CO.sub.2 Removal from high CO.sub.2 content hydrocarbon containing streams

• US 4,466,946 A
• Filed: 03/12/1982
• Issued: 08/21/1984
• Est. Priority Date: 03/12/1982
• Status: Expired due to Term

• Current Assignee: Amoco Corporation (BP PLC)
• Original Assignee: Standard Oil Company (BP PLC)
• Inventors: Turek, Edward A., George, Boyd A., Goddin, Clifton S. Jr.
• Primary Examiner(s): Thomas, Earl C.
• Application Number:
  US06/357,362
• Time in Patent Office: 893 Days
• Field of Search: 423/220, 423/226, 423/228, 423/229, 423/245, 208/189, 208/289, 208/290, 208/330, 208/331, 208/340, 208/342, 208/344, 55/16, 55/23, 62/24, 62/17
• US Class Current: 423/228
• CPC Class Codes: B01D 53/1412 Controlling the absorption process
• CPC Class Codes: B01D 53/1443 Pretreatment by diffusion
• CPC Class Codes: B01D 53/1462 Removing mixtures of hydrogen sulfide and carbon dioxide
• CPC Class Codes: Y02C 20/40 of CO2
• CPC Class Codes: Y10S 62/929 From natural gas

Abstract

Carbon dioxide is removed from CO₂ and hydrocarbon containing gaseous streams. In the instance where the hydrocarbons and CO₂ are such that hydrocarbons would condense out during CO₂ removal, the gas stream is treated in one or more stages to accomplish hydrocarbon composition control.

Claims

1. Process for treating a gaseous stream comprising hydrocarbons and CO₂ comprising

(a) separating a portion of hydrocarbons from the gaseous stream to produce a first stream;

(b) separating CO₂ from the first stream in a first CO₂ absorption zone by absorption in a first solution effective for CO₂ removal to produce a hydrocarbon enriched second stream;

(c) further separating CO₂ from the second stream in at least a second CO₂ absorption zone by absorption in a second solution effective for CO₂ removal to produce a further hydrocarbon enriched third stream,

wherein the gaseous stream comprises CO₂ and hydrocarbons such that in the absence of step (a) hydrocarbon condensation due to hydrocarbon dewpoint temperature increase occurs as CO₂ is removed in at least one of steps (b) and (c), and

wherein the first solution comprises an aqueous tertiary alkanolamine solution; and

the second solution comprises an aqueous alkanolamine solution selected from the group consisting of aqueous secondary alkanolamine solutions and aqueous primary alkanolamine solutions.

2. Process as in claim 1 wherein

the gaseous stream comprises in excess of about 20 mol% CO₂ and C₃ and heavier hydrocarbons such that in the absence of step (a) of claim 1 hydrocarbon condensation occurs in at least one of steps (b) and (c) of claim 1.

3. Process as in claim 2 wherein

the separating of step (a) to claim 1 is by chilling the gaseous stream to a temperature so that the hydrocarbon dewpoint temperature profile during CO₂ absorption is at least less than the temperature of one of the hydrocarbon enriched second stream and the further hydrocarbon enriched third stream.

4. Process as in claim 3 wherein

the gaseous stream is chilled to a temperature so that the hydrocarbon dewpoint temperature profile during CO₂ absorption is at least 10°

F. less than the temperature of said at least one of the hydrocarbon enriched second stream and the further hydrocarbon enriched third stream.

5. Process as in claim 3 wherein

the first solution comprises an aqueous triethanolamine (TEA) solution;

and

the second solution comprises an aqueous diethanolamine (DEA) solution.

6. Process as in claim 3 wherein

the gaseous stream comprises in the range of about 30 mol% CO₂ to about 95 mol% CO₂.

7. Process as in claim 3 wherein

the gaseous stream comprises in the range of about 30 mol% CO₂ to about 60 mol% CO₂.

