Methods of treating a subterranean formation with a treatment fluid having surfactant effective to increase the thermal stability of the fluid

Abstract

Methods of treating a subterranean formation penetrated by a wellbore are provided, the methods comprising the steps of: (a) for a treatment fluid to be used in treating a subterranean formation, establishing a desired viscosity at a desired temperature for a desired time; (b) forming a treatment fluid that has the desired viscosity at the desired temperature for the desired time, wherein the treatment fluid comprises: (i) a base fluid; (ii) a viscosifying agent comprising a polymer; and (iii) a surfactant; and (c) introducing the treatment fluid into a subterranean formation. According to one aspect, an otherwise substantially identical treatment fluid with a lower concentration of the surfactant would not achieve the desired viscosity at the desired temperature for the desired time. According to another aspect, the polymer is at a lower concentration in the base fluid than would be required for an otherwise substantially identical treatment fluid with a lower concentration of the surfactant to achieve the desired viscosity at the desired temperature for the desired time.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

Not Applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

TECHNICAL FIELD

The invention generally relates to methods of treating a hydrocarbon-bearing subterranean formation with viscosified fluids for various purposes, such as gravel packing and hydraulic fracturing. Such treatment fluids are viscosified with polymeric materials that are sensitive to elevated temperatures. The invention relates to using a surfactant to increase the thermal stability of such viscosified treatment fluids.

BACKGROUND

Hydrocarbon (e.g. crude oil and natural gas) is used for making various grades of fuels and oils. Hydrocarbon is obtained from a hydrocarbon-bearing subterranean formation by drilling a wellbore into the earth, either on land or under the sea, that penetrates the hydrocarbon-bearing formation. Typically, such a wellbore must be drilled thousands of feet into the earth to reach the hydrocarbon-bearing formations. Usually, the greater the depth of the well, the hotter the natural temperature of the formation.

Of course, it is desirable to maximize both the rate of flow and the overall amount of flow of hydrocarbon from the subterranean formation to the surface. The higher temperatures can be a problem for the gels used in various treatments on a subterranean formation to improve the flow of hydrocarbon.

For example, a treatment performed to restore or enhance the productivity of a well is called a stimulation treatment. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments.

Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. In general, hydraulic fracturing involves injecting a fracturing fluid through the wellbore and into an oil and gas bearing subterranean formation at a sufficiently high rate of fluid flow and at a sufficiently high pressure to initiate and extend one or more fractures in the formation. To conduct hydraulic pressure through the wellbore, the fracturing fluid must be substantially incompressible. In addition, because of the large quantities of fracturing fluid required, the fracturing fluid is preferably based on readily-available and plentiful fluid. Thus, the typical fracturing fluid is based on water.

The fracturing fluid is injected through the wellbore at such a high flow rate and under such high pressure that the rock of the subterranean formation that is subjected to the hydraulic treatment literally cracks apart or fractures under the strain. When the formation fractures, the pressure is relieved as the fracturing fluid starts to move quickly through the fracture and out into the formation. The theoretical objective of forming such a fracture in the rock of the formation is to create a large surface area of the faces of the fracture. The large surface area allows oil and gas to flow from the rock of the subterranean formation into the facture, which provides an easy path for the oil and gas to easily flow into the well.

However, once the high pressure is relieved by the escape of the fracturing fluid through the created fracture and out further into the subterranean formation, the fracture has a tendency to be squeezed closed by the natural pressures on the rock within the deep subterranean formation. To keep the fracture open, some kind of material must be placed in the fracture to prop the faces of the fracture apart.

The desirable material for the purpose of propping the fracture apart must meet several criteria. For example, the material must have a sufficient strength not to be entirely crushed by the natural forces tending to push the fracture closed. The material must be capable of being fluidized so that it can flow with or immediately following the fracturing fluid. Additionally, the material also must itself not block or seal the fracture. Thus, a typical material used for the purpose of propping open a fracture is sand. Sand, in the aggregate, has a sufficiently high mechanical strength to prop open a fracture in a subterranean formation at typical depths and natural subterranean pressures; it can behave as a fluid in that it can be poured and flow; and the particles, even when tightly compacted, have a network of void spaces between them that can provide high porosity to fluid flow.

While sand is the most commonly used material for the purpose of propping the fracture open, many other materials of the appropriate size range and mechanical strength can be used. In the oil and gas industry, any suitable particulate material that is used for the purpose of propping open a fracture produced by hydraulic fracturing is called a “proppant.”

To be able to carry and place a proppant into a newly-created fracture, a fluid must have a sufficient viscosity to suspend and carry the proppant. In a low viscosity fluid, for example, the proppant would have a tendency to simply fall under gravity toward the bottom of the well instead of being carried with the fracturing fluid out into the newly-created fracture. For a fluid to be able to carry the proppant instead of having the proppant fall out of the fluid, the fracturing fluid needs to be made to have a much higher viscosity than that of water. Preferably, the fracturing fluid is a gel, which has a very high viscosity and great capacity for carrying a proppant suspended in the fluid.

