High Density Brine Containing Colloidal Particles

Patent metadata

Field	Value
Publication number	US-2018155602-A1
Application number	US-201615578652-A
Country	US
Kind code	A1
Filing date	May 27, 2016
Priority date	May 30, 2015
Publication date	Jun 7, 2018
Grant date	—

Abstract

A wellbore fluid comprising an aqueous base fluid and a plurality of nanoparticles suspended in the aqueous base fluid. The nanoparticles are present in the wellbore fluid in an amount effective to have an effect of increasing the density by at least 0.2 lb/gal.

First claim

What is claimed:

1 . A wellbore fluid, comprising:
an aqueous base fluid; and a plurality of nanoparticles suspended in the aqueous base fluid, wherein the nanoparticles are present in the wellbore fluid in an amount effective to have an effect of increasing the density by at least 0.2 lb/gal.

2 . The wellbore fluid of claim 1 , wherein the nanoparticles are selected from the group of silica, iron carbonate, iron oxide, titanium oxide, tungsten oxide, zirconium oxide, zirconium silicate.

3 . The wellbore fluid of claim 2 , wherein the silica nanoparticles are selected from the group of colloidal silica nanoparticles and nano-sized precipitated silica.

4 . The wellbore fluid of claim 3 , wherein the silica nanoparticles are coated.

5 . The wellbore fluid of claim 1 , wherein an amount of nanoparticles ranges from about 4 wt % to about 60 wt %.

6 . The wellbore fluid of claim 1 , wherein the aqueous base fluid is selected from the group of alkali metal halides, alkaline earth metal halides, and alkali metal formates.

7 . The wellbore fluid of claim 1 , wherein the wellbore fluid has a viscosity ranging from about 5 cP to about 150 cP at room temperature.

8 . The wellbore fluid of claim 1 , wherein the wellbore fluid has a turbidity ranging from about 10 to about 300 nephelometric turbidity units.

9 . The wellbore fluid of claim 1 , wherein the wellbore fluid has a density in the range of about 11 ppg to about 18 ppg.

10 . The wellbore fluid of claim 1 , further comprising polyvinylpyrrolidone as a crystallization temperature agent.

11 . The wellbore fluid of claim 1 , wherein the wellbore fluid is a drilling fluid and further comprises a gelling agent and a plurality of salt or mineral particulates.

12 . The wellbore fluid of claim 1 , wherein the wellbore fluid is a fluid loss pill and further comprises a gelling agent and a plurality of salt or mineral particulates.

13 . The wellbore fluid of claim 1 , wherein the wellbore fluid is a gravel packing carrier fluid further comprising gravel.

14 . The wellbore fluid of claim 1 , wherein the wellbore fluid is an internal phase of an invert emulsion gravel packing carrier fluid further comprising gravel.

15 . The wellbore fluid of claim 1 , wherein the wellbore fluid is an internal phase of an invert emulsion drilling fluid.

16 . A method for completing a wellbore, the method comprising:
pumping a wellbore fluid into the wellbore, the wellbore fluid comprising:
an aqueous base fluid; and
a plurality of nanoparticles suspended in the aqueous base fluid; and
performing at least one completion operation while the wellbore fluid is in the wellbore.

17 . The method of claim 16 , wherein the nanoparticles are selected from the group of silica, iron carbonate, iron oxide, titanium oxide, tungsten oxide, zirconium oxide, zirconium silicate.

18 . The method of claim 17 , wherein the silica nanoparticles are selected from the group of colloidal silica nanoparticles and nano-sized precipitated silica.

19 . The method of claim 16 , wherein the aqueous base fluid is selected from the group of alkali metal halides, alkaline earth metal halides, an alkali metal formates.

20 . The method of claim 16 , wherein the wellbore fluid has a viscosity ranging from about 5 cP to about 150 cP at room temperature.

21 . The method of claim 16 , wherein the wellbore fluid has a turbidity ranging from about 10 to about 300 nephelometric turbidity units.

22 . The method of claim 16 , further comprising:
mixing the plurality of nanoparticles with the brine at a pH ranging from about 2 to about 10 with the formation of a premix fluid; and removing water from the premix fluid to form the wellbore fluid with a desired density.

23 . The method of claim 22 , wherein removing water is performed by mixing the premix fluid with dry salts with the formation of the wellbore fluid with a desired density.

24 . The method of claim 16 , wherein the wellbore fluid has a density in the range of about 11 ppg to about 18 ppg.

25 . A method comprising:
introducing a wellbore fluid into a wellbore, wherein the wellbore fluid has a turbidity ranging from about 10 to about 300 nephelometric turbidity units.

26 . The method of claim 25 , further comprising:
a wellbore fluid comprising:
an aqueous base fluid; and
a plurality of nanoparticles suspended in the aqueous base fluid, wherein the nanoparticles are selected from the group of silica, iron carbonate, iron oxide, titanium oxide, tungsten oxide, zirconium oxide, zirconium silicate.

Assignees

• Mi Llc

Inventors

• Zhang Hui
• Wei Xia
• Price Hoelscher Brandi Katherine
• Young Steven

Classifications

• C09K8/845

  containing inorganic compounds · CPC title

• C09K8/05 Primary

  containing inorganic compounds only, e.g. mixtures of clay and salt · CPC title

• C09K8/92

  characterised by their form or by the form of their components, e.g. encapsulated material (C09K8/70 takes precedence) · CPC title

• C09K2208/10

  Nanoparticle-containing well treatment fluids · CPC title

• C09K8/5045

  containing inorganic compounds · CPC title