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EP-4178910-B1 - MEMBRANE PROCESS FOR H2 RECOVERY FROM SULFUR RECOVERY TAIL GAS STREAM OF SULFUR RECOVERY UNITS AND PROCESS FOR ENVIRONMENTALLY GREENER SALES GAS

EP4178910B1EP 4178910 B1EP4178910 B1EP 4178910B1EP-4178910-B1

Inventors

  • CHOI, SEUNG-HAK
  • DUVAL, Sébastien, André
  • VAIDYA, MILIND
  • HAMAD, FERAS
  • BAHAMDAN, Ahmad
  • AL-TALIB, AHMED

Dates

Publication Date
20260506
Application Date
20210902

Claims (15)

  1. A method of treating tail gas generated from a sulfur recovery operation to generate hydrogen gas or a greener natural gas, the method comprising the steps of: providing an acid gas stream (105) to a sulfur recovery unit (110), the acid gas stream comprising carbon dioxide and hydrogen sulfide; removing sulfur from the acid gas stream via the sulfur recovery unit to generate a sulfur recovery unit waste stream (112); heating the sulfur recovery unit waste stream with a tail gas treatment reheater (120) to create a heated sulfur recovery unit waste stream (125); reacting the heated sulfur recovery unit waste stream in a tail gas treatment reactor (130) operable to reduce sulfur compounds into hydrogen sulfide such that a tail gas stream (135) is generated, wherein the tail gas stream comprises hydrogen, carbon dioxide, nitrogen, and hydrogen sulfide; cooling the tail gas stream in a quench tower (140) to generate a quench tower overhead stream (148); treating the quench tower overhead stream in an overhead stream treatment process (150), the overhead stream treatment process comprising an H2 selective membrane unit (160) and an H2S removal unit (180), to generate an H2S rich recycle (188), an H2S lean stream, an H2 rich stream (178), and an H2 lean stream, such that the H2S rich recycle comprises a concentration of hydrogen sulfide higher than the concentration of hydrogen sulfide in the H2S lean stream and the H2 rich stream comprises a higher concentration of hydrogen than the concentration of hydrogen gas in the H2 lean stream, and further wherein the H2 rich stream is generated in the H2 selective membrane unit and the H2S rich recycle is generated from the H2S removal unit, and further wherein the H2 selective membrane unit comprises an H2 selective membrane (162); and recycling the H2S rich recycle to the sulfur recovery unit.
  2. The method of claim 1, wherein: (i) the H2 selective membrane (162) has a selectivity of hydrogen over carbon dioxide of at least 20; and/or (ii) the H2 selective membrane is operable at a temperature range of between 100 °C and 300 °C.
  3. The method of any of claims 1-2, wherein the H2 selective membrane (162) comprises a glassy polymer operable to function at an operating temperature of 100 °C to 300 °C without degradation.
  4. The method of any of claims 1-3, wherein: (i) the H2 selective membrane (162) comprises a PBI polymer; or (ii) the H2 selective membrane comprises a PBI type polymer, wherein the PBI type polymer comprises a compound selected from the group consisting of: a hexaluoroisopropylidene functional group, a PBI polymer derived from tetra amino diphenyl sulfone, a PBI polymer derived from tetra amino diphenyl sulfone polymers, a PBI polymer derived from tetra amino diphenyl sulfone copolymers, an N-substitution modified PBI, a PBI and melamine-co-formaldehyde thermosets blend, a Pd/PBI-HFA composite, and combinations of the same.
  5. The method of any of claims 1-4, wherein the H2 selective membrane (162) further comprises Pd.
  6. The method of any of claims 1-5, wherein: (i) the H2 selective membrane (162) further comprises hydrofluoroalkane (HFA); and/or (ii) the H2 selective membrane comprises an aromatic polyamide layer formed on a porous support layer, and a coating comprising a glassy polymer formed on the aromatic polyamide layer, wherein the glassy polymer has a glass transition temperature greater than 50 °C.
  7. The method of any of claims 3-6, wherein the glassy polymer comprises a monomer, copolymer, block copolymer, terpolymer, block terpolymer, or any molecular structure generated by a combination of compounds selected from the group of compounds comprising: polyimide, polybenzimidazole, polyphenylsulfone, polyamide, polysulfone, polyphenyl ether, cellulose nitrate, cellulose diacetate, cellulose triacetate, poly(vinyl alcohol), poly(phenylene sulfide), poly(vinyl chloride), polystyrene, poly(methyl methacrylate), polyacrylonitrile, polytetrafluoroethylene, polyetheretherketone, polycarbonate, polyvinyltrimethylsilane, polytrimethylsilylpropyne, poly(ether imide), poly(ether sulfone), polyoxadiazole, poly(phenylene oxide), and combinations thereof.
