydrogen sulfide from such a gas is to add sulfur dioxide to the gas and then to contact the gas with an organic solvent.
  • the hydrogen sulfide and sulfur dioxide are absorbed simultaneously and Reaction (1) occurs as absorption takes place.
  • Patent 3,953,586 to Tani ura dissolves hydrogen sulfide- from a gas in a solvent such as N-methyl-2-pyrrolidone, then reacts the hydrogen sulfide with sulfur dioxide also dissolved in that solvent.
  • the proportion of hydrogen sulfide and sulfur dioxide in the reactor are such that there is an excess of hydrogen sulfide which leaves in the exiting solution and is removed in a stripper.
  • the hydrogen sulfide removed in the stripper is then burned to produce sulfur dioxide for Reaction (1) .
  • the Tanimura process requires that one-third of the hydrogen sulfide pass through the reaction zone unreacted, that this excess hydrogen sulfide be stripped from its solvent and burned to produce sulfur dioxide in accordance with Reaction (2), and that the resulting sulfur dioxide be absorbed in the same solvent. This is an energy-intensive process. It also results in the loss of any other gas that is co-absorbed with the hydrogen sulfide.
  • the difficulties encountered in the prior art are solved by absorbing hydrogen sulfide from a gas in a solvent having the characteristics described below; providing a solution in the same solvent of sulfur dioxide; mixing the two solutions in proportions such that the hydrogen sulfide is in small excess and causing reaction to occur in a first reaction zone; providing a zone of substantial liquid capacitance for hydrogen sulfide to effect a method of damping the fluctuations in hydrogen sulfide concentration in the vapor or liquid streams leaving the first reaction zone; and providing a second reaction zone in which the hydrogen sulfide leaving the first reaction zone reacts substantially to completion according to Reaction (1) with sulfur dioxide solution that has been introduced thereinto.
  • the zone of substantial liquid capacitance for hydrogen sulfide may coincide either with the first reaction zone or with the second reaction zone, or may be separate from both.
  • the hydrogen sulfide leaving the first reaction zone may be transferred directly to the second reaction zone by a stream of vapor or liquid leaving the first reaction zone or, alternatively, may first be stripped from the liquid in which it is dissolved by a vapor stream and then be reabsorbed from that vapor into the liquid in the second reaction zone.
  • the sulfur formed via Reaction (1) in either reaction zone may either remain dissolved in the solvent or precipitate, forming a slurry of crystals in the liquid in the reaction zone. Examples of these methods of employing this invention are illustrated in the following process descriptions.
  • Figure 1 is a flow diagram showing one embodiment of the invention
  • FIG. 2 is a similar flow diagram showing an alternative embodiment
  • Figure 3 is a flow diagram of a third embodiment of the invention in which a gas at near-atmospheric pressure that contains hydrogen sulfide such as a Claus process tail 'gas, is treated;
  • Figure 4 is a flow diagram of an embodiment of the invention in which a gas at high pressure, such as synthesis gas, is treated to remove hydrogen sulfide and and also, where present as in synthesis gas, carbon dioxide;
  • a gas at high pressure such as synthesis gas
  • Figure 5 is a flow diagram similar to Figure 4 but illustrating a-modification in which the reaction between hydrogen sulfide and sulfur dioxide is carried out under conditions to cause crystallization of sulfur.
  • FIG. 1 there are shown a Hydrogen sulfide absorber 10, a stripper-absorber 11, a solvent dehydrator 12, a sulfur crystallizer 13, a furnace 14, and a sulfur dioxide absorber 15.
  • this feed gas is natural gas which contains typically about 0.01 to 10 percent of hydrogen sulfide and small amounts of water and hydrocarbons higher than methane, chiefly propane and butane.
  • the bulk of the gas is methane and it is desired to remove hydrogen sulfide so that the amount remaining in the treated gas is one part per million or less.
  • Other feed gases may, if desired, be treated, for example refinery gases from hydrotreating crude oil, synthesis gas obtained from petroleum or coal, and similar hydrogen-sulfide- containing gas streams.
  • the removal of one or more of the minor components such as ethane or higher hydrocarbons may be unnecessary or undesired, but in the case illustrated by Figure 1 it is desired to remove and recover higher hydrocarbons.
