Non-condensable gas management during production of in-situ hydrocarbons

Patent metadata

Field	Value
Publication number	US-11713656-B2
Application number	US-202117352152-A
Country	US
Kind code	B2
Filing date	Jun 18, 2021
Priority date	Jun 18, 2020
Publication date	Aug 1, 2023
Grant date	Aug 1, 2023

Abstract

Methods for producing hydrocarbons from subterranean reservoirs utilize a production well having a plurality of individually-actuatable fluid-inlet components that are spaced apart to define a plurality of production-well fluid-inlet zones. An injection fluid including a non-condensable gas (NCG) is injected into the reservoir, such that a drainage fluid including at least a portion of the NCG occupies the production-well fluid-inlet zones. The gas phase:liquid phase ratio of a production fluid is modulated by identifying at least one of the production-well fluid-inlet zones as having a gas content above a threshold and thus being a higher-gas zone, and actuating variations in pump speed and the flow states of the plurality of fluid-inlet components adjacent and corresponding to the higher-gas zone to prioritize hydraulic communication with a subset of the plurality of production-well fluid-inlet zones spaced apart from the higher-gas zone.

First claim

The invention claimed is:

1. A method for producing hydrocarbons from a subterranean reservoir that is penetrated by an injection well and a production well, wherein the production well comprises a substantially-horizontal section along which a plurality of individually-actuatable fluid-inlet components are spaced apart to define a plurality of production-well fluid-inlet zones in hydraulic communication with the horizontal section of the production well, the method comprising:
injecting an injection fluid comprising a non-condensable gas into the reservoir, by way of the injection well, to drive steam, solvent, mobilized hydrocarbons, or a combination thereof to occupy one or more of the production-well fluid-inlet zones as a drainage fluid, the drainage fluid comprising a liquid phase portion and a gas phase portion, wherein the gas phase portion of the drainage fluid further comprises at least a portion of the non-condensable gas;
producing a production fluid at a production-flow rate via a pump running at a pump speed and in hydraulic communication with the production fluid, wherein the production fluid comprises at least a portion of the liquid phase portion of the drainage fluid and at least a portion of the gas phase portion of the drainage fluid such that the production fluid is defined by a liquid phase:gas phase ratio reflecting the proportions of the portion of the liquid phase portion in the production fluid and the portion of the gas phase portion in the production fluid;
identifying at least one of the production-well fluid-inlet zones as having a gas content above a threshold and thus being a higher-gas zone; and
selectively actuating at least one of the plurality of fluid-inlet components adjacent and corresponding to the higher-gas zone to reduce flow of the drainage fluid through the at least one of the plurality of fluid-inlet components corresponding to the higher-gas zone and thereby increase the liquid phase:gas phase ratio of the production fluid by prioritizing hydraulic communication with at least one other of the plurality of production-well fluid-inflow zones spaced apart from the higher-gas zone, and actuating variations in the pump speed to modulate the production-flow rate and account for the variations in one or more of the plurality of fluid-inlet components.

2. The method of claim 1 , wherein the plurality of fluid-inlet components comprises one or more inflow-control devices.

3. The method of claim 2 , wherein the one or more inflow-control devices comprise shiftable ports that are configured for remote operation.

4. The method of claim 3 , wherein the shiftable ports are actuated in response to changes in distributed acoustic sensing (DAS), distributed temperature sensing (DTS), or a combination thereof.

5. The method of claim 2 , wherein the one or more inflow-control devices are autonomous inflow-control devices.

6. The method of claim 1 , wherein the plurality of fluid-inlet components comprises one or more upper production ports.

7. The method of claim 6 , wherein one or more of the plurality of fluid-inlet components are coupled to a production-string tubing that is in hydraulic communication with the pump.

8. The method of claim 1 , wherein the plurality of fluid-inlet components are spaced apart by between about 50 m and about 500 m along the substantially-horizontal section of the production well.

9. The method of claim 1 , wherein one or more of the plurality of fluid-inlet components are interposed between annulus-flow restrictors.

10. The method of claim 9 , wherein the annulus-flow restrictors comprise packers.

11. The method of claim 1 , wherein actuating variations in the pump speed comprises adjusting parameters such that the average gas-production rate is between about 1,000 m 3 /day and about 30,000 m 3 /day under STP conditions.

12. The method of claim 1 , wherein at least one of the plurality of production-well fluid-inlet zones has a temperature of between about 50° C. and about 300° C.

13. The method of claim 1 , wherein at least one of the plurality of production-well fluid-inlet zones has a pressure of between about 500 kPaA and about 10,000 kPaA.

14. The method of claim 1 , wherein the NCG is methane, flue gas, CO 2 , O 2 , N 2 , or a combination thereof.

15. The method of claim 1 , wherein the subterranean reservoir is a thin pay reservoir having an average height of between about 5 m and about 15 m.

16. The method of claim 1 , wherein actuating variations in the pump speed comprises adjusting parameters such that the average gas-production rate is between about 10,000 m 3 /day and about 30,000 m 3 /day under STP conditions.

17. The method of claim 1 , wherein actuating variations in the pump speed comprises adjusting parameters such that the average gas-production rate is between about 20,000 m 3 /day and about 30,000 m 3 /day under STP conditions.

18. The method of claim 1 , wherein at least one of the plurality of production-well fluid-inlet zones has a temperature of between about 70° C. and about 250° C.

19. The method of claim 1 , wherein at least one of the plurality of production-well fluid-inlet zones has a temperature of between about 120° C. and about 200° C.

20. The method of claim 1 , wherein at least one of the plurality of production- well fluid-inlet zones has a pressure of between about 1,000 kPaA and about 8,000 kPaA.

21. The method of claim 1 , wherein at least one of the plurality of production- well fluid-inlet zones has a pressure of between about 3,000 kPaA and about 6,000 kPaA.

22. The method of claim 1 , wherein the plurality of fluid-inlet components are spaced apart by between about 100 m and about 400 m along the substantially-horizontal section of the production well.

23. The method of claim 1 , wherein the plurality of fluid-inlet components are spaced apart by between about 200 m and about 350 m along the substantially-horizontal section of the production well.

Assignees

• Cenovus Energy Inc

Inventors

• Ben-Zvi Amos
• Fardi Amin
• Gittins Simon D
• Miller Michael
• Miller Ryan
• Schrader Trenton M

Classifications

• E21B43/12 Primary

  Methods or apparatus for controlling the flow of the obtained fluid to or in wells (E21B43/25 takes precedence; valve arrangements E21B34/00) · CPC title

• E21B43/168 Primary

  Injecting a gaseous medium · CPC title

• E21B47/06

  Measuring temperature or pressure · CPC title