Configurations and methods for carbon dioxide and hydrogen production from gasification streams

• US 8,480,982 B2
• Filed: 02/22/2008
• Issued: 07/09/2013
• Est. Priority Date: 02/22/2007
• Status: Active Grant

• Current Assignee: Fluor Technologies Corporation (Fluor Corporation)
• Original Assignee: Fluor Technologies Corporation (Fluor Corporation)
• Inventors: Mak, John, Nielsen, Richard
• Primary Examiner(s): Warden, Jill
• Assistant Examiner(s): NGUYEN, HUY TRAM
• Application Number:
  US12/526,617
• Publication Number:
  US 20100111784A1
• Time in Patent Office: 1,964 Days
• Field of Search: 422/242.1, 422/630, 423/242.1
• US Class Current: 422/630
• CPC Class Codes: B01D 2256/16 Hydrogen
• CPC Class Codes: B01D 2257/304 Hydrogen sulfide
• CPC Class Codes: B01D 2257/504 Carbon dioxide
• CPC Class Codes: B01D 53/1406 Multiple stage absorption
• CPC Class Codes: B01D 53/1462 Removing mixtures of hydrogen sulfide and carbon dioxide
• CPC Class Codes: B01D 53/1475 Removing carbon dioxide
• CPC Class Codes: C01B 17/04 from gaseous sulfur compounds including gaseous sulfides
• CPC Class Codes: C01B 17/0456 the hydrogen sulfide-containing gas being a Claus process tail gas
• CPC Class Codes: C01B 17/164 Preparation by reduction of oxidic sulfur compounds
• CPC Class Codes: C01B 2203/0415 Purification by absorption in liquids
• CPC Class Codes: C01B 2203/0475 the impurity being carbon dioxide
• CPC Class Codes: C01B 2203/0485 the impurity being a sulfur compound
• CPC Class Codes: C01B 2203/86 Carbon dioxide sequestration
• CPC Class Codes: C01B 3/52 by contacting with liquids; Regeneration of used liquids C01B3/508 takes precedence
• CPC Class Codes: C01B 32/50 Carbon dioxide
• CPC Class Codes: Y02C 20/40 of CO2
• CPC Class Codes: Y02P 20/151 Reduction of greenhouse gas [GHG] emissions, e.g. CO2
• CPC Class Codes: Y02P 30/00 Technologies relating to oil refining and petrochemical industry

Abstract

A syngas treatment plant is configured to remove sulfurous compounds and carbon dioxide from shifted or un-shifted syngas in a configuration having a decarbonization section and a desulfurization section. Most preferably, the solvent in the decarbonization section is regenerated and cooled by flashing, while the solvent is regenerated in the desulfurization section via stripping using external heat, and it is still further preferred that carbonylsulfide is removed in the desulfurization section via hydrolysis, and that the so produced hydrogen sulfide is removed in a downstream absorber.

Claims

1. A plant comprising:

a gasification unit configured to produce a syngas;

a desulfurization section fluidly coupled to the gasification unit to receive the syngas, wherein the desulfurization section includes a primary absorber, a COS hydrolysis unit, a secondary absorber, and a regenerator that is configured to produce an H2S acid gas stream;

wherein the primary absorber is upstream of the COS hydrolysis unit, and wherein the COS hydrolysis unit is upstream of the secondary absorber;

wherein the primary and secondary absorbers are configured to absorb H2S from the syngas in a first solvent to thereby produce a desulfurized syngas;

a decarbonization section fluidly coupled to the desulfurization section to receive the desulfurized syngas and comprising a CO2 absorber that is configured to absorb CO2 from the desulfurized syngas and to produce a H2 product stream using a second solvent, wherein first and second solvents are circulated in separate solvent circuits;

a sulfur plant with a tail gas unit that is fluidly coupled to the regenerator and that is configured to produce sulfur from the H2S acid gas stream and a tail gas;

a third absorber that is fluidly coupled to the tail gas unit and that is configured to form a semi-lean solvent using lean solvent from the regenerator and to form a CO2 overhead; and

wherein the third absorber is fluidly coupled to the primary absorber such that the semi-lean solvent is provided to the primary absorber.

2. The plant of claim 1 wherein primary and secondary absorbers are configured to allow feeding of a bottom fluid from the secondary absorber as a semi-lean solvent to an intermediate position of the primary absorber.

3. The plant of claim 1 further comprising a H2S scavenger unit fluidly coupled between the desulfurization section and the decarbonization section.