  • a suitable solvent selected from Table I below enters absorber 10 through line 17.
  • This solvent is selected in accordance with the following criteria: It is a very strong solvent for sulfur dioxide and it has good solvating properties for hydrogen sulfide but less than its solvating property for sulfur dioxide. Solubility of various components of the feed gas in the solvent are as • follows: S0 >>5i2 s>C0S c 3 H 8 ' Further, the solvent is selected to -promote Reaction (1). Criteria of the solvent are further elaborated below.
  • Suitable contacting equipment such as various commercially available trays or packing may be employed to promote contact between the feed gas and the solvent in absorber 10.
  • the process is conducted so that the gas leaving through line 18 has an acceptably low content of hydrogen sulfide, e.g. one ppm or less.
  • the treatment in absorber 10 is at a low temperature, for example 0° to 30°C, in order to favor absorption of hydrogen sulfide in the solvent.
  • the resulting solution leaving through line 19 is heated at 20 by indirect heating, for instance by using steam as the heating medium, e.g. to 80° to 120°C sufficient to maintain sulfur in solution.
  • the steam used for this purpose may be generated in the process itself or it may come from an outside source or there may be a mix of the two sources of steam.
  • a solution of sulfur dioxide generated as described below joins line 19 through line 25 and the combined streams, suitably mixed as by means of a mixing tee (not shown), pass through a tube 26 which constitutes the first reaction zone where Reaction (1) occurs.
  • hydrogen sulfide is present in excess.
  • Typical concentrations of hydrogen sulfide and the sulfur dioxide in the reacting stream at the point of mixing and " before reaction has occurred are about 0.1 to 10 percent sulfur dioxide and 0.1 to 10 percent hydrogen sulfide.
  • Reaction (1) is exothermic and, since the solvent is selected to promote Reaction (1) the reaction is very rapid and goes to completion within a few seconds and a correspondingly short distance.
  • the proportions in which the two streams are mixed are such that there is a small excess of hydrogen sulfide.
  • This excess hydrogen sulfide is typically such that the solution entering the stripper section 11A of stripper-absorber 11 contains about 0.001 to 0.1 percent of hydrogen sulfide.
  • a large fraction of this dissolved hydrogen sulfide is stripped from the solution in the stripper section 11A of the stripper-absorber 11.
  • a portion of the sulfur dioxide solution is diverted from stream 25 into line 27 and is introduced into the reactive absorber section 11B of stripper-absorber 11.
  • the proportion so diverted is in excess of that required to react with the excess of hydrogen sulfide introduced into the stripper section 11A of stripper-absorber 11.
  • the reactive absorber section 11B thus forms a second reaction zone, one in which sulfur dioxide is present in excess. This will carry Reaction (1) to completion so that no appreciable quantity of hydrogen sulfide remains and it results in a solution of sulfur in this solvent which also contains much of the sulfur dioxide that enters the stripper-absorber 11 through line 27.
  • the resulting vapor in the top section 11C of stripper-absorber 11, which is completely free of hydrogen sulfide, contains some sulfur dioxide that is absorbed by fresh, neat solvent entering through line 30.
  • the light gases leaving stripper-absorber 11 through line 35 are thus substantially free of both hydrogen sulfide and sulfur dioxide.
  • the stripper-absorber 11 is shown as having a tray 31 between stripper section 11A and absorber (second reaction) zone 11B.
  • the tray is a chimney type of tray which permits vapor to pass from section 11A into section llB but prevents liquid from flowing from section 11B into section 11A.
  • it is relatively easy to maintain a net stoichiometric ratio of sulfur dioxide to hydrogen sulfide.
  • stripping zone 11A a small excess of hydrogen sulfide is maintained and the amount and fluctuation of this excess in the vapor phase is monitored and used to control the flow of sulfur dioxide solution through line 25 into reaction zone 26. If the concentration of hydrogen sulfide in the vapor in zone 11A becomes too small the rate of flow of sulfur dioxide solution will be diminished whereas if the concentration of hydrogen sulfide becomes too great the rate of flow of sulfur dioxide solution will be increased.
