Methods and compositions for stimulating the production of hydrocarbons from subterranean formations

• US 9,321,955 B2
• Filed: 06/14/2013
• Issued: 04/26/2016
• Est. Priority Date: 06/14/2013
• Status: Active Grant

• Current Assignee: Flotek Industries Incorporated
• Original Assignee: Flotek Industries Incorporated
• Inventors: Hill, Randal M., Champagne, Lakia M., Lett, Nathan L., Dismuke, Keith Ingram, Germack, David, Mast, Nicole, Soeung, Melinda
• Primary Examiner(s): Bates, Zakiya W
• Application Number:
  US13/918,155
• Publication Number:
  US 20140367107A1
• Time in Patent Office: 1,047 Days
• US Class Current: 1/1
• CPC Class Codes: C09K 8/26 Oil-in-water emulsions
• CPC Class Codes: C09K 8/40 Spacer compositions, e.g. compositions used to separate well-drilling from cementing masses
• CPC Class Codes: C09K 8/602 containing surfactants
• CPC Class Codes: C09K 8/68 containing organic compounds
• CPC Class Codes: C09K 8/70 characterised by their form or by the form of their components, e.g. foams
• CPC Class Codes: C09K 8/72 Eroding chemicals, e.g. acids
• CPC Class Codes: C09K 8/86 containing organic compounds
• CPC Class Codes: C09K 8/90 of natural origin, e.g. polysaccharides, cellulose
• CPC Class Codes: E21B 43/27 by use of eroding chemicals, e.g. acids

Abstract

Methods for treating an oil or gas well having a wellbore and selecting compositions for treating an oil or gas well having a wellbore.

Claims

1. A method of selecting a composition for treating an oil or gas well having a wellbore, comprising:

determining whether displacement of residual aqueous treatment fluid by formation crude oil or displacement of residual aqueous treatment fluid by formation gas is preferentially stimulated for the oil or gas well having a wellbore; and

selecting an emulsion or a microemulsion for injection into the wellbore to increase formation crude oil or formation gas production by the well, wherein the emulsion or the microemulsion comprises water, a first type of solvent, a second type of solvent and a surfactant,

wherein the first type of solvent and the second type of solvent are different and are selected from the group consisting of cyclic or acyclic, branched or unbranched alkanes having 8 carbon atoms and substituted with only an —

OH group and aromatic solvents having a boiling point between about 175-300°

F., when displacement of residual aqueous treatment fluid by formation gas is preferentially stimulated.

2. The method of claim 1, wherein the ratio of water to solvent is between about 15:

1 and 1;

10, or between 9;

1 and 1;

4, or between 3.2;

1 to 1;

4.

3. The method of claim 1, wherein the emulsion or the microemulsion is diluted with an aqueous fluid prior to injection to the wellbore.

4. The method of claim 3, wherein the emulsion or the microemulsion is diluted to between about 0.1 wt % and about 2 wt %.

5. The method of claim 3, wherein the emulsion or the microemulsion is diluted to between about 0.2 wt % and about 0.4 wt %.

6. The method of claim 3, wherein the emulsion or the microemulsion is diluted with water, brine, or a well-treatment fluid.

7. The method of claim 6, wherein the well-treatment fluid is an acid, a fracturing fluid, or slickwater.

8. The method of claim 1, wherein the emulsion or the microemulsion further comprises a freezing point depression agent.

9. The method of claim 8, wherein the emulsion or the microemulsion comprises a first type of freezing point depression agent and a second type of freezing point depression agent.

10. The method of claim 8, wherein the freezing point depression agent comprises an alkylene glycol, an alcohol, a combination of choline chloride and urea, and/or a salt.

11. The method of claim 8, wherein the freezing point depression agent is present in an amount between about 5 wt % and about 40 wt %.

12. The method of claim 1, wherein the emulsion or the microemulsion comprises a first type of surfactant and a second type of surfactant.

13. The method of claim 1, wherein the surfactant is selected from the group consisting of alkyl polyglycol or alkyl polyglucoside nonionic surfactants, or mixtures of said nonionic surfactants with an ionic surfactant comprising anionic, cationic, or zwitterionic surfactants.

