CA2570953C - Fracturing fluid and method for fracturing subterranean formations - Google Patents
Fracturing fluid and method for fracturing subterranean formations Download PDFInfo
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- CA2570953C CA2570953C CA2570953A CA2570953A CA2570953C CA 2570953 C CA2570953 C CA 2570953C CA 2570953 A CA2570953 A CA 2570953A CA 2570953 A CA2570953 A CA 2570953A CA 2570953 C CA2570953 C CA 2570953C
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- C—CHEMISTRY; METALLURGY
- C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
- C08L—COMPOSITIONS OF MACROMOLECULAR COMPOUNDS
- C08L5/00—Compositions of polysaccharides or of their derivatives not provided for in groups C08L1/00 or C08L3/00
- C08L5/14—Hemicellulose; Derivatives thereof
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
- C09K8/66—Compositions based on water or polar solvents
- C09K8/68—Compositions based on water or polar solvents containing organic compounds
- C09K8/685—Compositions based on water or polar solvents containing organic compounds containing cross-linking agents
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
- C09K8/70—Compositions for forming crevices or fractures characterised by their form or by the form of their components, e.g. foams
- C09K8/706—Encapsulated breakers
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/26—Gel breakers other than bacteria or enzymes
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Abstract
A fluid for fracturing subterranean formations and method of use are disclosed. The fracturing fluid is comprised of a polymer (guar gum or a guar derivative) as a gelling agent, a pH adjusting reagent, a delayed borate cross- linking agent (sparingly soluble borate minerals), and a high pH buffer. The fracturing fluid, upon mixture, initially has a low pH for optimal rapid hydration of the polymer (and the borate remains idle), allows for low tubular friction pressure due to the low viscosity. However, the fracturing fluid allows for a slow, continuous pH shift from the low pH to a higher pH, where the borate ion exists and is available to cross-link and cause gelling of the polymer.
Description
- 2 -Fracturing Fluid and Method for Fracturing Subterranean Formations Field of the Invention This invention relates to a fracturing fluid and method for fracturing subterranean formations.
Background of the Invention In the production of hydrocarbons from subterranean formations, it is common practice to hydraulically fracture the formation to improve hydrocarbon recovery. A fracturing fluid is introduced into the subterranean formation via the well-bore at a rate and pressure sufficient to produce fractures in the formation and to extend the fractures so formed from the well-bore into the formation.
Fluids employed to hydraulically fracture a subterranean formation will desirably have relatively low initial viscosities and low friction pressures when pumped, but high viscosities in the formation due to a cross-linking reaction between a gelling agent and a cross-linking agent.
While the use of high viscosity fracturing fluids is desirable in the fracturing of a subterranean formation, problems are nevertheless encountered in the use of such high viscosity fracturing fluids due to the high friction losses encountered during the introduction of the fluid into the subterranean formation. Since pumping equipment and auxiliary equipment used in the delivery of the fracturing fluids to the subterranean formation have limited capacity and operating pressure, the viscosity of the fracturing fluid which can be pumped is limited accordingly.
In an effort to overcome these problems, numerous compositions and systems have been proposed in the art to delay the cross-linking of the gelling agent so that low viscosity of the fracturing fluid can be maintained during pumping thus minimizing excessive friction losses and high well head pumping pressures, while at the same time permitting the desired cross-linking to occur in the subterranean 4109665v3
Background of the Invention In the production of hydrocarbons from subterranean formations, it is common practice to hydraulically fracture the formation to improve hydrocarbon recovery. A fracturing fluid is introduced into the subterranean formation via the well-bore at a rate and pressure sufficient to produce fractures in the formation and to extend the fractures so formed from the well-bore into the formation.
Fluids employed to hydraulically fracture a subterranean formation will desirably have relatively low initial viscosities and low friction pressures when pumped, but high viscosities in the formation due to a cross-linking reaction between a gelling agent and a cross-linking agent.
