WO2013002791A1

WO2013002791A1 - Catalyst and method for oxidizing hydrogen sulfide

Info

Publication number: WO2013002791A1
Application number: PCT/US2011/042420
Authority: WO
Inventors: Girish Srinivas; Steven C. Gebhard
Original assignee: Tda Research, Inc
Priority date: 2011-06-29
Filing date: 2011-06-29
Publication date: 2013-01-03

Abstract

A method and catalysts for oxidizing H₂S to elemental sulfur, SO₂ or both. The method includes contacting a gas stream containing H₂S with oxygen and a catalyst comprising one or more alkali metals, one or more alkaline earth metals or a combination thereof supported on silica wherein the catalyst does not contain a transition metal. More specifically, the method and catalysts are useful for oxidizing H₂S with O₂ in a gas stream containing H₂S and hydrogen wherein the hydrogen present is not substantially oxidized.

Description

CATALYST AND METHOD FOR OXIDIZING HYDROGEN SULFIDE

BACKGROUND OF THE INVENTION

[0001] The present invention relates to improved methods for H₂S removal from gas streams. The methods rely at least in part on selective direct oxidation of H₂S to elemental sulfur employing certain mixed metal oxide catalysts. The oxidization is selective for H₂S in the presence of other oxidizible species including hydrogen and certain hydrocarbon species.

[0002] Various catalysts for the oxidation of H₂S to elemental sulfur are known in the art. A number of catalysts are known for removing H₂S from gas streams by partial oxidation into sulfur and water. Most of the catalysts are transition metal oxides (TMO) supported on various catalyst carriers. .Examples include supported iron and vanadium oxides, as well as molybdenum and niobium oxide supported on titania (Ti0₂). For example, U.S. Patents 4,552,746 and 4,857,297 relate to a catalyst consisting essentially of titanium oxide (at least 80% by weight) for the removal of sulfur components, including hydrogen sulfide, from gas streams with production of elemental sulfur. The catalysts optionally contain 5 to 25% by weight alkaline earth metal sulfate. Conversion efficiency is reported to be highly dependent upon water content in the gas stream and gas streams with less than 10% by volume water are preferred.

[0003] U.S. patent 4,623,533 reports a Ti0₂-supported catalyst for direct oxidation of H₂S to sulfur. The catalyst is reported to contain from 0.1 to 25% by weight nickel oxide and from 0 to 10% by weight aluminum oxide (where the percentages are based on the supported catalyst). U.S. patent 6,299,851 reports the use of a vanadium-containing material and a catalytic substance selected from Sc, Y, La and Sm and optionally an antimony-containing promoter for oxidation of H₂S. U.S. patent 6,251 ,359 reports selective oxidation of H₂S to sulfur using a multi-component catalyst containing antimony, vanadium and magnesium materials. U.S. patent 5,653,953 relates to selective oxidation of H₂S using a mixed metal catalyst containing vanadium in combination with molybdenum or magnesium. U.S.

patents 4,243,647 and 4,31 ,683 report the use of a vanadium oxide or sulfide catalyst supported on a non-alkaline porous refractory oxide for oxidation of H₂S to elemental sulfur. The catalyst is reported not to oxidize H₂, CO or light hydrocarbons in the treated gas streams.

[0004] U.S. patent 5,352,422 relates to a catalyst for selective oxidation of sulfur- containing compounds to sulfur comprising at least one catalytically active material and optionally a carrier. The catalyst is described as having a specific surface area of more than 20 m²/g and an average pore radius of at least 25 A and under reaction conditions the catalyst exhibits "no substantial activity towards the Claus reaction." "No substantial activity towards the Claus reaction" is defined therein as the "absence of the influence of water on the selectivity of the oxidation reaction of H₂S to elemental sulfur in the presence of minimally a stoichiometric amount of 0₂ at 250 °C." More specifically this phrase is defined as "that in the presence of 30% by volume of water the selectively of the reaction to elemental sulfur should not be more than 15% lower than the selectivity in the absence of water." The catalyst requires a catalytically active material which is said to be a metal compound or mixture of metal compounds optionally in combination with one or more compounds of non-metals. The only catalytically active materials specifically described are transition metals, specifically an iron compound or a compound of iron and chromium.

[0005] A number of catalysts are described for oxidation of H₂S with oxygen to S0₂. U.S. patent 4,012,486 relates to bismuth containing catalysts for oxidation of H₂S to S0₂. U.S. patent 4,088,743 relates to vanadium supported on a non-alkaline porous refractory oxide. U.S. patent 4,314,983 reports catalysts containing both bismuth and vanadium oxides for H₂S oxidation to S0₂. U.S. patent 4,427,576 relates to catalysts comprising titanium dioxide, or titanium dioxide with zirconia or silica with certain metals for oxidation of H₂S to S0₂.

[0006] U.S. patent 6,099,819 reports certain mixed metal oxide catalysts containing titania for the partial oxidation of H₂S to elemental sulfur. Preferred metal oxides for combination with titania include oxides of V, Cr, Mn, Fe, Co, Ni, Cu, Nb, Mo, Tc, Ru, Rh, Hf, Ta, W, Au, La, Ce, Pr, Nd, Pm, Sm, Eu, Gd, Tb, Dy, Ho, Er, Tm, Yb, and Lu. Reaction is reported at temperatures from 100 to 400 °C. Catalysts are reported to show H₂S conversion between 90% and 99% and sulfur selectivity between 82% and 98% between 180 and 210 °C.

[0007] U.S. patent 7,060,233 reports a process for simultaneous removal of sulfur and mercury from gas streams. The method comprises a step of selective oxidation of H₂S to generate elemental sulfur or a mixture of elemental sulfur and S0₂. Sulfur generated in the gas stream is reported to react with mercury in the gas stream to generate mercuric sulfide which is removed from the gas stream by co-oxidation.

[0008] U.S. patent 7,578,985 relates to removal of H₂S and mercury from a gas stream in which a H₂S conversion catalyst is contacted with the gas stream at temperatures less than or equal to the dew point of elemental sulfur. The patent reports H₂S oxidation tests in syngas containing 13% H₂ and 10% CO. While H₂ and CO oxidization were reported to be minimal, the H₂S conversions (starting with about 4300 ppm) were also only on the order of 60%, and in some cases as much as 15% of the original sulfur in the H₂S was converted to COS. The patent refers to catalysts from U.S. patent 6,099,819, but does not report which catalyst was used to obtain the data reported in the patent.

[0009] U.S. 6,083,473 relates to a selective oxidation catalyst of sulfur-containing compounds which comprises a metal of Group VINA as an active metal oxide on a support comprising a laminar phyllosilicate alone or in combination with silica or alumina. The metals specifically referred to in the patent are iron, nickel and/or copper. A laminar phyllosilicate is described as an aluminosilicate having a laminar structure like a clay and an example given is montmorillonite clay. U.S. patent 6,207,127 relates to a method for oxidizing H2S to sulfur using a catalyst which is an iron and zinc oxide supported on silica.

[00010] U.S. 6,919,296 relates to catalysts for the selective oxidation of sulfur compounds to elemental sulfur. The catalyst is prepared by contacting a catalyst support, such as silica, with a mixed oxide having "atomically mixed" iron ions and zinc ions. The presence of chloride ions in the catalyst is reported to allow better control of sintering of the iron and zinc and to promote formation of iron and zinc oxide. The catalyst is reported to exhibit improved selectivity when chloride is present.

[00011 ] GB2143224 (1987) and GB2143225 (1987) relate to a process for oxidation of H₂S to sulfur and/or S0₂ by contacting a gas containing H₂S in the presence of oxygen with a catalyst comprising at least one metal from Group 3b and/or 4b supported on a silica- containing catalyst. The Group 3b metals are scandium, yttrium, thorium and the lanthanides (now Group 3 of the lUPAC Periodic Table) and the Group 4b metals are titanium, zirconium and hafnium (now Group 4 of the lUPAC Periodic Table).

[00012] A comparison of a wide variety of metal oxides for catalytic activity in the Claus reaction and for oxidation of H₂S by oxygen was made by Marshneva V.I. and Mokrinskii, V. V. (1989). Metal oxides were purchased or prepared by precipitation of the corresponding hydroxides (followed by calcining), or by calcining the corresponding metal carbonates. The oxides used exhibited different surface areas which could affect activity. Nevertheless, catalyst activity for the Claus reaction was ranked as: V₂0₅ » Ti0₂ > Mn₂0₃ > La₂0₃ > CaO > MgO > Al₂0₃ > Zr0₂ > Cr₂0₃ » Si0₂. The catalyst activity for the H₂S partial oxidation catalysis was ranked V₂0₅ > Mn₂0₃ > CoO > Ti0₂ > Fe₂0₃ > Bi₂0₃ > Sb₂0₅ > CuO > Al₂0₃ = MgO = Cr₂0₃. V₂0₅ was, by a large margin, the most active catalyst, with Bi₂0₃ a distant second.

[00013] Steijns, M. and Mars, P. (1974) report the results of tests of catalytic oxidation of hydrogen sulfide to sulfur with molecular oxygen by active carbon, molecular sieve 13X and liquid sulfur at temperatures ranging from 130-200 °C. Sulfur is reported to be adsorbed into the micropores of the catalysts and to function as a catalyst of the reaction. Selectivity for formation of sulfur is reported to be more than 90%. Steijns, M. and Mars, P. (1977) report the results of testing various porous materials including silica, alumina, silica-alumina and magnesium oxide, for the catalytic oxidation of H₂S with 0₂ at 200 °C. The pore structure and chemical composition of the materials was reported to affect activity and selectivity toward formation of sulfur product. The presence of water in the feed is reported to have an activity lowering effect. Sulfur dioxide is reported to be the main oxidation product in the presence of iron oxide or other "group 6-8 metal ions", presumably referring to the lUPAC Periodic Table. Active charcoals, zeolite NaX, Ti0_2l and Zr0₂ are reported to be most suitable for H₂S removal. The activity for H₂S oxidation of silica, including microporous silica, is reported to be low compared to active carbons and zeolites. However, the activity of silica is reported to increase with increased porosity.

[00014] U.S. patent 4,072,479 relates to removal of sulfur-containing compounds, exemplified as H₂S and methyl mercaptan from gas streams containing oxygen employing a bed of activated carbon treated with NaOH and moisture. The activated carbon is soaked in one bed volume of NaOH aqueous solution.

[00015] U.S. patent 6,652,826 relates to a process for the elimination of H₂S from gas mixtures by catalytic oxidation over activated carbon catalyst. In this process, H₂S is oxidized to sulfur and water. The patent emphasizes the advantages of operation of the reaction at higher pressures from 100 to 7000 kPa. Sulfur is reported to be loaded on the catalyst up to 80-150% of the mass of the catalyst before catalyst activity decreases significantly. The sulfur-loaded catalyst is thermally regenerated at temperatures of 250-400 °C at slightly above ambient pressure, however regenerated catalyst may contain sulfur up to 25-50% of the original catalyst mass.

[00016] GB published application 207196 (1924) relates to a process for obtaining sulfur from a gas containing H₂S. Sulfur is reported to be obtained by reacting a gas containing H₂S admixed with air with porous silicic acid (activated silica gel), such as the highly porous silicic acid obtained by dehydrating hydrated silicic acid.

[00017] U.S. patent 2,971 ,824 (1961 ) relates to a catalytic process for oxidation of H₂S with oxygen to form sulfur. The catalysts employed are described as synthetic crystalline aluminosilicates having zeolite structure. .Exemplary aluminosilicate zeolite catalysts include Molecular Sieves 5A, 10X and 13X. The oxidation is reported at temperatures from 175 to 700 °C and preferably 200 to 400 °C. In contrast to GB 207196, noted above, in Table II of the '824 patent, silica gel is reported to exhibit no catalytic activity for H₂S oxidation even at elevated temperatures.

[00018] Karge, H. and Rasko, J. (1978) report spectroscopic experiments on H₂S adsorption on Faujasite-type zeolites having varying Si/AI ratios. Aluminum-rich NaX zeolites having Si/AI ratios up to about 2.5 are reported to exhibit dissociative adsorption of H₂S in contrast to NaY zeolites (Si/AI of 2.5 or higher) where H₂S is reported adsorbed "practically without dissociation." The reference further reports preliminary experiments on oxidation of H₂S to sulfur on the zeolites where oxidation rate "seemed to be influenced" by oxygen partial pressure and Si/AI ratio. [00019] Dudzik Z. and Ziolek M. (1978) report on the catalytic activity of sodium faujasites (NaX and NaY zeolites) for H₂S oxidation with molecular oxygen over the temperature range 0-300 °C. Experiments are reported for O₂/H₂S ratios of 1 or 7.5. The products of oxidation observed are reported to vary with temperature. At lower temperatures 0-70 °C the main product is reported to be sulfur, with substantial amounts of S0₂ observed at temperatures above 20 °C. At temperatures between 70-185 °C, the primary product is reported to be S0₂ due to catalytic oxidation of sulfur adsorbed on the zeolite surface. At temperatures between 185-270 °C both sulfur and S0₂ are reported to be observed due to more rapid release of sulfur from the zeolite and oxidation of the sulfur on the zeolite surface. At 300 °C, only S0₂ is reported to be produced due to catalytic and non-catalytic oxidation of sulfur. Comparison of activity of NaX zeolite with a silica-alumina generated from the zeolite by fully collapsing the zeolite structure is reported to indicate that the faujasite structure is important to activity of NaX zeolite at 70 °C. In contrast to NaX zeolite, the collapsed-structure silica-alumina is reported to exhibit no activity for H₂S at 70 °C. A similar experiment conducted at 300 °C, comparing oxidation of H₂S by NaY zeolite and a corresponding collapsed-structure silica-alumina is reported to show no significant difference in their activity for H₂S oxidation.

