Drilling Fluids Having Reduced Sag Potential and Related Methods

• US 20120165231A1
• Filed: 12/23/2010
• Published: 06/28/2012
• Est. Priority Date: 12/23/2010
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Jamison, Dale, Miller, Jeffrey James, Braley, Nicholas, Siems, Donald R., Baker, Patrick Chris
• Granted Patent: US 8,476,201 B2
• Time in Patent Office: Days
• US Class Current: 507/143
• CPC Class Codes: C09K 8/03 Specific additives for general use in well-drilling compositions
• CPC Class Codes: C09K 8/05 containing inorganic compounds only, e.g. mixtures of clay and salt
• CPC Class Codes: C09K 8/36 Water-in-oil emulsions

Abstract

Invert emulsion drilling fluids that have extended emulsion stability and reduced sag potential are described herein. The drilling fluids comprise an invert emulsion, a weighting agent, and a plurality of colloidal particles. The invert emulsion comprises an oleaginous fluid continuous phase, an aqueous fluid internal phase, and a surfactant. At least a portion of the plurality of colloidal particles interact with the surfactant to form an associative supporting structure that inhibits sag of the weighting agent. In some embodiments, the weighting agent comprises barite particles, particularly barite particles that are less than about 45 μm in size. Methods for placing the invert emulsion drilling fluids in a subterranean formation via a wellbore are also disclosed.

Claims

1. A method comprising:

providing a drilling fluid that comprises;

an invert emulsion, the invert emulsion comprising an oleaginous fluid continuous phase, an aqueous fluid internal phase, and a surfactant;

a weighting agent; and

a plurality of colloidal particles;

wherein at least a portion of the plurality of colloidal particles interact with the surfactant to form an associative supporting structure that inhibits sag of the weighting agent; and

placing the drilling fluid in a subterranean formation via a wellbore penetrating the subterranean formation.

2. The method of claim 1, wherein the weighting agent comprises barite particles.

3. The method of claim 2, wherein the barite particles are less than about 45 microns in size.

4. The method of claim 1, wherein the colloidal particles have an average size between about 0.5 microns and about 5 microns.

5. The method of claim 1, wherein the colloidal particles are less than about 2 microns in size.

6. The method of claim 1, wherein the drilling fluid has a density that changes by less than about 5% over at least about 62 hours of static aging.

7. The method of claim 1, wherein the plurality of colloidal particles comprise at least one type of colloidal particle selected from the group consisting of a ground mineral, a zeolite particle, a sepiolite particle, an attapulgite particle, an illite particle, a montmorillonite particle, a non-organophilic clay particle, a bentonite particle, a quartz particle, a calcium carbonate particle, a silica flour particle, a calcium hydroxide particle, a magnesium hydroxide particle, an alumoxane particle, a carbon nanotube, a fullerene, graphite, a graphene, graphite oxide, a particle comprising a fibrous material, a metal nanoparticle, a metal nanorod, a metal nanosphere, a metal nanoplatelet, a non-metal nanoparticle, a non-metal nanorod, a non-metal nanosphere, a non-metal nanoplatelet, a metal oxide nanoparticle, a metal oxide nanorod, a metal oxide nanosphere, a metal oxide nanoplatelet, a hollow microsphere, a hollow nanosphere, a glass sphere, and combinations thereof

8. The method of claim 1, wherein at least a portion of the plurality of colloidal particles comprises calcium carbonate.

9. The method of claim 1, wherein the weighting agent comprises at least one weighting agent selected from the group consisting of hematite, magnetite, iron oxides, illmenite, siderite, celestite, dolomite, olivine, calcite, magnesium oxides, magnesium tetraoxide, halites, calcium carbonate, and strontium sulfate.

10. A method comprising:

providing a drilling fluid that is free of organophilic clays and comprises;

an invert emulsion, the invert emulsion comprising an oleaginous fluid continuous phase, an aqueous fluid internal phase, and a surfactant;

barite particles having a size of at most about 45 microns; and

a plurality of colloidal particles;

wherein the drilling fluid has a density that changes by less than about 5% over at least about 62 hours of static aging; and

drilling a wellbore in a subterranean formation using the drilling fluid.

11. The method of claim 10, wherein at least a portion of the plurality of colloidal particles comprises calcium carbonate.

12. The method of claim 10, wherein the drilling fluid has a sag rate of at most about 5 mm/hr.

13. A method comprising:

providing a drilling fluid that is free of organophilic clays and comprises;

an invert emulsion, the invert emulsion comprising an oleaginous fluid continuous phase, an aqueous fluid internal phase, and a surfactant;

barite particles having a size of at most about 45 microns; and

a plurality of colloidal particles;

wherein at least a portion of the plurality of the colloidal particles interact with the surfactant to form an associative supporting structure that inhibits sag of the barite particles; and

drilling a wellbore in a subterranean formation using the drilling fluid.

14. The method of claim 13, wherein the drilling fluid has a density that changes by less than about 5% over at least about 62 hours of static aging.

15. The method of claim 13, wherein at least a portion of the plurality of colloidal particles comprises calcium carbonate.

16. The method of claim 13, wherein the drilling fluid has a sag rate of at most about 5 mm/hr.

17. An organophilic clay-free drilling fluid comprising:

an oleaginous fluid continuous phase;

an aqueous fluid internal phase;

a surfactant;

barite particles; and

a plurality of colloidal particles;

wherein the drilling fluid has a density that changes by less than about 5% over at least about 62 hours of static aging.

18. The organophilic clay-free drilling fluid of claim 17, wherein the drilling fluid has a sag rate of at most about 5 mm/hr.

19. The organophilic clay-free drilling fluid of claim 17, wherein at least a portion of the plurality of colloidal particles comprises calcium carbonate.

20. The organophilic clay-free drilling fluid of claim 17, wherein the barite particles are less than about 45 microns in size.

21. An organophilic clay-free drilling fluid comprising:

an oleaginous fluid continuous phase;

an aqueous fluid internal phase;

a surfactant;

a weighting agent; and

a plurality of colloidal particles;

wherein at least a portion of the plurality of colloidal particles interact with the surfactant to form an associative supporting structure that inhibits sag of the weighting agent.

22. The organophilic clay-free drilling fluid of claim 21, wherein at least a portion of the plurality of colloidal particles comprises calcium carbonate.

23. The organophilic clay-free drilling fluid of claim 21, wherein the weighting agent comprises barite particles that are less than about 45 microns in size.