While the use of high viscosity fracturing fluids is desirable in the fracturing of a subterranean formation, problems are nevertheless encountered in the use of such high viscosity fracturing fluids due to the high friction losses encountered during the introduction of the fluid into the subterranean formation. Since pumping equipment and auxiliary equipment used in the delivery of the fracturing fluids to the subterranean formation have limited capacity and operating pressure, the viscosity of the fracturing fluid which can be pumped is limited accordingly.
In an effort to overcome these problems, numerous compositions and systems have been proposed in the art to delay the cross-linking of the gelling agent so that low viscosity of the fracturing fluid can be maintained during pumping thus minimizing excessive friction losses and high well head pumping pressures, while at the same time permitting the desired cross-linking to occur in the subterranean 4109665v3
- 3 -formations so that the desired high viscosity of the fracturing fluid can be achieved in the formation.
It is well known that boric acid is a very weak, inorganic acid and the borate ion does not exist as such until the pH is sufficiently high to react with more firmly bound second and third hydrogens. The borate ion complexes with many compounds, for example certain polysaccharides like guar gum. At a high pH, above pH 8, the borate ion exists and is available to cross-link and cause gelling. At lower pH, the borate is tied up by hydrogen and is not available for cross-linking.
The rate of cross-linking can be controlled by suitable adjustment of one or more of the following variables: initial pH of the aqueous solutions system, relative concentration of one or more of the sparingly soluble borates, the temperature of the borates, temperature of the aqueous system and particle size of the borate.
Summary of the Invention In one aspect, the invention relates to a fracturing fluid for fracturing a subterranean formation comprising a polymer (guar gum or a guar derivative) as a gelling agent, a pH adjusting reagent, a delayed borate cross-linking agent (sparingly soluble borate minerals), and a high pH buffer. The fracturing fluid, upon blending, initially has a low pH for optimal rapid hydration of the polymer (with the borate remaining idle), allows for low tubular friction pressure due to the low viscosity. However, the fracturing fluid allows for a slow, continuous pH
shift from the low pH to a higher pH, where the borate ion exists and is available to cross-link and cause gelling of the polymer.
The invention also relates to a method for fracturing subterranean formations utilizing a fracturing fluid composition, as described above, that undergoes a slow, continuous pH transition. This provides for the ability to simultaneously inject the polymer (guar gum) and the cross-linking agent (sparingly soluble borate minerals) into the well-bore, without pre-hydration of the polymer.
4109665 v3
It is well known that boric acid is a very weak, inorganic acid and the borate ion does not exist as such until the pH is sufficiently high to react with more firmly bound second and third hydrogens. The borate ion complexes with many compounds, for example certain polysaccharides like guar gum. At a high pH, above pH 8, the borate ion exists and is available to cross-link and cause gelling. At lower pH, the borate is tied up by hydrogen and is not available for cross-linking.
The rate of cross-linking can be controlled by suitable adjustment of one or more of the following variables: initial pH of the aqueous solutions system, relative concentration of one or more of the sparingly soluble borates, the temperature of the borates, temperature of the aqueous system and particle size of the borate.
Summary of the Invention In one aspect, the invention relates to a fracturing fluid for fracturing a subterranean formation comprising a polymer (guar gum or a guar derivative) as a gelling agent, a pH adjusting reagent, a delayed borate cross-linking agent (sparingly soluble borate minerals), and a high pH buffer. The fracturing fluid, upon blending, initially has a low pH for optimal rapid hydration of the polymer (with the borate remaining idle), allows for low tubular friction pressure due to the low viscosity. However, the fracturing fluid allows for a slow, continuous pH
shift from the low pH to a higher pH, where the borate ion exists and is available to cross-link and cause gelling of the polymer.
The invention also relates to a method for fracturing subterranean formations utilizing a fracturing fluid composition, as described above, that undergoes a slow, continuous pH transition. This provides for the ability to simultaneously inject the polymer (guar gum) and the cross-linking agent (sparingly soluble borate minerals) into the well-bore, without pre-hydration of the polymer.
