Methods using low concentrations of gas bubbles to hinder proppant settling

Patent metadata

Field	Value
Publication number	US-9328285-B2
Application number	US-41698409-A
Country	US
Kind code	B2
Filing date	Apr 2, 2009
Priority date	Apr 2, 2009
Publication date	May 3, 2016
Grant date	May 3, 2016

Abstract

Methods for reducing settling rates of proppants in fracturing fluids include injecting sufficient gas into the fluid to form bubbles that reduce proppant settling rates. Compositions including proppants made buoyant with gas bubbles.

First claim

We claim:

1. A method for fracturing a formation comprising:
pumping a liquid fracturing fluid into a formation to be fractured at a liquid pressure sufficient to fracture the formation, where the fluid includes a proppant,
during pumping, injecting a gas into the liquid fracturing fluid at a single downhole location and at a gas injection rate below an amount that would convert the fluid into a stable foam, and
changing the gas injection rate to produce a desired gasification profile in the fracturing fluid across the formation to be fractured during fracturing,
where the injecting produces gas microbubbles having an average size between about 10 and about 6000 micron (μm or μ) in the fracturing fluid, where the gasification profile is characterized by having a gas to fluid ratio of less than 20% and a microbubble volume fraction in the fracturing fluid between about 1 and about 40 percent in the fracturing fluid and where the microbubbles reduce a settling rate of the proppant in the fracturing fluid by hindering proppant settling, reducing proppant density, or forming microbubble coated proppant particles.

2. The method of claim 1 , wherein the average size is between about 20 μ and about 5000 μ and the microbubble volume fraction is between about 1 percent and about 20 percent.

3. The method of claim 1 , wherein the average size is between about 20 μ and about 4000 μ and the microbubble volume fraction is between about 1 percent and about 20 percent.

4. The method of claim 1 , wherein the average size is between about 20 μ and about 3000 μ and the microbubble volume fraction is between about 1 percent and about 20 percent.

5. The method of claim 1 , wherein the average size is between about 20 μ and about 2000 μ and the microbubble volume fraction is between about 1 percent and about 20 percent.

6. The method of claim 1 , wherein the average size is between about 20 μ and about 1000 μ and the microbubble volume fraction is between about 1 percent and about 20percent.

7. The method of claim 1 , wherein the single downhole location is upstream of the formation to be fractured.

8. The method of claim 1 , wherein the single downhole location is just before the formation to be fractured.

9. The method of claim 1 , wherein the single downhole location is a location within the formation to be fractured.

10. The method of claim 1 , further comprising:
injecting the gas at multiple downhole locations through nozzles, where the locations are upstream of and within the formation to be fractured, and
changing the gas injection rate at each of the locations to produce the desired gasification profile.

11. The method of claim 1 , further comprising:
injecting the gas at multiple downhole locations through nozzles, where the locations are within the formation to be fractured, and
changing the gas injection rate at each of the locations to produce the desired gasification profile.

12. A method for fracturing a formation comprising:
pumping a fracturing fluid into a formation to be fractured at a pressure sufficient to fracture the formation,
pumping a proppant-containing solution into the formation to be fractured,
during the pumping steps, after the pumping steps, or during and after the pumping steps, injecting a gas into the fracturing fluid at a gas injection rate below an amount sufficient to convert the fracturing fluid into a stable foam,
where the injecting occurs at a single downhole location producing gas microbubbles having an average size between about 10 and about 6000 micron (μm or μ) in the fracturing fluid, where the gasification profile is characterized by having a gas to fluid ratio of less than 20% and a microbubble volume fraction between about 1 and about 40 percent in the fracturing fluid, and where the microbubbles reduce a settling rate of the proppant in the fracturing fluid, reduce a density of the proppant in the fracturing fluid, or form microbubble coated particles having slower settling rates relative to particles without the microbubble coating,
monitoring a percent of the gas in the fracturing fluid at the single downhole location via a downhole sensor, and
changing the injection rate of the gas to achieve a desired gasification profile in the fracturing fluid across the formation to be fractured during fracturing.

13. The method of claim 12 , wherein the average size is between about 20 μ and about 5000 μ and the microbubble volume fraction is between about 1 percent and about 20 percent.

14. The method of claim 12 , wherein the average size is between about 20 μ and about 4000 μ and the microbubble volume fraction is between about 1 percent and about 20 percent.

15. The method of claim 12 , wherein the average size is between about 20 μ and about 3000 μ and the microbubble volume fraction is between about 1 percent and about 20 percent.

16. The method of claim 12 , wherein the average size is between about 20 μ and about 2000 μ and the microbubble volume fraction is between about 1 percent and about 20 percent.

17. The method of claim 12 , wherein the average size is between about 20 μ and about 1000 μ and the microbubble volume fraction is between about 1 percent and about 20 percent.

18. The method of claim 12 , wherein the single downhole location is upstream of the formation to be fractured.

19. The method of claim 12 , wherein the single downhole location is just before the formation to be fractured.

20. The method of claim 12 , wherein the single downhole location is a location within the formation to be fractured.

21. The method of claim 12 , further comprising:
injecting the gas at multiple downhole locations, where the locations are upstream of and within the formation to be fractured and each location includes a sensor that measures a percent of the gas in the fracturing fluid at that location,
monitoring the percent gas in the fracturing fluid at each of the locations using the sensors, and
changing the injection rate of the gas at each of the locations based on the percentages of the gas measured at each of the locations to achieve the desired gasification profile.

22. The method of claim 12 , further comprising:
injecting the gas at multiple downhole locations, where the locations are within the formation to be fractured and each of the locations includes a sensor that measures a percent of the gas in the fracturing fluid,
monitoring the percent gas in the fracturing fluid at each of the locations using the sensors, and
changing the injection rate of the gas at each of the locations based on the percentages of the gas measured at each of the locations to achieve the desired gasification profile.

Assignees

• Ekstrand Barry
• Zamora Frank
• Kakadjian Sarkis R
• Weatherford Technology Holdings Llc

Inventors

• Ekstrand Barry
• Zamora Frank
• Kakadjian Sarkis R

Classifications

• E21B43/267

  reinforcing fractures by propping · CPC title

• C09K8/70 Primary

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