CA2024525A1

CA2024525A1 - Process for removing hydrogen sulfide from a gaseous mixture and producing sulfur therefrom

Info

Publication number: CA2024525A1
Application number: CA 2024525
Authority: CA
Inventors: William A. Rendall; Michael E. Moir; James Szarka
Original assignee: Individual
Current assignee: Individual
Priority date: 1990-09-04
Filing date: 1990-09-04
Publication date: 1992-03-05
Also published as: GB2248444A; GB9118865D0

Abstract

PROCESS FOR REMOVING HYDROGEN SULFIDE FROM A GASEOUS MIXTURE
AND PRODUCING SULFUR THEREFROM

ABSTRACT

A method for removing hydrogen sulphide (H2S) from a gaseous mixture is disclosed. The method is a two step process including (1) reacting carbon dioxide (CO2) with H2S to form carbonyl sulfide (COS) and (2) subsequently decomposing COS to carbon monoxide (CO) and sulfur (S). Hydrogen (H2) as well as S may be recovered where CO is substituted as a reactant for CO2.

Description

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PROCESS FOR REMOVING HYDROGEN SULFIDE FROM A GASEOUS MIXTURE
AND PRODUCING SULFUR THEREFROM ' BACRGROUND OF INVENTION

Field of the Invention ~ ~ "., This invention relates to a method for removing hydrogen ~ .-~ulphide (H S) from a ga3eous mixture. More particularly, the 10 invention pertains to a method for producing carbonyl sulfide, ~C08) and producing sulfur (S) and carbon monoxide (CO) ~ i therefrom. ` ~ -Description of the Prior Art lS
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Acid raln 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 restrictionis on f sulfur emis~ions. Consequently, where the natural gas industry 20 once recoviered 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 H2S ~ ~
concentratlon gas treatment facilities. The principal pitfall ~ -to applying the S recovery technology developed thus far to ~ -25 small-scale, low H2S concentration gas treatment facilities is - `-economic feasibility. The S recovery processes applicable for small-scale applica~ions are not cost effective due to attendant chemical and was~e dispofial costs. -~

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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 H2S. Such an absorbent removal process produces a 5 N2S-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 H29 by molecular sieves. The adsorbed H2S is then desorbed by means of regeneration gas, producing a regeneration off-gas ~-with a high H2S 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 8as 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 c~m be realized. Moreover, with either liquid absorption or molecular sieves, a gas mixture with a high C02/H2S ratio usually requires removal of the majority of C2 to ensure adequate removal of the H2S. In a standard amine absorbent system, C02 removal alone accounts for a substantial amount of the system's energy requirement.

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An alternative to directly removing H2S from a gaseous ~ ;
mixture is to convert the N2S 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 discloset in U.S. Patent 4,522,793 (issued June 11, 1985, to Larson, et al.) and U.S. Pstent 4,671,946 (issued June 9, 1987, to De ~raa, et al.).

Larson et al. discloses a process for reducing the H2S

concentration in a natural gas stream by conversion of H2S and C2 to COS and H20. The desired H2S concentration i~ ;
obtained by contacting the natural gas stream with molecular - i~
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 H2S 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 ~ ~ ;

25 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 al. 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 5 COS liquifies. Subsequently, a lighter hydrocarbon fraction i6 separated from a heavier hydrocarbon fraction in which the COS
i8 adsorbed.

' ",' ,'' Neither Larson nor De Rraa disclose a method to recover 10 either hydrogen-containing conversion products or S. Both methods accomplish gas sweetening by simply converting H2S to COS without a sllbsequent S recovery step.

As mentioned above, conventional processes, such as 15 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 20 developed for ~mall-scale applications.

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The process technologies available for small-Rcale treatment of lean H2S natural gas feed streams fall in three general categories. One type is a solution based redox process which 25 allows recycling of the oxidizing solution that converts H2S
to S. A second type is ~I 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 H2S. -~

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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 ~ -S oxitation. 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, solutlon redox and chemical scavenging systems can be u~ed for recovering sulfur from feed streams having less than 30% H2S. 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 `i inevitably mandate improved sulfur recovery for all existing 20 sulfur emitting facilities. Smaller facilities, not covered by -' previous sulfur recovery standards, will be subjected to these - ;
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improved standards. ~' ~
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Consequently, a need exists for an economical and chemically efficient H2S removal/sulfur recovery process adaptable to small-scale 8as treatment facilities which process lean H2S
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. ;

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SUMMARY OF THE INVENTION ~ ~
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This invention relates to a process for removing H2S from a multi-component feed stream containing H2S and producing S
therefrom. The process comprises two reaction steps. In step one the multi-component feed stream i8 passed through a reactor containing a catalyst bed at a temperature suitable for converting the H2S to COS. The COS product i6 recovered from the step one reactor and fed to the step two reactor. In step two, COS is con~erted to CO and S.