4. The plant of claim 1 wherein the decarbonization section is configured to allow flashing of the second solvent to a degree sufficient to provide all cooling requirement for the second solvent prior to entry into the CO2 absorber.

5. The plant of claim 1 wherein the decarbonization section comprises a hydraulic turbine that is configured to provide power from pressure reduction of the second solvent to a solvent pump of the second solvent.

6. The plant of claim 1 wherein the decarbonization section further comprises a compressor that is configured to allow compression of flashed CO2 to a pressure suitable for at least one of liquefaction and sequestration.

7. The plant of claim 1 wherein the gasification unit is configured to produce an un-shifted syngas, and wherein the plant further comprises a shift reactor fluidly coupled between the primary and secondary absorber and configured to receive partially desulfurized syngas from the primary absorber.

8. The plant of claim 7 wherein the first solvent is a chemical solvent and the second solvent is a physical solvent.

9. The plant of claim 7 further comprising an expansion device and flash vessel coupled to the primary absorber and configured to allow separation of CO2 from rich solvent of the primary absorber.

10. The plant of claim 9 wherein the flash vessel is configured to allow feeding of a flashed vapor to at least one of the primary absorber and a combustor.

11. The plant of claim 7 further comprising a tail gas absorber, and a sulfur plant and tail gas unit fluidly coupled to the desulfurization section and configured to allow feeding of tail gas from the tail gas unit to the tail gas absorber.

12. The plant of claim 11 wherein the tail gas absorber is configured to receive lean first solvent from a stripper, and wherein the tail gas absorber is further configured to provide a semi-lean solvent to the primary absorber.

13. A syngas treatment plant comprising:

a gasification unit configured to produce a shifted syngas;

a desulfurization section fluidly coupled to the gasification unit to receive the shifted syngas, wherein the desulfurization section includes a primary absorber and receives the shifted syngas, a COS hydrolysis unit, a secondary absorber, and a regenerator that is configured to produce an H2S acid gas stream;

wherein the primary absorber is upstream of the COS hydrolysis unit, and wherein the COS hydrolysis unit is upstream of and directly coupled to the secondary absorber;

wherein the primary and secondary absorbers are configured to absorb H2S from the syngas in first and second respective portions of a CO2-loaded solvent to thereby produce a desulfurized syngas;

a decarbonization section fluidly coupled to the desulfurization section to receive the desulfurized syngas and comprising a CO2 absorber that is configured to absorb CO2 from the desulfurized syngas and to produce the CO2-loaded solvent and a H2 product stream using the solvent;

a cooler that is configured to cool the CO2-loaded solvent;

wherein the solvent is circulated between the desulfurization section and the decarbonization section; and

a sulfur plant with a tail gas unit that is fluidly coupled to the regenerator and that is configured to produce sulfur from the H2S acid gas stream and a tail gas;

a third absorber that is fluidly coupled to the tail gas unit and that is configured to form a semi-lean solvent using lean solvent from the regenerator and to form a CO2 overhead; and

wherein the third absorber is fluidly coupled to the primary absorber such that the semi-lean solvent is provided to the primary absorber.

14. A syngas treatment plant comprising:

a gasification unit configured to produce an un-shifted syngas;

a desulfurization section fluidly coupled to the gasification unit to receive the syngas, wherein the desulfurization section includes a primary absorber, a shift reactor, a COS hydrolysis unit, a secondary absorber, and a regenerator that is configured to produce an H2S acid gas stream;

wherein the primary absorber is upstream of the COS hydrolysis unit, and wherein the COS hydrolysis unit is upstream of the secondary absorber;

wherein the shift reactor is fluidly coupled between the primary and secondary absorber and configured to receive partially desulfurized syngas from the primary absorber;

wherein the primary and secondary absorbers are configured to absorb H2S from the syngas in a first solvent to thereby produce a desulfurized syngas;

a decarbonization section fluidly coupled to the desulfurization section to receive the desulfurized syngas and comprising a CO2 absorber that is configured to absorb CO2 from the desulfurized syngas and to produce a H2 product stream using a second solvent, wherein first and second solvents are circulated in separate solvent circuits; and

a sulfur plant with a tail gas unit that is fluidly coupled to the regenerator and that is configured to produce sulfur from the H2S acid gas stream and a tail gas;

a third absorber that is fluidly coupled to the tail gas unit and that is configured to form a semi-lean solvent using lean solvent from the regenerator and to form a CO2 overhead; and

wherein the third absorber is fluidly coupled to the primary absorber such that the semi-lean solvent is provided to the primary absorber.