Production of hydrocarbon using direct-contact steam generation

Patent metadata

Field	Value
Publication number	US-10851630-B2
Application number	US-201715716821-A
Country	US
Kind code	B2
Filing date	Sep 27, 2017
Priority date	Sep 28, 2016
Publication date	Dec 1, 2020
Grant date	Dec 1, 2020

Abstract

A process for in situ thermal recovery of hydrocarbons from a reservoir is provided. The process includes: providing an oxygen-enriched mixture, fuel, feedwater and an additive including at least one of ammonia, urea and a volatile amine to a Direct-Contact Steam Generator (DCSG); operating the DCSG, including contacting the feedwater and the additive with hot combustion gas to obtain a steam-based mixture including steam, CO2 and the additive; injecting the steam-based mixture or a stream derived from the steam-based mixture into the reservoir to mobilize the hydrocarbons therein; and producing a produced fluid including the hydrocarbons.

First claim

The invention claimed is:

1. A process for in situ thermal recovery of hydrocarbons from a reservoir, comprising:
providing an oxygen-enriched mixture, fuel, feedwater and an additive comprising at least one of ammonia, urea or a volatile amine to a direct-contact steam generator (DCSG);
operating the DCSG, comprising contacting the feedwater and the additive with hot combustion gas to obtain a steam-based mixture comprising steam, CO 2 and the additive;
injecting the steam-based mixture or a stream derived from the steam-based mixture into the reservoir to mobilize the hydrocarbons therein; and
producing a produced fluid comprising the hydrocarbons.

2. The process of claim 1 , wherein the additive comprises ammonia.

3. The process of claim 2 , wherein the ammonia is provided as an ammonium hydroxide solution.

4. The process of claim 1 , wherein the concentration of the additive in the steam-based mixture is between about 0.1 wt % and about 30 wt %.

5. The process of claim 1 , wherein the steam-based mixture comprises the additive in a gaseous and/or vapor state.

6. The process of claim 1 , wherein the additive further comprises at least one of a viscosity reduction agent or a well integrity agent, wherein the well integrity agent comprises an anticorrosive agent, an antifouling agent, a scale inhibitor or thermally stable cement or wherein the well integrity agent is configured to promote structural integrity of a tubing or annulus of an injection well or a production well, of a downhole tool or of the reservoir if damaged, or a combination thereof.

7. The process of claim 1 , wherein the feedwater and the additive are provided as a single feed stream to the DCSG.

8. The process of claim 1 , wherein the feedwater is provided as a feedwater stream and the additive is provided as a separate additive stream, to the DCSG.

9. The process of claim 8 , wherein the feedwater stream is contacted with the hot combustion gas for a longer time period than the additive stream.

10. The process of claim 1 , wherein the additive is provided to the DCSG and the steam-based mixture is injected into the reservoir during start-up.

11. The process of claim 1 , further comprising providing a waste stream comprising volatile organic components (VOCs) to the DCSG, in order to flare the VOCs in the DCSG.

12. The process of claim 1 , further comprising separating the produced fluid into produced gas, a non-gaseous hydrocarbon component and produced water.

13. The process of claim 12 , wherein the feedwater comprises at least part of the produced water.

14. The process of claim 13 , wherein the feedwater further comprises makeup water, the concentration of the makeup water in the feedwater being of up to about 5 wt % of the feedwater.

15. The process of claim 1 , wherein the additive comprises at least the volatile amine, which is selected from methyl amine, dimethyl amine, trimethyl amine, diethyl amine, ethyl amine, isopropyl amine, n-propyl amine, diethyl amine, 1,1-dimethyl hydrazine, isobutyl amine, n-butyl amine, pyrrolidone, triethylamine, methyl hydrazine, piperidine, dipropylamine, hydrazine, pyridine, ethylenediamine, 3-methoxypropylamine, N,N-diethylhydroxylamine, morpholine, pyrrole, cyclohexylamine or a mixture thereof.

16. A system for recovering hydrocarbons from a reservoir, comprising:
a DCSG for generating a steam-based mixture, the DCSG comprising:
an oxygen inlet for receiving an oxygen-enriched mixture;
a fuel inlet for receiving fuel; and
at least one inlet for receiving feedwater and an additive comprising
at least one of ammonia, urea or a volatile amine, the steam-based mixture comprising steam, CO 2 and the additive;

an injection well in fluid communication with the DCSG to receive the steam-based mixture or a stream derived from the steam-based mixture;
a production well for recovering produced fluids from the reservoir; and
a hydrocarbon separating unit in fluid communication with the production well to receive the produced fluids and separate the hydrocarbons from the produced fluids.

17. The system of claim 16 , wherein the additive comprises ammonia.

18. The system of claim 17 , wherein the ammonia is provided as an ammonium hydroxide solution.

19. The system of claim 17 , wherein the steam-based mixture comprises the additive in a gaseous state.

20. The system of claim 16 , wherein the additive further comprises at least one of a viscosity reduction agent or a well integrity agent, wherein the well integrity agent comprises an anticorrosive agent, an antifouling agent, a scale inhibitor or thermally stable cement or wherein the well integrity agent is configured to promote structural integrity of a tubing or annulus of an injection well or a production well, of a downhole tool or of the reservoir if damaged, or a combination thereof.

21. The system of claim 16 , wherein the concentration of the additive in the steam-based mixture is between about 0.1 wt % and about 30 wt %.

22. The system of claim 16 , wherein the at least one inlet for receiving the feedwater and the additive is a single inlet, such that the feedwater and the additive are provided as a single feed stream to the DCSG.

23. The system claim 16 , wherein the at least one inlet for receiving the feedwater and the additive comprises a feedwater inlet and a separate additive inlet, such that the feedwater is provided as a feedwater stream and the additive is provided as a separate additive stream, to the DCSG.

24. The system of claim 16 , wherein the injection well and the production well are formed within two separate well bores.

25. The system of claim 16 , wherein the injection well and the production well are formed within a single well bore.

26. A process for in situ thermal recovery of hydrocarbons from a reservoir, comprising:
providing an oxygen-enriched mixture, fuel, feedwater and an additive in liquid state to a DCSG, wherein the additive comprises at least one of a surfactant or a viscosity reduction agent for reducing the viscosity of the hydrocarbons;
operating the DCSG, comprising contacting the feedwater and the additive with hot combustion gas to obtain a steam-based mixture comprising steam, CO 2 and the additive in a gaseous state and/or a dispersed state; and
injecting the steam-based mixture or a stream derived from the steam-based mixture into the reservoir to mobilize the hydrocarbons therein; and
producing a produced fluid comprising the hydrocarbons.

27. The process of claim 26 , wherein the additive is in a gaseous state in the steam-based mixture.

28. The process of claim 26 , wherein the additive is in a dispersed state.

29. The process of claim 26 , wherein all of the steam-based mixture generated by the DCSG is injected into the reservoir.

Assignees

• Suncor Energy Inc

Inventors

• Acosta Ramirez Hugo
• Pugsley Todd

Classifications

• C01B32/50 Primary

  Carbon dioxide · CPC title

• C10G1/047

  Hot water or cold water extraction processes · CPC title

• E21C41/24

  for oil-bearing deposits · CPC title

• Y02E20/32

  Direct CO2 mitigation · CPC title

• F22B1/22

  using combustion under pressure substantially exceeding atmospheric pressure · CPC title