Gas-phase solvent management during production of in-situ hydrocarbons

Patent metadata

Field	Value
Publication number	US-11965403-B2
Application number	US-202117352155-A
Country	US
Kind code	B2
Filing date	Jun 18, 2021
Priority date	Jun 18, 2020
Publication date	Apr 23, 2024
Grant date	Apr 23, 2024

Abstract

Methods for producing hydrocarbons from subterranean reservoirs utilizing a production well having a plurality of fluid-inlet components spaced apart to define a plurality of production-well fluid-inlet zones. An injection fluid comprising a solvent is injected into the reservoir, resulting in a drainage fluid with a liquid phase and a gas phase occupying one or more of the production-well fluid-inflow zones. The production fluid is produced at a production-flow rate via a pump, and the gas phase:liquid phase ratio of the production fluid is modulated by orchestrating variations in the pump speed and one or more of the plurality of fluid-inlet components to prioritize hydraulic communication with a subset of the plurality of production-well fluid-inlet zones.

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:
i) injecting an injection fluid comprising a solvent into the reservoir, by way of the injection well, to mobilize hydrocarbons in the reservoir, such that a drainage fluid comprising a liquid phase and a gas phase occupies one or more of the production-well fluid-inlet zones, wherein the gas phase comprises at least a portion of the solvent and the liquid phase comprises mobilized hydrocarbons;
ii) 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 of the drainage fluid and at least a portion of the gas phase of the drainage fluid such that the production fluid is defined by a liquid phase:gas phase ratio;
iii) during the producing of the production fluid of ii), 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 by distributed measurements of temperature or acoustic energy along the production well or by evaluation of flow performed autonomously by the fluid inlet components themselves during the producing of the production fluid; and
iv) during the producing of the production fluid of ii), selectively actuating at least one of the plurality of fluid-inlet components based on the at least one of the plurality of fluid-inlet components being adjacent and corresponding to the higher-gas zone as determined in iii), in order to reduce flow of the drainage fluid through only the at least one of the 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 the rest of the plurality of production-well fluid-inflow zones spaced apart from the higher-gas zone, and orchestrating 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 3 , wherein the shiftable ports are actuated in response to changes in the liquid phase:gas phase ratio of the production fluid.

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

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

8. The method of claim 7 , 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.

9. 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.

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

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

12. The method of claim 1 , wherein orchestrating variations in the pump speed of iv) comprises adjusting parameters such that the average gas-production rate is between: (i) about 1,000 m 3 /day and about 30,000 m 3 /day under STP conditions, (ii) about 10,000 m 3 /day and about 30,000 m 3 /day under STP conditions, or (iii) about 20,000 m 3 /day and about 30,000 m 3 /day under STP conditions.

13. The method of claim 1 , wherein the liquid phase:gas phase ratio of the production fluid is between: (i) about 1:100 and about 1:1, (ii) about 1:80 and about 1:20, or (iii) about 1:60 and about 1:40.

14. The method of claim 1 , wherein at least one of the plurality of production-well fluid inlet zones has a temperature of between: (i) about 50° C. and about 300° C., (ii) about 70° C. and about 250° C., or (iii) about 120° C. and about 200° C.

15. The method of claim 1 , wherein at least one of the plurality of production-well fluid-inlet zones has a pressure of between: (i) about 500 kPaA and about 10,000 kPaA, (ii) about 1,000 kPaA and about 8,000 kPaA, or (iii) about 3,000 kPaA and about 6,000 kPaA.

16. The method of claim 1 , wherein the injection fluid further comprises steam.

17. The method of claim 16 , wherein the injection fluid comprises less than about 50% solvent and greater than about 50% steam on a mass basis.

18. The method of claim 16 , wherein the injection fluid comprises greater than about 50% solvent and less than about 50% steam on a mass basis.

19. The method of claim 1 , wherein the solvent comprises propane, butane, diluent, natural gas condensate, or a combination thereof.

20. 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.

Assignees

• Cenovus Energy Inc

Inventors

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

Classifications

• E21B43/2408 Primary

  SAGD in combination with other methods · CPC title