  8. The method of any of claims 1-7, wherein the step of treating the quench tower overhead stream (148) in the H2 selective membrane unit (160) and the H2S removal unit (180) further comprises the steps of: introducing the quench tower overhead stream to the H2 selective membrane unit before treatment in the H2S removal unit, such that the hydrogen gas is separated from the quench tower overhead stream before hydrogen sulfide is removed; generating the H2 lean stream from the H2 selective membrane unit; and then introducing the H2 lean stream to the H2S removal unit, such that the H2S removal unit produces the H2S rich stream (188) and the H2S lean stream.
  9. The method of any of claims 1-8, wherein: (i) the quench tower overhead stream (148) comprises at least 2 mol% hydrogen sulfide and/or (ii) the method further comprises the steps of: compressing the H2 rich stream (178) in a plant compressor (290) to generate a plant recycle (292); and recycling the plant recycle to a plant inlet for acid gas removal, such that processed natural gas from the plant inlet has an increased hydrogen content.
  10. The method of any of claims 1-9, wherein the H2 selective membrane unit (160) comprises a membrane feed compressor (454), a first H2 selective membrane (462), a permeate compressor (470), and a second H2 selective membrane (474), and further comprising the steps of: compressing the quench tower overhead stream (148) in the membrane feed compressor to generate a compressed membrane feed stream (458); introducing the compressed membrane feed stream to the first H2 selective membrane, the first H2 selective membrane having a first H2 selective membrane permeate side (463) and a first H2 selective membrane retentate side (461); allowing hydrogen to permeate the first H2 selective membrane to generate an H2 rich permeate (468); removing the H2 rich permeate from the first H2 selective membrane permeate side; removing the H2 lean stream from the first H2 selective membrane retentate side; compressing the H2 rich permeate in the permeate compressor to generate a second membrane feed stream (472); introducing the second membrane feed stream to the second H2 selective membrane, the second H2 selective membrane having a second H2 selective membrane retentate side (473) and a second H2 selective membrane permeate side (475); allowing hydrogen to permeate the second H2 selective membrane to generate the H2 rich stream (478) from the second H2 selective membrane permeate side; removing a membrane recycle stream (482) from the second H2 selective membrane retentate side; and recycling the membrane recycle stream to the first H2 selective membrane retentate side.
  11. The method of any of claims 1-10, wherein: (i) the step of treating the quench tower overhead stream (148) in the H2 selective membrane unit (160) and the H2S removal unit (180) further comprises the steps of: introducing the quench tower overhead stream to the H2S removal unit before treatment in the H2 selective membrane unit, such that hydrogen sulfide is removed from the quench tower overhead stream before hydrogen is removed from the quench tower overhead stream; generating the H2S lean stream from the H2S removal unit; and then introducing the H2S lean stream to the H2 selective membrane unit; and/or (ii) the H2S lean stream comprises less than 150 ppm hydrogen sulfide.
  12. The method of any of claims 1-11, wherein: (i) the method further comprises the step of incinerating the H2 lean stream (364) in an incinerator (394); and/or (ii) the H2 rich stream (378) is further processed to remove water, carbon dioxide, and nitrogen to produce a high quality hydrogen stream.
  13. The method of any of claims 1-12, wherein: (i) the H2 rich stream (378) is added to plant fuel gas; and/or (ii) the H2 selective membrane unit (360) comprises a membrane feed compressor (454), a first H2 selective membrane (462), a permeate compressor (470), and a second H2 selective membrane (474), and further comprising the steps of: compressing the H2S lean stream in the membrane feed compressor to generate a compressed membrane feed stream (458); introducing the compressed membrane feed stream to the first H2 selective membrane, the first H2 selective membrane comprising a first H2 selective membrane retentate side (463) and a first H2 selective membrane permeate side (461); allowing hydrogen to permeate the first H2 selective membrane to generate an H2 rich permeate (468); removing the H2 rich permeate from the first H2 selective membrane permeate side; removing the H2 lean stream from the first H2 selective membrane retentate side; compressing the H2 rich permeate in the permeate compressor to generate a second membrane feed stream (472); introducing the second membrane feed stream to the second H2 selective membrane, the second H2 selective membrane comprising a second H2 selective membrane retentate side (473) and a second H2 selective membrane permeate side (475); allowing hydrogen to permeate the second H2 selective membrane to generate the H2 rich stream from the second H2 selective membrane permeate side; removing a membrane recycle stream (482) from the second H2 selective membrane retentate side; and recycling the membrane recycle stream to the first H2 selective membrane retentate side.