[00020] Ziolek M. and Dudzik Z. (1981) report on the influence of the basicity and acidity of faujasite-type zeolites on their catalytic activity for oxidation of H₂S with molecular oxygen. Activity of NaX and NaY zeolites and modified forms in which sodium was partially exchanged with K⁺, Lf or Ca²⁺ were examined. A direct correlation between the number of alumina tetrahedral per unit cell and catalytic activity is reported for the sodium forms of the zeolites.

[00021] Verner, A.B. and Van Swaaij W.P.M. (1985) report oxidation of H₂S to elemental sulfur over NaX and NaY zeolites from nitrogen gas streams containing 1 vol% H₂S, 0.5 vol% 0₂. Tests were performed over the temperature range 120-200 °C. Sulfur formed was deposited on the catalyst and the rate of deposition of sulfur was determined gravimetrically. The NaX zeolite used was molecular sieve Type 13X. The reaction rate is reported to increase substantially with a decreasing Si/AI ratio of the zeolite with the NaX type zeolite (Si/AI = 1.15) being more active due to its lower Si/AI ratio.

[00022] The above-cited references are incorporated by reference herein in their entirety generally for their description of the state of the art and at least in part more particularly for descriptions of sulfur removal and/or recovery systems as well as applications of such systems in treating various gas streams.

[00023] While a number of catalysts have been reported for use in desulfurization processes, there remains a need in the art for improved high efficiency and lower cost desulfurization processes. In particular there remains a need for catalysts for conversion of H₂S to sulfur, that do not substantially oxidize hydrogen or lower molecular weight hydrocarbons.

SUMMARY OF THE INVENTION

[00024] The invention relates to methods for oxidation of H₂S to elemental sulfur or to S0₂ or a mixture of sulfur and S0₂ in the presence of oxygen:

H₂S + 0.5 0₂ - 1 /xSx + H₂0 eq. 1

H₂S + 30₂ ^ 2S0₂ + 2H₂0 eq. 2 and to catalysts for use in such methods. More specifically in the methods herein, a gas containing H₂S is contacted in the presence of oxygen with a catalyst to oxidize H₂S therein to elemental sulfur or a mixture of sulfur and S0₂. The elemental sulfur formed can then be separated from the gas. The methods of the invention are particularly useful for oxidation of H₂S to sulfur and/or S0₂ in gases also containing hydrogen, C_rC₄ hydrocarbons or both. At least in part, the amount of oxygen present, typically expressed as the ratio of 0₂/H₂S, generally affects the relative amounts of sulfur and S0₂ formed on oxidation with greater amount of S0₂ being formed at higher ( H₂S ratios. At least in part, the temperature at which the reaction is conducted generally affects the relative amounts of sulfur and S0₂ formed with greater amounts of S0₂ formed at higher operating temperatures. In a specific embodiment, the methods of the invention are particularly useful for oxidation of H₂S to sulfur in gases also containing hydrogen, C C₄ hydrocarbons or both.

[00025] Oxidation of H₂S of this invention is conducted from ambient pressure to about 1000 psig and at temperatures from 140 to 450°C. In specific embodiments, the reaction is carried out at temperatures ranging from 150 to 370 °C. In specific embodiments, the reaction is carried out at temperatures ranging from 150 to 350 °C. In specific embodiments, the reaction is carried out at temperatures ranging from 190 to 250 °C. In additional embodiments, the reaction is carried out at temperatures ranging from 200 to 240 °C. In specific embodiments, the reaction is carried out at pressure above ambient up to 500 psig. In specific embodiments, the reaction is carried out at pressure above ambient up to 300 psig. In specific embodiments, the reaction is carried out at pressure between 100-300 psig. In specific embodiments where a mixture of sulfur and S0₂ is formed the oxidation is conducted at temperatures ranging from 300 to 450 °C. In specific embodiments as described herein, the reaction can be carried out at temperatures and pressures below the dew point of sulfur. In sub-dew point operation, the feed gas should be essentially free of C₅+ hydrocarbons, e.g., less than 1% by volume (and preferably less than 0.5% by volume), to avoid reaction of hydrocarbons with liquid sulfur Catalyst regeneration after co-condensation of C₅+ hydrocarbons and sulfur requires significantly higher temperatures and may be impractical. [00026] The methods of this invention are useful, for example, to remove or decrease the level of H₂S in any H₂S-containing gases and particularly with those H₂S-containing gases which also contain 0.5% or more by volume hydrogen, 0.5% or more by volume C_rC₄ hydrocarbon or a combination thereof. The methods are useful, for example, with H₂S- containing gases which also contain 10% or more by volume hydrogen, C₁-C4 hydrocarbons or both. The methods are useful, for example, with H₂S-containing gases which also contain 20% or more by volume hydrogen, C C⁴ hydrocarbons or both. The methods of this invention are particularly useful for removing H₂S from associated gas generated during petroleum recovery that contains hydrogen. The methods of this invention are further useful for removal of H₂S from shifted syngas containing H₂S and levels of CO of 5% by volume or less. Shifted syngas contains hydrogen, carbon dioxide, may contain residual levels of carbon monoxide and may contain other species including CrC₄ hydrocarbons. C C₄ hydrocarbons include mixtures of two or more of such hydrocarbons as well as individual hydrocarbons, methane, ethane, propane or butane, and which includes all possible isomers thereof.

[00027] The methods of this invention are further particularly useful for removing H₂S from gas streams containing C0₂, for example, where the gas stream comprises 1 % or more C0₂, 10% or more C0₂ or 20% or more C0₂ and particularly from gas streams predominantly comprising C0₂ (where C0₂ is 50% or more of the gas stream by volume). The methods of this invention are further useful for removing H₂S from gas streams containing hydrogen in combination with C0₂ and which optionally further comprise lower molecular weight hydrocarbons (C₄ or less hydrocarbons).

[00028] The methods of this invention are further useful for removing H₂S from C0₂ gas streams, amine off gas streams and refinery streams which optionally contain hydrogen.

[00029] In specific embodiments, oxygen is supplied to the catalytic reaction as an oxygen- containing gas which comprises oxygen and a gas inert to the reaction. In specific embodiments, the oxygen-containing gas is air. In specific embodiments, the amount of oxygen supplied to the catalytic reaction is such that the ratio of O^H^ is 0.25 or higher. In specific embodiments, the amount of oxygen supplied to the catalytic reaction is such that the ratio of O^ ₂S is 10 or lower or the ration of 0₂/H₂S is 8 or lower. More preferably the ratio of 0₂/H₂S is 0.3 or higher. In a specific embodiment, the ratio of O^ ₂S is 0.3 to 2.0. In a specific embodiment, the ratio of O₂ H₂S is 0.4 to 0.6. In specific embodiments, the ratio of 0₂/H₂S is 1.0 or higher. In specific embodiments, the ratio of 0₂/H₂S is higher than 2. In specific embodiments, the ratio of 0₂ H₂S is 3 or higher. In specific embodiments, excess oxygen for sulfur formation (over stoichiometric with respect to eq. 1 above) can be supplied to the reaction without formation of significant amounts of S0₂. In specific embodiments, excess oxygen for S0₂ formation (over stoichiometric with respect to eq. 2, an O₂/H₂S ratio greater than 3) can be supplied to form a mixture of sulfur and S0₂.

[00030] Catalysts of this invention comprise one or more alkali metals, one or more alkaline earth metals or a combination thereof supported on a support material which exhibits minimal or no reverse Claus activity whereby elemental sulfur generated by H₂S oxidation reacts with water vapor to generate S0₂ under the conditions employed for H₂S-partial oxidation:

3S + 2H₂0 --> 2H₂S + S0₂ (reverse Claus) eq. 3

[00031] The methods of this invention can be used to oxidize H₂S with oxygen to sulfur where no substantial amount of S0₂ (1% by volumes or less and particularly less than 200 ppm) is formed, particularly at low 0₂ H₂S ratios (less than 3 and preferably 1 or less). The methods of this invention can be used to oxidize H₂S with oxygen to a form a mixture of sulfur and S0₂, particularly at high ( h^S ratios (greater than 3). It is believed in the methods of this invention employing the catalysts herein that S0₂ is predominantly formed by oxidation with oxygen (of H₂S and/or sulfur) rather than by the reverse Claus reaction.

[00032] The catalysts preferably do not contain a transition metal. More specifically, in an embodiment, the catalysts do not contain a transition metal that functions for oxidation of hydrogen. More specifically, in another embodiment, the catalysts do not contain a transition metal that functions for oxidation of C₁-C4 hydrocarbons. The support is preferably an oxide having no reverse Claus activity. In preferred embodiments, the catalyst support is silica. The support may also be various forms of hydrated or dehydrated silica. In the present invention, silica can be employed in any art-known form and in particular can be powdered or fumed silica, silica gel or silica in the form of pellets or extrudates. In addition, forms of silica alumina, silicates and aluminosilicates which do not exhibit reverse Claus activity may be employed.

[00033] In specific embodiments, the support is an aluminosilicate which is not a zeolite. In specific embodiments, the support is an aluminosilicate which is not a zeolite and which has a Si/AI ratio greater than 25. In specific embodiments, the support is an aluminosilicate which is not a zeolite and which has a Si/AI ratio greater than 50. In specific embodiments, the support is an aluminosilicate which is not a zeolite and which has a Si/AI ratio greater than 100. In other specific embodiments, the support is an aluminosilicate zeolite having Si/Ai ratio greater than 100. In specific embodiments, the support is not alumina and is not titania. In specific embodiments, the support does not contain alumina and does not contain titania.

[00034] In a specific embodiment, the support material is a mesoporous or mesostructured silica or aluminosilicate material. Such mesoporous or mesostructured materials are exemplified by MCM-41 , MCM-48 and MCM-50 materials (MCM = Mobil Crystalline Materials), which are commercially available or which can be prepared by art-known methods. See: Corma, A. (1997); Huo Q. et al. (1996); Kresge, C.T. et al. (1992); Beck, J.S. et al. (1992); Vartuli, J.C. et at. (1994, a); Vartuli, J.C. et al. (19994,b); Beck, J.S. et al. (1994). These references are incorporated by reference herein in their entirety for descriptions and methods of preparation of mesoporous materials which can be useful in this invention. esoporous silica or aluminosilicate supports can alternatively be disordered, exhibit ordered pore systems, exhibit non-uniform pore diameters or exhibit uniform pore diameters. These mesoporous materials can be composed only of silica (Si-MCM-41 or Si-MCM-48) or may contain some level of aluminum (silica-alumina/aluminosilicate). Mesoporous silica-alumina and aluminosilicates having sufficiently high Si/AI ratios such that they do not exhibit reverse Claus activity can be useful as supports for the catalysts of this invention. Silica-alumina and aluminosilicate materials that can be useful in the catalysts of this invention are those in which the Si/AI ratio is greater than 25. Silica-alumina and aluminosilicate materials that can be useful in the catalysts of this invention are those in which the Si/AI ratio is greater than 50. Silica-alumina and aluminosilicate materials preferred for use in the catalysts of this invention are those in which the Si/AI ratio is greater than 100.

[00035] In additional embodiments, the catalysts comprise one or more alkali metals, and one or more lanthanide metals (including yttrium). In other additional embodiments, the catalysts comprise one or more alkali metals, one or more alkaline earth metals and one or more lanthanide metals (including yttrium). In specific embodiments, the alkali metal is Na, K or a combination thereof. In specific embodiments, the alkaline earth metal is g, Ca or a combination thereof. In specific embodiments, the lanthanide metal is lanthanum or yttrium.

[00036] In specific embodiments, the catalysts comprise one or more alkali metals and one or more alkaline earth metals. In additional embodiments, the catalysts further comprise one or more lanthanide metals. In other specific embodiments, the catalysts comprise two or more alkali metals, two or more alkaline earth metals or combinations thereof. In specific embodiments, the catalysts comprise two or more or three or more alkali metals or alkaline earth metals. In additional embodiments of the foregoing catalysts, the catalysts further comprise one or more lanthanide metals.

