FRACTURES TREATMENT

• US 20170321112A1
• Filed: 11/06/2014
• Published: 11/09/2017
• Est. Priority Date: 11/06/2014
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (SLB)
• Original Assignee: Schlumberger Technology Corporation (SLB)
• Inventors: LECERF, Bruno, SHALAGINA, Anastasia Evgenyevna
• Granted Patent: US 10,781,679 B2
• Time in Patent Office: Days
• CPC Class Codes: C09K 2208/08 Fiber-containing well treatment fluids
• CPC Class Codes: C09K 8/64 Oil-based compositions
• CPC Class Codes: C09K 8/68 containing organic compounds
• CPC Class Codes: C09K 8/80 Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
• CPC Class Codes: C09K 8/82 Oil-based compositions C09K8/64 takes precedence
• CPC Class Codes: C09K 8/885 obtained otherwise than by reactions only involving carbon-to-carbon unsaturated bonds
• CPC Class Codes: E21B 43/267 reinforcing fractures by propping

Abstract

A fracture treatment method includes forming propped regions having an optimized conductivity. Also disclosed are systems to treat a fracture interval and to produce reservoir fluids from a formation.

Claims

1. A treatment fluid, comprising:

a viscosified carrier fluid having a viscosity above 50 mPa-s at a shear rate of 170 s-1 and a temperature of 25°

C.;

proppant dispersed in the carrier fluid; and

channelant containing 0.1 to 20 wt % silicones dispersed in the carrier fluid.

2. The treatment fluid of claim 1, wherein the carrier fluid is crosslinked.

3. The treatment fluid of claim 1, comprising from 0.06 to 1.8 kg/L of the proppant based on the total volume of the carrier fluid (from 0.5 to 15 ppa, pounds proppant added per gallon of carrier fluid).

4. The treatment fluid of claim 1, wherein the channelant is dispersed in the carrier fluid in an amount effective to inhibit settling of the proppant inn the carrier fluid.

5. The treatment fluid of claim 1, wherein the channelant is fiber.

6. The treatment fluid of claim 5 comprising from 0.48 to 12 g/L of the fibers based on the total volume of the carrier fluid (from 4 to 100 ppt, pounds per thousand gallons of carrier fluid).

7. The treatment fluid of claim 5, wherein the fibers are crimped staple fibers.

8. The treatment fluid of claim 5, wherein the fibers are crimped staple fibers comprising from 1 to 10 crimps/cm of length, a crimp angle from 45 to 160 degrees, an average extended length of fiber of from 3 to 15 mm, a mean diameter of from 6 to 40 microns, or a combination thereof.

9. The treatment fluid of claim 5, wherein the fibers comprise polyester.

10. The treatment fluid of claim 8, wherein the polyester is selected from the group consisting of polylactic acid, polyglycolic acid, copolymers of lactic and glycolic acid, and combinations thereof.

11. The treatment fluid of claim 1, wherein the channelant containing silicones is obtained by melt extrusion.

12. The treatment fluid of claim 1, wherein the silicone is a linear polysiloxane.

13. The treatment fluid of claim 1, wherein the silicone has an average molecular weight of from about 100 000 g/mol to about 900 000 g/mol.

14. A method to treat a subterranean formation penetrated by a wellbore, comprising:

injecting a treatment fluid into the subterranean formation to form a hydraulic fracture system, wherein the treatment fluid comprises;

a viscosified carrier fluid having a viscosity above 50 mPa-s at a shear rate of 170 s-1 and a temperature of 25°

C.;

proppant dispersed in the carrier fluid; and

channelant containing 0.1 to 20 wt % silicones dispersed in the carrier fluid.

15. The method of claim 14, further comprising injecting a pre-pad, pad, tail or flush stage or a combination thereof.

16. The method of claim 14, wherein the treatment fluid comprises from 0.06 to 1.8 kg/L of the proppant based on the total volume of the carrier fluid (from 0.5 to 15 ppa, pounds proppant added per gallon of carrier fluid).

17. The method of claim 14, wherein the channelant comprises polyester fibers at a concentration below 4.8 g/L of the fibers based on the total volume of the carrier fluid (less than 40 ppt).

18. A method of placing a proppant pack into a fracture formed in a subterranean formation, the method comprising:

injecting well a treatment fluid comprising proppant and channelant through a wellbore into a fracture in a subterranean formation, wherein the channelant contains 0.1 to 20 wt % silicones;

placing the proppant in the fracture in a plurality of proppant clusters forming pillars spaced apart; and

,

removing the channelant to form open channels around the pillars for fluid flow from the formation through the fracture toward the wellbore;

wherein the treatment fluid comprises alternating volumes of proppant-rich fluid and proppant-lean fluid.

19. The method of claim 18, wherein the channelant comprises degradable fibers.

20. The method of claim 18, wherein the injection comprises:

injecting a proppant-lean carrier stage to initiate the fracture; and

thereafter injecting into the fracture proppant and channelant.

21. The method of claim 18, wherein the solid proppant-rich substages and the proppant-lean substages in the treatment stage fluid have an overall volumetric ratio from 60:

40 to 95;

5.

22. A method to treat a subterranean formation penetrated by a wellbore, comprising:

injecting a treatment fluid, comprising particulate and at least a channelant containing 0.1 to 20 wt % silicones, above a fracturing pressure into the formation to distribute a mixture of a solid particulate in a fracture;

alternatingly injecting solid particulate-rich and solid particulate-lean substages of the treatment fluid stage into the fracture, wherein a volume of each of the solid particulate-rich substages is larger than a respective volume of an adjacent one of the solid particulate-lean substages to form a plurality of solid particulate-rich island regions in the fracture and an interconnected network of open channel regions between the island regions;

channelizing the particulate-rich island regions in situ in the fracture to form particulate clusters within the island regions separated from adjacent particulate clusters by open voids in the island regions;

reducing pressure in the fracture to close the fracture onto the island regions; and

hydraulically conducting fluid flow through the open channel regions between the formation and the wellbore.

23. The method of claim 22, wherein the solid particulate-rich substages each comprise alternating pulses injected at different rates.

24. The method of claim 22, wherein the channelant comprises an ester and the method further comprises releasing an acid from the ester.

25. A system to treat a fracture interval of a formation penetrated by a wellbore, comprising:

a subterranean formation penetrated by a wellbore;

a treatment fluid stage disposed at least partially in the wellbore, the treatment fluid stage comprising solid particulate-rich and solid particulate-lean substages, wherein a volume of each of the solid particulate-rich substages is equal or larger than a respective volume of an adjacent one of the solid particulate-lean substages to form a plurality of solid particulate-rich island regions in the fracture and an interconnected network of open channel regions between the island regions;

the solid particulate-rich substages each comprising alternating pulses comprising a substantially uniform distribution of one or more components in the alternate pulses and a heterogeneous distribution between alternate pulses of at least one other component to channelize the particulate-rich island regions in situ in the fracture to form particulate clusters within the island regions separated from adjacent particulate clusters by open voids within the island regions;

a pump system to inject the treatment fluid stage from the wellbore to the formation at a pressure above fracturing pressure to inject the treatment fluid stage into a fracture in the formation; and

a shut in system to close the fracture onto the solid particulate-rich island regions

wherein at least the particulate-rich substages comprise a channelant containing 0.1 to 20 wt % silicones.