  14. A system (100) for treating an acid gas contaminated stream (105) to control emissions, generate hydrogen gas, or generate a greener natural gas, the system comprising: a sulfur recovery unit (110), operable to convert sulfur compounds in an acid gas stream (105) to elemental sulfur and further to generate a sulfur recovery unit waste stream (112); a tail gas treatment reheater (120) fluidically connected to the sulfur recovery unit, operable to heat the sulfur recovery unit waste stream to create a heated sulfur recovery unit waste stream (125); a tail gas treatment reactor (130) fluidically connected to the tail gas treatment reheater, operable to reduce sulfur compounds in the heated sulfur recovery unit waste stream to hydrogen sulfide, to generate a tail gas stream (135); a quench tower (140) fluidically connected to the tail gas treatment reactor, operable to reduce the temperature of the tail gas stream, to generate a sour water stream (144) and a quench tower overhead stream (148); an H2 selective membrane unit (160) fluidically connected to the quench tower, comprising an H2 selective membrane (162), operable to selectively remove hydrogen from the quench tower overhead stream through the H2 selective membrane to generate an H2 rich stream (178) and an H2 lean stream; and an H2S removal unit (180) fluidically connected to the H2 selective membrane unit, operable to absorb hydrogen sulfide from the H2 lean stream with a solvent and configured to regenerate the solvent, to generate an H2S lean stream and an H2S rich recycle (188); optionally wherein the H2 selective membrane unit further comprises: a membrane feed compressor (454), operable to compress the heated sulfur recovery unit waste stream, to generate a compressed membrane feed stream (458); a first H2 selective membrane (462), operable to selectively remove hydrogen from the compressed membrane feed stream through the first H2 selective membrane to generate an H2 rich permeate (468) and the H2 lean stream; a permeate compressor (470), operable to compress the H2 rich permeate to generate a second membrane feed stream (472); and a second H2 selective membrane (474), operable to selectively remove hydrogen from the second membrane feed stream through the second H2 selective membrane, to generate the H2 rich stream and a membrane recycle stream (482).
  15. A system (100) for treating an acid gas contaminated stream (105) to control emissions, generate hydrogen gas, or generate a greener natural gas, the system comprising: a sulfur recovery unit (110), operable to convert sulfur compounds in an acid gas stream (105) to elemental sulfur and further to generate a sulfur recovery unit waste stream (112); a tail gas treatment reheater (120) fluidically connected to the sulfur recovery unit, operable to heat the sulfur recovery unit waste stream to generate a heated sulfur recovery unit waste stream (125); a tail gas treatment reactor (130) fluidically connected to the tail gas treatment reheater, operable to reduce sulfur compounds in the heated sulfur recovery unit waste stream to hydrogen sulfide, to generate a tail gas stream (135); a quench tower (140) fluidically connected to the tail gas treatment reactor, operable to cool the tail gas stream, to generate a sour water stream (144) and a quench tower overhead stream (148); an H2S removal unit (180) fluidically connected to the quench tower, operable to absorb hydrogen sulfide from the quench tower overhead stream with a solvent and configured to regenerate the solvent, to generate an H2S lean stream and an H2S rich recycle (188); and an H2 selective membrane unit (160) fluidically connected to the H2S removal unit, comprising an H2 selective membrane (162), operable to selectively remove hydrogen from the H2S lean stream through the H2 selective membrane to generate an H2 rich stream (178) and an H2 lean stream; optionally wherein the H2 selective membrane unit further comprises: a membrane feed compressor (454), operable to compress the H2S lean stream, to generate a compressed membrane feed stream (458); a first H2 selective membrane (462), operable to selectively remove hydrogen from the compressed membrane feed stream through the first H2 selective membrane to generate an H2 rich permeate (468) and the H2 lean stream; a permeate compressor (470), operable to compress the H2 rich permeate to generate a second membrane feed stream (472); and a second H2 selective membrane (474), operable to selectively remove hydrogen from the second membrane feed stream through the second H2 selective membrane, to generate the H2 rich stream and a membrane recycle stream (482).

