Methods of Treating Wellbores with Recyclable Fluids

• US 20070215355A1
• Filed: 08/16/2006
• Published: 09/20/2007
• Est. Priority Date: 03/20/2006
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (SLB)
• Original Assignee: Schlumberger Technology Corporation (SLB)
• Inventors: Schuurman, Rene, Pena, Alejandro, Lungwitz, Bernhard, Shapovalov, Alexander
• Granted Patent: US 7,776,796 B2
• Time in Patent Office: Days
• US Class Current: 166/305.100
• CPC Class Codes: C09K 8/52 Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
• CPC Class Codes: C09K 8/90 of natural origin, e.g. polysaccharides, cellulose
• CPC Class Codes: Y10S 507/927 Well cleaning fluid

Abstract

Methods for treating wellbores using fluids containing a sphingan heteropolysaccharide which contributes viscosity stability and a decrease in friction pressure. Some methods are clean-out operations using recyclable-viscosity fluids containing at least a sphingan heteropolysaccharide and an optional salt. Others include methods of pumping fluids incorporating sphingan heteropolysaccharides to reduce pumping frictional pressure.

Claims

1. A method of performing wellbore cleanout operation comprising:

a. preparing and injecting into a wellbore an aqueous fluid comprising a sphingan heteropolysaccharide;

b. entraining wellbore fill material in the aqueous fluid;

c. recovering at the surface at least a portion of the fluid and the entrained wellbore fill material for substantial separation of the wellbore fill material from the fluid; and

d. injecting the portion of the fluid into the wellbore for a second cycle;

wherein no significant replenishment of the sphingan heteropolysaccharide is required.

2. The method of claim 1 further comprising de-gassing of the fluid upon recovering the fluid at the surface.

3. The method of claim 1 further comprising substantially removing organic materials from the fluid recovered at the surface.

4. The method of claim 1 wherein the heteropolysaccharide is selected from the group consisting of gellan gum and gellan gum derivatives, welan gum and welan gum derivatives, diutan gum and diutan gum derivatives, rhamsan gum and rhamsan gum derivatives, polysaccharide S-8 and polysaccharide S-8 derivatives, polysaccharide S-88 and polysaccharide S-88 derivatives, polysaccharide S-198 and polysaccharide S-198 derivatives, polysaccharide S-657 and polysaccharide S-657 derivatives, polysaccharide NW11 and polysaccharide NW11 derivatives, and any mixtures thereof.

5. The method of claim 1 wherein the sphingan heteropolysaccharide is a heteropolysaccharide with a tetrasaccharide repeating unit in the polymer backbone as represented by the chemical formula:

6. The method of claim 5 wherein the sphingan heteropolysaccharide is diutan gum having a tetrasaccharide repeating unit in the polymer backbone as represented by the chemical formula:

7. The method of claim 1 wherein the sphingan heteropolysaccharide is incorporated in an amount from about 0.1% to about 2.0% by weight of total liquid phase weight.

8. The method of claim 7 wherein the sphingan heteropolysaccharide is incorporated in an amount from about 0.2% to about 1.0% by weight of total liquid phase weight.

9. The method of claim 1, the fluid further comprising an electrolyte selected from the group consisting of organic acids, organic acid salts, inorganic salts, and combinations of one or more organic acids or organic acid salts with one or more inorganic salts, and the electrolyte is incorporated in an amount of from about 2% to about 240% weight-to-volume ratio.

10. The method of claim 9 wherein the electrolyte is sodium bromide and is incorporated in an amount of from about 10% to about 80% weight-to-volume ratio.

11. The method of claim 9 wherein the electrolyte is cesium formate and is incorporated in an amount of from about 80% to about 240% weight-to-volume ratio.

12. The method of claim 1 wherein the fluid further comprises a gas component.

13. The method of claim 12 wherein the gas component is nitrogen.

14. The method of claim 12 wherein the gas component comprises from about 10% to about 90% of total fluid volume percent, preferably from about 30% to about 80% of total fluid volume percent, and more preferably from about 40% to about 70% of total fluid volume percent.

15. The method of claim 1, the fluid further comprising an organoamino compound.

16. The method of claim 15 wherein the organoamino compound is selected from the group consisting of tetraethylenepentamine, triethylenetetramine, pentaethylenhexamine, triethanolamine, and any mixtures thereof, and the organoamino compound is incorporated in an amount from about 0.01 wt % to about 2.0 wt % based on total liquid phase weight, and preferably in an amount from about 0.05 wt % to about 1.0 wt % based on total liquid phase weight.

17. The method of claim 1, the fluid having a density from about 1.0 to about 2.3 kg/l.

18. The method of claim 17, the fluid having a density from about 1.1 to about 2.1 kg/l.

19. The method of claim 18, the fluid having a density from about 1.3 to about 1.9 kg/l.

20. The method of claim 1 further comprising:

e. entraining wellbore fill material in the aqueous fluid after injecting the portion of the fluid into the wellbore for a second cycle;

f. recovering at the surface at least a portion of the fluid injected into the wellbore for a second cycle with entrained wellbore fill material for substantial separation of the wellbore fill material from the fluid injected into the wellbore for a second cycle; and

g. injecting the portion of the fluid recovered in step f. into the wellbore for a third cycle;

wherein no significant replenishment of the heteropolysaccharide is required.

21. The method of claim 20 further comprising:

h. entraining wellbore fill material in the aqueous fluid after injecting the portion of the fluid into the wellbore for a third cycle;

i. recovering at the surface at least a portion of the fluid injected into the wellbore for a third cycle with entrained wellbore fill material for substantial separation of the wellbore fill material from the fluid injected into the wellbore for a third cycle; and

j. injecting the portion of the fluid recovered in step i. into the wellbore for a fourth cycle;

wherein no significant replenishment of the heteropolysaccharide is required.

22. A method of treating a wellbore comprising:

a. preparing and injecting into a wellbore, an aqueous fluid comprising a sphingan heteropolysaccharide;

b. recovering at the surface at least a portion of the fluid; and

c. injecting the portion of the fluid into the wellbore for a second cycle;

wherein no significant replenishment of the heteropolysaccharide is required.

23. The method of claim 22 further comprising:

d. treating the wellbore after injecting the portion of the fluid into the wellbore for a second cycle;

e. recovering at the surface at least a portion of the fluid injected into the wellbore for a second cycle; and

f. injecting the portion of the fluid recovered in step e. into the wellbore for a third cycle;

wherein no significant replenishment of the heteropolysaccharide is required.

24. The method of claim 22 as used in wellbore cleanout operations.

25. The method of claim 22 as used in drilling, drill-in, displacement, completion, hydraulic fracturing, work-over, packer fluid emplacement, maintenance, well treating, testing, or abandonment operations.

26. A method of reducing frictional pressure of a fluid composition pumped through a tube by incorporation of a sphingan heteropolysaccharide as a component of the fluid composition.

27. The method of claim 26 wherein the tube is a component of a coiled tubing unit.

28. The method of claim 27 wherein pumping flowrate of the fluid is about 9.5 m³/h or greater.

29. The method of claim 27 wherein the outer diameter of the tube is about 4.5 cm or less.