  • This procedure precludes the need to maintain a stoichiometric ratio of hydrogen sulfide to sulfur dioxide in reaction zone 26; the amount of hydrogen sulfide in the vapor in zone 11A is easily monitored and need not be maintained at a precise level but may fluctuate between limits; the management of flow of sulfur dioxide solution into reaction zone 26 is easy to accomplish; and the process lends itself to automated control by control equipment that is commercially available.
  • the flow of sulfur dioxide solution through line 27 into reactive absorber section 11B is kept at a constant value.
  • the capacitance for hydrogen sulfide of the solution inventory in this section of the stripper-absorber 11, provided by the excess sulfur dioxide in the solution effectively dampens the fluctuations in the net flow of hydrogen sulfide.
  • the liquid phase is removed from the bottom of stripper-absorber 11 through line 41.
  • This liquid phase may be a homogeneous solution of sulfur, water and higher hydrocarbons in the solvent or it may be a two-phase liquid mixture of such a solution and liquid sulfur. It is heated by steam in heater 42 and a portion of the heated liquid is returned through line 43 to the bottom of stripper-absorber 11. Therefore the heater 42 also serves as a reboiler.
  • the liquid phase or phases passing forwardly through line 41 enters solvent dehydrator 12 at its mid-portion. Water is evaporated and leaves the solvent dehydrator along with hydrocarbon vapor, chiefly butane vapor, through line 44 and is condensed in cooler 45. The condensate passes by line 44 to vessel 50.
  • Two phases are present in vessel 50, namely a lower aqueous phase and an upper hydrocarbon phase.
  • the aqueous phase is removed from the system through line 51.
  • a portion of the hydrocarbon phase is returned to the upper end of the solvent stripper 12 through line 52 to serve as reflux and the remainder of the hydrocarbon phase is recovered through line 53 as a by-product. : : ' .
  • the dehydrated solvent leaves the bottom of solvent dehydrator 12 through line 54.
  • a portion of the liquid is vaporized in reboiler 55 and returned to the bottom of solvent dehydrator 12 through line 56 and the remainder of the solvent proceeds by line 57 to sulfur crystallizer 13.
  • Sulfur crystallizer 13 may be of conventional design and mode of operation, for example the solvent may be cooled.by means of direct contact with liquid propane refrigerant. This results in the crystallization of sulfur. Suitable equipment (not shown) is employed to separate the solid sulfur from the solvent which is returned by way of line 17 to the top of absorber 10 and the top of stripper-absorber 11. One-third of the sulfur proceeds by way of line 60 to furnace 14 and two-thirds is withdrawn from the system through line 61.
  • Furnace 14 is supplied with air by compressor 62.
  • the proportion of sulfur diverted to furnace 14 is sufficient to provide the sulfur dioxide needed for Reaction (1).
  • the heat of Reaction (3) is used to generate steam in steam coil 64. This steam may be used in the system.
  • the gas phase (sulfur dioxide, nitrogen, etc.) leaves the furnace by way of line 65 and enters sulfur dioxide absorber 15. This sulfur dioxide is absorbed in a stream of solvent diverted from line 17 through line 66. This step may be conducted so that the stack gas leaving through line 67 contains only a trace of sulfur dioxide.
  • a solution of sulfur dioxide leaves the bottom of sulfur dioxide absorber 15 through line 25 and re-enters the system.
  • FIG. 2 a variant is shown which is applicable to a situation in which it is not necessary to recover gases such as propane and other higher hydro- carbons.
  • gases such as propane and other higher hydro- carbons.
  • An example is the removal of hydrogen sulfide from a raw synthesis gas -- a mixture of hydrogen, carbon monoxide, carbon dioxide, methane and other, very minor components.
  • the conditions in hydrogen sulfide absorber 10, such as the choice of solvent and the conditions of operation, will be such that only hydrogen sulfide and carbon dioxide are absorbed.
  • the unit 11 will not function as a hydrogen sulfide absorber or reactor; therefore the gas leaving this unit through line 35 will contain a small amount of hydrogen sulfide which, along with other uncondensable gases, principally carbon dioxide, will be separated from water by cooler 36 and the water phase will be removed through line 40.