Using a water-soluble polymeric material, such as a gum, is one of the ways to build viscosity in aqueous systems. Such a gum can be mixed with an aqueous fluid for use in a well to increase fluid viscosity. A sufficient concentration of the gum in an aqueous system can form a linear gel. Furthermore, the gum also can be crosslinked with other compounds, such as borates or various metals, to create a viscous fluid, which is highly advantageous to transporting a proppant in a hydraulic fracturing procedure.

Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore or enhance the natural permeability of the reservoir in the near-wellbore area. Matrix operations can include treating the formation with an acid to dissolve some of the acid soluble rock material. It is sometimes desirable to perform a matrix treatment with a gelled fluid.

Another type of treatment for a subterranean formation is gravel packing, which is used to help control fines migrations. “Fines” are tiny particles that have a tendency to flow through the formation with the production of hydrocarbon. The fines have a tendency to plug small pore spaces in the formation and block the flow of oil. As all the hydrocarbon is flowing from a relatively large region around the wellbore region toward a relatively small area around the wellbore, the fines have a tendency to become densely packed and screen out or plug the area immediately around the wellbore. Moreover, the fines are highly abrasive and can be very harmful to pumping equipment.

In general, gravel packing involves placing sand or gravel around the wellbore to help screen out the fines. Like with placing a proppant in a subterranean formation during hydraulic fracturing, a gelled fluid is used to help place the gravel in a gravel packing operation. Gravel packing can also be done in conjunction with other treatments including hydraulic fracturing such as the FracPac^SM service.

Other examples of uses of gelled fluids include but are not limited to spacers for cements and/or muds, fluid loss pills, and gelled pipeline clean-out fluids (“pigs”).

In all the various types of treatments for a subterranean formation that involve the use of a gelled fluid, the gels are sensitive to temperature. Many of the subterranean formations to be treated have a natural formation temperature greater than 175° F. (80° C.), and most are within the range of 175-550° F. (80-288° C.). Many of the polymer-based gels are sensitive to temperatures above about 220° F. (105° C.). Especially the gels that are based on natural polymeric materials, such as guar or cellulose, which are the most economical in the large quantities required for a treatment of a subterranean formation, are sensitive to such high temperatures.

Efforts have been made to improve the thermal stability of gels, but greater thermal stability is always desirable.

SUMMARY OF THE INVENTION

According to the invention, methods are provided for treating a subterranean penetrated by a wellbore with a treatment fluid that is thermally stabilized by a surfactant.

According to one aspect of the invention, a method of treating a subterranean formation penetrated by a wellbore is provided, the method comprising the steps of: (a) for a treatment fluid to be used in treating a subterranean formation, establishing a desired viscosity at a desired temperature for a desired time; (b) forming a treatment fluid that has the desired viscosity at the desired temperature for the desired time, wherein the treatment fluid comprises: (i) a base fluid; (ii) a viscosifying agent comprising a polymer; and (iii) a surfactant; wherein an otherwise substantially identical treatment fluid with a lower concentration of the surfactant would not achieve the desired viscosity at the desired temperature for the desired time; and (c) introducing the treatment fluid into a subterranean formation.

According to another aspect of the invention, a method of treating a subterranean formation penetrated by a wellbore is provided, the method comprising the steps of: (a) for a treatment fluid to be used in treating a subterranean formation, establishing a desired viscosity at a desired temperature for a desired time; (b) forming a treatment fluid that has the desired viscosity at the desired temperature for the desired time, wherein the treatment fluid comprises: (i) a base fluid; (ii) a viscosifying agent comprising a polymer; and (iii) a surfactant; wherein the polymer is at a lower concentration in the base fluid than would be required for an otherwise substantially identical treatment fluid with a lower concentration of the surfactant to achieve the desired viscosity at the desired temperature for the desired time; and (c) introducing the treatment fluid into a subterranean formation.

These and other aspects of the invention will be apparent to one skilled in the art upon reading the following detailed description. While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof will be described in detail and shown by way of example. It should be understood, however, that it is not intended to limit the invention to the particular forms disclosed, but, on the contrary, the invention is to cover all modifications and alternatives falling within the spirit and scope of the invention as expressed in the appended claims

BRIEF DESCRIPTION OF THE DRAWING

The accompanying drawings are incorporated into and form a part of the specification to illustrate several examples of the present inventions. These drawings together with the description serve to explain the principles of the inventions. The drawings are only for illustrating preferred and alternative examples of how the inventions can be made and used and are not to be construed as limiting the inventions to the illustrated and described examples. The various advantages and features of the present inventions will be apparent from a consideration of the drawings in which:

FIG. 1 is a graph of the viscosity measurements in cP at a shear rate of 81/sec vs. time as the sample was rapidly heated from room temperature to 240° F. in about 20 minutes and then held at 240° F. (115° C.) on samples of a borate-crosslinked hydroxypropyl guar in 4% KCl water at a pH of about 10.5, where Sample 1 is without any of the surfactant blend and Sample 2 has 1 gal/Mgal of the surfactant blend.

