Remote steam generation and water-hydrocarbon separation in steam-assisted gravity drainage operations

Patent metadata

Field	Value
Publication number	US-10246979-B2
Application number	US-201514671104-A
Country	US
Kind code	B2
Filing date	Mar 27, 2015
Priority date	Mar 28, 2014
Publication date	Apr 2, 2019
Grant date	Apr 2, 2019

Abstract

A Steam-Assisted Gravity Drainage (SAGD) method for recovering hydrocarbons from a reservoir can include generating steam and CO2 from feedwater, fuel and oxygen; transferring a steam-CO2 mixture comprising at least a portion of the steam and at least a portion of the CO2, to a proximate SAGD injection well; injecting the steam-CO2 mixture into the SAGD injection well; obtaining produced fluids from a SAGD production well underlying the SAGD injection well; transferring the produced fluids for separation proximate to the SAGD production well; separating the produced fluids into a produced gas and a produced emulsion; transferring the produced emulsion for separation proximate to the SAGD production well; separating the produced emulsion to obtain a produced hydrocarbon-containing component and produced water; supplying at least a portion of the produced water as at least part of the feedwater; and supplying the produced hydrocarbon-containing component to a central processing facility.

First claim

The invention claimed is:

1. A system for recovering hydrocarbons from a reservoir, the system comprising:
a processing facility comprising a first water-hydrocarbon separator; and
a remote hydrocarbon recovery facility connected to the processing facility by a supply line, the remote hydrocarbon recovery facility comprising:
a steam generator for receiving feedwater and generating a steam-based mixture therefrom, wherein the steam generator comprises a Direct-Contact Steam Generator (DCSG);
a well pad supporting a well pair comprising:
an injection well in fluid communication with the steam generator to receive the steam-based mixture; and
a production well for recovering produced fluids from the reservoir; and

a second water-hydrocarbon separator in fluid communication with the production well to receive the produced fluids and produce a produced water component and a hydrocarbon mixture comprising an amount of water, the supply line providing fluid communication between the first water-hydrocarbon separator and the second water-hydrocarbon separator to transport the hydrocarbon mixture to the processing facility without transporting the produced water component, the first water-hydrocarbon separator separating the hydrocarbon mixture into treated water and produced hydrocarbons.

2. The system of claim 1 , wherein the DCSG is a Direct-Fired Steam Generator (DFSG).

3. The system of claim 1 , further comprising:
a fuel line for supplying fuel from the processing facility to the steam generator.

4. The system of claim 1 , further comprising:
an oxygen supply assembly for supplying an oxygen-containing gas to the steam generator for combustion.

5. The system of claim 1 , wherein the amount of water in the hydrocarbon mixture is up to about 10 wt %.

6. The system of claim 1 , further comprising:
a second recycle line for conveying at least a portion of the treated water back to the remote hydrocarbon recovery facility to recycle at least a portion of the treated water as part of the feedwater to the steam generator.

7. The system of claim 1 , further comprising:
a gas-emulsion separator in fluid communication with the production well to receive the produced fluids and produce a produced gas and gas-depleted produced fluids, the second water-hydrocarbon separator being configured to receive the gas-depleted produced fluids to produce the produced water component and the hydrocarbon mixture.

8. The system of claim 7 , further comprising a produced gas line for transporting the produced gas from the gas-emulsion separator to the processing facility.

9. The system of claim 1 , wherein the second water-hydrocarbon separator comprises a free water knockout drum.

10. The system of claim 9 , wherein the first water-hydrocarbon separator comprises a treater.

11. The system of claim 9 , wherein the water-hydrocarbon separator further comprises a skim tank.

12. The system of claim 9 , wherein the water-hydrocarbon separator further comprises an induced floatation unit.

13. The system of claim 9 , wherein the water-hydrocarbon separator further comprises a walnut shell filtering unit.

14. The system of claim 9 , wherein the water-hydrocarbon separator further comprises a slop-oil tank.

15. The system of claim 1 , further comprising:
a diluent line to supply a diluent to the produced fluids to produce diluted produced fluids that are separated in the second water-hydrocarbon separator.

16. The system of claim 15 , wherein the diluent line is connected upstream of the water-hydrocarbon separator.

17. The system of claim 15 , wherein the diluent line is in fluid communication with the processing facility to receive the diluent therefrom.

18. The system of claim 15 , wherein the diluent line is in fluid communication with a diluent tank or diluent truck located at the remote hydrocarbon recovery facility.

19. The system of claim 1 , further comprising:
a water recycle line for recycling at least a portion of the produced water component from the second water-hydrocarbon separator as at least part of the feedwater received by the DCSG.

20. The system of claim 19 , wherein recycling at least a portion of the produced water component comprises recycling all of the produced water component.

21. The system of claim 19 , wherein the feedwater further comprises makeup water.

22. The system of claim 21 , wherein the makeup water is at least partially obtained from the processing facility.

23. The system of claim 21 , wherein the concentration of the makeup water in the feedwater is about 0 wt% to about 90 wt%.

24. The system of claim 21 , wherein the concentration of the makeup water in the feedwater is about 0 wt% to about 20 wt%.

25. The system of claim 21 , further comprising:
a makeup water line for supplying the makeup water to the steam generator from a water source.

26. The system of claim 25 , wherein the water source comprises a water tank located at the remote hydrocarbon recovery facility.

27. The system of claim 1 , wherein the hydrocarbons are recovered from the reservoir by Steam-Assisted Gravity Drainage (SAGD).

28. The system of claim 7 , wherein the injection well is a SAGD injection well and the production well is a SAGD production well underlying the SAGD injection well.

29. The system of claim 27 , wherein the steam-based mixture comprises a steam-CO 2 mixture that includes steam and combustion gases produced by the DCSG.

30. The system of claim 29 , wherein the steam-CO 2 mixture comprises between about 1 wt. % and about 12 wt. % of CO 2 .

31. The system of claim 1 , wherein the steam generator of the remote hydrocarbon recovery facility consists of a DCSG.

32. The system of claim 31 , comprising a feedwater supply line in fluid communication between the DCSG and the second water-hydrocarbon separator, and configured to supply all of the produced water component to the DCSG.

33. The system of claim 31 , comprising a plurality of the remote hydrocarbon recovery facilities being connected to the processing facility by respective supply lines to supply respective hydrocarbon mixtures to the processing facility.

34. The system of claim 31 , wherein the steam generator and the second water-hydrocarbon separator are located within 200 meters of the well pad, and the processing facility is located multiple kilometers away from the remote hydrocarbon recovery facility.

35. The system of claim 34 , wherein the steam generator and the second water-hydrocarbon separator are located on the well pad.

Assignees

• Suncor Energy Inc

Inventors

• Donald Andrew
• Pugsley Todd Stewart
• Bunio Gary L
• Gates Ian Donald

Classifications

• E21B43/2408 Primary

  SAGD in combination with other methods · CPC title

• E21B43/40

  Separation associated with re-injection of separated materials {(E21B43/385 takes precedence)} · CPC title

• E21B43/164

  Injecting CO2 or carbonated water (in combination with organic material C09K8/594) · CPC title