Method for upgrading in situ heavy oil

Patent metadata

Field	Value
Publication number	US-9739125-B2
Application number	US-201514972361-A
Country	US
Kind code	B2
Filing date	Dec 17, 2015
Priority date	Dec 18, 2014
Publication date	Aug 22, 2017
Grant date	Aug 22, 2017

Abstract

A method is provided for producing upgraded heavy oil from a subterranean reservoir by producing a steam chamber within the reservoir by the action of steam and flowing a liquid phase additive into a near wellbore region of the steam chamber to control asphaltenes mobility within the near wellbore region. Build-up of asphaltenes, which derive from the heavy oil, in the near wellbore region has the potential of affecting heavy oil production rates from the reservoir. The additive is formulated to mobilize the asphaltenes within this region.

First claim

What is claimed is:

1. A method for enhancing oil recovery, comprising:
providing a subterranean reservoir containing heavy oil;
providing a production wellbore containing a production tubing and an injection wellbore spaced-apart from the production wellbore at a predetermined elevation and containing an injection tubing;
injecting steam into the subterranean reservoir and generating a steam chamber in the reservoir to form a near wellbore region in the steam chamber close to the injection tubing and the production tubing, a far wellbore region in the steam chamber distant from the injection tubing and the production tubing, and a condensing region along a perimeter of the steam chamber, such that the injection tubing is in fluid communication with the production tubing within the steam chamber and producing a first heavy oil having a first asphaltene content;
injecting a vapor phase light solvent and additional steam into the steam chamber at a predetermined steam injection temperature and at a predetermined steam injection pressure and producing a second heavy oil having a second asphaltene content, wherein the second heavy oil is produced in response to the light solvent and the additional steam interacting with the heavy oil in the condensing region and causing asphaltenes in the heavy oil to precipitate and remain in the steam chamber; and
injecting a liquid phase additive to the near wellbore region of the steam chamber for mobilizing asphaltenes in the near wellbore region of the steam chamber to remove the asphaltenes from the near wellbore region of the steam chamber for maintaining production of the second heavy oil;
wherein the liquid phase additive has an initial boiling point that is higher than the predetermined steam injection temperature at the predetermined steam injection pressure;
wherein at least 90 wt. % of the additive remains in the liquid phase in the steam chamber at the predetermined steam injection pressure and the predetermined steam injection temperature; and
wherein the second heavy oil is an upgraded heavy oil, and wherein the second asphaltene content of the second heavy oil is less than 95 wt. % of the first asphaltene content of the first heavy oil.

2. The method of claim 1 , wherein the step of generating the steam chamber comprises injecting the steam into the subterranean reservoir from both the injection tubing and the production tubing.

3. The method of claim 1 , wherein the first asphaltene content of the first heavy oil is greater than 5%.

4. The method of claim 1 , wherein the second heavy oil has an API gravity that is at least 2 API numbers higher than the API gravity of the first heavy oil.

5. The method of claim 1 , wherein the steam injection temperature is in a range from 150°-400° C. and the steam injection pressure is in a range 350-14,000 kPa.

6. The method of claim 1 , wherein the light solvent comprises at least 80 wt. % C3-C5 hydrocarbons.

7. The method of claim 1 , wherein the additional steam and the light solvent are supplied to the steam chamber using a first injection tubing, and the liquid phase additive is supplied to the near wellbore region of the steam chamber using a second injection tubing.

8. The method of claim 1 , further comprising producing the second heavy oil, liquid water, light solvent and asphaltene-enriched additive from the steam chamber.

9. The method of claim 1 , further comprising:
injecting the additional steam and the vapor phase light solvent into the steam chamber at the predetermined steam injection temperature and the predetermined steam injection pressure to maintain the additional steam and the light solvent as vapors; and producing the second heavy oil from the reservoir; and
continuing to inject the additional steam and the liquid phase additive, without additional injection of the light solvent, into the steam chamber at conditions sufficient to maintain the additive as a liquid and for a time sufficient to increase production rate of the second heavy oil from the reservoir.

10. The method of claim 9 , further comprising injecting the additional steam and the vapor phase light solvent at a first steam rate, and thereafter injecting the additional steam in combination with the liquid phase additive at a second steam rate, wherein the second steam rate is less than the first steam rate.

11. The method of claim 1 , wherein the liquid phase additive is injected into the steam chamber at a temperature in a range from 150°-400° C. and at a pressure in a range from 350-14,000 kPa.

12. The method of claim 1 , further comprising determining a base pressure differential between the injection tubing and the production tubing before provision of the liquid phase additive to the steam chamber, and providing the liquid phase additive to the steam chamber at a rate sufficient to maintain a pressure differential between the injection tubing and the production tubing of less than 1000 kPa higher than the base pressure differential.

13. The method of claim 1 , wherein the liquid phase additive comprises a base fluid and at least one dispersing agent.

14. The method of claim 13 , wherein the base fluid is selected from the group consisting of a jet fuel boiling range fraction and a diesel fuel boiling range fraction.

15. The method of claim 13 , wherein the base fluid comprises in a range from 60-100 wt. % aromatics.

16. The method of claim 13 , wherein the liquid phase additive comprises an average dispersing agent content of 1-30,000 ppm.

17. The method of claim 13 , wherein the at least one dispersing agent is selected from the group consisting of polyolefin amides, alkyl magnesium sulfonates, succinyl-amines with alkyl and aryl substituents, alkyl aryl phosphonic acids, alkylated polycondensed aromatics, alkylaromatics, alkylaryl sulfonic acids, phosphoric esters, phosphonocarboxylic acids, sarcosinates, ethercarboxylic acids, aminoalkylenecarboxylic acids, alkylphenols, ethoxylates of alkylphenol s, imidazolines, alkylamide-imidazolines, alkylsuccinimides, alkylpyrrolidones, fatty acid amides, ethoxylates of fatty acid amides, fatty esters of polyhydric alcohols, ion-pair salts of imines and organic acids, and ionic liquids.

18. The method of claim 1 , wherein the liquid phase additive provides a liquid level in the near wellbore region for maintaining production of the second heavy oil.

Assignees

• Chevron Usa Inc

Inventors

• Benson Ian Phillip
• Ovalles Cesar Francisco

Classifications

• E21B43/2406 Primary

  Steam assisted gravity drainage [SAGD] · CPC title

• C09K8/592

  Compositions used in combination with generated heat, e.g. by steam injection · CPC title