4109665 v3
- 4 -Detailed Description of the Preferred Embodiments In one embodiment, a fracturing fluid according to the invention is comprised of an aqueous solution, guar gum or a guar derivative as the polymer gelling agent, a pH adjusting reagent, a delayed borate cross-linking agent, a high pH buffer, a clay control additive, and a delayed viscosity breaker for controlled viscosity reduction of the fluid once placed in the formation.
The guar derivative in the fracturing fluid may be compounds such as hydroxypropyl guar. The guar gum or guar derivative in the fracturing fluid is high purity, high yielding, and fast hydrating. It is used at concentrations of about 1.2 kg/m3 to about 4.8 kg/m3, preferably at a relatively low concentrations, ranging from 1.8 kg/m3 to 3.0 kg/m3, to minimize formation damage. The guar gum or guar derivative may be mixed into an oil-based slurry to allow for accurate and continuous injection during fracturing.
The pH adjusting reagent in the fracturing fluid may be reagents such as acetic acid, fumaric acid, formic acid, or other suitable weak organic acid. The pH
adjusting reagent, is added to ensure the pH of the aqueous solution is in the optimum range for polymer hydration, namely, between about pH 4 and about pH 7 for the guar gum or guar derivatives.
The borate cross-linking agent, or agents, is comprised of a sparingly soluble borate mineral, or minerals. These minerals are added at concentrations of about 0.025 to about 0.4 percent by weight of water. The slow solubility of these borate reagents, in conjunction with the high pH buffer, serves to delay cross-linking. This mechanism provides more effective and accurate use of the known cross-link time controls, such as: initial water temperature, initial water pH, and borate/buffer concentration.
Upon addition of the high pH buffer (i.e., a buffer that has the tendency towards shifting the....pti_of the solution to a basic, pH 8 or higher) and the 4109665 v
The guar derivative in the fracturing fluid may be compounds such as hydroxypropyl guar. The guar gum or guar derivative in the fracturing fluid is high purity, high yielding, and fast hydrating. It is used at concentrations of about 1.2 kg/m3 to about 4.8 kg/m3, preferably at a relatively low concentrations, ranging from 1.8 kg/m3 to 3.0 kg/m3, to minimize formation damage. The guar gum or guar derivative may be mixed into an oil-based slurry to allow for accurate and continuous injection during fracturing.
The pH adjusting reagent in the fracturing fluid may be reagents such as acetic acid, fumaric acid, formic acid, or other suitable weak organic acid. The pH
adjusting reagent, is added to ensure the pH of the aqueous solution is in the optimum range for polymer hydration, namely, between about pH 4 and about pH 7 for the guar gum or guar derivatives.
The borate cross-linking agent, or agents, is comprised of a sparingly soluble borate mineral, or minerals. These minerals are added at concentrations of about 0.025 to about 0.4 percent by weight of water. The slow solubility of these borate reagents, in conjunction with the high pH buffer, serves to delay cross-linking. This mechanism provides more effective and accurate use of the known cross-link time controls, such as: initial water temperature, initial water pH, and borate/buffer concentration.
Upon addition of the high pH buffer (i.e., a buffer that has the tendency towards shifting the....pti_of the solution to a basic, pH 8 or higher) and the 4109665 v
- 5 -borate mineral to the aqueous solution, the aqueous solution undergoes a pH
shift from low pH, for optimum polymer hydration (i.e. pH of about 4 to 7), to high pH, of about pH 8 to about pH 11, whereupon, the boron is able to cross-link the polymer.
The preferred final pH is about 8.5 to about 9.5, which maximizes the shear stability resulting in the final gel.
The slow, continuous pH shift instils a unique advantage to this fluid system.
At the initial, low pH, rapid hydration of the polymer occurs, while at the same time, the boron remains idle. This initial stage provides low tubular friction pressure due to the low viscosity. As the pH increases from the initial range of about 4 to 7, increasing to a pH of about 8.2 to 8.8, a highly shear stable cross-linked fluid is formed. This occurs ideally within the time it takes the fluid to travel from the surface to the bottom of the well-bore.