  • the noncondensable gases will leave through line 38 and go to sulfur dioxide absorber 15 which will result in reaction of this small excess of hydrogen sulfide with the sulfur dioxide in the absorber 15. It will therefore be apparent that the sulfur dioxide absorber 15 performs the function of zone 11B in unit 11 in Figure 1, providing both a zone of substantial liquid capacitance for hydrogen sulfide and the second reaction zone for the process.
  • FIG. 3 the application of the present invention to the treatment of a gas at near- atmospheric pressure is illustrated.
  • hydrogen sulfide When hydrogen sulfide is present in such a gas, especially when its concentration is also relatively low, it may not be practical to absorb the hydrogen sulfide physically as an initial step. The solvent flow required might then be excessively high.
  • hydrogen sulfide is the only component that one wishes to remove from a gas stream, it may be desired to keep the flow of solvent as low as possible to minimize co-absorption of other components.
  • the process configuration shown in Figure 3 is a preferred embodiment of this invention.
  • This process configuration is also suitable for treating the tail gas from a Claus process sulfur plant.
  • Such a gas contains sulfur dioxide as well as hydrogen sulfide.
  • the Claus process carries out Reaction (1) in the vapor phase by contacting a mixture of hydrogen sulfide and sulfur dioxide in the vapor phase with a solid catalyst.
  • the hydrogen sulfide and sulfur dioxide are employed in stoichiometric ratio; the reaction is carried out at an elevated temperature and results in an equilibrium in which about five percent of the H 2 S/S0 2 mixture is unreacted; and this gaseous mixture (the tail gas) requires treatment before it can be vented to the atmosphere.
  • the hydrogen sulfide results from absorbing it from a gas, for example natural gas or a process gas, into an alkaline solution such as an aqueous solution of ethanolamine or sodium carbonate from which it is then stripped by steam and is used in the Claus process.
  • the gas to be treated (whether from a Claus .plant or from some other source) enters reactor-absorber 84 through line 85.
  • the gas stream is usually kept well above the dewpoint of water because of the corrosive nature of the sulfoxy acid compounds that form in liquid water when ,__ both hydrogen sulfide and sulfur dioxide are present (Wackenroder's liquid).
  • the gas enters the bottom section 84a of absorber 84 which has a reactor section 84b and an upper section 84c.
  • a solution of sulfur dioxide enters the top of section ' 84b through line 86.
  • hydrogen sulfide reacts with both the sulfur dioxide entering with it through line 85 and with the sulfur dioxide entering with the solvent in line 86.
  • the liquid stream leaving the reactor section of column 84 contains a small amount of dissolved hydrogen sulfide, which is stripped from the liquid by steam that is introduced through line 90 at the bottom of the stripper section 84a either by direct injection or by boiling water out of the solvent mixture by indirect heat exchange.
  • the liquid stream leaving the bottom of column 84 through line 91 is thus substantially free of dissolved hydrogen sulfide and sulfur dioxide, but contains in solution the sulfur that has been formed by reaction. This stream is then sent to a crystallizer for recovery of sulfur as has been previously described.
  • the gas stream in line 88 enters the bottom of reactor-absorber column 92.
  • a fixed flow of sulfur dioxide solution enters the top of the reactor section 92a of column 92 through line 93.
  • the sulfur dioxide contained in this stream is in small excess over the hydrogen sulfide contained in the gas stream from line 88, so that substantially all of the hydrogen sulfide is removed from the gas stream as it passes through section 92a of column 92.
  • Fresh, neat solvent entering the absorber section 92b of column 92 through line 94 serves to reabsorb any sulfur dioxide that may have been stripped from solution by the gas stream as it passed through the reactor section of column 92.
  • the gas stream leaving column 92 through line 95 is thus substantilly free of both hydrogen sulfide and sulfur dioxide and may be discharged to the atmosphere.
  • the liquid stream leaving column 92 through line 96 contains unreacted sulfur dioxide and is pumped by pump 97 to column 84 as previously noted.
  • the sulfur dioxide used to form the sulfur dioxide solution that enters through lines 89 and 93 can be produced by burning either hydrogen sulfide or part of the sulfur made in this process. As before, the heat released in the combustion can be used to produce steam.