FIG. 2 is a graph of the viscosity measurements in cP at a shear rate of 81/sec vs. time as the sample was rapidly heated from room temperature to 285° F. (140° C.) in about 20 minutes and then held at 285° F. (140° C.) on samples of a borate-crosslinked hydroxypropyl guar in 4% KCl water at a pH of about 10.5, where Sample 2 contained 1 gal/Mgal of the surfactant blend, Sample 3 contained 2 gal/Mgal of the surfactant blend, and Sample 4 contained 3 gal/Mgal of the surfactant blend.

FIG. 3 is a graph of the viscosity measurements in cP at a shear rate of 81/sec vs. time as the sample was rapidly heated from room temperature to 285° F. (140° C.) in about 20 minutes and then held at 285° F. (140° C.) on samples of a borate-crosslinked hydroxypropyl guar in 4% KCl water at a pH of about 10.5, where Sample 5 contained none of the surfactant blend and no sodium thiosulfate, Sample 6 contained 3 gal/Mgal of the surfactant blend and no sodium thiosulfate, Sample 7 contained none of the surfactant blend and 1 lb/Mgal of sodium thiosulfate, and Sample 8 contained 3 gal/Mgal of the surfactant blend and 1 lb/Mgal of sodium thiosulfate. The graph of FIG. 3 also shows the temperature of the sample vs. time.

FIG. 4 is a graph of viscosity measurements in cP vs. shear rates ranging from about 0.1 to about 1,000 sec⁻¹ measured at room temperature before and after heating the sample for 15 minutes at 285° F. (140° C.) on samples of the uncrosslinked HPG gel, where Sample 9, denoted as Sample 9a before heating and as Sample 9b after heating, contained 3 gal/Mgal of the surfactant blend, and where Sample 10, denoted as Sample 10a before heating and as Sample 10b after heating, contained no surfactant blend. While not being limited to one theory, one potential explanation to the polymer-surfactant interaction is that the degradation of polymer chains is delayed with the addition of surfactant as illustrated by the viscosities before and after the samples were heated.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

As used herein and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or parts of an assembly, subassembly, or structural element.

As used herein, the natural temperature of the subterranean formation is the temperature as unaffected by temporarily flooding of the formation with a fluid at a different temperature that would temporarily change the natural temperature of the formation.

As used herein, the solubility of a substance is its concentration in a saturated solution. A substance having a solubility of less than 1 g/100 mL of solvent is usually considered insoluble. The solubility is sometimes called “equilibrium solubility” because the rates at which solute dissolves and is deposited out of solution are equal at this concentration.

The methods according to the present invention will be described by referring to and showing various examples of how the invention can be made and used.

According to one aspect of the invention, a method of treating a subterranean formation penetrated by a wellbore is provided, the method comprising the steps of: (a) for a treatment fluid to be used in treating a subterranean formation, establishing a desired viscosity at a desired temperature for a desired time; (b) forming a treatment fluid that has the desired viscosity at the desired temperature for the desired time, wherein the treatment fluid comprises: (i) a base fluid; (ii) a viscosifying agent comprising a polymer; and (iii) a surfactant; wherein an otherwise substantially identical treatment fluid with a lower concentration of the surfactant would not achieve the desired viscosity at the desired temperature for the desired time; and (c) introducing the treatment fluid into a subterranean formation.

According to another aspect of the invention, a method of treating a subterranean formation penetrated by a wellbore is provided, the method comprising the steps of: (a) for a treatment fluid to be used in treating a subterranean formation, establishing a desired viscosity at a desired temperature for a desired time; (b) forming a treatment fluid that has the desired viscosity at the desired temperature for the desired time, wherein the treatment fluid comprises: (i) a base fluid; (ii) a viscosifying agent comprising a polymer; and (iii) a surfactant; wherein the polymer is at a lower concentration in the base fluid than would be required for an otherwise substantially identical treatment fluid with a lower concentration of the surfactant to achieve the desired viscosity at the desired temperature for the desired time; and (c) introducing the treatment fluid into a subterranean formation.

According to either aspect of the invention, the step of establishing a desired viscosity at a desired temperature for a desired time comprises: ascertaining the temperature of the subterranean formation. The invention offers advantages when the subterranean formation has a temperature that is greater than 175° F. (80° C.) and it is desired to have a treatment fluid be able to maintain a desired viscosity and be thermally stable at or above this temperature. While some gels are sufficiently stable at such moderately high temperatures, the invention has particular advantages, when a desired viscosity is desired to have a thermally stability of at least 220° F. (105° C.).

Preferably, the desired viscosity is at least 100 cP at a shear rate of at least 1/sec; the desired temperature is at least 175° F. (80° C.); and the desired time is at least 0.5 hour. More particularly, the desired viscosity is in the range of 100-5,000 cP at a shear rate in the range of 1-1,000/sec; the desired temperature is in the range of 175-400° F. (80-205° C.); and the desired time is in the range of about 0.5-8 hours.

