DIRECT STEAM GENERATOR DEGASSING

• US 20150369025A1
• Filed: 02/19/2015
• Published: 12/24/2015
• Est. Priority Date: 02/18/2014
• Status: Active Grant

• Current Assignee: Heat IP Holdco LLC
• Original Assignee: Conocophillips Company (ConocoPhillips)
• Inventors: LATIMER, Edward, COPELAND, Chris, FIEDLER, Michelle, LAMONT, David
• Granted Patent: US 10,087,730 B2
• Time in Patent Office: Days
• US Class Current: 1/1
• CPC Class Codes: B01D 19/0068 General arrangements, e.g. flowsheets B01D19/0063 takes precedence
• CPC Class Codes: B01D 19/0073 by a method not covered by groups B01D19/0005 - B01D19/0042
• CPC Class Codes: B01D 5/0069 with degasification or deaeration
• CPC Class Codes: E21B 43/24 using heat, e.g. steam injection

Abstract

Systems and methods generate steam mixed with desired non-condensable gas concentrations using a direct steam generator. Injecting the steam into a reservoir may facilitate recovering hydrocarbons from the reservoir. Cooling an output of the direct steam generator produces water condensate, which is then separated from the non-condensable gas, such as carbon dioxide. Reducing pressure of the condensate subsequently heated by cross-exchange with effluent of the direct steam generator regenerates the steam with the carbon dioxide removed for the injection.

Claims

1. A method of recovering hydrocarbons with steam, comprising:

vaporizing water by direct contact of the water with combustion products to produce a resulting fluid including the steam and carbon dioxide;

cooling the fluid to provide a mixture of the carbon dioxide and water condensate;

separating a gas phase with the carbon dioxide from a liquid phase with the condensate;

regenerating the steam by reducing pressure and then heating the condensate in a heat exchanger for thermal transfer with the fluid; and

injecting into a formation the steam with the carbon dioxide removed for recovery of the hydrocarbons.

2. The method of claim 1, wherein the cooling of the fluid includes passing the fluid through the heat exchanger and then passing the fluid through a cooling unit that dissipates heat independent of flows resulting from the vaporizing of the water.

3. The method of claim 1, wherein the reducing of the pressure includes passing the condensate through at least one of an orifice and a throttling valve.

4. The method of claim 1, further comprising recycling to vaporize a liquid component that is separated from the steam following the reducing of the pressure and the heating in the heat exchanger.

5. The method of claim 1, wherein the gas phase with the carbon dioxide is conveyed to a sequestration site distinct from the formation with the hydrocarbons.

6. The method of claim 1, wherein the fluid is at a first pressure between 10,000 and 14,500 kilopascals (kPa) and the steam that is injected into the formation is at a second pressure between 5500 and 10,000 kPa.

7. The method of claim 1, wherein the separating of the gas phase results in the steam that is injected having less than ten percent of the carbon dioxide from the fluid.

8. The method of claim 1, wherein the mixture of the carbon dioxide and the water condensate prior to separation is at least eighty percent liquid by weight.

9. The method of claim 1, wherein the mixture of the carbon dioxide and the water condensate prior to separation is between eighty-three and ninety-three percent liquid by weight.

10. The method of claim 1, wherein the vaporizing of the water provides the steam that is superheated.

11. A system for recovering hydrocarbons with steam, comprising:

a steam generator in which water vaporizes by direct contact with combustion products to produce a resulting fluid including the steam and carbon dioxide;

a cooler coupled to receive the fluid from the steam generator for reducing temperature of the fluid to form a mixture of the carbon dioxide and water condensate;

a separation vessel coupled to the cooler for removing a gas phase with the carbon dioxide from a liquid phase with the condensate;

a pressure reducer coupled between an outlet for the condensate from the vessel and a heat exchanger forming at least part of the cooler to regenerate the steam at less pressure than the steam output from the steam generator using heat from the fluid output by the steam generator;

at least one injection well coupled to the pressure reducer for introducing into a formation the steam with the carbon dioxide removed.

12. The system of claim 11, wherein the cooler includes the heat exchanger and a cooling unit that dissipates heat independent of flows from the steam generator.

13. The system of claim 11, wherein the pressure reducer is at least one of an orifice and a throttling valve.

14. The system of claim 11, further comprising a recycle conduit coupled to supply the steam generator with a liquid component separated from the steam regenerated after the pressure reducer and the heat exchanger.

15. The system of claim 11, further comprising a sequestration site distinct from the formation with the hydrocarbons and where the gas phase with the carbon dioxide is conveyed.

16. The system of claim 11, wherein the steam generator operates at a first pressure between 10,000 and 14,500 kilopascals (kPa) and the pressure reducer is configured to provide the steam that is injected into the formation at a second pressure between 5500 and 10,000 kPa.

17. A method of degassing an output from direct steam generation, comprising:

vaporizing water by direct contact of the water with combustion products to produce a resulting fluid including steam and carbon dioxide;

cooling the fluid in a heat exchanger and then a cooling unit to liquefy the steam into a water condensate at a first pressure;

separating the carbon dioxide in a gaseous phase from the condensate; and

regenerating the steam at a second pressure lower than the first pressure by passing the condensate through a pressure reducer and then the heat exchanger for thermal transfer with the fluid.

18. The method of claim 17, wherein the separating results in the steam at the second pressure having less than ten percent of the carbon dioxide from the fluid.

19. The method of claim 17, wherein a mixture of the carbon dioxide and the water condensate prior to the separating is between eighty-three and ninety-three percent liquid by weight.

20. The method of claim 17, wherein the pressure reducer is at least one of an orifice and a throttling valve.