  • the process configuration in Figure 3 makes use of two reaction zones, one in which hydrogen sulfide is in excess and one in which sulfur dioxide is in excess.
  • the control of the exact stoichiometry of the reaction is made relatively simple by the capacitance for hydrogen sulfide of- solvent containing sulfur dioxide, which allows moderate variations in the hydrogen sulfide content of the tail gas from the Claus plant to occur without upsetting the control of the process.
  • the gas stream entering through line 85 must contain a ratio of hydrogen sulfide to sulfur dioxide that is substantially greater than 2. This excess hydrogen sulfide can be provided by bypassing part of the hydrogen sulfide around the Claus plant if it proves undesireable to operate the Claus plant with such an excess.
  • the process shown in Figure 3 is not limited to the treatment of the tail gas from a Claus plant nor to the treatment of a gas stream containing both hydrogen sulfide and sulfur dioxide. It is suitable as an alternative to the process shown in Figure 1 for treating any gas stream that contains hydrogen sulfide, but is particularly suitable for treating low-pressure gas streams because of the reduced flow of solvent that is required.
  • heating or cooling of some of the streams in Figure 3 may be required in some instances, and that columns 84 and 92 could be consolidated if desired.
  • the gas to be treated in this example is raw "synthesis gas", a mixture of hydrogen and carbon monoxide that contains carbon dioxide and hydrogen sulfide as undesireable components.
  • the pressure of the gas stream is relatively high, typically at about 40 atmospheres.
  • the gas to be treated enters high-pressure absorber 97 through line 98.
  • Lean solvent enters through line 99 and contacts the gas in absorber 97 countercurrently, absorbing most of the carbon dioxide and substantially all of the hydrogen sulfide from the gas, which leaves absorber 97 through line 100.
  • Small amounts of hydrogen and carbon monoxide are co-absorbed in the solvent stream, which leaves absorber 97 through line 101. This hydrogen and carbon dioxide are stripped from the solvent in the operation described below and are returned, together with some carbon dioxide and hydrogen sulfide, through line 102.
  • reaction (1) occurs in line 105 before the combined streams enter stripper 106, where hydrogen and carbon monoxide are stripped from the solvent.
  • the temperature of the stream in line 105 is monitored and heater 103 supplies any heat that is needed to ensure that sulfur does not precipitate.
  • the quantity of sulfur dioxide entering through line 104 is regulated to be about 90 to 99 per cent of that required to react with all of the hydrogen sulfide in the stream in line 101. This regulation is accomplished by monitoring the hydrogen sulfide content of the gas leaving stripper 106 through line 102 and keeping it at a relatively low, constant value.
  • the stripping vapor in stripper 106 is predominantly carbon dioxide, which is boiled out of solution in line 107 as a result of heat supplied by heater 108.
  • the purpose of this stripping vapor is not only to recover hydrogen and carbon monoxide from the solvent but also to homogenize the hydrogen sulfide concentration in the solvent.
  • the concentration of hydrogen sulfide in the solvent leaving stripper 106 through line 109 will have a relatively constant value that is about one-tenth to one-hundredth that of the stream leaving absorber 97 through line 101.
  • This remaining hydrogen sulfide is eliminated by adding a second regulated stream of sulfur dioxide through line 110.
  • Reaction (1) occurs in line 111 before the solvent mixture reaches cooler 112.
  • the sulfur content (either hydrogen sulfide or sulfur dioxide) of the carbon dioxide stream leaving crystallizer 113 through line 114 is negligible.
  • the flow of sulfur dioxide solution through line 110 is regulated to keep the sulfur compound level in line 114 in the low parts-per-million range. It is advantageous to maintain a slight excess of sulfur dioxide in the solvent leaving line 111. Because of its higher solubility, a given excess of sulfur dioxide in the solvent results in substantially less sulfur content of the gas in line 114 than does a similar excess of hydrogen sulfide.
  • Cooler 112 reduces the solvent temperature to-the point of incipient sulfur precipitation. Additional cooling is produced when the dissolved carbon dioxide flashes from solution at the pressure of the crystallizer.