More preferably, the desired viscosity is at least 500 cP at a shear rate of at least 81/sec; the desired temperature is at least 220° F. (105° C.); and the desired time is at least 1 hour. More particularly, the desired viscosity is in the range of 500-2,500 cP at a shear rate of 81/sec; the desired temperature is in the range of 220-300° F. (105-149° C.); and the desired time is in the range of 2-4 hours.

In the methods according to the invention, the viscosity of the treatment fluid can be measured according to a modified API2 test procedure, which is well know to persons of skill in the art of making treatment fluids for treating a subterranean formation. Further, for example, the viscosity of the treatment fluid can be measured with a Nordman Model 50 viscometer. It is to be understood, of course, that measurement of viscosity is somewhat dependent on the exact testing procedure and equipment employed.

In most situations, the base fluid comprises water. The water can be selected from the group consisting of: fresh water, brackish water, seawater, unsaturated salt water, brine, and any combination thereof in any proportion. It should be understood, of course, that the base fluid can also comprise a gas. The use of a gas can be useful, for example, in making a foamed treatment fluid.

When the base fluid comprises water, the viscosifying agent preferably comprises: a water-soluble polymeric material. More preferably, the water-soluble polymeric material is a polysaccharide. For example, the viscosifying agent can be selected from the group consisting of: guar, hydroxylalkyl guar, carboxyalkylhydroxyalkyl guar, carboxyalkyl cellulose, carboxyalkylhydroxyalkyl cellulose, hydroxyethyl cellulose, hydroxypropyl cellulose, carboxymethyl guar, xanthans, scleroglucan, diutan, succinoglycan, welan, derivatives of any of the foregoing, and any combination thereof in any proportion. More preferably, the viscosifying agent is selected from the group consisting of hydroxypropyl guar, carboxypropylhydroxypropyl guar, carboxymethylcellulose, carboxymethyhydroxymethyl cellulose, and any combination thereof in any proportion.

The viscosifying agent preferably further comprises: a crosslinking agent. The crosslinking agent can help crosslink the polymeric material and increase the viscosity of the fluid. For example, the crosslinking agent can be present in the treatment fluid in an amount in the range of from about 50 ppm to about 10,000 ppm.

When a crosslinking agent is employed, the crosslinking agent is preferably selected from the group consisting of: crosslinking agent is selected from the group consisting of boron compounds, compounds that supply zirconium IV ions, compounds that supply titanium IV ions, aluminum compounds, iron compounds, chromium, compounds that supply antimony ions, and any combination thereof in any proportion.

For a guar-based viscosifying agent, one of the preferred crosslinking agents comprises a boron compound. When a boron compound is employed as a crosslinking agent, the treatment fluid preferably further comprises a pH adjusting agent for elevating the pH of the treating fluid. This is important because borate crosslinking agents require a high pH to function. Preferably, the pH adjusting agent is selected from the group consisting of sodium hydroxide, potassium hydroxide and lithium hydroxide. The pH adjusting agent is preferably in the treating fluid in an amount in the range of from about 0.1% to about 0.3% by weight of the water therein. Regardless of the amount by weight, the pH adjusting agent is most preferably present in at least a sufficient concentration to increase the pH of the water to at least 9.

The treatment fluid preferably further comprises a breaker for the viscosifying agent. When the treatment fluid comprises a borate crosslinker, which operates at a relatively high pH, the breaker preferably comprises a delayed release acid. The delayed release acid is preferably in at least a sufficient concentration in the base fluid to lower the pH of the water to less than 9.

As the term is used herein, a “surfactant” (a contraction of the term surface-active agent) is a substance that, when present in a low concentration in a system, has the property of adsorbing onto the surfaces or interfaces of the system and of altering to a marked degree the surface or interfacial free energies of those surfaces or interfaces. See “Surfactants and Interfacial Phenomena,” Rosen, 3^rd Edition (ISBN 0-471-47818-0). Structurally, a surfactant is an organic compound that contains at least one lyophilic (“solvent-loving”) and one lyophobic (“solvent-fearing”) group in the molecule.

According to a preferred embodiment of the invention wherein the base fluid comprises water, the surfactant is present in the treatment fluid in an amount in the range of from about 1-45 lb/Mgal of the water. According to another preferred embodiment of the invention, the surfactant is present in at least the critical micelle concentration, that is, the concentration required for the surfactant to form a micelle.

It has been discovered that a surfactant has an unexpected effect on improving the thermal stability of a viscosified fluid. This provides two applications that are believed to have been unknown.

First, this allows a treatment fluid to be formulated to achieve a desired viscosity at a desired temperature for a desired time that had until now not been believed to be achievable. This greatly expands the useful ranges for a viscosified treatment fluid having a particular formulation beyond the limits previously thought practical. The ability to use a particular polymeric viscosified system at a higher temperature and/or for a longer time has the benefit of allowing less expensive viscosifying agents to be used in higher temperature applications. This also provides the benefit of being able to use the system at such higher temperatures without the use of other non-surfactant thermal stabilizers, as hereinafter described in more detail.

