Submicron particles surfactant method for improved oil recovery from subterranean reservoirs

• US 9,725,640 B2
• Filed: 04/12/2013
• Issued: 08/08/2017
• Est. Priority Date: 04/12/2012
• Status: Active Grant

• Current Assignee: ChemEOR, Inc.
• Original Assignee: ChemEOR, Inc.
• Inventors: Tang, Hongxin, Lu, Zayne Hai
• Primary Examiner(s): Hutton, Jr., Doug
• Assistant Examiner(s): VARMA, ASHISH K
• Application Number:
  US13/986,229
• Publication Number:
  US 20140305649A1
• Time in Patent Office: 1,579 Days
• Field of Search: 1663082
• CPC Class Codes: C09K 2208/10 Nanoparticle-containing well treatment fluids
• CPC Class Codes: C09K 8/584 characterised by the use of specific surfactants
• CPC Class Codes: C09K 8/602 containing surfactants
• CPC Class Codes: C09K 8/70 characterised by their form or by the form of their components, e.g. foams

Abstract

Methods of stimulating a well comprising providing a stimulation fluid comprising at least one surfactant and submicron particles, the submicron particles having a particle size between about 200 nm and about 800 nm and a specific surface area greater than about 5 square meters per gram; and introducing the stimulation fluid into a wellbore. Additional methods to enhance oil recovery from subterranean reservoirs accessible via a well are described.

Claims

1. A method of stimulating a well comprising:

i) forming a stimulation fluid comprising;

at least one surfactant; and

submicron fumed silica particles having a particle size greater than 200 nm and up to 800 nm and a specific surface area greater than about 5 square meters per gram, wherein the stimulation fluid changes a wettability of a reservoir matrix, and wherein the submicron fumed silica particles contributes to said change; and

ii) introducing the stimulation fluid into a wellbore in contact with the reservoir matrix,

whereby the well is stimulated to improve its hydrocarbon production due in part to the wettability change.

2. The method of claim 1, wherein the stimulation fluid is defined by properties comprising at least one of the following features:

(a) the ability to lower an oil and water interfacial tension between oil and water in the reservoir;

(b) the ability to enhance a mobility or a spreading of hydrocarbons out of the porous matrix portion of the reservoir;

or

(c) the ability to enhance compatibility with chemicals in other well treatment processes that can be performed on the well.

3. The method of claim 1, wherein the surfactant is selected from the group consisting of ethoxylated alkylphenols, ethoxysulfate alkylphenols, ethoxylated alcohols, ethoxysulfate alcohols, ethoxylated amines, ethoxylated amides, alpha olefin sulfonates, internal olefin sulfonates, alkyl aryl sulfonates, petroleum sulfonates, propoxylated ethoxylated alcohols, propoxylated ethoxylated sulfates, propoxylated ethoxylated sulfonates, propoxylated ethoxylated amines, propoxylated ethoxylated amides, alkyl polyglycosides, amine salts, ammonium salts, and mixtures thereof, including primary amines.

4. The method of claim 1, wherein the well is in fluid communication with a subterranean formation comprising a fractured reservoir.

5. The method of claim 1, further comprising introducing a hydraulic fracturing compound into the well to synthetically fracture a reservoir that is in fluid communication with the well, either simultaneously or in sequence with introducing the stimulation fluid.

6. The method of claim 1, wherein the stimulation fluid further comprises urea.

7. The method of claim 1, wherein the introducing step is modified by first combining the submicron fumed silica particles with dry treatment additives to be introduced into the well to fashion a dry mixture, such that when said mixture meets any of a second fluid that is separately introduced, the second fluid being a diluent of the surfactant, the surfactant, or a treatment fluid distinct from the stimulation fluid, the stimulation fluid is provided and introduced.

8. The method of claim 1, wherein the surfactant comprises a biosurfactant.

9. The method of claim 8, wherein the biosurfactant comprises a glycolipid or a lipopeptide.

10. The method of claim 1, wherein the fumed silica particles have a particle size distribution in the range of between 200 nm to 300 nm and a specific surface area of approximately 200 square meters per gram.

