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

• US 9,428,683 B2
• Filed: 03/14/2013
• Issued: 08/30/2016
• Est. Priority Date: 03/14/2013
• Status: Active Grant

• Current Assignee: Flotek Industries Incorporated
• Original Assignee: Flotek Industries Incorporated
• Inventors: Hill, Randal M., Champagne, Lakia M., Lett, Nathan L., Green, Maria Elizabeth, Saboowala, Hasnain
• Primary Examiner(s): DiTrani, Angela M
• Assistant Examiner(s): Miller, Crystal J
• Application Number:
  US13/829,495
• Publication Number:
  US 20140262261A1
• Time in Patent Office: 1,265 Days
• US Class Current: 1/1
• 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 8/92 characterised by their form or by the form of their components, e.g. encapsulated material C09K8/70 takes precedence
• CPC Class Codes: E21B 43/16 Enhanced recovery methods for obtaining hydrocarbons
• CPC Class Codes: E21B 43/26 by forming crevices or fractures

Abstract

Methods and compositions for stimulating of the production of hydrocarbons (e.g., formation crude oil and/or formation gas) from subterranean formations, and methods of selecting a composition for treating an oil or gas well. In some embodiments, the compositions are emulsions or microemulsions, which may include water, a terpene, and a surfactant.

Claims

1. A method comprising:

selecting an emulsion or a microemulsion composition for injection into a wellbore of a well based on a determination of whether formation crude oil is produced or whether formation gas is produced by the well,

wherein, when formation crude oil is produced by the well, the emulsion or the microemulsion composition is selected to comprise a terpene having a phase inversion temperature greater than 43°

C., water, and a surfactant and the ratio of water to terpene is between about 3;

1 and about 1;

2; and

wherein, when formation gas is produced by the well, the emulsion or the microemulsion is selected to comprise a terpene having a phase inversion temperature less than 43°

C., water and a surfactant, and the ratio of water to terpene is between about 3;

1 and about 1;

2; and

injecting the emulsion or the microemulsion into the wellbore.

2. The method of claim 1, further comprising injecting the emulsion or the microemulsion into the wellbore to increase production of formation crude oil or formation gas by the well.

3. The method of claim 1, wherein the ratio of water to terpene is about 1:

1.

4. The method of claim 1, wherein the terpene is selected from the group consisting of linalool, geraniol, nopol, α

-terpineol, menthol, eucalyptol, menthone, d-limonene, terpinolene, β

-ocimene, γ

-terpinene, α

-pinene, and citronellene.

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

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

7. 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.

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

9. The method of claim 8, wherein the emulsion or the microemulsion is diluted to between about 0.1 wt % and about 2 wt %.

10. The method of claim 8, wherein the emulsion or the microemulsion is diluted to between about 0.2 wt % and about 0.4 wt %.

11. The method of claim 8, wherein the emulsion or the microemulsion is diluted with water or brine.

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

13. The method of claim 12, wherein the emulsion or the microemulsion comprises a first type of freezing point depression agent and a second type of freezing point depression agent.

14. The method of claim 12, wherein the freezing point depression agent comprises an alkylene glycol, an alcohol, and/or a salt.

15. The method of claim 12, wherein the freezing point depression agent is present in an amount between about 5 wt % and about 40 wt %.

16. The method of claim 12, wherein the surfactant is present in an amount between about 15 wt % and 55 wt %.