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 100C. Producing gaseous H20 reduces the thermodynamic drive otherwise provided by producing liquid H20. Therefore, beyond 100C the H2S conversion rate to COS does not increase significantly with increased , temperature.

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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 2~ 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. ~ ~

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,,. ," . ",, : -~ .,', The S produced from the COS decompo~ition reaction is recovered by condensing the gaseous S product with a --~
" , conventional heat exchanger. CO and CO2 may be vented or ~ -recycled for use in step one reactor following their separation 5 from any hydrocarbon gases in the process stream.
, :.,,' . ', :' The described COS process i8 effective with natural gas streams containing H2S at various levels, including very low concentrations (i.e. ppm level). The COS process performance 10 will remain consistent despite variations in feed stream composition and flow rate, often characteristic of small-scale treating applications. The COS process has been tested ~uccessfully at ambient pressure. With this success, it is anticipated that the COS process should perform equally well at 15 hiBher pressures. Thls tolerance to a wide range of pressure conditlons would permit applying the process to a variety of gas `
treatment facilitles without requiring additional compression ~ -equipment.

DESCRIPTION OF THE DRAWING

The process of this invention will be better understood by referring to the followi~g detailed description and the attached drawin~ in which:

FIG. 1 depicts the process steps for converting H2S to COS
and H20 or H2 with subsequent COS decomposition to produce S
where the raw feed stream contains excess CO2. The diagram also depicts an optional membrane for H2 removal, a condensing -~
means for separating CO from CO2 and CH4 and a recycle line for returning CO produced from COS decomposition to the feed stream line. These optional features (depicted in dashed lines) would be employed where H2 capture is an additional objective.

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g DESCRIPTION OF THE PREFERRED EMBODIMENT

~ As mentioned above, the proposed process involves two reaction steps. In step one, H2S present in the feedstream i8 converted to COS. In ~tep two, this COS product is dissociated to CO and S. Subsequently, the S is recovered and CO may be recycled when N2 production in step one is also desired.

Referring to FIG. 1, a mùlti-component gaseous feed stream ~;
10 containing CH4 (methane), CO2, 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 5-`
is in a regeneration mode. Bed regeneration may be required ~ 5 from time to time to remove H2O reaction products wh~ch 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 feedin8 either bed 14a or 14b, by line 13. A second option (not shown) is to use the hot -20 oxhaust gas from the second itep (i.e., the decomposition -reaction) of the process which will be discussed below. ~ -i As FIG. 1 illustrates, the proposed proce~s may be used to recover either exclusively S or both S and H2 from H2S. The 2S recovery option employed will depend upon H2S concentration in the natural gas feed stream. Generally, as the H2S
concentration in the feed stream increases, the incentive for ;
H2 recovery with CO recycle becomes greater.

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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 i6 obtained by initially reacting H2S i~
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with C02, while both H2 and S recovery is achieved by reacting H2S with CO in the first step of the proces6. In option 2, the CO may be initially introduced by line 10 but may - ~
be ~ubsequently recycled by line 30 to a step one conver6ion , .!
15 bed 14a or 14b for reuse a6 a reactant. `-' "'"`;, ,:
The first step of the process includes a conversion bed 14a .. . .. .
which preferably contains.alumina or molecular sieves for catalysing one of the two conversion reactions. Where the 20 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 i8 recovered with a membrane 20 which selectively permeate~
~2~ Besides the presence of a catalyst, the efficiency of converting H2S to COS is affected by several factors including the bed's temperature and the C02/H2S ratio. The temperature range for the conversion reaction is from about 60 to 120C. However, the preferred temperature for optimizing the ;~
conversion reaction with an alumina catalyst is about 90C. The conversion process may be maintained with a C02/H2S ratio as ;
low as 2.4/1 (all ratios herein are C02/H2S unless indicated ~` 2~2~2~