11. A method to enhance oil recovery from a subterranean reservoir, the reservoir being accessible via a well, the method comprising:

injecting a treatment fluid comprising submicron fumed silica particles and at least one surfactant into the well, wherein the submicron fumed silica particles have a particle size greater than 200 nm and up to 800 nm and a specific surface area greater than about 5 square meters per gram, wherein the treatment fluid changes a wettability of a reservoir matrix, and wherein the submicron fumed silica particles contribute to said change; and

injecting a well-servicing volumetric solution into the well to perform a second well treatment process, wherein the second well treatment process is selected from the group consisting of a scale inhibition squeeze process, a well acidizing process, a chemical process to reduce water production rate, an acid fracturing process, and a hydraulic fracturing process,

wherein the treatment fluid and the well-servicing volumetric solution are injected into the well within less than about 21 days of one another.

12. The method of claim 11, wherein the submicron fumed silica particles have a particle size greater than 200 nm and up to 300 nm.

13. The method of claim 11, wherein the submicron fumed silica particles have a specific surface area greater than about 150 square meters per gram.

14. The method of claim 11, wherein the treatment fluid is defined by properties comprising at least one of the following features:

(a) the ability to lower an oil and water interfacial tension between oil and water in the reservoir;

(b) the ability to enhance a mobility or a spreading of hydrocarbons out of the porous matrix portion of the reservoir;

or

(c) the ability to enhance compatibility with chemicals in the second well treatment process.

15. The method of claim 11, wherein the surfactant is selected from the group consisting of ethoxylated alkylphenols, ethoxysulfate alkylphenols, ethoxylated alcohols, ethoxysulfate alcohols, ethoxylated amines, ethoxylated amides, alpha olefin sulfonates, internal olefin sulfonates, alkyl aryl sulfonates, petroleum sulfonates, propoxylated ethoxylated alcohols, propoxylated ethoxylated sulfates, propoxylated ethoxylated sulfonates, propoxylated ethoxylated amines, propoxylated ethoxylated amides, alkyl polyglycosides, amine salts, ammonium salts, and mixtures thereof, including primary amines.

16. The method of claim 11, wherein the subterranean formation is a fractured reservoir.

17. The method of claim 11, further comprising introducing a hydraulic fracturing compound into the well to synthetically fracture the reservoir, either simultaneously or in sequence with introducing the treatment fluid.

18. The method of claim 11, wherein the treatment fluid further comprises urea.

19. The method of claim 11, further comprising, prior to injecting the treatment fluid, combining the submicron fumed silica particles with dry treatment additives to be introduced into the well to fashion a dry mixture, such that when said mixture meets any of a fluid that is separately introduced, the fluid being a diluent of the surfactant, the surfactant, the second well treatment solution, or a treatment fluid distinct from either the treatment fluid or the second well treatment solution, the treatment fluid is formed.

20. The method of claim 11, wherein the surfactant comprises a biosurfactant.

21. The method of claim 20, wherein the biosurfactant comprises a glycolipid or a lipopeptide.

22. The method of claim 11, wherein the submicron fumed silica particles are present in the treatment fluid in an amount in a range of from about 0.00004% to about 0.1% by weight based on the total weight of the treatment fluid.

23. The method of claim 11, wherein the submicron fumed silica particles are present in a pre-diluted dispersion in an amount in a range of from about 0.1% to about 30% by weight based on the total weight of said pre-diluted dispersion.

24. The method of claim 11, further comprising injecting a spacer slug comprising fresh water brine and a hydrocarbon.

25. The method of claim 11, further comprising adding to the well-servicing volumetric solution at least one of a portion of the treatment fluid, or a second surfactant selected to increase the oil-to-water ratio of oil recovery from the porous matrix portion of the reservoir.

26. The method of claim 11, further comprising:

(a) halting fluid production from the well;

(b) simultaneously injecting the well-servicing volumetric solution and the treatment fluid into the well;

(c) shutting in the well for a soaking period of time; and

(d) returning the well to production to recover additional oil from the reservoir.

27. The method of claim 26, further comprising, between steps (b) and (c), injecting a spacer slug of inert fluid into either a production or injection well.

28. The method of claim 11, wherein the treatment fluid and the well-servicing volumetric solution are injected into the well within less than about thirty days of one another.

29. A method to enhance oil recovery from a subterranean reservoir, the reservoir being accessible via a well, the method comprising:

forming an EOR injection fluid comprising submicron fumed silica particles and at least one surfactant into the well, wherein the submicron fumed silica particles have a particle size greater than 200 nm and up to 800 nm and a specific surface area greater than about 5 square meters per gram, wherein the EOR injection fluid changes a wettability of a reservoir matrix, and wherein the submicron fumed silica particles contribute to said change; and

introducing the EOR injection fluid into the reservoir via the well,

whereby hydrocarbon production from the reservoir is enhanced due in part to the wettability change.