After entering the subterranean zone, the buffer continues to raise the pH to about 9.0 to 10, resulting in a gel thermally stable to temperatures in excess of 1200C
and also increasing the proppant suspension capability of the fluid.
Guar based polymers are normally pre-hydrated in the mix solution using an hydration unit/retention tank before the cross-linking agent is added.
However, in the slow pH transition of the above mentioned fracturing fluid allows hydration of the polymer to occur even after the cross-linking agent has been added. As a result, the polymer (guar gum or derivative) and borate cross-linking agent can be injected "on-the-fly" simultaneously without pre-hydration of the polymer.
In addition, the slow and controllable shift from low pH to high pH allows high concentrations of the borate cross-linking minerals and high pH buffers to be added without risking over cross-linking the polymer.
4109665v4
shift from low pH, for optimum polymer hydration (i.e. pH of about 4 to 7), to high pH, of about pH 8 to about pH 11, whereupon, the boron is able to cross-link the polymer.
The preferred final pH is about 8.5 to about 9.5, which maximizes the shear stability resulting in the final gel.
The slow, continuous pH shift instils a unique advantage to this fluid system.
At the initial, low pH, rapid hydration of the polymer occurs, while at the same time, the boron remains idle. This initial stage provides low tubular friction pressure due to the low viscosity. As the pH increases from the initial range of about 4 to 7, increasing to a pH of about 8.2 to 8.8, a highly shear stable cross-linked fluid is formed. This occurs ideally within the time it takes the fluid to travel from the surface to the bottom of the well-bore.
After entering the subterranean zone, the buffer continues to raise the pH to about 9.0 to 10, resulting in a gel thermally stable to temperatures in excess of 1200C
and also increasing the proppant suspension capability of the fluid.
Guar based polymers are normally pre-hydrated in the mix solution using an hydration unit/retention tank before the cross-linking agent is added.
However, in the slow pH transition of the above mentioned fracturing fluid allows hydration of the polymer to occur even after the cross-linking agent has been added. As a result, the polymer (guar gum or derivative) and borate cross-linking agent can be injected "on-the-fly" simultaneously without pre-hydration of the polymer.
In addition, the slow and controllable shift from low pH to high pH allows high concentrations of the borate cross-linking minerals and high pH buffers to be added without risking over cross-linking the polymer.
4109665v4
- 6 -The fracturing fluid is slowly and controllably degraded using an encapsulated oxidizer such as ammonium or potassium persulfate, or a combination of an encapsulated oxidizer and a delayed release acid.
In another aspect, this invention relates to a method for fracturing a subterranean formation utilizing the disclosed fracturing fluid. Furthermore, this invention allows for a method of fracturing a subterranean formation utilizing the disclosed fracturing fluid by simultaneously injecting, "on-the-fly", the polymer (guar gum or derivative) and borate cross-linking agent, without requiring pre-hydration of the polymer.
In another aspect, this invention relates to a method for fracturing a subterranean formation utilizing the disclosed fracturing fluid. Furthermore, this invention allows for a method of fracturing a subterranean formation utilizing the disclosed fracturing fluid by simultaneously injecting, "on-the-fly", the polymer (guar gum or derivative) and borate cross-linking agent, without requiring pre-hydration of the polymer.
Claims (38)
1. A fracturing fluid for fracturing subterranean formations, the fracturing fluid comprising:
an aqueous solution;
a polymer selected from the group consisting of: a guar gum polymer and a guar derivative polymer;
a pH adjusting reagent;
at least one delayed borate cross-linking agent;
a high pH buffer;
wherein, the polymer and the delayed borate cross-linking agent are adapted to be injected simultaneously into the subterranean formation without pre-hydration of the polymer; and whereby, the fracturing fluid has an initial low pH that provides for the rapid hydration of the polymer, providing a low viscosity fluid;
whereby, the fracturing fluid provides for a slow, continuous increase in pH, wherein a highly shear stable cross-linked fluid is formed at a pH of about 8 or higher.
an aqueous solution;
a polymer selected from the group consisting of: a guar gum polymer and a guar derivative polymer;
a pH adjusting reagent;
at least one delayed borate cross-linking agent;
a high pH buffer;
wherein, the polymer and the delayed borate cross-linking agent are adapted to be injected simultaneously into the subterranean formation without pre-hydration of the polymer; and whereby, the fracturing fluid has an initial low pH that provides for the rapid hydration of the polymer, providing a low viscosity fluid;
whereby, the fracturing fluid provides for a slow, continuous increase in pH, wherein a highly shear stable cross-linked fluid is formed at a pH of about 8 or higher.