[00037] In specific embodiments, the catalysts comprise Na or K in combination with Mg or Ca. In other embodiments, the catalysts comprise Na or K in combination with both Mg and Ca. In other embodiments, the catalysts comprise Na in combination with Mg and Ca. In additional embodiments, the foregoing catalysts further comprise one or more lanthanide metals. In these embodiments, the catalysts are preferably supported on silica.

[00038] In specific embodiments, the catalyst consists essentially of one or more alkali metals and one or more alkaline earth metals and catalyst support. In this embodiment, the catalyst does not contain an amount of any species, particularly a metal that catalyzes the oxidation of hydrogen under the conditions of the methods herein. In this embodiment, it is more preferred that the catalyst does not contain an amount of any species, particularly a metal, that catalyzes the oxidation of hydrogen or the oxidation of a hydrocarbon having 1 -4 carbon atoms under the conditions of the methods herein. In a specific embodiment the catalyst support is silica. In specific embodiments, the catalyst consists essentially of one or more alkali metals and one or more lanthanide metals and catalyst support. In this embodiment, the catalyst does not contain an amount of any species, particularly a metal, that catalyzes the oxidation of hydrogen under the conditions of the methods herein. In this embodiment, it is more preferred that the catalyst does not contain an amount of any species, particularly a metal, that catalyzes the oxidation of hydrogen or the oxidation of a hydrocarbon having 1-4 carbon atoms under the conditions of the methods herein. In a specific embodiment the catalyst support is silica. In specific embodiments, the catalyst consists essentially of one or more alkali metals, one or more alkaline earth metals and one or more lanthanide metals and catalyst support. In this embodiment, the catalyst does not contain an amount of any species, particularly a metal, that catalyzes the oxidation of hydrogen under the conditions of the methods herein. In this embodiment, it is more preferred that the catalyst does not contain an amount of any species, particularly a metal, that catalyzes the oxidation of hydrogen or the oxidation of a hydrocarbon having 1-4 carbon atoms under the conditions of the methods herein. In a specific embodiment the catalyst support is silica.

In specific embodiments, the catalyst does not contain a transition metal. In specific embodiments, the catalyst does not contain niobium, titanium, iron, vanadium or bismuth. In specific embodiments, the catalyst does not contain a lanthanide metal.

[00039] In specific embodiments the catalyst consists of at least one alkali metal and one or more alkaline earth metals or one or more lanthanide metals supported on silica. In specific embodiments, the catalyst consists of at least one alkali metal and one or more alkaline earth metals supported on silica. In specific embodiments, the catalyst consists of at least one alkali metal, one or more alkaline earth metals and one or more lanthanide metals supported on silica.

[00040] In specific embodiments, the support represents from 20% to 98% by weight of the catalyst. More specifically, the support represents from 25% to 85% by weight of the catalyst. More specifically, the support represents from 50% to 80% by weight of the catalyst. More specifically, the support represents from 70% to 80% by weight of the catalyst. More specifically the support represents from 70% to 75% by weight of the catalyst.

[00041] In specific embodiments, the alkali metal(s), calculated as metal oxides, represent from 2 to 25% by weight of the catalyst. More specifically, the alkali metal(s), calculated as metal oxides, represent from 5 to 20 % by weight of the catalyst. More specifically, the alkali metal(s), calculated as metal oxides, represent from 8 to 20% by weight of the catalyst. More specifically, the alkali metal(s), calculated as metal oxides, represent from 10 to 18% by weight of the catalyst. More specifically, the alkali metal(s), calculated as metal oxides, represent from 12 to 16% by weight of the catalyst. In specific embodiments, the alkaline earth(s), calculated as metal oxides, represent from 2-50% by weight of the catalyst. More specifically, the alkaline earth(s), calculated as metal oxides, represent from 5-25% by weight of the catalyst. More specifically, the alkaline earth(s), calculated as metal oxides, represent from 8- 20% by weight of the catalyst. More specifically, the alkaline earth(s), calculated as metal oxides, represent from 10-18% by weight of the catalyst. More specifically, the alkali metal(s), calculated as metal oxides, represent from 12 to 16% by weight of the catalyst.

[00042] In specific embodiments, the alkali metal(s), calculated as metal oxides, represent from 2 to 25% by weight of the catalyst and the alkaline earth metal(s), calculated as metal oxides, represent from 2-25% by weight of the catalyst. In specific embodiments, the alkali metal(s), calculated as metal oxides, represent from 5 to 20% by weight of the catalyst and the alkaline earth metal(s), calculated as metal oxides, represent from 5-20% by weight of the catalyst. In specific embodiments, the alkali metal(s), calculated as metal oxides, represent from 10 to 18% by weight of the catalyst and the alkaline earth metal(s), calculated as metal oxides, represent from 10-18% by weight of the catalyst. In specific embodiments, the alkali metal(s), calculated as metal oxides, represent from 12 to 16% by weight of the catalyst and the alkaline earth metal(s), calculated as metal oxides, represent from 12-16% by weight of the catalyst.

[00043] In specific embodiments, the alkali metal(s), calculated as metal oxides, represent from 2 to 25% by weight of the catalyst and the alkaline earth metal(s), calculated as metal oxides, represent from 2-25% by weight of the catalyst with the balance representing support. In specific embodiments, the alkali metal(s), calculated as metal oxides, represent from 5 to 20% by weight of the catalyst and the alkaline earth metal(s), calculated as metal oxides, represent from 5-20% by weight of the catalyst with the balance representing support. In specific embodiments, the alkali metal(s), calculated as metal oxides, represent from 10 to 18% by weight of the catalyst and the alkaline earth metal(s), calculated as metal oxides, represent from 10-18% by weight of the catalyst with the balance representing support. In specific embodiments, the alkali metal(s), calculated as metal oxides, represent from 12 to 16% by weight of the catalyst and the alkaline earth metal(s), calculated as metal oxides, represent from 12-16% by weight of the catalyst with the balance representing support.

[00044] In specific embodiments, when present with one or more alkali metals, lanthanide metal(s), calculated as metal oxides, represent from 2 to 25% by weight of the catalyst, from 5 to 20% by weight of the catalyst, from 10 to 18% by weight of the catalyst or from 12 to 16% of the catalyst. In specific embodiments, when present with one or more alkali metals, lanthanide metal(s), calculated as metal oxides, represents from 0.75 to 1.25 of the weight of alkali metal(s), calculated as metal oxides. In specific embodiments, when present with one or more alkali metals and one or more alkaline earth metals, lanthanide metal(s), calculated as metal oxides, the total of alkaline earth metal(s) and lanthanide metal(s) represent from 2 to 25% by weight of the catalyst, from 5 to 20% by weight of the catalyst, from 10 to 18% by weight of the catalyst or from 12 to 16% of the catalyst. In specific embodiments, when present with one or more alkali metals and one or more alkaline earth metals, the combination of alkaline earth metal(s) and lanthanide metal(s), calculated as metal oxides, represents from 0.75 to 1.25 of the weight of alkali metal(s), calculated as metal oxides.

[00045] In specific embodiments, the invention relates to non-transition metal catalysts and methods for the oxidation of hydrogen sulfide (H₂S) with oxygen to form elemental sulfur. In more specific embodiments, the invention relates to catalysts and methods for the oxidation of H₂S in gas mixtures that contain significant quantities of hydrogen wherein substantial oxidation of the hydrogen present does not occur. In additional embodiments catalysts of the invention also exhibit little or no oxidation of low molecular weight hydrocarbons that may be present in the gas mixtures in addition to H₂S and optional hydrogen. The catalysts and methods of this invention are useful for oxidation of H₂S in H₂S-contaminated hydrogen gas streams, for example, for removing H₂S from synthesis gas, from shifted synthesis gas (i.e. where CO concentrations are low) and for removing H₂S from associated gas that is produced during heavy oil recovery using thermal and steam drive methods.

[00046] In specific embodiments, the catalysts of this invention do not substantially oxidize hydrogen, that is the reaction:

H₂ + 0.5 0₂ H₂0 eq. 4 consumes less than 20% by volume of the hydrogen present. In specific embodiments, less than 10% by volume of hydrogen present is oxidized. In other specific embodiments less than 5% by volume of hydrogen is oxidized.

[00047] In specific embodiments, the catalysts of the invention can be used to remove H₂S from hydrogen-containing gases without consuming additional 0₂. In specific embodiments, the catalysts of this invention will oxidize H₂S to sulfur and water and not substantially oxidize hydrogen. In specific embodiments, the catalysts of this invention will not substantially oxidize low molecular weight hydrocarbons (i.e., C_rC₄ hydrocarbons), such that hydrocarbon oxidation consumes less than 10% by volume of the hydrocarbon present. In specific embodiments, less than 5% by volume of hydrocarbons present is oxidized. In specific embodiments, less than 1% by volume of hydrocarbons present is oxidized.

[00048] H₂S partial oxidation with the catalysts herein is generally operated between about 14 °C to about 370 °C and at pressures between ambient and 1000 psig. In specific embodiments, the oxidation is operated at pressures between ambient and 300 psig. The pressure and temperature limits are at least in part dictated by the dew points of sulfur vapor (which depends on the H₂S concentration in the feed), water vapor and any potentially condensable hydrocarbons or other components in the feed. H₂S partial oxidation is preferably conducted above the dew point of sulfur.

[00049] Operation of the methods for oxidation or partial oxidation of H₂S below the sulfur dew point can cause liquid sulfur to form in or on the catalyst. While not a preferred embodiment, the process of the invention can be operated below the sulfur dew point. In this case, sulfur is removed from the catalyst by heating above the dew point and can thereafter be captured. Catalytic activity can be restored by heating the catalyst to temperatures above the sulfur dew point to slowly evaporating the liquid sulfur. Sulfur removal and catalyst restoration is preferably conducted by slow heating to prevent polymerization of sulfur in or on the catalyst. During sub-dew point C₅+ hydrocarbons are preferably removed prior to treatment. Co-condensation of sulfur and higher molecular weight hydrocarbons in or on the catalyst (as the result, for example of sub-dew point operation) with gases containing C₅+ hydrocarbons, can lead to irreversible fouling and should be avoided. For example, higher molecular weight hydrocarbons are preferably removed from gas streams to be treated with catalysts of this invention upstream of the oxidation reaction to avoid their condensation in the system and particularly on the catalyst employed. Higher molecular weight hydrocarbons can be removed from gas streams to be treated by use, for example, of a refrigeration plant upstream of partial oxidation.

[00050] Catalysts of the invention are substantially inert to methane, ethane, propane and other low molecular weight alkanes, as well as hydrogen and C0_2> where substantially inert means that

[00051] Higher molecular weight hydrocarbons (C₅+, pentanes and higher) are preferably removed from gas-streams of this invention to avoid catalyst fouling.

[00052] Gas streams treated by the methods of this invention may contain other sulfur- containing species which may either be oxidized directly, or may be first converted to H₂S by art-recognized methods and H₂S is thereafter oxidized by the methods of this invention. Sulfur-containing species in addition to H₂S that may be present in gas streams include, among others, CS₂, COS, and mercaptans. In a specific embodiment, the methods of this invention can be combined with art-known methods for converting other sulfur containing species, such as S0₂, COS, CS₂ and/or mercaptans to H₂S.

[00053] The invention also relates to methods of removing H₂S from shifted syngas streams, from hydrogen recycle gas streams, from C0₂, from natural gas, and from associated gas streams, particularly from associated gas produced during heavy oil recovery that contains hydrogen. The process of this invention can be combined with various art-known processes for removal of H₂S from gas streams.

BRIEF DESCRIPTION OF THE DRAWINGS

[00054] FIG. 1 is a schematic process diagram illustrating a direct oxidation reactor of this invention for oxidation of H₂S employing catalyst of this invention. I think it would be a good idea to change the figure so that the inlet says just FEED or add other feed streams to the title. I will do this and paste in a new FIG 1.

[00055] FIG. 2 is a schematic system diagram illustrating an exemplary application of the methods and catalysts of this invention applied to removal of H₂S from shifted syngas. The process elements illustrated for gasification, shift reactions, optional COS hydrolysis and optional H₂S scavenging can be any of a variety of processes that are known in the art.

[00056] FIG. 3 is a graph illustrating results of contacting silica granules made from fumed silica with test gas containing H₂S. Test conditions were: T = 220°C, P = 200 psig, 1% H₂S, 0.5% 0₂ (from air), space velocity = 1000 volume gas/volume catalyst/hour. The silica particles exhibit no activity for H₂S oxidation. The thermal conductivity detector on the gas chromatograph used for gas analysis was reading about 10% high during this experiment (11 ,000 ppm instead of 10,000 ppm for 1% H₂S). The detector was recalibrated after this experiment and its accuracy checked prior to all other experiments.

