Configurations and methods of flexible CO2 removal

• US 10,150,926 B2
• Filed: 02/21/2018
• Issued: 12/11/2018
• Est. Priority Date: 12/12/2013
• Status: Active Grant

• Current Assignee: Fluor Technologies Corporation (Fluor Corporation)
• Original Assignee: Fluor Technologies Corporation (Fluor Corporation)
• Inventors: Mak, John
• Primary Examiner(s): Holecek, Cabrena
• Application Number:
  US15/901,585
• Publication Number:
  US 20180179460A1
• Time in Patent Office: 293 Days
• CPC Class Codes: B01D 2252/20 Organic absorbents
• CPC Class Codes: B01D 2252/2025 Ethers or esters of alkylene glycols, e.g. ethylene or propylene carbonate
• CPC Class Codes: B01D 2252/2026 Polyethylene glycol, ethers or esters thereof, e.g. Selexol
• CPC Class Codes: B01D 2252/20468 containing a pyrrolidone-ring
• CPC Class Codes: B01D 2256/24 Hydrocarbons
• CPC Class Codes: B01D 2257/304 Hydrogen sulfide
• CPC Class Codes: B01D 53/1406 Multiple stage absorption
• CPC Class Codes: B01D 53/1425 Regeneration of liquid absorbents
• CPC Class Codes: B01D 53/1431 Pretreatment by other processes
• CPC Class Codes: B01D 53/1475 Removing carbon dioxide
• CPC Class Codes: B01D 53/1493 Selection of liquid materials for use as absorbents
• CPC Class Codes: C10L 2290/06 Heat exchange, direct or indirect
• CPC Class Codes: C10L 2290/08 Drying or removing water
• CPC Class Codes: C10L 2290/48 Expanders, e.g. throttles or flash tanks
• CPC Class Codes: C10L 2290/541 Absorption of impurities during preparation or upgrading of a fuel
• CPC Class Codes: C10L 2290/545 Washing, scrubbing, stripping, scavenging for separating fractions, components or impurities during preparation or upgrading of a fuel
• CPC Class Codes: C10L 3/103 Sulfur containing contaminants
• CPC Class Codes: C10L 3/104 Carbon dioxide
• CPC Class Codes: Y02C 20/40 of CO2

Abstract

A plant comprises a feed gas source, H2S removal unit, first absorber and a second, pressure reduction stages, first and second heat exchangers, stripping unit, and a conduit. The H2S removal unit selectively removes H2S from a feed gas from the feed gas source to produce an H2S depleted feed gas. The first absorber and the second absorber remove CO2 from the H2S depleted feed gas using a semi-lean and an ultralean solvent to produce a product gas and a rich solvent. The plurality of pressure reduction stages generates a cooled flashed solvent. The first heat exchanger and the second heat exchanger use the cooled flashed solvent to cool the H2S depleted feed gas and the semi-lean solvent. The stripping unit strips the flashed solvent with dried air to produce the ultralean solvent, and the conduit combines a portion of the ultralean solvent with the H2S depleted feed gas.

Claims

1. A plant comprising:

a feed gas source that is configured to provide a hydrocarbonaceous feed gas comprising H2S and CO2 at a pressure of at least 300 psig;

a H2S removal unit configured to selectively remove H2S from the hydrocarbonaceous feed gas to produce a H2S depleted feed gas;

a first absorber and a second absorber fluidly coupled in series and configured to remove CO2 from the H2S depleted feed gas using a semi-lean and an ultralean solvent, respectively, thereby producing a product gas and a rich solvent;

a plurality of pressure reduction stages configured to receive and reduce pressure of the rich solvent to thereby generate work, a CO2 stream, and a cooled flashed solvent;

a first heat exchanger and a second heat exchanger configured to use the cooled flashed solvent to cool the H2S depleted feed gas and the semi-lean solvent;

a stripping unit configured to strip the flashed solvent with dried air to thereby produce the ultralean solvent; and

a conduit configured to combine a portion of the ultralean solvent with the H2S depleted feed gas.