2. The fracturing fluid according to claim 1, wherein the polymer is present in the fracturing fluid at a concentration of about 1.2 kg/m3 to about 4.8 kg/m3.
3. The fracturing fluid according to claim 1, wherein the polymer is present in the fracturing fluid at a concentration of about 1.8 kg/m3 to about 3.0 kg/m3.
4. The fracturing fluid according to any one of claims 1 to 3, wherein the polymer is hydroxypropyl guar.
5. The fracturing fluid according to any one of claims 1 to 4, wherein the pH
adjusting reagent adjusts the initial pH of the aqueous solution to be within the range of about pH 4 to about pH 7.
adjusting reagent adjusts the initial pH of the aqueous solution to be within the range of about pH 4 to about pH 7.
6. The fracturing fluid according to any one of claims 1 to 5, wherein the pH
adjusting reagent is a weak organic acid.
adjusting reagent is a weak organic acid.
7. The fracturing fluid according to claim 6, wherein the pH adjusting reagent is acetic acid.
8. The fracturing fluid according to claims 6, wherein the pH adjusting reagent is fumaric acid.
9. The fracturing fluid according to claims 6, wherein the pH adjusting reagent is formic acid.
10. The fracturing fluid according to any one of claims 1 to 9, wherein the at least one borate cross-linking agent consists of a sparingly soluble borate mineral.
11. The fracturing fluid according to claim 10, wherein the at least one borate cross-linking agent is present in the fracturing fluid at a concentration of about 0.0025 to about 0.4 percent by weight of water.
12. The fracturing fluid according to any one of claims 1 to 11, wherein the high pH buffer adjusts the pH of the aqueous solution to be within the range of about pH
8 to about pH 11.
8 to about pH 11.
13. The fracturing fluid according to any one of claims 1 to 11, wherein the high pH buffer adjusts the pH of the aqueous solution to be within the range of about pH
8.5 to about pH 9.5.
8.5 to about pH 9.5.
14. The fracturing fluid according to any one of claims 1 to 13, wherein the fracturing fluid further comprises a clay control additive.
,
,
15. The fracturing fluid according to any one of claims 1 to 14, wherein the fracturing fluid further comprises a delayed viscosity breaker, whereby the delayed viscosity breaker allows for controlled viscosity reduction.
16. The fracturing fluid according to claim 15, wherein the delayed viscosity breaker is an encapsulated oxidizer.
17. The fracturing fluid according to claim 16, wherein the delayed viscosity breaker is ammonium persulfate.
18. The fracturing fluid according to claim 16, wherein the delayed viscosity breaker is potassium persulfate.
19. The fracturing fluid according to claim 15, wherein the delayed viscosity breaker is a combination of an encapsulated oxidizer and a delayed release acid.
20. A method for fracturing subterranean formations, comprising the steps of:
blending the following to form a fracturing fluid:
an aqueous solution;
a polymer selected from the group consisting of: a guar gum polymer and a guar derivative polymer;
a pH adjusting reagent;
at least one delayed borate cross-linking agent; and a high pH buffer;
during the blending step, the polymer and the delayed borate cross-linking agent are simultaneously injected into the subterranean formation without pre-hydration of the polymer; and whereby, the fracturing fluid has an initial low pH that provides for the rapid hydration of the polymer, providing a low viscosity fluid; and whereby, the fracturing fluid provides for a slow, continuous increase in pH, wherein a highly shear stable cross-linked fluid is formed at a pH of about 8 or higher.