[00057] FIG. 4 is a graph illustrating the results of testing of the specific catalyst of Table 1 showing H₂S conversion and S0₂ production (ppm) as a function of reaction time at indicated 0₂/H₂S ratios. The experiment was done at ambient pressure and 220°C. The experiment was divided into four phases. In the first two phases the feed gas was as 1% H₂S, 0.5% 0₂, with the balance split between C0₂ and N₂. The 0₂/H₂S ratio was changed from 0.5 (stoichiometric) in the first phase to 0.45 (sub-stoichiometric) in the second phase. In the third phase, methane was added to the feed gas (29% by volume). In the fourth phase, 1.3% hydrogen was added to the feed gas.

[00058] FIG. 5-FIG. 8 are graphs illustrating the results of catalyst tests showing H₂S conversion and S0₂ production (ppm) as a function of reaction time at indicated 0₂:H₂S ratios. The test temperature was 240°C, the pressure was ambient, and a space velocity of 1000 volume gas/volume catalyst/hour was used. Initially, the 0;/H₂S was set at stoichiometric (O^hbS = 0.5). During this time the H₂S conversion was approximately 92% and about 100 ppm of S0₂ was produced. The 0₂ H₂S ratio was then lowered to 0₂ H₂S = 0.45. The catalyst employed was the specific catalyst of Table 1.

[00059] FIG. 9 is a graph illustrating the results of catalyst tests (employing the specific catalyst of Table 1) showing H₂S conversion and S0₂ production (ppm) as a function of reaction time. In this experiment, the oxygen concentration was 2 vol% and the H₂S concentration was 2500 ppm (0.25%) which gives a O₂/H₂S ratio = 8. The hydrogen concentration was 30 vol% along with 25% C02 to simulate shifted syngas. The water concentration was 2% and the balance was nitrogen (40.75%). The catalyst temperature was 220°C and the system pressure was 200 psig.

DETAILED DESCRIPTION OF THE INVENTION

[00060] The present invention relates to methods and catalysts for oxidation of H₂S to elemental sulfur. While the methods and catalysts of this invention are generally useful for the oxidation of H₂S, they are particularly useful for the partial oxidation of H₂S to elemental sulfur in the presence of hydrogen, low molecular weight hydrocarbons (C C₄ hydrocarbons) or both. In methods herein using catalysts of this invention hydrogen is not substantially oxidized. In methods herein using catalysts of this invention, C C₄ hydrocarbons are not substantially oxidized.

[00061] Catalysts of this invention contain at least one alkali metal on a support material which exhibits no substantial level of Claus activity under the conditions employed for (-Impartial oxidation. Preferably, the catalysts of this invention contain one or more alkali metals and one or more alkaline earth metals and/or one or more lanthanide metals supported on a support material which exhibits no substantial level of Claus activity under the conditions employed for H₂S-partial oxidation. The support is preferably an oxide having no substantial reverse Claus activity. In specific embodiments, the catalyst itself exhibits no substantial level of reverse Claus activity.

[00062] A catalyst exhibiting Claus activity catalyzes the Claus reaction which is reversible:

S0₂ + 2H₂S <-> 3S + 2H₂0 eq. 5

The reverse Claus reaction is then:

where H₂S is oxidized to sulfur by S0₂. While the desired sulfur product is formed by the forward reaction with S0_2l the reaction is in equilibrium so that a catalyst with Claus activity will catalyze both the forward and reverse reaction with possible production of the undesired product S0₂. In the present invention, it is preferred to minimize the reverse reaction (as shown) between water and elemental sulfur and thus minimize production of S0₂ under the reaction conditions used for oxidation of H₂S with oxygen. This can in part be achieved by use of a catalyst support that exhibits no substantial reverse Claus activity where the support converts less than about 5% by weight of sulfur present into S0₂. Again preferably, the catalyst itself exhibits only low levels of Claus activity to minimize the level of S0₂ generated. In specific embodiments, the catalyst itself of the invention exhibits low levels of Claus or reverse Claus activity where less than 20% of the sulfur present is converted into S0₂ and H₂S. In specific embodiments, the catalyst itself converts less than 10% of the sulfur present into S0₂and H₂S. In other specific embodiments, the catalyst itself converts less than 5% of the sulfur present into S0₂ and H₂S.

[00063] The preferred support is silica that nominally has the formula Si0₂, although various hydrated forms of silica, such as silica gel can also be used. The silica or hydrated silica can be in the form, among others, of fumed silica, silica pellets, silica extrudates, granules and mixtures thereof. High surface area silica is preferred to maximize dispersion of catalytically active components. However, lower surface area silica including soda-lime, borosilicate glass or fused silica can be used depending on the desired activity of the catalyst. Silica supports include various forms of hydrated silica. Silica can be employed in any art- known form and in particular can be powdered or fumed silica, silica gel or silica in the form of pellets or extrudates granules and mixtures thereof. Silica supports further include porous silica, amorphous silica or colloidal silica. In specific embodiments, fumed silica, particularly in the form of extrudates and preformed silica pellets (commercially available) are employed as catalysts supports. The silica can be in naturally occurring forms such as diatomaceous earth, with the caveat that such natural forms should be substantially free (less than 0.5% and preferably less than 0.1% by weight) of metal ions other than alkali, alkaline earth or lanthanide metals. In specific embodiments, the silica support is free of titanium, is free of silicates, is free of zeolites, is free of aluminum and /or is free of transition metals.

[00064] In specific embodiments, the support can comprise or be a silicate having surface area of 5 m2/g or more. Silicates useful in this invention do not contain transition metals. More preferred silicates are calcium or magnesium silicate.

[00065] In addition, forms of aluminosilicates and silica alumina which do not exhibit reverse Claus activity may be employed. In specific embodiments, the support is an aluminosilicate which is not a zeolite. In specific embodiments, the support is a non-zeolite aluminosilicate having Si/AI ratio greater than 25. In specific embodiments, the support is a non-zeolite aluminosilicate having Si/AI ratio greater than 50. In specific embodiments, the support is a non-zeolite aluminosilicate having Si/AI ratio greater than 100. In specific embodiments, the support is an aluminosilicate zeolite having Si AI ratio greater than 100. In specific embodiments, the support is a silica alumina, which may be in the form of silica alumina gel, having a low alumina content which is less than 10% by weight, alternatively is less than 5% by weight or is less than 1% by weight alumina. In specific embodiments, the support is not alumina and is not titania. In specific embodiments, the support does not contain alumina and does not contain titanium. In specific embodiments, the support consists of 90% or more by weight silica. Alternatively, the support consists of 95% or more by weight silica or the support consists of 99% or more by weight of silica.

[00066] In a specific embodiment, the support material is a mesoporous or mesostructured silica, aluminosilicate or silica-alumina material. Such materials are exemplified by MCM-41 , MCM-48 and MCM-50 materials (MCM = Mobil Crystalline Materials). See: Huo Q. et al.

(1996); Kresge, C.T. et al. (1992); Beck, J.S. et al. (1992); Vartuli, J.C. et al. (1994, a); Vartuli, J.C. et al. (19994,b); Beck, J.S. et al. (1994); W091/11390; US patent 5,098,684 and US patent 3,556,725. Mesoporous supports can alternatively be disordered, exhibit ordered pore systems, exhibit non-uniform pore diameters or exhibit uniform pore diameters. These mesoporous materials can be composed only of silica (Si-MCM-14 or Si-MCM-48) or may contain some level of aluminum (silica-alumina/aluminosilicate). Mesoporous Silica-alumina and aluminosilicates having sufficiently high Si/AI ratios such that they do not exhibit reverse Claus activity can be useful as supports for the catalysts of this invention. Silica-alumina and aluminosilicate materials that can be useful in the catalysts of this invention are those in which the Si/AI ratio is greater than 25. Silica-alumina and aluminosilicate materials that can be useful in the catalysts of this invention are those in which the Si/AI ratio is greater than 50. Silica-alumina and aluminosilicate materials preferred for use in the catalysts of this invention are those in which the Si AI ratio is greater than 100.

[00067] High surface area support is preferred to maximize dispersion of catalytically active components. However, lower surface area supports can be used. For example, high surface area silica or lower surface area silica including, soda-lime, borosilicate glass or fused silica can be used depending on the desired activity of the catalyst. Supports preferably have surface areas from 5 m²/g to 100 m²/g. Supports can have surface areas between 5 m²/g to 15 m²/g. Supports can have surface area of 100m²/g or higher.

[00068] The preferred active components of the catalyst are alkali and alkaline earth salts and oxides such as lithium, sodium, potassium, rubidium, cesium, magnesium, calcium, barium and strontium, with the most preferred being sodium, calcium and magnesium. Selected amounts of each salt or oxide precursor are dissolved in water and the resulting solution is used to treat the selected support. The lanthanide series of elements includes: La, Ce, Pr, Nd, Pm, Sm, Eu, Gd, Tb, Dy, Ho, Er, Tm, Yb, and Lu. The catalysts of the inventive catalyst can also be made with lanthanide salts and yttrium (Y) or scandium (Sc) compounds, since these elements exhibit chemistry similar to the lanthanides.

[00069] In specific embodiments, the alkali metal is Na, K or a combination thereof. In specific embodiments, the alkaline earth metal is Mg, Ca or a combination thereof. In specific embodiments, the lanthanide metal is lanthanum or yttrium. In specific embodiments, the catalysts comprise Na or K in combination with Mg or Ca. In other embodiments, the catalysts comprise Na or K in combination with both Mg and Ca. In other embodiments, the catalysts comprise Na in combination with Mg and Ca. In additional embodiments, the foregoing catalysts further comprise one or more lanthanide metals. In all these embodiments, the catalysts are preferably supported on silica.

[00070] A specific example of a catalyst of this invention and a preferred range for catalyst components are listed in Table 1.

Table 1

[00071] Table 1 contains the compositions of catalysts as prepared where the weight percentages of the components Na, Ca and Mg are expressed on the basis of their oxides. After preparation, oxides, may react with moisture in the environment forming hydroxides, e.g., Na₂0 can form NaOH. The catalyst may contain some level of metal precursor For example, when metal nitrate salts are employed as precursors, the metal nitrate may not completely decompose at calcining temperature around 400°C.

[00072] The catalysts of this invention can be prepared by any art-recognized method for the preparation of supported metal catalysts. One preferred method for catalyst synthesis is impregnation and more specifically the incipient wetness impregnation method. In, such methods, metal precursors in desired amounts are dissolved in a selected volume of solvent (water, aqueous solution, or organic solvent), the solvent containing dissolved metal(s) is contacted with the support material and the volume of solvent impregnates the pores of the support. The impregnated support is dried and calcined. Any suitable metal precursor, such as nitrates can be employed in preparation of the catalyst. The preferred catalyst precursors are common anionic salts, including nitrates, carbonates, borates, oxalates, and hydroxides, of the alkali, alkaline earth and lanthanide elements because they are inexpensive. Precursors should be selected to avoid components which may adversely affect catalyst activity. Water- soluble salts may be used. However, non-water-soluble and oxides or other compounds of the alkali, alkaline earth or lanthanide elements can be used. After preparation and calcining in air (e.g., at 400 °C) the supported metal(s) are expected to be predominantly in the form of oxides. Thermal treatment is expected to decompose the precursors however some level of precursor material (e.g., nitrates) may be present without detrimental effect to activity. In some cases, metal oxide initially present may react with environmental water to generate OH^".

[00073] The catalysts of this invention can also be made, for example, by intimately mixing (e.g. ball milling) of amounts of the precursor salts selected to achieve desired compositions with a selected amount of silica. Intimate mixing is followed by pressing to form pellets or tablets and thereafter calcining, as described above.

[00074] The methods and catalysts of this invention can be employed in various system configurations and used in various specific H₂S clean-up applications. In general, the direct oxidation al method of this invention can be combined upstream or downstream as appropriate with any one or more compatible sulfur recovery or removal processes that are known in the art. The methods herein can in general be combined with any art-known sulfur recovery or removal process that can be operated such that the pressure range, temperature range, and/or component concentration (e.g., H₂S, 0₂, etc.) range, if any, of any gas stream(s) linking the processes are within (or can be reasonably adjusted to be within) the operational range of the inventive process. For example, the inventive process can be operated downstream of a chemical or catalytic process in which various sulfur-containing species in a gas stream are converted to H₂S. More specifically, the methods herein can optionally be combined with known methods (e.g., hydrogenation/hydrolysis process) for converting other sulfur containing species, such as S0₂, COS, CS₂ and/or mercaptans (e.g., RSH, where R is aliphatic) to H₂S. The inventive process can be operated downstream of a combustion, adsorption, fractionation or reactive process which decreases the level of any undesired gas component, e.g., H₂S (assuming residual H₂S remains), S0₂, particulates, aerosols (e.g., containing hydrocarbons), condensate (e.g., containing heavier hydrocarbons), heavier hydrocarbons, etc. The inventive process can also be operated downstream of a concentration, fractionation, adsorption or reactive process that increases the level of any desired gas component. The inventive process can be operated downstream of a less than completely efficient sulfur removal process for removal of residual H₂S to increase efficiency.