2. The plant of claim 1, wherein the solvent is a physical solvent selected from the group consisting of propylene carbonate, tributyl phosphate, normal methyl pyrrolidone, a dimethyl ether of polyethylene glycol, and a polyethylene glycol dialkyl ether.

3. The plant of claim 1, wherein the H2S removal unit is configured to remove H2S using a H2S selective solvent or a solid phase adsorbent.

4. The plant of claim 1, wherein the hydrocarbonaceous feed gas comprises at least 20 mol % CO2.

5. The plant of claim 1, wherein the dried air has a water dew point of equal or less than −

40°

F.

6. The plant of claim 1, wherein the product gas has a CO2 content of 500 ppmv to 0.5 mol % CO2, and the CO2 stream is a dry H2S-free gas suitable for CO2 sequestration.

7. The plant of claim 1, wherein the plurality of pressure reduction stages is configured such that at least 85% of the CO2 content in the rich solvent is removed from the solvent at atmospheric pressure.

8. The plant of claim 1, wherein the first absorber and the second absorber are formed in a single vessel having a first absorber section and a second absorber section.

9. A plant comprising:

a feed gas source that is configured to provide a hydrocarbonaceous feed gas comprising H2S and CO2;

a H2S removal unit configured to receive the hydrocarbonaceous feed gas and selectively remove H2S from the hydrocarbonaceous feed gas to produce a H2S depleted feed gas;

a first absorber and a second absorber fluidly coupled in series and configured to remove CO2 from the H2S depleted feed gas using a semi-lean and an ultralean solvent, respectively, thereby producing a product gas and a rich solvent;

a plurality of pressure reduction stages configured to receive and reduce a pressure of the rich solvent to thereby generate work, a CO2 stream, and a cooled flashed solvent;

a first heat exchanger configured to use the cooled flashed solvent to cool the H2S depleted feed gas;

a second heat exchanger configured to use the cooled flashed solvent to cool the semi-lean solvent;

a stripping unit configured to strip the flashed solvent with dried air to thereby produce the ultralean solvent; and

a conduit configured to combine a portion of the ultralean solvent with the H2S depleted feed gas between the H2S removal unit and the first heat exchanger.

10. The plant of claim 9, wherein the solvent is a physical solvent selected from the group consisting of propylene carbonate, tributyl phosphate, normal methyl pyrrolidone, a dimethyl ether of polyethylene glycol, and a polyethylene glycol dialkyl ether.

11. The plant of claim 9, wherein the H2S removal unit is configured to remove H2S using a H2S selective solvent or a solid phase adsorbent.

12. The plant of claim 9, further comprising a hydraulic turbine configured to receive the rich solvent and generate the work.

13. The plant of claim 9, wherein the dried air has a water dew point of equal or less than −

40°

F.

14. The plant of claim 9, wherein the product gas has a CO2 content of 500 ppmv to 0.5 mol % CO2.

15. The plant of claim 9, wherein the plurality of pressure reduction stages is configured such that at least 85% of the CO2 content in the rich solvent is removed from the rich solvent at atmospheric pressure.

16. The plant of claim 9, wherein the first absorber and the second absorber are formed in a single vessel having a first absorber section and a second absorber section.

17. The plant of claim 9, wherein the second absorber is configured to receive at least a portion of the ultra-lean solvent and produce the semi-lean solvent due to absorption of CO2 in the ultra-lean solvent.

18. The plant of claim 9, wherein the first heat exchanger is configured to cool the H2S depleted feed gas upstream of the first absorber using the cooled flashed solvent, and wherein the second heat exchanger is configured to cool the semi-lean solvent from the second absorber between the second absorber and the first absorber.

19. The plant of claim 9, further comprising:

a third heat exchanger configured to cool the H2S depleted feed gas upstream of the first absorber using the product gas.

20. The plant of claim 9, further comprising:

a pressure reduction valve configured to reduce the pressure of the cooled flashed solvent and cool the cooled flashed solvent.