GB2248444A - Process for removing hydrogen sulfide from a gaseous mixture and producing sulfur therefrom - Google Patents

Abstract

A two-step method for removing hydrogen sulfide (H2S) from a gaseous mixture comprises (1) reacting carbon dioxide (CO2) with H2S in the presence of a catalyst such as alumina to form carbonyl sulfide (COS) and (2) subsequently decomposing COS to carbon monoxide (CO) and sulfur (S) which may be in the presence of a metal catalyst such as alumina or a metal sulphide or by photochemical or microwave means. Hydrogen (H2) as well as S may be recovered where CO is substituted as a reactant for CO2.

Description

PROCESS FOR REMOVING HYDROGEN SULFIDE FROM A GASEOUS MIXTURE AND PRODUCING SULFUR THEREFROM This invention relates to a method for removing hydrogen sulphide (H2S) from a gaseous mixture. More particularly, the invention pertains to a method for producing carbonyl sulfide, (COS) and producing sulfur (S) and carbon monoxide (CO) therefrom.

Acid rain has become the focal point of much environmental debate and legislation. In an effort to combat acid rain production, a number of countries are enhancing restrictions on sulfur emissions. Consequently, where the natural gas industry once recovered S primarily in large scale/high H2S concentration gas treatment facilities, the industry is now focusing as well on S recovery in small-scale, low H concentration gas treatment facilities. The principal pitfall to applying the S recovery technology developed thus far to small-scale, low E2S 2# concentration gas treatment facilities is economic feasibility. The S recovery processes applicable for small-scale applications are not cost effective due to attendant chemical and waste disposal costs.

In a known process for the removal of H2S from a gas mixture, the gas mixture is contacted with a suitable liquid absorbent, such as an amine solution, that absorbs almost all the H25 Such an absorbent removal process produces a H2S-loaded absorbent and a purified gas mixture containing almost no H2S. The loaded absorbent is subsequently regenerated, giving a regeneration off-gas with a high H2S content.

Another known H2S-removal process involves adsorption of H2S by molecular sieves. The adsorbed H2 S is then desorbed by means of regeneration gas, producing a regeneration off-gas with a high H25 content.

In both of these processes, the regeneration off-gas is fed to a H2S processing installation, such as a Claus unit, where sulfur gases are converted to elemental sulfur.

The known processes are, however, too expensive for the removal of H2S from a gas mixture with lean H2S content (i.e., less than about 30% H2S). The Claus process is a cost effective means of H2S conversion only where the economics of large scale processing can be realized. Moreover, with either iquid absorption or molecular sieves, a gas mixture with a high CC2/H2S ratio usually requires removal of the majority of CO2 to ensure adequate removal of the H2S. In a standard mine absorbent system, C02 removal alone accounts for a substantial amount of the system's energy requirement.

An alternative to directly removing H25 from a gaseous mixture is to convert the H2S into another sulfur containing compound, such as carbonyl sulfide (COS). In a paper presented at the 22nd Annual Gas Conditioning Conference, the University of Oklahoma, April 1972, entitled "Advances in Molecular Sieve Technology for Natural Gas Sweetening" by Turnock and Gustafson, conversion of H2S into COS was a suggested process treatment step for reducing H2S concentrations in natural gas. Two processes have been suggested to convert H2S to COS for removing H2S from a gas mixture by cost effective means.

These processes are disclosed in U.S. Patent 4,522,793 (issued June 11, 1985, to Larson, et al.) and U.S. Patent 4,671,946 (issued June 9, 1987, to De Kraa, et al.).

Larson et al. discloses a process for reducing the H2S concentration in a natural gas stream by conversion of H2S and 002 to COS and H 20. The desired H2S concentration is obtained by contacting the natural gas stream with molecular sieves for adsorption and conversion of H2S to COS. This treated gas stream then has a sufficiently low H2S content to be saleable. However, reducing the R2S concentration by merely converting it to COS remains undesireable since the COS can react with trace amounts of water (H20) in the pipeline to produce H2S. Consequently, Larson's sweetening process has limited utility where post and pre-transfer H2S concentrations are equally critical to marketing the natural gas. Also, in some natural gas markets, a total S concentration for saleable gas may range from 100 to 500 ppm S.Such a total S specification warrants S removal, not simple conversion, to produce a saleable product.

De Kraa et at. discloses a process for converting H2S to COS with subsequent removal of the COS by cryogenic separation.

The gas mixture containing the COS conversion product is passed to a separator maintained at a temperature and pressure at which COS liquifies. Subsequently, a lighter hydrocarbon fraction is separated from a heavier hydrocarbon fraction in which the COS is adsorbed.

Neither Larson nor De Kraa disclose a method to recover either hydrogen-containing conversion products or S. Both methods accomplish gas sweetening by simply converting H2S to COS without a subsequent S recovery step.

As mentioned above, conventional processes, such as amine/Claus, have performed well for sweetening large volumes of natural gas and producing sulfur therefrom. However, the Claus process is not well adapted to small-scale combustion furnace operations using acid gas feed streams lean in H2S (i.e. < 30% H2S). Morever, no cost effective sweetening process has been developed for small-scale applications.