[00075] Alternatively, or in combination, the inventive process can be operated upstream of a sulfur removal process (chemical or biological) to decrease the sulfur load on that process. The inventive process of this invention can also be operated upstream of a sulfur removal or recovery system that requires or exhibits improved operation at a selected ratio of H₂S to S0₂. The inventive process of this invention can be operated upstream of a sulfur removal or recovery system that is detrimentally affected by the presence of S0₂ to reduce S0₂ levels entering the system and improving overall efficiency.

[00076] Compatible processes can be linked, typically by transfer of a product gas stream from one process to the feed inlet of another process directly or by intervening cooling, heating, pressure adjustment, water removal, solvent removal, filtering equipment or related processing equipment as will be appreciated by those of ordinary skill in the art.

[00077] An additional benefit of the use of the methods herein is that H₂S removal can be accomplished without the significant energy loss that results from the use of cool gas clean-up technologies. The catalyst of this invention can also be used to desulfurize natural gas and associated gas. The catalyst of this invention is useful for removing the bulk of the sulfur from gas streams that contain significant concentrations of hydrogen such as associated gas from heavy oil or bitumen recovery operations, or hydrogen recycle in refinery streams. When syngas is generated by the partial oxidation of hydrocarbon (POX), H₂S has to be removed downstream because desulfurizing the hydrocarbon feed to the POX unit is usually impractical. The catalyst of this invention is useful for removing H₂S syngas streams generated by POX. In this case, the H₂S contaminated gas from the POX unit is subjected to the water gas shift reaction using a sulfur-tolerant catalyst (a.k.a. sour shift). Gas exiting the sour shift reactors contains mostly H₂ and most of the CO has been converted to C0₂. The gas still contains H₂S, which can then be removed by selective oxidation of H₂S into elemental sulfur and water vapor using the catalyst of this invention. The result is a sulfur-free hydrogen stream, which can be used to generate power in a fuel cell, can be used in oil refining to upgrade products, or can be used in an ammonia plant where hydrogen is reacted with nitrogen to form ammonia using an iron based catalyst.

[00078] In such processes, the catalyst of this invention is used to oxidize most of the H₂S in the feed to elemental sulfur and water without oxidation of hydrogen or low molecular weight hydrocarbons the feed. Because methane, light hydrocarbons, hydrogen and C0₂ are inert over the catalyst, H₂S oxidation can be done without the need for upstream H₂S separation. This is a distinct advantage over many of the more traditional methods of converting H₂S into sulfur. In many cases, for example the Claus process, the H₂S is currently removed from the gas stream and concentrated using an amine absorption unit with the concentrated H₂S stream feeding the Claus process. This adds expense and is uneconomical for desulfurizing gas that contains less than about 5% H₂S. The catalyst of this invention allows the gas to pass directly through the catalyst bed where H₂S is oxidized into sulfur and water, which are condensed downstream. None of the valuable hydrocarbons in the gas are oxidized. Particularly for H₂S concentrations below about 5%, the catalyst of this invention provides a more economical solution to gas desulfurization.

[00079] The catalysts and methods of this invention can be generally used for removing H₂S from H₂S-contaiminated hydrogen-containing gas streams, such as recycle streams in hydrodesulfurization (HDS) plants in petroleum refineries. As increasing quantities of sour crude are imported into the U.S. to make gasoline, larger amounts of H₂ are required to remove sulfur from the imported crude. Because H₂ is expensive, unreacted H₂ exiting the HDS unit is separated from the product gases (using an amine unit) and reused. The catalyst of this invention can be used to oxidize H₂S in the hydrogen into sulfur and water without oxidizing the hydrogen.

[00080] Heavy oils (for example, those from the San Joaquin basis of Southern California) are currently recovered by pumping steam at 1000 psia into the formation and then pumping out the oil. The steam serves to reduce the viscosity of the heavy oil and the pressure drives the oil to the recovery wells. The saturation temperature of 1000 psia steam is approximately 285°C. At this temperature, some thermal cracking of the hydrocarbons in the reservoir occurs as evidenced by the presence of about 2% hydrogen and various olefins (alkenes) in the gas that is recovered along with the oil. This gas from thermal cracking may simply be flared or more beneficially can supplement natural gas used to fire steam boilers. This gas, typically contains 1 -2 vol% H₂S. As a result, whether the gas is used as boiler fuel (typical Ci - C₃ concentrations are on the order of 20-25%) or flared, it must be desulfurized to meet S0₂ emissions regulations when burned. The catalysts of this invention are useful for oxidizing H₂S into elemental sulfur and water vapor for desulfurizing the gas containing low molecular weight hydrocarbons (Ci-C₄) produced during heavy oil recovery. In this application, heavier (C₅+) hydrocarbons that are or may be present are preferably removed upstream to prevent the possibility of catalyst fouling.

[00081] Another application of the catalysts of this invention is for removing H₂S from associated gas produced during heavy oil recovery, such as with the Steam Assisted Gravity Drainage (SAGD) recovery of bitumen from oil sands, for example, from Canadian oil sands. SAGD is a process similar to steam driven heavy oil recovery. In SAGD, high pressure steam is pumped into wells that have been horizontally drilled into oil or tar sand formations. The bitumen melts and drains down to similar horizontal wells that are used for recovery. The chemical compositions of heavy oil and tar sand bitumen are somewhat similar, and as a result the gas associated with bitumen recovery contains about 2% H₂, 1-2% H₂S and a considerable amount of C₅+ hydrocarbons. In application of the catalysts and methods of this invention to this application, the C₅+ hydrocarbons in the bitumen recovery gas are removed upstream of the H₂S oxidation reactor using art-recognized, commercially available technologies (e.g. refrigeration). Once the C₅+ hydrocarbons have been removed, the H₂S is removed by catalytic oxidation.

[00082] Because the catalysts of this invention can selectively oxidize H₂S into elemental sulfur and water without oxidizing hydrogen, the catalysts and the methods herein can also be applied to syngas clean-up, particularly to syngas produced by coal gasification (Satterfield 1991). Coal contains organically bound sulfur, as well as mineral sulfur, that when gasified produces H₂S because of the reducing atmosphere. For the syngas to be used for fuels or hydrogen production, the H₂S must be removed because it will poison the catalysts in downstream processes. However, to employ the present methods and catalyst to clean up syngas, the syngas should first be shifted using the water gas shift reaction:

CO + H₂0 = C0₂ + H₂ eq. 6 to minimize the concentration of carbon monoxide in the syngas, because sulfur vapor and CO will spontaneously react in the vapor phase under reaction conditions (e.g., in the absence of a catalyst) to produce carbonyl sulfide (COS) according to the reaction:

CO + S = COS eq. 7

[00083] For example, a common laboratory synthesis of COS entails passing CO over a pool of molten sulfur at 350°C (Brauer 1963). At this temperature, CO reacts with the sulfur vapor above the liquid sulfur to form COS. Similar experiments have been conducted using the catalyst test apparatus discussed in this invention with the same direct gas phase reaction between CO and sulfur vapor being observed. With shifted syngas, where the CO concentration is below about 5%, no more than about 250 ppm of COS will form. The catalysts and methods of this invention are thus particularly useful for removing H₂S from shifted syngas in a single step. The resulting sulfur free gas that contains H₂, water vapor and C0₂ can then be sent to a hydrogen separation membrane or pressure swing adsorption (PSA) unit for further purification.

[00084] Additionally, the catalysts and methods of this invention can be applied to remove sulfur and mercury from gas streams containing both H₂S and mercury vapor. Mercury vapor present in the gas streams being treated by the methods of this invention are reactively scavenged by sulfur formed on oxidation of H₂S. Reaction of mercury vapor with sulfur forms stable mercury (II) sulfide which can be readily removed from the gas stream. A process for removing both H₂S and mercury vapor is specifically useful for example for applications to gas- streams produced by coal gasification processes. U.S, patents 7,060,233 and 7,578,985 are incorporated by reference herein for descriptions of processes for and applications of sulfur and mercury removal from gases.

[00085] A schematic process scheme is shown in FIG. 1 for a Direct Oxidation (DO) catalytic reactor using the catalysts and methods of this invention. This process can be a stand-alone system or can be incorporated into art-recognized systems to facilitate or enhance H₂S removal in various processes. Sour syngas (i.e., containing H₂S) enters the DO reactor at temperatures ranging from 145 to 370 °C, where H₂S is oxidized into elemental sulfur, S0₂ and water according to equations 1 or 2 above. By adjusting the amount of oxygen added to the gas stream and/or adjusting the temperature of the process, the relative amounts of sulfur and S0₂ formed can be adjusted. [00086] There is no need for an amine-based acid gas removal (AGR) system in this system as DO reactor treats the gas directly. The catalyst is preferably operated at a temperature above the dew point of the sulfur vapor to prevent condensation of sulfur in the catalyst bed. The sulfur formed in the reactor is transferred through heat-traced lines to a Claus-type sulfur condenser that is operated at a pressure and temperature conditions to keep the sulfur liquid, without causing sulfur polymerization, which would plug the system. At ambient pressure, the sulfur condenser is operated at temperatures to avoid sulfur polymerization (wtiich starts at about 160°C, Tuller 1954; Nickless 1968). Sulfur condensers are typically operated at about 138 °C.

[00087] Employing a C₅+ free feed gas, the sulfur produced in the DO reactor of FIG. 1 is of Claus quality using catalysts and methods of this invention. The sulfur product can be sold or disposed of as desired. Clean gas exiting the sulfur condenser still contains about a relatively low level of sulfur vapor due to the vapor pressure of sulfur at the sulfur condenser temperature (about 75 ppm at 138°C.)

[00088] In a specific embodiment, the DO reactor of FIG. 1 can be operated to generate little or no S0₂. In this embodiment, the ratio of O₂/H₂S is preferably less than 3, and more preferably is less than 2. In this embodiment, the ratio of O₂ H₂S can be less than 1 , can be 0.5 (stoichiometric for sulfur formation) or can be less than 0.5.

[00089] In a specific embodiment, the DO reactor of FIG. 1 can be operated to generate a mixture of H₂S and S0₂. In this embodiment, the ratio of O₂ H₂S is preferably greater than 2 and more preferably is 3 (stoichiometric for S0₂ formation by eq. 2) or more. In this embodiment, the ratio of 0₂/H₂S can be greater than 3 or greater than 4 and typically is less than 10 or less than 8.

[00090] DO catalytic reactors of FIG. 1 can be combined in separate sequential multiple stages to improve H₂S removal and can also be used in combination with other processes. A single stage of direct oxidation will remove approximately 90% of 1 -2% H₂S in the feed. If more recovery is required, a second stage can be added where gas exiting the first stage is passed to the second stage (to obtain 99% removal). Alternatively, or in combination, gas with lower H₂S concentration exiting the DO reactor can be cycled back, with adjusted 0₂ content, into the DO reactor for removal of additional H₂S. If still further removal of H₂S is required, a standard downstream sulfur recovery unit can be added downstream of one or more stages of the DO reactor of FIG. 1. Standard sulfur recovery units include, among others, a liquid redox process, such as LO-CAT® process (Gas Technology Products, Inc.), a liquid-phase Claus process, such as CrystaSulf™ (Crystatech, Inc.) (Mclntush et al. 2000 & 2001) sulfur removal process, or an H₂S scavenger (e.g. iron oxide). For exemplary sulfur recovery processes, see Kohl, A.L and Nielsen, R. (1997) Gas Purification (Fifth Ed.) Gulf Publishing Company, Houston TX, Chapters 8 and 9.

[00091] In a specific application, the methods and catalysts of this invention can be combined with art-known liquid sulfur recovery processes. For exemplary liquid sulfur recovery processes, see Kohl, A.L. and Nielsen, R. (1997) Chapter 9. For example, the catalysts and methods of this invention can be used in hybrid sulfur recovery processes for upstream processing of gas streams that are to be introduced into downstream sulfur recovery processes. A primary function of the catalyst and methods of this invention in such hybrid or combined sulfur recovery systems is to reduce the sulfur load on those downstream sulfur recovery processes. In general, the catalysts and methods of this invention can be combined with any art-known sulfur recovery systems. In a specific embodiment, a DO reactor of FIG. 1 can be adapted upstream of an existing already-installed liquid sulfur recovery process.

[00092] In such hybrid sulfur recovery processes, the catalysts and methods of this invention can be used, for example as illustrated in FIG. 1 , to remove the bulk of the sulfur from gas streams that contain significant concentrations of hydrogen such as associated gas from heavy oil or bitumen recovery operations, hydrogen recycle in refinery streams, or in warm gas cleanup systems used in ammonia or hydrogen plants. In this process, catalysts of this invention are used to oxidize most (90% or more) of the H₂S in the feed to elemental sulfur and water without oxidation of hydrogen or low molecular weight hydrocarbons in the feed. Because methane, light hydrocarbons, hydrogen and C0₂ are inert over the catalyst, H₂S oxidation can be done without the need for upstream H₂S separation. Gas exiting the upstream process contains about 10% or less of the original H₂S and then is processed downstream by the other sulfur recovery process. The catalysts and methods of this invention can be employed to increase the capacity or expand the range of such sulfur recovery processes which are currently in place or when combined in new installations of such sulfur recovery processes reduce the sulfur load or the size of the equipment employed for carrying out the other sulfur recovery process.

