# US 9,433,894 B2 · Removal of hydrogen sulfide from gas streams > Agents: this data is available as JSON from the patentgrep API and MCP server — see https://patentgrep.com/llms.txt - Number: US 9,433,894 B2 - Document ID: US9433894B2 - Status: Granted - Kind: B2 - Application number: 14/261,550 - Filed: 2014-04-25 - Published: 2014-11-13 - Granted: 2016-09-06 - Earliest claimed: 2013-05-09 - Assignees: Tronox Alkali Wyoming Corporation - Applicants: Tronox Alkali Wyoming Corporation - Inventors: Gerald Niedringhaus - Web page: https://patentgrep.com/patent/US9433894B2 ## CPC - B01D 53/526: {Mixtures of hydrogen sulfide and carbon dioxide} - B01D 53/52: Hydrogen sulfide - B01D 53/78: with gas-liquid contact - C01D 7/126: {Multi-step processes, e.g. from trona to soda ash} - B01D 2251/304: of sodium - B01D 2251/606: Carbonates - B01D 2256/22: Carbon dioxide - B01D: SEPARATION (separating solids from solids by wet methods B03B, B03D; by pneumatic jigs or tables B03B; by other dry methods B07; magnetic or electrostatic separation of solid materials from solid materials or fluids, separation by high-voltage electric fields B03C; centrifuges, vortex apparatus B04; presses per se for squeezing-out liquid from liquid-containing material B30B9/02; treatment of water C02F, e.g. softening by ion-exchange C02F1/42; {arrangements of air intake cleaners in gas turbine plants F02C7/05} ; arrangements or mounting of filters in air-conditioning, air-humidification or ventilation F24F13/28) - C01D: COMPOUNDS OF ALKALI METALS, i.e. LITHIUM, SODIUM, POTASSIUM, RUBIDIUM, CAESIUM, OR FRANCIUM (metal hydrides {monoborane, diborane or addition complexes thereof} C01B6/00; salts of oxyacids of halogens C01B11/00; peroxides, salts of peroxyacids C01B15/00; sulfides C01B17/22; thiosulfates, dithionites, polythionates C01B17/64; compounds containing selenium or tellurium C01B19/00; binary compounds of nitrogen with metals C01B21/06; azides C01B21/08; {compounds other than ammonia and cyanogen, containing nitrogen and other non-metals C01B21/082}; metal amides C01B21/092; nitrites C01B21/50; phosphides C01B21/50; {compounds of noble gases C01B23/0005}; phosphides C01B25/08; salts of oxyacids of phosphorus C01B25/16; carbides C01B32/90; compounds containing silicon C01B33/00; compounds containing boron C01B35/00; cyanides C01C3/08; salts of cyanic acid C01C3/14; salts of cyanamide C01C3/16; thiocyanates C01C3/20) ## Abstract A method for removing hydrogen sulfide from a gas stream in a gas-liquid absorber apparatus having two separate absorption sections and utilizing a first absorber alkali solution stream that is a waste sodium carbonate source from a soda ash production facility and a second absorber alkali solution stream that is a process feed stream from a soda ash production facility. The method is particularly well suited for removing H2S from a CO2-containing gas stream generated in a soda ash production facility. ## Claims ### Claim 1 A method for removing hydrogen sulfide from a carbon dioxide gas stream in a soda ash production facility comprising introducing a H2S-contaminated carbon dioxide gas stream from a carbon dioxide stripping unit operation in a soda ash production facility containing at least 20 vol % CO2 into a gas absorption apparatus for sequential contact of the gas stream with a first absorber alkali stream in a first absorber section and with a second absorber alkali stream in a second absorber section, wherein the first absorber alkali stream is an aqueous alkali waste stream containing at least 1 wt. % Na2CO3 and solubilized impurities from the soda ash production facility and is contacted with the H2S-contaminated carbon dioxide gas stream in the first absorber section of the gas absorption apparatus in an amount sufficient to absorb a substantial amount of the H2S from the gas stream to produce a H2S-depleted carbon dioxide gas stream and a first absorber effluent stream containing the absorbed H2S, and wherein the second absorber alkali stream is an aqueous process stream containing at least 1 wt. % Na2CO3 from the soda ash production facility and is contacted with the H2S-depleted carbon dioxide gas stream in the second absorber section of the gas absorption apparatus in an amount sufficient to absorb a substantial amount of the residual H2S in the H2S-depleted carbon dioxide gas stream from the gas stream to produce a purified carbon dioxide gas stream and a second absorber effluent stream containing the absorbed residual H2S; withdrawing the first absorber effluent stream containing absorbed H2S and solubilized impurities from the first absorber section; withdrawing the second absorber effluent stream containing absorbed residual H2S from the second absorber section and thereafter utilizing the second absorber effluent stream in the soda ash production facility, for further processing for recovery of its solubilized Na2CO3 values; and withdrawing the purified carbon dioxide gas stream from the gas absorption apparatus. ### Claim 2 (depends on 1) The method of claim 1 wherein the first absorber section and the second absorber section are each a single stage absorption unit and a portion of the first absorber effluent stream is recycled to the first absorber section. ### Claim 3 (depends on 1) The method of claim 1 wherein the H2S-contaminated carbon dioxide gas stream obtained from the carbon dioxide stripping unit operation in a soda ash production facility contains at least about 30 vol. % CO.sub.2. ### Claim 4 (depends on 1) The method of claim 1 wherein the H2S-contaminated carbon dioxide gas stream obtained from the carbon dioxide stripping unit operation in a soda ash production facility contains at least about 0.1 vol. % H2S. ### Claim 5 (depends on 1) The method of claim 1 wherein the first absorber alkali stream is obtained from a source selected from group