The process technologies available for small-scale treatment of lean H25 natural gas feed streams fall in three general categories. One type is a solution based redox process which allows recycling of the oxidizing solution that converts H2S to S. A second type is a gas phase oxidation process using oxygen to convert H2S to S with a catalyst at moderately low temperature. A third type is a chemical scavenging process using either chemical solids or solutions (non-recyclable) which react with H S.

Unfortunately, these existing technologies have an assortment of disadvantages when applied to small-scale treatment facilities. Existing sulfur recovery processes capable of operating on lean H2S gas feed employ gas phase oxidation. However, one commercial process utilizes a vanadium catalyst which poses toxicity and, ultimately, disposal problems. Another commercial process was developed as an enhancement to existing Claus facilities and has never been tested in a stand-alone mode of operation.

Also, solution redox and chemical scavenging systems can be used for recovering sulfur from feed streams having less than 30% H25. However, these systems have an assortment of drawbacks including high chemical costs, waste disposal problems, formation of undesirable by products, and production of poor quality sulfur.

The continued development of clean air legislation will inevitably mandate improved sulfur recovery for all existing sulfur emitting facilities. Smaller facilities, not covered by previous sulfur recovery standards, will be subjected to these improved standards.

Consequently, a need exists for an economical and chemically efficient H25 removal/sulfur recovery process adaptable to small-scale gas treatment facilities which process lean H multi-component feed streams. Such a process should minimize use of external chemicals, provide uncomplicated process steps, and permit regeneration/recycling of catalysts/reactants used in the process.

According to the invention there is provided a process for removing hydrogen sulfide from a multi-component feed stream containing hydrogen sulfide and producing sulfur therefrom, which comprises: (a) passing said multi-component feed stream through a first reactor containing a catalyst bed maintained at a suitable temperature to convert said hydrogen sulfide to carbonyl sulfide; and (b) passing said carbonyl sulfide to a second reactor for decomposing said carbonyl sulfide to produce carbon monoxide and sulfur.

In a preferred embodiment, the step one reactor contains a catalyst bed having a strong affinity for water, such as alumina. Additionally, the step one reactor is maintained preferably at temperatures near 1000C. Producing gaseous H20 reduces the thermodynamic drive otherwise provided by producing liquid H20. Therefore, beyond 100 C the H2S conversion rate to COS does not increase. significantly with increased temperature.

The step two reactor, in a preferred embodiment, contains a transition metal sulfide catalyst coated on alumina. The COS decomposition may be driven by a variety of energy sources.

With a catalyst present, the step two reaction may proceed thermally as low as about 300 C. Alternatively, the COS dissociation reaction may be promoted by photochemical or microwave means. Where microwave means are employed, heat for driving the dissociation reaction may be produced with a microwave absorbing transition metal catalyst.

The invention will be better understood by referring, by way of example, to accompanying Figure 1 which shows one preferred embodiment of the invention.

As mentioned above, the proposed process involves two reaction steps. In step one, H25 present in the feedstream is converted to COS. In step two, this COS product is dissociated to CO and S. Subsequently, the S is recovered and CO may be recycled when H2 production in step one is also desired.

Referring to FIG. 1, a multi-component gaseous feed stream containing CH4 (methane), C02, and H2S is introduced by line 10 into one of the two H2S conversion beds 14a and 14b in parallel arrangement. Such an arrangement permits one bed 14a to continuously process the feed stream while a second bed 14b is in a regeneration mode. Bed regeneration may be required from time to time to remove H20 reaction products which may saturate the bed's catalyst. The bed may be regenerated by two options. One option is to use external heaters or dryers 16 to produce a hot regeneration gas for feeding either bed 14a or 14b, by line 13. A second option (not shown) is to use the hot exhaust gas from the second step (i.e., the decomposition reaction) of the process which will be discussed below.

As FIG. 1 illustrates, the proposed process may be used to recover either exclusively S or both S and H2 from H25. The recovery option employed will depend upon H2S concentration in the natural gas feed stream. Gererally, as the H2S concentration in the feed stream increases, the incentive for 2 recovery with CO recycle becomes greater.

The following chemical equations represent the reactions which occur in Step One and Two of the process depicted in FIG. 1.

Step One Reaction Options (Option 1) C02 + H2S =COS + H20 (Option 2) CO + H2S = COS + H2 Step Two Reaction COS = CO + S Exclusive S recovery is obtained by initially reacting 25 with CO2, while both H2 and S recovery is achieved by reacting H2S with CO in the first step of the process. In option 2, the CO may be initially introduced by line 10 but nay be subsequently recycled by line 30 to a step one conversion bed 14a or 14b for reuse as a reactant.

