Environmentally acceptable wellbore stability additive

Patent metadata

Field	Value
Publication number	US-12404440-B2
Application number	US-202418751467-A
Country	US
Kind code	B2
Filing date	Jun 24, 2024
Priority date	Jul 11, 2022
Publication date	Sep 2, 2025
Grant date	Sep 2, 2025

Abstract

A treatment fluid can include a base fluid and a stabilizing additive. The stabilizing additive can include a plurality of environmentally acceptable nanoparticles. The particle size distribution of the plurality of nanoparticles can be selected such that the nanoparticles stabilize a wellbore wall of a subterranean formation or form a filtercake to inhibit or prevent fluid loss into permeable areas of the formation. The plurality of nanoparticles can have a particle size distribution of a d10 value in the range of 20 to 45 nanometers, a d50 value in the range of 40 to 80 nanometers, and a d90 value in the range of 80 to 140 nanometers. The plurality of nanoparticles can also be coated with a polymeric shell. The treatment fluid can be used in an oil and gas operation.

First claim

What is claimed is:

1. A method of treating a portion of a subterranean formation comprising:
introducing a treatment fluid into the subterranean formation, wherein the treatment fluid is a drilling fluid that comprises:
a base fluid; and
a stabilizing additive, wherein the stabilizing additive comprises a plurality of nanoparticles, wherein the plurality of nanoparticles has a particle size distribution of a d10 value in a range of 20 to 45 nanometers, a d50 value in a range of 40 to 80 nanometers, and a d90 value in a range of 80 to 140 nanometers, and wherein the plurality of nanoparticles are made from inorganic materials selected from the group consisting of amorphous or crystalline silica, barite, iron oxide, titanium oxide, calcium carbonate, and combinations thereof; and

causing or allowing the plurality of nanoparticles to stabilize and reduce fluid loss into permeable areas of the subterranean formation.

2. The method according to claim 1 , wherein the treatment fluid forms a filtercake on a wellbore wall of a subterranean formation or seals exposed surfaces of the subterranean formation.

3. The method according to claim 1 , wherein the plurality of nanoparticles has a particle size distribution of a d10 value in a range of 30 to 45 nm, a d50 value in a range of 50 to 80 nm, and a d90 value in a range of 80 to 130 nm.

4. The method according to claim 1 , wherein the stabilizing additive is environmentally acceptable.

5. The method according to claim 1 , wherein the stabilizing additive further comprises a polymeric shell that wholly or partially surrounds the plurality of nanoparticles.

6. The method according to claim 5 , wherein the polymer of the polymeric shell is selected from polyesters, polyamides, carrageenan, pectin, alginate, carboxymethylcellulose, guar, carboxymethyl hydroxypropyl guar, carboxymethyl hydroxyethyl guar, xanthan, diutan, carboxymethylhydroxylcellulose, carboxymethyl starch, hydroxypropyl starch, scleroglucan, welan gum, rhamzan, succinoglycan, polyglycolide, polycaprolactone, polybutylene succinate, chitosan, chitin, galactomannan, B-glucans, xylan, mannans, polyvinyl alcohol (PVA), inulin, starch, cellulose, guar gum, hydroxyethyl cellulose, hydroxypropyl guar gum, lignin, lignite, polysaccharides containing glucose, mannose, and glucuronic acid units, sodium carboxymethylcellulose, sodium lignosulfonate, whey, xanthan gum, or hydroxypropylated cross-linked corn starch.

7. The method according to claim 5 , wherein the polymeric shell increases a thermal stability, alters the wettability, or prevents aggregation of the plurality of environmentally acceptable nanoparticles, or protects the plurality of environmentally acceptable nanoparticles against contaminants in the treatment fluid or a reservoir fluid.

8. The method according to claim 5 , wherein the polymeric shell has tackifying properties.

9. The method according to claim 5 , wherein the plurality of nanoparticles are coated with the polymeric shell prior to introduction of the treatment fluid into the subterranean formation.

10. The method according to claim 1 , wherein the treatment fluid further comprises a polymer, and wherein the polymer wholly or partially coats the plurality of nanoparticles in situ during introduction of the treatment fluid into the subterranean formation.

11. The method according to claim 1 , wherein the subterranean formation is a water-sensitive subterranean formation.

12. The method according to claim 1 , wherein the treatment fluid has a total filtrate loss of less than 50 milliliters using a particle plugging test with a disk having 12 micrometer pores at testing conditions of a pressure differential of 1,200 psi (8.3 megapascals) and a temperature of 180° F. (82.2° C.).

13. The method according to claim 1 , wherein the treatment fluid has an API spurt loss of less than 5 milliliters using a particle plugging test with a disk having 12 micrometer pores at testing conditions of a pressure differential of 1,200 psi (8.3 megapascals) and a temperature of 180° F. (82.2° C.).

14. The method according to claim 1 , wherein the stabilizing additive is added to the base fluid of the treatment fluid in neat form as a dry powder.

15. The method according to claim 1 , wherein the stabilizing additive is added to the base fluid of the treatment fluid as a suspension.

16. The method according to claim 15 , wherein the suspension comprises an environmentally acceptable suspension fluid.

17. The method according to claim 16 , wherein the environmentally acceptable suspension fluid is selected from the group consisting of an ester of fatty acids, vegetable oils, fish oils, seed oils, and combinations thereof.

18. The method according to claim 1 , wherein the stabilizing additive is inherently or readily biodegradable.

19. The method according to claim 1 , wherein the treatment fluid has a plastic viscosity in the range of 10 to 90 centipoise at a temperature of 120° F. (48.9° C.).

20. The method according to claim 1 , wherein the treatment fluid is used in an offshore operation.

Assignees

• Halliburton Energy Services Inc

Inventors

• Deville Jay
• May Preston
• Miller Jeffrey J
• Castanares Miren Aranzazu
• Shumway William W

Classifications

• E21B43/16

  Enhanced recovery methods for obtaining hydrocarbons · CPC title

• E21B43/26

  by forming crevices or fractures · CPC title

• C09K2208/10

  Nanoparticle-containing well treatment fluids · CPC title

• C09K8/516

  characterised by their form or by the form of their components, e.g. encapsulated material · CPC title

• C09K8/514

  of natural origin, e.g. polysaccharides, cellulose (C09K8/512 takes precedence) · CPC title