Second, this allows a treatment fluid to be formulated with a lower polymer loading to achieve a desired viscosity at a desired temperature for a desired time than had until now had not been believed to be achievable with such lower polymer loadings. This also greatly expands the useful ranges for a viscosified treatment fluid having a particular polymer loading beyond the limits previously thought practical. The use of lower polymer loading to achieve a particular desired viscosity at a desired temperature for a desired time has the benefit of reducing the amount of polymer damage to a subterranean formation to be treated with a viscosified fluid.

It should be understood that the use of surfactant or increased concentrations of surfactant is not itself required to appreciably increase the viscosity of the viscosified fluid. Rather, the surfactant, acting as a thermal stabilizer for the polymer, permits a lower loading of the polymer to achieve a desired viscosity at a desired temperature for a desired time. Previously, one of the approaches for combating the thermal degradation of the polymer of the viscosifying agent was to simply increase the loading of the polymer.

According to the invention, these benefits permit the use of formulations for a treatment fluid with a surfactant or an increased concentration of a surfactant under conditions that are beyond the viscosity parameters that have been previously used with substantially identical formulations with such concentrations of the surfactant. Thus, the formulations of viscosified treatment fluid according to the invention have not been previously employed in treating a subterranean formation that is desired to be treated with a fluid capable of achieving a particularly desired viscosity at a desired temperature for a desired time that was previously believed to be beyond the useful parameters of the treatment fluid. The relationship between the concentration of the surfactant and the increased thermal stability of the treatment fluid had not been previously recognized in the art. Therefore, the formulations according to the invention had not been previously used in treatments of subterranean formations that required a certain viscosity with a greater temperature and time stability than heretofore though possible for such a formulation.

The surfactant can be, and often is, in a blend with one or more solvents prior to mixing the surfactant with the base fluid in making a treatment fluid. The solvent is selected for properties that help improve the handling characteristics of the surfactant. Preferably, the amount of the solvent in the surfactant blend is at least sufficient to substantially improve the handling characteristics of the surfactant, but not in such concentration as to unnecessarily dilute the surfactant. Preferably, the solvent in the surfactant blend does not substantially affect the viscosity or thermal stability of the treatment fluid. Because the concentration of the solvent in the surfactant blend preferably does not unduly dilute the surfactant, when the relatively low loading of the surfactant blend is mixed with the base fluid to form the treatment fluid, the solvent in the surfactant is also in relatively low concentration in the base fluid and would not be expected to substantially affect the viscosity or thermal stability of the treatment fluid.

Thus, a treatment fluid made with a surfactant in a solvent blend is expected to be otherwise substantially identical to a treatment fluid made with less surfactant. According to a preferred embodiment of one aspect of the invention, an otherwise substantially identical treatment fluid without any of the surfactant would not achieve the desired viscosity at the desired temperature for the desired time. According to a preferred embodiment of another aspect of the invention, the polymer is at a lower concentration in the base fluid than would be required for an otherwise substantially identical treatment fluid without any of the surfactant to achieve the desired viscosity at the desired temperature for the desired time.

According to a preferred embodiment of the invention, the surfactant is preferably selected to be effective to increase the thermal stability of the viscosifying agent. According to another preferred embodiment of the invention, the surfactant is at a substantially higher concentration than would be used for surfactant purposes. More particularly, the surfactant is at a concentration greater than a concentration that would be used for the emulsion prevention, foaming, or surface tension reduction. Increasing the concentration above the concentrations used for these traditional surfactant purposes unexpectedly provides proportionately increasing thermal stability to a viscosified treatment fluid.

One preferred class of surfactants is non-ionic surfactants. Examples of non-ionic surfactants suitable for use according to the invention include linear ethoxylates, branched ethoxylates, linear alkyl ethoxylated alcohols, branched alkyl ethoxylated alcohols, linear propoxylates, linear alkyl propoxylated alcohols, phenol-formaldehyde non-ionic resin blends, and any combination in any proportion of the foregoing. More specific examples include alkoxylated lanolin oil, castor oil ethoxylate, diethylene glycol monotallowate, ethoxylated fatty alcohols, ethoxylated nonylphenol, glyceryl tribehenate, polyglyceryl-3 diisostearate, and tallow amine ethoxylates. According to a presently most preferred embodiment of the invention, the non-ionic surfactant comprises a nonylphenol ethoxylate. According to another presently most preferred embodiment of the invention, the non-ionic surfactant comprises an alkyl polyglycoside.

Another preferred class of surfactants is anionic. Examples of anionic surfactants suitable for use according to the invention, the anionic surfactant include sulfonic acid such as dodecylbenzene sulfonic acid, salts of sulfonic acid, sulfonate such as methyl ester sulfonate, fatty acid, and salts of fatty acid such as sodium laurate.