The first step of the process includes a conversion bed :-a which preferably contains alumina or molecular sieves for catalyzing one of the two conversion reactions. Where the conversion reaction in step one is H2S + C02 =COS + H20, the H20 is retained on the catalyst bed 14a. Where the conversion reaction in step one is H2S + CO = COS + H2, the H2 is recovered with a membrane 20 which selectively permeates H2. Besides the presence of a catalyst, the efficiency of converting H25 to COS is affected by several factors including the bed's temperature and the C02/H2S ratio.The temperature range a the conversion reaction is from about 5C to t200C. However, the preferred temperature for opt miz.ng =e conversion reactlon with an alumina catalyst is about 90 C. ne conversion process may be maintained with a C02/H2S ratio as low as 2.4/1 (all ratios herein are C02/H2S unless indicate otherwise). The conversion efficiency, however, sign ficanrly improves with a 10/1 ratio at a 1000C reaction temperature.

Generally, the higher the ratio the better the conversion results. COS produced from the first step is transferred to the second step of the process by line 15.

In the second step of the sulfur recovery process, COS is decarposed at bed 18 whereby, COS = CO + S. The decomposition bed 18 may be maintained at a wide temperature range from 400 to 80000. Although the decomposition reaction may occur at high temperatures (e.g., above about 700 C) without the use of a catalyst, the COS decomposition is more economically efficient with a catalyst, such as alumina, metal sieves or a transition metal sulfide. Noreover, a catalyzed decomposition reaction allows use of milder temperatures (e.g., about 400@C) which eliminates the need for materials of construction tolerant to extremely high process temperatures.

Thermal COS decomposition generally produces more CO and S with higher temperatures up to some maximum temperature.

Naturally, this maximum temperature will vary with changes in flowrate, presence or absence of a catalyst, type of catalyst, and pressure. Also, selectivity of the COS decomposition reaction is more favorable with excess C02 present. Excess CO 2inhibits a competing and undesirable decomposition reaction: 2 COS = CS2 + 002. Excess C02 may he present from the raw feed gas or may be introduced at some point (not shown) before the decomposition bed 18.

Following COS decomposition, the S produced is recovered by condensing gaseous S to a liquid with a heat exchanger 22. The S may be transferred for use in another downstream process (not shown) or transferred to a storage vessel by line 24.

Following S removal, the gas product stream, containing some C32 and CO but predominantly CH4, may be passed downstream via line 28 for sale or further treatment (i.e., to remove 002) Alternatively, where the conversion reaction also is used to produce H2, the CO from the COS decomposition may be recycled by line 30 to the feed stream 12 for reuse as a reactant. Separating CO from C02 and CH4 may be achieved by some separation technique 26, such as bed adsorption or solution adsorpt on. The C02/CH4 product stream may be subsequently transferred for sale or additional treatment by line 27.

The equipment required for achieving the above described processes is commercially available. Generally, the type of equipment required will be apparent to those skilled in the art. However, all materials of construction should be inert to corrosive compounds such as acid gases. Also, the COS dissociation reaction, equipment materials of construction should tolerate continuous operation at high temperaturs (e.g., 400-700 C).

Claims (14)

CLAIMS:

1. A process for removing hydrogen sulfide from a multicomponent feed stream containing hydrogen sulfide and producing sulfur therefrom, which comprises: (a) passing said multi-component feed stream through a first reactor containing a catalyst bed maintained at a suitable temperature to convert said hydrogen sulfide to carbonyl sulfide; and (b) passing said carbonyl sulfide to a second reactor for decomposing said carbonyl sulfide to produce carbon monoxide and sulfur.

2. A process as claimed in claim 1, comprising introducing carbon monoxide to said first reactor.

3. A process as claimed in claim 2, comprising recovering hydrogen produced from said first reactor.

4. A process as claimed in claim 2, comprising separating by condensation means said carbon monoxide and sulfur from the other components of said multi-component feed stream.

5. A process as claimed in claim 4, comprising recycling said carbon monoxide back to said first reactor.

6. A process as claimed in any preceding claim, wherein said carbonyl sulfide is thermally cracked in said second reactor.

7. A process as claimed in any preceding claim, wherein said second reactor contains a catalyst.

8. A process as claimed in claim 7, wherein said catalyst is alumina.

9. A process as claimed in claim 7, wherein said catalyst comprises molecular sieves.

10. A process as claimed in claim 7, wherein said catalyst is a transition metal sulfide.

11. A process for removing hydrogen sulfide from a multicomponent feed stream containing hydrogen sulfide and recovering hydrogen and sulfur therefrom, which comprises: (a) passing said multi-component feed stream through a first reactor containing a catalyst bed maintained at a suitable temperature to convert said hydrogen sulfide to hydrogen and carbonyl sulfide; (b) introducing carbon monoxide to said reactor for converting said hydrogen sulfide to hydrogen and carbonyl sulfide; (c) separating said hydrogen and carbonyl sulfide produced from said first reactor; and (d) passing said carbonyl sulfide to a second reactor for decomposing said carbonyl sulfide to produce carbon monoxide and sulfur.

12. A process as claimed in claim 11, additionally comprising separating by condensation means said carbon monoxide and sulfur from other components of said multi-component feed stream.

13. A process as claimed in claim 12, additionally comprising recycling said carbon monoxide back to said first reactor.

14. A process for removing hydrogen sulfide from a multicomponent feed stream containing hydrogen sulfide, substantially as hereinbefore described with reference to accompanying Figure 1.