8. Process as in claim 3 wherein

the gaseous stream is a gaseous stream from a CO₂ miscible flood produced reservoir and is characterized by containing greater than about 30 mol% CO₂ and by a variable C₃ and heavier hydrocarbon composition.

9. Process as in claim 8 wherein

the gaseous stream is further characterized by a generally increasing C₄ and heavier hydrocarbon fraction as a function of increased CO₂ content in the gaseous stream from the CO₂ miscible flood produced reservoir.

10. Process as in claim 1 wherein

the gaseous stream further comprises H₂ S;

the first CO₂ absorption zone and the second CO₂ absorption zone are effective for separation of CO₂ and H₂ S to produce an acid gas stream comprising CO₂ and H₂ S; and

the acid gas stream is introduced into a third CO₂ absorption zone to produce a CO₂ stream substantially free of H₂ S.

35. Process as in claim 3 wherein:

the first solution comprises an aqueous methyldiethanolamine (MDEA) solution; and

the second solution comprises an aqueous diethanolamine (DEA) solution.

36. Process for treating a gaseous steam as in claim 1 wherein step (c) further comprises:

separating a second portion of hydrocarbons from the second stream prior to further separating CO₂ from the second stream to produce the third stream.

11. Process for treating a gaseous stream comprising

(a) separating at least a first portion of hydrocarbons from the gaseous stream to produce a first stream having a reduced hydrocarbon content;

(b) separating CO₂ from the first stream in a first CO₂ absorption zone by absorption in a first solution effective for CO₂ removal to produce a hydrocarbon enriched second stream;

(c) subsequently separating a second portion of hydrocarbons from the second stream to produce a third stream having a further reduced hydrocarbon content; and

(d) further separating CO₂ from the third stream in at least a second CO₂ absorption zone by absorption in a second solution effective for CO₂ removal to produce a further hydrocarbon enriched fourth stream; and

wherein

the separation of step (a) is effective for preventing hydrocarbon condensation due to hydrocarbon dewpoint temperature increase during CO₂ removal in at least the first CO₂ absorption zone, and

the separation of step (c) is effective for preventing hydrocarbon condensation due to hydrocarbon dewpoint temperature increase during CO₂ removal in said at least a second CO₂ absorption zone, and wherein

the gaseous stream comprises CO₂ and hydrocarbons such that in the absence of steps (a) and (c) hydrocarbon condensation due to hydrocarbon dewpoint increase occurs as CO₂ is removed, and wherein

the first solution comprises an aqueous tertiary alkanolamine solution; and

the second solution comprises an aqueous alkanolamine solution selected from the group consisting of aqueous secondary alkanolamine solutions and aqueous primary alkanolamine solutions.

12. Process as in claim 11 wherein

the gaseous stream comprises in excess of about 20 mol% CO₂ and C₃ and heavier hydrocarbons such that in the absence of steps (a) and (c) hydrocarbon condensation occurs in steps (b) and (d) respectively during CO₂ separation.

13. Process as in claim 12 wherein

The separating of step (a) is by chilling the gaseous stream so that the hydrocarbon dewpoint temperature profile during CO₂ absorption is less than the temperature of the thus produced hydrocarbon enriched second stream;

and

the separating of step (c) is by chilling the hydrocarbon enriched second stream so that the hydrocarbon dewpoint temperature profile during CO₂ absorption is less than the temperature of the thus produced hydrocarbon enriched fourth stream.

14. Process as in claim 13 wherein

the gaseous stream is chilled to a temperature so that the hydrocarbon dewpoint temperature profile during CO₂ absorption is at least 10°

F. less than the temperature of the thus produced hydrocarbon enriched second stream; and

the hydrocarbon enriched second stream is chilled to a temperature so that the hydrocarbon dewpoint temperature profile during absorption is at least 10°

F. less than the temperature of the thus produced hydrocarbon enriched fourth stream.

15. Process as in claim 12 wherein

the first solution comprises an aqueous triethanolamine (TEA) solution;

and

the second solution comprises an aqueous diethanolamine solution.