14. The method of claim 1, wherein the surfactant is present in an amount between about 15 wt % and 55 wt %.

15. A method of treating an oil or gas well having a wellbore comprising:

injecting an emulsion or a microemulsion into the wellbore of the oil or gas well to stimulate displacement of residual aqueous treatment fluid by formation gas and increase production of formation gas by the well,

wherein the emulsion or the microemulsion comprises water, a first type of solvent, a second type of solvent and a surfactant; and

wherein the first type of solvent and the second type of solvent are different and are selected from the group consisting of cyclic or acyclic, branched or unbranched alkanes having 8 carbon atoms and substituted with only an —

OH group and aromatic solvents having a boiling point between about 175-300°

F.

16. The method of claim 15, wherein the ratio of water to solvent is between about 15:

1 and 1;

10, or between 9;

1 and 1;

4, or between 3.2;

1 to 1;

4.

17. The method of claim 15, wherein the emulsion or the microemulsion is diluted with an aqueous fluid prior to injection to the wellbore.

18. The method of claim 15, wherein the emulsion or the microemulsion is diluted to between about 0.1 wt % and about 2 wt %.

19. The method of claim 17, wherein the emulsion or the microemulsion is diluted to between about 0.2 wt % and about 0.4 wt %.

20. The method of claim 17, wherein the emulsion or the microemulsion is diluted with water, brine, or a well-treatment fluid.

21. The method of claim 20, wherein the well-treatment fluid is an acid, a fracturing fluid, or slickwater.

22. The method of claim 15, wherein the emulsion or the microemulsion further comprises a freezing point depression agent.

23. The method of claim 15, wherein the emulsion or the microemulsion comprises a first type of freezing point depression agent and a second type of freezing point depression agent.

24. The method of claim 23, wherein the freezing point depression agent comprises an alkylene glycol, an alcohol, a combination of choline chloride and urea, and/or a salt.

25. The method of claim 23, wherein the freezing point depression agent is present in an amount between about 5 wt % and about 40 wt %.

26. The method of claim 15, wherein the emulsion or the microemulsion comprises a first type of surfactant and a second type of surfactant.

27. The method of claim 15, wherein the surfactant is selected from the group consisting of alkyl polyglycol or alkyl polyglucoside nonionic surfactants, or mixtures of said nonionic surfactants with an ionic surfactant comprising anionic, cationic, or zwitterionic surfactants.

28. The method of claim 15, wherein the surfactant is present in an amount between about 15 wt % and 55 wt %.

29. A method of selecting a composition for treating an oil or gas well having a wellbore, comprising:

determining whether displacement of residual aqueous treatment fluid by formation crude oil or displacement of residual aqueous treatment fluid by formation gas is preferentially stimulated for the oil or gas well having a wellbore; and

selecting an emulsion or a microemulsion for injection into the wellbore to increase formation crude oil or formation gas production by the well, wherein the emulsion or the microemulsion comprises water, at least a first type of solvent, a second type of solvent and a surfactant,

wherein the first type of solvent is selected from the group consisting of unsubstituted cyclic or acyclic, branched or unbranched alkanes having 6-12 carbon atoms, unsubstituted acyclic branched or unbranched alkenes having one or two double bonds and 6-12 carbon atoms, cyclic or acyclic, branched or unbranched alkanes having 9-12 carbon atoms and substituted with only an —

OH group, branched or unbranched dialkylether compounds having the formula C_nH_2n+1OC_mH_2m+1, wherein n+m is between 6 and 16, and aromatic solvents having a boiling point between about 300-400°

F., when displacement of residual aqueous treatment fluid by formation crude oil is preferentially stimulated, and

the second type of solvent is a terpene or terpenoid, when displacement of residual aqueous treatment fluid by formation gas is preferentially stimulated,

wherein the terpene or terpenoid is selected to have a phase inversion temperature greater than 109.4°

F.

30. A method of selecting a composition for treating an oil or gas well having a wellbore, comprising:

determining whether displacement of residual aqueous treatment fluid by formation crude oil or displacement of residual aqueous treatment fluid by formation gas is preferentially stimulated for the oil or gas well having a wellbore; and

selecting an emulsion or a microemulsion for injection into the wellbore to increase formation crude oil or formation gas production by the well, wherein the emulsion or the microemulsion comprises water, at least a first type of solvent, a second type of solvent and a surfactant,

wherein the first type of solvent is selected from the group consisting of cyclic or acyclic, branched or unbranched alkanes having 8 carbon atoms and substituted with an —

OH group and aromatic solvents having a boiling point between about 175-300°

F., and the second type of solvent is a terpene or terpenoid, when displacement of residual aqueous treatment fluid by formation gas is preferentially stimulated,

wherein the terpene or terpenoid is selected to have a phase inversion temperature less than 109.4°

F.