It is also envisioned that a fluid system can be devised utilizing cationic, amphoteric, or zwitterionic surfactants. Finally, it is also readily envisioned that combinations of nonionic, anionic, cationic, amphoteric, and/or zwitterionic may be utilized.

The discovery that a surfactant is capable of increasing the thermal stability of a viscosified fluid permits higher concentrations of the surfactant to be used as a thermal stabilizer instead of traditional non-surfactant stabilizers such as methanol, oxygen scavengers, or reducing agents. For example, there is a concern regarding the flammability and health concerns in using methanol. Further, in some wells there is a concern that sodium thiosulfate provides a source of sulfates that can contribute to barium sulfate scaling. Having an alternative to such traditional thermal stabilizers is of major value.

According to a further aspect of the invention, it has been also been discovered that a surfactant provides increased and synergistic benefits of thermally stabilizing a viscosified fluid when used in conjunction with a non-surfactant thermal stabilizer. Preferably, the non-surfactant thermal stabilizer is selected from the group consisting of: thiosulfates, methanol, formate brines, and any combination thereof in any combination. According to the presently most preferred embodiment of the invention, the non-surfactant thermal stabilizer comprises sodium thiosulfate.

According to preferred embodiment of the invention, the treatment fluid further comprises gravel, which can be used, for example, in gravel packing a subterranean formation for fines control. According to another preferred embodiment, the treatment fluid further comprises proppant, which can be used, for example, in hydraulic fracturing of a subterranean formation. According to yet another preferred embodiment, the treatment fluid further comprises resin. It is noted, however, that the viscosity of a treatment fluid is normally measured without any gravel, proppant, or resin components.

According to a preferred embodiment of the invention, the step of introducing the treatment fluid into a subterranean formation further comprises introducing the treatment fluid at a rate and pressure sufficient to form at least one fracture in the subterranean formation.

The invention will be illustrated with the following examples, which in general demonstrate that a surfactant unexpectedly increases the viscosity and/or thermal stability of a viscosified treatment fluid. Further, the following examples demonstrate that a surfactant and a non-surfactant thermal stabilizer used together unexpectedly and synergistically increase the viscosity and/or thermal stability of a viscosified treatment fluid.

EXAMPLES

In all the following examples, the gel system was a borate-crosslinked, 50 lb/Mgal hydroxyproyl guar (“HPG”) in 4% by weight KCl water at a pH of about 10.5.

The surfactant in all the following examples was a non-ionic surfactant comprising nonylphenol ethoxylates. The surfactant was in a blend with a non-ionic non-emulsifier of light aromatic solvent and isopropyl alcohol. Further, additional experiments to the following examples were conducted that demonstrated the solvents in the surfactant blend have no effect on the viscosity or thermal stability of the treatment fluid sample. In addition, additional experiments to the following examples demonstrated similar effects on increasing the viscosity and thermal stability of viscosified fluids to the effects demonstrated by the following examples are obtained with other surfactants, such as alkyl polyglycoside.

Example 1

In Example 1, Sample 1 was a borate-crosslinked HPG gel prepared without any of the surfactant blend, and Sample 2 contained 1 gal/Mgal of the surfactant blend.

Experiments on Samples 1 and 2 were conducted using a Nordman Model 50 viscometer according to a modified API2 test procedure as the sample was rapidly heated from room temperature to 240° F. in about 20 minutes and then held at 240° F. Viscosity was frequently measured at a shear rate of 81/sec over a period of more than 3 hours.

The results of these experiments on Sample 1 and Sample 2 shown in the graph of FIG. 1 demonstrate an unexpectedly improved thermal stability of a borate crosslinked HPG gel with 1 gal/Mgal of the surfactant blend compared to an otherwise identical treatment fluid without any of the surfactant blend. In other words, the improved thermal stability is observed compared to an otherwise substantially identical treatment fluid without any of the surfactant.

Example 2

In Example 2, experiments were conducted to study the effect of varying the concentration of the surfactant in the borate-crosslinked HPG gel. Sample 2 contained 1 gal/Mgal of the surfactant blend. Sample 3 contained 2 gal/Mgal of the surfactant blend. Sample 4 contained 3 gal/Mgal of the surfactant blend.

Experiments on Samples 2, 3, and 4 were conducted using a Nordman Model 50 viscometer according to a modified API2 test procedure as the sample was rapidly heated from room temperature to 285° F. (140° C.) in about 20 minutes and then held at 285° F. (140° C.). Viscosity was frequently measured at a shear rate of 81/sec over a period of more than 3 hours.

The results shown in the graph of FIG. 2 demonstrate that increased surfactant concentrations unexpectedly improve the thermal stability of a borate-crosslinked HPG gel.

