Bulk CO.sub.2 recovery process

• US 5,061,465 A
• Filed: 08/24/1989
• Issued: 10/29/1991
• Est. Priority Date: 08/24/1989
• Status: Expired due to Fees

• Current Assignee: Lawrence C. Griffin
• Original Assignee: Phillips Petroleum Company (ConocoPhillips)
• Inventors: Carter, Cecil O.
• Primary Examiner(s): Straub, Gary P.
• Assistant Examiner(s): Kalinchak, Stephen G.
• Application Number:
  US07/397,947
• Time in Patent Office: 796 Days
• Field of Search: 423/228, 423/229
• US Class Current: 423/229
• CPC Class Codes: B01D 53/1418 Recovery of products
• CPC Class Codes: B01D 53/1425 Regeneration of liquid absorbents
• CPC Class Codes: B01D 53/1456 Removing acid components
• CPC Class Codes: B01D 53/1493 Selection of liquid materials for use as absorbents

Abstract

A high temperature absorption process for bulk recovery of CO₂ comprises contacting a gaseous mixture containing CO₂, H₂ S, and natural gas with C₃ and heavier components and having a high and variable CO₂ loading, with an amine absorbent solution at a temperature above 220° F. The amine absorbent solution is continuously regenerated in a multiple section flashing so as to reduce the energy requirements for regeneration and thereby making the process more suitable for bulk recovery of CO₂ from gas streams associated with enhanced oil recovery projects employing CO₂ for miscible flood of oil reservoirs.

Claims

1. A process for removing an acid gas component from a gaseous mixture containing said acid gas and hydrocarbons comprising methane, ethane and heavier hydrocarbons, said process comprising the steps of:

(a) contacting a feed gas stream comprising said gaseous mixture with an absorbent consisting essentially of an aqueous alkanolamine solution in a contacting zone wherein said acid gas component is absorbed by said absorbent at a temperature in the range of from about 240°

F. to about 260°

F.;

(b) withdrawing a liquid stream enriched in said acid gas component from said contacting zone; and

(c) withdrawing from said contacting zone a gaseous hydrocarbon stream having a reduced concentration of said acid gas component compared to the concentration of said acid gas component in said feed gas stream.

2. A process in accordance with claim 1 wherein said liquid stream withdrawn in step (b) is regenerated at essentially the same temperature as the absorption in step (a) and recycled to said contacting zone.

3. A process in accordance with claim 1 wherein said acid gas component is carbon dioxide and said aqueous alkanolamine solution consists essentially of an aqueous methyldiethanolamine solution.

4. A process in accordance with claim 3 wherein said methlydiethanolamine solution contains from about 20 to about 60 weight percent of methyldiethanolamine.

5. A process in accordance with claim 4 wherein conditions in said contacting zone include a pressure within the range of from about 100 psig to about 400 psig.

6. A process in accordance with claim 5 wherein the molar ratio of feed gas to alkanolamine solution within said contacting zone is in the range of from about 2.3 to about 5.1.

7. A process in accordance with claim 3 wherein the carbon dioxide content of said feed gas is in the range of from about 19 mole percent to about 85 mole percent.

8. A process in accordance with claim 1 wherein said aqueous alkanolamine solution is selected from the group of aqueous solution consisting of MEA, DEA, MDA, DGA, TEA, and combinations of any two or more thereof.

9. A process for removing carbon dioxide from a gaseous mixture containing carbon dioxide and hydrocarbons comprising methane, ethane and which includes C₃ and heavier hydrocarbons, said method comprising the steps of:

(a) contacting a feed gas stream comprising said gaseous mixture with an absorbent consisting essentially of an aqueous methyldiethanolamine (MDEA) solution in a contacting zone and at a contacting temperature wherein said carbon dioxide is absorbed in said absorbent solution at a temperature in the range of from about 240°

F. to about 260°

F.;

(b) withdrawing a liquid MDEA stream enriched in carbon dioxide from said contacting zone;

(c) passing the thus withdrawn liquid MDEA stream through a first pressure reducing vessel at a temperature substantially matching the contacting temperature in said contacting zone to effect a first flashing separation of absorbed CO₂ from said liquid MDEA stream;

(d) withdrawing a liquid MDEA stream enriched in carbon dioxide from said first pressure reducing zone and passing the thus withdrawn liquid MDEA stream to a second pressure reducing zone;

(e) effecting a second flashing separation of absorbed CO₂ from said liquid MDEA stream in said second pressure reducing vessel;

(f) withdrawing a liquid MDEA stream enriched in carbon dioxide from said second pressure reducing vessel and passing the thus withdrawn liquid stream to a third pressure reducing vessel;

(g) effecting a third flashing separation of absorbed CO₂ from said liquid MDEA stream at a temperature substantially matching the contacting temperature in said contacting zone in said third pressure reducing vessel so as to produce regenerated liquid MDEA and gaseous carbon dioxide;

(i) withdrawing a regenerated liquid MDEA stream from said third pressure reducing vessel and passing the thus withdrawn regenerated liquid MDEA stream to said contacting zone to effect said contacting step in paragraph (a); and

(j) withdrawing from said contacting zone a gaseous hydrocarbon stream having a reduced concentration of CO₂ compared to the concentration of CO₂ in said feed gas stream.

10. A process in accordance with claim 9 additionally comprising the step of:

passing gaseous CO₂ from said first, second, and third pressure reducing vessels to a compressor.

11. A process in accordance with claim 9 wherein said liquid methyldiethanolamine (MDEA) absorbent solution consists essentially of from about 20 to about 60 weight percent solution of methyldiethanolamine.

12. A process in accordance with claim 9 wherein conditions in said contacting zone include a pressure within the range of from about 100 to about 400 psig.

13. A process in accordance with claim 12 wherein the molar ratio of feed gas to absorbent solution within said contacting zone is in the range of from about 2.3 to about 5.1.

14. A process in accordance with claim 13 wherein the CO₂ content of said feed gas is in the range of from about 19 mole percent to about 85 mole percent.