  • the operations of the crystallizer 113, the sulfur furnace and boiler 116, and the sulfur dioxide absorber 117 are similar to those described in the previous examples. Solvent leaves crystallizer 113 through line 118 and a portion is diverted to sulfur dioxide absorber 117 where it absorbs sulfur dioxide from furnace 116 entering through line 119. A portion of the sulfur leaving crystallizer 113 is diverted through line 115a to furnace 116.
  • the process configuration of Figure 4 depends upon having two reaction zones and a method of homogenizing the concentration of the liquid stream passing from the first zone to the second by utilizing the capacitance of the solution for dissolved hydrogen sulfide.
  • the zone of high capacitance in this example is located between the two reaction zones. Again in this example it is essential to have excess hydrogen sulfide in the first reaction zone and advantageous to have excess sulfur dioxide in the second reaction zone. However, in this example it is feasible to operate with a small excess of hydrogen sulfide in the second reaction zone as well.
  • FIG. 5 An example of this method of practicing the invention is shown in Figure 5, a modified version of Figure 4. : - • ,
  • the high-pressure absorber 97 is operated as described with reference to Figure 4, and flow lines and pieces of equipment that remain unchanged bear the same reference numerals as in Figure 4.
  • the rich solvent leaving absorber 97 through line 101 is cooled in exchanger 103 to near the temperature of the cooling water before it enters flash cha ber-crystallizer 120.
  • the pressure is reduced to flash carbon dioxide from solution in sufficient quantity to obtain the desired temperature.
  • Sulfur dioxide solution enters 120 through line 104 at a metered rate that is regulated to maintain a constant, small fraction of unreacted hydrogen sulfide in the gas leaving 120 through line 102.
  • This gas is compressed to the pressure of absorber 97 in compressor 121 and returned to the bottom of the absorber.
  • the liquid stream leaving flash chamber-crystallizer 120 through line 109 contains a slurry of sulfur crystals and a small, nearly constant concentration of unreacted hydrogen sulfide.
  • sulfur dioxide solution is added to this stream through line 110 in nearly exact stoichiometric ratio, as determined by monitoring for traces of unreacted hydrogen sulfide or sulfur dioxide in the sweet carbon dioxide in line 114 that has flashed from solution in crystallizer 113.
  • Reactor-crystallizer 120 is a stirred-tank reactor, with well-defined capacitance characteristics.
  • the organic solution or solvent should, as stated above, be one in which sulfur dioxide has a high solubility and which has a solvating power for hydrogen sulfide and other concomitants in accordance with the following descending scale: S0 2 >>H 2 S>COS and mercaptans >C0 2 , C3H 8 .
  • the solvating power of the solvent for the major constituents of the gas should of course be quite low. Further, the solvent should promote Reaction (1) and it should not form strong chemical complexes with sulfur dioxide or with constituents of the feed gas. Where it is desired to remove water from the feed gas a more polar solvent is indicated.
  • the solvent should have moderate miscibility with water and should be a moderately good solvent for sulfur, for example, 'capable of dissolving at 25°C one gram per liter or more.
  • solvent may be modified by including a less polar component.
  • Solvent mixtures i.e., “mixtures” in the sense of two or more liquid components which are in solution as a homogeneous phase
  • mixing may be employed to advantage to achieve such objects.
  • Dialkyl ethers of polyethylene glycols such as triethylene glycol dimethyl ether, tetraethylene glycol diethyl ether, etc.
  • Dialkyl ethers of polypropylene glycols such as tripropylene glycol dimethyl ether, tetrapropylene glycol diethyl ether, etc.
  • Monoalkyl ethers of polyethylene glycols such as diethylene glycol monomethyl ether, triethylene glycol monoethyl ether, etc.
  • Monoalkyl ethers of polypropylene glycols such as dipropylene glycol monomethyl ether, tripropylene glycol monomethyl ether.
  • glycol ethers have the general formula R_0-f—R-0-_— n R where R is -CH -CH - or -CH -CH(CH3 ) -, n represents the number of alkylene oxide units, e.g. 3 or 4, R]_ is alkyl (e.g. methyl or ethyl) and R is hydrogen or alkyl.
  • Tertiary aromatic amines such as N,N-dimeth ⁇ l aniline, N-phenyl diethanolamine, etc. ' : Trialkyl phosphates such as tributyl phosphate, tripropyl phosphate, etc.