16. Process as in claim 12 wherein

the gaseous stream comprises in the range of about 30 mol% CO₂ to about 95 mol% CO₂.

17. Process as in claim 12 wherein

the gaseous stream comprises in the range of about 30 mol% CO₂ to about 60 mol% CO₂.

18. Process as in claim 12 wherein

the gaseous stream is a gaseous stream from a CO₂ miscible flood produced reservoir and is characterized by containing greater than about 30 mol% CO₂ and by a variable C₃ and heavier hydrocarbon composition.

19. Process as in claim 18 wherein

the gaseous stream is further characterized by a generally increasing C₄ and heavier hydrocarbon fraction as a function of increased CO₂ content in the gaseous stream from the CO₂ miscible flood produced reservoir.

20. Process as in claim 11 wherein

the gaseous stream further comprises H₂ S;

the first CO₂ absorption zone and the second CO₂ absorption zone are effective for separation of CO₂ and H₂ S to produce an acid gas stream comprising CO₂ and H₂ S; and

the acid gas stream is introduced into a third CO₂ absorption zone to produce a CO₂ stream substantially free of H₂ S.

37. Process as in claim 12 wherein:

the first solution comprises an aqueous methyldiethanolamine (MDEA) solution; and

the second solution comprises an aqueous diethanolamine (DEA) solution.

21. Process for treating a gaseous stream comprising hydrocarbons and CO₂, the process comprising:

(a) separating a first portion of CO₂ from the gaseous stream in a permeation zone by selective permeation of CO₂ across a differentially permeable membrane to produce a CO₂ permeate and a hydrocarbon enriched first stream; and

(b) further separating CO₂ from the hydrocarbon enriched first stream in at least one CO₂ absorption zone by absorption utilizing an aqueous alkanolamine solution effective for CO₂ removal to produce a further hydrocarbon enriched process stream, and wherein

the gaseous stream comprises hydrocarbons including C₃ and heavier hydrocarbons such that hydrocarbon condensation occurs during separation of CO₂ unless the gaseous stream is treated to remove at least a portion of the hydrocarbons, the process thus further comprising;

separating a portion of hydrocarbons from the gaseous stream such that hydrocarbon condensation does not occur due to hydrocarbon dewpoint increase as CO₂ is removed during step (a); and

subsequently separating a further portion of hydrocarbons from the hydrocarbon enriched first stream such that hydrocarbon condensation does not occur due to hydrocarbon dewpoint increase as CO₂ is removed during step (b).

22. Process as in claim 21 wherein

said at least one CO₂ absorption zone of step (b) of claim 21 comprises at least two CO₂ absorption zones;

and wherein

the gaseous stream comprises hydrocarbons including C₃ and heavier hydrocarbons such that hydrocarbon condensation occurs during absorption of CO₂ unless the stream is treated to remove at least a portion of the hydrocarbons, the process further comprising;

separating a first portion of hydrocarbons from the gaseous stream prior to separating CO₂ in accordance with step (a) of claim 21 such that hydrocarbon condensation does not occur during step (a);

separating CO₂ from the hydrocarbon enriched first stream in a first CO₂ absorption zone by absorption in a first solution effective for CO₂ removal to produce a second stream; and

separating a second portion of hydrocarbons from the second stream to produce a third stream having reduced hydrocarbon content;

further separating CO₂ from the third stream in at least a second CO₂ absorption zone by absorption in a second solution effective for CO₂ removal to produce a further hydrocarbon enriched fourth stream; and

wherein

the step of separating a second portion of hydrocarbons from the second stream is effective to prevent hydrocarbon condensation during CO₂ separation in said at least a second CO₂ absorption zone.