[00093] In specific embodiments, the catalysts and methods of this invention can be combined with a nonaqueous absorption-based sulfur recovery process, a liquid-phase Claus process, such as the CrystaSulf™ (Crystatech, Inc.) sulfur removal process which is typically applied to natural gas and other gas streams. This sulfur removal process is a commercial nonaqueous sulfur recovery process that removes H₂S from gas streams by converting it into elemental sulfur see for example U.S. patents 6,416,729; 6,544,492; and 6,818, 194 and Mclntush et al. 2000; 2001. In a specific embodiment, for combination with a liquid-phase Claus process, such as the CrystaSulf™ (Crystatech, Inc.) process, the method and catalysts of this invention would be employed to preferably remove as much H₂S as possible in a single pass, typically to achieve around 90% H₂S, removal. The method and catalysts of this invention would not generate S0₂ sufficient for the liquid-phase Claus, so supplemental S0₂ feed would be needed as known in the art. Supplemental S0₂ may be obtained for example from combustion of sulfur generated in the DO of this invention. The temperature of gas exiting the DO of this invention can be readily adjusted using standard art-known methods (e.g., standard heat exchangers) to the inlet temperature appropriate for the liquid-phase Clause process (about 37 °C).

[00094] In another specific embodiment, the catalysts and methods of this invention can be combined with a liquid redox process. Such processes are typically used for small scale (ca. 0.2 - 10 ton/day) sulfur recovery operations because they are generally more economical than small-scale Claus sulfur recovery units. They are extremely efficient, removing over 99% of the sulfur in the feed. One of the best liquid oxidation systems in use are the LO-CAT® and LO-CAT® (II) processes (Gas Technology Products, Inc.), which are based on a liquid redox system with a dual-chelate iron solution. In this process, the H₂S containing gas stream is contacted with the chelated Fe³* complex catalyst in solution. The H₂S dissolves in the solution forming hydrosulfide ions (HS ) that reduce Fe³* to Fe²⁺ forming sulfur according to eq. 7. The solution is then regenerated with air oxidizing the Fe²⁺ to the original Fe^3* by eq. 8. 2Fe³⁺ HS^" 2Fe²⁺ S + H⁺ eq. 7

2Fe ⁺ + 0.5O₂ + H₂0 -> 2Fe³⁺ 20H^" eq. 8

[00095] Both reactions take place at about 50°C. The sulfur is generally removed as a froth in the oxidizer, since it is insoluble in the aqueous solution, and depending on the quantity and quality of the sulfur, it is either sold as a commodity chemical or sent to disposal. The effluent air from the liquid redox system is generally free of sulfur compounds and is either vented directly to the atmosphere or sent to an incineration unit prior to venting. Processes such as the Lo-CAT process cannot tolerate any significant levels of S0₂, because it leads to the formation of thiosulfate which builds up and adds cost because of the increased need for solution replacement.

[00096] Although liquid redox processes can recover more than 99% of the H₂S in small- scale gas treatment plants, there are some limitations. One of the major concerns is the high chemical costs for make-up and catalyst replacement. Also, gas/liquid mass transfer limitations are important and the vessels need to be somewhat large generating high capital costs. Formation of thiosulfate, HCN, bacterial growth, and thermal instability must be suppressed by chemical additives.

[00097] Employing the methods and catalysts of this invention, for example as in DO reactor FIG.1, upstream of a liquid redox process allows the size of the liquid redox unit to be reduced for a given application, which in turn reduces both capital costs and operating costs for sulfur recovery. By using sub-stoichiometric air and operating at a temperature just above the sulfur dew point, the process of this invention will convert about 90% of the incoming H₂S into elemental sulfur, leaving the remainder of the H₂S (10% of the original) unconverted. Essentially no S0₂ is formed. The product gas exiting the DO catalytic reactor is then processed in a liquid redox unit. By first removing the bulk of the sulfur with the DO catalytic process of this invention, the size of the LO-CAT unit can be decreased and the chemical and operating costs of the liquid redox unit will be lower than a liquid redox unit designed to process all of the original H₂S in the feed.

[00098] In another specific embodiment, the catalysts and methods of this invention can be combined with desulfurization processes that rely on a biological transformation (employing microorganisms) of sulfide to sulfur or of sulfite via sulfide to sulfur are employed commercially. A DO catalytic reactor of FIG. 1 can be employed upstream of such a biological desulfurization process. Hydrogen sulfide is first converted to hydrosulfide ions (HS ) that can be directly converted (oxidized) to elemental sulfur by sulfur bacteria, such as Thiobacilli. Sulfur dioxide (if present) is converted to sulfite (S0₃ ² ), which can, for example, be reduced to sulfide (S^2~) in an anaerobic reactor in the presence of microorganisms and hydrogen and the dissolved sulfide ions can then be oxidized to sulfur in an aerobic reactor in the presence of microorganisms (see, Janssen 2001 ). Exemplary commercial processes are those marketed as the Shell-Paques Thiopaq process or as the Thiopaq DeSOx process.

[00099] FIG. 2 schematically illustrates application of the methods and catalysts of this invention for H₂S removal from shifted syngas generated by gasification from coal or other carbonaceous feedstocks. The system (100) as labeled provides hydrogen as a fuel for a gas turbine (50) to generate power. The system (100) includes gasification (10) illustrated with coal, particulate filtering and ash removal (12), intermediate gas cooling (13), which can be used to generate high pressure steam (14) for power, high-temperature, sulfur-tolerant (sour) water gas shift (16), intermediate gas cooling (23) with more steam generation (14), and low temperature sour shift (26). If needed an optional sorbent bed (15) for removal of undesired metals (e.g., As, Se, Cd, etc.) can be positioned prior to the shift reactor (16). The system includes a reactor (20) for direct oxidation of H₂S into sulfur and water (as shown in FIG. 1) using the catalyst of this invention. The system can contain a reactor for hydrolysis of COS (18) to remove traces of COS (which is converted back to H₂S). The system can, if needed, be provided with a H₂S scavenger process (19) to remove residual H₂S. The product exiting steps 18 and 19 is syngas that is highly enriched in H₂ (essentially with no CO) with the balance being water vapor and C0₂. The C0₂ can be separated downstream (if desired) from hydrogen, for example using art-known membrane separation technology (30). The hydrogen can be burned in a gas turbine (50) as illustrated. Alternatively, the hydrogen can be fed to a fuel cell to generate electricity, or used as a chemical feedstock (e.g. ammonia production, hydrotreating in a petroleum refinery).

[000100] With respect to the processes illustrated in FIG. 2, including gasification processes, water shift reactor processes, optional COS hydrolysis processes, and H₂S scavenger processes, any art-recognized technologies can be employed in such systems. For example, H₂S scavenger process such as those provided in the art designated as Sulfatreat processes ( -l SWACO), some of which employ ZnO, can be employed. Similarly, art-known membrane separation and other gas separation technologies can be employed for separation of C0₂ from hydrogen.

[000101] In the system as illustrated in FIG. 2, H₂S is removed by catalytic oxidation with oxygen (usually from air). The entire gas stream is processed and there is no need for upstream physical or chemical solvents to extract or concentrate the H₂S. Catalytic oxidation of H₂S produces elemental sulfur (which is initially a vapor that is subsequently condensed and recovered downstream of the catalytic reactor) and water vapor.

[000102] It will be appreciated by one of ordinary skill in the art that the process flow diagram of FIG. 1 and the system flow diagram of FIG. 2 contain process elements/equipment including sulfur condensers, gasifiers, water shift reactors, COS hydrolysis reactors, H₂S scavengers, membrane separators for hydrogen separation from C0₂, particle and ash removal systems, sorbent beds, gas cooling equipment, and turbines that are illustrious of equipment and processes known in the art for implementing the indicated process or function. The ordinary skilled artisan will recognize a number of variations of such processes and equipment that can be readily employed or routinely adapted to achieve the indicated conversion, separation or function.

[000103] When a Markush group or other grouping is used herein, all individual members of the group and all combinations and possible sub-combinations of the group are intended to be individually included in the disclosure. Every combination of components or materials described or exemplified herein can be used to practice the invention, unless otherwise stated. One of ordinary skill in the art will appreciate that catalysts, supports, starting materials, synthetic methods, reaction conditions, reactor configurations, methods, device elements, and materials other than those specifically exemplified can be employed in the practice of the invention without resort to undue experimentation. All art-known functional equivalents, of any such methods, device elements, and materials are intended to be included in this invention. Whenever a range is given in the specification, for example, a temperature range, a frequency range, a time range, or a composition range, the ranges given are inclusive (unless specifically stated otherwise), and all intermediate ranges and all sub-ranges, as well as, all individual values included in the ranges given are intended to be included in the disclosure. Any one or more individual members of a range or group disclosed herein can be excluded from a claim of this invention. The invention illustratively described herein suitably may be practiced in the absence of any element or elements, limitation or limitations which is not specifically disclosed herein.

[000104] Gas percentages used herein refer to volume percent unless otherwise specified.

[000105] As used herein, "comprising" is synonymous with "including," "containing," or "characterized by," and is inclusive or open-ended and does not exclude additional, unrecited elements or method steps. As used herein, "consisting of" excludes any element, step, or ingredient not specified in the claim element. As used herein, "consisting essentially of" does not exclude materials or steps that do not materially affect the basic and novel characteristics of the claim. The term "comprising" is intended to be broader than the terms "consisting essentially of" and "consisting of, however, the term "comprising" as used herein in its broadest sense is intended to encompass the narrower terms "consisting essentially of " and "consisting of.", thus the term "comprising" can be replaced with "consisting essentially of to exclude steps that do not materially affect the basic and novel characteristics of the claims and "comprising" can be replaced with "consisting of to exclude not recited claim elements.

[000106] Although the description herein contains many specifics, these should not be construed as limiting the scope of the invention, but as merely providing illustrations of some of the embodiments of the invention.

[000107] Each reference cited herein is hereby incorporated by reference in its entirety. However, if any inconsistency arises between a cited reference and the present disclosure, the present disclosure takes precedent. Some references provided herein are incorporated by reference to provide details concerning the state of the art prior to the filing of this application, other references may be cited to provide additional or alternative device elements, additional or alternative materials, additional or alternative methods of analysis or applications of the invention. Patents and publications mentioned in the specification are indicative of the levels of skill of those skilled in the art to which the invention pertains. References cited herein are incorporated by reference herein in their entirety to indicate the state of the art as of their publication or filing date and it is intended that this information can be employed herein, if needed, to exclude specific embodiments that are in the prior art.

[000108] One of ordinary skill in the art will appreciate that device elements, as well as materials, shapes and dimensions of device elements, as well as methods other than those specifically exemplified can be employed in the practice of the invention without resort to undue experimentation. All art-known functional equivalents, of any such materials and methods are intended to be included in this invention. The terms and expressions which have been employed are used as terms of description and not of limitation, and there is no intention that in the use of such terms and expressions of excluding any equivalents of the features shown and described or portions thereof, but it is recognized that various modifications are possible within the scope of the invention claimed. Thus, it should be understood that although the present invention has been specifically disclosed by preferred embodiments and optional features, modification and variation of the concepts herein disclosed may be resorted to by those skilled in the art, and that such modifications and variations are considered to be within the scope of this invention.

THE EXAMPLES

[000109] Example 1: Catalyst Synthesis

Catalysts are typically prepared by the incipient wetness method, also referred to as wet impregnation, where the support material is contacted with a solution containing dissolved catalyst components. Selected metal precursors are dissolved in water and the support material is contacted with the solution. The impregnated support is dried and then calcined. As noted above, supports exhibiting substantially no Claus activity are preferably employed. The preferred support material is silica.

[000110] A. Preparation of the catalyst by impregnation of a silica support with nitrate salts

To prepare 100 grams of catalyst containing 73 wt% silica (Si0₂), 14 wt% sodium (as Na₂0), 9 wt% calcium (as CaO) and 4 wt% Mg (as MgO), dissolve 38.39 grams of sodium nitrate (NaN0₃), 25.45 grams of magnesium nitrate hexahydrate (Mg(N0₃)₂.6 H₂0), and 37.90 grams of calcium nitrate tetrahydrate (Ca(N0₃)₂ ^» 4 H₂0) in 58.49 grams of hot distilled water. Use this solution to impregnate 73 grams of high surface area (> 80 m²/g) silica (Si0₂) (fumed or pellets) under vacuum. The impregnation is done by placing the silica in a vacuum flask and evacuating the air with a vacuum pump. This removes air from the internal pores of the silica support and allows the nitrate solution to enter the pores. After impregnation, the vacuum is relieved, the catalyst removed, and transferred to a porcelain evaporating dish. The dish is placed in an oven and dried in air at 130°C for 20 hours. The porcelain dish is then transferred to a muffle furnace where the catalyst is calcined in air at 400°C for 20 hours. The dish is initially placed in a cold furnace and the temperature of the furnace is ramped a rate of 10°C/minute until the temperature reaches 400°C at which point the 20 hour calcining begins.