blending the following to form a fracturing fluid:
an aqueous solution;
a polymer selected from the group consisting of: a guar gum polymer and a guar derivative polymer;
a pH adjusting reagent;
at least one delayed borate cross-linking agent; and a high pH buffer;
during the blending step, the polymer and the delayed borate cross-linking agent are simultaneously injected into the subterranean formation without pre-hydration of the polymer; and whereby, the fracturing fluid has an initial low pH that provides for the rapid hydration of the polymer, providing a low viscosity fluid; and whereby, the fracturing fluid provides for a slow, continuous increase in pH, wherein a highly shear stable cross-linked fluid is formed at a pH of about 8 or higher.
21. The method according to claim 20, wherein the polymer is present in the fracturing fluid at a concentration of about 1.2 kg/m3 to about 4.8 kg/m3.
22. The method according to claim 20, wherein the polymer is present in the fracturing fluid at a concentration of about 1.8 kg/m3 to about 3.0 kg/m3.
23. The method according to any one of claims 20 to 22, wherein the polymer is hydroxypropyl guar.
24. The method according to any one of claims 20 to 23, wherein the pH
adjusting reagent adjusts the pH of the aqueous solution to be within the range of about pH 4 to about pH 7.
adjusting reagent adjusts the pH of the aqueous solution to be within the range of about pH 4 to about pH 7.
25. The method according to any one of claims 20 to 24, wherein the pH
adjusting reagent is a weak organic acid.
adjusting reagent is a weak organic acid.
26. The method according to claim 25, wherein the pH adjusting reagent is acetic acid.
27. The method according to claim 25, wherein the pH adjusting reagent is fumaric acid.
28. The method according to claim 25, wherein the pH adjusting reagent is formic acid.
29. The method of any one of claims 20 to 28, wherein the at least one borate cross-linking agent consists of a sparingly soluble borate mineral.
30. The method according to claim 29, wherein the at least one borate cross-linking agent is present in the fracturing fluid at a concentration of about 0.0025 to about 0.4 percent by weight of water.
31. The method according to any one of claims 20 to 30, wherein the high pH
buffer adjusts the pH of the aqueous solution to be within the range of about pH 8 to about pH 11.
buffer adjusts the pH of the aqueous solution to be within the range of about pH 8 to about pH 11.
32. The method according to any one of claims 20 to 30, wherein the high pH
buffer adjusts the pH of the aqueous solution to be within the range of about pH 8.5 to about pH 9.5.
buffer adjusts the pH of the aqueous solution to be within the range of about pH 8.5 to about pH 9.5.
33. The method according to any one of claims 20 to 32, wherein the fracturing fluid further comprises a clay control additive.
34. The method according to any one of claims 20 to 33, wherein the fracturing fluid further comprises a delayed viscosity breaker, whereby the delayed viscosity breaker allows for controlled viscosity reduction.
35. The method according to claim 34, wherein the delayed viscosity breaker is an encapsulated oxidizer.
36. The method according to claim 34, wherein the delayed viscosity breaker is ammonium persulfate.
37. The method according to claim 34, wherein the delayed viscosity breaker is potassium persulfate.
38. The method according to claim 34, wherein the delayed viscosity breaker is a combination of an encapsulated oxidizer and a delayed release acid.
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| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2570953A CA2570953C (en) | 2006-12-12 | 2006-12-12 | Fracturing fluid and method for fracturing subterranean formations |
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| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2570953A CA2570953C (en) | 2006-12-12 | 2006-12-12 | Fracturing fluid and method for fracturing subterranean formations |
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| Publication Number | Publication Date |
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| CA2570953A1 CA2570953A1 (en) | 2008-06-12 |
| CA2570953C true CA2570953C (en) | 2014-11-25 |
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| CA2570953A Expired - Fee Related CA2570953C (en) | 2006-12-12 | 2006-12-12 | Fracturing fluid and method for fracturing subterranean formations |
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| US8387696B2 (en) | 2007-08-03 | 2013-03-05 | M-I L.L.C. | Delayed breaker |
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