Preflush chemicals for scale inhibitor squeeze

Patent metadata

Field	Value
Publication number	US-10550308-B2
Application number	US-201816159585-A
Country	US
Kind code	B2
Filing date	Oct 12, 2018
Priority date	Mar 11, 2016
Publication date	Feb 4, 2020
Grant date	Feb 4, 2020

Abstract

A method and system for removing water from the near wellbore during scale inhibitor squeeze treatments.

First claim

The invention claimed is:

1. An improved method of scale inhibitor squeeze treatment, said treatment comprising injecting a scale inhibitor into a wellbore, injecting a push solution into said wellbore, shutting said well in for a period of time, and opening said well for flowback of said injected fluids and subsequent production of oil, the improvement comprising injecting a preflush solution into said wellbore before injecting a scale inhibitor into said wellbore, wherein said preflush solution comprises at least 90 volume percent petroleum miscible fluid, at least 1 volume percent alkyl polyglycoside (APG), at least 0.5 volume percent ethoxylated alcohol (EA) or alcohol ethoxysulfates (AES), and at least 1 volume percent linear alcohol, wherein said preflush solution is capable of forming a Winsor Type III or Type IV microemulsion with water, and wherein increased oil production is achieved by said method as compared with a similar method in a similar wellbore but not using said preflush solution.

2. The method of claim 1 , wherein said alkyl polyglycosides are C10-C14 alkyl polyglucosides, said ethoxylated alcohols are C9-C15 with an average of about 12 ethylene oxide groups, and said alcohols are about C6-C12.

3. The method of claim 1 , wherein said preflush solution comprises 94.28% diesel, 2.51% GLUCOPON® 600 CSUP, 1.09% TOMADOL® 91-2.5, 0.12% TOMADOL® 25-12, 1% n-hexanol, and 1% n-octanol.

4. The method of claim 1 , wherein said preflush solution comprises 92% C8-C14 hydrocarbons; 3% GLUCOPON® 600 UP; 1% TOMADOL® 91-2.5; 2% n-butanol; and 1% n-hexanol.

5. The method of claim 1 , wherein said preflush solution comprises 95% C10-C14 hydrocarbons; 2% TRITON® CG-600; 2% TERGITOL® 15-S-3; 0.5% n-butanol and 0.5% n-hexanol.

6. The method of claim 1 , wherein said APG are C8-C16, said EA or AES are C8-C15 with an average of about 2-14 ethylene oxide groups, and said alcohols are about C4-C15.

7. A scale inhibitor squeeze method for minimizing scaling in a reservoir, comprising:
a) injecting a preflush solution into a wellbore in a reservoir;
b) injecting a scale inhibitor fluid into said wellbore;
c) injecting a push fluid to push the injected scale inhibitor fluid into the reservoir surrounding said wellbore;
d) shutting in said wellbore for a period of time;
e) opening said wellbore for back flow of said push fluid and said scale inhibitor fluid and lastly for back flow of said preflush solution; and
f) producing a hydrocarbon reservoir fluid from said wellbore;
wherein said preflush solution comprises at least 90 vol % petroleum miscible fluid, at least 1 vol % alkyl polyglycoside (APG), at least 0.5 vol % ethoxylated alcohol (EA) or alcohol ethoxysulfates (AES), and at least 1 vol % linear alcohol, and wherein said preflush solution forms a Winsor Type III or Type IV microemulsion with water.

8. The method of claim 7 , wherein said preflush fluid penetrates at least 0.5-5 feet into said reservoir.

9. The method of claim 7 , wherein said preflush fluid penetrates at least 0.5-8 feet into said reservoir.

10. The method of claim 7 , wherein said push fluid comprises brine or hydrocarbon.

11. The method of claim 7 , wherein said push fluid comprises said preflush solution.

12. The method of claim 7 , wherein said preflush solution forms a Type III or Type IV microemulsion with any water left behind from said backflowed push fluid and said scale inhibitor fluid, thus removing said water on backflow of said microemulsion.

13. The method of claim 7 , wherein the rate of production of said hydrocarbon reservoir fluid is at least as good after said method as it was before said method.

14. The method of claim 7 , wherein the rate of production of said hydrocarbon reservoir fluid is improved after said method over what it was before said method.

Assignees

• Conocophillips Co

Inventors

• Blumer David
• Xu Ying
• Mclelland Greg
• WATERS Judy

Classifications

• C09K8/528 Primary

  inorganic depositions, e.g. sulfates or carbonates · CPC title

• E21B37/06

  using chemical means for preventing or limiting {, e.g. eliminating,} the deposition of paraffins or like substances · CPC title