  • Tetrahydrothiophene oxide (sulfolane).
  • High boiling aromatic compounds containing nitrogen within a ring such as quinoline, a ⁇ rolein, the benzyl pyridines and similar compounds.
  • Trialkyl phosphates such as those in Section (1) above.
  • tertiary aromatic amines such as N,N-dieth ⁇ l aniline, quinoline and isoquinoline.
  • a solvent preferably has a value of k 2 at room temperature (25°C) of at least 1.0 and preferably of 10 liter/mole-sec. or higher.
  • the kinetics of Reaction (1) was determined for a specific solvent composition by carrying out the reaction in the following way: A sample of solvent containing hydrogen sulfide was placed in a calorimeter, together with a thermocouple and a magnetic stirring bar. A sample of solvent containing sulfur dioxide was then added rapidly to the calorimeter while stirring vigorously. The temperature rise that resulted from reaction was followed by recording the potential of the thermocouple as a function of time during the experiment. The change in temperature was used to calculate the change in concentrations of both hydrogen sulfide and sulfur dioxide as the reaction progressed, and this information was used to calculate the value of k 2 in the equation above.
  • quinoline and similar aromatic ring-nitrogen compounds are exceptionally effective catalysts for Reaction (1) and are particularly advantageous in the practice of this invention.
  • the value of k 2 was determined for mixtures of N,N-dimethyl aniline (DMA) and triethylene glycol dimethyl ether (Triglyme) at 25°C as a function of composition. The values were about 1.0 at 1% DMA, 4.0 at 10% DMA, and 8.0 at 100% DMA. For a mixture of 1% quinoline in Triglyme the value of k 2 was about 20. In more concentrated solutions of quinoline in Triglyme the values of k were too high to be estimated accurately by this technique.
  • DMA N,N-dimethyl aniline
  • Triglyme triethylene glycol dimethyl ether
  • quinoline, substituted pyridiries such as 4-benzyl pyridine and 3-pyridyl carbinol, and similar compounds can be used in the practice of this invention at low cost and with little volatile loss.
  • Their use is thus preferred to the use of DMA, as taught by Urban (U.S. Patent No. 2,987,379), or the use of N-methyl-2-pyrrolidone as taught by Fuchs (U.S. Patent No. 3,103,411) and Tanimura (U.S. Patent No. 3,953,586).
  • a combination of solvents may be preferred, e.g. a mixture of a solvent from Section 1 of Table I for high solvating power for sulfur dioxide and dimethyl aniline for its catalytic and sulfur solvating properties.

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  • Gas Separation By Absorption (AREA)

Abstract

L'élimination du sulfure d'hydrogène contenu dans des gaz se fait en deux étapes. Pendant la première étape, des solutions de sulfure d'hydrogène et d'oxyde sulfureux dans un solvant réagissent l'une avec l'autre en produisant du soufre et de l'eau. Un excédent de sulfure d'hydrogène est maintenu pendant la première étape, ce qui a pour résultat une solution contenant du soufre, de l'eau et l'excédent de sulfure d'oxygène, ou un gaz contenant l'excédent de sulfure d'hydrogène. L'excédent de sulfure d'hydrogène dans la solution ou dans le gaz est ensuite traité pendant la deuxième étape avec une même solution dans le même solvant d'oxyde sulfureux en quantités supérieures ou presque identiques aux quantités requises pour réagir avec le sulfure d'hydrogène. L'excédent d'oxyde sulfureux dans la phase vapeur de la deuxième étape peut être absorbé dans du diluant pur. On choisit un solvant ayant une capacité élevée de solution du sulfure d'hydrogène, une capacité moindre mais encore importante de solution du sulfure d'hydrogène, et capable de promouvoir la réaction du sulfure d'hydrogène avec l'oxyde sulfureux. Des gaz comme le gaz naturel, le gaz de synthèse et le gaz résiduel d'une usine de Claus peuvent être ainsi traités. En sélectionnant de manière appropriée les solvants et/ou les conditions, des composants mineurs contenus dans le courant de gaz en train d'être traité peuvent être séparés et récupérés s'ils ont une valeur quelconque, par exemple, le propane contenu dans le gaz naturel, le gaz carbonique et l'eau du gaz de synthèse, etc. Grâce à ce procédé, il n'est pas nécessaire de maintenir des rapports stoechiométriques exacts entre le sulfure d'hydrogène et l'oxyde sulfureux, il n'est pas nécessaire d'utiliser une vitesse élevée d'écoulement du solvant, on obtient une capacitance de la phase liquide pour le sulfure d'hydrogène qui amortit les effets des fluctuations de la teneur en sulfure d'hydrogène du courant de gaz, etc.