[000111] B. Preparation of the catalyst by wet mixing of silica support with

hydroxides

The preparation of 100 grams of catalyst containing 73 wt% silica (Si0₂), 14 wt% sodium (as Na₂0), 9 wt% calcium (as CaO) and 4 wt Mg (as MgO), requires 11.89 grams of calcium hydroxide (Ca(OH)₂), 5.79 grams of magnesium hydroxide Mg(OH)₂ and 18.07 grams of sodium hydroxide (NaOH). Dissolve 18.07 grams of NaOH in approximately 58 mL of water. Add this solution to 73 grams of Si0₂ pellets, 11.89 grams of Ca(OH)₂ and 5.79 grams of Mg(OH)₂. Place contents into polyethylene jar containing ceramic milling balls. Add enough water to wet the entire mixture. Calcium and magnesium hydroxides have low solubilities in water and the mixture will be silica pellets in a thin paste of Ca(OH)₂ and Mg(OH)₂.

Commutate in the ball mill for 4 hours. Remove paste and place in porcelain evaporating dish and dry in a drying oven at 130°C for 20 hours. Calcine catalyst at 400°C for 20 hours.

[000112] Example 2: Catalyst Test Methods

A catalyst test apparatus was designed for assessment of catalytic oxidation of H₂S in H₂S- containing gases to elemental sulfur and water. The apparatus can be employed for example to assess H₂S oxidation in the presence of simulated coal-derived syngas, as well as shifted syngas. All of the tubing and fittings of the apparatus are made from 316 stainless steel and have been coated with a chemically vapor deposited layer of silica (Restek SilcoSteel™). Relatively large tubing (¹/₂" O.D.) are used to minimize plugging with sulfur, which can happen if there are cold spots, or if liquid sulfur is overheated. Test pressure can range up to about -750 psig and test temperature can range up to ~600°C and space velocities of 100 to 2000 volume gas/volume catalyst/hour can be used. The apparatus is equipped to feed and control multiple gases and liquids. The gases are blended together in a stainless steel manifold. More specifically H₂S (diluted with nitrogen), C0₂, CO, H₂ can be metered into the system and liquid water can be injected into a heated section of tubing where it is vaporized into steam. A chemical metering pump (ISCO Model 100DM) is used to control the flow rate of water. The gases, steam and dilute 0₂ (again in N₂) are then mixed and fed to the reactor. The flow rates are adjustable so that the feed to the reactor has the desired composition for catalyst testing. The total flow rate of the gases fed to the reactor is between 0.5 - 1.5 standard liter/min. The system pressure is controlled using a Badger Meter Co. pressure control valve (PCV) that is located downstream of the reactor. A pressure transducer on the system supplies a signal to computer that controls the valve and maintains the desired pressure upstream of the PCV.

[000113] After gases have been blended in the manifold, they pass into a short section of 1/2 " tubing where the gas is preheated to ~50°C below the selected catalyst test temperature. A typical simulated syngas composition is 30% CO, 20% H₂, 10% C0₂, 20% H₂0, 1% H₂S with the balance N₂. Typical catalyst test temperatures are 160°C to 400°C, and depending on the experiment, the H₂S concentration can vary from 100 ppm to -1% (10,000 ppm). Higher concentrations of any of the gases can be achieved by adjusting the flow rates.

[000114] The preheated gas mixture then flows into a 316 stainless steel catalyst test reactor. Different sizes of reactor which accommodate different amounts of catalyst can be used. Typically, for these tests, the test reactor was made from a 1/2" VCR bulkhead union holding 5-10 grams of granulated catalyst. The catalyst is held in place using VCR gaskets at the top and bottom of the reactor. The gaskets have 60 um stainless steel frits that allow gas to pass through with minimal pressure drop but prevent the catalyst from falling out of the reactor. Thermocouples are used to monitor the catalyst bed temperature as well as for temperature control. The reactor is heated using a three-zone Mellen brand tube furnace. All of the reactor parts were coated with SilcoSteel™ by Restek. The different size reactors are easy to change out, which is very useful, especially when performing tests over wide ranges of space velocities (cm³g_as/cm³ _Mtaiyst/hour) because it allows us to use the mass flow controllers within their most accurate flow ranges.

[000115] Gases leaving the reactor pass through a sulfur condenser maintained at about 130°C using circulating hot silicone oil. A Sentry heat transfer coil is used as the condenser and a Thermo Haake hot oil circulator supplies the heat transfer fluid. Product gas from the oxidation reactor contains sulfur vapor which flows through the inner tube of the heat transfer coil. The hot silicone oil flows through the annular space between the inner and outer tubes. The coil is insulated externally and the flow rate of silicone oil through the bath is high enough that there is very little temperature difference between the inlet and outlet of the sulfur condenser. Approximately isothermal operation ensures that sulfur will not solidify inside the condenser or become overheated and harden through polymerization. Liquid sulfur has a moderately narrow temperature range (from 120°C to 170°C) where sulfur is liquid, but still has a reasonable viscosity. Overheating sulfur (c.a. 180°C) can cause plugging at the coil due to the formation of the polymeric "plastic sulfur."

[000116] Downstream of the sulfur condenser, liquid sulfur flows into a 1 -liter stainless steel sample cylinder that acts as a storage vessel. The vessel is heated with three close-fitting band heaters and is insulated. The temperature is maintained at about 30°C. A heat-traced valve located below the sulfur vessel is used to periodically drain the vessel.

[000117] Downstream of the sulfur collection vessel, the gas flows through a second stainless steel cylinder that is packed with borosilicate glass wool (Pyrex™). The temperature of this vessel is kept below the melting point of sulfur (m.p. = 115°C) to remove entrained sulfur aerosols and residual sulfur vapor (in equilibrium with liquid in the sulfur pot). The temperature in the glass-wool filled knockout is kept at ~90°C. Downstream of the knockout are two stainless steel filters that keep solids out of the pressure control valve (PVC). There is a bypass around the PCV for manual depressurization or operation at ambient pressure, if necessary.

[000118] Product gas analysis is done on-line using a gas chromatograph (GC,SRI

Instruments Inc.). A slipstream of gas downstream of the PCV flows continuously through a gas sampling valve located on the GC. The sampling valve is periodically cycled to inject a gas sample into the instrument. The GC is also computer controlled, but with a separate program supplied by the manufacturer. The GC uses a packed column (Restek RT-Sulfur) to separate H₂, CO, C0₂, CH₄, H₂S, H₂0 and COS.

[000119] The GC is equipped with two different types of detectors: 1 ) a thermal conductivity detector (TCD) for high gas concentrations that is sensitive to all gases, and 2) a flame photometric detector (FPD) that is selective and very sensitive to sulfur compounds. In a TCD, gases exiting the GC column pass through a cell having two heated filaments. Pure carrier gas (He) flows through two other filaments in a parallel cell. The cells are heated to prevent condensation. When an individual component of the gas elutes from the GC column the thermal conductivity of the gas is briefly lower than that of the pure carrier gas in the reference cell. The filaments are connected using a Wheatstone bridge and when the thermal conductivity in the sample side changes the bridge becomes unbalanced and a signal is generated. Because thermal conductivity differences are measured, the TCD can detect any gas with a thermal conductivity lower than that of He. When hydrogen (a gas with a very high thermal conductivity) is measured, the carrier gas used is a mixture of 3% H^He to improve the sensitivity for H₂.

[000120] Gas exiting the TCD passes into the FPD where sulfur compounds are detected. In the FPD, the sample is burned in a hydrogen/air flame. When organic compounds burn in the flame, C0₂ and H₂0 are produced to which the FPD is blind. When sulfur is present (for example as COS, H₂S, S0₂ etc.), combustion in the H₂/air flame results in the formation of electronically excited S₂ molecules. When the S₂ molecules relax to the ground state, radiation is emitted at 394 nm. An optical filter is placed between the flame and a

photomultiplier that only passes radiation at this wavelength. The result is that the FPD only detects sulfur compounds. The advantages of using FPD are that any peak that appears in the FPD spectrum contains sulfur, and the FPD is extremely sensitive (-200 ppb). This makes the FPD useful for accurate measurement of high conversions of H₂S (low outlet concentration) and for measuring low levels of undesirable sulfur compounds such as COS and S0₂.

[000121] Gas exiting the system is scrubbed in a carboy containing about 10 gallons of bleach (10% NaOCI) to oxidize unreacted H₂S and S0₂ to form sodium sulfites and sulfates which remain in solution. Scrubbed gas from the outlet of the carboy is attached to the laboratory ventilation system and exhausted.

[000122] The system is fully computer controlled using an automated control system with process control software (OPTO 22, Temecula, CA) and thus can run continuously and unattended. The control system runs on a Windows® operating system-based (Microsoft Corp) desktop PC. Process conditions, including temperature and pressure, are continuously monitored and recorded to the PC hard drive. The computer also serves as a safety device, shutting down the apparatus in a controlled manner in the event of a malfunction. Mechanical pressure relief and independent temperature monitoring electronics (with their own

thermocouples) are used to back up the computer in the event of an excessive temperature or pressure event. The process control software is used in conjunction with autonomous control modules for maintaining process conditions. The process control software sends set points from the PC to the control modules located in a separate electrical (NEMA type) enclosure. The control system modules perform the actual control function and the PC simply serves as an interface for downloading control logic and set points and monitoring process variables. Proportional-integral-derivative (PID) control logic is used to maintain the system pressure and temperatures. The gas flow rates are maintained by the internal electronics of the mass flow controllers once they receive a set point from the control system software.

[000123] Example 3: CATALYST TEST RESULTS

A. Testing of Silica Support Alone

FIG. 3 shows the test results when the catalytic reactor contained fumed silica granules. A mixture of H₂S, air, and nitrogen were admitted into the reactor at a flow rate that gave a space velocity of approximately 1000 volume gas/volume catalyst/hour. The H₂S concentration remained constant at the inlet concentration (1% = 10,000 ppm) for approximately 90 hours indicating that the silica granules were catalytically inactive. The temperature was 240°C and the pressure was 250 psig. The thermal conductivity detector read about 10% high (11 ,000 ppm in FIG. 2); this was corrected for in all catalyst tests.

[000124] Catalyst Test with Simulated Associated Gas

FIG. 4 shows initial results for a test of a catalyst that had a composition of the specific example catalyst shown in Table 1 using a simulated associated gas that had a composition similar to that of the associated gas. Associated gas is produced during heavy oil and underground tar sand bitumen production. The experiment was done at ambient pressure, 220°C with varying O₂/H₂S ratios.

[000125] The experiment was divided into four phases and the H₂S conversion and S0₂ concentration was measured at each phase. Between zero and 48 hours the 0₂/H₂S ratio was 0₂/H₂S = 0.5, which is stoichiometric for the reaction: H₂S + ½ 0₂ = S + H₂0. During the first 18 hours of the experiment, S0₂ production was unsteady. Between 18 and 48 hours, the catalyst reached steady state producing about 700 ppm of S0₂. The H₂S conversion between zero and 48 hours was greater than 95%. When the 0₂/H₂S ratio was reduced to slightly less than stoichiometric (0₂ H₂S = 0.45) the S0₂ concentration in the product gas was reduced to 100 ppm. During this initial time period, the feed gas concentration was 1% H₂S, 0.5% 0₂, with the balance split between C0₂ and N₂. During the time when the C½ H₂S = 0.45, the H₂S concentration was approximately 95% with no sign of catalyst deactivation. At approximately 115 min, the concentration of nitrogen was decreased, and methane increased so that methane concentration was 29%. Methane is the hydrocarbon present in greatest

concentration in associated gas. The presence of methane caused the S0₂ concentration to increase slightly to about 175 ppm, but the H₂S conversion remained constant at 95%. Finally, at about 135 min, 1.3% hydrogen was added to the gas. This caused a decrease in the amount of S0₂ back to about 100 ppm. The H₂S conversion dropped to about 93%.

[000126] FIGS. 5-9 show the results of catalyst testing on samples of the specific catalyst of Table 1 , where the synthesis was scaled up to produce 10 kg of catalyst in four batches of 2.5 kg each. This batch size was chosen based on the limitations of the available equipment, and the fact that 2.5 kg represents a scale up factor of 25 (rather than 100 if all of the catalyst was made in one batch). Previously the largest amounts of catalyst made in one batch in the laboratory were 100-200 grams. FIGS. 5-9 show the results of internal quality control experiments on each batch of catalyst. These experiments were done on a small grab sample of each 2.5 kg batch to verify that the scaled up synthesis reproduced the catalyst synthesis at the 100-200 gram scale. Each batch was separately calcined and then tested in the laboratory.