Description

FIELD This disclosure relates to methods and systems for treating a sulfur recovery tail gas stream. More specifically, this disclosure relates to removing H2S (hydrogen sulfide) and H2 (hydrogen) from the tail gas stream from a sulfur recovery unit. BACKGROUND As part of natural gas processing and hydro-treatment of oil fractions, a large amount of H2S is produced. The conversion of H2S into elemental sulfur (S) is performed in a sulfur recovery unit (SRU). The most common process used for this conversion is known as the modified Claus treatment process, or alternately the Claus unit or modified Claus unit. The modified Claus treatment process is a combination of thermal and catalytic processes that are used for converting gaseous H2S into S. Claus unit feed gases have a wide range of compositions. Feed gases originate from absorption processes using various solvents (amine, physical or hybrid solvents) to extract H2S from the by-product gases of petroleum refining, natural gas processing, and other industries using sour water stripper units. The first process of a Claus unit is a thermal process in a reaction furnace. The feed gas to the Claus unit is burned in the reaction furnace using sufficient combustion air, or oxygen enriched air, to burn a stoichiometric one-third of the contained H2S. The H2S from the feed gas is thermally converted into S, along with sulfur dioxide (SO2). The reaction furnace operation is designed to maximize sulfur recovery in consideration of the feed composition, by adjusting air/oxygen feed, reaction temperature, pressure, additional fuel, and residence time. In addition, the reaction furnace destroys contaminants, such as hydrocarbons, that are present in the feed gas stream. Such contaminants pose problems for the catalytic reactors through the development of carbon-sulfur compounds that lead to plugging or deactivation of the catalyst beds. The heated reaction product gas from the reaction furnace containing sulfur vapor is used to produce high pressure steam in a waste heat boiler, which also results in cooling the gas. The product gas is then further cooled and condensed in a heat exchanger. The condensed liquid S is separated from the remaining unreacted gas in the outlet end of the condenser and sent to a sulfur pit or other collection area. The separated gas then enters the catalytic process of the Claus unit. The catalytic process contains between two and three catalytic reactors. Following the sulfur condenser, the separated gas is reheated and enters the first catalytic reactor. In the first catalytic reaction some of the H2S in the feed gas is converted into S through a reaction with the SO2. The outlet product gas from the first catalytic reactor is cooled in a second condenser. Again, the condensed liquid S is separated from the remaining unreacted gas in the outlet end of the second condenser and sent to sulfur storage. The separated gas from the second condenser is sent to another re-heater and the sequence of gas reheat, catalytic reaction, condensation and separation of liquid S from unreacted gas is repeated for the second and third catalytic reactors. For a well-designed and well-operated Claus sulfur recovery plant having three catalytic reactors, an overall sulfur recovery of 96-98% is achievable depending on the feed gas composition. To achieve higher recovery, a tail gas treatment unit must be added to further process the exhaust gas upstream of or as an alternative to an incinerator. Currently available tail gas treatment units are effective at achieving up to 99.9% or greater recovery, but add significant capital cost to the Claus treatment unit, often on the same order of magnitude as the Claus unit itself. During the thermal step in a sulfur recovery unit, a large fraction of H2 is generated during the thermal stage of sulfur recovery due to H2S splitting into S and H2. A significant portion of the H2 remains in the tail gas downstream catalytic converter and hydrogenation stages. Generally, 1.0 mol% to 3.0 mol% H2 remains in the tail gas stream. H2 is a valuable gas, but separating H2 from the tail gas is difficult and expensive. Conventional membranes currently used in industrial applications can perform this separation, but the membranes are expensive and difficult to operate. Conventional membranes also suffer from low efficiency, since they struggle to efficiently and effectively separate H2 from streams containing H2S, carbon dioxide (CO2), or nitrogen (N2). Additionally, conventional membranes used for H2 separation are unable to withstand the operating temperatures of a tail gas stream, requiring substantial cooling resulting in additional costs and equipment. Even if the conventional membranes can handle higher temperature, they often degrade over time at these temperatures, leading to a shortened membrane lifespan. These drawbacks make conventional membranes cost prohibitive. There are many different types of conventional membranes, incl