otherwise). The conversion efficiency, however, significantly improves with a 10/1 ratio at a 100C 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 decomposed at bed 18 whereby, COS = C0 + S. The decomposition bed 18 may be maintained at a wide temperature range from 400 to 800C. Although the decomposition reaction may occur at high temperatures (e.g., above about 700C) without the use of a `
catalyst, the COS decomposition is more economically efficient with a catalyst, such as alumina or a transition metal sulfide. ~ -Moreover, a catalyzed decomposition reaction allows use of ~`
15 milter temperatures (e.g., about 400C) which eliminates the ; ;
need for materials of construction tolerant to extremely high process temperatures.
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Thermal COS decomposition generally produces more C0 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 C02 inhibits a compet~ng and undesirable decomposition reaction: 2 COS - CS2 + C02. Excess C02 may be present from the raw feed gas or may be introduced at some point ~not .
shown) before the decomposition bed 18.

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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 tran6ferred to a storage vessel by line 24. ~ ;

Following S removal, the gas product stream, containing some C2 and C0 but predominantly CH4, may be passed downstream via line 28 for sale or further treatment (i.e., to remove G02). Alternatively, where the conversion reaction also is used to produce H2, the C0 from the COS tecomposition may be recycled by line 30 to the feed stream 12 for reuse as a reactant. Separating C0 from C02 and CH4 may be achieved by some separation technique 26, such as bed adsorption or solution adsorption. The C02/CH4 product stream may be subsequently 5 trans~erred for sale or additional treatment by line 27. ; ;

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The equipment required for achieving the above described processes is commeroially available. Generally, the type of equipment required will be apparent to those skilled in the 20 art. However, all materials of construction should be inert to i -~ ;
corrosive compounds such as acid gases. Also, the COS ;;
dissociation reaction, equipment materials of construction should tolerate continuous operation at high temperaturs (e.g., 400-700C).

The preferred apparatus and mode of practicing the invention have been described. It is to be understood that the foregoing is illustrative only and that other means and techniques can be ;~
employed without departing from the true scope of the invention defined in the following claims.
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Claims

1. 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.

2. The process of claim 1 additionally comprising introducing carbon monoxide to said first reactor.

3. The process of claim 2 additionally comprising recovering hydrogen produced from said first reactor.

4. The process of claim 2 additionally comprising separating by condensation means said carbon monoxide and sulfur from the other components of said multi-component feed stream.

5. The process of claim 4 additionally comprising recycling said carbon monoxide back to said first reactor.

6. The process of claim 1 wherein said carbonyl sulfide is thermally cracked.

7. The process of claim 1 wherein said second reactor contains a catalyst.

8. The process of claim 7 wherein said catalyst is alumina.

9. The process of claim 7 wherein said catalyst is molecular sieves.

10. The process of claim 7 wherein said catalyst is a transition metal sulfide.

11. A process for removing hydrogen sulfide from a multi-component 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. The process of claim 11 additionally comprising separating by condensation means said carbon monoxide and sulfur from other components of said multi-component feed stream.

13. The process of claim 12 additionally comprising recycling said carbon monoxide back said first reactor.

14. The process of claim 11 wherein said carbonyl sulfide is thermally cracked.

15. The process of claim 11 wherein said second reactor contains a catalyst.

16. The process of claim 15 wherein said catalyst is alumina.

17. The process of claim 15 wherein said catalyst is molecular sieves.

18. The process of claim 15 wherein said catalyst is a transition metal sulfide.

19. A process for removing hydrogen sulfide from a natural gas feed stream containing hydrogen sulfide and carbon dioxide 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 first reactor for converting said hydrogen sulfide to hydrogen and carbonyl sulfide;
(c) separating said hydrogen and carbonyl sulfide produced from said first reactor;
(d) passing said carbonyl sulfide to second reactor for decomposing said carbonyl sulfide to produce carbon monoxide and sulfur;

(e) separating said carbon monoxide and sulfur; and (f) recycling said carbon monoxide back to said first reactor.

20. The process of claim 19 additionally comprising separating by condensation means said carbon monoxide and sulfur from the other components of said multi-component feed stream.

21. The process of claim 19 wherein said carbonyl sulfide is thermally cracked.

22. The process of claim 21 wherein said second reactor contains a catalyst.

23. The process of claim 22 wherein said catalyst is alumina.

24. The process of claim 22 wherein said catalyst is molecular sieves.

25. The process of claim 22 wherein said catalyst is a transition metal sulfide.