consisting of monohydrate crystallizer purge solution, decahydrate crystallizer purge solution, sesquicarbonate crystallizer purge solution, sodium bicarbonate crystallizer purge solution, trona mechanical mining waste water, surface holding pond alkali water, impure natural alkali lake brines, and combinations of these. ### Claim 6 (depends on 1) The method of claim 1 wherein the alkali stream contacted with the gas stream in the first absorber section contains at least about 5 wt. % Na2CO3. ### Claim 7 (depends on 1) The method of claim 1 wherein the second absorber alkali stream is obtained from a source selected from the group consisting of aqueous alkali mining solutions recovered from solution mining of trona, nahcolite or other NaHCO.sub.3-containing mineral ores and crystallizer feed stream solutions, used to crystallize sodium carbonate monohydrate, sodium carbonate decahydrate, sodium sesquicarbonate or sodium bicarbonate. ### Claim 8 (depends on 1) The method of claim 1 wherein the alkali stream contacted with the gas stream in the second absorber section contains at least about 5 wt. % Na2CO3. ### Claim 9 (depends on 1) The method of claim 1 wherein the absorption of hydrogen sulfide effected in the first and second absorber sections is sufficient to reduce the hydrogen sulfide in the purified carbon dioxide gas stream to less than 10% of the concentration of hydrogen sulfide in the H2S-contaminated carbon dioxide gas stream introduced into the absorber. ### Claim 10 (depends on 1) The method of claim 1 wherein the purified carbon dioxide gas stream withdrawn from the gas absorption apparatus contains less than 100 ppmv H2S. ### Claim 11 A method for removing hydrogen sulfide from a gas stream in a soda ash production facility comprising introducing a H2S-contaminated gas stream in a soda ash production facility containing at least 20 vol % CO2 into a gas absorption apparatus for sequential contact of the gas stream with a first absorber alkali stream in a first absorber section and with a second absorber alkali stream in a second absorber section, wherein the first absorber alkali stream is an aqueous alkali waste stream containing at least 1 wt. % Na2CO3 and solubilized impurities from the soda ash production facility and is contacted with the H2S-contaminated gas stream in the first absorber section of the gas absorption apparatus in an amount sufficient to absorb a substantial amount of the H2S from the gas stream to produce a H2S-depleted gas stream and a first absorber effluent stream containing the absorbed H2S, and wherein the second absorber alkali stream is an aqueous process stream containing at least 1 wt. % Na2CO3 from the soda ash production facility and is contacted with the H2S-depleted gas stream in the second absorber section of the gas absorption apparatus in an amount sufficient to absorb a substantial amount of the residual H2S in the H2S-depleted gas stream from the gas stream to produce a purified gas stream and a second absorber effluent stream containing the absorbed residual H2S; withdrawing the first absorber effluent stream containing absorbed H2S and solubilized impurities from the first absorber section; withdrawing the second absorber effluent stream containing absorbed residual H2S from the second absorber section and thereafter utilizing the second absorber effluent stream in the soda ash production facility, for further processing for recovery of its solubilized Na2CO3 values; and withdrawing the purified gas stream from the gas absorption apparatus. ### Claim 12 (depends on 11) The method of claim 11 wherein the H2S-contaminated gas stream contains at least 30 vol % carbon dioxide. ### Claim 13 (depends on 11) The method of claim 11 wherein the first absorber section and the second absorber section are each a single stage absorption unit and a portion of the first absorber effluent stream is recycled to the first absorber section. ### Claim 14 (depends on 11) The method of claim 11 wherein the H2S-contaminated gas stream in the soda ash production facility contains at least about 0.1 vol. % H2S. ### Claim 15 (depends on 11) The method of claim 11 wherein the first absorber alkali stream is obtained from a source selected from group consisting of monohydrate crystallizer purge solution, decahydrate crystallizer purge solution, sesquicarbonate crystallizer purge solution, sodium bicarbonate crystallizer purge solution, trona mechanical mining waste water, surface holding pond alkali water, impure natural alkali lake brines, and combinations of these. ### Claim 16 (depends on 11) The method of claim 11 wherein the alkali stream contacted with the gas stream in the first absorber section contains at least about 5 wt. % Na2CO3. ### Claim 17 (depends on 11) The method of claim 11 wherein the second absorber alkali stream is obtained from a source selected from the group consisting of aqueous alkali mining solutions recovered from solution mining of trona, nahcolite or other NaHCO.sub.3-containing mineral ores and crystallizer feed stream solutions, used to crystallize sodium carbonate monohydrate, sodium carbonate decahydrate, sodium sesquicarbonate or sodium bicarbonate. ### Claim 18 (depends on 11) The method of claim 11 wherein the alkali stream contacted with the gas stream in the second absorber section contains at least about 5 wt. % Na2CO3. ### Claim 19 (depends on 11) The method of claim 11 wherein the absorption of hydrogen sulfide effected in the first and second absorber sections is sufficient to reduce the hydrogen sulfide in the purified gas stream to less than 10% of the concentration of hydrogen sulfide in the H2S-contaminated gas stream introduced into the absorber. ### Claim 20 (depends on 19) The method of claim 19 wherein the purified gas stream withdrawn from the gas absorption apparatus contains less than 100 ppmv H2S.