Example 3

In this Example, four gel samples of the borate-crosslinked, 50 lb/Mgal HPG in 4% KCl water at a pH of about 10.5 were prepared containing varying amounts of the surfactant blend and sodium thiosulfate, as shown in Table 1:

TABLE 1
Sample #	Gal/Mgal surfactant blend	Lb/Mgal sodium thiosulfate
5	0	0
6	3	0
7	0	1
8	3	1

Samples 5, 6, 7, and 8 were evaluated on a Nordman Model 50 viscometer using a modified API2 test procedure as the sample was rapidly heated from room temperature to 285° F. (140° C.) in about 20 minutes and then held at 285° F. (140° C.). Viscosity was frequently measured at a shear rate of 81/sec over a period of about 1.5 hours.

The results shown in the graph of FIG. 3 demonstrate an unexpected synergistic relationship between a surfactant and sodium thiosulfate for improving the thermal stability of a borate crosslinked HPG gel.

Example 4

In this Example, experiments were conducted to study the effect of the surfactant on test samples of an HPG base gel before and after heating the gel. Sample 9 contained 3 gal/Mgal of the surfactant blend. Sample 10 contained no surfactant blend.

Before heating, the samples are referred to as Sample 9a and Sample 10a. The viscosity of Samples 9a and 10a was measured on an ATS Stresstech Rheometer at room temperature and at shear rates ranging from about 0.1 to about 1,000 sec⁻¹.

After measuring the viscosity of the samples 9a and 10a at room temperature, each sample was then heated to 285° F. for 15 minutes and allowed to cool back to room temperature. After heating, the samples are referred to as Sample 9b and Sample 10b. The viscosity of Samples 9b and 10b was measured on a Stresstech Rheometer at room temperature and at shear rates ranging from about 0.1 to about 1,000 sec⁻¹.

The results of this Example 4 are plotted in the graph of FIG. 4.

In considering the results, it is first important to first observe that there is no appreciable difference between the viscosity curves of FIG. 4 for Sample 9a with the surfactant blend and for Sample 10a without the surfactant blend. This is important because it demonstrates that none of the ingredients of the surfactant blend at 3 gal/Mgal appreciably affect the viscosity before heating the fluid. Further, the concentration of the isopropyl alcohol is too low to affect the viscosity of the treatment fluid samples. Thus, Sample 9 is otherwise substantially identical to treatment fluid Sample 10 without any of the surfactant.

After heating the samples, however, there is a dramatic difference between the viscosity curves of FIG. 4 for Sample 9b with the surfactant blend and for Sample 10b without the surfactant blend. These results show that the presence of the surfactant slows down the thermal degradation of a polymer. In fact, the viscosity of the tested HPG gel with the surfactant was nearly 5 times better than the gel with no surfactant (Table 2).

TABLE 2
Sample Fluid                     Visc. @ 1 s−1
HPG gel with 3 gal/Mgal surfactant before heating 1436
(sample 9a)
HPG gel with no surfactant before heating 1436
(sample 10a)
HPG gel with 3 gal/Mgal surfactant after heating 420
(sample 9b)
HPG gel with no surfactant after heating 87
(sample 10b )

The foregoing descriptions of specific embodiments of the present invention have been presented for purposes of illustration and description. They are not intended to be exhaustive or to limit the invention to the precise forms disclosed, and obviously many modifications and variations are possible in light of the above teaching. The embodiments were chosen and described in order to best explain the principles of the invention and its practical application, to thereby enable others skilled in the art to best utilize the invention and various embodiments with various modifications as are suited to the particular use contemplated. It is intended that the scope of the invention be defined by the claims appended hereto and their equivalents.

Claims

1. A method of treating a subterranean formation penetrated by a welbore, the method comprising the steps of:

a. for a treatment fluid to be used in treating a subterranean formation establishing a desired viscosity at a desired temperature for a desired time;

b. forming a treatment fluid that has the desired viscosity at the desired temperature for the desired time, wherein the treatment fluid comprises; i. a base fluid; ii. a viscosifying agent comprising a polysaccharide; and iii. a surfactant; wherein an otherwise substantially identical treatment fluid with a lower concentration of the surfactant would not achieve the desired viscosity at the desired temperature for the desired time; and

c. introducing the treatment fluid into a subterranean formation.

2. The method according to claim 1, wherein:

a. the desired viscosity is at least 100 cP at a shear rate of at least 1/sec;

b. the desired temperature is at least 175° F. (80° C.); and

c. the desired time is at least 0.5 hour

3. The method according to claim 2, wherein:

a. the desired viscosity is in the range of 100-5,000 cP at a shear rate in the range of 1-1,000/sec;

b. the desired temperature is in the range of 175-400° F. (80-205° C.); and

c. the desired time is in the range of about 0.5-8 hours.

4. The method according to claim 3, wherein:

a. the desired viscosity is at least 500 cP at a shear rate of at least 81/sec;

b. the desired temperature is at least 220° F. (105° C.); and

c. the desired time is at least 1 hour.

5. The method according to claim 4, wherein:

a. the desired viscosity is in the range of 500-2,500 cP at a shear rate of 81/sec;

b. the desired temperature is in the range of 220-300° F. (105-149° C.); and

c. the desired time is in the range of 2-4 hours.