PCT/US1985/002179 1984-11-04 1985-11-01 Procede d'elimination du sulfure d'hydrogene contenu dans des gaz WO1986002628A1 (fr)

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US657,809 1984-11-04

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Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO1999012849A1 (fr) * 1997-09-10 1999-03-18 The Regents Of The University Of California Procede a haute efficacite pour recuperer du soufre a partir d'un gaz contenant du h2s
US6551570B1 (en) * 1997-11-12 2003-04-22 Apollo Evironmental Systems Corp. Hydrogen sulfide removal process
US6645459B2 (en) 2001-10-30 2003-11-11 The Regents Of The University Of California Method of recovering sulfurous components in a sulfur-recovery process
CN103534198A (zh) * 2011-03-22 2014-01-22 瓦斯技术研究所 用于从含硫气态流中除去硫的方法和系统
WO2018157178A3 (fr) * 2017-02-27 2018-10-04 Honeywell International Inc. Double extracteur à gaz de balayage d'eau

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US3103411A (en) * 1959-06-11 1963-09-10 Method of removing hydrogen sulfide
US3363989A (en) * 1965-11-04 1968-01-16 Shell Oil Co Method of removing sulfur containing gases from gaseous mixtures and recovering sulfur therefrom
US3875295A (en) * 1972-06-01 1975-04-01 Inst Francais Du Petrole Process for withdrawing hydrogen sulfide from an industrial gas with sulfur production
US3882222A (en) * 1971-03-09 1975-05-06 Inst Francais Du Petrole Process for purifying a gas containing oxygenated sulfur compounds and recovering sulfur using ammonia liquors
US3953586A (en) * 1972-12-15 1976-04-27 Waichi Tanimura Process for purifying gases containing H2 S

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3103411A (en) * 1959-06-11 1963-09-10 Method of removing hydrogen sulfide
US3363989A (en) * 1965-11-04 1968-01-16 Shell Oil Co Method of removing sulfur containing gases from gaseous mixtures and recovering sulfur therefrom
US3882222A (en) * 1971-03-09 1975-05-06 Inst Francais Du Petrole Process for purifying a gas containing oxygenated sulfur compounds and recovering sulfur using ammonia liquors
US3875295A (en) * 1972-06-01 1975-04-01 Inst Francais Du Petrole Process for withdrawing hydrogen sulfide from an industrial gas with sulfur production
US3953586A (en) * 1972-12-15 1976-04-27 Waichi Tanimura Process for purifying gases containing H2 S

Cited By (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO1999012849A1 (fr) * 1997-09-10 1999-03-18 The Regents Of The University Of California Procede a haute efficacite pour recuperer du soufre a partir d'un gaz contenant du h2s
US6495117B1 (en) * 1997-09-10 2002-12-17 Regents Of The University Of California Process for recovering sulfur from H2S-bearing gas
US6551570B1 (en) * 1997-11-12 2003-04-22 Apollo Evironmental Systems Corp. Hydrogen sulfide removal process
US6645459B2 (en) 2001-10-30 2003-11-11 The Regents Of The University Of California Method of recovering sulfurous components in a sulfur-recovery process
CN103534198A (zh) * 2011-03-22 2014-01-22 瓦斯技术研究所 用于从含硫气态流中除去硫的方法和系统
WO2018157178A3 (fr) * 2017-02-27 2018-10-04 Honeywell International Inc. Double extracteur à gaz de balayage d'eau
US10688435B2 (en) 2017-02-27 2020-06-23 Honeywell International Inc. Dual stripper with water sweep gas

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