[000127] FIG. 5 shows the results for the first batch of catalyst. The test temperature was 240°C, the pressure was ambient, and a space velocity of 1000 volume gas/volume catalyst/hour was used. Initially, the O^H₂S was set at stoichiometric (0₂/H₂S = 0.5). During this time the H₂S conversion was approximately 92% and about 100 ppm of S0₂ was produced. The 0₂/H₂S ratio was then lowered to 0₂/H₂S = 0.45. This caused a slight decrease in the H₂S conversion from 92% to about 86%, but S0₂ was essentially eliminated. FIGs. 6-8 show similar results for the other three 2.5 kg batches of catalyst.

[000128] Catalyst Testing with Simulated Coal-Derived Synthesis Gas Subjected to Water-Gas Shift

Coal gasification produces syngas that is a mixture of CO, C0₂, H₂ and methane where the components present in the highest concentrations are CO and H₂. Under the conditions employed for H₂S oxidation, gas phase CO will react with sulfur vapor in the absence of a catalyst to form COS, i.e., the thermal rates and equilibrium constant are favorable under these conditions (Svoronos and Bruno 2002; Brauer 1963). For cyclooctasulfur (C₈) the reaction would be:

S₈ + 8CO -» 8COS, AG = -43 kcal/mole of S₈ eq. 9

[000129] However, any of the other sulfur species present in the vapor phase (the next most abundant is S₆) could also react with CO to form COS. As a result H₂S oxidation to elemental sulfur in the presence of both CO and H₂ (while not oxidizing either gas) produces unacceptable amounts of carbonyl sulfide (COS) from the above reaction. If, however, the syngas is first subjected to several stages of the water-gas-shift reaction:

CO + H₂0 = C0₂ + H₂ eq. 10 then the CO concentration can be reduced to levels where little COS is formed. Under these conditions, H₂S oxidation is taking place in a gas stream that contains mostly H₂, C0₂ and water vapor (i.e., shifted syngas). We have observed that when the CO concentration in the gas has been reduced to approximately 3%, then about 250 ppm of COS will form.

[000130] FIG. 9 shows the result of an H₂S oxidation experiment using the specific CaO- MgO-Na₂0 catalyst supported on silica (of Table 1). In this experiment, the oxygen

concentration was 2 vol% and the H₂S concentration was 2500 ppm (0.25%) which gives a 0₂/H₂S ratio = 8. The hydrogen concentration was quite high (30 vol%) along with 25% C0₂ to simulate shifted syngas. The water concentration was 2% and the balance was nitrogen (40.75%). The catalyst temperature was 220°C and the system pressure was 200 psig.

[000131] The large increase in H₂S concentration observed between 0 and 2 hours in FIG. 9 (above the H₂S feed to the reactor, which was 2500 ppm) was due to degassing of liquid sulfur in the system (H₂S dissolves in liquid sulfur forming a variety of sulfanes (H₂S_X), Nickless 1968). Therefore, every time the flow of H₂ was started, a H₂S transient was observed.

Although the H₂S transient in FIG. 9 appears to be long lived, this is an artifact of the residence time in the system rather than an indication of the rate of H₂S outgassing from molten sulfur. The volume of the reactor system (including the sulfur pot downstream of the condenser) is about 3 liters and the operating pressure is 200 psig. The total gas flow rate was about 565 standard cm³/min (seem), which at temperature and pressure corresponds to an actual gas flow rate of only 66 cm³/min. Thus, one residence time is 3000/66 = 45 min. For a step concentration change in any system, at least 3 residence times are required for the system to stabilize at a new level.

[000132] The oxygen was added at t = 2 hr to wait for the transient to pass, and as soon as it was added, the H₂S concentration began to decrease. By 6 hours, 100% H₂S conversion was achieved, where it remained for the next 10 hours. This result indicates that hydrogen is not competing with H₂S for oxygen. Because the H₂S conversion remained at 100% for a time long enough to displace all of the gas in the system at least 10 times, these results show the steady state activity and selectivity of the exemplary catalyst. In this experiment, a large amount of oxygen was added to determine if it would lead to excessive S0₂ formation, and it did not as levels of S0₂ detected were found to be less than 100 ppm.

[000133] The foregoing examples are in no way intended to be limiting. REFERENCES

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Removing Sulfur for High-pressure Sour Natural Gas with Sulfur Throughputs between 1 and 30 Long Tons/Day," Proc. 80W Annual GPA Convention

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Process," Proceedings Reid Gas Conditioning, Conference, February 27 - March 1 ,

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Claims

We Claim:

1. A method for oxidizing H₂S to elemental sulfur, S0₂ or both by contacting a gas stream containing H₂S with oxygen and a catalyst comprising one or more alkali metals, one or more alkaline earth metals or a combination thereof supported on silica or silica-alumina which does not exhibit reverse Clause activity and wherein the catalyst does not contain a transition metal

2. The method of claim 1 wherein the catalyst support is silica.

3. The method of claim 1 or claim 2 wherein alkali metal calculated as metal oxide represents from 2 to 25% by weight of the catalyst, and the alkaline earth, calculated as metal oxide, represent from 2-50% by weight of the catalyst.

4. The method of claim 1 or claim 2 wherein the catalyst further comprises one or more lanthanide metals.

5. The method of claim 1 or claim 2 wherein the catalyst further comprises one or more lanthanide metals and wherein the lanthanide metal calculated as metal oxide represents from 2 to 25% by weight of the catalyst.

6. The method of claim 1 or claim 2 wherein the catalyst comprises one or more alkali metals and one or more alkaline earth metals.

7. The method of claim 1 or claim 2 wherein the alkali metals are selected from Na, K or mixtures thereof and the alkaline earth metals are selected from Mg, Ca or mixtures thereof.

8. The method of claim 1 or claim 2 wherein the catalyst comprises Na, Mg and Ca.

9. The method of claim 1 or claim 2 wherein the catalyst comprises Na, Mg and Ca and wherein Na calculated as metal oxide represents from 2 to 25% by weight of the catalyst, and the total of Mg and Ca calculated as metal oxide, represent from 2-50% by weight of the catalyst.

10. The method of claim 1 or claim 2 wherein the catalyst comprises Na, Mg and Ca and wherein Na calculated as metal oxide represents from 10-15% by weight of the catalyst, Mg calculated as metal oxide, represents from 2-6% by weight of the catalyst, and Ca calculated as metal oxide, represents from 7-11% by weight of the catalyst and the balance of the catalyst is silica.

11. The method of claim 1 or claim 2 wherein the catalyst comprises Na, Mg and Ca and wherein Na calculated as metal oxide represents about 14% by weight of the catalyst, Mg calculated as metal oxide, represents about 4% by weight of the catalyst, and Ca calculated as metal oxide, represents about 9% by weight of the catalyst and the balance of the catalyst is silica.

12. The method of claim 1 or claim 2 wherein the catalyst comprises one or more alkali metals and one or more lanthanide metals.

13. The method of claim 1 or claim 2 wherein the catalyst comprises one or more alkali metals and one or more lanthanide metals and wherein alkali metal, calculated as metal oxide represents from 2 to 25% by weight of the catalyst, and lanthanide metal, calculated as metal oxide, represents from 2-25% by weight of the catalyst.

14 The method of claim 1 or claim 2 wherein the catalyst comprises one or more alkali metals and one or more lanthanide metals and wherein the alkali metal is selected from Na or K and the lanthanide metal is selected from lanthanum or yttrium.

15. The method of claim 1 or claim 2 wherein the catalyst comprises one or more alkali metals, one or more alkaline earth metals and one or more lanthanide metals.

16. The method of claim 1 or claim 2 wherein the catalyst comprises one or more alkali metals, one or more alkaline earth metals and one or more lanthanide metals and wherein alkali metal, calculated as metal oxide represents from 2 to 25% by weight of the catalyst, alkaline earth, calculated as metal oxide, represents from 2-25% by weight of catalyst and lanthanide metal, calculated as metal oxide, represents from 2-25% by weight of the catalyst.

17. The method of claim 1 or claim 2 wherein the catalyst comprises one or more alkali metals, one or more alkaline earth metals and one or more lanthanide metals and wherein the alkali metal is selected from Na, K or mixtures thereof, the alkaline earth is selected from Mg, Ca or mixtures thereof and the lanthanide metal is selected from lanthanum, cerium, praseodymium, neodymium, samarium, europium, gadolinium, terbium, dysprosium, holmium, erbium, thulium, ytterbium, lutetium, yttrium, scandium or mixtures thereof.

18. The method of claim 1 or claim 2 wherein the gas stream is contacting catalyst at a temperature ranging from 140 to 370°C and at ambient pressure to about 1000 psig.

19. The method of claim 1 or claim 2 wherein hydrogen is present in the gas stream and less than 20% by volume of the hydrogen present is consumed during oxidation of H₂S.

20. The method of claim 1 or claim 2 wherein hydrogen is present in the gas stream in an amount ranging from 0.5% by volume to 35% by volume.

21. The method of claim 1 or claim 2 wherein the gas stream further comprises C0₂.

22. The method of claim 1 or claim 2 wherein hydrogen is present in the gas stream and wherein the gas stream further comprises C0₂.

23. The method of claim 1 or claim 2 wherein the gas stream comprises less than 5% by volume of CO.

24. The method of claim 1 or claim 2 wherein hydrogen is present in the gas stream and wherein less than 10% by volume of the hydrogen in the gas stream is oxidized.

25. The method of claim 1 or claim 2 wherein hydrogen is present in the gas stream and wherein less than 5% by volume of the hydrogen in the gas stream is oxidized.

26. The method of claim 1 or claim 2 wherein the gas stream further comprises Ci-C₄ hydrocarbons.

27. The method of claim 1 or claim 2 wherein the gas stream further comprises CrC₄ hydrocarbons and wherein less than 10% by volume of CrC₄ hydrocarbons in the gas stream is oxidized.

28. The method of claim 1 or claim 2 wherein the gas stream further comprises C_rC₄ hydrocarbons and wherein less than 5% by volume of the C C₄ hydrocarbons in the gas stream is oxidized.

29. The method of claim 1 or claim 2 wherein the gas stream comprises hydrogen and Ci-C₄ hydrocarbons.

30. The method of claim 1 or claim 2 wherein the ratio of 0₂/H₂S during the contacting step is 0.3 or higher.

31. The method of claim 1 or claim 2 wherein the ratio of 0₂/H₂S during the contacting step is 0.5 or higher.

32. The method of claim 1 or claim 2 wherein the ratio of 0₂/H₂S during the contacting step is 1 or higher.

33. The method of claim 1 or claim 2 wherein the ratio of 0₂/H₂S during the contacting step is 2 or higher.

34. The method of claims 1 or claim 2 wherein the gas stream further comprises mercaptans.

35. The method of claim 1 or claim 2 wherein the gas stream is associated gas associated gas from heavy oil or bitumen recovery.

36. The method of claim 1 or claim 2 wherein the gas stream is a hydrogen recycle stream.

37. The method of claim 1 or 2 wherein the gas steam is predominantly C0₂.

38. The method of claim 1 or claim 2 wherein substantially no S0₂ is formed by oxidation with 0₂.

39. A catalyst for oxidizing H₂S in the presence of oxygen comprising:

one or more alkali metals, one or more alkaline earth metals and optionally one or more lanthanide metals supported on a silica or alumina-silica support material which exhibits no substantial level of Claus activity under the conditions employed for H₂S-oxidation.

40. The catalyst of claim 39 wherein the support is silica.

41. The catalyst of claim 40 which comprises sodium, calcium and magnesium on a silica support.

42. The catalyst of claim 41 wherein sodium calculated as Na₂0 represents from 2 to 25% by weight of the catalyst and combined calcium and magnesium calculated as the respective metal oxides represent from 2-50% by weight of the catalyst.

43. The catalyst of claim 41 wherein sodium calculated as Na₂0 represents from 12 to 16% by weight of the catalyst and combined calcium and magnesium calculated as the respective metal oxides represent from 12-16% by weight of the catalyst.

44. The catalyst of claim 41 wherein sodium calculated as Na₂0 represents from 12 to 16% by weight of the catalyst and calcium calculated as CaO represents from 7 to 11 % by weight of the catalyst and magnesium calculated as MgO represents from 2- 6% by weight of the catalyst.

45. The catalyst of claim 40 consisting of sodium, calcium and magnesium on a silica support.

46. The catalyst of claim 45 wherein sodium calculated as Na₂0 represents from 2 to 25% by weight of the catalyst and combined calcium and magnesium calculated as the respective metal oxides represent from 2-50% by weight of the catalyst.

47. The catalyst of claim 45 wherein sodium calculated as Na₂0 represents from 12 to 16% by weight of the catalyst and calcium calculated as CaO represents from 7 to 11 % by weight of the catalyst and magnesium calculated as MgO represents from 2- 6% by weight of the catalyst.