6. The method according to claim 1, wherein the base fluid comprises water.

7. The method according to claim 6, wherein the viscosifying agent comprises: a water-soluble polysaccharide.

8. The method according to claim 1, wherein an otherwise substantially identical treatment fluid without any of the surfactant would not achieve the desired viscosity at the desired temperature for the desired time.

9. canceled.

10. canceled.

11. The method according to claim 1, wherein the surfactant comprises: a non-ionic surfactant.

12. The method according to claim 11, wherein the non-ionic surfactant is selected from the group consisting of: linear ethoxylates, branched ethoxylates, linear alkyl ethoxylated alcohols, branched alkyl ethoxylated alcohols, linear propoxylates, linear alkyl propoxylated alcohols, phenol-formaldehyde non-ionic resin blends, and any combination in any proportion of the foregoing.

13. The method according to claim 1, wherein the surfactant comprises: an anionic surfactant.

14. The method according to claim 13, wherein the anionic surfactant is selected from the group consisting of: sulfonic acid, salt of a sulfonic acid, sulfonate, fatty acid, and salt of fatty acid, and any combination in any proportion of the foregoing.

15. The method according to claim 1, wherein the treatment fluid further comprises: a non-surfactant thermal stabilizer.

16. A method of treating a subterranean formation penetrated by a wellbore, the method comprising the steps of:

a. for a treatment fluid to be used in treating a subterranean formation, establishing a desired viscosity at a desired temperature for a desired time;

b. forming a treatment fluid that has the desired viscosity at the desired temperature for the desired time, wherein the treatment fluid comprises: i. a base fluid; ii. a viscosifying agent comprising a polysaccharide; and iii. a surfactant; wherein the polysaccharide is at a lower concentration in the base fluid than would be required for an otherwise substantially identical treatment fluid with a lower concentration of the surfactant to achieve the desired viscosity at the desired temperature for the desired time; and

c. introducing the treatment fluid into a subterranean formation.

17. The method according to claim 16, wherein:

a. the desired viscosity is at least 100 cP at a shear rate of at least 1/sec;

b. the desired temperature is at least 175° F. (80° C.); and

c. the desired time is at least 0.5 hour.

18. The method according to claim 17, wherein:

a. the desired viscostiy is in the range of 100-5,000 cP at a shear rate in the range of 1-1,000/sec;

b. the desired temperature is in the range of 175-400° F. (80-205° C.); and

c. the desired time is in the range of about 0.5-8 hours.

19. The method according to claim 18, wherein:

a. the desired viscosity is at least 500 cP at a shear rate of at least 81/sec;

b. the desired temperature is at least 220° F. (105° C.); and

c. the desired time is at least 1 hour.

20. The method according to claim 19, wherein:

a. the desired viscosity is in the range of 500-2,500 cP at a shear rate of 81/sec;

b. the desired temperature is in the range of 220-300° F. (105-149° C.); and

c. the desired time is in the range of 2-4 hours.

21. The method according to claim 16, wherein the base fluid comprises water.

22. The method according to claim 21, wherein the viscosifying agent comprises: a water-soluble polysaccharide.

23. The method according to claim 16, wherein the polysaccharide is at a lower concentration in the base fluid than would be required for an otherwise substantially identical treatment fluid without any of the surfactant to achieve the desired viscosity at the desired temperature for the desired time.

24. canceled.

25. canceled.

26. The method according to claim 16, wherein the surfactant comprises: a non-ionic surfactant.

27. The method according to claim 26, wherein the non-ionic surfactant is selected from the group consisting of: linear ethoxylates, branched ethoxylates, linear alkyl ethoxylated alcohols, branched alkyl ethoxylated alcohols, linear propoxylates, linear alkyl propoxylated alcohols, phenol-formaldehyde non-ionic resin blends, and any combination in any proportion of the foregoing.

28. The method according to claim 16, wherein the surfactant comprises: an anionic surfactant.

29. The method according to claim 28, wherein the anionic surfactant is selected from the group consisting of: sulfonic acid, salt of a sulfonic acid, sulfonate, fatty acid, and salt of fatty acid, and any combination in any proportion of the foregoing.

30. The method according to claim 16, wherein the treatment fluid further comprises: a non-surfactant thermal stabilizer.

31. A method of treating a subterranean formation penetrated by a wellbore, the method comprising the steps of:

a. forming a treatment fluid comprising: i. a base fluid; ii. a viscosity agent comprising a polysaccharide; iii. a surfactant; and iv. a non-surfactant thermal stabilizer; and

b. introducing the treatment fluid into a subterranean formation.

32. The method according to claim 31, wherein the base fluid comprises water.

33. The method according to claim 32, wherein the viscosifying agent comprises: a water-soluble polysaccharide.

34. The method according to claim 32, wherein the non-surfactant thermal stabilizer is selected from the group consisting of: thiosulfates, methanol, formate brines, and any combination thereof in any combination.