23. Process as in claim 22 wherein

the first solution comprises an aqueous tertiary alkanolamine solution;

and

the second solution comprises an aqueous alkanolamine solution selected from the group consisting of aqueous secondary alkanolamine solutions and aqueous primary alkanolamine solutions.

24. Process as in claim 21 wherein

said at least one CO₂ absorption zone comprises at least two CO₂ absorption zones;

and wherein

the step of subsequently removing a further portion of hydrocarbons from the hydrocarbon enriched first stream such that hydrocarbon condensation does not occur during step (b) of claim 21 occurs prior to at least one of said at least two CO₂ absorption zones.

25. Process as in claim 21 wherein

the gaseous stream comprises in the range of 30 mol% CO₂ to 95 mol% CO₂.

26. Process as in claim 25 wherein

the gaseous stream comprises in the range of about 60 mol% CO₂ to about 95 mol% CO₂.

27. Process as in claim 21 wherein

the CO₂ absorption zone comprises at least a first CO₂ absorption zone and a second CO₂ absorption zone and step (b) of claim 21 further comprises:

(1) separating CO₂ from the first stream in the first CO₂ absorption zone by absorption in a first solution effective for CO₂ removal to produce a hydrocarbon enriched second stream;

(2) further separating CO₂ from the second stream in at least a second CO₂ absorption zone by absorption in a second solution effective for CO₂ removal to produce a further hydrocarbon enriched third stream.

28. Process as in claim 27 wherein

the first solution has a lower reactivity towards CO₂ and lower energy requirements for regeneration than the second solution.

29. Process as in claim 28 wherein

the first solution comprises an aqueous tertiary alkanolamine solution;

and

the second solution is selected from the group consisting of aqueous secondary alkanolamine solutions and aqueous primary alkanolamine solutions.

30. Process as in claim 28 wherein

the first solution comprises an aqueous triethanolamine (TEA) solution;

and

the second solution comprises an aqueous diethanolamine (DEA) solution.

31. Process as in claim 21 wherein

said at least one CO₂ absorption zone comprises at least a first CO₂ absorption zone and a second CO₂ absorption zone;

and wherein

the step of subsequently removing a further portion of hydrocarbons from the hydrocarbon enriched first stream such that hydrocarbon condensation does not occur during step (b) of claim 21 occurs prior to at least one of said first CO₂ absorption zone and said second CO₂ absorption zone, step (b) of claim 21 further comprising;

(1) separating CO₂ from the first stream in the first CO₂ absorption zone by absorption in a first solution effective for CO₂ removal to produce a hydrocarbon enriched second stream;

(2) further separating CO₂ from the second stream in at least a second CO₂ absorption zone by absorption in a second solution effective for CO₂ removal to produce a further hydrocarbon enriched third stream, and wherein

the first solution comprises an aqueous tertiary alkanolamine solution; and

the second solution comprises an aqueous alkanolamine solution selected from the group consisting of aqueous secondary alkanolamine solutions and aqueous primary alkanolamine solutions.

32. Process as in claim 31 wherein

the first solution comprises an aqueous triethanolamine (TEA) solution;

and

the second solution comprises an aqueous diethanolamine (DEA) solution.

33. Process as in claim 21 wherein

the gaseous stream is a gaseous stream from a CO₂ miscible flood produced reservoir and is characterized by containing greater than about 30 mol% CO₂ and by a variable C₃ and heavier hydrocarbon composition.

34. Process as in claim 21 wherein

the gaseous stream is further characterized by a generally increasing C₄ and heavier hydrocarbon fraction as a function of increased CO₂ content in the gaseous stream from the CO₂ miscible flood produced reservoir.

38. Process as in claim 28 wherein:

the first solution comprises an aqueous methyldiethanolamine (MDEA) solution; and

the second solution is an aqueous diethanolamine (DEA) solution.

39. Process as in claim 31 wherein:

the first solution comprises an aqueous methyldiethanolamine (MDEA) solution; and

the second solution comprises an aqueous diethanolamine (DEA) solution.